SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2012

OR

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

For the transition period from           to           

Commission File No. 001-32331

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 16429, Bristol, Virginia	24209
(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 x  No  o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  o  No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  x  No  o

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.   x

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   x	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 o No x

The aggregate market value of the Common Stock held by non-affiliates of the registrant on June 30, 2012, was approximately $1.3 billion based on the closing price of theCompany’s common stock as reported that date on the New York Stock Exchange of $8.71 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 22, 2013 — 220,720,180 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2013 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, 2012.

2012 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	27
Item 1A.	Risk Factors	30
Item 1B.	Unresolved Staff Comments	47
Item 2.	Properties	47
Item 3.	Legal Proceedings	54
Item 4.	Mine Safety Disclosures	54
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	54
Item 6.	Selected Financial Data	56
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	61
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	92
Item 8.	Financial Statements and Supplementary Data	93
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	173
Item 9A.	Controls and Procedures	173
Item 9B.	Other Information	174
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	174
Item 11.	Executive Compensation	175
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	175
Item 13.	Certain Relationships and Related Transactions, and Director Independence	175
Item 14.	Principal Accountant Fees and Services	175
PART IV
Item 15.	Exhibits and Financial Statement Schedules	176

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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:

• our liquidity, results of operations and financial condition; 

• decline in coal prices;

• worldwide market demand for coal, electricity and steel;

• utilities switching to alternative energy sources such as natural gas, renewables and coal from basins where we do not operate;

• our production capabilities and costs;

• availability of mining and processing equipment and parts;

• 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;

• competition in coal markets;

• regulatory and court decisions;

• 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;

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

• potential instability and volatility in worldwide financial markets;

• the outcome of pending or potential litigation or governmental investigations, including with respect to the Upper Big Branch explosion;

• our relationships with, and other conditions affecting, our customers, including the inability to collect payments from our customers if their creditworthiness declines;

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

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

• inherent risks of coal mining beyond our control;

• weather conditions or catastrophic weather-related damage;

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

• 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;

• 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;

• inflationary pressures on supplies and labor;

• 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;

• reclamation and mine closure obligations;

• our assumptions concerning economically recoverable coal reserve estimates;

• significant or rapid increases in commodity prices;

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

• disruption in coal supplies;

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

• our ability to negotiate new UMWA (as defined below) wage agreements on terms acceptable to us, increased unionization of our workforce in the future, and any strikes by our workforce;

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

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• our ability to integrate successfully operations that we have acquired or developed with our existing operations, as well as those operations that we may acquire or develop in the future, 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;

• indemnification of certain obligations not being met;

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

• our substantial indebtedness and potential future indebtedness;

• restrictive covenants in our secured credit facility and the indentures governing our outstanding debt securities;

• certain terms of our outstanding debt securities, including any conversions of our convertible senior debt securities, that may adversely impact our liquidity;

• our ability to obtain or renew surety bonds on acceptable terms or maintain self bonding status; and

• other factors, including those discussed in Item 1A “Risk Factors” and in Item 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report on Form 10-K for the year ended December 31, 2012.

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

We are one of America’s premier coal suppliers, ranked third largest among publicly-traded U.S. coal producers as measured by 2012 consolidated revenues of $7.0 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 as well as a growing exporter of thermal coal. As of December 31, 2012, we operated 107 mines and 26 coal preparation plants in Northern and Central Appalachia and the Powder River Basin, with approximately 12,400 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; 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.

Steam coal, which is primarily purchased by large utilities and industrial customers as fuel for electricity generation,accounted for approximately 81% of our 2012 coal sales volume. Metallurgical coal, which is used primarily to make coke, akey component in the steel making process, accounted for approximately 19% of our 2012 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 2012, we sold a total of 108.8 million tons of steam and metallurgical coal and generated coal revenues of $6.0 billion. EBITDA from continuing operations was ($1.8) billion, and we incurred a loss from operations of $2.4 billion. We define and reconcile EBITDA from continuing operations in Item 6-“Selected Financial Data.” Our coal sales during 2012 consisted of 108.8 million tons of coal, of which 105.8 million was produced and processed by us, exclusive of coal purchased from third party brokerages. We also purchased 3.0 million tons from third parties, of which 1.0 million tons we fully processed at our processing plants prior to resale, 1.7 million tons we blended with our coal prior to resale, and 0.3 million tons in raw product we shipped direct to our customers without any further processing or blending on our behalf. Approximately 42% of our total revenues in 2012 was derived from sales made to customers outside the United States, primarily in Canada, India, the Netherlands, South Korea and Turkey.

As of December 31, 2012, we owned or leased approximately 4.6 billion tons of proven and probable coal reserves, ofwhich approximately 1.5 billion tons are classified as metallurgical coal reserves. Of our total proven and probable reserves,approximately 78% are low sulfur reserves, with approximately 63% having sulfur content below 1%. Approximately 69% 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.

During the twelve months ended December 31, 2012, we announced the planned idling of certain mining operations and preparation plants in our eastern operations and other planned production curtailments as well as an organizational streamlining. The mines impacted are located in Virginia, West Virginia, Pennsylvania, Kentucky and Wyoming. The combination of mine idlings, production curtailments and mining out of certain reserves will take place through early 2013, and is expected to reduce 2013 production and shipments by approximately 17 million to 28 million tons compared to 2012 levels. The majority of the reduction will come from higher-cost thermal coal operations in the east and the Power River Basin. These reductions will allow us to focus on higher margin products. We will continue to evaluate market conditions and will make further adjustments if market conditions warrant. Our reorganization efforts will serve to reduce overhead while enhancing operational effectiveness as we align our structure to our smaller production footprint. As part of our reorganization we established an operational performance group to support the deployment of best practices across the organization in areas such as operations improvement and preventive maintenance. Satellite offices in Richmond, Virginia, Denver, Colorado, Latrobe, Pennsylvania, and Linthicum Heights, Maryland have been closed and overhead support functions are being consolidated from other locations as well. We expect to achieve overhead savings from the streamlining of field and corporate support functions, which are expected to be reflected in lower cost of coal sales and selling, general and administrative expenses.

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During the twelve months ended December 31, 2012, we tested certain of our long-lived assets and goodwill for impairment. We recorded charges for asset impairment of $1,000.5 million and goodwill impairment of $1,713.5 million. Additionally, we recorded severance-related expenses of $33.9 million and $13.6 million for professional fees. Additionally, we recorded other restructuring expenses of $20.9 million related to reserves for advanced royalties and deposits which may not be recoverable and liabilities related to certain property leases that were terminated. See Note 8 and Note 9 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K related to asset impairment and restructuring expenses and goodwill impairment, respectively.

History

Old Alpha (as defined below) 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. The following are significant developments:

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.

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. 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.

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

On June 1, 2011, we completed our acquisition (the “Massey Acquisition”) of Massey Energy Company (“Massey”) for approximately $6.7 billion, of which approximately $1.0 billion was paid in cash and $5.7 billion was paid in common stock and other equity. Massey, together with its affiliates, was a major U.S. coal producer with approximately 2.4 billion tons of proven and probable reserves operating mines and associated processing and loading facilities in Central Appalachia. Our

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consolidated results of operations for the twelve months ended December 31, 2011 include Massey’s results of operations for the period June 1, 2011 through December 31, 2011. Our consolidated results of operations for the twelve months ended December 31, 2010 do not include amounts related to Massey’s results of operations.

Unless we have indicated otherwise, or the context otherwise requires, references in this report to “Alpha”, the “Company”, “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. 

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 2012 consolidated revenues and have significant coal reserves. Based on 2012 consolidated revenues of $7.0 billion, we are the third largest publicly traded coal producer in the United States. As of December 31, 2012, we controlled approximately 4.6 billion tons of proven and probable coal reserves.

We have a diverse portfolio of coal mining operations and reserves.  As of December 31, 2012, we operated a total of 107 mines and had reserves in the three major U.S. coal producing basins: Northern and Central Appalachia and the Powder River Basin. Our reserves 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. We believe that this geographic diversity provides us with a significant competitive advantage, allowing us to source coal from multiple regions to meet the needs of our customers and reduce their transportation costs.

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 have implemented our industry-leading safety program Running Right, an employee engagement safety-based management approach. During 2012, we experienced a 20% improvement in our incident rate and a 32% reduction in our serious and substantial Mine Safety and Health Administration (“MSHA”) citations, as compared to 2011. Construction of the Running Right Leadership Academy will provide a world-class training facility that will integrate our Running Right program, with other safety, operations improvement and maintenance initiatives.

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 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 long-term customer relationships.

We are the largest producer of metallurgical coal in the United States and have a broad base of 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 in the range of 25 to 30 million tons annually through our access to international shipping points on the east and gulf coasts of the United States, including our 41% ownership interest in DTA. Our capacity and our international customer base are important to our metallurgical coal franchise and will be important as we grow our thermal export franchise.

Business Strategy

Our objective is to increase shareholder value and focus on free cash flow generation by creating a durable, sustainable steam coal portfolio, support and augment our metallurgical coal franchise and address non-strategic operations. 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 mining 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.

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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. and seaborne coal industries 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. For example, as domestic demand for thermal coal from the Central Appalachia basin is tempered by abnormally low natural gas prices and an increasingly stringent regulatory environment, we may shift our strategy as necessary to increase export thermal sales to counter-balance the tempered domestic demand.

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 long-term growth in international coal consumption and the continued consumption of significant volumes of coal in the U.S.

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, mix of coal qualities and access to export terminal capacity provide us with the opportunity to work with many leading electricity generators, steel companies and other industrial customers across the country and much of the world.

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.

Coal Mining Techniques

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

Longwall Mining

We utilize longwall mining techniques at certain of our mines in the Northern Appalachia basin which is the most productive 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. Ultimate 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

Certain of our mines in the Central Appalachia basin 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, continuous haulage or battery coal haulers are used to transport coal from the continuous miner 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/shovel and truck/front-end loader mining methods at our surface mines throughout our Eastern and Western operations.  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

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coal typically does not need to be cleaned in a preparation plant before sale. Productivity depends on overburden and coal thickness (strip ratio), equipment utilized and geologic factors.

Highwall Mining

We utilize highwall mining methods at the surface mines in our Eastern Operations. A highwall mining system consists of a remotely controlled continuous miner, which extracts coal and conveys it via augers or belt conveyors to the portal. The cut is typically a rectangular, horizontal opening in the highwall (the unexcavated face of exposed overburden and coal in a surface mine) 11-feet wide and reaching depths of up to 1,000 feet. Multiple parallel openings are driven into the highwall, separated by narrow pillars that extend the full depth of the hole.

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 4.6 billion tons of proven and probable reserves, approximately 69% have a heat value above 12,500 Btus per pound, which is considered high btu 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 78% 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.

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 higher 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”) 2011 International Energy Outlook, world-wide economically recoverable coal reserves using today’s technology are estimated to be approximately 948

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billion tons. Also according to the 2011 EIA International Energy Outlook, the United States is one of the world’s largest producers of coal and has approximately 27% of global coal reserves, representing about 222 years of supply based on current usage rates. According to the U.S. Department of Energy, the energy content of the United States’ demonstrated recoverable coal reserves exceeds the world’s proven oil reserves.

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 and remains close to one billion tons in 2012.

	Actual (1)			Preliminary (1) (2)	Projected (1)		Annual Growth
Consumption by Sector	2009	2010	2011	2012	2017	2032	2012-2017		2017-2032
	(Tons in millions)
Electric Generation	934	975	962	908	843	983	-1.5	%	0.1	%
Industrial	45	52	50	48	50	53	0.7	%	0.1	%
Steel Production	15	21	24	25	19	17	-5.8	%	-1.3	%
Coal-to-Liquids Processes	—	—		—	10	27			4.8	%
Residential/Commercial	3	3	3	3	3	3	-0.2	%	-0.1	%
Export	59	82	106	97	103	119	1.3	%	2.2	%
Total	1,056	1,133	1,145	1,081	1,028	1,202

 ___________________________

⁽¹⁾  Data sourced from the U.S. Department of Energy’s EIA’s 2012 Annual Energy Outlook.

⁽²⁾  Preliminary data subject to change and finalization.

Much of the nation’s power generation infrastructure is coal-fired. As a result, coal has maintained an annual 37% to 51% 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 2012, non-hydropower renewable power generation accounted for 5.4% of all the electricity generated in the United States, and wind and solar power represented 3.5% 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.

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, entering service in 2017 are as follows:

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	Range of Total System Levelized Costs (2010 $/megawatthour) for Plants Entering Service in 2017
Plant Type (1)	Minimum		Average		Maximum
Conventional Coal	$	90.50	$	97.70	$	114.30
Advanced Coal	$	102.50	$	110.90	$	124.00
Conventional Natural Gas Combined Cycle	$	59.50	$	66.10	$	81.00
Conventional Natural Gas Combustion Turbine	$	91.90	$	127.90	$	152.40
Advanced Nuclear	$	107.20	$	111.40	$	118.70
Geothermal	$	84.00	$	98.20	$	112.00
Biomass	$	97.80	$	115.40	$	136.70

 ______________________________

⁽¹⁾  Data sourced from the U.S. Department of Energy’s EIA 2012 Annual Energy Outlook.

Coal Production.  United States coal production was approximately 1 billion tons in 2012. 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) (2)	Projected (1)		Annual Growth
Production by Region	2009	2010	2011	2012	2017	2032	2012-2017		2017-2032
	(Tons in millions)
Powder River Basin	417	428	429	419	401	498	-0.8	%	1.5	%
Central Appalachia	197	186	186	178	104	85	-10.1	%	-1.2	%
Northern Appalachia	127	130	135	125	152	178	4.0	%	1.1	%
Illinois Basin	106	110	118	110	118	134	1.6	%	1.0	%
Other	227	230	225	216	229	277	1.2	%	1.3	%
Total	1,074	1,084	1,093	1,048	1,004	1,172

 ____________________________

⁽¹⁾  Data sourced from the U.S. Department of Energy’s EIA’s 2012 Annual Energy Outlook and Short-Term Energy Outlook.

⁽²⁾  Preliminary data subject to change and finalization.

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 Illinois basin 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 2012, imports accounted for a relatively small percentage of total U.S coal consumption. Approximately 1.1% of total U.S. coal consumption in 2012 was imported. Excess industry capacity also 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, transportation 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 accounted for greater than 93% of 2012 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, most notably natural gas, but also including 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 allowances in order to meet Clean Air Act requirements.

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

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economic activity and the availability and relative cost of substitute materials. In the export metallurgical market we largely compete with producers from Australia, Canada, and other international producers of metallurgical coal.

Mining Operations

Our active operations are located in Central and Northern Appalachia and the Powder River Basin, which include the states of Kentucky, Pennsylvania, Virginia, West Virginia and Wyoming. As of December 31, 2012, our operations include 26 preparation plants, each of which receive, blend, process and ship coal that is produced from one or more of our 107 active mines (some of which are operated by third parties under contracts with us) using five mining methods: longwall mining, room-and-pillar mining, truck-and-shovel mining, truck and front-end loader mining, and highwall 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 combination 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 2012, most of our preparation plants also processed coal that we purchased from third party producers before reselling it to our customers. Mines have been developed in close proximity to our preparation plants and rail shipping facilities. Coal is transported to customers by means of railroads, trucks, barge lines, and ocean-going vessels from terminal facilities.

The following table provides location and summary information regarding our coal operations and preparation plants as of December 31, 2012:

Coal Operations

			Preparation Plants/Shipping Points as of December 31, 2012	Number and Type of Mines as of December 31, 2012				2012 Production of Saleable Tons (in thousands) (1)
Reportable Segment	Coal Basin	Location		Underground	Surface	Total	Transportation
East	Central Appalachia	Kentucky, Virginia, and West Virginia	Cave Branch, Delbarton, Elk Run, Erbacon, Goals, Green Valley, Homer III, Kepler, Liberty, Litwar, Mammoth, Marfork, McClure, Omar, Pax, Pigeon Creek, Power Mountain, Rockspring, Roxana, Sidney, Toms Creek, Zigmon	67	22	89	Barge, CSX, NS, RJCC, Truck	46,130
	Northern Appalachia	Pennsylvania	Clymer, Cumberland, Emerald, and Portage	7	9	16	Barge, Truck, CSX, NS	13,163
West	Powder River Basin	Wyoming	Belle Ayr and Eagle Butte	—	2	2	BNSF, UP, Truck	46,695
	Total from active operations			74	33	107		105,988

_______________________________ 

⁽¹⁾  Includes coal purchased from third-party producers that was processed at our preparation plants in 2012.

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.

Eastern Coal Operations

Our operations in Northern Appalachia (“NAPP”) consist of our Cumberland and Emerald mining complexes, as well as 5 underground mines and 9 surface mines and 2 additional preparation plants. We control approximately 940.4 million tons of reserves through our operations in NAPP. Approximately 180.9 million tons are assigned to active mines and 759.5 million tons

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are unassigned. During 2012, approximately 15% of the shipments were marketed as high volatility metallurgical coal to export customers. There are approximately 2,000 salaried and hourly employees at our operations in NAPP as of December 31, 2012. The hourly work force at certain mines is represented by the United Mine Workers of America (“UMWA”).

At our Cumberland and Emerald mining complexes, coal is mined primarily by using longwall mining systems supported by continuous miners. 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 steam coal primarily to eastern utilities. Cumberland shipped 6.4 million tons of coal in 2012. 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 4.2 million tons of coal in 2012. 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.

At our 5 underground mines and 9 surface mines in NAPP, 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. The mines sell high Btu, low, medium, and high sulfur coal to eastern utilities and steel companies. 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 2012, these operations shipped 2.6 million tons.

Our operations in Central Appalachia (“CAPP”) consist of 67 underground mines, 22 surface mines and 22 preparation plants, a portion of which are operated by independent contractors. Our operations in CAPP collectively shipped 46.9 million tons in 2012. We control approximately 2,830.7 million tons of coal reserves through our operations in CAPP. Approximately 1,392.5 million tons are assigned to active mines and approximately 1,438.2 million tons are unassigned. There are approximately 9,200 salaried and hourly employees at our operations in CAPP as of December 31, 2012. In addition, at certain mines a portion of our hourly workforce is represented by the UMWA.

Our coal in CAPP is mined using several different mining methods, including continuous miners employing the room-and-pillar method at our underground mines, and the truck and front-end loader and highwall mining methods at our surface mines. We have mines that sell high Btu, low, medium and high sulfur steam coal primarily to eastern utilities and metallurgical coal to steel companies.

We transport coal produced at certain of our mines by truck and belt to the following preparation plants: Delbarton, Elk Run, Goals, Mammoth, Marfork, Rockspring, Sidney, and Zigmon. In addition, we transport coal by truck and belt to our Pax loadout.

We transport coal produced at certain of our mines by truck to the following preparation plants: Cave Branch, Erbacon, Green Valley, Liberty, McClure, Pigeon Creek, Power Mountain, Roxanna, and Toms Creek. In addition, we transport coal by truck to our Omar and Homer III loadouts.

We transport coal mined at certain of our mines by truck or rail to our Litwar preparation plant, Kepler preparation plant or our Ben's Creek loadout.

The coal produced by certain of the surface mines is transported to the Roxanna preparation plant.

At our preparation plants, the coal is cleaned, blended and loaded onto rail or truck for shipment to customers. The coal produced by certain of our surface mines is transported to raw coal loading docks where it is blended and loaded onto rail for shipment to customers.

Western Coal Operations

Our Western Coal Operations in the Powder River Basin consist of our Belle Ayr and Eagle Butte operations, which collectively shipped 46.7 million tons in 2012. Coal is mined primarily using the truck and shovel mining method. We control approximately 771.5 million tons of coal reserves in the Powder River Basin and all of the coal reserves are assigned to active mines. There are approximately 600 salaried and hourly employees in our Powder River Basin operations.

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Belle Ayr consists of one mine that produces sub-bituminous, low sulfur steam 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 24.3 million tons of coal in 2012. 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 steam 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 22.4 million tons of coal in 2012. 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.

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 completed multi-year project during 2012, approximately 11 miles of rough grade road in West Virginia and, in exchange, NCI was 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 was constructed, any coal recovered was 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. Our subsidiary Coal Gas Recovery, LLC 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 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 2012 we shipped a total of 3.7 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 2012, we received cash payments related to the terminal of $16.9 million partially offset by payments we made for expenses of $7.9 million. The terminal is held in a partnership with subsidiaries of two other companies, Arch Coal, Inc. and Peabody Energy Corp.

Coal Handling Joint Venture.  In the Massey Acquisition, we acquired a 50% interest in a joint venture that owns and operates third-party end-user coal handling facilities. Certain of our subsidiaries currently operate the coal handling facilities of the joint venture.

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 Bristol, Virginia, included 40 employees as of December 31, 2012, and consists of sales managers, distribution/traffic managers, contract administrators and administrative personnel. In

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addition to marketing coal produced at our operations, we also purchase and resell 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 relevant to our customers, we are able to serve a diverse customer base. This diversity allows us to adjust to changing market conditions and supports higher 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 108.8 million tons of coal in 2012, consisting of 105.8 million tons of coal produced and processed by us, and 3.0 million tons of purchased coal. 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. A portion of purchased coal was processed by us, meaning that we washed, crushed or blended the coal at one of our preparation plants or loading facilities prior to resale. A portion of purchased coal was sold direct to customers, meaning we did not wash, crush or blend the coal prior to resale.We sold a total of 106.3 million tons of coal in 2011, consisting of 100.3 million tons of coal produced and processed by us, and 6.0 million tons of purchased coal. We sold a total of 84.8 million tons of coal in 2010, consisting of 81.8 million tons of coal produced and processed by us, and 3.0 million tons of purchased coal.

The breakdown of tons sold for 2012, 2011, and 2010 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)
2012	88.5	81	%	20.3	19	%
2011 (2)	87.1	82	%	19.2	18	%
2010	73.0	86	%	11.8	14	%

_________________________________

⁽¹⁾  Sales of steam coal during 2012, 2011, and 2010 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, South America and Africa.

⁽²⁾  The amounts for 2011 include the results of operations for Massey for the period from June 1, 2011 through December 31, 2011. The amounts for 2010 do not include the results of operations for Massey.

We sold coal to approximately 200 different customers in 2012. Our top ten customers in 2012 accounted for approximately 42% of 2012 total revenues and our largest customer during 2012 accounted for approximately 9% of 2012 total revenues. The following table provides information regarding exports in 2012, 2011, and 2010 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
2012	21.3	20	%		$2,930.6	42	%
2011 (1)	16.3	15	%		$3,096.0	44	%
2010	9.6	11	%		$1,351.0	34	%

 ____________________________

⁽¹⁾  The amounts for 2011 include the results of operations for Massey for the period from June 1, 2011 through December 31, 2011. The amounts for 2010 do not include the results of the operations for Massey.

Export shipments during each of 2012, 2011, and 2010 serviced customers in 27 countries across North America, Europe, South America, Asia and Africa. India was the largest export market in 2012, with sales to India accounting for approximately 13% of total export revenues and 6% of total revenues. India was the largest export market in 2011, with sales to India accounting for approximately 15% of total export revenues and 7% of total revenues. Brazil was the largest export market in 2010, with sales to Brazil accounting for approximately 11% of total export revenues and 4% of total revenues. All of our sales are made in U.S. dollars.

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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 may provide us with greater predictability of sales volume and sales prices. A majority of our steam coal sales are shipped under long-term contracts. 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 and price reopener 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.

During 2012, approximately 52% and 77% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts. During 2011, approximately 50% and 81% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to 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.

Our sales backlog, including backlog subject to price reopener and/or extension provisions, was approximately 162.7 million tons as of January 25, 2013 and approximately 234.9 million tons for the comparable period in 2012. Of these tons, approximately 49% and 48%, respectively, were expected to be filled within one year.

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 26 preparation plants, loadout facilities, and in certain cases directly from our mines. The coal we purchase isloaded 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 vessels from terminal facilities. Rail shipmentsconstituted approximately 70% of total shipments of coal volume produced and processed from our mines to the preparationplant to the customer in 2012. The balance was shipped from our preparation plants, loadout facilities or mines via truck. In2012, approximately 9% of our coal sales volume was delivered to our customers through transport on the Great Lakes and domestic rivers, approximately 4% was moved through the Norfolk Southern export facility at Norfolk, Virginia, approximately 7% was moved through the coal export terminal at Newport News, Virginia operated by DTA, and approximately 6% was moved through the export terminals at Baltimore, Maryland and New Orleans, Louisiana. We own a 41% interest in the coal export terminal at Newport News, Virginia 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 2012, 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 substantial 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, fuel, 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.

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We have a centralized sourcing group, which sets sourcing policy and strategy focusing primarily on major supplier contract negotiation and administration, including but not limited to the purchase of major capital goods in support of the mining operations. The supplier base has been relatively stable for many years, but there has been some consolidation. We are not dependent on any one supplier. We promote competition between suppliers and seek to develop relationships with suppliers that focus on lowering our costs while improving quality and service. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

Employees

As of December 31, 2012, we had approximately 12,400 employees. As of December 31, 2012, the UMWA represented approximately 11% of our total employees. Our UMWA-represented employees are located in Kentucky, Virginia, West Virginia and Pennsylvania, and produced approximately 10% of our coal sales volume during the fiscal year ended December 31, 2012. Relations with organized labor are important to our success, and we believe our relations with our employees are very good.

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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 respect 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, due in part to the extensive and comprehensive regulatory requirements, violations occur from time to time. 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 April 2012, MSHA published a final rule to revise the requirements for pre-shift, supplemental, on-shift and weekly examinations of underground coal mines. The final rule adds a requirement that operators identify violations of mandatory health or safety standards and also requires the mine operator to record and correct these violations, note the actions taken to correct the conditions and review with mine examiners (e.g., the mine foreman, assistant mine foreman or other certified persons) on a quarterly basis all citations and orders issued in areas where pre-shift, supplemental, on-shift and weekly examinations are required.

In January 2013, MSHA published a final rule that implements changes to its Pattern of Violations (“POV”) program. Under the final changes, MSHA may issue a POV notice without first issuing a potential POV notice, and will consider all significant and substantial citations and orders issued, including non-final citations and orders, when determining POV status., The final rule restates the statutory requirement that, for mines in POV status, each significant and substantial violation will result in a withdrawal order until a complete inspection finds no such violations.

In October 2010, MSHA published a proposed rule to reduce the permissible concentration of respirable dust in underground coal mines from the current standard of 2 milligrams per cubic meter of air to one milligram per cubic meter, mandate the use of continuous personal dust monitors, address extended work shifts, redefine normal production shifts, require additional medical surveillance examinations for miners, provide for the use of a single, full-shift sample to determine compliance, and make various other changes to the existing respirable dust standard.

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In August 2011, MSHA published a proposed rule to require certain underground mining equipment to be equipped with proximity detection systems 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 new or more stringent safety and health requirements will have on our operating costs, but they will increase our costs and those of others in the industry. 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 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 mines 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.

As of December 31, 2012, all of our 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 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 dependents. 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 2012 and 2011 for our obligations to the Combined Benefit Fund were approximately $0.6 million and $0.5 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 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 2012 and 2011 for our obligation to the 1992 Plan were $1.5 million and $1.0 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 expanded transfers from the Abandoned Mine Land Fund (“AML”). To the extent these transfers are adequate, they have incrementally eliminated 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 of 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.

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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 mining 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.

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 (the “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 the 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 (“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 characterize adequately 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 elements 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 is information regarding 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

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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, the OSM issued revisions to its Stream Buffer Zone Rule under SMCRA. The revisions allow disposal of excess spoil within 100 feet of streams if the 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 a settlement agreement with environmental groups that filed legal challenges seeking to invalidate the 2008 rule, the OSM agreed to issue a new proposed rule in 2011 and a final rule in 2012. In April 2010, as initial steps toward issuing a new Stream Protection Rule under SMCRA, the OSM commenced a pre-rulemaking information gathering process and solicited public comment on a notice of intent to conduct an environmental impact study. The 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 areas; requiring additional monitoring during mining and reclamation; establishing corrective action thresholds; and limiting variances and exceptions to the “approximate original contour” requirement for reclamation. The OSM has not yet issued the proposed rule. 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 our ability to obtain or the cost of bonds in the future.

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 GHG. Although our gas operations capture some of the coalbed methane in several of our operations, most is vented into the atmosphere when the coal is mined.

Considerable and increasing government attention in the United States and other countries is being paid to reducing GHG 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 GHGs, 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 GHG emission reductions and related financing. In particular, the Durban Platform for Enhanced Action, as agreed to by the United States and 193 other countries in December 2011 at the 17th UNFCCC, calls for a second phase of the Kyoto Protocol's GHG emissions restrictions to be effective through 2020 and for a new international treaty to come into effect and be implemented from 2020. In December 2012, the 18th UNFCCC in Doha made further progress toward a new treaty. Any international GHG agreement in which the United States participates, if at all, could adversely affect the price and demand for coal in the United States.

In addition to possible future U.S. treaty obligations, regulation of GHGs 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, 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 incent the construction and development of carbon capture and sequestration plants as well as

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other advanced coal technologies. We cannot predict the financial impact of future GHG or clean energy legislation on our operations or our customers at this time.

The EPA also is implementing plans to regulate GHG emissions. The EPA's Mandatory Greenhouse Gas Reporting Rule required power plants and other large sources of GHGs to file annual reports disclosing GHG emissions beginning in 2011. In July 2010, the EPA issued amendments that required underground coal mines and certain other source categories to file their first annual reports disclosing GHG emissions in 2012, covering calendar year 2011. Our facilities subject to the rule have begun reporting the required GHG data.

More generally, 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 the 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, certain new and modified emission sources must meet Best Available Control Technology for GHG emissions. 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 March 2012 the EPA issued proposed regulations to establish GHG new source performance standards for new fossil-fuel fired electric utility generating units, and a final rule is anticipated in 2013. Federal legislation that would variously suspend or eliminate the EPA's regulatory authority over GHGs has been introduced in both the House and Senate.

In addition to federal GHG regulations, several state and regional climate change initiatives are taking effect before federal action. The Regional Greenhouse Gas Initiative (“RGGI”), a regional GHG cap-and-trade program calling for a ten percent reduction of emissions by 2018, has nine participating states in the Northeast (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont). The RGGI program has had numerous emission allowances auctions and entered its second three-year control period in 2012.

On December 17, 2010, the California Air Resources Board (“CARB”) issued a final rule approving a state-wide GHG cap-and-trade program pursuant to the California Global Warming Solutions Act of 2006 that would reduce California's GHG emissions to 1990 levels in yearly increments by 2020. In January 2013, CARB's cap-and-trade program became effective for the electricity sector and certain other facility categories. Other GHG 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 GHG emissions, such as those of Kansas, Colorado, and Texas.

Considerable uncertainty is associated with these GHG emissions 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 GHG 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 more stringent GHG emissions limitations 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 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. In addition, if regulation of GHG 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

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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 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 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:

• Sulfur Dioxide and Nitrogen Dioxide. 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”). Under the Clean Air Act, the new NAAQS generally must be attained no later than five years after the EPA designates an area as non-attainment.

• Fine Particulate Matter. The EPA has established NAAQS for both particulate matter with an aerodynamic diameter less than or equal to 10 microns (“PM10”), and fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns (“PM2.5” or “fine particulate matter”). Over the past decade, the EPA has taken several steps to lower the NAAQS for particulate matter, which is currently being implemented in a number of designated non-attainment areas. Most recently, in December 2012, the EPA issued a final rule to reduce the annual PM2.5 standard, retaining the existing 24-hour PM2.5 standard and the existing PM10 standards. The final rule will trigger a new round of non-attainment designations and ultimately regulation. Meeting the new PM2.5 standard also may require reductions of nitrogen oxide and SO2 emissions.

• Acid Rain. Title IV of the Clean Air Act required a two-phase reduction of SO2 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 SO2 emission allowances.

• Ozone. The EPA's 1997 NAAQS for ozone, as amended in 2008, is being implemented in a number of designated non-attainment areas. In addition, the EPA proposed a more stringent ozone NAAQS in January 2010, with the EPA's review of the updated science regarding ozone currently scheduled for completion in 2013. 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/Cross-State Air Pollution Rule. In 2005, the EPA issued its final Clean Air Interstate Rule (“CAIR”) for further reducing emissions of SO2 and nitrogen oxides (“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 SO2 and NOx through an allowance trading program or other system. At full implementation, the EPA projected that CAIR would cut regional SO2 emissions by more than 70% from the 2003 levels, and cut NOx emissions by more than 60% from 2003 levels. In July 2011, in response to the court order on CAIR, the EPA issued a new rule to replace CAIR, called the Cross-State Air Pollution Rule (“CASPR”). CASPR would require additional reductions of power plant emissions in 27 eastern states - by 73% for SO2 and 54% for NOx compared to 2005 levels, according to the EPA. As well, CASPR would severely limit interstate emissions trading as a compliance option. In December 2011, a federal appellate court issued a stay of CASPR pending judicial review. During the stay, CAIR remained in effect. In August 2012, the U.S. Court of Appeals for the District of Columbia struck down CASPR, finding that it required certain upwind states to reduce their emissions below their respective contributions to nonattainment and that it usurped states' roles in implementing emission reduction strategies. Although the EPA may appeal the matter to the United States Supreme Court, it is anticipated that the EPA will implement CAIR, which remains in effect except in Minnesota, where a stay applies, and will initiate a new rulemaking to establish more stringent standards. CAIR or more stringent standards may ultimately require many coal-fired sources to install additional pollution control equipment for NOx and SO2.

• Mercury and Air Toxics Standards. In December 2011, the EPA issued the Mercury and Air Toxics Standards (“MATS”), which sets technology-based emission limitation standards for mercury and other toxic air pollutants for coal and oil fired electric generating units with a capacity of 25 megawatts (“MW”) or more. Existing units generally

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have up to four years to comply. The MATS is subject to a pending court challenge in the U.S. Court of Appeals for the District of Columbia Circuit, and the EPA has announced that it expects to act on petitions for reconsideration of certain aspects of the MATS during 2013. The MATS may ultimately require many coal-fired sources to install additional pollution control equipment or to close.

• Regional Haze. Under the EPA's regional haze rule designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks, state implementation plans must either require designated facilities to install Best Available Retrofit Technology (“BART”) to reduce emissions that contribute to visibility problems or adopt an emissions trading program or other alternative program that provides greater reasonable progress towards improving visibility. The regional haze program, which the EPA first established in 1999, primarily affects the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. In May 2012, the EPA issued a final rule that would authorize use of the CASPR trading programs in place of source-specific BART for SO2 and/or NOx emissions from power plants, enabling states to avoid further action under their regional haze implementation plans until 2018. Although the status of the final rule is in doubt following the court decision overturning the CASPR, we expect 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 (“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 and streams. 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 and the interpretation of longstanding regulations is changed. In addition, legal challenges to regulations may impact their content and the timing 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 CWA (“404 permits”) are required to conduct dredging or filling activities in jurisdictional waters. Coal companies must secure 404 permits for the purpose of creating water impoundments, refuse disposal enhancements, refuse slurry impoundments, valley fills or for conducting certain other mining activities. Jurisdictional waters typically include ephemeral, intermittent and perennial streams. The United States Supreme Court ruled in Rapanos v. United States in 2006 that certain waters with tenuous connections to navigable waters might not be jurisdictional waters requiring 404 permits. The case did not involve disposal of mining overburden or coal processing refuse, but has implications for the mining industry. Subsequently, in December 2008 the COE and the EPA issued a joint memorandum to provide guidance to the COE regions and COE districts implementing 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. In April 2011, the COE and the EPA released draft, nonbinding guidance for public comment and announced their intent to subsequently issue a proposed rule. 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.

The COE's issuance of 404 permits is subject to the National Environmental Policy Act (“NEPA”). NEPA requires that a federal agency must take a “hard look” at any activity that may “significantly affect the quality of the human environment”. NEPA allows an initial Environmental Assessment (“EA”) to be completed to determine if a project will have a significant impact on the environment. If the EA reveals a significant impact, then the agency must prepare an Environmental Impact Statement (“EIS”), a very lengthy data collection and review process.

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.

Issues concerning 404 permitting for fills have included the adequacy of the pre-mining assessments of areas to be impacted required by the COE and conducted by the permit applicants, and the necessity at steep sloped areas of Central Appalachia to impound streams below their valley fills for the purpose of constructing sediment ponds, which both the COE and the EPA have considered to be “treatment systems” excluded from the definition of “waters of the United States” to which the CWA applies. In August 2012, following a challenge to these practices, the United States District Court for the Southern District of West Virginia upheld the COE's issuance of a 404 permit to the Company's Highland Mining subsidiary. Although it has prevailed in court, the COE is continuing to assess its protocol for evaluating the pre-mining stream conditions, as well as

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procedures used in the measurement of the success of mitigation. 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 our ability to maintain current operations and to permit new operations.

In February 2012, the COE published a final notice reissuing Nationwide Permit 21 (“NWP 21”), which had previously been used to authorize valley fills in connection with mining operations. Availability of the NWP 21 as reissued is limited to discharges with impacts not greater than a half-acre of waters, including no more than 300 linear feet of streambed. The district engineer may waive the 300-linear-foot limit by making a written determination that the discharge will result in minimal individual and cumulative adverse effects. The NWP21 also is not available for discharges associated with construction of “valley fills”, which are broadly defined as a fill structure that is typically constructed within valleys associated with steep, mountainous terrain, associated with surface coal mining activities. The NWP21 as reissued is of limited value to our operations. Accordingly, most of our 404 permits must be obtained on an individual, site-specific basis, which increases the time and cost of the overall permitting process. Further, surface coal mine permitting has been impeded by the Enhanced Surface Coal Mining Pending Permit Coordination Procedures, issued by the EPA and the COE on June 11, 2009 (“ECP”), and guidance contained in a July 2011 Memorandum entitled “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”), replacing interim guidance that was issued in April 2010. However, in two decisions in October 2011 and July 2012, in response to a court challenge by the National Mining Association and by several states, the U.S. District Court for the District of Columbia held that the EPA acted outside the scope of its authority under the CWA when it instituted the ECP and issued the Detailed Guidance without undergoing the notice and comment rulemaking process. Although the ECP and Detailed Guidance are no longer in effect, any future application of procedures similar to ECP, such as may be enacted following notice and comment rulemaking, would have the potential to delay the issuance of permits for our coal mines, or to change the conditions or restrictions imposed in those permits.

In January 2011, the EPA vetoed a federal CWA 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. In March 2012, the United States District Court for the District of Columbia found that the EPA's post-issuance “veto” of a 404 permit exceeded the EPA's authority under the Clean Water Act. The EPA has appealed this decision to the United States Court of Appeals. If the District Court's decision is ultimately overturned, 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 System Permits

The 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, potentially could create requirements for treatment systems and higher costs to comply with permit conditions. In particular, the EPA, despite having its Detailed Guidance on conductivity invalidated by a federal court, continues to seek to require states to impose conductivity or total dissolved solids (“TDS”) limits. Conductivity is a measure that reflects levels of various salts present in water. Although states have not yet begun applying conductivity or TDS limits routinely, if the EPA is successful in requiring such limits, in order to obtain new NPDES permits and renewals for coal mining in Appalachia, applicants will be required to 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 former EPA Administrator stated that these water quality standards may be difficult for most mining operations to meet. Additionally, the now overturned Detailed Guidance contained 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. We have begun to address these issues in some of our current permitting actions, but there can be no guarantee that we will be able to meet any 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. As discussed in Note 21, Legal Proceedings - Mine Water Discharge Suits, to the Company's Consolidated Financial Statements, certain of the Company's subsidiaries have been and are subject to such proceedings.

There also have been renewed efforts by the federal and state agencies to examine the coal industry's record of compliance with NPDES permit limits. This enhanced scrutiny resulted in an agreement by Massey to pay a $20 million penalty in 2008 for

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over 4,000 alleged NPDES permit violations. Subsequently, a number of our operating subsidiaries have been subject to enforcement actions, and in some cases have entered into settlements. See Note 21 to the Company's Consolidated Financial Statements.

The CWA 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 Stream 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

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.

At present, fossil fuel combustion wastes are exempt from hazardous waste regulation under RCRA. However, the failure in 2008 of an ash disposal dam in Tennessee focused attention on this issue. In May 2010, the EPA issued for public comment proposed regulations setting out two options for governing management and disposal of coal ash from coal-fired power plants. Under the more stringent option, the EPA would regulate coal ash as a “special waste” subject to RCRA subtitle C 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 regulated 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. We currently cannot predict whether these rules, once finalized, will 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.”

Coal slurry impoundment. Coal slurry consists of solid and liquid waste and is a by-product of the coal mining and preparation processes. It is a fine coal refuse and water mixture. Impoundment is for the storage of liquid and primarily noncombustible solids that are by-products of coal cleaning.

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.

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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.

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.

Southern Appalachia. Coal producing region consisting of Alabama and a portion of southeastern Tennessee.

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.

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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 68% 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 32% 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.

Risks Relating to Our Industry and the Global Economy

A substantial or extended decline in coal prices would reduce our revenues and adversely impact our earnings and the value of our coal reserves.

Our results of operations are substantially dependent upon the prices we receive for our coal. Those prices depend upon factors beyond our control (some of which are described in more detail in other risk factors below), including:

• the demand for domestic and foreign coal, which depends significantly on the demand for electricity and steel;

• the price and availability of natural gas and other alternative fuels;

• competition from other suppliers of coal and other energy sources;

• the regulatory and tax environment for our industry and those of our customers; and

• the proximity to and availability, reliability and cost of transportation and port facilities.

Sustained declines in coal prices in the United States or other countries would materially adversely affect our operating results and cash flows, as well as the value of our coal reserves. For example, because of lower prices for certain types of coal that we produce, in 2012, we reduced or halted production at certain of our mines, and could further reduce our production in the future if coal prices decline further.

Lower demand for steam coal by North American electric power generators would reduce our revenues and could further reduce the price of our steam coal.

Steam coal accounted for approximately 81% and 82% of our coal sales volume during 2012 and 2011, respectively. The majority of our sales of steam coal were to U.S. and Canadian electric power generators. That demand is affected primarily by:

• the overall demand for electricity, which is in turn influenced by the global economy and the weather, among other factors (for example, North America has experienced mild winters for the past two years, resulting in lower demand);

• the availability, quality and price of competing fuels, such as natural gas, nuclear fuel, oil and alternative energy sources such as hydroelectric power, which may change over time as a result of, among other things, technological developments;

• increasingly stringent environmental and other governmental regulations, including air emission standards for coal-fired power plants; and

• higher than normal coal inventories at many utilities.

Recently, to the extent economically feasible, many North American electric power generators have shifted from coal to natural gas-fired power plants, and we expect that new power plants that are built 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. Increasingly stringent regulations have also reduced the number of new power plants being built.Any further reduction in the amount of coal consumed by North American electric power generators would reduce the amount of steam coal that we sell and the price that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

Lower demand for metallurgical coal by U.S. and foreign steel producers would reduce our revenues and could further reduce the price of our metallurgical coal.

We produce metallurgical coal that is used in both the U.S. and foreign steel industries. Metallurgical coal accounted for approximately 19% and 18% of our coal sales volume in 2012 and 2011, respectively.  Any deterioration in conditions in the U.S. or the foreign steel industry, including the demand for steel and the continued financial viability of the industry, would reduce the demand for our metallurgical coal and could impact the collectability of our accounts receivable from U.S. or foreign steel industry customers. The demand for foreign-produced steel both in foreign markets and in the U.S. market is also dependent on factors such as tariff rates on steel. In addition, the U.S. steel industry increasingly relies on processes to make steel that do not use coke, such as electric arc furnaces or pulverized coal processes. 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

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impacting our earnings and the value of our coal reserves. Lower demand for metallurgical coal in international markets would reduce the amount of metallurgical coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

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. We also compete in international markets against coal producers in other countries. International demand for U.S. coal exports also affects coal demand in the United States. This competition may affect domestic and foreign coal prices and impact our ability to retain or attract coal customers. For example, competitors using longwall mining technology in the Illinois basin may, as a result of greater production efficiencies, be able to offer lower thermal coal prices compared to coal we produce in Central Appalachia. In addition, if the currencies of our foreign competitors decline against the U.S. dollar or against our customers' currencies, those competitors may be able to offer lower prices to our customers.

In the past, high demand for coal and attractive pricing brought new investors to the coal industry, leading to the development of new mines and added production capacity. Subsequent overcapacity in the industry has contributed, and may continue to contribute, to lower coal prices. In addition, lower coal prices set by our competitors may also put downward pressure on coal prices.

Lower demand for U.S. coal exports would reduce our foreign sales and could negatively impact our revenues and results of operations and could result in additional downward pressure on domestic coal prices.

Coal exports accounted for approximately 20% and 15% of our coal sales volume in 2012 and 2011, respectively. In addition to the factors described above, demand for U.S. coal exports is dependent upon a number of factors outside of our control, including currency exchange rates, ocean freight rates and port and shipping capacity. 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 reduce our foreign sales and negatively impact our revenues and results of operations. 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.

Economic downturns and disruptions in the global financial markets have had and could in future have a material adverse effect on the demand for and price of coal, on our sales, margins and profitability, and on our own ability to obtain financing.

In recent years, economic downturns and disruptions in the global financial markets have from time to time resulted in, 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. This occurred in particular in connection with the extreme market disruption in 2008, as well as the recent concerns about the debt burden of certain Eurozone countries and the overall stability of the euro. These disruptions, and in particular the tightening of credit in financial markets, have from time to time adversely affected our customers' ability to obtain financing for operations and resulted in a temporary decrease in demand, lower coal prices, the cancellation of some orders for our coal and the restructuring of agreements with some of our customers. Additionally, China is the world's largest importer of coal and decreases in their demand could impact the prices we receive for our export shipments. Any prolonged global, national or regional economic recession or other similar events could have a material adverse effect on the demand for and price of coal, on our sales, margins and profitability, and on our own ability to obtain financing. We are unable to predict the timing, duration and severity of any potential future disruptions in financial markets and potential future adverse economic conditions in the United States and other countries and the impact these events may have on our operations and the industry in general.

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

Our largest customer during 2012 accounted for approximately 9% of our total revenues, and sales to our ten largest customers accounted for approximately 42%. These customers may not continue to purchase coal from us as they have previously, 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.

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We may not be able to extend our existing long-term supply contracts or enter into new ones with customers, and our existing supply contracts may contain certain provisions that may reduce protection from short-term coal price volatility, 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 (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. During 2012, approximately 52% and 77% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts. As of January 25, 2013, 8% of our planned shipments for 2013 were 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. Further, our long-term contracts may sometimes prevent us from capitalizing on more favorable market prices.

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 terms less favorable to us.

In large part as a result of increasing and frequently changing regulation, as described above, electric power generators are increasingly less willing to enter into long-term coal supply contracts, instead purchasing higher percentages of coal under short-term supply contracts. This industry shift away from long-term supply contracts could adversely affect us and the level of our revenues. For example, few customers with a contractual obligation to purchase coal from us would increase the risk that we will not have a market for our production. In addition, the prices we receive in the spot market may be less than the contractual price a customer is willing to pay for a committed supply. Spot market prices also tend to be more volatile than contractual prices, which could result in decreased revenues.

In addition, price adjustment, “price reopener” and other similar provisions in long-term supply contracts may reduce the protection from short-term coal price volatility that these contracts traditionally provide. Price reopener provisions are particularly common in international metallurgical coal sales contracts. Some of our coal supply contracts 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 cases, 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 which would be uncertain. During periods of economic weakness, some of our customers may experience lower demand for their products and services and may be unwilling to take all of their contracted tonnage or request a lower price. Customers may make similar requests when market prices have dropped significantly, as has occurred recently. 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.

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

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness and financial health 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. Furthermore, 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. In recent years, downturns in the economy and disruptions in the global financial markets have, from time to time, affected the creditworthiness of our customers and limited their liquidity and credit availability.

We also have coal supply contracts with energy trading and brokering companies under which those companies sell coal to end users. These contracts involve an increased risk that we may not be able to collect payment if the creditworthiness of the trading or brokering company declines, as we typically do not have a direct contractual relationship with the end user.

Customers in other countries may be subject to other pressures and uncertainties that may affect their ability to pay, including trade barriers, exchange controls and local economic and political conditions. We derived 42% and 44% of our total revenues from coal sales made to customers outside the United States in 2012 and 2011, respectively.

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Regulatory and Legal Risks

We are subject to a number of lawsuits, including various lawsuits relating to the explosion at the Upper Big Branch mine, which, depending on the outcome, could have adverse financial effects or cause reputational harm to us.

A number of legal actions are pending relating to past safety conditions at former Massey mines, the April 2010 explosion at the Upper Big Branch mine, which we refer to as the UBB explosion, and other related matters, including accusations of securities fraud. Although in December 2011, we entered into a Non-Prosecution Agreement and settlement resolving a number of these matters (see “Legal Proceedings”), a number of legal actions remain outstanding, and it is possible that other actions may be brought in the future.

In particular, we are subject to purported class actions that allege violations of the federal securities laws, derivative actions against current and former Massey directors and officers and actions brought by certain of the families of the twenty-nine miners that died in the UBB explosion and certain employees and contractors alleging injuries as a result of the UBB explosion.

In addition, several former Massey employees have been convicted of or charged with federal criminal charges. Massey's former officers, directors and employees may continue to be subject to future actions and claims. Under the merger agreement with Massey, we agreed to leave in place and not modify provisions contained in the organizational documents of Massey and its subsidiaries and certain related indemnification agreements that grant rights to indemnification and exculpation from liabilities for acts or omissions occurring at or prior to the effective time of the Massey acquisition and related rights to the advancement of expenses in favor of any current or former director, officer, employee or agent of Massey.

The outcomes of these pending and potential cases and claims are uncertain. Depending on the outcome, these actions could have adverse financial effects or cause reputational harm to us. We may not resolve these actions favorably, may agree to settle or may not be successful in implementing remedial safety measures that may be imposed as a result of some of these actions and/or investigations.

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

Global climate change continues to attract considerable public and scientific attention, and the current administrationhas highlighted action to address climate change as a major priority of its second term. There is concern in particular about the emissions of GHGs, such as carbon dioxide and methane. Combustion of fossil fuels like coal and gas results in the creation of carbon dioxide, which is currently emitted into the atmosphere by coal and gas end users, such as coal-fired electric power generators. As a result, there have been and are expected to be numerous GHG emissions initiatives that could reduce the demand for coal, including:

• international action to extend the Kyoto Protocol through 2020 and to enact a new international treaty to take effect thereafter that would more aggressively reduce GHG emissions;

• various federal EPA initiatives, including a formal finding under the Clean Air Act that GHG emissions result in “endangerment” to public health and welfare, required annual reporting of GHG emissions; the final “tailoring rule” requiring certain large industrial facilities, including power plants, to obtain permits to emit, and to use best available control technology to curb emissions of, GHGs; and a March 2012 proposed rule to impose federal limits on GHG emissions from new power plants;

• state and regional climate change initiatives, such as the Regional Greenhouse Gas Initiative of eastern states and the Western Climate Initiative, and recent and proposed legislation and regulation in various states, including California's GHG cap-and-trade regulations, which took effect for the electricity sector on January 1, 2013 and have the objective of reducing state-wide GHG emissions to 1990 levels by 2020;

• litigation by various states and municipal entities seeking to have certain utilities, including some of our customers, reduce their emission of carbon dioxide; and

• climate change guidelines for investors and lenders (for example, guidelines announced by three of Wall Street's largest investment banks in February 2008 that 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 initiatives, as the content of proposed legislation and regulation is not yet determined and many of the new regulatory initiatives remain subject to governmental and judicial review. Given this uncertainty, the various alternatives proposed and the complex interactions between economic and environmental issues, it is difficult to predict the economic effects of these initiatives.

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However, any regulatory controls on GHG emissions are likely to impose significant costs on many coal-fired power plants and industrial boilers and could have the effect of making them unprofitable. For example, if the EPA's current rule proposal on carbon dioxide emissions becomes final, the construction of new coal-fired power plants may be economically unfeasible using currently available technology. Accordingly, some existing power generators are switching to other fuels that generate fewer emissions, some power plants have closed and others are scheduled to close, and fewer coal-fired plants are being constructed, all of which reduce demand for coal and would reduce the amount of coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

In addition, regulatory controls on allowable emissions and the price of emissions allowances have a potentially significant impact on the demand for our coal based on its sulfur content. We sell both higher sulfur and low sulfur coal. More widespread installation by power generators of technology that reduces sulfur emissions may make high sulfur coal more competitive with our low sulfur coal. Decreases in the price of emissions allowances could have a similar effect. Significant increases in the price of emissions allowances could reduce the competitiveness of higher sulfur coal compared to low sulfur coal and possibly natural gas at power plants not equipped to reduce sulfur dioxide emissions. Any of these consequences could result in a decrease in revenues from some of our operations, which could adversely affect our business and results of operations.

Other extensive environmental laws and regulations also could affect our customers, reduce the demand for coal and cause our sales to decline.

Our customers' operations are subject to extensive environmental laws and regulations relating to the regulation of emissions and discharges; the storage, treatment and disposal of wastes; and other operational permits. 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. A series of more stringent requirements may become effective in coming years, including:

• implementation of the current and more stringent proposed ambient air quality standards for sulfur dioxide, nitrogen oxides, particulate matter and ozone;

• implementation of the EPA's 2005 Clean Air Interstate Rule or a more stringent replacement rule to significantly reduce nitrogen oxide and sulfur dioxide emissions from power plants in 27 eastern states;

• implementation of the EPA's December 2011 Mercury and Air Toxics Standards, which impose stringent limits on emissions of mercury and other toxic air pollutants from electric power generators and are being phased in generally over four years; and

• more stringent EPA regulations governing management and disposal of coal ash.

See Item 1 “Business-Environmental and Other Regulatory Matters.”

These environmental laws and regulations impose significant costs on our customers, which are increasing as their requirements become more stringent. These costs make coal more expensive to use and make it a less attractive fuel source of energy for our customers. Accordingly, some existing power generators are switching to other fuels that generate fewer emissions, some power plants have closed and others are scheduled to close, and fewer coal-fired plants are being constructed, all of which reduce demand for coal and would reduce the amount of coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

The extensive regulation of the mining industry imposes significant costs on us, and future regulations or violations 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 relating to matters such as:

• controls on emissions and discharges;

• the effects of operations on surface water and groundwater quality and availability;

• the storage, treatment and disposal of wastes;

• the remediation of contaminated soil, surface and groundwater;

• surface subsidence from underground mining; and

• employee health and safety, and benefits for current and retired coal miners.

These laws and regulations are becoming increasingly stringent. For example:

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• federal and state agencies and citizen groups have increasingly focused on the amount of selenium and other constituents in our wastewater discharges, and over the past five years a number of our subsidiaries have entered into consent decrees and orders imposing penalties and requiring extensive efforts to study and reduce our discharges of selenium and other substances;

• MSHA and the state of West Virginia have implemented or proposed changes to mine safety and health requirements to impose more stringent health and safety controls, enhance mine inspection and enforcement practices, increase sanctions, and expand monitoring and reporting; and

• as described above, more stringent regulation of GHG emissions is being considered that, if expanded to cover coal mining, could increase our costs, require additional controls, or compel us to limit our current operations, particularly at our underground coal mines.

In addition, these laws and regulations require us to obtain numerous governmental permits (described in more detail below). Federal and state authorities also inspect our operations, and in response to the UBB explosion, federal and West Virginia authorities conducted special inspections of coal mines. We expect the heightened inspection intensity to continue.

We incur substantial costs to comply with the laws, regulations and permits that apply to our mining and other operations, and to address the outcome of inspections. The required compliance and actions are often time-consuming and may delay commencement or continuation of exploration or production. In addition, due in part to the 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 the violations, as well as substantial civil or criminal penalties and limitations or shutdowns of our operations. For example, in December 2011, we entered into a comprehensive settlement with MSHA in which we resolved various outstanding MSHA civil citations, violations and orders related to the UBB explosion and other matters for approximately $34.8 million (see “Legal Proceedings”). For more information concerning certain violations that have occurred, see Exhibit 95 to this Annual Report on Form 10-K for the year ended December 31, 2012.

MSHA and state regulators may also order temporarily close a mine in the event of certain violations of safety rules, accidents or imminent dangers. 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.

These factors have had and will continue to have a significant effect on our costs of production and competitive position, and as a result on our results of operations, cash flows and financial condition. New laws and regulations, as well as future interpretations or different enforcement of existing laws and regulations, may have a similar or more significant impact on us, including delays, interruptions or a termination of operations.

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 those of 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 law 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. (For example, see Item 1 “Business Environmental and Other Regulatory Matters” for a discussion of Superfund and RCRA matters.) 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 for more than our share of the contamination or other damages, or even for the entire share.

We maintain extensive coal slurry impoundments at a number of our mines. These 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 resulting damages. 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, although not regulated in the same manner as our slurry impoundments, could result in additional scrutiny of our impoundments.

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These and other 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 financial condition and results of operations.

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 regulatory permits that impose strict conditions on various environmental and safety matters in connection with coal mining. The permitting rules are complex and change over time, potentially in ways that may make our ability to comply with the applicable requirements more difficult or impractical or even preclude the continuation 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 permits or mining activities. In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.

As a result, the permitting process is costly and time-consuming, required permits may not be issued or renewed in a timely fashion (or at all), and permits that are issued may be conditioned in a manner that may restrict our ability to conduct our mining activities efficiently. We may also be required under certain permits to provide authorities data on the impact on the environment of proposed exploration for or production of coal.

In particular, certain of our activities require a Section 404 dredge and fill permit from the Army Corps of Engineers (the “COE”). In recent years, the Section 404 permitting process has been subject to increasingly stringent regulatory and administrative requirements and a series of court challenges, which have resulted in increased costs and delays in the permitting process. The COE has taken action to restrict the availability of its Nationwide Permit 21, and the EPA has announced a new rulemaking that would further address the circumstances when a Section 404 permit is needed. Increasingly stringent requirements governing coal mining also are being considered or implemented under the Surface Mining Control and Reclamation Act, the National Pollution Discharge Elimination System permit process, and various other environmental programs. It is unclear what impact these and other developments 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.

Many of our permits are subject to renewal from time to time, and renewed permits may contain more restrictive conditions than our existing permits. For example, many of our permits governing surface stream and groundwater discharges and impacts will be subject to new and more stringent conditions to address various new water quality requirements upon renewal over the next several years. To obtain renewed 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 continue to operate the facility as planned or at all. Although we have no estimates at this time, our costs to satisfy these conditions could be substantial.

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 delay or prevent commencing or continuing exploration or production operations, and as a result, adversely affect our coal production, cash flows and profitability.

Any failure by third parties to fulfill their indemnification obligations to us could increase our liabilities and adversely affect our results of operations, financial position and cash flows.

In the acquisition agreements entered into with the sellers of the companies that we have acquired (including Coastal Coal Company, Nicewonder and Progress), and agreements that companies we have acquired entered into prior to our acquisition of them, such as the Distribution Agreement entered into by Massey and Fluor as of November 30, 2000 in connection with the spin-off of Fluor by Massey (the “Distribution Agreement”), the respective sellers and, in some cases, their parent companies or other parties, agreed to retain responsibility for and indemnify 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 obligations of those other parties to indemnify us with respect to their retained liabilities will continue for a substantial period of time and in some cases indefinitely. In other cases, the sellers' indemnification obligations continue for a shorter period of time. Certain indemnification obligations are also subject to deductible amounts and do 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 or other applicable party to satisfy their obligations with respect to claims and retained liabilities covered by the applicable agreements or breaches of its representations and warranties could have an

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adverse effect on our results of operations and financial position if claimants successfully assert that we are liable for those claims and/or retained liabilities.

Recently, litigation has been commenced between Fluor and the purchasers of Fluor's prior business regarding the purchasers' obligation to indemnify Fluor against claims and judgment arising out of that business. To the extent the litigation results in a determination that Fluor is not entitled to indemnification from the purchasers, Fluor's ability to satisfy all or some of its indemnification obligations with respect to Alpha's subsidiaries under the Distribution Agreement may be negatively affected. See “Legal Proceedings-Other Legal Proceedings.”

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

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

Risks Relating to Our Operations

A decline in demand for metallurgical coal would limit our ability to sell our high quality steam coal as higher priced metallurgical coal, which would reduce our revenues and profitability, and could affect the economic viability of some of our mines with higher operating costs.

We are able to mine, process and market some of our coal reserves as either metallurgical coal or high quality steam coal. In deciding our approach to these reserves, management assesses the conditions in the metallurgical and steam coal markets, including factors such as the current and anticipated future market prices of steam coal and metallurgical coal, the generally higher price of metallurgical coal as compared to steam coal, the lower volume of saleable tons that results when producing coal for sale in the metallurgical market rather than the steam market, the increased costs of producing metallurgical coal, the likelihood of being able to secure a longer term sales commitment for steam coal and our contractual commitments to deliver different types of coal to our customers. A decline in demand for metallurgical coal relative to steam coal could cause us to shift coal from the metallurgical market to the steam market, thereby reducing our revenues and profitability.

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 all the production from these mines had to be sold as steam coal, those mines would not be economically viable and would likely need to be closed, which could lead to asset impairment charges and accelerated reclamation costs, as well as reduced revenue and profitability.

Certain provisions in our long-term supply contracts may result in economic penalties upon our failure to meet specifications.

Coal supply agreements 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. Following the UBB explosion, Massey notified certain of its customers that it was declaring force majeure under certain of its sales contracts impacted by the lost tonnage resulting from the explosion and subsequent shutdown at the Upper Big Branch mine. It is possible that certain of these customers may ultimately challenge the declaration of force majeure or contest whether they received timely or proper allocations or amounts of coal following the declaration of force majeure.

In addition, 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, moisture 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. Further, some of our contracts allow our customers to terminate the contract in the event of regulatory changes that restrict the use or type of coal the customer may use at its facilities or increase the price of coal or the cost of using coal beyond specified limits.

As a result of these issues, we may not achieve the revenue or profit we expect to achieve from our long-term sales commitments.

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

A majority of our coal mining operations are conducted in underground mines, with the balance 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:

• 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 or increased costs of mining, processing and loading equipment and parts and other materials from suppliers;

• the proximity to and availability, reliability and cost of transportation facilities;

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

• accidental mine water discharges;

• coal slurry releases and impoundment failures;

• unexpected mine safety accidents, including fires and explosions from methane and other sources;

• a shortage of skilled labor;

• strikes and other labor-related interruptions; and

• the termination of material contracts by state or other governmental authorities.

If any of these or other 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 would adversely affect our operating results and could result in impairments to our assets.

We maintain insurance policies that provide limited coverage for some, but not all, of these risks. Even where covered by insurance, these risks may not be fully covered and insurers may contest their obligations to make payments. Failures by insurers to make payments could have a material adverse effect on our cash flows, results of operations or financial condition.

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.

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 or, if available, may not be able to be mined at costs comparable to those of the depleting mines. In addition, 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.

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, and we may be required to make increased contributions due to plan underfunding status.

We contribute to a multi-employer defined benefit pension plan administered by the UMWA. In the event of a partial or complete withdrawal by us from a multi-employee plan that is underfunded, we would be liable for a proportionate share of that 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. If any other contributing employer withdraws from an underfunded plan, and that 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

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remaining contributing employers, would be liable for our proportionate share of the plan's unfunded vested benefits, which would increase our liability in the case of withdrawal by contributing subsidiaries.

The Pension Protection Act of 2006 (“PPA”) requires a minimum funding ratio of 80% be maintained for a multi-employer plan. 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 be deemed to be “critical”; in either case, it will be subject to additional funding requirements. In October 2012, we received notice that the plan was considered to be in seriously endangered status for the July 1, 2012 plan year, and the plan was projected to have an accumulated funding deficiency by the plan year beginning July 1, 2018. In 2012, a funding improvement plan was sent to all participating companies for adoption. The goals of the funding improvement plan are to improve the funded status and to avoid an accumulated funding deficiency for all plan years in the funding improvement period. The funding improvement plan provides increased contribution rates beginning in 2017. The Plan's funded status is reviewed annually by the certifying actuary. If the funded status does not improve prior to the beginning of 2017, the increase in contribution rates could be substantial, which 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. Generally, a plan with a funding ratio below the prescribed target is subject to additional contributions requirements (amortization of funding shortfalls). Furthermore, any plan with a funding ratio of less than 80% will be deemed at risk and will be subject to even higher funding requirements. In addition, the value of existing assets held in our pension trust is affected by changes in the economic environment. The volatile financial markets in 2008 and 2009 caused investment income and the value of the investment assets held in our pension trust to decline. As a result, depending on economic recovery and growth in the value of our invested assets, we may be required to make significant cash contributions into the pension trust in order to comply with the funding requirements of the PPA, which could have a material effect on our financial condition, results of operations and cash flows. In 2012, we contributed $0.5 million to our pension plans. We currently expect to make contributions in 2013 for our defined benefit retirement plans up to $20.0 million to maintain a funding ratio of at least 80%.

As of December 31, 2012, our annual measurement date, our defined benefit pension plans were underfunded by $207.1 million. These defined benefit 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 defined benefit pension plan under limited circumstances. If our U.S. defined benefit 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, which could have a material effect on our financial condition, results of operations and cash flows.

Expenditures for certain employee benefits 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, 2012, as reflected in Note 18 to our Consolidated Financial Statements, included $1,006.2 million of postretirement obligations, $231.2 million of defined benefit pension and supplemental employee retirement plan obligations,$180.0 million of self-insured workers' compensation obligations and $141.8 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 required 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 effect 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.

Cybersecurity attacks, natural disasters and other similar crises or disruptions may negatively affect our business, financial condition and results of operations.

Our business may be impacted by disruptions such as cybersecurity attacks or failures, threats to physical security, and extreme weather conditions or other natural disasters. These disruptions or any significant increases in energy prices that follow 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.

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Federal 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 of providing 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 expected to extend through 2018. In the short term, our healthcare costs could increase due to, among other things, an increase in 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 on annual dollar limits per covered individual. In the long term, our healthcare costs could increase due to, among other things, an excise tax on “high cost” plans and the elimination of annual dollar limits per covered individual.

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 governmental agencies will provide additional regulations or interpretations concerning the application of this excise tax. We will continue to evaluate the impact of the PPACA, including any new regulations or interpretations, in future periods.

If the assumptions underlying our accruals for reclamation and mine closure obligations prove to be 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 total $856.7 million as of December 31, 2012, are based upon permit requirements and our historical experience, and depend on a number of variables, including the estimated future asset retirement costs, estimated proven reserves, assumptions involving profit margins of third party contractors, inflation rates and discount rates. Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results and financial position could be adversely affected.

Estimates of our economically recoverable coal reserves involve uncertainties, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs, decreased profitability and asset impairments.

We base our estimates of our economically recoverable coal reserves on engineering, economic and geological data assembled and analyzed by our staff, including various engineers and geologists, and periodically reviewed by outside firms. Our estimates as to the quantity and quality of the coal in our reserves are updated annually to reflect production of coal from the reserves and new drilling, engineering or other data. These estimates depend upon a variety of factors and assumptions, many of which involve uncertainties and factors beyond our control and may vary considerably from actual results, such as:

• geological and mining conditions that may not be fully identified by available exploration data or that may differ from experience in current 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 about coal prices, operating costs, mining technology improvements, development costs and reclamation costs.

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. In addition, actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our reserves may vary materially from estimates. Accordingly, our estimates may not accurately reflect our actual reserves. Any inaccuracy in our reserve estimates could result in lower than expected revenues, higher than expected costs, decreased profitability and asset impairments.

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 is not verified at all. Accordingly, actual or alleged defects in title or boundaries may exist, which may result in the loss of our right

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to mine on the property or in unanticipated costs to obtain leases or mining contracts to allow us to conduct our mining operations on the property, which could adversely affect our business and profitability. In addition, from time to time, the rights of third parties for competing uses of adjacent, overlying or underlying lands, such as oil and gas activity, coalbed methane, 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. Furthermore, some leases require us to produce a minimum quantity of coal and pay minimum production royalties. If those requirements are not met, the leasehold interest may terminate.

Decreased availability or increased costs of key equipment and materials could impact our cost of production and decrease our profitability.

We depend on reliable supplies of mining equipment, replacement parts and materials such as explosives, diesel fuel, tires and magnetite. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies. Any significant reduction in availability or increase in cost of any mining equipment or key supplies could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows.

In addition, the prices we pay for these materials are strongly influenced by the global commodities market. Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives and diesel and other liquid fuels. Some materials, such as steel, are needed to comply with regulatory requirements. A rapid or significant increase in the cost of these commodities could increase our mining costs because we have limited ability to negotiate lower prices, and in some cases, do not have a ready substitute.

Disruptions in transportation services and increased transportation costs could impair our ability to supply coal to our customers and adversely affect our business.

In 2012, 70% 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, 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 in the rail transportation services we use and we are unable to find alternatives, our business could be adversely affected. Some of our operations are serviced by a single rail carrier. Due to the difficulty in arranging alternative transportation, these operations are particularly at risk to disruptions, capacity issues or other difficulties with that carrier's transportation services, which could adversely impact our revenue and return on investment from these operations.

We also depend upon trucks, beltlines, ocean vessels and barges to deliver coal to our customers. In addition, much of our eastern coal is transported from our mines to our loading facilities by trucks owned and operated by third parties. Disruption of any of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, terrorist attacks and other events could impair our ability to supply coal to our customers, resulting in decreased shipments and revenue. Disruption in shipment 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.

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 revenues and earnings. Because transportation costs represent a significant portion of the total cost of coal for our customers, increases in transportation costs could also reduce overall demand for coal or make our coal production less competitive than coal produced from other sources.

Because we purchase coal to be blended and resold with coal that we produce, disruption in supplies of coal produced by third parties could impair our ability to fill customers' orders or increase our costs.

We sold 1.9 million tons of coal purchased from third parties during 2012, representing approximately 1.8% of our total coal sales volume during 2012. 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 a portion of the coal that we purchase from third parties prior to resale. The availability of the coal we purchase 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 purchased coal could impair our ability to fill our customers' orders or require us to pay higher prices to obtain the required coal from other sources. Any increase in the prices we pay for purchased coal could increase our costs and therefore lower our earnings.

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

Approximately 89% of our 2012 coal production came from mines operated by union-free employees, and approximately89% of our workforce is union-free, as of December 31, 2012. However, under the National Labor Relations Act, employees have the right at any time 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.

Certain of our subsidiaries have wage agreements with the UMWA or other unions that expire at various times. Certain of our idled operations have wage agreements that can be terminated either by us or the union with notice, which could be a risk if those operations become active in the future. As is the case with our union-free operations, the union-represented employees could strike, which would disrupt our production, increase our costs and disrupt shipments of coal to our customers, and could result in the closure of affected mines, all of which could reduce our profitability.

Past and future acquisitions and other strategic transactions involve a number of risks, any of which could result in a material adverse effect on our business, financial condition or results of operations.

Our ability to grow depends in part on our ability to identify, negotiate, complete and integrate suitable acquisitions. In the past five years, we have completed several significant acquisitions, including the Massey Acquisition, and several smaller acquisitions, joint ventures and investments. Our ability to complete these transactions is subject to the availability of attractive targets that can be successfully integrated into our existing business and that will provide us with complementary capabilities, products or services on terms acceptable to us, as well as general market conditions, among other things.

Risks inherent in acquisition and other strategic transactions include:

• uncertainties in assessing the value, strengths, and potential profitability, and identifying the extent of all weaknesses, risks, contingent and other 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 due to inaccurate assumptions underlying estimates of expected cost savings, the deterioration of general industry and business conditions, unanticipated legal, insurance and financial compliance costs, or other factors;

• the ability of management to manage successfully our exposure to pending and potential litigation and regulatory obligations;

• unanticipated increases in competition that limit our ability to expand our business or capitalize on expected business opportunities, including retaining current customers; and

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

The ultimate success of an acquisition or other strategic transaction will depend in part on our ability to continue to realize the anticipated synergies, business opportunities and growth prospects from combining the acquired businesses with ours. We may not be able to successfully integrate the companies, businesses or properties that we acquire. Problems that could arise from the integration of the acquired business may involve:

• coordinating management and personnel and managing different corporate cultures;

• applying our Running Right program at acquired mines and facilities;

• establishing, testing and maintaining effective internal control processes and systems of financial reporting to the acquired business, particularly in the case of private company acquisitions;

• the diversion of our management's and our finance and accounting staff's resources and time commitments, and the disruption of either our or the acquired company's ongoing businesses;

• tax costs or inefficiencies, and

• inconsistencies in standards, information technology systems, procedures or policies.

Any one or more of these factors could cause us not to realize the benefits anticipated from a transaction, adversely affect our ability to maintain relationships with clients, employees or other third parties or reduce our earnings.

Moreover, any acquisition or other strategic transaction we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. Future transactions 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

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period as defined in current accounting standards, to be recorded in current period earnings, which could affect our results of operations.

We may incur additional goodwill impairment charges which may require us to record a significant charge to earnings.

In accordance with U.S. generally accepted accounting principles (“GAAP”), we are required to assess our goodwill to determine if it is impaired on an annual basis and more frequently in the event of circumstances indicating potential impairment. These circumstances could include a decline in our actual or expected future cash flows or income, a significant adverse change in the business climate or in our industry, or a decline in market capitalization, among others. If our goodwill testing indicates that impairment has occurred, we are required to record a non-cash impairment charge for the difference between the carrying value of the goodwill and the implied fair value of the goodwill in the period the determination is made. For example, we recorded impairment charges of $1,713.5 million during the year ended December 31, 2012 to reduce the carrying value of goodwill to its implied fair value for certain of our reporting units in Eastern and Western Coal Operations. We continue to carry goodwill on our balance sheet, and it is possible that in future, we may be required to record additional impairment charges for our goodwill. These charges could be significant, which could have a material adverse effect on our business, results of operations or financial condition.

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 in a cost-effective manner coal reserves of the quality our customers need. Although we have coal reserves that we believe will support current production levels for more than 20 years, we have not yet developed the mines for all our reserves. We may not be able to mine all of our reserves as profitably as we do at our current operations. In addition, in order to develop our reserves, we must receive various governmental permits. As discussed above, some of these permits are becoming increasingly more difficult and expensive to obtain and the review process continues to lengthen. We may be unable to obtain the necessary permits on terms that would permit us to operate profitably or at all.

Because our reserves are depleted as we mine our coal, our future success and growth depend in part on our ability to acquire additional coal reserves that are economically recoverable. Our planned development projects and acquisition activities may not result in significant additional reserves, and we may not succeed in developing new mines or expanding existing mines beyond our existing reserves. Replacement reserves may not be available when required or, if available, may not be able to be mined at costs comparable to those 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 those mines. Our ability to acquire other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates available on commercially reasonable terms, among other factors. 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, and our goodwill may become impaired.

Disruptions in supplies of coal from mines operated by third party contractors could impair our ability to fill customers' orders or increase our costs.

We use third-party contractors to operate some of our mines. Operational difficulties at these mines, increased competition 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. Disruption in our supply of contractor-produced coal could impair our ability to fill our customers' orders or require us to pay higher prices obtain the required coal from other sources. Any increase in the prices we pay for contractor-produced coal could increase our costs and therefore lower our earnings.

Changes in 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 some of our coal forward purchase and sales agreements as derivative instruments. We also use enter into commodity swap and option agreements for a portion of our diesel fuel needs to reduce the risk that changes in the market price of diesel fuel can have on our operations. Some of these agreements have not been designated as qualifying cash flow hedges, so we are required

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to record changes in fair value of these derivative instruments in earnings. These changes in fair value can have a significant non-cash impact on our earnings from period to period.

Our hedging activities for diesel fuel 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 needs. As of December 31, 2012, we had financial swap contracts with respect to approximately 53% and 39% of our calendar year 2013 and 2014 expected diesel fuel needs, respectively. While our hedging strategy provides us protection in the event of price increases for diesel fuel, it may also prevent us from the benefits of price decreases. If prices for diesel fuel decrease significantly below our swap prices, it could have a material effect on our financial condition, result of operations and cash flows. We are also exposed to counterparty risk related to our swap counterparties.

Risks Relating to Our Liquidity

Our substantial indebtedness exposes us to various risks.

At December 31, 2012, we had $3,449.9 million of indebtedness outstanding before discounts applied for financial reporting, representing 41% of our total capitalization, of which $1,266.7 million will mature in the next three years. In addition, at December 31, 2012, we had $0.3 million of letters of credit outstanding under our credit facility and $160.2 million of letters of credit outstanding under our accounts receivable securitization facility.

Our substantial indebtedness could have important consequences to our business. For example, it could:

• make it more difficult for us to pay or refinance our debts as they become due during adverse economic and industry conditions because any related decrease in revenues could cause us to not have sufficient cash flows from operations to make our scheduled debt payments;

• force us to seek additional capital, restructure or refinance our debts, or sell assets;

• cause us to be less able to take advantage of significant business opportunities such as acquisition opportunities and to react to changes in market or industry conditions;

• cause us to use a portion of our cash flow from operations for debt service, reducing the availability of working capital and delaying or preventing investments, capital expenditures, research and development and other business activities;

• cause us to be more vulnerable to general adverse economic and industry conditions;

• expose us to the risk of increased interest rates because certain of our borrowings, including borrowings under our credit facility, will be at variable rates of interest;

• make us more highly leveraged than some of our competitors, which could place us at a competitive disadvantage;

• limit our ability to borrow additional monies in the future to fund working capital, capital expenditures and other general corporate purposes; and

• result in a downgrade in the credit rating of our indebtedness, which could harm our ability to incur additional indebtedness and result in more restrictive borrowing terms, including increased borrowing costs and more restrictive covenants, all of which could affect our internal cost of capital estimates and therefore impact operational and investment decisions.

Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at that time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations, and the terms of existing or future debt instruments may restrict us from adopting some of these alternatives.

Our ability to make the required payments on our indebtedness is dependent on the cash flow generated by our subsidiaries, which may be constrained by legal, contractual, market or operating conditions from paying us dividends.

We will be dependent to a significant extent on the generation of cash flow by our subsidiaries and their ability to make that cash available to us, by dividend, debt repayment or otherwise. These subsidiaries may not be able to, or be permitted to, make distributions to enable us to make payments in respect of our indebtedness. Each of these subsidiaries is a distinct legal entity and, under certain circumstances, legal and contractual restrictions, as well as the financial condition and operating requirements of our subsidiaries, may limit our ability to obtain cash from our subsidiaries. In the event that we do not receive distributions from our subsidiaries, we may be unable to make required payments of principal, premium, if any, and interest on our indebtedness.

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We may incur more debt which could further exacerbate the risks associated with our significant indebtedness.

We may incur additional indebtedness in the future under the terms of our credit facility and the indentures governing our debt securities. Our credit facility provides for a revolving line of credit of up to $1.0 billion, with no borrowings outstanding as of December 31, 2012. 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 bonding obligations for our mines.

The terms of our credit facilities and the indentures governing our notes 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 facilities and the indentures governing our notes contain 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, complying 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 notes. 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 reason, our business, financial condition, results of operations and cash flows could be materially and adversely affected. Other covenants must be met for us to be able to access available capacity under our credit facility, including the maintenance of $500 million of liquidity through the end of 2014. If we are unable to access undrawn capacity when we need it, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

Certain terms of our 2.375% convertible notes due 2015 and our 3.25% convertible notes due 2015 may adversely impact our liquidity.

Upon conversion of our 2.375% convertible notes due 2015 and our 3.25% convertible notes due 2015, we will be required to make certain cash payments to holders of converted notes. As a result, the conversion of the convertible notes may significantly reduce our liquidity, and we may not have sufficient funds to make these payments. Our failure to make these payments with respect to our convertible notes would cause a default under the relevant indentures and a cross default under our other indentures and our credit facility.

Failure to maintain capacity for required letters of credit could limit our available borrowing capacity under our credit facilities, 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, 2012, we had $160.5 million of letters of credit in place, of which $0.3 million was outstanding under our credit facility and $160.2 million was outstanding under our A/R 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 $1.0 billion, all of which can be used to issue letters of credit, and our accounts receivable securitization facility provides for the issuance of up to $275.0 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 credit 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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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, may demand less favorable terms upon renewal or may impose new or increased collateral requirements. We also maintain self-bonding in certain states, and the relevant state regulators may determine that we are no longer eligible for that status, which would require us to acquire additional surety bonds from third parties. Those events could result from a variety of factors including, without limitation:

• a significant decline in our financial position or creditworthiness;

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

• restrictions on the availability of collateral for current and future third-party surety bond issuers under the indentures governing our outstanding debt and under our credit agreements;

• the exercise by third-party surety bond issuers of their right to refuse to renew the surety or to require collateral for new or existing bonds; and

• a determination by state regulators that a change to our self-bonding status is necessary to protect the state's interests.

We have discussions from time to time, including recently, with state regulators regarding our self-bonding status and with surety bond providers regarding our existing and current surety bonds. In addition, if the financial markets experience the instability and volatility that they did in the recent past, 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.

A failure to maintain our self-bonding status, difficulty in acquiring surety bonds or additional collateral requirements would increase our costs and likely require greater use of our credit facility, A/R Facility or alternative sources of funding for this purpose, which would reduce our liquidity. If we were to be unable to provide the financial assurance that is required by state and federal law to secure our reclamation and coal lease obligations, our ability to mine or lease coal and, as a result, our results of operations could be adversely affected.

We may be unable to repurchase our debt if we experience a change of control.

Under certain circumstances, we will be required, under the terms of the indentures governing our various series of notes, to offer to purchase all of the outstanding notes of each series at either 100% or 101%, as the case may be, of their principal amount if we experience a change of control. If a change of control were to occur, we may not have sufficient funds to purchase our various series of notes or any other securities that we would be required to offer to purchase. We also might not be able to obtain additional financing to fund those purchases. Our failure to repurchase the notes upon a change of control would cause a default under the relevant indentures and a cross default under our other indentures and our credit facility. A change of control (as defined for purposes of our credit facility) is also an event of default under the credit facility that would permit lenders to accelerate the maturity of certain borrowings. If that were to occur, we may not be able to replace our credit facility on terms equal to or more favorable than the current terms, or at all. Any of our future debt agreements may contain similar provisions as our existing indentures or credit facility.

Risks Relating to Our Common Stock

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 convertible notes, could dilute the interests of our existing stockholders and could cause the market price for our common stock to decline. We may issue equity or equity-lined securities in the future for a number of reasons, including to finance our operations and business strategy, adjust our ratio of debt to equity, satisfy claims or obligations or for other reasons. 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.

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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 the initiation of dividends. 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.

Provisions in our organizational documents and the instruments governing our debt 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 the issuance of 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 provisions may have the effect of delaying or deterring a change of control of our Company, and could limit the price that certain investors might be willing to pay in the future for shares of our common stock.

If a “fundamental change” (as defined in the indentures 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 indentures governing our 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 indentures governing our senior notes) occurs, holders of the senior notes will have the right to require us to repurchase all or a portion of their 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

“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. “Probable 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 we retained. 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.

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Since November 2004, we have retained third party consultants to verify reserves for our major 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 are 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 using 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.

We estimate that, as of December 31, 2012, we owned or leased total proven and probable coal reserves of approximately 4,570.9 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 4,570.9 million tons, approximately 2,344.9 million tons were assigned reserves that we expect to be mined in future operations. Approximately 2,226.0 million tons were unassigned reserves that we are holding for future development. All of our reserves in Wyoming are assigned. Approximately 69% of our reserves are classified as high Btu coal (coal delivered with an average heat value of 12,500 Btu per pound or greater). Approximately 63% of our reserves have sulfur content of less than 1%.

As with most coal-producing companies that operate in Appalachia, 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, 2012, 710.6 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, 2012, of 3,060.5 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, 2012, 39.8 million tons of reserves are owned and require no royalty or per-ton payments. Our remaining Wyoming reserve holdings at December 31, 2012, of 731.7 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, 2012 were 28.3 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 summarizes, by location, our proven and probable coal reserves as of December 31, 2012.

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Reportable Segment	Coal Basin	Location	Total Recoverable Reserves Proven & Probable (1)	Proven Reserves		Probable Reserves
East	CAPP	Virginia, West Virginia, Kentucky	2,830.7	1,861.6		969.1
	NAPP	Pennsylvania	940.4	593.8		346.6
West	Powder River Basin	Wyoming	771.5	752.9		18.6
	Totals from active operations		4,542.6	3,208.3		1,334.3
	Percentages from active operations			71	%	29	%
N/A	Illinois Basin	Illinois	28.3	20.3		8.0
	Total from all operations		4,570.9	3,228.6		1,342.3
	Percentage from all operations			71	%	29	%

The following table provides the “quality” (sulfur content and average Btu content per pound) of our proven and probable coal reserves by location as of December 31, 2012.

			Recoverable Reserves Proven & Probable (1)	Sulfur Content						Average BTU
Reportable Segment	Coal Basin	Location		<1%		1.0% - 1.5%		>1.5%		>12,500		<12,500
East	CAPP	Virginia, West Virginia, Kentucky	2,830.7	1,985.8		625.9		219.0		2,293.2		537.5
	NAPP	Pennsylvania	940.4	110.2		47.2		783.0		844.7		95.7
West	Powder River Basin	Wyoming	771.5	771.5		—		—		—		771.5
	Totals from active operations		4,542.6	2,867.5		673.1		1,002.0		3,137.9		1,404.7
	Percentages from active operations			63	%	15	%	22	%	69	%	31	%
N/A	Illinois Basin	Illinois	28.3	—		—		28.3		—		28.3
	Total from all operations		4,570.9	2,867.5		673.1		1,030.3		3,137.9		1,433.0
	Percentage from all operations			63	%	15	%	22	%	69	%	31	%

The following table summarizes, by location, 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, 2012.

			Recoverable Reserves Proven & Probable (1)
Reportable Segment				Total Tons				Total Tons
	Coal Basin	Location		Assigned(2)		Unassigned(2)		Owned		Leased		Coal Type(3)
			(In millions of tons)
East	CAPP	Virginia, West Virginia, Kentucky	2,830.7	1,392.5		1,438.2		259.0		2,571.7		Steam and Metallurgical
	NAPP	Pennsylvania	940.4	180.9		759.5		451.6		488.8		Steam and Metallurgical
West	Powder River Basin	Wyoming	771.5	771.5		—		39.8		731.7		Steam
	Total from active operations		4,542.6	2,344.9		2,197.7		750.4		3,792.2
	Percentage from active operations			52	%	48	%	17	%	83	%
N/A	Illinois Basin	Illinois	28.3	—		28.3		—		28.3		Steam
	Total from all operations		4,570.9	2,344.9		2,226.0		750.4		3,820.5
	Percentage from all operations			51	%	49	%	17	%	83	%

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⁽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.

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⁽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⁾  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 at Wabash 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 shipping points as of December 31, 2012:

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

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Item 3. Legal Proceedings

For a description of the Company’s legal proceedings, see Note 21 to the Consolidated Financial Statements contained elsewhere in this Annual Report on Form 10-K, which is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Annual Report on Form 10-K.

PART II

Item 5. Market for Registrant’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.

2012	High	Low
First Quarter	$23.68	$14.54
Second Quarter	$17.30	$7.46
Third Quarter	$9.74	$5.28
Fourth Quarter	$10.17	$6.22

2011	High	Low
First Quarter	$68.05	$49.58
Second Quarter	$61.66	$40.65
Third Quarter	$47.25	$17.65
Fourth Quarter	$29.29	$15.49

As of December 31, 2012, there were 5,693 registered holders of record of our common stock. 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

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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 four indices, the S&P 500 Index, the S&P 400 Index, the Russell 3000 Index and the Bloomberg US Coal Index. In addition, the stock performance graph includes the dates of the Foundation Merger (July 31, 2009) and the Massey Acquisition (June 1, 2011).

The graph assumes that:

• you invested $100 in Old Alpha common stock and in each index at the closing price on December 31, 2007;

• all dividends were reinvested; and

• you continued to hold your investment through December 31, 2012.

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.

_______________________________

* $100 invested on 12/31/07 in stock or index, including reinvestment of dividends.

Fiscal year ending December 31

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	12/31/2007		12/31/2008		7/31/2009		12/31/2009		12/31/2010		6/1/2011		12/31/2011		12/31/2012
Alpha Natural Resources	$	100.00	$	49.85	$	102.56	$	133.56	$	184.82	$	164.41	$	62.90	$	29.99
S&P 500	$	100.00	$	61.51	$	67.25	$	75.94	$	85.65	$	89.53	$	85.65	$	97.13
S&P 400*	$	100.00	$	62.72	$	73.18	$	84.67	$	105.72	$	113.65	$	102.44	$	118.90
Russell 3000	$	100.00	$	61.30	$	67.89	$	76.91	$	88.26	$	92.65	$	87.44	$	99.66
Bloomberg US Coal Index	$	100.00	$	31.03	$	40.30	$	54.93	$	72.74	$	69.66	$	38.74	$	27.35

* The S&P 400 Index has been included above as our stock was moved from the S&P 500 Index to the S&P 400 Index during 2012.

Repurchase of Common Stock

On May 19, 2010, the Board of Directors authorized a share repurchase program, which permitted us to repurchase up to $125 million of our outstanding common stock, par value $0.01 per share (“Shares”).  The program enabled us to repurchase Shares from time to time, as market conditions warrant. The program was completed during 2011.  On August 22, 2011, the Board of Directors authorized an additional share repurchase program, which permits us to repurchase up to $600 million of 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 2012.

	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased  as Part of Publicly Announced Share Repurchase Programs (2)	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Programs (000’s omitted) (3)
October 1, 2012 through October 31, 2012	4,318	$	7.48	—	$	500,002
November 1, 2012 through November 30, 2012	43,167	$	8.83	—	$	500,002
December 1, 2012 through December 31, 2012	12,469	$	8.69	—	$	500,002
	59,954			—	$	500,002

_________________________________ 

⁽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, 2012, the Company issued 157,717 shares of common stock to employees upon vesting of restricted stock and restricted stock units and repurchased 59,954 shares of common stock to satisfy the employees’ minimum statutory tax withholdings. 

⁽²⁾  On August 22, 2011, the Board of Directors authorized the company to repurchase up to $600 million of common shares. Under this program, we may repurchase shares from time to time on the open market or in privately negotiated transactions, including structured or accelerated transactions, at prevailing prices as permitted by securities laws and other legal requirements, and subject to market conditions and other factors. To facilitate repurchases, we make purchases pursuant to one or more trading plans under Rule 10b5-1 of the Exchange Act, which allow us to repurchase shares during periods when we otherwise might be prevented from doing so under insider trading laws or because of self-imposed trading blackout periods. This program may be discontinued at any time.

⁽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 opportunities.

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, 2012 and 2011, and for the years ended December 31, 2012, 2011, and 2010 have been derived from the audited Consolidated Financial Statements and related Notes thereto of Alpha Natural Resources, Inc. and subsidiaries included elsewhere in this Annual Report on Form 10-K. You should read the following table in conjunction with the

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Consolidated Financial Statements and related Notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this Annual Report on Form 10-K.

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.

On June 1, 2011, we completed our acquisition of Massey Energy Company (“Massey”). Our consolidated results of operations for the year ended December 31, 2011 include Massey’s results of operations for the period June 1, 2011 through December 31, 2011. Our consolidated results of operations for the years ended December 31, 2010, 2009 and 2008 do not include amounts related to Massey’s results of operations.

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,
	2012			2011(9)			2010			2009			2008
	(In thousands)
Statements of Operations Data:
Revenues:
Coal revenues	$	6,015,696		$	6,189,434		$	3,497,847		$	2,210,629		$	2,140,367
Freight and handling revenues	761,928			662,238			332,559			189,874			279,853
Other revenues (1)	197,260			256,009			86,750			95,004			48,533
Total revenues	6,974,884			7,107,681			3,917,156			2,495,507			2,468,753
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)	5,004,516			5,080,921			2,566,825			1,616,905			1,627,960
Gain on sale of coal reserves	—			—			—			—			(12,936		)
Freight and handling costs	761,928			662,238			332,559			189,874			279,853
Other expenses	45,432			142,709			65,498			21,016			91,461
Depreciation, depletion and amortization	1,037,575			770,769			370,895			252,395			164,969
Amortization of acquired intangibles, net	(70,338		)	(114,422		)	226,793			127,608			—
Selling, general, and administrative expenses (exclusive of depreciation and amortization shown separately above)	209,788			382,250			180,975			170,414			71,923
Asset impairment and restructuring(2)	1,068,906			—			—			—			—
Goodwill impairment(3)	1,713,526			802,337			—			—			—
Total costs and expenses	9,771,333			7,726,802			3,743,545			2,378,212			2,223,230
Income (loss) from operations	(2,796,449		)	(619,121		)	173,611			117,295			245,523
Other income (expense):
Interest expense	(198,147		)	(141,914		)	(73,463		)	(82,825		)	(39,812		)
Interest income	3,373			3,978			3,458			1,769			7,351
Gain (loss) on early extinguishment of debt	773			(10,026		)	(1,349		)	(5,641		)	(14,702		)
Gain on termination of Cliffs’ merger, net	—			—			—			—			56,315
Miscellaneous income (expense), net	3,306			635			(821		)	3,186			(3,834		)
Total other (expense) income, net	(190,695		)	(147,327		)	(72,175		)	(83,511		)	5,318
Income (loss) from continuing operations before income taxes	(2,987,144		)	(766,448		)	101,436			33,784			250,841
Income tax (expense) benefit	549,996			35,906			(4,218		)	33,023			(52,242		)
Income (loss) from continuing operations (4)	$	(2,437,148	)	$	(730,542	)	$	97,218		$	66,807		$	198,599

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	Years Ended December 31,
	2012			2011(9)			2010			2009			2008
Earnings (Loss) Per Share Data:
Basic earnings (loss) per common share:
Income (loss) from continuing operations attributable to Alpha Natural Resources, Inc.	$	(11.06	)	$	(4.06	)	$	0.81		$	0.74		$	2.90
Loss from discontinued operations attributable to Alpha Natural Resources, Inc.	—			—			(0.01		)	(0.10		)	(0.48		)
Net income (loss) per basic share attributable to Alpha Natural Resources, Inc.	$	(11.06	)	$	(4.06	)	$	0.80		$	0.64		$	2.42
Diluted earnings (loss) per common share:
Income (loss) from continuing operations attributable to Alpha Natural Resources, Inc.	$	(11.06	)	$	(4.06	)	$	0.80		$	0.73		$	2.83
Loss from discontinued operations attributable to Alpha Natural Resources, Inc.	—			—			(0.01		)	(0.10		)	(0.47		)
Net income (loss) per diluted share attributable to Alpha Natural Resources, Inc.	$	(11.06	)	$	(4.06	)	$	0.79		$	0.63		$	2.36

	Years Ended December 31,
	2012			2011(9)			2010			2009			2008
	(In thousands)
Balance sheet data (at period end):
Cash and cash equivalents	$	730,723		$	585,882		$	554,772		$	465,869		$	676,190
Working capital	$	1,110,614		$	638,827		$	928,691		$	592,403		$	729,829
Total assets (5)	$	13,089,806		$	16,594,045		$	5,179,283		$	5,120,343		$	1,709,838
Notes payable and long-term debt, including current portion, net (6)	$	3,386,052		$	2,968,081		$	754,151		$	790,253		$	451,315
Stockholders’ equity (7)	$	4,967,815		$	7,375,044		$	2,656,036		$	2,591,289		$	795,692
Statement of cash flows data:
Net cash provided by (used in):
Operating activities	$	518,419		$	686,637		$	693,601		$	356,220		$	458,043
Investing activities	$	(672,976	)	$	(1,147,007	)	$	(508,497	)	$	(281,810	)	$	(77,625	)
Financing activities	$	299,398		$	491,480		$	(96,201	)	$	(284,731	)	$	241,407
Capital expenditures	$	(402,377	)	$	(528,586	)	$	(308,864	)	$	(187,093	)	$	(137,751	)

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

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	Years Ended December 31,
	2012			2011(7)			2010			2009			2008
	(In thousands)
Income (loss) from continuing operations	$	(2,437,148	)	$	(730,542	)	$	97,218		$	66,807		$	198,599
Interest expense	198,147			141,914			73,463			82,825			39,812
Interest income	(3,373		)	(3,978		)	(3,458		)	(1,769		)	(7,351		)
Income tax expense (benefit)	(549,996		)	(35,906		)	4,218			(33,023		)	52,242
Depreciation, depletion, and amortization	1,037,575			770,769			370,895			252,395			164,969
Amortization of acquired intangibles, net	(70,338		)	(114,422		)	226,793			127,608			—
EBITDA from continuing operations(8)	$	(1,825,133	)	$	27,835		$	769,129		$	494,843		$	448,271

⁽¹⁾  Other revenues for 2011 include $127.2 million related to derivative contracts accounted for at fair value. Other revenues for 2009 include $18.1 million for the modification of a coal supply agreement.

⁽²⁾  Asset impairment and restructuring charges were recorded during 2012. See Note 8 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

⁽³⁾  Goodwill impairment charges were recorded during 2012. See Note 9 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

⁽⁴⁾  Income from continuing operations for 2011 includes the following significant amounts from the Massey Acquisition: Total revenues-$1.9 billion; Cost of coal sales-$1.9 billion; Depreciation, depletion and amortization-$397.7 million; and Amortization of acquired intangibles, net-($216.2) million. 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; and Amortization of acquired intangibles, net-$127.6 million. See Note 3 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

⁽⁵⁾  Total assets as of December 31, 2011 included the impact of the addition of the following significant assets acquired in the Massey Acquisition: $6.4 billion of owned and leased mineral rights; $1.7 billion of property and equipment; and $2.7 billion of goodwill. Total assets as of December 31, 2009 included the impact of 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 3 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

⁽⁶⁾  Long-term debt, including current portion and debt discount as of December 31, 2011 includes $628.2 million, net of debt discount, assumed in the Massey Acquisition. 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 3 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

⁽⁷⁾  Stockholders’ equity as of December 31, 2011 includes approximately $5.7 billion related to the issuance of common shares and other equity consideration for the Massey Acquisition. Stockholders’ equity as of December 31, 2009, includes approximately $1.7 billion related to the issuance of common shares and other equity consideration related to the Foundation Merger. See Note 3 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

⁽⁸⁾  EBITDA from continuing operations is defined as income (loss) from continuing operations attributable plus interest expense, income tax expense (benefit), depreciation, depletion and amortization and amortization of acquired intangibles, 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.

⁽⁹⁾  As a result of changes to the provisional opening balance sheet of Massey and for certain other immaterial corrections and reclassifying adjustments, the Company adjusted depreciation, depletion and amortization, amortization of acquired intangibles, net, cost of coal sales, other expenses, other revenues and goodwill impairment and restated its consolidated balance sheet as of December 31, 2011 and its consolidated results of operations for the year ending December 31, 2011. The Company recorded additional goodwill impairment of $57,012, increased its net loss before income taxes by $50,131, and increased its net loss by $53,152 for the year ended December 31, 2011.

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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 June 1, 2011, we completed our acquisition (the “Massey Acquisition”) of Massey Energy Company (“Massey”). Massey, together with its affiliates, was a major U.S. coal producer operating mines and associated processing and loading facilities in Central Appalachia. Our consolidated results of operations for the year ended December 31, 2011 include Massey’s results of operations for the period June 1, 2011 through December 31, 2011. Our consolidated results of operations for the year ended December 31, 2010 do not include amounts related to Massey’s results of operations. See Note 3 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K for additional information regarding the Massey Acquisition.

Prior to the finalization of the purchase price allocation, we recorded adjustments to the provisional opening balance sheet and certain immaterial corrections. Adjustments were made primarily to reflect corrections to asset retirement obligations, updated estimates of certain tax liabilities, updated estimates of certain property values, updated estimates of below market contract liabilities, updated estimates for litigation related matters and related insurance recoveries, other miscellaneous adjustments and the deferred tax impact of all adjustments made. See Note 3 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K for additional information.

Overview

We are one of America’s premier coal suppliers, ranked third largest among publicly-traded U.S. coal producers asmeasured by consolidated 2012 revenues of $7.0 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 as well as a growing exporter of thermal coal. As of December 31, 2012, we operate 107 mines and 26 coal preparation facilities in Northern and Central Appalachia and the Powder River Basin, with approximately 12,400 employees.

We produce, process, and sell steam and metallurgical coal from mines and coal preparation facilities 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 2012, 2011 and 2010 accounted for approximately 81%, 82% and 86%, respectively, of our annual coal sales volume, and our sales of metallurgical coal in 2012, 2011 and 2010, which generally sells at a premium over steam coal, accounted for approximately 19%, 18% and 14%, respectively, of our annual coal sales volume.

Our sales of steam coal during 2012, 2011 and 2010 were made primarily to large utilities and industrial customers throughout the United States, and our sales of metallurgical coal during 2012, 2011 and 2010 were made primarily to steel companies in the Northeastern and Midwestern regions of the United States and in several countries in Europe, Asia, South America and Africa. Approximately 42%, 44% and 34% of our total revenues in 2012, 2011 and 2010, respectively, were derived from sales made to customers outside the United States, primarily in Canada, India, the Netherlands, South Korea 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 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, 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

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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.

Business Developments

In addition to the Massey Acquisition completed on June 1, 2011, recent business developments included the following:

During the twelve months ended December 31, 2012, we announced the planned idling of certain mining operations and preparation plants in our eastern operations and other planned production curtailments as well as an organizational streamlining. The mines impacted are located in Virginia, West Virginia, Pennsylvania, Kentucky and Wyoming. The combination of mine idlings, production curtailments and mining out of certain reserves will take place through early 2013, and is expected to reduce 2013 production and shipments by approximately 17 million to 28 million tons compared to 2012 levels. The majority of the reduction will come from higher-cost thermal coal operations in the east and production curtailments in the Power River Basin. These reductions will allow us to focus on higher margin products. We will continue to evaluate market conditions and will make further adjustments if market conditions warrant. Our reorganization efforts will serve to reduce overhead while enhancing operational effectiveness as we align our structure to our smaller production footprint. As part of our reorganization we established an operational performance group to support the deployment of best practices across the organization in areas such as operations improvement and preventive maintenance. Satellite offices in Richmond, Virginia, Denver, Colorado, Latrobe, Pennsylvania, and Linthicum Heights, Maryland have been closed and overhead support functions are being consolidated from other locations as well. We expect to achieve overhead savings from the streamlining of field and corporate support functions, which are expected to be reflected in lower cost of coal sales and selling, general and administrative expenses.

During the twelve months ended December 31, 2012, we tested certain of our long-lived assets and goodwill for impairment. We recorded charges for asset impairment of $1,000.5 million and goodwill impairment of $1,713.5 million. Additionally, we recorded severance-related expenses of $33.9 million and $13.6 million for professional fees. Additionally, we recorded other restructuring expenses of $20.9 million related to reserves for advanced royalties and deposits which may not be recoverable and liabilities related to certain property leases that were terminated. See Note 8 and Note 9 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K related to asset impairment and restructuring expenses and goodwill impairment, respectively.

On October 11, 2012, we, certain of our wholly-owned domestic subsidiaries, as guarantors, and Union Bank, N.A., as trustee, entered into a third supplemental indenture (the “Third Supplemental Indenture”) to the indenture dated June 1, 2011 (the “Base Indenture” and, together with the Third Supplemental Indenture, the “9.75% Senior Notes Indenture”). The 9.75% Senior Notes Indenture governs Alpha's 9.75% senior notes due 2018 (the “9.75% Senior Notes”), which were issued on October 11, 2012 in an aggregate principal amount of $500.0 million. The 9.75% Senior Notes bear interest at a rate of 9.75% per annum, payable semi-annually on April 15 and October 15 of each year, beginning on April 15, 2013, and will mature on April 15, 2018. Additionally, in October, 2012, pursuant to a cash tender offer with respect to our 3.25% convertible senior notes, we and Alpha Appalachia Holdings, Inc. (formerly Massey) repurchased $122.5 million in aggregate principal amount of our outstanding 3.25% convertible senior notes using a portion of the net proceeds from the offering of the 9.75% Senior Notes. See Note 12 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K .

Coal Pricing Trends, Uncertainties and Outlook

After a period of cyclical weakness in the global metallurgical coal market in the second half of 2012 during which approximately 30 million tons of uneconomic production was removed from the seaborne market, developments are beginning to point to gradual improvement. Chinese coking coal imports increased for the full year 2012 compared to 2011 levels. China's purchasing managers' index (“PMI”) has also been rising for several months. Recently, tropical storms have hampered activity at Australian ports and disrupted rail shipments, although the impact is not as severe as the extreme weather events witnessed in early 2011.

In the Atlantic basin, European demand has been muted by economic headwinds, Brazil slowed its importation of coking coal somewhat in 2012, and U.S. demand has been generally stable. As a result, for the last several quarters, the Atlantic market has been characterized by market weakness and over-supply, particularly for lower quality metallurgical coals. Currently the Atlantic basin remains disconnected from Asia where the impact of production cuts and strengthening demand have begun to spark gradual improvement in the metallurgical coal market. Current spot transactions of Australian metallurgical coal in Asia have reportedly risen above the recent benchmark price, and are higher compared to levels experienced in September of 2012. As the leading U.S. producer of metallurgical coal, Alpha expects to be well-positioned to

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benefit from an eventual recovery in the global metallurgical coal market, particularly in the Atlantic.

Throughout 2012, the market for domestic steam coal remained challenging due in part to a warm winter, low natural gas prices and the long-term secular trend of coal-fired plant retirements, all of which contributed to reduced coal usage and led to record-high inventory levels that peaked in the spring of 2012. As natural gas prices have increased from low levels experienced in the early part of 2012, coal has recovered some of its market share that was lost with the low natural gas prices. As a result of the increased usage of coal in the second half of the year, along with domestic production cuts during 2012, utility inventories have started to retreat but remain elevated as of the end of the year.

The Energy Information Administration (“EIA”) 2013 Annual Energy Outlook Early Release forecasts that coal-fired electrical generation will decrease by an average annual rate of 1.6% through 2015. The EIA estimates that electric power generation from coal decreased by 12.7% in 2012 compared to 2011 as low natural gas prices, increased environmental regulation, and other factors weighed on coal-fired generation. Based on weekly coal production reporting through December 31, 2012 from the EIA, year-over-year Appalachian production decreased by approximately 9.9% and western coal production decreased by approximately 8.0% during 2012.

In light of the continuing weakness in the U.S. steam coal market, Alpha adjusted its shipment levels and implemented a restructuring plan to adjust its operating footprint. With respect to the Powder River Basin, Alpha has reduced its planned shipments in the near-term until elevated inventories eventually correct, allowing acceptable profit levels. In the East, Alpha's Pittsburgh seam longwalls, with high heat content and relatively lower costs, are expected to be competitive and productive in 2013. In Central Appalachia, Alpha has idled or closed a number of higher production cost steam coal operations in order to control costs and match supply with structurally diminished demand that has decreased markedly over the course of 2012. At the same time, Alpha more than doubled its Eastern thermal coal exports in 2012 to nearly six million tons, and the Company plans to continue to expand its export thermal franchise in 2013, and beyond.

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 strives to aggressively control costs and 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 and 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 experience difficult geologic conditions, delays in obtaining permits, labor shortages, unforeseen equipment problems, and unexpected shortages of critical materials such as tires, fuel 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.”

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Results of Operations

EBITDA from continuing operations is calculated as follows:

	Years Ended December 31,
	2012			2011			2010
	(In thousands)
Income (loss) from continuing operations	$	(2,437,148	)	$	(730,542	)	$	97,218
Interest expense	198,147			141,914			73,463
Interest income	(3,373		)	(3,978		)	(3,458		)
Income tax expense (benefit)	(549,996		)	(35,906		)	4,218
Depreciation, depletion, and amortization	1,037,575			770,769			370,895
Amortization of acquired intangibles, net	(70,338		)	(114,422		)	226,793
EBITDA from continuing operations	$	(1,825,133	)	$	27,835		$	769,129

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

As noted previously, the financial results for the year ended December 31, 2011 include only seven months of operations related to the acquired Massey operations due to the timing of the closing of the Massey Acquisition on June 1, 2011. To help understand the operating results for the periods, the term “Massey operations” refers to the estimated results from former Massey operations for the seven month period from June 1, 2011 to December 31, 2011 and the term “Alpha operations” refers to the results of Alpha not inclusive of results from the Massey operations for the twelve months ended December 31, 2011.

Summary

Total revenues decreased $132.8 million, or 2%, for the twelve months ended December 31, 2012 compared to the prior year period. The decrease in total revenues was due to decreased coal revenues of $173.7 million, decreased other revenues of $58.7 million, partially offset by increased freight and handling revenues of $99.6 million. The decrease in coal revenues consisted of decreased metallurgical coal revenues of $448.6 million partially offset by increased steam coal revenues of $274.9 million. The increase in freight and handling revenues was due primarily to increased average freight rates and increased export shipments. The decrease in other revenues was due primarily to period over period changes in fair value of derivative coal contracts offset by increased contractual settlement-related revenues.

Net loss increased $1,706.6 million for the twelve months ended December 31, 2012 compared to the prior year period. The increase was largely due to increased goodwill impairment expense of $911.2 million, asset impairment and restructuring expense of $1,068.9 million, increased other expense, net of $43.4 million, decreased coal and other revenues discussed above, partially offset by increased tax benefits of $514.1 million and decreased certain operating costs and expenses, which are described below, of $35.2 million.

The decrease in certain operating costs and expenses of $35.2 million consisted of decreased selling, general and administrative expenses of $172.5 million, or 45%, decreased other expenses of $97.2 million, or 68%, decreased cost of coal sales of $76.4 million, or 2%, partially offset by increased depreciation, depletion and amortization expenses of $266.8 million, or 35%, and decreased credits to expense for amortization of acquired intangibles, net of $44.1 million, or 39%.

Coal sales volumes increased 2.5 million tons for the twelve months ended December 31, 2012 compared to the prior year period. The increase in coal sales volumes was due to increases of 4.6 million and 1.1 million tons of eastern steam and metallurgical coal, respectively, and a decrease of 3.2 million tons of western steam coal. The increase in eastern steam and metallurgical coal was due primarily to the inclusion of the Massey operations for the full twelve month period in 2012.

The average coal sales realization per ton for the twelve months ended December 31, 2012 was $55.29 compared to $58.22 in the prior year period, a decrease of $2.93 per ton, or 5%. The decrease was largely attributable to a $30.83 per ton, or 19%, decrease in metallurgical average coal sales realization per ton. The average coal sales realization per ton for metallurgical coal and eastern steam coal was $131.02 and $65.92, respectively, for the twelve months ended December 31, 2012 compared to $161.85 and $66.92, respectively, in the prior year period. The average coal sales realization per ton for western steam coal was $12.94 for the twelve months ended December 31, 2012 compared to $11.95 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 18% for the twelve months ended December 31, 2012 compared to 19% in the prior year period. Coal margin percentage for our Eastern and Western Coal Operations was 18% and 22%, respectively, for the twelve months ended December 31, 2012 compared to 19% and 16%, 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 $10.01 for the twelve months ended December 31, 2012 compared to $11.08 in the prior year period. Coal margin per ton for our Eastern and Western Coal Operations was $15.42 and $2.84, respectively, for the twelve months ended December 31, 2012 compared to $19.16 and $1.96, respectively, in the prior year period.

Revenues

	Years Ended December 31,				Increase (Decrease)
	2012		2011		$ or Tons			%
	(Amounts in thousands, except per ton data)
Coal revenues:
Eastern steam	$	2,755,474	$	2,488,729	$	266,745		11	%
Western steam	604,880		596,724		8,156			1	%
Metallurgical	2,655,342		3,103,981		(448,639		)	(14	)%
Freight and handling revenues	761,928		662,238		99,690			15	%
Other revenues	197,260		256,009		(58,749		)	(23	)%
Total revenues	$	6,974,884	$	7,107,681	$	(132,797	)	(2	)%
Tons sold:
Eastern steam	41,797		37,192		4,605			12	%
Western steam	46,732		49,949		(3,217		)	(6	)%
Metallurgical	20,267		19,177		1,090			6	%
Total	108,796		106,318		2,478			2	%
Coal sales realization per ton:
Eastern steam	$	65.92	$	66.92	$	(1.00	)	(1	)%
Western steam	$	12.94	$	11.95	$	0.99		8	%
Metallurgical	$	131.02	$	161.85	$	(30.83	)	(19	)%
Average	$	55.29	$	58.22	$	(2.93	)	(5	)%

Coal revenues. Coal revenues decreased $173.7 million, or 3%, for the twelve months ended December 31, 2012 compared to the prior year period. The decrease in coal revenues consisted of decreased metallurgical coal revenues, partially offset by increased eastern and western steam coal revenues.

The increase in eastern steam coal revenues was largely due to increased tons shipped due to the inclusion of the Massey operations for the full twelve month period in 2012, partially offset by slightly lower average coal sales realizations per ton. Total eastern steam coal shipments increased 4.6 million tons, which consisted of increased export shipments of 4.1 million tons, or 225%, and increased domestic shipments of 0.5 million tons, or 2%, compared to the prior year period. Total eastern steam coal revenues increased $266.7 million, or 11%, which consisted of increased export coal revenues of $251.5 million, or 233%, and increased domestic coal revenues of $15.2 million, or 1%, compared to the prior year period.

The decrease in metallurgical coal revenues was largely due to lower average coal sales realizations per ton, partially offset by increased tons shipped due to the inclusion of the Massey operations for the full twelve month period in 2012. Total eastern metallurgical coal shipments increased 1.1 million tons, which consisted of increased export shipments of 1.2 million tons, or 8%, partially offset by decreased domestic shipments of 0.1 million tons, or 1%, compared to the prior year period. Total eastern metallurgical coal revenues decreased $448.6 million, or 14%, which consisted of decreased export coal revenues of

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$474.3 million, or 20%, partially offset by increased domestic coal revenues of $25.7 million, or 3%, compared to the prior year period.

The increase in western steam coal revenues was due to an increase of $0.99, or 8%, in average coal sales realization. Western coal sales volumes decreased 3.2 million tons compared to the prior year period largely due to lower utility customer demand resulting from natural gas switching and lower electrical generation.

Our sales mix of metallurgical coal and steam coal based on volume was 19% and 81%, respectively, for the twelve months ended December 31, 2012 compared with 18% and 82% in the prior year period. Our sales mix of metallurgical coal and steam coal based on coal revenues was 44% and 56%, respectively, for the twelve months ended December 31, 2012 compared with 50% for each in the prior year period.

Freight and handling. Freight and handling revenues and costs were $761.9 million for the twelve months ended December 31, 2012, an increase of $99.6 million, or 15%, compared to the prior year period. The increase was primarily due to increased export volumes and increased average freight rates compared to the prior year period.

Other. Other revenues decreased $58.7 million, or 23%, and other expenses decreased $97.2 million, or 68%, for the twelve months ended December 31, 2012 compared to the prior year period resulting in a net increase to income from operations of $38.5 million. The net increase was due primarily to increased contractual settlement related income of $140.7 million, partially offset by a $123.3 million decrease period over period in the change in fair value and settlements of derivative coal contracts.

Costs and Expenses

	Years Ended December 31,						Increase (Decrease)
	2012			2011			$			%
	(Amounts in thousands, except per ton data)
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)	$	5,004,516		$	5,080,921		$	(76,405	)	(2	)%
Freight and handling costs	761,928			662,238			99,690			15	%
Other expenses	45,432			142,709			(97,277		)	(68	)%
Depreciation, depletion and amortization	1,037,575			770,769			266,806			35	%
Amortization of acquired intangibles, net	(70,338		)	(114,422		)	44,084			(39	)%
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)	209,788			382,250			(172,462		)	(45	)%
Asset impairment and restructuring	1,068,906			—			1,068,906			NM
Goodwill impairment	1,713,526			802,337			911,189			114	%
Total costs and expenses	$	9,771,333		$	7,726,802		$	2,044,531		26	%
Cost of coal sales per ton(1):
Eastern coal operations	$	71.76		$	80.06		$	(8.30	)	(10	)%
Western coal operations	$	10.10		$	9.99		$	0.11		1	%
Average	$	45.28		$	47.14		$	(1.86	)	(4	)%

__________________________

⁽¹⁾  Cost of coal sales per ton includes only costs associated with our Eastern and Western Coal Operations. 

Cost of coal sales. Cost of coal sales decreased $76.4 million, or 2%, for the twelve months ended December 31, 2012 compared to the prior year period. The decrease in cost of coal sales was due primarily to decreased merger-related expenses, a reduction of approximately $154.4 million in estimated asset retirement obligations arising largely from changes in engineering estimates of future water treatment costs at closed mines, including the impacts of evolving treatment technologies and maturing treatment plans, a benefits-related accrual reversal of $42.1 million, and decreased purchased coal expenses, partially

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offset by increased costs due to the inclusion of the Massey operations for the full twelve month period in 2012 and increased costs related to regulatory compliance, including the impacts of MSHA and environmental compliance. Cost of coal sales for the twelve months ended December 31, 2012 included approximately $31.5 million of expenses related to a closed mine and approximately $34.7 million of merger-related expenses primarily related to contract matters. Comparatively, cost of coal sales for the twelve months ended December 31, 2011 included approximately $193.5 million of merger-related expenses related to severance and stock compensation expenses and the fair value adjustments made in acquisition accounting to Massey's beginning inventory, approximately $40.9 million of expenses related to a closed mine, approximately $37.1 million related to changes in asset retirement obligation estimates for future water treatment costs at closed mines and approximately $8.0 million of expenses related to mineral lease terminations.

Depreciation, depletion and amortization. Depreciation, depletion, and amortization increased $266.8 million, or 35%, for the twelve months ended December 31, 2012 compared to the prior year period. The increase in depreciation, depletion and amortization expenses was primarily due to the inclusion of the Massey operations for a full twelve months, including the fair value adjustments made in acquisition accounting to property, equipment and owned and leased mineral rights.

Amortization of acquired intangibles, net. Amortization of acquired intangibles, net includes the amortization of above and below market coal contracts, mining permits and other intangible assets assumed in prior acquisitions. Amortization expense for above market contracts decreased $73.5 million compared to the prior year period and amortization credits for below market contracts decreased $110.1 million compared to the prior year period. Amortization of permits and other intangible assets increased $7.5 million compared to the prior year period due to the inclusion of amortization expense for a full twelve month period in 2012 compared to seven months in 2011. Amortization of acquired intangibles, net for the next five years is estimated to be $2.0 million, $42.9 million, $30.9 million, $21.8 million, and $4.7 million.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $172.5 million, or 45%, for the twelve months ended December 31, 2012 compared to the prior year period. Selling, general and administrative expenses decreased primarily due to decreased stock compensation expenses associated with performance-based awards and decreased merger-related expenses. For the twelve months ended December 31, 2012, selling, general and administrative expenses included approximately $11.4 million in merger-related expenses primarily related to professional fees and severance. The same period in 2011 included approximately $164.0 million in merger-related expenses primarily related to professional fees for legal and transaction services, severance and stock compensation, and bridge loan fees incurred in connection with the Massey Acquisition.

Asset impairment and restructuring. See Business Developments, Critical Accounting Policies and Note 8 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

Goodwill impairment. See Business Developments, Critical Accounting Policies and Note 9 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

Interest expense. Interest expense increased $56.2 million, or 40%, during the twelve months ended December 31, 2012 compared to the prior year period primarily due to a larger average outstanding balance of debt during the period as a result of the debt assumed in the Massey Acquisition, the financing transactions that were completed in June 2011 and the issuance of 9.75% senior notes in October 2012 (See Liquidity and Capital Resources and Note 12 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K).

Income tax benefit. Income tax benefit from continuing operations of $550.0 million was recorded for the twelve months ended December 31, 2012 on loss from continuing operations before income taxes of $2,987.1 million, which equates to an effective tax benefit rate of 18.4%. The rate is lower than the federal statutory rate of 35% primarily due to the non-deductible goodwill impairment and changes in valuation allowances, partially offset by the impact of the percentage depletion deduction, state taxes and state apportionment change, net of federal tax impacts.

Income tax benefit from continuing operations of $35.9 million was recorded for the twelve months ended December 31, 2011 on loss from continuing operations before income taxes of $766.4 million, which equates to an effective tax benefit rate of 4.7%. The rate is lower than the federal statutory rate of 35% primarily due to the non-deductible goodwill impairment, partially offset by the impact of percentage depletion deductions. (See Note 17 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.)

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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 higher energy content and is often located closer to the end user.

	Years Ended December 31,					Increase (Decrease)
	2012			2011		Tons/$			Percent
	(In thousands, except per ton data)
Western Coal Operations
Steam tons sold	46,732			49,949		(3,217		)	(6	)%
Steam coal sales realization per ton	$	12.94		$	11.95	$	0.99		8	%
Total revenues	$	611,329		$	602,157	$	9,172		2	%
EBITDA from continuing operations	$	65,153		$	74,891	$	(9,738	)	(13	)%
Eastern Coal Operations
Steam tons sold	41,797			37,192		4,605			12	%
Metallurgical tons sold	20,267			19,177		1,090			6	%
Steam coal sales realization per ton	$	65.92		$	66.92	$	(1.00	)	(1	)%
Metallurgical coal sales realization per ton	$	131.02		$	161.85	$	(30.83	)	(19	)%
Total revenues	$	6,290,289		$	6,423,805	$	(133,516	)	(2	)%
EBITDA from continuing operations	$	(1,807,515	)	$	143,649	$	(1,951,164	)	(1,358	)%

Western Coal Operations - EBITDA from continuing operations decreased $9.7 million for the twelve months ended December 31, 2012 compared to the prior year period. The decrease was due primarily to goodwill impairment and restructuring expenses of $53.3 million and $0.8 million, respectively, partially offset by increased coal and other revenues of $9.2 million, decreased selling, general and administrative expenses of $9.4 million and decreased cost of coal sales of $27.2 million.

The increase in coal and other revenues consisted of increased coal revenues of $8.2 million and increased other revenues of $1.0 million. The increase in coal revenues was due to higher average coal sales realization per ton compared to the prior year period. Tons shipped decreased 3.2 million, or 6%, compared to the prior year period.

The decrease in cost of coal sales was primarily due to decreased supplies and maintenance costs, decreased outside services, and a benefits-related accrual reversal, partially offset by increased sales-related variable costs due to the increase in coal revenues. Average coal sales realization per ton increased $0.99, or 8%, and cost of coal sales per ton increased $0.11, resulting in an increase to coal margin per ton of $0.88, or 45%.

Eastern Coal Operations - EBITDA from continuing operations decreased $1,951.2 million for the twelve months ended December 31, 2012 compared to the prior year period. The decrease was largely due to increased goodwill impairment expense of $857.9 million, asset impairment and restructuring expenses of $1,034.0 million and decreased coal and other revenues of $232.2 million, partially offset by decreased cost of coal sales of $59.1 million, decreased other expense of $95.1 million and decreased selling, general and administrative expenses of $11.5 million.

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The decrease in coal and other revenues consisted of decreased coal revenues of $181.9 million and decreased other revenues of $50.3 million. The decrease in coal revenues consisted of decreased metallurgical coal revenues of $448.6 million, partially offset by increased steam coal revenues of $266.7 million. The increase in other revenues was due primarily to increased contractual settlement related income, partially offset by decreased period over period change in fair value of derivative coal contracts.

The increase in eastern steam coal revenues was largely due to increased tons shipped due to the inclusion of the Massey operations for the full twelve month period in 2012, partially offset by slightly lower average coal sales realizations per ton. Total eastern steam coal shipments increased 4.6 million tons, which consisted of increased export shipments of 4.1 million tons, or 225%, and increased domestic shipments of 0.5 million tons, or 2%, compared to the prior year period. Total eastern steam coal revenues increased $266.7 million, or 11%, which consisted of increased export coal revenues of $251.5 million, or 233%, and increased domestic coal revenues of $15.2 million, or 1%, compared to the prior year period. Coal sales realization per ton for eastern steam export sales was $61.44 per ton compared to $60.00 per ton in the prior year period and coal sales realization per ton for eastern steam domestic sales was $66.65 per ton compared to $67.27 per ton in the prior year period.

The decrease in metallurgical coal revenues was largely due to lower average coal sales realizations per ton. Metallurgical coal shipments increased 1.1 million tons, which consisted primarily of increased export shipments, compared to the prior year period. Total metallurgical coal revenues decreased $448.6 million, or 14%, which consisted of decreased export metallurgical coal revenues of $474.3 million, or 20%, partially offset by increased domestic metallurgical coal revenues of $25.7 million, or 3%, compared to the prior year period. Coal sales realization per ton for eastern metallurgical export sales was $122.18 per ton compared to $165.53 per ton in the prior year period and coal sales realization per ton for eastern metallurgical domestic sales was $158.78 per ton compared to $151.36 per ton in the prior year period.

The decrease in cost of coal sales was due primarily to decreased merger-related expenses, a reduction of approximately $153.9 million in estimated asset retirement obligations arising largely from changes in engineering estimates of future water treatment costs at closed mines, including the impacts of evolving treatment technologies and maturing treatment plans, a benefits-related accrual reversal of $39.6 million and decreased purchased coal expenses, partially offset by increased costs due to the inclusion of the Massey operations for the full twelve month period in 2012 and increased costs related to regulatory compliance, including the impacts of MSHA and environmental compliance. Cost of coal sales for the twelve months ended December 31, 2012 included approximately $31.5 million of expenses related to a closed mine and approximately $34.7 million of merger-related expenses primarily related to contract matters. Comparatively, cost of coal sales for the twelve months ended December 31, 2011 included approximately $40.9 million of expenses related to a closed mine and approximately $188.2 million of merger-related expenses related to severance and stock compensation expenses and the fair value adjustments made in acquisition accounting to Massey's beginning inventory, $37.1 million related to increases in asset retirement obligation estimates for future water treatment costs at closed mines and approximately $8.0 million of expenses related to mineral lease terminations.

Average coal sales realization per ton decreased $12.04, or 12%, while cost of coal sales per ton decreased $8.30, resulting in a decrease to coal margin per ton of $3.74, or 20%. The decrease in average coal sales realization per ton was due primarily to a decrease in metallurgical coal sales realization per ton. The decrease in cost of coal sales per ton was due primarily to lower volumes of purchased coal and the impact of general cost control efforts.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Summary

Total revenues increased $3,190.5 million, or 81%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase in total revenues was due to increased coal revenues of $2,691.6 million, increased freight and handling revenues of $329.6 million and increased other revenues of $169.3 million. The increase in coal revenues consisted of an increase from the Alpha operations of $813.0 million, or 23%, and $1,878.6 million from the Massey operations. The increase in freight and handling revenues was primarily related to the Alpha operations. The increase in other revenues consisted of an increase of $144.4 million, or 166%, from the Alpha operations, and $24.9 million from the Massey operations.

Income from continuing operations decreased $827.8 million for the twelve months ended December 31, 2011 compared to the prior year period. The decrease was largely due to a goodwill impairment charge of $802.3 million, increases in certain operating costs and expenses of $2,851.3 million, increased other expenses, net of $75.2 million, partially offset by increased coal revenues and other revenues discussed above and increased tax benefits of $40.1 million.

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The increase in certain operating costs and expenses of $2,851.3 million was due to increased cost of coal sales of $2,514.1 million, or 98%, increased depreciation, depletion and amortization expenses of $399.9 million, or 108%, increased other expenses of $77.2 million, or 118%, increased selling, general and administrative expenses of $201.3 million, or 111%, and decreased expenses for amortization of acquired intangibles, net of $341.2 million, or 150%. The increase in cost of coal sales consisted of an increase of $591.2 million, or 23%, from the Alpha operations and $1,922.8 million from the Massey operations. Cost of coal sales in 2011 included $193.5 million of merger-related costs incurred in connection with the Massey Acquisition. The increase in depreciation, depletion and amortization expenses was primarily due to the inclusion of the Massey operations, including the fair value adjustments made in acquisition accounting to property, equipment and owned and leased mineral rights. The increase in other expenses consisted of an increase of $17.9 million, or 27%, from the Alpha operations and $59.3 million from the Massey operations. The increase in selling, general and administrative expenses included $164.0 million in merger-related costs incurred in connection with the Massey Acquisition. The decrease in expense for amortization of acquired intangibles, net, consisted of a decrease in amortization expense of $125.0 million, or 55%, from the Alpha operations and a credit to amortization expense of $216.2 million from the Massey operations.

We sold 106.3 million tons of coal during the twelve months ended December 31, 2011 compared to 84.8 million tons in the prior year period, an increase of 21.5 million tons, or 25%. The 106.3 million tons consisted of 37.2 million tons of steam coal and 19.2 million tons of metallurgical coal from our Eastern Coal Operations and 49.9 million tons of steam coal from our Western Coal Operations. The 84.8 million tons in the prior year consisted of 24.0 million tons of steam coal and 11.8 million tons of metallurgical coal from our Eastern Coal Operations and 49.0 million tons of steam coal from our Western Coal Operations.

The increase in coal sales volumes of 21.5 million tons in 2011 was due to increases of 13.2 million and 7.3 million tons of eastern steam and metallurgical coal, respectively, and an increase of 1.0 million tons of western steam coal. The increases in eastern steam and metallurgical coal were due primarily to the inclusion of 15.9 million tons of eastern steam and 5.0 million tons of metallurgical coal from the Massey operations, a decrease of 2.7 million tons of eastern steam and an increase of 2.3 million tons of metallurgical coal from the Alpha operations.

The average coal sales realization per ton for the twelve months ended December 31, 2011 was $58.22 compared to $41.22 in the prior year period, an increase of $17.00 per ton, or 41%. The increase was largely attributable to the $47.96 per ton, or 42%, increase in metallurgical average coal sales realization per ton. The average coal sales realization per ton for metallurgical coal and eastern steam coal was $161.85 and $66.92, respectively, for the twelve months ended December 31, 2011 compared to $113.89 and $67.07, respectively, in the prior year period. The average coal sales realization per ton for western steam coal was $11.95 for the twelve months ended December 31, 2011 compared to $10.95 in the prior year period.

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 19% for the twelve months ended December 31, 2011 compared to 27% in the prior year period. Coal margin percentage for our Eastern and Western Coal Operations was 19% and 16%, respectively, for the twelve months ended December 31, 2011 compared to 28% and 22%, 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 $11.08 for the twelve months ended December 31, 2011 compared to $11.14 in the prior year period. Coal margin per ton for our Eastern and Western Coal Operations was $19.16 and $1.96, respectively, for the twelve months ended December 31, 2011 compared to $23.09 and $2.39, respectively, in the prior year period.

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Revenues

	Years Ended December 31,				Increase (Decrease)
	2011		2010		$ or Tons			%
	(In thousands, except per ton data)
Revenues:
Coal revenues:
Eastern steam	$	2,488,729	$	1,609,832	$	878,897		55	%
Western steam	596,724		536,064		60,660			11	%
Metallurgical	3,103,981		1,351,951		1,752,030			130	%
Freight and handling revenues	662,238		332,559		329,679			99	%
Other revenues	256,009		86,750		169,259			195	%
Total revenues	$	7,107,681	$	3,917,156	$	3,190,525		81	%
Tons sold:
Eastern steam	37,192		24,001		13,191			55	%
Western steam	49,949		48,977		972			2	%
Metallurgical	19,177		11,871		7,306			62	%
Total	106,318		84,849		21,469			25	%
Coal sales realization per ton:
Eastern steam	$	66.92	$	67.07	$	(0.15	)	—	%
Western steam	$	11.95	$	10.95	$	1.00		9	%
Metallurgical	$	161.85	$	113.89	$	47.96		42	%
Average	$	58.22	$	41.22	$	17.00		41	%

Coal revenues. Coal revenues increased $2,691.6 million, or 77%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase in coal revenues consisted of an increase in metallurgical coal revenues of $1,752.0 million, or 130%, an increase in eastern steam coal revenues of $878.9 million, or 55%, and an increase in western steam coal revenues of $60.7 million, or 11%.

The increase in metallurgical coal revenues was largely due to an increase in tons shipped and increased average coal sales realization per ton. Metallurgical tons shipped increased 7.3 million, or 62%, compared to the prior year period and consisted of an increase of 2.3 million tons, or 19%, from the Alpha operations and 5.0 million tons from the Massey operations. The average coal sales realization per ton for metallurgical coal increased $47.96, or 42%, due primarily to increased pricing and demand for metallurgical coal compared to the prior year period.

The increase in eastern steam coal revenues was due to 15.9 million tons and $1,082.6 million from the Massey operations, partially offset by decreases of $203.7 million from the Alpha operations. The decrease in eastern steam coal revenues from the Alpha operations was primarily due to a decrease in eastern steam coal sales volumes, which decreased 2.7 million tons, or 11%, compared to the prior year period due primarily to increased production of metallurgical tons in response to the increase in demand and lower production at our Pennsylvania Services longwall mines.

The increase in western steam coal revenues was due primarily to an increase in average coal sales realization per ton. Average coal sales realization per ton increased $1.00, or 9%, 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 twelve months ended December 31, 2011 was 18% and 82%, respectively, compared with 14% and 86% in the prior year period. Our sales mix of metallurgical coal and steam coal based on volume for the Massey operations for the twelve months ended December 31, 2011 was 24% and 76%, respectively, and our sales mix of metallurgical coal and steam coal based on volume for the Alpha operations for the twelve

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months ended December 31, 2011 was 17% and 83%, respectively, compared to 14% and 86%, respectively, in the prior year period.

Our sales mix of metallurgical coal and steam coal based on revenues for the twelve months ended December 31, 2011 was 50% compared with 39% and 61% in the prior year period. Our sales mix of metallurgical coal and steam coal based on revenues for the Massey operations for the twelve months ended December 31, 2011 was 42% and 58%, respectively, and our sales mix of metallurgical coal and steam coal based on revenues for the Alpha operations for the twelve months ended December 31, 2011 was 54% and 46%, respectively, compared to 39% and 61%, respectively, in the prior year period.

Freight and handling. Freight and handling revenues and costs were $662.2 million for the twelve months ended December 31, 2011, an increase of $329.7 million, or 99%, compared to the prior year period. The increase was due to higher export shipments combined with higher shipping rates compared to the prior year period.

Other revenues. Other revenues increased $169.3 million, or 195%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase in other revenues was largely due to increased revenues of approximately $129.0 million related to derivative contracts accounted for at fair value, a majority of which were assumed in the Massey Acquisition, sublease revenues of approximately $14.4 million related to a sea-going vessel charter that we entered into in December 2010, increased rail load-out refunds of $10.0 million and increased royalty and rental revenues of approximately $6.6 million.

Costs and expenses

	Years Ended December 31,					Increase (Decrease)
	2011			2010		$			%
	(In thousands, except per ton data)
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)	$	5,080,921		$	2,566,825	$	2,514,096		98	%
Freight and handling costs	662,238			332,559		329,679			99	%
Other expenses	142,709			65,498		77,211			118	%
Depreciation, depletion and amortization	770,769			370,895		399,874			108	%
Amortization of acquired intangibles, net	(114,422		)	226,793		(341,215		)	(150	)%
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)	382,250			180,975		201,275			111	%
Goodwill impairment	802,337			—		802,337			NM
Total costs and expenses	$	7,726,802		$	3,743,545	$	3,983,257		106	%
Cost of coal sales per ton(1):
Eastern coal operations	$	80.06		$	59.47	$	20.59		35	%
Western coal operations	$	9.99		$	8.56	$	1.43		17	%
Average	$	47.14		$	30.08	$	17.06		57	%

______________________

⁽¹⁾  Cost of coal sales per ton includes only costs associated with our Eastern and Western Coal Operations.

Cost of coal sales. Cost of coal sales increased $2,514.1 million, or 98%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase in cost of coal sales consisted of an increase of $591.3 million, or 23%, from the Alpha operations and $1,922.8 million from the Massey operations. The increases from the Alpha operations were primarily driven by increased production of higher cost metallurgical coal tons, increases in purchased coal expenses, increased costs for commodities used in the production process, higher sales related variable costs such as royalties and production and severance taxes due to higher sales realizations for metallurgical coal, transportation expenses and wages and employee benefits. Cost of coal sales from the Alpha operations included charges of approximately $37.1 million related to changes in asset retirement obligation-related estimates of water treatment costs at certain closed mines. Cost of coal sales from the Massey operations included charges of approximately $152.7 million related to the fair value adjustment made in acquisition accounting to

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Massey's beginning inventory, approximately $35.5 million related to accruals made in connection with aligning certain employee benefits for employees from Massey and other employee compensation-related accruals, approximately $40.9 million of operating costs related to an idled mine and approximately $8.0 million related to expenses in connection with mineral lease terminations. The consolidated average cost of coal sales per ton was $47.14 compared to $30.08 in the prior year period. The average cost of coal sales per ton for Eastern and Western Coal Operations was $80.06 and $9.99, respectively, compared to $59.47 and $8.56, respectively, in the prior year period.

Other expenses. Other expenses increased $77.2 million, or 118%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase in other expenses was primarily due to increased expenses of approximately $61.2 million for contract-related matters primarily related to contracts assumed in the Massey Acquisition, an increase of approximately $17.6 million related to sea-going vessel charters that we entered into in the fourth quarter of 2010 and the first half of 2011, and increases of approximately $4.2 million and $3.5 million related to Dry Systems Technologies and sales of natural gas, respectively.

Depreciation, depletion and amortization. Depreciation, depletion, and amortization increased $399.9 million, or 108%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase consisted of depreciation, depletion and amortization of $397.7 million from the Massey operations, which includes impacts of fair value adjustments made to property and equipment and owned and leased mineral rights in acquisition accounting, and increased depreciation, depletion and amortization of $2.2 million from the Alpha operations.

Amortization of acquired intangibles, net. Amortization of acquired intangibles, net decreased $341.2 million, or 150%, for the twelve months ended December 31, 2011 compared to the prior year period. The decrease consisted of a $125.0 million decrease in amortization expense of acquired above-market coal supply agreements from the Alpha operations and a net credit to amortization expense from the Massey operations of $216.2 million related to the amortization of acquired below-market coal supply agreements and amortization of other intangible assets that were valued in the Massey Acquisition.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $201.3 million, or 111%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase was due primarily to acquisition-related expenses totaling $164.0 million for a combination of employee compensation, professional fees incurred for legal, valuation and financial services in connection with the Massey Acquisition and related debt financing transactions and increased non-cash stock-based compensation.

Goodwill impairment. See Note 9 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K. Also, see Critical Accounting Policies.

Interest expense. Interest expense increased $68.5 million, or 93%, during the twelve months ended December 31, 2011 compared to the prior year period primarily due to a larger average outstanding balance of debt during the period as a result of the debt assumed in the Massey Acquisition and the financing transactions that were completed during the period.

Income tax benefit. Income tax benefit from continuing operations of $35.9 million was recorded for the twelve months ended December 31, 2011 on loss from continuing operations before income taxes of $766.4 million, which equates to an effective tax rate of 4.7%. The rate is lower than the federal statutory rate of 35% primarily due to the non-deductible goodwill impairment and the impact of the percentage depletion deduction.

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 the percentage depletion deduction and the reversal of certain tax reserves of approximately $14.0 million, partially offset by 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).

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Segment Analysis

	Years Ended December 31,				Increase (Decrease)
	2011		2010		Tons/$			Percent
	(In thousands, except per ton data)
Western Coal Operations
Steam tons sold	49,949		48,977		972			2	%
Steam coal sales realization per ton	$	11.95	$	10.95	$	1.00		9	%
Total revenues	$	602,157	$	544,058	$	58,099		11	%
EBITDA from continuing operations	$	74,891	$	97,583	$	(22,692	)	(23	)%
Eastern Coal Operations
Steam tons sold	37,192		24,001		13,191			55	%
Metallurgical tons sold	19,177		11,871		7,306			62	%
Steam coal sales realization per ton	$	66.92	$	67.07	$	(0.15	)	—	%
Metallurgical coal sales realization per ton	$	161.85	$	113.89	$	47.96		42	%
Total revenues	$	6,423,805	$	3,324,548	$	3,099,257		93	%
EBITDA from continuing operations	$	143,649	$	678,339	$	(534,690	)	(79	)%

Western Coal Operations - EBITDA from continuing operations for our Western Coal Operations decreased $22.7 million, or 23%, compared to the prior year period. The decrease was due primarily to increased cost of coal sales, selling, general and administrative expenses and other expenses of $80.0 million, $0.4 million and $0.4 million, respectively, partially offset by an increase in total revenues of $58.1 million. Cost of coal sales per ton increased $1.43, or 17% while average coal sales realization per ton increased $1.00, or 9%, resulting in a decrease to coal margin per ton of $0.43, or 18%. The increase in cost of coal sales per ton was due primarily to increased diesel fuel expenses, increased sales-related variable costs due to higher sales realization per ton, a higher ratio of production from the Belle Ayr mine which incurs higher production costs due to higher stripping ratios, and weather related delays experienced in the second quarter of 2011 that impacted transportation and coal shipments. The increase in total revenues consisted of an increase in coal revenues of $60.7 million, or 11%, partially offset by decreased other revenues of $2.6 million, or 32%. The increase in coal revenues was largely due to the increase in average coal sales realization per ton, which reflected increased shipments and increased contractual pricing during the period compared to the prior year.

Eastern Coal Operations - EBITDA from continuing operations decreased $534.7 million, or 79%, compared to the prior year period. The decrease was due to a goodwill impairment charge of $802.3 million, increased cost of coal sales of $2,379.6 million, increased other expenses of $50.7 million and increased selling, general and administrative expenses of $72.6 million, increased other miscellaneous expenses of $0.6 million and an increase in loss on early extinguishment of debt of $3.1 million, partially offset by increased coal and other revenues of $2,630.9 million and $143.3 million, respectively. Coal revenues and cost of coal sales for the East include $1,878.6 million and $1,922.8 million, respectively, from the Massey operations for the twelve months ended December 31, 2011.

Average coal sales realization per ton increased $16.65, or 20%, compared to the prior year period. The increase in average coal sales realization per ton was due primarily to an increase of $47.96, or 42%, related to metallurgical average coal sales realization. The average coal sales realization per ton for metallurgical coal related to the Alpha operations was $162.92, an increase of $49.03, or 43%, compared to the prior year period. The average coal sales realization per ton for metallurgical coal related to the Massey operations was $158.85.

Average cost of coal sales per ton increased $20.59, or 35%, compared to the prior year period. The increase in cost of coal sales per ton was due primarily to increased production of metallurgical tons in response to the increase in demand, lower production at our longwall mines, increases in royalties and production taxes due to higher average sales realization per ton and inflationary increases to other variable costs. Cost of coal sales from the Alpha operations included charges of approximately $37.1 million related to changes in asset retirement obligation-related estimates of water treatment costs at certain closed mines. Cost of coal sales from the Massey operations included charges of approximately $152.7 million related to the fair value adjustment made in acquisition accounting to Massey's beginning inventory, approximately $35.5 million related to accruals made in connection with aligning certain employee benefits for employees from Massey and other employee compensation-

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related accruals, approximately $40.9 million of operating costs related to an idled mine and approximately $8.0 million related to expenses in connection with mineral lease terminations.

Liquidity and Capital Resources

Our primary liquidity and capital resource requirements stem from the cost of our coal production and purchases, our capital expenditures, our income taxes, our debt service, our reclamation obligations, our litigation settlements and associated costs, and from time to time, our securities repurchases. Our primary sources of liquidity have been from sales of coal, borrowings under our credit facility and debt arrangements (see “—Credit Agreement and Long-Term Debt”), and to a much lesser extent, sales of purchased coal to customers, cash from sales of non-core assets and miscellaneous revenues.

We believe that cash on hand, cash generated from our operations and borrowing capacity available under the Third Amended and Restated Credit Agreement and our accounts receivable securitization facility (the “A/R Facility”) will be sufficient to meet our working capital requirements, anticipated capital expenditures, debt service requirements, reclamation obligations, potential securities repurchases, and expected settlements and costs related to outstanding litigation for at least the next twelve months.

At December 31, 2012, we had available liquidity of $2,052.2 million, including cash and cash equivalents of $730.7 million, marketable securities of $298.2 million and $1,023.3 million of unused revolving credit facility commitments available under the Third Amended and Restated Credit Agreement and our A/R Facility, after giving effect to $0.3 million and $160.2 million of letters of credit outstanding, respectively, as of December 31, 2012, subject to limitations described in the Third Amended and Restated Credit Agreement and the A/R Facility. Our total long-term debt, net of debt discount and including current portion, was $3,386.1 million at December 31, 2012, see “—Credit Agreement and Long-Term Debt”.

On May 8, 2012, Standard & Poor's rating service lowered its rating for our overall corporate credit to BB- from BB, lowered its rating for our 6.00% senior notes due 2019 and our 6.25% senior notes due 2021, and lowered its rating of our 2.375% convertible senior notes due 2015 (the “2.375% Convertible Notes”). On June 27, 2012, Moody's lowered our corporate family rating from Ba2 to B1 and also lowered the ratings on our senior unsecured debt from Ba3 to B2. Additionally, on September 27, 2012, Standard & Poor's rating service lowered its rating for our overall corporate credit to B+ from BB-. Given that we do not have negative ratings triggers in our credit facilities or bond indentures, our compliance with covenants and the availability of funding under our facilities and indentures has not been impacted by these downgrades.

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. 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. Our pension plans have funding ratios greater than 80%. Annual funding contributions to the plans are made as recommended by consulting actuaries based upon the ERISA funding standards. Plan assets consist of cash and cash equivalents, an investment in a group annuity contract, equity and fixed income funds, and private equity funds. We are required 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. The volatile financial markets in 2008 and 2009 caused investment income and the value of the investment assets held in our pension trust to decline.  As a result, depending on economic recovery and growth in the value of our invested assets, 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 2013 of up to $20.0 million for our defined benefit pension plans.

In September 2011, we entered into a federal coal lease, which contains an estimated 130.2 million tons of proven and probable coal reserves in the Powder River Basin. The lease bid was $143.4 million, payable in five equal annual installments of $28.7 million. The first installment was paid in September 2011. In August 2012, we entered into an agreement with a third party to exchange our federal coal lease for another federal coal lease, which contains an estimated 222.0 million tons of proven and probable coal reserves in the Powder River Basin adjacent to our existing mining operations. As a result of the exchange, we paid $17.4 million at closing and have four annual remaining lease bid installments of $42.1 million due each November until the obligation is satisfied in 2015. We paid the first annual installment of $42.1 million in November 2012. Also, as a result of the exchange, we recorded a note payable which had a present value of approximately $10.3 million as of December 31, 2012, of which approximately $3.9 million is included in current portion of long-term debt and approximately $6.4 million is included in long-term debt on our consolidated balance sheet. This note is payable in four annual installments of $3.9 million due each November through 2015. We paid the first annual installment of $3.9 million in November 2012.

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With respect to global economic events, there continues to be uncertainty in the financial markets and weakness in the coal industry, and these issues bring potential liquidity risks for us. These risks could include declines in our stock value, declines in our cash and cash equivalents, less availability and higher costs of additional credit, restrictions to or the loss of our self-bonding capability and requests for additional collateral by surety providers and potential counterparty defaults and 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.

Cash Flows

Cash and cash equivalents increased by $144.8 million, $31.1 million and $88.9 million for the years ended December 31, 2012, 2011 and 2010. The net change in cash and cash equivalents was attributable to the following:

Cash Flows	Years Ended December 31,
(in thousands)	2012			2011			2010
Net cash provided by operating activities	$	518,419		$	686,637		$	693,601
Net cash used in investing activities	(672,976		)	(1,147,007		)	(508,497		)
Net cash (used in) provided by financing activities	299,398			491,480			(96,201		)
Net change in cash and cash equivalents	$	144,841		$	31,110		$	88,903

Net cash provided by operating activities for the year ended December 31, 2012 was $518.4 million, a decrease of $168.2 million from the $686.6 million of net cash provided by operating activities for the year ended December 31, 2011. In addition to reduced cash earnings, the decrease in operating cash flows is partially due to cash payments, net of insurance recoveries, to settle litigation matters acquired from Massey, including UBB wrongful death claims, and cash payments for restructuring obligations, partially offset by a contractual prepayment received for which revenue was deferred until the underlying tons are shipped in future years.

Net cash used in investing activities for the year ended December 31, 2012 was $673.0 million, a decrease of $474.0 million from the $1,147.0 million of net cash used in investing activities for the year ended December 31, 2011. The decrease was primarily due to the inclusion in 2011 of the cash portion of consideration paid to acquire Massey of $711.4 million, net of cash acquired. Capital expenditures decreased to $402.4 million in 2012 from $528.6 million in 2011. Cash paid for acquisition of mineral rights increased to $95.8 million in 2012 from $64.9 million in 2011. Proceeds from disposition of property, plant and equipment increased to $38.3 million in 2012 from $8.5 million in 2011.

Net cash provided by financing activities for the year ended December 31, 2012 was $299.4 million, a decrease of $192.1 million from the $491.5 million of net cash provided by financing activities for the year ended December 31, 2011. The primary source of cash for financing activities included $494.8 million of proceeds from borrowings of long-term debt, offset by principal repayments and repurchases of long-term debt of $160.2 million. Debt issuance costs account for $16.4 million of the use of cash for financing activities for the year ended December 31, 2012. Common stock repurchases consist of shares repurchased from employees to satisfy the employees’ minimum statutory tax withholdings upon the vesting of restricted stock and performance shares and used cash of $7.5 million in 2012.

Net cash provided by operating activities for the year ended December 31, 2011 was $686.6 million, a decrease of $7.0 million from the $693.6 million of net cash provided by operating activities for the year ended December 31, 2010. Non-cash amounts included in net income for the year ended December 31, 2011 were primarily related to an increase in depreciation, depletion, accretion and amortization expense, an increase in amortization of debt issuance costs and accretion of debt discount, a decrease in mark-to-market adjustments for derivatives, an increase in stock-based compensation expense, an increase in employee benefit plan costs, a decrease in deferred taxes, and a goodwill impairment charge. The cash used by changes in operating assets and liabilities for the year ended December 31, 2011 was primarily related to an increase in accounts receivable, net of $178.7 million, a decrease in inventories, net of $120.5 million, and a decrease of $105.6 million in pension and postretirement medical benefit obligations.

Net cash used in investing activities for the year ended December 31, 2011 was $1,147.0 million, an increase of $638.5 million from the $508.5 million of net cash used in investing activities for the year ended December 31, 2010. The increase was primarily due to the cash portion of consideration paid to acquire Massey of $711.4 million, net of cash acquired, and increased capital expenditures of $219.7 million.

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Net cash provided by financing activities for the year ended December 31, 2011 was $491.5 million, an increase of $587.7 million from the $96.2 million of net cash used in financing activities for the year ended December 31, 2010. The primary source of cash for financing activities included $2,100.0 million of proceeds from borrowings of long-term debt, offset by principal repayments of long-term debt of $1,315.4 million. In addition, common stock repurchases of $212.3 million and debt issuance costs of $85.2 million account for $297.5 million of the use of cash for financing activities for the year ended December 31, 2011. Common stock repurchases consist of shares repurchased as part of publically announced share repurchase programs and repurchase of common shares from employees to satisfy the employees' minimum statutory tax withholdings upon the vesting of restricted stock and performance shares. The majority of the financing activities for the year ended December 31, 2011 relate to the Massey Acquisition.

Credit Agreement and Long-term Debt

As of December 31, 2012 and 2011, our total long-term indebtedness consisted of the following (in thousands):

	December 31, 2012			December 31, 2011
6.25% senior notes due 2021	$	700,000		$	700,000
6.00% senior notes due 2019	800,000			800,000
9.75% senior notes due 2018	500,000			—
Term loan due 2016	540,000			585,000
3.25% convertible senior notes due 2015	536,162			658,673
2.375% convertible senior notes due 2015	287,500			287,500
Other	86,203			23,554
Debt discount	(63,813		)	(86,646		)
Total long-term debt	3,386,052			2,968,081
Less current portion	(95,015		)	(46,029		)
Long-term debt, net of current portion	$	3,291,037		$	2,922,052

Notes Indenture and the Senior Notes

On June 1, 2011, we and certain of our wholly owned domestic subsidiaries (collectively, the “Alpha Guarantors”) and Union Bank, N.A., as trustee, entered into an indenture (the “Base Indenture”) and a first supplemental indenture (the “First Supplemental Indenture” and, together with the Base Indenture, the “Notes Indenture”) governing our newly issued 6.00% senior notes due 2019 (the “2019 Notes”) and 6.25% senior notes due 2021 (the “2021 Notes”).

On June 1, 2011, in connection with the Massey Acquisition, we, the Alpha Guarantors, Massey, and certain wholly owned subsidiaries of Massey (the “Massey Guarantors” and together with the Alpha Guarantors the “Guarantors”), and Union Bank, N.A., as trustee, entered into a supplemental indenture (the “Second Supplemental Indenture”) to the Notes Indenture pursuant to which Massey and certain wholly owned subsidiaries of Massey agreed to become additional guarantors for the 2019 Notes and 2021 Notes.

On October 11, 2012, we, the Alpha Guarantors and Union Bank, N.A., as trustee, entered into a supplemental indenture (the “Third Supplemental Indenture”) to the Notes Indenture governing our newly issued 9.75% senior notes due 2018 (the “2018 Notes” and, together with the 2019 Notes and the 2021 Notes, the “Senior Notes”).

The 2018 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on April 15 and October 15 of each year, beginning on April 15, 2013, and will mature on April 15, 2018. The 2019 Notes bear interest at a rate of 6.00% per annum, payable semi-annually on June 1 and December 1 of each year, beginning on December 1, 2011, and will mature on June 1, 2019. The 2021 Notes bear interest at a rate of 6.25% per annum, payable semi-annually on June 1 and December 1 of each year, beginning on December 1, 2011, and will mature on June 1, 2021.

As of December 31, 2012, the carrying values of the 2018 Notes, 2019 Notes and 2021 Notes were $495.2 million, net of discount of $4.8 million, $800.0 million and $700.0 million, respectively. As of December 31, 2011, the carrying values of the 2019 Notes and 2021 Notes were $800.0 million and $700.0 million, respectively.

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We may redeem the 2018 Notes, in whole or in part, at any time prior to maturity, at a price equal to 100.000% of the aggregate principal amount of the 2018 Notes plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date. In addition, we may redeem up to 35% of the aggregate principal amount of the 2018 Notes with the net cash proceeds from certain equity offerings, at any time prior to October 15, 2015, at a redemption price equal to 109.75% of the aggregate principal amount of the 2018 Notes, plus accrued and unpaid interest, if any, to, but not including the applicable redemption date, if at least 65% of the aggregate principal amount of the 2018 Notes originally issued under the Notes Indenture remains outstanding immediately after the redemption and the redemption occurs within 180 days of the date of the closing of such equity offering.

We may redeem the 2019 Notes, in whole or in part, at any time prior to June 1, 2014, at a price equal to 100.000% of the aggregate principal amount of the 2019 Notes plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date.  We may redeem the 2019 Notes, in whole or in part, at any time during the twelve months commencing June 1, 2014, at 103.000% of the aggregate principal amount of the 2019 Notes, at any time during the twelve months commencing June 1, 2015, at 101.500% of the aggregate principal amount of the 2019 Notes, and at any time after June 1, 2016 at 100.000% of the aggregate principal amount of the 2019 Notes, in each case plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date.  In addition, we may redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net cash proceeds from certain equity offerings, at any time prior to June 1, 2014, at a redemption price equal to 106.000% of the aggregate principal amount of the 2019 Notes, plus accrued and unpaid interest, if any, to, but not including the applicable redemption date, provided that at least 65% of the aggregate principal amount of the 2019 Notes originally issued under the Notes Indenture remains outstanding after the redemption and the redemption occurs within 180 days of the closing of such equity offering.

We may redeem the 2021 Notes, in whole or in part, at any time prior to June 1, 2016, at a price equal to 100.000% of the aggregate principal amount of the 2021 Notes plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date.  We may redeem the 2021 Notes, in whole or in part, at any time during the twelve months commencing June 1, 2016, at 103.125% of the aggregate principal amount of the 2021 Notes, at any time during the twelve months commencing June 1, 2017, at 102.083% of the aggregate principal amount of the 2021 Notes, at any time during the twelve months commencing June 1, 2018, at 101.042% of the aggregate principal amount of the 2021 Notes, and at any time after June 1, 2019, at 100.000% of the aggregate principal amount of the 2021 Notes, in each case plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date.  In addition, we may redeem up to 35% of the aggregate principal amount of the 2021 Notes with the net cash proceeds from certain equity offerings, at any time prior to June 1, 2016, at a redemption price equal to 106.250% of the aggregate principal amount of the 2021 Notes, plus accrued and unpaid interest, if any, to, but not including the applicable redemption date, provided that at least 65% of the aggregate principal amount of the 2021 Notes originally issued under the Notes Indenture remains outstanding after the redemption and the redemption occurs within 180 days of the date of the closing of such equity offering.

Upon the occurrence of a change in control repurchase event with respect to any of the series of the Senior Notes, unless we have exercised our right to redeem those Senior Notes, we will be required to offer to repurchase each holder’s Senior Notes of such series at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the date of repurchase.

The Notes Indenture contains covenants that limit, among other things, our ability to:

• incur, or permit its subsidiaries to incur, additional debt;

• issue, or permit its subsidiaries to issue, certain types of stock;

• pay dividends on our or our subsidiaries’ capital stock or repurchase our common stock;

• make certain investments;

• enter into certain types of transactions with affiliates;

• incur liens on certain assets to secure debt;

• limit dividends or other payments by its restricted subsidiaries to us and our other restricted subsidiaries;

• consolidate, merge or sell all or substantially all of our assets; and

• make certain payments on our or our subsidiaries’ subordinated debt.

These covenants are subject to a number of important qualifications and exceptions. These covenants may not apply at any time after the Senior Notes are assigned a credit grade rating of at least BB+ (stable) from Standard & Poor’s Ratings Services and of at least Ba1 (stable) from Moody’s Investor Service, Inc.

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Third Amended and Restated Credit Agreement

On May 19, 2011, in connection with the Massey Acquisition, we entered into a Third Amended and Restated Credit Agreement to amend and restate in its entirety our credit agreement dated as of July 30, 2004, as amended as of November 12, 2004 and as of October 18, 2005, as amended and restated as of July 7, 2006, as amended effective July 31, 2009 and as further amended and restated as of April 15, 2010 (as so amended and restated, the “Former Credit Agreement”; the Former Credit Agreement, as amended and restated by the Third Amended and Restated Credit Agreement, is referred to as the “Credit Agreement”), with Citicorp North America, Inc., as administrative agent and as collateral agent, Bank of America, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, The Royal Bank of Scotland plc and Union Bank, N.A. and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as co-documentation agents, Morgan Stanley Senior Funding, Inc., as sole syndication agent, Citigroup Global Markets Inc. and Morgan Stanley Senior Funding, Inc., as joint lead arrangers and joint book managers, and various other financial institutions, as lenders. The terms of the Credit Agreement amended and restated and superseded the Former Credit Agreement in its entirety upon the satisfaction of certain conditions precedent, which included the consummation of the Massey Acquisition (the satisfaction of such conditions precedent is referred to as the “initial Credit Event”). The Former Credit Agreement remained in full force and effect until the occurrence of the initial Credit Event.

Upon the occurrence of the initial Credit Event, the Credit Agreement provided for a $600.0 million senior secured term loan A facility (the “Term Loan Facility”) and a $1.0 billion senior secured revolving credit facility (the “Revolving Facility”).  Pursuant to the Credit Agreement, we may request incremental term loans or increase the revolving commitments under the Revolving Facility in an aggregate amount of up to $1.3 billion plus an additional $750.0 million subject to compliance with a consolidated senior secured leverage ratio.  The lenders under these facilities will not be under any obligation to provide any such incremental loans or commitments, and any such addition of or increase in such loans or commitments will be subject to certain customary conditions precedent.

On June 26, 2012, we entered into an amendment (the “Credit Agreement Amendment”) to the Credit Agreement. The Credit Agreement Amendment, among other things:

1) replaces the maximum net leverage ratio covenant with a maximum net secured leverage ratio covenant through the end of 2014, increases the maximum net leverage ratio covenant for the first and second quarters of 2015, and decreases the minimum interest coverage ratio from the fourth quarter of 2012 through the end of 2013;

2) adds a minimum liquidity covenant of $500.0 million through the end of 2014;

3) increases the applicable margin for borrowings under the Credit Agreement if our consolidated net leverage ratio is greater than 3.75 to 1.00 for the preceding fiscal quarter;

4) modifies the requirements for incremental term loan or revolving credit facilities in excess of $500.0 million; and,

5) provides additional real property collateral to secure obligations under the Credit Agreement and certain hedging and cash management obligations with lenders and affiliates of lenders.

As of December 31, 2012, the carrying value of the Term Loan Facility was $539.5 million, net of debt discount of $0.5 million, with $75.0 million classified as current portion of long-term debt. As of December 31, 2011, the carrying value of the Term Loan Facility was $584.3 million, net of debt discount of $0.7 million, with $45.0 million classified as current portion of long-term debt. There were no borrowings outstanding under the Revolving Facility as of December 31, 2012 or 2011. Letters of credit outstanding at December 31, 2012 and 2011 under the Revolving Facility were $0.3 million and $0.3 million, respectively.

Interest Rate and Fees.  Borrowings under the Credit Agreement bear interest at a rate per annum equal to an applicable margin plus, at our option, either (a) a base rate determined by reference to the highest of (i) the rate that Citibank, N.A. announces from time to time as its prime or base commercial lending rate, (ii) the federal funds effective rate plus 0.50% and (iii) a London Interbank Offer (“LIBO”) rate for a 30-day interest period as determined on such day, plus 1.00%, or (b) a LIBO rate for the interest period relevant to such borrowing adjusted for certain additional costs.  The initial applicable margin for borrowings under the Credit Agreement is 1.50% with respect to base rate borrowings and 2.50% with respect to LIBO rate borrowings.  Commencing October 1, 2011, the applicable margin for borrowings under the Credit Agreement became subject to adjustment each fiscal quarter based on our consolidated leverage ratio for the preceding fiscal quarter.  Swingline loans bear interest at a rate per annum equal to the base rate plus the applicable margin.  The interest rate in effect at December 31, 2012 and 2011 was 2.72% and 2.51%, respectively. In addition to paying interest on outstanding principal under the Credit Agreement, we are required to pay a commitment fee to the lenders under the Revolving Facility in respect of the unutilized

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commitments thereunder. The initial commitment fee is 0.50% per annum.  Commencing October 1, 2011, the commitment fee became subject to adjustment each fiscal quarter based on our consolidated leverage ratio for the preceding fiscal quarter.  We must also pay customary letter of credit fees and agency fees.

Mandatory Prepayments.  The Credit Agreement requires us to prepay outstanding loans, subject to certain exceptions, with (i) 100% of the net cash proceeds (including the fair market value of noncash proceeds) from certain asset sales and condemnation events in excess of the greater of $1.5 billion and 15% of consolidated tangible assets as of the end of each fiscal year, (ii) 100% of the aggregate gross proceeds (including the fair market value of noncash proceeds) from certain Intracompany Disposals (as defined in the Credit Agreement) exceeding $500.0 million during the term of the Credit Agreement and (iii) 100% of the net cash proceeds from any incurrence or issuance of certain debt, other than debt permitted under the Credit Agreement. Mandatory prepayments will be applied first to the Term Loan Facility and thereafter to reductions of the commitments under the Revolving Facility. If at any time the aggregate amount of outstanding revolving loans, swingline loans, unreimbursed letter of credit drawings and undrawn letters of credit under the Revolving Facility exceeds the commitment amount, we will be required to repay outstanding loans or cash collateralize letters of credit in an aggregate amount equal to such excess, with no reduction of the commitment amount.

Voluntary Prepayments; Reductions in Commitments. We may prepay, in whole or in part, amounts outstanding under the Credit Agreement, with prior notice but without premium or penalty (other than customary “breakage” costs with respect to LIBO rate loans) and in certain minimum amounts.  We may also repurchase loans outstanding under the Term Loan Facility pursuant to standard reverse Dutch auction and open market purchase provisions, subject to certain limitations and exceptions.  We may make voluntary reductions to the unutilized commitments of the Revolving Facility from time to time without premium or penalty.

Amortization and Final Maturity.  Beginning on September 30, 2011, we became required to make scheduled quarterly amortization payments with respect to loans under the Term Loan Facility.  In the first two quarters of 2013, each quarterly amortization payment will be in an amount equal to 2.5% of the original principal amount of the term loans.  In the last two quarters of 2013 and the first two quarters of 2014, each quarterly amortization payment will be in an amount equal to 3.75% of the original principal amount of the term loans.  In the last two quarters of 2014 and the first two quarters of 2015, each quarterly amortization payment will be in an amount equal to 5% of the original principal amount of the term loans.  In the last two quarters of 2015 and the first two quarters of 2016, each quarterly amortization payment will be in an amount equal to 12.5% of the original principal amount of the term loans.  There is no scheduled amortization under the Revolving Facility.  The principal amount outstanding on the loans under the Revolving Facility will be due and payable on June 30, 2016.  The Term Loan Facility and Revolving Facility will each mature on June 30, 2016.

Guarantees and Collateral.  All obligations under the Credit Agreement are unconditionally guaranteed by certain of our existing wholly owned domestic subsidiaries, and are required to be guaranteed by certain of our future wholly owned domestic subsidiaries.  All obligations under the Credit Agreement and certain hedging and cash management obligations with lenders and affiliates of lenders thereunder are secured, subject to certain exceptions, by substantially all of our assets and the assets of our subsidiary guarantors, in each case subject to exceptions, thresholds and limitations.

Certain Covenants and Events of Default. The Credit Agreement contains a number of negative covenants that, among other things and subject to certain exceptions, restrict our ability and the ability of our subsidiaries to:

• make investments, loans and acquisitions;

• incur additional indebtedness;

• incur liens;

• consolidate or merge;

• sell assets, including capital stock of its subsidiaries;

• pay dividends on its capital stock or redeem, repurchase or retire its capital stock or its other Indebtedness;

• engage in transactions with its affiliates;

• materially alter the business it conducts; and

• create restrictions on the payment of dividends or other amounts to us from our restricted subsidiaries.

In addition, the Credit Agreement requires us to comply with certain financial ratio maintenance covenants described below.

The Credit Agreement also contains customary representations and warranties, affirmative covenants and events of default, including a cross-default provision in respect of any other indebtedness that has an aggregate principal amount exceeding $25.0 million.

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Former Credit Agreement

The Former Credit Agreement consisted of term loans and revolving credit facility commitments due on July 31, 2014.  During the year ended December 31, 2011, borrowings under the Former Credit Agreement totaling $227.9 million were repaid.  The Former Credit Agreement was replaced with the Credit Agreement as described above.

3.25% Convertible Senior Notes due 2015

As a result of the Massey Acquisition, we became a guarantor of Massey’s 3.25% Convertible Notes, with aggregate principal outstanding at June 1, 2011 of $659.1 million. The 3.25% Convertible Notes bear interest at a rate of 3.25% per annum, payable semi-annually in arrears on August 1 and February 1 of each year. The 3.25% Convertible Notes will mature on August 1, 2015, unless earlier repurchased by us or converted. The 3.25% Convertible Notes had a fair value of $730.9 million at the acquisition date. We account for the 3.25% Convertible Notes under Accounting Standards Codification (“ASC”) 470-20, which requires issuers of convertible debt instruments that may be settled wholly or partially in cash upon conversion to separately account for the liability and equity components in a manner reflective of the issuers’ nonconvertible debt borrowing rate.  As of December 31, 2012, the carrying amount of the debt was $515.9 million, net of debt discount of $20.3 million. As of December 31, 2011, the carrying amount of the debt was $624.9 million, net of debt discount of $33.7 million.  As of December 31, 2012 and 2011, the carrying amount of the equity component totaled $110.4 million.  The debt discount is being accreted over the four-year term of the 3.25% Convertible Notes, and provides for an effective interest rate of 4.21%.

On October 25, 2012, we completed a cash tender offer for a portion of the outstanding 3.25% Convertible Notes. We paid $115.9 million, including interest, to redeem $122.5 million of the 3.25% Convertible Notes. We recognized a gain on early extinguishment of debt of $0.8 million.

The 3.25% Convertible Notes are senior unsecured obligations and rank equally with all of our existing and future senior unsecured indebtedness. The 3.25% Convertible Notes are guaranteed on a senior unsecured basis by Massey’s subsidiaries (which are among our subsidiaries), other than certain minor subsidiaries of Massey.  The 3.25% Convertible Notes are effectively subordinated to all our existing and future secured indebtedness and all existing and future liabilities of our non-guarantor subsidiaries, including trade payables. The 3.25% Convertible Notes are convertible in certain circumstances and in specified periods at a conversion rate, subject to adjustment, of the value of 11.4560 shares of common stock per $1,000 principal amount of 3.25% Convertible Notes. From and after the effective date of the Massey Acquisition, the consideration deliverable upon conversion of the 3.25% Convertible Notes ceased to be based upon Massey common stock and instead became based upon Reference Property (as defined in the indenture governing the 3.25% Convertible Notes, (the “3.25% Convertible Notes Indenture”)) consisting of 1.025 shares of our common stock (subject to adjustment upon the occurrence of certain events set forth in the 3.25% Convertible Notes Indenture) plus $10.00 in cash per share of Massey common stock. Upon conversion of the 3.25% Convertible Notes, holders will receive cash up to the principal amount of the notes being converted, and any excess conversion value will be delivered in cash, Reference Property, or a combination thereof, at our election. One of the circumstances under which the 3.25% Convertible Notes would become convertible is if our common stock price exceeds a set threshold during a reference period specified in the 3.25% Convertible Notes Indenture.

The 3.25% Convertible Notes Indenture contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee or the holders of at least 25% in aggregate principal amount of the 3.25% Convertible Notes then outstanding may declare the principal of the 3.25% Convertible Notes and any accrued and unpaid interest immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to the Company, the principal amount of the 3.25% Convertible Notes together with any accrued and unpaid interest thereon will automatically become due and immediately payable.

The 3.25% Convertible Notes were not convertible as of December 31, 2012 or 2011 and as a result have been classified as long-term at both dates. 

2.375% Convertible Senior Notes Due April 15, 2015

As of December 31, 2012 and 2011, we had $287.5 million aggregate principal amount of 2.375% convertible senior notes due April 15, 2015 (the “2.375% Convertible Notes”).  The 2.375% 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 its 2.375% Convertible Notes under ASC 470-20, which requires issuers of convertible debt instruments that may be settled wholly or partially in cash upon conversion to separately account for the liability and equity components in a manner reflective of the

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issuers’ nonconvertible debt borrowing rate.  The related deferred loan costs and discount are being amortized and accreted, respectively, over the seven-year term of the 2.375% Convertible Notes, and provide for an effective interest rate of 8.64%.  As of December 31, 2012 and 2011, the carrying amounts of the debt component were $249.3 million and $235.3 million, respectively.  As of December 31, 2012 and 2011, the unamortized debt discount was $38.2 million and $52.2 million, respectively.  As of December 31, 2012 and 2011, the carrying amount of the equity component was $69.9 million.

The 2.375% Convertible Notes are our senior unsecured obligations and rank equally with all of our existing and future senior unsecured indebtedness. The 2.375% 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 2.375% 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 2.375% Convertible Notes, subject to adjustment upon the occurrence of certain events set forth in the indenture governing the 2.375% Convertible Notes (the “2.375% Convertible Notes Indenture”). Upon conversion of the 2.375% 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 combination thereof, at our election.

The 2.375% 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, or the holders of not less than 25% in aggregate principal amount of the 2.375% Convertible Notes then outstanding may declare the principal of 2.375% 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 us, the principal amount of the 2.375% Convertible Notes together with any accrued and unpaid interest thereon will automatically become due and be immediately payable.

The 2.375% Convertible Notes were not convertible as of December 31, 2012 and 2011 and therefore have been classified as long-term debt at both dates.

6.875% Senior Notes due 2013

We assumed Massey’s 6.875% senior notes due 2013 (the “2013 Notes”) with an aggregate principal amount outstanding of $760.0 million as part of the Massey Acquisition. Following a cash tender offer for the 2013 Notes and upon redemption of the 2013 Notes on the redemption date of July 1, 2011, we recorded a loss on early extinguishment of $0.8 million.

7.25% Senior Notes Due August 1, 2014

Foundation PA, one of our subsidiaries, had notes that were scheduled to mature on August 1, 2014 (the “2014 Notes”). The outstanding 2014 Notes were redeemed and became due and payable on August 18, 2011 (the “Redemption Date”), at a redemption price equal to 101.208% of the principal amount of the 2014 Notes, plus any and all accrued and unpaid interest up to but excluding the Redemption Date. We paid $302.9 million, including interest, to redeem the 2014 Notes. We recognized a loss on early extinguishment of debt of $4.4 million, including the premium paid.

Accounts Receivable Securitization

Alpha and certain of our subsidiaries are parties to the A/R Facility. 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 $275.0 million of those accounts receivable to a financial institution for the issuance of letters of credit or for cash borrowings for our ultimate benefit under the A/R Facility.

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. 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. The A/R Facility was amended in June 2011 to increase the capacity of the A/R Facility from $150.0 million to $190.0 million and the A/R Facility was amended and restated in October 2011 to further increase the capacity of the A/R Facility to $275.0 million.  Unless extended by the parties, the receivables purchase agreement supporting the borrowings under the A/R Facility expires on October 17, 2014, or earlier upon the occurrence of certain events customary for facilities of this type.

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On June 26, 2012, the SPE and Alpha Natural Resources, LLC (“ANR LLC”), each of which are our subsidiaries, entered into an amendment (the “A/R Facility Amendment”) to the Second Amended and Restated Receivables Purchase Agreement, dated as of October 19, 2011, by and among the SPE, ANR LLC, certain financial institutions from time to time parties thereto as conduit purchasers, committed purchasers, purchaser agents and LC Participants (as defined therein) and PNC Bank, National Association, as administrator and LC Bank (as defined therein). The A/R Facility Amendment, among other things, replaces the maximum net leverage ratio termination event with a termination event based on a maximum net secured leverage ratio through the end of 2014 and increases the maximum net leverage ratio termination event for the first and second quarters of 2015.

As of December 31, 2012, letters of credit in the amount of $160.2 million were outstanding under the A/R Facility and no cash borrowing transactions had taken place. As of December 31, 2011, letters of credit in the amount of $160.0 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.

Capital Leases

Alpha entered into capital leases for equipment during 2012. Alpha's liability for capital leases as of December 31, 2012 totaled $67.0 million.

Analysis of Material Debt Covenants

We were in compliance with all covenants under the Credit Agreement and the indentures governing our notes as of December 31, 2012. A breach of the covenants in the Credit Agreement or the indentures governing our notes, including the financial covenants under the Credit Agreement that measure ratios based on Adjusted EBITDA, could result in a default under the Credit Agreement or the indentures governing our notes and the respective lenders and note holders could elect to declare all amounts borrowed due and payable.  Any acceleration under either the Credit Agreement or one of the indentures governing our notes would also result in a default under the other indentures governing our notes. Additionally, under the Credit Agreement and the indentures governing our notes 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 our Credit Agreement are: 

	Actual Covenant Levels; Period Ended December 31, 2012		Required Covenant Levels
Minimum Adjusted EBITDA to cash interest ratio	6.0		2.25x
Maximum total senior secured debt less unrestricted cash to Adjusted EBITDA ratio	0.04		2.5x
Minimum consolidated liquidity (in thousands)	$	2,052,200	$	500,000

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 Credit Agreement. 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 intangibles, net 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

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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 Credit Agreement and therefore, is different from EBITDA presented elsewhere in this Annual Report on Form 10-K.

	Three Months Ended												Twelve Months Ended December 31, 2012
	March 31, 2012 (2)			June 30, 2012			September 30, 2012			December 31, 2012
	(In thousands)
Net loss	$	(28,768	)	$	(2,234,656	)	$	(46,146	)	$	(127,578	)	$	(2,437,148	)
Interest expense	45,434			46,534			47,345			58,834			198,147
Interest income	(1,097		)	(1,324		)	(1,328		)	376			(3,373		)
Income tax benefit (expense)	(43,785		)	(449,798		)	(83,182		)	26,769			(549,996		)
Amortization of acquired intangibles, net	(35,512		)	(17,286		)	(11,682		)	(5,858		)	(70,338		)
Depreciation, depletion and amortization	285,772			272,850			238,894			240,059			1,037,575
EBITDA	222,044			(2,383,680		)	143,901			192,602			(1,825,133		)
Non-cash charges (1) (3)	(4,451		)	1,526,823			56,800			218,557			1,797,729
Other adjustments (1) (4)	10,184			1,042,389			14,206			40,747			1,107,526
Adjusted EBITDA	$	227,777		$	185,532		$	214,907		$	451,906		$	1,080,122

___________________________

⁽¹⁾  Calculated in accordance with the Credit Agreement.

⁽²⁾  Adjusted to reflect immaterial corrections and adjustments to the provisional opening balance sheet of Massey. See Note 3 in the Notes to the Consolidated Financial Statements contained elsewhere in this Annual Report of Form 10-K.

⁽³⁾  Includes $188.2 million for the three months ended December 31, 2012 and $1,525.3 million for the three months ended June 30, 2012 characterized under the Credit Agreement as goodwill impairment, which corresponds to goodwill impairment described elsewhere in this Annual Report of Form 10-K.

⁽⁴⁾  Includes $40.3 million for the three months ended December 31, 2012, $13.7 million for the three months ended September 30, 2012, $1,010.9 million for the three months ended June 30, 2012 and $4.0 million for the three months ended March 31, 2012 characterized under the Credit Agreement as business optimization expenses and other restructuring charges, which corresponds to asset impairment and restructuring charges described elsewhere in this Annual Report of Form 10-K.

Cash interest is calculated in accordance with the Credit Agreement and is equal to interest expense less interest income and non-cash interest expense plus pro forma interest expense. Cash interest for the twelve months ended December 31, 2012 is calculated as follows (in thousands):

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Interest expense	$	198,147
Less interest income	(3,373		)
Less non-cash interest expense	(47,545		)
Other adjustments	34,102
Net cash interest expense (1)	$	181,331

_____________________

⁽¹⁾  Calculated in accordance with the Credit Agreement

Consolidated liquidity is calculated in accordance with our Credit Agreement and is equal to the sum of all unrestricted cash and cash equivalents, marketable securities and unused revolving credit facility commitments available under our Credit Agreement and our A/R Facility. At December 31, 2012, we had available liquidity of $2.1 billion, including cash and cash equivalents of $730.7 million, marketable securities of $298.2 million and $1.0 billion of unused revolving credit facility commitments available under our Credit Agreement and our A/R Facility.

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 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 letters of credit are also used to collateralize a portion of the surety bonds.

We had outstanding surety bonds with a total face amount of $445.3 million as of December 31, 2012 to secure various obligations and commitments. In addition, we had $160.5 million of letters of credit in place, of which $0.3 million was outstanding under the Credit Agreement, and $160.2 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. We meet frequently with our surety providers and have had discussions with certain providers regarding the extent of and the terms of their participation in the program. These discussions may cause us to shift surety bonds between providers or to alter the terms of their participation in our program. In the event that our self-bonding capacity or additional surety bonds become unavailable or our surety bond providers require additional collateral, we would seek to secure our obligations with letters of credit, cash deposits or other suitable forms of collateral, which would likely require greater use of our credit facility and A/R Facility for this purpose. A failure to maintain our self-bonding status, an inability to acquire surety bonds or additional collateral requirements could result from a variety of factors, including a significant decline in our financial position or creditworthiness, and restrictions on the availability of collateral under our credit agreements and indentures.

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 or dispositions of, or combinations with, coal mining companies. When we believe that these opportunities are consistent with our strategic plans and our acquisition or disposition 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 resources 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.

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Contractual Obligations

The following is a summary of our significant contractual obligations as of December 31, 2012 (in thousands):

	2013		2014-2015		2016-2017		After 2017		Total
Long-term debt (1)	$	75,000	$	1,138,662	$	150,000	$	2,000,000	$	3,363,662
Capital lease obligations (2)	14,579		24,276		8,737		19,384		66,976
Other debt (3)	5,436		8,704		5,087		—		19,227
Equipment purchase commitments	7,659		—		—		—		7,659
Operating leases	56,952		44,609		784		—		102,345
Minimum royalties	80,868		144,537		44,938		62,318		332,661
Federal coal lease	42,130		84,260		—		—		126,390
Coal purchase commitments	48,981		30,212		—		—		79,193
Total	$	331,605	$	1,475,260	$	209,546	$	2,081,702	$	4,098,113

 ______________________________

⁽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 9.75% on our loans, would be approximately $178.8 million in 2013, $337.2 million in 2014 to 2015, $283.0 million in 2016 to 2017 and $237.4 million after 2017.

⁽²⁾  Capital lease obligations include principal amounts due in the years shown. Cash interest payable on these obligations with interest rates ranging between 2.13% and 13.86%, would be approximately $4.3 million in 2013, $7.0 million in 2014 to 2015, $5.7 million in 2016 to 2017 and $34.9 million after 2017.

⁽³⁾  Other debt includes principal amounts due in the years shown.  Cash interest payable on these obligation, with interestrates ranging between 4.00% and 6.132%, would be approximately $0.9 million in 2013, $1.6 million in 2014 to 2015 and $0.3 million in 2016 to 2017.

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): 

	2013		2014-2015		2016-2017		After 2017		Total
Asset retirement obligation	$	85,770	$	166,177	$	121,160	$	1,274,257	$	1,647,364
Postretirement benefit obligation	42,250		93,143		104,754		1,936,140		2,176,287
Pension benefit obligation (1)	25,684		57,906		66,072		1,675,366		1,825,028
Black lung benefit obligation	5,640		11,848		12,841		218,947		249,276
Workers’ compensation benefit obligation	15,418		21,690		16,909		108,849		162,866
Total	$	174,762	$	350,764	$	321,736	$	5,213,559	$	6,060,821

⁽¹⁾  We currently expect to make contributions in 2013 of up to $20 million for our defined benefit pension plans. The estimated undiscounted cash flows will be paid from the defined benefit pension plan assets held within the defined benefit pension plan trust. In addition, the estimated undiscounted cash flows disclosed above include cash flows related to our supplemental executive retirement plans, which are paid directly by us, and are $1.2 million in 2013, $2.6 million in 2014 to 2015, $2.7 million in 2016 to 2017 and $37.6 million thereafter.

We expect to spend between $300 million and $350 million on capital expenditures during 2013. This amount includes the remaining portion of the Company’s commitment to invest $80.0 million for mine safety, which is approximately $51.0 million as of December 31, 2012.

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,

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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, 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 options and 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. Options and 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 is required in certain areas such as cash flow hedge accounting and hedge effectiveness testing. We assess each option or 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, sealing portals at deep mines and the treatment of water. 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. We are also faced with increasingly stringent environmental regulation, much of which is beyond our control, which could increase our costs and materially increase our asset retirement obligations. 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 perform 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.

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 and updated plans. At December 31, 2012, we had recorded asset retirement obligation liabilities of $856.7 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2012, we estimate that the aggregate undiscounted cost of final mine closures is approximately $1.6 billion.

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:

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• 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, 2012, we had 4,570.9 million tons of proven and probable coal reserves, of which 2,344.9 million tons were assigned to our active operations and 2,226.0 million tons were unassigned.

Postretirement Medical Benefits. We have long-term liabilities for postretirement medical benefit cost obligations. Detailed information related to these liabilities is included in Note 18 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 a 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 3.74% to 4.41% for the year ended December 31, 2012. At December 31, 2012, we had total postretirement medical benefit obligations of $1,006.2 million, including amounts reported as current.

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	$	7,803	$	(5,933	)
Effect on accumulated postretirement benefit obligation	$	137,535	$	(114,782	)

Discount rate	One-Half Percentage Point Increase			One-Half Percentage Point Decrease
	(In thousands)
Effect on total service and interest cost components	$	18		$	(12	)
Effect on accumulated postretirement benefit obligation	$	(67,096	)	$	71,890

Retirement Plans. We have three non-contributory defined benefit retirement plans (the “Pension Plans”) covering certain of our salaried and non-union hourly employees, all of which are frozen to new participants. We also have two unfunded non-qualified Supplemental Executive Retirement Plans (“SERPs”) 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, and our contributions can be deducted for federal income tax purposes. We contributed $3.7 million to our defined benefit retirement plans for the year ended December 31, 2012. For the year ended December 31, 2012, we recorded a net periodic benefit credit of $3.8 million for our Pension Plans and SERPs and have recorded net obligations of $231.2 million.

The calculation of the net periodic benefit expense and projected benefit obligation associated with our Pension Plans and SERPs 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 45% equity funds and 55% fixed income funds. Investments are rebalanced on a periodic basis

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to stay within these targeted guidelines. The long-term rate of return assumption used to determine net periodic benefit expense was 7.25% for the year ended December 31, 2012. The long-term rate of return assumption to be used in 2013 is expected to be 6.75%. Any difference between the actual experience and the assumed experience is deferred as an unrecognized actuarial 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 rates used to determine pension expense ranged from 3.74% to 4.57% for the year ended December 31, 2012. The differences resulting from actual versus assumed discount rates are amortized into pension expense over the remaining average 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, 2012 by approximately $1.0 million and decrease the projected benefit obligation as of December 31, 2012 by approximately $65.4 million. The corresponding effects of a one half of one percentage-point decrease in the discount rate would decrease the net periodic pension cost for the year ended December 31, 2012 by approximately $1.5 million and increase the projected benefit obligation as of December 31, 2012 by approximately $71.5 million.

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 covered 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, 2012, we had workers’ compensation obligations of $180.0 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 compulsory 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, 2012, we had black lung obligations of $141.8 million, which are net of assets of $3.4 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, unsettled industry circumstances, ability to utilize net operating losses, 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, 2012, 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

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operating losses partially offset the tax effect of the temporary differences. If federal tax attributes related to alternative minimum tax credit carryforwards and federal net operating loss carryforwards increase relative to our deferred tax liabilities, we may be required to establish additional valuation allowances. At December 31, 2012, a valuation allowance of $105.8 million has been provided on certain state net operating losses and gross deferred tax assets not expected to provide future tax benefits.

Asset Impairment. U.S. GAAP requires that a long-lived asset group that is held and used should be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the long-lived asset group might not be recoverable. Testing long-lived assets for impairment after indicators of impairment have been identified is a two-step process. Step one compares the net undiscounted cash flows of an asset group to its carrying value. If the carrying value of an asset group exceeds the net undiscounted cash flows of that asset group, step two is performed whereby the fair value of the asset group is estimated and compared to its carrying amount. The amount of impairment, if any, is equal to the excess of the carrying value of an asset group over its estimated fair value. The amount of impairment, if any, is allocated to the long-lived assets on a pro-rata basis, except that the carrying value of the individual long-lived assets are not reduced below their estimated fair value. Our asset groups generally consist of the assets and applicable liabilities of one or more mines and preparation plants and associated coal reserves for which cash flows are largely independent of cash flows of other mines, preparation plants and associated reserves.

During 2012, as a result of certain announcements regarding production curtailments at certain mining operations, we determined that indicators of impairment were present for certain of our long-lived asset groups. We further determined that undiscounted cash flows were less than the carrying value for five of our asset groups. For these five asset groups, we proceeded to step two and estimated the fair values of the asset groups. The fair values of the asset groups were estimated using an income approach utilizing market-place participant assumptions. The income approach is based on a discounted cash flow methodology in which expected future net cash flows are discounted to present value, using an appropriate after-tax weighted average cost of capital (discount rate). The income approach is dependent upon a number of significant management estimates about future performance including sales volumes and prices, costs to produce, income taxes, capital spending, working capital changes and the after-tax weighted average cost of capital. Changes in any of these assumptions could materially impact the estimated fair value of our asset groups. Our forecasts of coal prices generally reflect a long-term outlook of market prices expected to be be received for our coal. If actual coal prices are less than our expectations, it could have a material impact on the fair value of our asset groups. Our forecasts of costs to produce coal are based on our operating forecasts and an assumed inflation rate for materials and supplies such as steel, diesel fuel and explosives. If actual costs are higher or if inflation increases above our expectations, it could have a material impact on the fair value of our asset groups. We also are faced with increasingly stringent safety standards and governmental regulation, much of which is beyond our control, which could increase our costs and materially decrease the fair value of our asset groups.

The carrying values of the five asset groups that proceeded to step two exceeded their estimated fair values and accordingly, we recorded asset impairment charges for the year ending December 31, 2012 of $1,000.5 million. The asset impairment charges reduced the carrying values of mineral reserves by $714.6 million, property, plant and equipment, by $281.4 million, and other acquired intangibles by $4.5 million. The asset impairments established a new cost basis on which future depreciation, depletion and amortization will be based.

Goodwill. Goodwill represents the excess of purchase price over the fair value of the identifiable net assets of acquired companies. Goodwill is not amortized; instead, it is tested for impairment annually as of October 31 of each year, or more frequently if indicators of impairment exist.

We test goodwill for impairment using a fair value approach at the reporting unit level. For certain of our reporting units, we apply a qualitative assessment. For the remaining reporting units, we perform our goodwill impairment test in two steps. Step one compares the fair value of each reporting unit to its carrying value, including goodwill. If the fair value of a reporting unit determined in step one is lower than its carrying value, we proceed to step two, which compares the carrying value of goodwill to its implied fair value. In estimating the implied fair value of goodwill at a reporting unit, we assigned the fair value of the reporting unit to all of the assets and liabilities associated with the reporting unit as if the reporting unit had been acquired in a business combination. Any excess of carrying value of goodwill over its implied fair value at a reporting unit is recorded as impairment.

The valuation methodology utilized in step one to estimate the fair value of the reporting units is based on both a market and income approach and is within the range of fair values yielded under each approach. The income approach is based on a discounted cash flow methodology in which expected future net cash flows are discounted to present value, using an appropriate after-tax weighted average cost of capital (discount rate). The market approach is based on a guideline company and similar transaction methodology. Under the guideline company approach, certain operating metrics from a selected group

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of publicly traded guideline companies that have similar operations to the Company's reporting units are used to estimate the fair value of the reporting units. Under the similar transaction approach, recent merger and acquisition transactions for companies that have similar operations to the Company's reporting units are used to estimate the fair value of the Company's reporting units.

The income approach is dependent upon a number of significant management estimates about future performance including sales volumes and prices, costs to produce, income taxes, capital spending, working capital changes and the after-tax weighted average cost of capital. Changes in any of these assumptions could materially impact the estimated fair value of our reporting units. Our forecasts of coal prices generally reflect a long-term outlook of market prices expected to be be received for our coal. If actual coal prices are less than our expectations, it could have a material impact on the fair value of our reporting units. Our forecasts of costs to produce coal are based on our operating forecasts and an assumed inflation rate for materials and supplies such as steel, diesel fuel and explosives. If actual costs are higher or if inflation increases above our expectations, it could have a material impact on the fair value of our reporting units. We also are faced with increasingly stringent safety standards and governmental regulation, much of which is beyond our control, which could increase our costs and materially decrease the fair value of our reporting units.

In connection with the testing of certain of our long-lived assets for impairment, we performed a goodwill impairment test as of June 1, 2012 and recorded goodwill impairment of $1,525.3 million to reduce the carrying value of goodwill to its implied fair value for nine reporting units in our Eastern Coal Operations segment and one reporting unit in our Western Coal Operations segment.

During the fourth quarter of 2012, we announced the completion of a reorganization effort aimed at enhancing operational effectiveness by aligning our structure to a smaller production footprint following announced production curtailments. The reorganization included personnel and structural changes and other consolidation efforts. As a result, our internal management reporting structure was also changed. As a result, prior to our annual goodwill impairment testing, we reassessed our reporting units based on our new management reporting structure. We allocated the existing goodwill to our new reporting units based on a relative fair value approach as required under U.S. GAAP. In connection with our annual goodwill impairment test performed as of October 31, 2012, we recorded goodwill impairment of $188.2 million to reduce the carrying value of goodwill to its implied fair value for one of our reporting units in our Eastern Coal Operations segment. The fair value of our other reporting unit in our Eastern Coal Operations segment exceeded its carrying value by a total of approximately $400 million, or 9%.

Contingencies. We are parties to a number of legal proceedings. These matters include personal injury claims, environmental issues and other matters more fully described in Note 21 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K. We record accruals based on an estimate of the ultimate outcome of these matters, however these matters are difficult to predict and involve significant judgment by management.

New accounting pronouncements. See Note 2 in the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K for disclosures related to new accounting policies adopted.

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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 25, 2013, we had sales commitments for approximately 92% of planned shipments for 2013, 8% of which is unpriced. Uncommitted and unpriced tonnage was 8% for 2013. 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 61.4 million gallons of diesel fuel in 2013 and 2014. Through our derivative swap contracts, we have fixed prices for approximately 53% and 39% of our expected diesel fuel needs for 2013 and 2014, respectively. If the price of diesel fuel were to decrease in 2013, 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.

We also sell coalbed methane through our Coal Gas Recovery business. 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, we enter into “pay variable, receive fixed” natural gas swaps for a portion of our anticipated gas production in order to fix the selling price for a portion of our production.  The natural gas swaps have been designated as qualifying cash flow hedges. As of December 31, 2012, we had swap agreements outstanding to hedge the variable cash flows related to approximately 76% of anticipated natural gas production in 2013.

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 Credit Agreement, which has a variable interest rate of 2.5 percentage points over the LIBO rate, subject, in the case of the revolving credit line, to adjustment based on leverage ratios. As of December 31, 2012, our term loan due 2016 under the Credit Agreement had an outstanding balance of $539.5 million, net of debt discount of $0.5 million. The current portion of the term loan due in the next twelve months was $75.0 million. A 50 basis point increase or decrease in interest rates would increase or decrease our interest expense by $2.9 million.

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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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2012. 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, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, 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, 2012, 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 March 1, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. 

/s/ KPMG LLP

Roanoke, Virginia

March 1, 2013

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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,
	2012			2011			2010
Revenues:
Coal revenues	$	6,015,696		$	6,189,434		$	3,497,847
Freight and handling revenues	761,928			662,238			332,559
Other revenues	197,260			256,009			86,750
Total revenues	6,974,884			7,107,681			3,917,156
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)	5,004,516			5,080,921			2,566,825
Freight and handling costs	761,928			662,238			332,559
Other expenses	45,432			142,709			65,498
Depreciation, depletion and amortization	1,037,575			770,769			370,895
Amortization of acquired intangibles, net	(70,338		)	(114,422		)	226,793
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization shown separately above)	209,788			382,250			180,975
Asset impairment and restructuring	1,068,906			—			—
Goodwill impairment	1,713,526			802,337			—
Total costs and expenses	9,771,333			7,726,802			3,743,545
Income (loss) from operations	(2,796,449		)	(619,121		)	173,611
Other income (expense):
Interest expense	(198,147		)	(141,914		)	(73,463		)
Interest income	3,373			3,978			3,458
Gain (loss) on early extinguishment of debt	773			(10,026		)	(1,349		)
Miscellaneous income (expense), net	3,306			635			(821		)
Total other expense, net	(190,695		)	(147,327		)	(72,175		)
Income (loss) from continuing operations before income taxes	(2,987,144		)	(766,448		)	101,436
Income tax (expense) benefit	549,996			35,906			(4,218		)
Income (loss) from continuing operations	(2,437,148		)	(730,542		)	97,218
Discontinued operations:
Loss from discontinued operations before income taxes	—			—			(2,719		)
Income tax benefit	—			—			1,052
Loss from discontinued operations	—			—			(1,667		)
Net income (loss)	$	(2,437,148	)	$	(730,542	)	$	95,551
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	(11.06	)	$	(4.06	)	$	0.81
Loss from discontinued operations	—			—			(0.01		)
Net income (loss)	$	(11.06	)	$	(4.06	)	$	0.80
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	(11.06	)	$	(4.06	)	$	0.80
Loss from discontinued operations	—			—			(0.01		)
Net income (loss)	$	(11.06	)	$	(4.06	)	$	0.79
Weighted average shares - basic	220,261,555			180,126,226			119,808,514
Weighted average shares - diluted	220,261,555			180,126,226			121,757,949

See accompanying Notes to Consolidated Financial Statements.

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ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Amounts in thousands)

	Years ended December 31,
	2012			2011			2010
Net income (loss)	$	(2,437,148	)	$	(730,542	)	$	95,551
Other comprehensive income (loss), net of tax:
Employee benefit plans:
Current year actuarial gain (loss), net of income tax of ($516), $94,516 and $29,154, for the years ended December 31, 2012, 2011 and 2010, respectively	(651		)	(156,990		)	(46,451		)
Prior service (cost) credit for period, net of income tax benefit of ($16,776), $6,177 and ($4,203), for the years ended December 31, 2012, 2011 and 2010, respectively	28,084			(10,260		)	6,696
Less: reclassification adjustment for amounts reclassified to earnings due to amortization of actuarial net (gain) loss, net of income tax of ($2,898), ($260) and $1,313, for the years ended December 31, 2012, 2011 and 2010, respectively	4,802			432			(2,091		)
Less: reclassification adjustment for amounts reclassified to earnings due to amortization of prior service cost (credit), net of income tax of $241, $229 and ($430), for the years ended December 31, 2012, 2011 and 2010, respectively	(400		)	(380		)	684
Cash flow hedges:
Unrealized gains related to cash flow hedges, net of income tax of ($8,272), ($5,291) and ($4,664), for the years ended December 31, 2012, 2011 and 2010, respectively	13,812			8,297			7,821
Less: reclassification adjustment for amounts reclassified to earnings related to settlement of cash flow hedges, net of income tax of $6,215, $9,571 and $181, for the years ended December 31, 2012, 2011 and 2010, respectively	(10,390		)	(15,407		)	(277		)
Available-for-sale marketable securities:
Unrealized holding gains arising during the period, net of income tax of ($185), ($34), and ($142) for the years ended December 31, 2012, 2011 and 2010, respectively	309			56			223
Less: reclassification adjustment for (gains) losses reclassified to earnings, net of tax of $200 and ($3) for the years ended December 31, 2012 and 2011, respectively	(334		)	5			—
Total other comprehensive income (loss), net of tax	35,232			(174,247		)	(33,395		)
Total comprehensive income (loss)	$	(2,401,916	)	$	(904,789	)	$	62,156

See accompanying Notes to Consolidated Financial Statements.

95

ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

	December 31, 2012			December 31, 2011
Assets
Current assets:
Cash and cash equivalents	$	730,723		$	585,882
Trade accounts receivable, net	418,166			641,975
Inventories, net	398,060			492,022
Prepaid expenses and other current assets	786,273			828,196
Total current assets	2,333,222			2,548,075
Property, equipment and mine development costs (net of accumulated depreciation and amortization of $1,910,058 and $1,355,937, respectively)	2,219,016			2,812,069
Owned and leased mineral rights and land (net of accumulated depletion of $908,416 and $633,207, respectively)	7,428,192			8,284,328
Goodwill, net	567,665			2,281,191
Other acquired intangibles (net of accumulated amortization of $655,047 and $551,584, respectively)	228,552			347,889
Other non-current assets	313,159			320,493
Total assets	$	13,089,806		$	16,594,045
Liabilities and Stockholders’ Equity
Current liabilities:
Current portion of long-term debt	$	95,015		$	46,029
Trade accounts payable	255,191			504,059
Accrued expenses and other current liabilities	872,402			1,359,160
Total current liabilities	1,222,608			1,909,248
Long-term debt	3,291,037			2,922,052
Pension and postretirement medical benefit obligations	1,195,187			1,214,724
Asset retirement obligations	763,482			743,613
Deferred income taxes	971,001			1,507,923
Other non-current liabilities	678,676			921,441
Total liabilities	8,121,991			9,219,001
Commitments and Contingencies (Note 21)
Stockholders’ Equity
Preferred stock - par value $0.01, 10.0 million shares authorized, none issued	—			—
Common stock - par value $0.01, 400.0 million shares authorized, 232.2 million issued and 220.6 million outstanding at December 31, 2012 and 231.0 million issued and 219.8 million outstanding at December 31, 2011	2,322			2,310
Additional paid-in capital	8,075,694			8,073,512
Accumulated other comprehensive income (loss)	(166,598		)	(201,830		)
Treasury stock, at cost: 11.6 million and 11.2 million shares at December 31, 2012 and December 31, 2011, respectively	(270,302		)	(262,795		)
Accumulated deficit	(2,673,301		)	(236,153		)
Total stockholders’ equity	4,967,815			7,375,044
Total liabilities and stockholders’ equity	$	13,089,806		$	16,594,045

See accompanying Notes to Consolidated Financial Statements.

96

ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)

	Years Ended
	December 31,
	2012			2011			2010
Operating activities:
Net income (loss)	$	(2,437,148	)	$	(730,542	)	$	95,551
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	1,037,575			770,769			371,103
Amortization of acquired intangibles, net	(70,338		)	(114,422		)	226,793
Amortization of debt issuance costs and accretion of debt discount	43,745			30,263			18,552
Mark-to-market adjustments for derivatives	(2,795		)	(125,391		)	11,316
Accretion of asset retirement obligations	65,548			43,062			17,621
Stock-based compensation	9,881			53,685			33,255
Employee benefit plans, net	72,465			68,157			55,771
(Gain) loss on early extinguishment of debt	(773		)	10,026			1,349
Change in future costs of asset retirement obligations	(154,377		)	37,137			6,688
Deferred income taxes	(554,575		)	(17,084		)	(70,579		)
Asset impairment and restructuring	1,068,906			—			—
Goodwill impairment	1,713,526			802,337			—
Other, net	(39,984		)	(22,698		)	(11,464		)
Changes in operating assets and liabilities:
Trade accounts receivable, net	229,882			(178,704		)	(48,507		)
Inventories, net	93,962			120,460			(21,886		)
Prepaid expenses and other current assets	230,259			28,199			59,075
Other non-current assets	(7,549		)	(30,191		)	(7,468		)
Trade accounts payable	(246,228		)	84,784			(21,755		)
Accrued expenses and other current liabilities	(407,128		)	(41,763		)	42,730
Pension and postretirement medical benefit obligations	(53,008		)	(105,584		)	(70,770		)
Asset retirement obligations	(50,313		)	(22,833		)	(5,593		)
Other non-current liabilities	(23,114		)	26,970			11,819
Net cash provided by operating activities	518,419			686,637			693,601
Investing activities:
Cash paid for acquisition, net of cash acquired	—			(711,387		)	—
Capital expenditures	(402,377		)	(528,586		)	(308,864		)
Acquisition of mineral rights under federal lease	(95,765		)	(64,900		)	(36,108		)
Purchases of marketable securities	(555,096		)	(374,048		)	(372,790		)
Sales of marketable securities	352,112			547,249			214,240
Purchase of equity-method investment	(10,100		)	(14,800		)	(5,000		)
Proceeds from disposition of property and equipment	38,250			8,470			4,025
Other, net	—			(9,005		)	(4,000		)
Net cash used in investing activities	(672,976		)	(1,147,007		)	(508,497		)
Financing activities:
Proceeds from borrowings on long-term debt	494,795			2,100,000			—
Principal repayments on long-term debt	(160,157		)	(1,315,357		)	(56,854		)
Principal repayments of capital lease obligations and other debt	(10,548		)	—			—
Debt issuance costs	(16,361		)	(85,226		)	(8,594		)
Excess tax benefit from stock-based awards	—			—			5,505
Common stock repurchases	(7,507		)	(212,257		)	(41,664		)
Proceeds from exercise of stock options	176			4,320			5,521
Other, net	(1,000		)	—			(115		)
Net cash provided by (used in) financing activities	299,398			491,480			(96,201		)
Net increase in cash and cash equivalents	144,841			31,110			88,903
Cash and cash equivalents at beginning of period	585,882			554,772			465,869
Cash and cash equivalents at end of period	$	730,723		$	585,882		$	554,772
Supplemental cash flow information:
Cash paid for interest	$	144,958		$	92,137		$	61,056
Cash paid for income taxes	$	5,038		$	17,829		$	42,289
Cash received for income tax refunds	$	38,934		$	—		$	—
Supplemental disclosure of non-cash investing and financing activities:
Issuance of equity in connection with mergers and acquisitions	$	—		$	5,673,092		$	—
Capital equipment leases	$	53,192		$	—		$	—

See accompanying Notes to Consolidated Financial Statements.

97

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Amounts in thousands, except per share data)

	Common Stock			Additional Paid-in		Treasury			Accumulated Other Comprehensive			Retained Earnings (Accumulated			Total Stockholders’
	Shares	Amount		Capital		Stock at Cost			Income (Loss)			Deficit)			Equity
Balances, December 31, 2009	123,217	$	1,232	$	2,194,281	$	(8,874	)	$	5,812		$	398,838		$	2,591,289
Net income	—	—		—		—			—			95,551			95,551
Other comprehensive income (loss), net	—	—		—		—			(33,395		)	—			(33,395		)
Exercise of stock options	452	4		5,517		—			—			—			5,521
Stock-based compensation and net issuance of common stock for share vesting	623	6		38,728		(16,665		)	—			—			22,069
Stock repurchase program	—	—		—		(24,999		)	—			—			(24,999		)
Balances, December 31, 2010	124,292	$	1,242	$	2,238,526	$	(50,538	)	$	(27,583	)	$	494,389		$	2,656,036
Net loss	—	—		—		—			—			(730,542		)	(730,542		)
Other comprehensive income (loss), net	—	—		—		—			(174,247		)	—			(174,247		)
Equity component of convertible debt assumed in Massey Acquisition	—	—		110,375		—			—			—			110,375
Equity consideration for the Massey Acquisition	105,985	1,060		5,672,032		—			—			—			5,673,092
Exercise of stock options	346	4		4,316		—			—			—			4,320
Stock-based compensation and net issuance of common stock for share vesting	400	4		48,263		(12,257		)	—			—			36,010
Stock repurchase program	—	—		—		(200,000		)	—			—			(200,000		)
Balances, December 31, 2011	231,023	$	2,310	$	8,073,512	$	(262,795	)	$	(201,830	)	$	(236,153	)	$	7,375,044
Net loss	—	—		—		—			—			(2,437,148		)	(2,437,148		)
Other comprehensive income (loss), net	—	—		—		—			35,232			—			35,232
Exercise of stock options	16	—		176		—			—			—			176
Stock-based compensation and net issuance of common stock for share vesting	1,195	12		2,006		(7,507		)	—			—			(5,489		)
Balances, December 31, 2012	232,234	$	2,322	$	8,075,694	$	(270,302	)	$	(166,598	)	$	(2,673,301	)	$	4,967,815

See accompanying Notes to Consolidated Financial Statements. 

98

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

(1) Business and Basis of Presentation

Business

Alpha Natural Resources, Inc. and its consolidated subsidiaries (the “Company” or “Alpha”) 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 June 1, 2011, pursuant to the terms of the previously announced Agreement and Plan of Merger dated as of January 28, 2011 (the “Merger Agreement”), the Company completed its acquisition (the “Massey Acquisition”) of Massey Energy Company, a Delaware corporation (“Massey”). Massey, together with its affiliates, was a major U.S. coal producer operating mines and associated processing and loading facilities in Central Appalachia. For the year ended December 31, 2011, Massey’s financial results are included for the seven month period June 1, 2011 through December 31, 2011. See Note 3 for further disclosures related to the Massey Acquisition.

At December 31, 2012, the Company’s coal operations consisted of 74 deep and 33 surface mines located in Virginia, West Virginia, Pennsylvania, Kentucky and Wyoming. At December 31, 2012, the Company had approximately 12,400 employees, of which 11% 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.

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.

Reclassifications

Certain amounts in the 2011 Consolidated Balance Sheet, Consolidated Statement of Cash Flows and Consolidated Statement of Stockholders' Equity have been reclassified to conform to the current year presentation. Also, see Note 3 for further details regarding final acquisition accounting adjustments and certain immaterial corrections.

(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 (“GAAP”). 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; reclamation obligations; acquisition accounting; pensions, postemployment, postretirement medical and other employee benefit obligations; useful lives for depreciation, depletion, and amortization; reserves for workers’ compensation and black lung claims; current and deferred income taxes; reserves for contingencies and litigation; 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, 2012.

99

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Marketable Securities

The Company classifies its marketable securities as trading or 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 fair value adjustments to available-for-sale securities are classified as a separate component of stockholders’ equity. Unrealized gains and losses resulting from fair value adjustments to trading securities are recorded in current period earnings or loss. 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 6 and 10 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. The allowance for doubtful accounts was $7,845 and $4,663 at December 31, 2012 and 2011, respectively.

Account balances are written off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. 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 related 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.

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 6 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. Advance royalty balances are generally charged off against the allowance when the lease rights are either terminated or expire.

100

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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

Balance at December 31, 2009	$	17,852
Provision for non-recoupable advance mining royalties	916
Write-offs of advance mining royalties(1)	(5,298		)
Balance at December 31, 2010	13,470
Acquisition of Massey Energy Company(2)	12,348
Provision for non-recoupable advance mining royalties	2,249
Write-offs of advance mining royalties	(7,694		)
Balance at December 31, 2011	20,373
Provision for non-recoupable advance mining royalties	8,913
Write-offs of advance mining royalties	(1,484		)
Balance at December 31, 2012	$	27,802

⁽¹⁾  Includes $4,100 reported in discontinued operations.

⁽²⁾  See Note 3 for discussion surrounding the Massey Acquisition.

Property, Equipment and Mine Development Costs

Costs for 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 less any incidental revenue generated 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 one 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 lives or improve productivity are capitalized and depreciated over the period benefited. 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.

Owned and Leased Mineral Rights and Land

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 $325,999, $253,622, and $111,846 for the years ended December 31, 2012, 2011, and 2010, respectively.

Acquired Intangibles

Application of acquisition accounting resulted in the recognition of an asset for above market-priced coal supply and transportation agreements and a liability for below market-priced coal supply agreements on the date of the acquisitions. The coal supply and transportation agreements were valued based on the present value of the difference between the expected net contractual cash flows based on the stated contract terms, and the estimated net contractual cash flows derived from applying forward market prices at the acquisition dates for new contracts of similar terms and conditions. The coal supply and transportation agreement assets and liabilities are being amortized over the actual amount of tons shipped under each contract. The coal supply and transportation agreement asset is reported in other acquired intangibles and the coal supply agreement liability is reported in other non-current liabilities in the Consolidated Balance Sheets.

101

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

In addition, the application of acquisition accounting also resulted in the Company recording intangible assets related to mining permits and covenants not-to-compete, which are reported in other acquired intangibles in the Consolidated Balance Sheets. Amortization of other acquired intangible assets was $113,750, $179,761, and $234,094 of expense and amortization of coal supply agreement liabilities was a credit to expense of ($184,088), ($294,183), and ($7,301), equating to a net (credit) expense of ($70,338), ($114,422) and $226,793 for the years ended December 31, 2012, 2011 and 2010, respectively, which is included in amortization of acquired intangibles, net in the Consolidated Statements of Operations. Future net amortization expense related to acquired intangibles is expected to be as follows:

2013	$	2,021
2014	42,868
2015	30,895
2016	21,824
2017	4,668
Thereafter	5,797
Total net future amortization expense	$	108,073

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 or asset groups may not be recoverable. Recoverability of assets or asset groups to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset or asset groups. If the carrying amount of an asset or asset groups 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 or asset groups. 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. See Note 8 for further disclosures related to asset impairments.

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 routinely performs its goodwill impairment testing as of October 31 of each year. During 2012, the Company performed goodwill impairment tests as of June 1, 2012 and October 31, 2012.

The Company first assesses goodwill on a qualitative basis. If the qualitative assessment indicates that an impairment potentially exists, then the Company tests its 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 implied fair value of goodwill is less than its carrying value. See Note 9 for further disclosures related to goodwill.

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, estimated costs to reclaim support acreage, treat mine water discharge 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 at operations that are not currently being reclaimed, the offset is capitalized by increasing the carrying amount of the related long-lived asset. When the liability is initially recorded at operations that are currently being reclaimed, the offset is recorded to cost of coal sales. Over time, the liability is accreted and any capitalized cost is depreciated over the useful life of

102

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 13 for further disclosures related to 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 basis 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 record a change to the valuation allowance in the period the determination is made. See Note 17 for further disclosures related to 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, road construction and intercontinental commodity transportation services. With the exception of road construction and intercontinental commodity transportation services 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. Revenue from intercontinental commodity transportation services is recognized on a ratable basis over the period of time in which transportation services are provided.

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.

Workers’ Compensation and Pneumoconiosis (Black Lung) Benefits

Workers’ Compensation

The Company is self-insured for workers’ compensation claims at certain of its operations and is covered by a third-party insurance provider at other locations. 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. See Note 18 for further disclosures related to workers' compensation liabilities.

103

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 cost. See Note 18 for further disclosures related to other postretirement benefits.

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 18 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 Consolidated Balance Sheets the amount of the Company’s unfunded Accumulated Postretirement Benefit Obligation (“APBO”) 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 cost. See Note 18 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 4 for further disclosures related to earnings per share.

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 19 for further disclosures related to 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

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 16 for further disclosures related to 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.

New Accounting Pronouncements Adopted

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which amended accounting guidance related to fair value measurements and disclosures with the purpose of converging the fair value measurement and disclosure guidance issued by the FASB and the International Accounting Standards Board (“IASB”). The guidance is effective for reporting periods beginning after December 15, 2011. The guidance includes amendments that clarify the intent of the application of existing fair value measurement requirements along with amendments that change a particular principle or requirement for fair value measurements and disclosures. The Company adopted the new guidance on January 1, 2012. The adoption did not have a material impact on its Consolidated Financial Statements or related disclosures.

In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”), which amended accounting guidance related to presentation of comprehensive income. The standards update is intended to help financial statement users better understand the causes of an entity’s change in financial position and results of operation. The amendment eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendment requires that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance also requires that reclassification adjustments for items that are reclassified from other comprehensive income to net income be presented on the face of the financial statement where the components of net income and other comprehensive income are presented. In December 2011, the FASB issued ASU 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”), which defers only those changes in ASU 2011-05 that relate to the presentation of reclassification adjustments out of accumulated other comprehensive income. ASU 2011-05 and ASU 2011-12 are effective for reporting periods beginning after December 15, 2011. The Company adopted the new guidance on January 1, 2012.

In September 2011, the FASB issued ASU 2011-08, Testing Goodwill for Impairment (“ASU 2011-08”). ASU 2011-08 is intended to simplify how entities test for goodwill impairment by adding a qualitative review step to assess whether the required quantitative impairment analysis is necessary. ASU 2011-08 permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If it is concluded that this is not the case, it is not necessary to perform the two-step impairment test as described in Accounting Standards Codification (“ASC”) Topic 350, Intangibles-Goodwill and Other. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. See Note 9.

In February 2013, the FASB issued ASU 2013-02, Reportingof Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). The standard requires that companies present either in a single note or

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source (e.g., the release due to cash flow hedges from interest rate contracts) and the income statement line items affected by the reclassification (e.g., interest income or interest expense). If a component is not required to be reclassified to net income in its entirety (e.g., the net periodic pension cost), companies would instead cross reference to the related footnote for additional information (e.g., the pension footnote). ASU 2013-02 is effective for interim and annual reporting periods beginning after December 15, 2012. The Company will adopt the provisions of the new guidance during the first quarter of 2013.

(3) Mergers and Acquisitions

On June 1, 2011, the Company completed its acquisition of 100% of the outstanding common stock of Massey, a coal producer with operations located primarily in Virginia, West Virginia, and Kentucky. The Company issued 1.025 shares of Alpha common stock and $10.00 in cash for each share of Massey common stock. Upon closing of the Massey Acquisition, Alpha shareholders owned 54% of the combined company and Massey shareholders owned 46% of the combined company.

The Consolidated Statements of Operations include acquisition related expenses (on a pre-tax basis) of $34,736 and $193,453 in cost of coal sales, $11,418 and $163,959 in selling, general and administrative, and ($32,418) and $44,687 of net other expenses for the years ending December 31, 2012 and 2011, respectively. Included in cost of coal sales is $3,968 and $152,733 related to the impact of acquisition accounting and related fair value adjustments to coal inventory, $1,468 and $35,521 of expenses for benefit integration activities and employee severance, $0 and $5,199 of stock compensation expense and $29,300 and $0 of expenses for contractual settlement-related matters for the years ending December 31, 2012 and 2011, respectively. Selling, general and administrative includes $10,209 and $117,546 for professional fees related to legal, financing and integration services, $1,209 and $30,396 in expenses for benefits alignment and employee severance, and $0 and $16,017 in stock compensation expense for the years ending December 31, 2012 and 2011, respectively. The net other expenses of ($32,418) and $44,687 for the years ending December 31, 2012 and 2011, respectively, were recorded for contract-related matters related to coal contracts assumed in the Massey Acquisition.

Total revenues reported in the Consolidated Statements of Operations for the year ending December 31, 2011 included revenues of $1,878,612 from operations acquired from Massey. The amount of earnings from continuing operations from the operations acquired from Massey included in the consolidated results of operations for the year ending December 31, 2011 is not readily determinable due to various intercompany transactions and allocations that have occurred in connection with the operations of the combined company.

The fair value of the total consideration transferred was approximately $6,714,057. The acquisition date fair value of each class of consideration transferred was as follows:

Common shares	$	5,649,592
Other equity awards	23,500
Cash	1,040,965
Total purchase price	$	6,714,057

The Company issued 105,984,847 shares of common stock in the transaction. Fair value of common stock issued was determined by the closing price of Alpha’s common stock on the day of the Massey Acquisition. The fair value of other equity awards was determined in accordance with the provisions of ASC 805. The total purchase price has been allocated to the net tangible and intangible assets of Massey as follows:

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Provisional as of December 31, 2011		Adjustments			Final
Inventories	$	414,310	$	—		$	414,310
Other current assets	998,034		61,949			1,059,983
Property, equipment and mine development costs	1,705,531		(8,885		)	1,696,646
Owned and leased mineral rights and land	6,445,688		399			6,446,087
Goodwill	2,613,442		87,646			2,701,088
Other intangible assets	365,379		(5,889		)	359,490
Other non-current assets	90,788		2			90,790
Total assets	12,633,172		135,222			12,768,394
Total current liabilities	1,128,922		145,412			1,274,334
Long-term debt, including current portion	1,397,405		—			1,397,405
Pension and post-retirement medical benefits, including current portion	294,657		—			294,657
Asset retirement obligation, including current portion	610,506		18,330			628,836
Deferred income taxes, including current portion	1,303,415		(23,145		)	1,280,270
Below-market contract obligations	707,969		(5,375		)	702,594
Other liabilities, including current portion of black lung and workers' compensation	365,866		—			365,866
Total liabilities	5,808,740		135,222			5,943,962
Equity component of convertible notes	110,375		—			110,375
Net tangible and intangible assets acquired	$	6,714,057	$	—		$	6,714,057

The Company finalized the purchase price allocation as of May 31, 2012.

Intangible assets and liabilities related to coal supply agreements and transportation agreements are being amortized over the actual amount of tons shipped under each contract. Mine permits are being amortized over a weighted average useful life of approximately 7.5 years and had a weighted average term of approximately 2.3 years before the next renewal or extension at the time of the merger.

Goodwill has been allocated to Eastern Coal Operations. The goodwill recognized is generally attributable to intangible assets that do not qualify for separate recognition such as the Massey workforce, synergies expected to be realized through administrative, sales and operating cost savings and capital expenditure efficiencies and annual revenue synergies expected to be achieved from the integration of the Massey assets into the Company's existing operations.

Prior to the finalization of the purchase price allocation, the Company recorded adjustments to the provisional opening balance sheet and certain immaterial corrections as shown in the above table. Adjustments were made primarily to reflect corrections to asset retirement obligations, updated estimates of certain tax liabilities, updated estimates of certain property values, updated estimates of below market contract liabilities, updated estimates for litigation related matters and related insurance recoveries, other miscellaneous adjustments and the deferred tax impact of all adjustments made.

As a result of the adjustments, the Company adjusted depreciation, depletion and amortization, amortization of acquired intangibles, net, cost of coal sales, other expenses, other revenues and goodwill impairment and restated its consolidated balance sheet as of December 31, 2011 and its consolidated results of operations for the three months ended June 30, 2011, September 30, 2011, December 31, 2011, and March 31, 2012 for the changes to the provisional opening balance sheet of Massey and for certain other immaterial corrections and reclassifying adjustments. As a result, the Company recorded additional goodwill impairment of $57,012, increased its net loss before income taxes by $50,131, and increased its net loss by $53,152 for the year ended December 31, 2011 and decreased its net loss by $351 for the three months ended March 31, 2012.

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The following unaudited pro forma information has been prepared for illustrative purposes only and assumes the Massey Acquisition occurred on January 1, 2010. 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 Massey Acquisition occurred on January 1, 2010, or of future results of operations.

	Year Ended  December 31, 2011			Year Ended  December 31, 2010
Total revenues
As reported	$	7,107,681		$	3,917,156
Pro forma	$	8,642,096		$	6,965,995
Income (loss) from continuing operations
As reported	$	(730,542	)	$	97,218
Pro forma	$	(834,645	)	$	(35,952	)
Earnings (loss) per share from continuing operations-basic
As reported	$	(4.06	)	$	0.81
Pro forma	$	(3.73	)	$	(0.16	)
Earnings (loss) per share from continuing operations-diluted
As reported	$	(4.06	)	$	0.80
Pro forma	$	(3.73	)	$	(0.16	)

(4) 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 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, the Company’s outstanding 2.375% convertible senior notes due 2015 (the “2.375% Convertible Notes”), and for periods subsequent to the Massey Acquisition, the outstanding 3.25% convertible senior notes due 2015 issued by Massey (the “3.25% Convertible Notes”). The 2.375% Convertible Notes and 3.25% Convertible Notes become dilutive for earnings per common share calculations in certain circumstances.  The shares that would be issued to settle the conversion spread are included in the diluted earnings per common share calculation when the conversion option is in the money.  For the years ended December 31, 2012, 2011 and 2010, the conversion options for the 2.375% Convertible Notes and the 3.25% Convertible Notes were not in the money, and therefore there was no dilutive earnings per share impact.

For the years ended December 31, 2012 and December 31, 2011, there was no dilutive impact on earnings per share as the Company incurred a net loss for 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:

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Years Ended December 31,
	2012	2011	2010
Weighted average shares - basic	220,261,555	180,126,226	119,808,514
Dilutive effect of stock equivalents	—	—	1,949,435
Weighted average shares- diluted	220,261,555	180,126,226	121,757,949

(5) Inventories, net

Inventories, net consisted of the following:

	December 31,
	2012		2011
Raw coal	$	58,382	$	52,215
Saleable coal	233,550		340,672
Materials and supplies and other, net	106,128		99,135
Total inventories, net	$	398,060	$	492,022

(6) Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consisted of the following:

	December 31,
	2012		2011
Marketable securities - short term (2)	$	297,452	$	80,342
Prepaid insurance	21,292		52,594
Insurance and indemnification receivables (1)	196,074		289,019
Notes and other receivables	37,201		42,423
Deferred income taxes - current	117,692		129,885
Deferred long wall move expenses	11,159		16,781
Refundable income taxes	11,369		51,711
Derivative financial instruments	21,981		35,327
Prepaid freight	36,174		71,348
Deposits	15,923		33,636
Other prepaid expenses	19,956		25,130
Total prepaid expenses and other current assets	$	786,273	$	828,196

⁽¹⁾  See Note 11.

⁽²⁾  Short-term marketable securities consisted of the following:

	December 31, 2012
			Unrealized
	Cost		Gain		Loss			Fair value
Short-term marketable securities:
U.S. treasury and agency securities (a)	$	85,537	$	32	$	(1	)	$	85,568
Corporate debt securities (a)	211,852		75		(43		)	211,884
Total short-term marketable securities	$	297,389	$	107	$	(44	)	$	297,452

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	December 31, 2011
			Unrealized
	Cost		Gain		Loss			Fair value
Short-term marketable securities:
U.S. treasury and agency securities (a)	$	18,415	$	61	$	—		$	18,476
Corporate debt securities (a)	61,861		7		(2		)	61,866
Total short-term marketable securities	$	80,276	$	68	$	(2	)	$	80,342

^(a)  Unrealized gains and losses are recorded as component of stockholders’ equity.

(7) Property, Equipment and Mine Development Costs

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

	December 31,
	2012		2011
Plant and mining equipment	$	3,688,516	$	3,641,521
Mine development	304,765		272,629
Coalbed methane equipment	16,753		15,210
Office equipment and software	66,152		56,547
Other	6,605		6,605
Construction in progress	46,283		175,494
	4,129,074		4,168,006
Less accumulated depreciation and amortization	1,910,058		1,355,937
Total property, equipment and mine development costs, net	$	2,219,016	$	2,812,069

Included in plant and mining equipment are assets under capital leases totaling $84,044 with accumulated depreciation of $8,174 as of December 31, 2012. Included in plant and mining equipment are assets under capital lease totaling $30,190 with accumulated depreciation of $197 as of December 31, 2011.

Depreciation and amortization expense associated with property, equipment and mine development costs was $711,577, $517,222 and $257,649 for the years ended December 31, 2012, 2011 and 2010, respectively.

Interest costs applicable to major asset additions are capitalized during the construction period. During the years ended December 31, 2012, 2011 and 2010, interest costs of $1,194, $1,925 and $2,152 were capitalized, respectively.

As of December 31, 2012 the Company had commitments to purchase approximately $7,659 of new equipment, expected to be acquired at various dates in 2013.

(8) Asset Impairment and Restructuring

U.S. GAAP requires that a long-lived asset group that is held and used should be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the long-lived asset or asset group might not be recoverable. As a result of announcements made during 2012 regarding plans to curtail certain coal mining operations, the Company determined that indicators of impairment with respect to certain of its long-lived assets or asset groups existed. The Company's asset groups generally consist of the assets and applicable liabilities of one or more mines and preparation plants and associated coal reserves for which cash flows are largely independent of cash flows of other mines, preparation plants and associated coal reserves.

The Company determined that the undiscounted cash flows were less than the carrying value for certain asset groups. The Company estimated the fair value of these asset groups using a discounted cash flow analysis utilizing market-place participant

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

assumptions. To the extent that the carrying values of the asset groups exceeded their fair value, the Company recorded an asset impairment charge. The Company recorded asset impairment charges totaling $1,000,453 during the year ended December 31, 2012, of which $994,876 was recorded for asset groups in our Eastern Coal Operations segment and $5,577 was recorded for an asset group in the Company's Other segment. The asset impairment charges reduced the carrying values of mineral reserves $714,580, property, plant and equipment $281,357, and other acquired intangibles $4,516. The asset impairments established a new cost basis on which future depreciation, depletion and amortization will be based.

In connection with the plans to curtail mining operations and the associated company actions, for the year ended December 31, 2012, the Company also recorded severance expenses of $33,856, professional fees and other expenses of $13,636, lease termination costs of $13,445 and reserved $7,516 for advanced royalties, deposits and other assets which may not be recoverable.

(9) Goodwill and Other Acquired Intangibles, Net

Goodwill:

	Balance as of December 31, 2011			Acquisitions		Impairments			Balance as of December 31, 2012
Goodwill:
Eastern operations	$	3,024,308		$	—	$	—		$	3,024,308
Western operations	53,308			—		—			53,308
All other	5,912			—		—			5,912
Total goodwill	$	3,083,528		$	—	$	—		$	3,083,528
Accumulated impairment losses:
Eastern operations	$	(802,337	)	$	—	$	(1,660,218	)	$	(2,462,555	)
Western operations	—			—		(53,308		)	(53,308		)
All other	—			—		—			—
Total accumulated impairment losses	$	(802,337	)	$	—	$	(1,713,526	)	$	(2,515,863	)
Goodwill, net:
Eastern operations	$	2,221,971		$	—	$	(1,660,218	)	$	561,753
Western operations	53,308			—		(53,308		)	—
All other	5,912			—		—			5,912
Total goodwill, net	$	2,281,191		$	—	$	(1,713,526	)	$	567,665

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Balance as of December 31, 2010		Acquisitions		Impairments			Balance as of December 31, 2011
Goodwill:
Eastern operations	$	323,220	$	2,701,088	$	—		$	3,024,308
Western operations	53,308		—		—			53,308
All other	5,912		—		—			5,912
Total goodwill	$	382,440	$	2,701,088	$	—		$	3,083,528
Accumulated impairment losses:
Eastern operations	$	—	$	—	$	(802,337	)	$	(802,337	)
Western operations	—		—		—			—
All other	—		—		—			—
Total accumulated impairment losses	$	—	$	—	$	(802,337	)	$	(802,337	)
Goodwill, net:
Eastern operations	$	323,220	$	2,701,088	$	(802,337	)	$	2,221,971
Western operations	53,308		—		—			53,308
All other	5,912		—		—			5,912
Total goodwill, net	$	382,440	$	2,701,088	$	(802,337	)	$	2,281,191

The Company performs its annual goodwill impairment test as of October 31 of each year. Interim goodwill impairment tests are performed as conditions warrant. During the fourth quarter of 2011 and continuing throughout the first half of 2012, domestic and international coal markets declined as a result of slowing economic activity, fuel switching for electricity generation due to low priced natural gas and U.S. environmental regulations that discourage the use of coal. By June 1, 2012, due to the declining markets and the restructuring actions taken by the Company, the Company updated projections of production volumes and cash operating costs. These events, combined with the Company's assessment of its long-lived assets for impairment as of June 1, 2012, triggered an interim goodwill impairment test.

The Company performed its annual goodwill impairment test for a certain reporting unit in the Other segment using a qualitative approach. For the remaining reporting units, the Company performed its annual goodwill impairment test using a two-step approach. Step one compares the fair value of each reporting unit to its carrying value. The valuation methodology utilized to estimate the fair value of the reporting units is based on both a market and income approach and is within the range of fair values yielded under each approach. The income approach is based on a discounted cash flow methodology in which expected future net cash flows are discounted to present value, using an appropriate after-tax weighted average cost of capital. The market approach is based on a guideline company and similar transaction method. Under the guideline company method, certain operating metrics from a selected group of publically traded guideline companies that have similar operations to the Company’s reporting units are used to estimate the fair value of the reporting units. Under the similar transaction method, recent merger and acquisition transactions for companies that have similar operations to the Company’s reporting units are used to estimate the fair value of the Company’s reporting units.

In step two of the goodwill impairment test, the Company compares the carrying value of goodwill to its implied fair value. In estimating the implied fair value of goodwill at a reporting unit, the Company assigns the fair value of the reporting unit to all of the assets and liabilities associated with the reporting unit as if the reporting unit had been acquired in a business combination.

As a result of applying the approach discussed above at its annual impairment testing date of October 31, 2012, the interim impairment testing date of June 1, 2012 and at its annual impairment testing date of October 31, 2011, the Company recorded impairment charges of $188,194, $1,525,332 and $802,337, respectively, to reduce the carrying value of goodwill to its implied fair value. The impairment charge related to the Company's Eastern Coal Operations was $188,194, $1,472,024 and $802,337 at October 31, 2012, June 1, 2012 and October 31, 2011, respectively. The impairment charge related to the Company's Western Coal Operations was $53,308 at June 1, 2012.

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Other Acquired Intangibles:

	December 31, 2012
	Acquisition value		Accumulated amortization			Balance, net
Assets:
Above-market coal supply and transportation agreements	$	780,370	$	(613,529	)	$	166,841
Mining permits	95,679		(34,037		)	61,642
Covenant not-to-compete	7,100		(7,100		)	—
Other	450		(381		)	69
Total(1)	$	883,599	$	(655,047	)	$	228,552
Liabilities:
Below-market coal supply agreements(2)	$	611,328	$	(490,850	)	$	120,478

	December 31, 2011
	Acquisition value		Accumulated amortization			Balance, net
Assets:
Above-market coal supply and transportation agreements	$	780,370	$	(527,044	)	$	253,326
Mining permits	106,918		(16,506		)	90,412
Covenant not-to-compete	7,100		(3,089		)	4,011
Other	5,085		(4,945		)	140
Total(1)	$	899,473	$	(551,584	)	$	347,889
Liabilities:
Below-market coal supply agreements(2)	$	611,328	$	(306,762	)	$	304,566

⁽¹⁾  Reported as other acquired intangibles in the Consolidated Balance Sheets.

⁽²⁾  Reported in other long-term liabilities in the Consolidated Balance Sheets.

(10) Other Non-current Assets

Other non-current assets consisted of the following:

	December 31,
	2012		2011
Marketable securities - long term (1)	$	8,888	$	24,618
Unamortized deferred financing costs, net	85,662		87,477
Advance mining royalties, net	61,604		61,585
Virginia tax credit, net	20,759		20,256
Equity-method investments	55,570		48,338
Derivative financial instruments	4,718		8,571
Insurance receivables	25,677		28,936
Other	50,281		40,712
Total other non-current assets	$	313,159	$	320,493

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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

	December 31, 2012
			Unrealized
	Cost		Gain		Loss			Fair value
Long-term marketable securities:
Corporate debt securities (a)	$	754	$	1	$	—		$	755
Mutual funds held in rabbi trust (b)	7,544		2,084		(1,495		)	8,133
Total long-term securities	$	8,298	$	2,085	$	(1,495	)	$	8,888

	December 31, 2011
			Unrealized
	Cost		Gain		Loss			Fair value
Long-term marketable securities:
US treasury and agency securities (a)	$	20,451	$	49	$	(11	)	$	20,489
Mutual funds held in rabbi trust (b)	4,222		578		(671		)	4,129
Total long-term securities	$	24,673	$	627	$	(682	)	$	24,618

^(a)  Unrealized gains and losses are recorded as a component of stockholders’ equity.

^(b)  Unrealized gains and losses are recorded in current period earnings.

(11) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following:

	December 31,
	2012		2011
Wages and employee benefits	$	126,760	$	184,806
Current portion of asset retirement obligations	93,219		190,993
Taxes other than income taxes	131,291		143,835
Freight	9,090		27,553
Current portion of self insured workers’ compensation obligations	26,700		21,681
Interest payable	27,884		18,237
Derivative financial instruments	3,154		32,214
Current portion of postretirement medical benefit obligations	42,250		38,171
Deferred revenue	43,185		7,585
Litigation (a)	316,766		604,023
Other	52,103		90,062
Total accrued expenses and other current liabilities	$	872,402	$	1,359,160

^(a)  The Company has recorded related receivables of $196,074 and $289,019 from insurance coverage and indemnifications in prepaid expenses and other current assets at December 31, 2012 and 2011, respectively.

(12) Long-Term Debt

Long-term debt consisted of the following:

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	December 31,
	2012			2011
6.25% senior notes due 2021	$	700,000		$	700,000
6.00% senior notes due 2019	800,000			800,000
9.75% senior notes due 2018	500,000			—
Term loan due 2016	540,000			585,000
3.25% convertible senior notes due 2015	536,162			658,673
2.375% convertible senior notes due 2015	287,500			287,500
Other	86,203			23,554
Debt discount, net	(63,813		)	(86,646		)
Total long-term debt	$	3,386,052		$	2,968,081
Less current portion	(95,015		)	(46,029		)
Long-term debt, net of current portion	$	3,291,037		$	2,922,052

Notes Indenture and the Senior Notes

On June 1, 2011, Alpha, certain of Alpha’s wholly owned domestic subsidiaries (collectively, the “Alpha Guarantors”) and Union Bank, N.A., as trustee, entered into an indenture (the “Base Indenture”) and a first supplemental indenture (the “First Supplemental Indenture” and, together with the Base Indenture, the “Notes Indenture”) governing Alpha’s newly issued 6.00% senior notes due 2019 (the “2019 Notes”) and 6.25% senior notes due 2021 (the “2021 Notes”).

On June 1, 2011, in connection with the Massey Acquisition, Alpha, the Alpha Guarantors, Massey, and certain wholly owned subsidiaries of Massey (the “Massey Guarantors” and together with the Alpha Guarantors the “Guarantors”), and Union Bank, N.A., as trustee, entered into a supplemental indenture (the “Second Supplemental Indenture”) to the Notes Indenture pursuant to which Massey and certain wholly owned subsidiaries of Massey agreed to become additional guarantors for the 2019 Notes and 2021 Notes.

On October 11, 2012, Alpha, the Guarantors and Union Bank, N.A., as trustee, entered into a supplemental indenture (the “Third Supplemental Indenture”) to the Notes Indenture governing Alpha's newly issued 9.75% senior notes due 2018 (the “2018 Notes” and, together with the 2019 Notes and the 2021 Notes, the “Senior Notes”).

The 2018 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on April 15 and October 15 of each year, beginning on April 15, 2013, and will mature on April 15, 2018. The 2019 Notes bear interest at a rate of 6.00% per annum, payable semi-annually on June 1 and December 1 of each year, beginning on December 1, 2011, and will mature on June 1, 2019. The 2021 Notes bear interest at a rate of 6.25% per annum, payable semi-annually on June 1 and December 1 of each year, beginning on December 1, 2011, and will mature on June 1, 2021.

As of December 31, 2012, the carrying values of the 2018 Notes, 2019 Notes and 2021 Notes were $495,161, net of discount of $4,839, $800,000 and $700,000, respectively. As of December 31, 2011, the carrying values of the 2019 Notes and 2021 Notes were $800,000 and $700,000, respectively.

Alpha may redeem the 2018 Notes, in whole or in part, at any time prior to maturity, at a price equal to 100.000% of the aggregate principal amount of the 2018 Notes plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date. In addition, Alpha may redeem up to 35% of the aggregate principal amount of the 2018 Notes with the net cash proceeds from certain equity offerings, at any time prior to October 15, 2015, at a redemption price equal to 109.75% of the aggregate principal amount of the 2018 Notes, plus accrued and unpaid interest, if any, to, but not including the applicable redemption date, if at least 65% of the aggregate principal amount of the 2018 Notes originally issued under the Notes Indenture remains outstanding immediately after the redemption and the redemption occurs within 180 days of the date of the closing of such equity offering.

Alpha may redeem the 2019 Notes, in whole or in part, at any time prior to June 1, 2014, at a price equal to 100.000% of the aggregate principal amount of the 2019 Notes plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date.  Alpha may redeem the 2019 Notes, in whole or in part, at any time during

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

the twelve months commencing June 1, 2014, at 103.000% of the aggregate principal amount of the 2019 Notes, at any time during the twelve months commencing June 1, 2015, at 101.500% of the aggregate principal amount of the 2019 Notes, and at any time after June 1, 2016 at 100.000% of the aggregate principal amount of the 2019 Notes, in each case plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date.  In addition, Alpha may redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net cash proceeds from certain equity offerings, at any time prior to June 1, 2014, at a redemption price equal to 106.000% of the aggregate principal amount of the 2019 Notes, plus accrued and unpaid interest, if any, to, but not including the applicable redemption date, provided that at least 65% of the aggregate principal amount of the 2019 notes originally issued under the Notes Indenture remains outstanding after the redemption and the redemption occurs within 180 days of the closing of such equity offering.

Alpha may redeem the 2021 Notes, in whole or in part, at any time prior to June 1, 2016, at a price equal to 100.000% of the aggregate principal amount of the 2021 Notes plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date.  Alpha may redeem the 2021 Notes, in whole or in part, at any time during the twelve months commencing June 1, 2016, at 103.125% of the aggregate principal amount of the 2021 Notes, at any time during the twelve months commencing June 1, 2017, at 102.083% of the aggregate principal amount of the 2021 Notes, at any time during the twelve months commencing June 1, 2018, at 101.042% of the aggregate principal amount of the 2021 Notes, and at any time after June 1, 2019, at 100.000% of the aggregate principal amount of the 2021 Notes, in each case plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date.  In addition, Alpha may redeem up to 35% of the aggregate principal amount of the 2021 Notes with the net cash proceeds from certain equity offerings, at any time prior to June 1, 2016, at a redemption price equal to 106.250% of the aggregate principal amount of the 2021 Notes, plus accrued and unpaid interest, if any, to, but not including the applicable redemption date, provided that at least 65% of the aggregate principal amount of the 2021 notes originally issued under the Notes Indenture remains outstanding after the redemption and the redemption occurs within 180 days of the date of the closing of such equity offering.

Upon the occurrence of a change in control repurchase event with respect to any of the series of the Senior Notes, unless Alpha has exercised its right to redeem those Senior Notes, Alpha will be required to offer to repurchase each holder’s Senior Notes of such series at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the date of repurchase.

The Notes Indenture contains covenants that limit, among other things, Alpha’s ability to:

• incur, or permit its subsidiaries to incur, additional debt;

• issue, or permit its subsidiaries to issue, certain types of stock;

• pay dividends on Alpha’s or its subsidiaries’ capital stock or repurchase Alpha’s common stock;

• make certain investments;

• enter into certain types of transactions with affiliates;

• incur liens on certain assets to secure debt;

• limit dividends or other payments by its restricted subsidiaries to Alpha and its other restricted subsidiaries;

• consolidate, merge or sell all or substantially all of its assets; and

• make certain payments on Alpha’s or its subsidiaries’ subordinated debt.

These covenants are subject to a number of important qualifications and exceptions. These covenants may not apply at any time after the Senior Notes are assigned a credit grade rating of at least BB+ (stable) from Standard & Poor’s Ratings Services and of at least Ba1 (stable) from Moody’s Investor Service, Inc.

Third Amended and Restated Credit Agreement

On May 19, 2011, in connection with the Massey Acquisition, Alpha entered into a Third Amended and Restated Credit Agreement to amend and restate in its entirety the credit agreement dated as of July 30, 2004, as amended as of November 12, 2004 and as of October 18, 2005, as amended and restated as of July 7, 2006, as amended effective July 31, 2009 and as further amended and restated as of April 15, 2010 (as so amended and restated, the “Former Credit Agreement”; the Former Credit Agreement, as amended and restated by the Third Amended and Restated Credit Agreement, is referred to as the “Credit Agreement”), with Citicorp North America, Inc., as administrative agent and as collateral agent, Bank of America, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, The Royal Bank of Scotland plc and Union Bank, N.A. and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as co-documentation agents, Morgan Stanley Senior Funding, Inc., as sole syndication agent, Citigroup Global Markets Inc. and Morgan Stanley Senior Funding, Inc., as joint lead arrangers and joint

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

book managers, and various other financial institutions, as lenders. The terms of the Credit Agreement amended and restated and superseded the Former Credit Agreement in its entirety upon the satisfaction of certain conditions precedent, which included the consummation of the Massey Acquisition (the satisfaction of such conditions precedent is referred to as the “initial Credit Event”). The Former Credit Agreement remained in full force and effect until the occurrence of the initial Credit Event.

Upon the occurrence of the initial Credit Event, the Credit Agreement provided for a $600,000 senior secured term loan A facility (the “Term Loan Facility”) and a $1,000,000 senior secured revolving credit facility (the “Revolving Facility”).  Pursuant to the Credit Agreement, Alpha may request incremental term loans or increase the revolving commitments under the Revolving Facility in an aggregate amount of up to $1,250,000 plus an additional $750,000 subject to compliance with a consolidated senior secured leverage ratio.  The lenders under these facilities will not be under any obligation to provide any such incremental loans or commitments, and any such addition of or increase in such loans or commitments will be subject to certain customary conditions precedent.

On June 26, 2012, the Company entered into an amendment (the “Credit Agreement Amendment”) to the Credit Agreement. The Credit Agreement Amendment, among other things:

1) replaces the maximum net leverage ratio covenant with a maximum net secured leverage ratio covenant through the end of 2014, increases the maximum net leverage ratio covenant for the first and second quarters of 2015, and decreases the minimum interest coverage ratio from the fourth quarter of 2012 through the end of 2013;

2) adds a minimum liquidity covenant of $500,000 through the end of 2014;

3) increases the applicable margin for borrowings under the Credit Agreement if the Company's consolidated net leverage ratio is greater than 3.75 to 1.00 for the preceding fiscal quarter;

4) modifies the requirements for incremental term loan or revolving credit facilities in excess of $500,000; and,

5) provides additional real property collateral to secure obligations under the Credit Agreement and certain hedging and cash management obligations with lenders and affiliates of lenders.

As of December 31, 2012, the carrying value of the Term Loan Facility was $539,481, net of debt discount of $519, with $75,000 classified as current portion of long-term debt. As of December 31, 2011, the carrying value of the Term Loan Facility was $584,330, net of debt discount of $670, with $45,000 classified as current portion of long-term debt.  There were no borrowings outstanding under the Revolving Facility as of December 31, 2012 or 2011.  Letters of credit outstanding at December 31, 2012 and 2011 under the Revolving Facility were $300 and $300, respectively.

Interest Rate and Fees.  Borrowings under the Credit Agreement bear interest at a rate per annum equal to an applicable margin plus, at Alpha’s option, either (a) a base rate determined by reference to the highest of (i) the rate that Citibank, N.A. announces from time to time as its prime or base commercial lending rate, (ii) the federal funds effective rate plus 0.50% and (iii) a London Interbank Offer (“LIBO”) rate for a 30-day interest period as determined on such day, plus 1.00%, or (b) a LIBO rate for the interest period relevant to such borrowing adjusted for certain additional costs.  The initial applicable margin for borrowings under the Credit Agreement is 1.50% with respect to base rate borrowings and 2.50% with respect to LIBO rate borrowings.  Commencing October 1, 2011, the applicable margin for borrowings under the Credit Agreement became subject to adjustment each fiscal quarter based on Alpha’s consolidated leverage ratio for the preceding fiscal quarter.  Swingline loans bear interest at a rate per annum equal to the base rate plus the applicable margin.  The interest rate in effect at December 31, 2012 and 2011 was 2.72% and 2.51%, respectively. In addition to paying interest on outstanding principal under the Credit Agreement, Alpha is required to pay a commitment fee to the lenders under the Revolving Facility in respect of the unutilized commitments thereunder. The initial commitment fee is 0.50% per annum.  Commencing October 1, 2011, the commitment fee became subject to adjustment each fiscal quarter based on Alpha’s consolidated leverage ratio for the preceding fiscal quarter.  Alpha must also pay customary letter of credit fees and agency fees.

Mandatory Prepayments.  The Credit Agreement requires Alpha to prepay outstanding loans, subject to certain exceptions, with (i) 100% of the net cash proceeds (including the fair market value of noncash proceeds) from certain asset sales and condemnation events in excess of the greater of $1,500,000 and 15% of consolidated tangible assets as of the end of each fiscal year, (ii) 100% of the aggregate gross proceeds (including the fair market value of noncash proceeds) from certain Intracompany Disposals (as defined in the Credit Agreement) exceeding $500,000 during the term of the Credit Agreement and

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

(iii) 100% of the net cash proceeds from any incurrence or issuance of certain debt, other than debt permitted under the Credit Agreement. Mandatory prepayments will be applied first to the Term Loan Facility and thereafter to reductions of the commitments under the Revolving Facility. If at any time the aggregate amount of outstanding revolving loans, swingline loans, unreimbursed letter of credit drawings and undrawn letters of credit under the Revolving Facility exceeds the commitment amount, Alpha will be required to repay outstanding loans or cash collateralize letters of credit in an aggregate amount equal to such excess, with no reduction of the commitment amount.

Voluntary Prepayments; Reductions in Commitments. Alpha may prepay, in whole or in part, amounts outstanding under the Credit Agreement, with prior notice but without premium or penalty (other than customary “breakage” costs with respect to LIBO rate loans) and in certain minimum amounts.  Alpha may also repurchase loans outstanding under the Term Loan Facility pursuant to standard reverse Dutch auction and open market purchase provisions, subject to certain limitations and exceptions.  Alpha may make voluntary reductions to the unutilized commitments of the Revolving Facility from time to time without premium or penalty.

Amortization and Final Maturity.  Beginning on September 30, 2011, Alpha became required to make scheduled quarterly amortization payments with respect to loans under the Term Loan Facility.  In the first two quarters of 2013, each quarterly amortization payment will be in an amount equal to 2.5% of the original principal amount of the term loans.  In the last two quarters of 2013 and the first two quarters of 2014, each quarterly amortization payment will be in an amount equal to 3.75% of the original principal amount of the term loans.  In the last two quarters of 2014 and the first two quarters of 2015, each quarterly amortization payment will be in an amount equal to 5% of the original principal amount of the term loans.  In the last two quarters of 2015 and the first two quarters of 2016, each quarterly amortization payment will be in an amount equal to 12.5% of the original principal amount of the term loans.  There is no scheduled amortization under the Revolving Facility.  The principal amount outstanding on the loans under the Revolving Facility will be due and payable on June 30, 2016.  The Term Loan Facility and Revolving Facility will each mature on June 30, 2016.

Guarantees and Collateral.  All obligations under the Credit Agreement are unconditionally guaranteed by certain of Alpha’s existing wholly owned domestic subsidiaries, and are required to be guaranteed by certain of Alpha’s future wholly owned domestic subsidiaries.  All obligations under the Credit Agreement and certain hedging and cash management obligations with lenders and affiliates of lenders thereunder are secured, subject to certain exceptions, by substantially all of Alpha’s assets and the assets of Alpha’s subsidiary guarantors, in each case subject to exceptions, thresholds and limitations.

Certain Covenants and Events of Default. The Credit Agreement contains a number of negative covenants that, among other things and subject to certain exceptions, restrict Alpha’s ability and the ability of Alpha’s subsidiaries to:

• make investments, loans and acquisitions;

• incur additional indebtedness;

• incur liens;

• consolidate or merge;

• sell assets, including capital stock of its subsidiaries;

• pay dividends on its capital stock or redeem, repurchase or retire its capital stock or its other Indebtedness;

• engage in transactions with its affiliates;

• materially alter the business it conducts; and

• create restrictions on the payment of dividends or other amounts to Alpha from Alpha’s restricted subsidiaries.

In addition, the Credit Agreement requires Alpha to comply with certain financial ratio maintenance covenants.

The Credit Agreement also contains customary representations and warranties, affirmative covenants and events of default, including a cross-default provision in respect of any other indebtedness that has an aggregate principal amount exceeding $25,000.

Former Credit Agreement

The Former Credit Agreement consisted of term loans and revolving credit facility commitments due on July 31, 2014.  During the year ended December 31, 2011, borrowings under the Former Credit Agreement totaling $227,896 were repaid.  The Former Credit Agreement was replaced with the Credit Agreement as described above. 

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

3.25% Convertible Senior Notes due 2015

As a result of the Massey Acquisition, the Company became a guarantor of Massey’s 3.25% Convertible Notes, with aggregate principal outstanding at June 1, 2011 of $659,063. The 3.25% Convertible Notes bear interest at a rate of 3.25% per annum, payable semi-annually in arrears on August 1 and February 1 of each year. The 3.25% Convertible Notes will mature on August 1, 2015, unless earlier repurchased by the Company or converted. The 3.25% Convertible Notes had a fair value of $730,900 at the acquisition date. The Company accounts for the 3.25% Convertible Notes under ASC 470-20, which requires issuers of convertible debt instruments that may be settled wholly or partially in cash upon conversion to separately account for the liability and equity components in a manner reflective of the issuers’ nonconvertible debt borrowing rate.  As of December 31, 2012, the carrying amount of the debt was $515,901, net of debt discount of $20,261. As of December 31, 2011, the carrying amount of the debt was $624,946, net of debt discount of $33,727.  As of December 31, 2012 and 2011, the carrying amount of the equity component totaled $110,375.  The debt discount is being accreted over the four-year term of the 3.25% Convertible Notes, and provides for an effective interest rate of 4.21%.

On October 25, 2012, the Company completed a cash tender offer for a portion of the outstanding 3.25% Convertible Notes. The Company paid $115,943, including interest, to redeem $122,511 of the 3.25% Convertible Notes. The Company recognized a gain on early extinguishment of debt of $773.

The 3.25% Convertible Notes are senior unsecured obligations and rank equally with all of the Company’s existing and future senior unsecured indebtedness. The 3.25% Convertible Notes are guaranteed on a senior unsecured basis by Massey’s subsidiaries (which are among the Company’s subsidiaries), other than certain minor subsidiaries of Massey.  The 3.25% 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 non-guarantor subsidiaries, including trade payables. The 3.25% Convertible Notes are convertible in certain circumstances and in specified periods at a conversion rate, subject to adjustment, of the value of 11.4560 shares of common stock per $1,000 principal amount of 3.25% Convertible Notes. From and after the effective date of the Massey Acquisition, the consideration deliverable upon conversion of the 3.25% Convertible Notes ceased to be based upon Massey common stock and instead became based upon Reference Property (as defined in the indenture governing the 3.25% Convertible Notes, (the “3.25% Convertible Notes Indenture”)) consisting of 1.025 shares of Alpha common stock (subject to adjustment upon the occurrence of certain events set forth in the 3.25% Convertible Notes Indenture) plus $10.00 in cash per share of Massey common stock. Upon conversion of the 3.25% Convertible Notes, holders will receive cash up to the principal amount of the notes being converted, and any excess conversion value will be delivered in cash, Reference Property, or a combination thereof, at the Company’s election.  One of the circumstances under which the 3.25% Convertible Notes would become convertible is if the Company’s common stock price exceeds a set threshold during a reference period specified in the 3.25% Convertible Notes Indenture.

The 3.25% Convertible Notes Indenture contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee or the holders of at least 25% in aggregate principal amount of the 3.25% Convertible Notes then outstanding may declare the principal of the 3.25% Convertible Notes and any accrued and unpaid interest immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to the Company, the principal amount of the 3.25% Convertible Notes together with any accrued and unpaid interest thereon will automatically become due and immediately payable.

The 3.25% Convertible Notes were not convertible as of December 31, 2012 or 2011 and as a result have been classified as long-term at both dates.

2.375% Convertible Senior Notes Due April 15, 2015

As of December 31, 2012 and 2011, the Company had $287,500 aggregate principal amount of 2.375% convertible senior notes due April 15, 2015.  The 2.375% 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 2.375% Convertible Notes under ASC 470-20, which requires issuers of convertible debt instruments that may be settled wholly or partially in cash upon conversion to separately account for the liability and equity components in a manner reflective of the issuers’ nonconvertible debt borrowing rate.  The related deferred loan costs and discount are being amortized and accreted, respectively, over the seven-year term of the 2.375% Convertible Notes, and provide for an effective interest rate of 8.64%.  As of December 31, 2012 and 2011, the carrying amounts of the debt component were $249,306 and $235,251, respectively.  As of

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

December 31, 2012 and 2011, the unamortized debt discount was $38,194 and $52,249, respectively.  As of December 31, 2012 and 2011, the carrying amount of the equity component was $69,851.

The 2.375% 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 2.375% 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 2.375% 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 2.375% Convertible Notes, subject to adjustment upon the occurrence of certain events set forth in the indenture governing the 2.375% Convertible Notes (the “2.375% Convertible Notes Indenture”). Upon conversion of the 2.375% 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 combination thereof, at the Company’s election.

The 2.375% 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, or the holders of not less than 25% in aggregate principal amount of the 2.375% Convertible Notes then outstanding may declare the principal of 2.375% 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 2.375% Convertible Notes together with any accrued and unpaid interest thereon will automatically become due and be immediately payable.

The 2.375% Convertible Notes were not convertible as of December 31, 2012 and 2011 and therefore have been classified as long-term debt at both dates.

6.875% Senior Notes due 2013

The Company assumed Massey’s 6.875% senior notes due 2013 (the “2013 Notes”) with an aggregate principal amount outstanding of $760,000 as part of the Massey Acquisition. Following a cash tender offer for the 2013 Notes and upon redemption of the 2013 Notes on the redemption date of July 1, 2011, the Company recorded a loss on early extinguishment of $752.

7.25% Senior Notes Due August 1, 2014

Foundation PA Coal Company, LLC (“Foundation PA”), one of the Company’s subsidiaries, had notes that were scheduled to mature on August 1, 2014 (the “2014 Notes”). The outstanding 2014 Notes were redeemed and became due and payable on August 18, 2011 (the “Redemption Date”) at a redemption price equal to 101.208% of the principal amount of the 2014 Notes, plus any and all accrued and unpaid interest up to but excluding the Redemption Date. The Company paid $302,909, including interest, to redeem the 2014 Notes. The Company recognized a loss on early extinguishment of debt of $4,438, including the premium paid.

Accounts Receivable Securitization

The Company and certain of its subsidiaries are parties to an 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 $275,000 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. The A/R Facility was amended in June 2011 to increase the capacity of the A/R Facility from $150,000 to $190,000 and the A/R Facility was amended and restated in October 2011 to further increase the capacity of the A/R Facility to $275,000. Unless extended by the

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

parties, the receivables purchase agreement supporting the borrowings under the A/R Facility expires October 17, 2014, or earlier upon the occurrence of certain events customary for facilities of this type.

On June 26, 2012, the SPE and Alpha Natural Resources, LLC (“ANR LLC”), each of which are subsidiaries of the Company, entered into an amendment (the “A/R Facility Amendment”) to the Second Amended and Restated Receivables Purchase Agreement, dated as of October 19, 2011, by and among the SPE, ANR LLC, certain financial institutions from time to time parties thereto as conduit purchasers, committed purchasers, purchaser agents and LC Participants (as defined therein) and PNC Bank, National Association, as administrator and LC Bank (as defined therein). The A/R Facility Amendment, among other things, replaces the maximum net leverage ratio termination event with a termination event based on a maximum net secured leverage ratio through the end of 2014 and increases the maximum net leverage ratio termination event for the first and second quarters of 2015.

As of December 31, 2012, letters of credit in the amount of $160,230 were outstanding under the A/R Facility and no cash borrowing transactions had taken place. As of December 31, 2011, letters of credit in the amount of $159,987 were outstanding under the A/R Facility 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 Company 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.

Capital Leases

The Company entered into capital leases for equipment during 2012. The Company's liability for capital leases as of December 31, 2012 totaled $66,976.

Future Maturities

Future maturities of long-term debt as of December 31, 2012 are as follows:

2013	$	95,015
2014	124,667
2015	1,046,975
2016	155,643
2017	8,181
Thereafter	2,019,384
Total long-term debt	$	3,449,865

(13) Asset Retirement Obligations

As of December 31, 2012 and 2011, the Company had recorded asset retirement obligation accruals for mine reclamation and closure costs totaling $856,701 and $934,606, respectively. The portion of the costs expected to be paid within a year of $93,219 and $190,993, as of December 31, 2012 and 2011, 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, 2012 or 2011. 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 are secured by surety bonds.

121

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Changes in the asset retirement obligations were as follows:

Total asset retirement obligations at December 31, 2010	$	222,993
Asset retirement obligations assumed in Massey Acquisition(1)	628,836
Accretion for the period	43,062
Sites added during the period	2,438
Revisions in estimated cash flows(2)	60,110
Expenditures for the period	(22,833		)
Total asset retirement obligations at December 31, 2011	934,606
Accretion for the period	65,548
Sites added during the period	2,154
Revisions in estimated cash flows(3)	(95,294		)
Expenditures for the period	(50,313		)
Total asset retirement obligations at December 31, 2012	$	856,701
Less current portion	(93,219		)
Long-term portion	$	763,482

⁽¹⁾  See Note 3.

⁽²⁾  As a result of matters related to the treatment of mine water discharges for selenium more fully discussed in Note 21, the Company increased its asset retirement obligations by $55,316 , of which $37,137 was related to inactive mines and was recorded as an increase to cost of coal sales in the Consolidated Statements of Operations for the year ended December 31, 2011.

⁽³⁾  Amount includes a reduction related to inactive mines of $154,377 for changes in engineering estimates largely pertaining to future water treatment costs, including the impacts of evolving treatment technologies and maturing treatment plans which was recorded as a reduction to cost of coal sales in the Consolidated Statements of Operations for the year ended December 31, 2012.

(14) Other Non-current Liabilities

Other non-current liabilities consisted of the following:

	December 31,
	2012		2011
Self insured workers’ compensation obligations	$	153,283	$	165,925
Black lung obligations	135,879		152,789
Below-market and other contract-related obligations, net	255,031		471,531
Deferred coal revenue	43,539		3,909
Derivative financial instruments	972		6,666
Other	89,972		120,621
Total other non-current liabilities	$	678,676	$	921,441

(15) 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.

122

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 values of the 6.25% senior notes due 2021, the 6.00% senior notes due 2019, the 9.75% senior notes due 2018, the 2.375% Convertible Notes and the 3.25% Convertible Notes were estimated using observable market prices as these securities are traded. The fair values of the term loans are estimated based on a current market rate of interest offered to the Company for debt of similar maturities.

The estimated fair values of long-term debt were as follows:

	December 31, 2012
	Carrying Amount		Total Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
6.25% senior notes due 2021	$	700,000	$	649,110	$	649,110	$	—	$	—
6.00% senior notes due 2019	800,000		755,600		755,600		—		—
9.75% senior notes due 2018(4)	495,161		540,125		540,125		—		—
Term loan due 2016(1)	539,481		537,316		—		537,316		—
3.25% convertible senior notes due 2015(2)	515,901		513,375		513,375		—		—
2.375% convertible senior notes due 2015(3)	249,306		268,094		268,094		—		—
Total long-term debt	$	3,299,849	$	3,263,620	$	2,726,304	$	537,316	$	—

	December 31, 2011
	Carrying Amount		Total Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
6.25% senior notes due 2021	$	700,000	$	682,500	$	682,500	$	—	$	—
6.00% senior notes due 2019	800,000		780,000		780,000		—		—
Term loan due 2016(1)	584,330		584,989		—		584,989		—
3.25% convertible senior notes due 2015(2)	624,946		596,955		596,955		—		—
2.375% convertible senior notes due 2015(3)	235,251		276,596		276,596		—		—
Total long-term debt	$	2,944,527	$	2,921,040	$	2,336,051	$	584,989	$	—

⁽¹⁾  Net of debt discount of $519 and $670 as of December 31, 2012 and 2011, respectively.

⁽²⁾  Net of debt discount of $20,261 and $33,727 as of December 31, 2012 and 2011, respectively.

⁽³⁾  Net of debt discount of $38,194 and $52,249 as of December 31, 2012 and 2011, respectively.

⁽⁴⁾  Net of debt discount of $4,839 as of December 31, 2012.

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.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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, 2012 and 2011, 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, 2012
	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	$	85,568		$	85,568	$	—		$	—
Mutual funds held in rabbi trust	$	8,133		$	8,133	$	—		$	—
Corporate debt securities	$	212,639		$	—	$	212,639		$	—
Forward coal sales	$	15,359		$	—	$	15,359		$	—
Forward coal purchases	$	(4	)	$	—	$	(4	)	$	—
Commodity swaps	$	7,080		$	—	$	7,080		$	—
Commodity options	$	138		$	—	$	138		$	—

	December 31, 2011
	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	$	38,965		$	38,965	$	—		$	—
Mutual funds held in rabbi trust	$	4,129		$	4,129	$	—		$	—
Corporate debt securities	$	61,866		$	—	$	61,866		$	—
Forward coal sales	$	27,254		$	—	$	27,254		$	—
Forward coal purchases	$	(15,456	)	$	—	$	(15,456	)	$	—
Commodity swaps	$	3,222		$	—	$	3,222		$	—
Commodity options	$	95		$	—	$	95		$	—
Interest rate swaps	$	(10,097	)	$	—	$	(10,097	)	$	—

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 and Mutual Funds Held in Rabbi Trust — The fair value of marketable securities is based on observable market data.

Senior Notes, 2.375% Convertible Notes and 3.25% Convertible Notes — The fair value is based on observable market data.

Level 2 Fair Value Measurements

124

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 estimates of fair value.

Forward Coal Purchase and Sales — 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.

Term Loan due 2016 — The fair values of the Term Loan due 2016 is estimated based on market rates of interest offered for debt of similar maturities.

(16) 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. 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.

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 8%, 6%, and 7% of cost of coal sales for the years ended December 31, 2012, 2011, and 2010, 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 diesel fuel. 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, 2012, the Company had swap agreements outstanding to hedge the variable cash flows related to 53% and 39% of anticipated diesel fuel usage for calendar years 2013 and 2014, respectively. The average fixed price per swap for diesel fuel hedges is $3.01 per gallon and $2.82 per gallon for calendar years 2013 and 2014, respectively. 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, 2012, 2011, and 2010.

125

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The Company also sells coalbed methane through its Coal Gas Recovery business. 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, 2012, the Company had swap agreements outstanding to hedge the variable cash flows related to approximately 76% of anticipated natural gas production in 2013.

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 expired during 2012. During 2012, 2011 and 2010, changes in fair value were 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, 2012		December 31, 2011
Commodity swaps (1)	$	11,202	$	16,532
Commodity options (1)	138		112
	$	11,340	$	16,644

Derivatives not designated as  cash flow hedging instruments	December 31, 2012		December 31, 2011
Forward coal sales (2)	$	15,359	$	27,254
Total asset derivatives	$	26,699	$	43,898

⁽¹⁾  As of December 31, 2012, $6,622 is recorded in prepaid expenses and other current assets and $4,718 is recorded in other non-current assets in the Consolidated Balance Sheets. As of December 31, 2011, $14,436 is recorded in prepaid expenses and other current assets and $2,208 is recorded in other non-current assets in the Consolidated Balance Sheets.

⁽²⁾  As of December 31, 2012, $15,359 is recorded in prepaid expenses and other current assets in the Consolidated Balance Sheets. As of December 31, 2011, $20,891 is recorded in prepaid expenses and other current assets and $6,363 is recorded in other non-current assets in the Consolidated Balance Sheets.

	Liability Derivatives
Derivatives designated as  cash flow hedging instruments	December 31, 2012		December 31, 2011
Commodity swaps (1)	$	3,429	$	12,874

126

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Derivatives not designated as  cash flow hedging instruments	December 31, 2012		December 31, 2011
Forward coal purchases (2)	$	4	$	15,456
Commodity swaps (3)	693		436
Commodity options-coal (4)	—		17
Interest rate swaps (5)	—		10,097
Total	$	697	$	26,006
Total liability derivatives	$	4,126	$	38,880

________________________________ 

⁽¹⁾  As of December 31, 2012, $2,457 is recorded in accrued expenses and other current liabilities and $972 is recorded in other non-current liabilities in the Consolidated Balance Sheets. As of December 31, 2011, $6,222 is recorded in accrued expenses and other current liabilities and $6,652 is recorded in other non-current liabilities in the Consolidated Balance Sheets. 

⁽²⁾  As of December 31, 2012, $4 is recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets. As of December 31, 2011, $15,456 is recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets.

⁽³⁾  As of December 31, 2012, $693 is recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets. As of December 31, 2011, $436 is recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets.

⁽⁴⁾  As of December 31, 2011, $3 is recorded in accrued expenses and other current liabilities and $14 is recorded in other non-current liabilities in the Consolidated Balance Sheets.

⁽⁵⁾  As of December 31, 2011, $10,097 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, 2012, 2011, and 2010 and their location within the consolidated financial statements:

	Gain (loss) reclassified from accumulated other comprehensive income (loss) to  earnings						Gain (loss) recorded in accumulated other comprehensive income (loss) (2)
Derivatives designated as  cash flow hedging instruments	2012		2011		2010		2012			2011		2010
Commodity swaps (1) (2)	$	10,390	$	15,407	$	277	$	13,831		$	8,277	$	7,821
Commodity options (1) (2)	—		—		—		(19		)	20		—
Total	$	10,390	$	15,407	$	277	$	13,812		$	8,297	$	7,821

 __________________

⁽¹⁾  Amounts recorded in other expenses in the Consolidated Statements of Operations.

⁽²⁾  Net of tax.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Gain (loss) recorded in earnings
Derivatives not designated as  cash flow hedging instruments	2012			2011			2010
Forward coal sales (1)	$	(11,887	)	$	149,252		$	(739	)
Forward coal purchases (1)	15,452			(22,408		)	(1,099		)
Commodity swaps (2)	348			(436		)	(428		)
Commodity options-diesel fuel (2)	—			—			(94		)
Commodity options-coal (1)	17			246			(8		)
Interest rate swaps (3)	(400		)	(1,263		)	(8,901		)
Freight swap (2)	—			—			(47		)
Total	$	3,530		$	125,391		$	(11,316	)

_________________________________

⁽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 year ended December 31, 2012, the Company reclassified ($460), net of tax, out of accumulated other comprehensive income (loss) because the underlying forecasted transactions were considered probable not to occur. During the next twelve months, the Company expects to reclassify approximately $2,053, 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, 2012, 2011 and 2010:

	Years Ended December 31,
	2012			2011			2010
Balance at beginning of period	$	1,333		$	8,443		$	899
Net change associated with current year hedging transactions	13,812			8,297			7,821
Net amounts reclassified to earnings	(10,390		)	(15,407		)	(277		)
Balance at end of period	$	4,755		$	1,333		$	8,443

(17) Income Taxes

The total income tax expense (benefit) provided on pre-tax income was allocated as follows:

	Years Ended December 31,
	2012			2011			2010
Continuing operations	$	(549,996	)	$	(35,906	)	$	4,218
Discontinued operations	—			—			(1,052		)
	$	(549,996	)	$	(35,906	)	$	3,166

Significant components of income tax expense (benefit) from continuing operations were as follows:

128

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Years Ended December 31,
	2012			2011			2010
Current tax expense (benefit):
Federal	$	(1,686	)	$	(12,915	)	$	63,045
State	6,265			(5,906		)	11,367
	$	4,579		$	(18,821	)	$	74,412
Deferred tax expense (benefit):
Federal	$	(482,015	)	$	(18,743	)	$	(68,169	)
State	(72,560		)	1,658			(2,025		)
	$	(554,575	)	$	(17,085	)	$	(70,194	)
Total income tax expense (benefit):
Federal	$	(483,701	)	$	(31,658	)	$	(5,124	)
State	(66,295		)	(4,248		)	9,342
	$	(549,996	)	$	(35,906	)	$	4,218

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,
	2012			2011			2010
Federal statutory income tax expense (benefit)	$	(1,045,500	)	$	(268,257	)	$	35,503
Increases (reductions) in taxes due to:
Percentage depletion allowance	(76,252		)	(60,166		)	(47,917		)
State taxes, net of federal tax impact	(22,620		)	(12,041		)	(2,092		)
State tax rate and NOL change, net of federal tax benefit	(8,180		)	(8,180		)	7,437
Deduction for domestic production activities	—			—			(2,201		)
Change in valuation allowances	40,757			5,352			25
Change in law - Medicare Part D Subsidy (1)	—			—			25,566
Other non-deductible costs	1,638			9,999			2,014
State apportionment change, net of federal tax impact	(18,654		)	13,166			—
Non-deductible goodwill impairment	572,503			280,818			—
Reversal of reserves for uncertain tax positions (2)	—			(1,057		)	(14,018		)
Other, net	6,312			4,460			(99		)
Income tax expense (benefit)	$	(549,996	)	$	(35,906	)	$	4,218

⁽¹⁾  Includes federal tax expense and state tax expense (net of federal tax benefit) of $23,454 and $2,112, respectively.

⁽²⁾  Amount for the year ended December 31, 2011 includes state tax benefits and interest expense of $1,012 and $45, respectively. Amount for the year ended December 31, 2010 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 Health Care and Education 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.

129

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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.

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,
	2012			2011
Deferred tax assets
Asset retirement obligations	$	316,440		$	349,677
Other liabilities	133,943			218,033
Pension and postretirement medical obligations	457,072			462,801
Alternative minimum tax credit carryforwards	215,308			216,815
Goodwill	34,791			7,837
Workers’ compensation obligations	109,399			120,221
Acquired intangibles, net	48,759			91,753
Other	15,955			13,671
Net operating loss carryforwards	563,699			499,553
Gross deferred tax assets	1,895,366			1,980,361
Less valuation allowance	(105,847		)	(64,523		)
Total net deferred tax assets	1,789,519			1,915,838
Deferred tax liabilities
Property, equipment and mineral reserves	(2,535,035		)	(3,146,298		)
Other assets	(86,010		)	(115,148		)
Debt discount	(21,783		)	(32,430		)
Total deferred tax liabilities	(2,642,828		)	(3,293,876		)
Net deferred tax liability	$	(853,309	)	$	(1,378,038	)

The breakdown of the net deferred tax liability as recorded in the accompanying Consolidated Balance Sheets is as follows:

	December 31,
	2012			2011
Current asset	$	117,692		$	129,885
Noncurrent liability	(971,001		)	(1,507,923		)
Total net deferred tax liability	$	(853,309	)	$	(1,378,038	)

Changes in the valuation allowance during the years ended December 31, 2012 and 2011 were as follows:

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	December 31,
	2012		2011
Valuation allowance beginning of period	$	64,523	$	10,975
Increase in valuation allowance not affecting income tax expense	567		48,196
Increase in valuation allowance recorded as an increase to income tax expense-continuing operations	40,757		5,352
Valuation allowance end of period	$	105,847	$	64,523

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. The Federal impact of the valuation allowance attributable to state net operating loss carryforwards is shown as a component of the net operating loss carryforward deferred tax asset. If the entire valuation allowance recorded at December 31, 2012 was reversed, an income tax benefit of $86,392 would be recognized.

At December 31, 2012, the Company has regular tax net operating loss carryforwards for Federal income tax purposes of $1.4 billion which are available to offset regular Federal taxable income. The net operating losses generated will not start to expire until 2023. The Company has gross net operating loss carryforwards for state income taxes of $1.6 billion which are available to offset future state taxable income generally through 2032. A valuation allowance has been provided for $827,263 of the state net operating losses. The Company also has alternative minimum tax credit carryforwards of approximately $215,308, 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 that would affect the Company’s effective tax rate if recognized is $28,741 as of December 31, 2012. The Company believes that it is unlikely that total unrecognized benefits recorded as of December 31, 2012 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, 2012, the Company has recorded accrued interest expense of $295.

The following reconciliation illustrates the Company’s liability for uncertain tax positions:

	December 31,
	2012		2011			2010
Unrecognized tax benefits — beginning of period	$	28,741	$	25,442		$	39,944
Gross adjustments — Massey Acquisition	—		2,721			—
Gross increases — tax positions in prior periods	—		1,590			—
Gross decreases — settlements with taxing authorities	—		—			(12,114		)
Reduction as a result of a lapse of the applicable statute of limitations	—		(1,012		)	(2,388		)
Unrecognized tax benefits - end of period	$	28,741	$	28,741		$	25,442

Tax years 2009-2012 remain open to federal and state examination. The Internal Revenue Service initiated a corporate income tax audit during the second quarter of 2011 for the Company’s 2008 and 2009 tax years and during the second quarter of 2012 for the Company's 2010 tax year. The 2008 audit was settled during the third quarter of 2012 with no material effect on the Consolidated Financial Statements.

(18) 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 March 2010, the Patient Protection and Affordable Care Act (“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

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 multiple changes having taken effect by 2012, and with additional changes extending over the next several years through 2018 and beyond. Plan standard changes that could affect the Company in the short term include minimum essential coverage requirements, restrictions on the plan cost contribution level an employer may require of its employees, the establishment of state and federal exchanges designed to compete with private insurers, a mandate that all individuals purchase health insurance (or pay a penalty), and a requirement that all employers with at least 50 full-time employees provide health insurance to their respective workforces (or pay a penalty). 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.

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. The Company has accrued approximately $40,000 as of December 31, 2012 for the estimated impact of the PPACA, which is included in pension and postretirement medical benefit obligations on the accompanying Consolidated Balance Sheets. 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 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 plans are contributory while others are noncontributory. Additionally, certain plans are established by collective bargaining agreements.

The Company assumed defined benefit health care plans as a result of the Massey Acquisition that provide postretirement medical benefits to eligible union and non-union employees. To be eligible, retirees must meet certain age and service requirements. Depending on year of retirement, benefits may be subject to annual deductibles, coinsurance requirements, lifetime limits and retiree contributions. These plans are unfunded. Beginning January 1, 2013, the majority of the Company's union retirees were enrolled in an Employer Group Waiver Plan (“EGWP”), and the majority of the Company's non-union retirees were moved to a health reimbursement account (“HRA”) arrangement. The Company will provide a fixed annual notional credit through the HRA to most post-65 retirees under this arrangement, which retirees may use to purchase insurance through a Medicare exchange.

The components of the change in accumulated benefit obligations of the plans for postretirement medical benefits were as follows:

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	December 31,
	2012			2011
Change in benefit obligations:
Accumulated benefit obligation-beginning period:	$	1,079,368		$	706,335
Assumption of obligations due to Massey Acquisition	—			187,025
Service cost	16,408			12,728
Interest cost	42,122			43,212
Actuarial (gain) loss	(47,753		)	142,936
Benefits paid	(39,117		)	(31,175		)
Less: Federal subsidy on benefits paid	—			1,870
Change in plan provisions	(44,835		)	16,437
Accumulated benefit obligation-end of period	$	1,006,193		$	1,079,368
Change in fair value of plan assets:
Employer contributions	$	39,117		$	31,175
Benefits paid	(39,117		)	(31,175		)
Fair value of plan assets at December 31	—			—
Funded status	$	(1,006,193	)	$	(1,079,368	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	(42,250	)	$	(38,171	)
Long-term liabilities	(963,943		)	(1,041,197		)
	$	(1,006,193	)	$	(1,079,368	)
Amounts recognized in accumulated other comprehensive (income) loss:
Prior service cost (credit)	$	(28,340	)	$	15,854
Net actuarial loss	151,929			204,338
	$	123,589		$	220,192

The following table details the components of the net periodic benefit cost for postretirement medical benefits:

	Years Ended December 31,
	2012			2011			2010
Service cost	$	16,408		$	12,728		$	10,933
Interest cost	42,122			43,212			35,860
Amortization of net actuarial loss	4,656			2,302			1,010
Amortization of prior service cost (credit)	(641		)	(609		)	1,114
Net periodic benefit cost	$	62,545		$	57,633		$	48,917

Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss are as follows:

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Years Ended December 31,
	2012			2011			2010
Current year actuarial (gain) loss	$	(47,753	)	$	142,936		$	82,752
Prior service cost (credit) for period	(44,835		)	16,437			(10,899		)
Amortization of net actuarial loss	(4,656		)	(2,302		)	(1,010		)
Amortization of prior service (cost) credit	641			609			(1,114		)
Total recognized in other comprehensive (income) loss	$	(96,603	)	$	157,680		$	69,729
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$	(34,058	)	$	215,313		$	118,646

The estimated amount that will be amortized from Accumulated other comprehensive (income) loss into net period benefit cost in 2013 is as follows:

Actuarial loss	$	4,147
Prior service cost	(3,819		)
	$	328

The weighted-average assumptions used to determine the postretirement plans’ benefit obligation as of December 31, 2012 and 2011 were as follows:

	December 31,
	2012		2011
Discount rate	3.89	%	4.41	%

The discount rates used in determining net periodic postretirement medical benefit cost for the years ended December 31, 2012, 2011, and 2010 were as follows:

	Years Ended December 31,
	2012	2011	2010
Discount rate	3.74%-4.41%	4.37%-5.28%	4.59% - 5.88%

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	2018

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, 2012:

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	One Percentage Point Increase		One Percentage Point Decrease
Effect on total service and interest cost components	$	7,803	$	(5,933	)
Effect on accumulated postretirement benefit obligation	$	137,535	$	(114,782	)

Employee contributions are not expected to be made and the Company’s plans are unfunded. The Company expects to contribute approximately $42,250 to its postretirement medical and life insurance plans in 2013.

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:

	Postretirement Medical and Life Insurance Benefits
2013	$	42,250
2014	45,152
2015	47,990
2016	51,071
2017	53,683
2018-2022	283,750
	$	523,896

(b) Company Administered Defined Benefit Pension Plans

In conjunction with the Massey Acquisition, the Company assumed a qualified non-contributory defined benefit pension plan, which covered substantially all administrative and non-union employees of Massey. Based on a participant’s entrance date to the plan, the participant may have accrued benefits based on one of four benefit formulas. Benefits were frozen under this plan effective December 31, 2011.

In addition to the qualified defined benefit pension plan noted above, the Company assumed a nonqualified supplemental benefit pension plan for certain salaried employees. Participants in this nonqualified supplemental benefit pension plan accrued benefits under the same formula as the qualified defined benefit pension plan, however, where the benefit is capped by the Internal Revenue Service (“IRS”) limitations, this nonqualified supplemental benefit pension plan compensates for benefits in excess of the IRS limit. Benefits were frozen under this plan effective December 31, 2011. This supplemental benefit pension plan is unfunded.

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. Benefits under these plans were frozen as of December 31, 2010.

The qualified non-contributory defined benefit pension plans assumed in the Massey Acquisition and in the Foundation Merger are collectively referred to as the “Pension Plans”. The non-qualified supplement benefit pension plan assumed in the Massey Acquisition and the non-qualified Supplement Executive Retirement Plan are collectively referred to as the “SERPs”.

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, private equity funds and a guaranteed insurance contract.

The following tables set forth the plans’ accumulated benefit obligations, fair value of plan assets and funded status:

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	December 31,
	2012			2011
Change in benefit obligation:
Accumulated benefit obligation at beginning of period	$	716,289		$	252,930
Assumption of obligations due to Massey Acquisition	—			391,614
Service cost	—			8,380
Interest cost	31,990			24,465
Actuarial loss	97,854			77,192
Benefits paid	(20,398		)	(15,803		)
Settlements	(33,352		)	(16,331		)
Curtailment	—			(6,158		)
Accumulated benefit obligation at end of period	$	792,383		$	716,289
Change in fair value of plan assets:
Fair value of plan assets at beginning of period	$	541,555		$	211,645
Assumption of plan assets due to the Massey Acquisition	—			283,984
Actual return on plan assets	69,610			7,686
Employer contributions	3,736			70,374
Benefits paid	(20,398		)	(15,803		)
Settlements	(33,352		)	(16,331		)
Fair value of plan assets at end of period	561,151			541,555
Funded status	(231,232		)	(174,734		)
Accrued benefit cost at end of year	$	(231,232	)	$	(174,734	)

Gross amounts recognized in accumulated other comprehensive (income) loss were as follows:

	Years Ended December 31,
	2012		2011
Net actuarial loss	$	140,660	$	76,662

The following table details the components of net periodic benefit cost:

	Years Ended December 31,
	2012			2011			2010
Service cost	$	—		$	8,380		$	7,453
Interest cost	31,990			24,465			13,634
Expected return on plan assets	(38,798		)	(29,984		)	(13,396		)
Amortization of net actuarial (gain) loss	1,837			(97		)	232
Curtailment loss (gain)	—			—			(5,051		)
Settlement loss (gain)	1,207			(2,431		)	—
Total	$	(3,764	)	$	333		$	2,872

Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss are as follows:

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Years Ended December 31,
	2012			2011		2010
Current year actuarial (gain) loss	$	67,042		$	93,332	$	(18,876	)
Amortization of net actuarial (loss) gain	(1,837		)	97		4,819
Settlement gain (loss)	(1,207		)	2,431		—
Total recognized in other comprehensive (income) loss	$	63,998		$	95,860	$	(14,057	)
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$	60,234		$	96,193	$	(11,185	)

The estimated amount that will be amortized from Accumulated other comprehensive (income) loss into net period benefit cost in 2013 is as follows:

Actuarial loss $ 1,968

The following table presents information applicable to plans with accumulated benefit obligations in excess of plan assets:

	December 31,
	2012		2011
Projected benefit obligation	$	792,383	$	716,289
Accumulated benefit obligation	$	792,383	$	716,289
Fair value of plan assets	$	561,151	$	541,555

The current portion of the Company’s pension 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 is recognized. Accordingly, there was no current pension liability reflected in the Consolidated Balance Sheets as of December 31, 2012 and 2011.

The weighted-average actuarial assumptions used in determining the benefit obligations as of December 31, 2012 and 2011 were as follows:

	December 31,
	2012	2011
Discount rate	3.68%-4.03%	4.24%-4.57%

The weighted-average actuarial assumptions used to determine net periodic benefit cost for the years ended December 31, 2012 and 2011 were as follows:

	December 31,
	2012	2011	2010
Discount rate	3.74% - 4.57%	4.32% - 5.51%	5.39%
Rate of increase in future compensation (a)	N/A	3.00%	5.00%
Expected long-term return on plan assets	7.25%	7.75%	7.92%
Measurement date	December 31, 2012	December 31, 2011	December 31, 2010

^(a) These Pension Plans are frozen.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 assets of the Pension Plans 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 2013, the Company will utilize an expected long-term return on plan assets of 6.75%.

Assets of the Pension Plans are held in trusts and are invested in accordance with investment guidelines that have been established by the Company’s Benefits Committee in consultation with the outside investment advisors. The target allocation for 2013 and the actual asset allocation as reported at December 31, 2012 is as follows:

	Target Allocation Percentages 2013		Percentage of Plan Assets 2012
Equity funds	45.0	%	43.1	%
Fixed income funds	55.0	%	54.2	%
Private equity funds/guaranteed insurance contract	—	%	2.7	%
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, 2012, 2011 and 2010, $3,736, $70,374 and $43,478, respectively, of cash contributions were made to the Pension Plans and SERP. The Company expects to contribute up to $20,000 to the Pension Plans in 2013.

The following represents expected future pension benefit and SERP payments for the next ten years:

	Pension Benefits
2013	$	31,255
2014	34,670
2015	34,774
2016	35,768
2017	37,089
2018-2022	193,072
	$	366,628

The fair values of the Company’s Pension Plans’ assets as of December 31, 2012, by asset category are as follows:

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

			Quoted Market Prices in Active Market for Identical Assets		Significant Observable Inputs		Significant Unobservable Inputs
Asset Category	Total		(Level 1)		(Level 2)		(Level 3)
Equity securities:
Multi-asset fund (a)	$	240,879	$	—	$	240,879	$	—
Fixed income securities:
Bond fund (b)	303,348		—		303,348		—
Other types of investments:
Private equity funds (c)	5,608		—		—		5,608
Guaranteed insurance contract	9,600		—		—		9,600
Total	$	559,435	$	—	$	544,227	$	15,208
Receivable (d)	1,716
Total	$	561,151

^(a)  This fund contains equities (domestic and international), real estate, and bonds.

^(b)  This fund contains bonds representing a diversity of sectors and maturities. This fund also includes mortgage-backed securities and U.S. Treasuries.

^(c)  This category includes several private equity funds that invest primarily in U.S. and European markets.

^(d)  Receivable for investments sold at December 31, 2012, which approximates fair value.

The fair values of the Company’s Pension Plans’ assets as of December 31, 2011, by asset category are as follows:

			Quoted Market Prices in Active Market for Identical Assets		Significant Observable Inputs		Significant Unobservable Inputs
Asset Category	Total		(Level 1)		(Level 2)		(Level 3)
Cash equivalents:
Short-term investment fund	$	407	$	—	$	407	$	—
Equity securities:
U.S. large-cap structured fund	84,064		—		84,064		—
U.S. small-cap fund	10,426		—		10,426		—
U.S. growth fund	20,794		—		20,794		—
U.S. value fund	20,947		—		20,947		—
International fund	72,825		—		72,825		—
Emerging markets fund	25,771		—		25,771		—
Fixed income securities:
Bond fund (a)	290,610		—		290,610		—
Other types of investments:
Private equity funds (b)	5,070		—		—		5,070
Guaranteed insurance contract	9,444		—		—		9,444
Total	$	540,358	$	—	$	525,844	$	14,514
Receivable (c)	1,197
Total	$	541,555

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

^(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)  Receivable for investments sold at December 31, 2011, which approximates fair value.

Changes in level 3 plan assets for the year ended December 31, 2012 were as follows:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Private Equity Funds			Guaranteed Insurance Contract		Total
Beginning balance, December 31, 2011	$	5,070		$	9,444	$	14,514
Actual return on plan assets:
Relating to assets still held at the reporting date	467			—		467
Relating to assets sold during the period	139			—		139
Purchases, sales, and settlements	(68		)	156		88
Ending balance, December 31, 2012	$	5,608		$	9,600	$	15,208

Changes in level 3 plan assets for the year ended December 31, 2011 were as follows:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Real Estate Equity Fund			Private Equity Funds			Diversified Alternative Fund			Guaranteed Insurance Contract		Total
Beginning balance, December 31, 2010	$	5,268		$	4,879		$	148		$	—	$	10,295
Assumption of plan assets due to Massey Acquisition	—			—			—			9,444		9,444
Actual return on plan assets:
Relating to assets still held at the reporting date	—			255			—			—		255
Relating to assets sold during the period	651			291			(3		)	—		939
Purchases, sales, and settlements	(5,919		)	(355		)	(145		)	—		(6,419		)
Ending balance, December 31, 2011	$	—		$	5,070		$	—		$	9,444	$	14,514

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.

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.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

(c)    Multi-Employer Pension Plans

Certain of the Company’s subsidiaries are subject to collective bargaining agreements with expiration dates ranging from December 31, 2016 to June 30, 2017 that require them to participate in a UMWA pension plan (the “1974 Plan”). The plan is a multi-employer pension plan administered by a Board of Trustees appointed by the UMWA and the Bituminous Coal Operators' Association, and the Company is required to make contributions to the plan at rates defined by the various contracts. The 1974 Plan’s legal name is United Mine Workers of America 1974 Pension Plan and the Employer Identification Number is 52-1050282. The 1974 Plan is considered to be in Seriously Endangered Status for the plan year beginning July 1, 2012, because the actuary determined that the 1974 Plan’s funded percentage is less than 80%, and the 1974 Plan is projected to have an accumulated funding deficiency within six plan years after the plan year beginning July 1, 2012. Even though the 1974 Plan is projected to have an accumulated funding deficiency within six plan years after the plan year beginning July 1, 2012, it is expected to have sufficient assets to pay benefits and expenditures during this time. In 2012, a funding improvement plan was sent to all participating companies for adoption. The goals of the funding improvement plan are to improve the funded status and to avoid an accumulated funding deficiency for all plan years in the funding improvement period. The funding improvement plan provides increased contribution rates beginning in 2017. The Plan's funded status is reviewed annually by the certifying actuary. For the years ended December 31, 2012, 2011, and 2010, the Company incurred expenses related to the 1974 Plan of $23,102, $15,140, and $19,915. The contributions to the 1974 Plan made by two of our wholly-owned subsidiaries, Cumberland Coal Resources, LP and Emerald Coal Resources, LP, represent more than 5% of the total contributions to the 1974 Plan.

In connection with the Massey Acquisition and the Foundation Merger, the Company assumed 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 years ended December 31, 2012, 2011, and 2010 was $1,540, $1,026 and $865, 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 $10,018 as of December 31, 2012.

(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. In addition, as a result of the Massey Acquisition and the Foundation Merger, the Company assumed obligations related to providing workers’ compensation and black lung benefits to certain employees. The Company’s subsidiaries are insured for worker’s compensation and black lung obligations by a third-party insurance provider with the exception of certain subsidiaries where we are a qualified self-insurer for workers’ compensation and/or black lung related obligations; and with the exception of Wyoming where the Company participates in a compulsory state-run fund for workers’ compensation. Certain of the Company’s subsidiaries are self-insured for black lung benefits and fund benefit payments through a Section 501(c)(21) tax-exempt trust 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, 2012, 2011, and 2010 was $46,346, $25,766, and $16,901, respectively.

For the Company’s subsidiaries that are self-insured for workers’ compensation claims, the liability at December 31, 2012 and 2011 was $179,983 and $187,606, respectively, including a current portion of $26,700 and $21,681, respectively. Self-insured workers’ compensation expense for the years ended December 31, 2012, 2011, and 2010 was ($1,525), $25,460, and $15,573, respectively.  Certain of the Company’s subsidiaries’ self-insured workers’ compensation obligations are secured by letters of credit in the amount of $72,215 and surety bonds in the amount of $11,463.  In addition, certain of the Company’s subsidiaries’ self-insured workers’ compensation obligations are secured by $8,867 of deposits.

141

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The following tables set forth the accumulated black lung benefit obligations, fair value of plan assets and funded status for the years ended December 31, 2012 and 2011:

	December 31,
	2012			2011
Change in benefit obligation:
Accumulated benefit obligation at beginning of period	$	160,595		$	46,137
Assumption of obligation due to Massey Acquisition	—			93,875
Service cost	8,114			4,171
Interest cost	5,612			5,143
Actuarial (gain) loss	(19,228		)	15,194
Benefits paid	(9,822		)	(3,925		)
Accumulated benefit obligation at end of period	$	145,271		$	160,595
Change in fair value of plan assets:
Fair value of plan assets at beginning of period	$	3,089		$	1,116
Actual return on plan assets	(23		)	(8		)
Benefits paid	(9,822		)	(3,925		)
Employer contributions	10,187			5,906
Fair value of plan assets at end of period (1)	3,431			3,089
Funded status	(141,840		)	(157,506		)
Accrued benefit cost at end of year	$	(141,840	)	$	(157,506	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	5,961		$	5,378
Long-term liabilities	135,879			152,128
	$	141,840		$	157,506

⁽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 (income) loss consisted of the following as of December 31, 2012 and 2011:

	December 31,
	2012		2011
Net actuarial loss	$	7,614	$	26,768

The following table details the components of the net periodic benefit cost for black lung obligations:

142

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Years Ended December 31,
	2012			2011			2010
Service cost	$	8,114		$	4,171		$	1,412
Interest cost	5,612			5,143			2,235
Expected return on plan assets	(52		)	(37		)	(69		)
Amortization of net actuarial loss	—			918			405
Net periodic expense	$	13,674		$	10,195		$	3,983

Other changes in the black lung plan assets and benefit obligations recognized in other comprehensive (income) loss are as follows:

	Years Ended December 31,
	2012			2011			2010
Current year actuarial (gain) loss	$	(19,154	)	$	15,238		$	11,729
Amortization of net actuarial loss	—			(918		)	(405		)
Total recognized in other comprehensive (income) loss	$	(19,154	)	$	14,320		$	11,324
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$	(5,480	)	$	24,516		$	15,307

The weighted-average assumptions related to black lung obligations used to determine the benefit obligation as of December 31, 2012 and 2011 were as follows:

	2012		2011
Discount rate	3.84	%	4.40%
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:

	Years Ended December 31,
	2012	2011	2010
Discount rate	3.96% - 4.40%	4.39% - 5.23%	4.01% - 5.73%
Rate of increase in future compensation	3.00%	3.00%	3.00%
Expected long-term return on plan assets	3.00%	3.00%	3.00%

Estimated future cash payments related to black lung obligations for the fiscal years ending after December 31, 2012 are as follows:

143

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Year ending December 31:
2013	$	5,961
2014	6,170
2015	6,438
2016	6,761
2017	7,112
2018-2022	40,658
	$	73,100

(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, 2012, 2011, and 2010 were $70,004, $46,866, and $20,205, 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, 2012, 2011, and 2010, the Company incurred total claims expense of $219,707, $145,517, and $92,058, respectively, which represents claims processed and an estimate for claims incurred but not reported.

(19) Stock-Based Compensation Awards

On May 17, 2012, the Company's stockholders approved the 2012 Long-Term Incentive Plan (the “2012 LTIP”). The principal purpose of the 2012 LTIP is to advance the interests of the Company and its stockholders by providing incentives to certain eligible persons who contribute significantly to the strategic and long-term performance objectives and growth of the Company. The 2012 LTIP is currently authorized for the issuance of awards of up to 6,400,000 shares of common stock, and as of December 31, 2012, 5,283,123 shares of common stock were available for grant under the plan. The 2012 LTIP provides for a variety of awards, including options, stock appreciation rights, restricted stock, restricted share units (both time-based and performance-based), and any other type of award deemed by the Compensation Committee in its discretion to be consistent with the purpose of the 2012 LTIP. Prior to the approval of the 2012 LTIP, the Company issued awards under the 2010 Long Term Incentive Plan (the “2010 LTIP”) and the Alpha Appalachia 2006 Stock and Incentive Compensation Plan (the “2006 SICP”). Upon approval of the 2012 LTIP, no additional awards were issued or are able to be issued under the 2010 LTIP or the 2006 SICP. The 2012 LTIP, the 2010 LTIP and the 2006 SICP are collectively referred to as the “Stock Plans.” 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 2012 LTIP, the 2010 LTIP, the 2006 SICP, the 2005 LTIP, and the 2004 SIP, respective of which plan the awards were granted.

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 years ended December 31, 2012, 2011, and 2010, the Company repurchased 441,923, 221,553, and 367,860 common shares, respectively, from employees at an average price paid per share of $16.99, $55.32, and $45.30, respectively. 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.

144

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

At December 31, 2012, the Company had two types of stock-based awards outstanding: restricted share units (both time-based and performance-based) and stock options. Stock-based compensation expense from continuing operations totaled $9,881, $53,685, and $33,255, for the years ended December 31, 2012, 2011, and 2010, respectively. For the years ended December 31, 2012, 2011, and 2010, approximately 51%, 72%, and 75%, respectively, of stock-based compensation expense from continuing operations is reported as selling, general and administrative expenses and approximately 49%, 28%, and 25%, 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 December 31, 2012, 2011, and 2010 was $0, $0, and $5,505, 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). Restricted stock awards granted to the Company’s directors 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 year ended December 31, 2009, the Company granted restricted stock awards to its executive officers, directors and key employees in the amount of 921,901, of which none remain outstanding at December 31, 2012. No awards were granted for the years ended December 31, 2012, 2011 and 2010.

Restricted stock award activity for the year ended December 31, 2012 is summarized in the following table:

	Number of  Shares		Weighted- Average  Grant Date  Fair Value
Non-vested shares outstanding at December 31, 2011	544,759		$	18.82
Vested	(544,759	)	$	18.82
Non-vested shares outstanding at December 31, 2012	—		$	—

The fair value of restricted stock awards that vested for the years ended December 31, 2012, 2011, and 2010 was $11,142, $13,987, and $20,062, respectively. As of December 31, 2012, there was no unrecognized compensation cost related to non-vested restricted stock awards to be recognized.

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, 2012, the Company granted time-based share units under the 2012 LTIP to certain executive officers, directors and key employees in the amount of 1,016,733 all of which remained outstanding at December 31, 2012.

During the year ended December 31, 2012, the Company granted time-based share units under the 2006 SICP to certain executive officers, directors and key employees in the amount of 146,044, of which 136,537 remained outstanding at December 31, 2012.

145

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

During the years ended December 31, 2012, 2011 and 2010, the Company granted time-based share units under the 2010 LTIP to certain executive officers, directors and key employees in the amount of 706,564, 357,455 and 1,515, respectively, of which 708,282 remained outstanding at December 31, 2012.

During the year ended December 31, 2010, 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, of which 122,663 remained outstanding at December 31, 2012.

During the years ended December 31, 2010, 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, of which 45,469 remained outstanding at December 31, 2012.

Time-based share unit activity for the year ended December 31, 2012 is summarized in the following table:

	Number of  Shares		Weighted- Average  Grant Date  Fair Value
Non-vested shares outstanding at December 31, 2011	1,209,832		$	44.01
Granted	1,869,341		$	11.60
Vested	(942,108	)	$	34.69
Forfeited/Expired	(79,126	)	$	32.12
Non-vested shares outstanding at December 31, 2012	2,057,939		$	19.30

The fair value of time-based share unit awards that vested in the years ended December 31, 2012, 2011, and 2010 was $13,775, $10,218, and $7,754, respectively. As of December 31, 2012, there was $16,604 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 2.99 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. 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 stock 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 2012, the Company awarded 1,149,392 performance-based share units, of which 1,092,119 remain outstanding as of December 31, 2012. At December 31, 2012, the Company had assessed the total shareholder return target as probable of achievement. As of December 31, 2012, there was $8,861 of unamortized compensation cost related to the 2012 performance-based share units which is expected to be recognized as expense over a weighted-average period of 2.11 years.

During 2011, the Company awarded 227,199 performance-based share units, of which 216,758 remain outstanding as of December 31, 2012. At December 31, 2012, there was no unamortized compensation cost related to the 2011 performance-based share units expected to be recognized as expense due to the Company's assessment of probability of achievement of performance targets.

During 2010, the Company awarded 265,636 performance-based share units, of which 253,714 remain outstanding as of December 31, 2012. At December 31, 2012, there was no unamortized compensation cost related to the 2010 performance-

146

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

based share units expected to be recognized as expense due to the Company's assessment of probability of achievement of performance targets.

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 was to be recognized over the remaining vesting periods. For the years ended December 31, 2011 and 2010, approximately $2,487 and $1,525, respectively, of the additional compensation expense was recognized.

Performance-based share unit activity for the year ended December 31, 2012 is summarized in the following table:

	Number of  Shares		Weighted- Average  Grant Date  Fair Value
Non-vested shares outstanding at December 31, 2011	1,626,734		$	46.56
Granted	2,298,784		$	15.70
Earned	(311,662	)	$	37.14
Forfeited or expired	(488,674	)	$	23.55
Non-vested shares outstanding at December 31, 2012	3,125,182		$	28.40

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 2009 and vested on February 22, 2012 was $4,937. The fair value of performance-based share unit awards granted in 2008 and vested on February 22, 2011 was $11,293. 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 June 1, 2011, in connection with the Massey Acquisition, the Company issued 912,509 fully vested stock options to Massey employees to replace outstanding Massey options with an estimated fair market value of $29,217, of which $5,717 was expensed immediately and the remainder was treated as part of the purchase consideration for the Massey Acquisition. The Company estimated the fair market value using a trinomial lattice model with assumptions for volatility, expected remaining life of options, expected dividend yield and a risk-free rate of interest. As of December 31, 2012, 676,024 of the options were outstanding and exercisable.

The fair value of the Massey options assumed on June 1, 2011 was estimated using the Black-Scholes option-pricing model using the following assumptions:

• Price of the underlying stock:

• Closing stock price for Massey on June 1, 2011 — $65.14

• Closing stock price for Alpha on June 1, 2011 — $53.40

• Option exercise price:

• Pre-conversion option exercise prices — Ranging from $13.49 to $56.60

• Post-conversion option exercise prices — Ranging from $11.15 to $46.78 (Adjusted for the Massey Acquisition ratio of 1.21)

• Expected life in years — 8.50 years

• Risk-free interest rate — 2.60%

• Dividend yield — 0%

• Expected volatility — 47.66%

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 Massey options assumed on June 1, 2011 was $26.00.

147

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Stock option activity for the year ended December 31, 2012 is summarized in the following table:

	Number of Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (Years)
Outstanding at December 31, 2011	1,149,266		$	21.92
Exercised	(16,133	)	$	11.01
Forfeited/Expired	(123,032	)	$	25.23
Outstanding at December 31, 2012	1,010,101		$	21.71	4.37
Exercisable at December 31, 2012	1,010,101		$	21.71	4.37

As of December 31, 2012, the options outstanding and exercisable had an aggregate intrinsic value of $388. Cash received from the exercise of stock options during the years ended December 31, 2012, 2011, and 2010 was $176, $4,320, and $5,521, respectively. As of December 31, 2012, 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, 2012, 2011, and 2010 was $253, $12,952, and $17,449, 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, 2012 follows:

	Options Outstanding and Exercisable
Exercise Price	Shares	Weighted- Average Remaining Life (yrs)	Weighted- Average Exercise Price
$ 4.31-$7.87	171,580	1.60	$	7.47
$ 11.15-$20.44	404,123	4.00	$	16.78
$ 23.93-$34.76	301,269	4.90	$	27.91
$ 40.82-$48.26	133,129	7.89	$	41.03
	1,010,101	4.37	$	21.71

(20) Related Party Transactions

For the years ended December 31, 2012, 2011, and 2010, there were no material related party transactions.

(21) 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 could be material.

(b) Commitments and Contingencies

Commitments

148

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The Company leases coal mining and other equipment under long-term capital and operating leases with varying terms. In addition, the Company leases mineral interests and surface rights from land owners under various terms and royalty rates.

As of December 31, 2012, aggregate future minimum non-cancelable lease payments under operating leases and minimum royalties under coal leases were as follows:

	Operating  Leases		Coal  Royalties
Year Ending December 31:
2013	$	56,952	$	80,868
2014	37,331		74,181
2015	7,278		70,356
2016	654		22,754
2017	130		22,184
Thereafter	—		62,318
Total	$	102,345	$	332,661

For the years ended December 31, 2012, 2011, and 2010, net rent expense from continuing operations under operating leases was $81,021, $73,092, and $18,659, respectively, and coal royalty expense from continuing operations was $336,068, $322,890, and $192,834, respectively.

The following is a schedule by years of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2012:

	Capital Leases
Year Ending December 31:
2013	$	18,899
2014	18,572
2015	12,722
2016	8,060
2017	6,424
Thereafter	54,296
Total minimum lease payments	$	118,973
Less: Amount representing interest (rates range from 2.13% to 13.86%)	(51,997		)
Present value of net minimum lease payments	$	66,976

Other Commitments

As of December 31, 2012, the Company had commitments to purchase 0.9 million tons of coal at a cost of approximately $79,193 during 2013 and 2014.

In September 2011, the Company entered into a federal coal lease, which contained an estimated 130,200,000 tons of proven and probable coal reserves in the Powder River Basin. The lease bid was $143,415, payable in five equal annual installments of $28,683. The first installment was paid in September 2011. In August 2012, the Company entered into an agreement with a third party to exchange this federal coal lease for a federal coal lease from a third party, which contains an estimated 222,000,000 tons of proven and probable coal reserves in the Powder River Basin adjacent to the Company's existing mining operations. As a result of the exchange the Company paid $17,392 at closing and has four annual remaining lease bid installments of $42,130 due each November until the obligation is satisfied in 2015. The Company paid the first annual installment of $42,130 in November 2012. Also as a result of the exchange, the Company recorded a note payable, which had a present value of $10,275 as of December 31, 2012, of which $3,946 is recorded as current portion of long-term debt and $6,329

149

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

is recorded as long-term debt in the Company's Consolidated Balance Sheet as of December 31, 2012. The note is payable in four annual installments of $3,946 due each November through 2015. The Company paid the first annual installment of $3,946 in November 2012.

Also, see Note 12 regarding the Company’s Other debt and Note 7 regarding equipment purchase commitments.

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, 2012 is $414,846.

Letters of Credit

The amount of outstanding bank letters of credit issued under the Company’s accounts receivable securitization program and its Revolving Facility as of December 31, 2012 is presented in Note 12.

(d) Legal Proceedings

The Company's legal proceedings range from cases brought by a single plaintiff to purported class actions. These legal proceedings, as well as governmental examinations, involve various business units and a variety of claims including, but not limited to, contract disputes, personal injury claims, property damage claims (including those resulting from blasting, trucking and flooding), environmental and safety issues, and employment matters. While some matters pending against the Company or its subsidiaries specify the damages claimed by the plaintiffs, many seek an unquantified amount of damages or are at very early stages of the legal process. Even when the amount of damages claimed against the Company or its subsidiaries is stated, (i) the claimed amount may be exaggerated or unsupported; (ii) the claim may be based on a novel legal theory or involve a large number of parties; (iii) there may be uncertainty as to the likelihood of a class being certified or the ultimate size of the class; (iv) there may be uncertainty as to the outcome of pending appeals or motions; and/or (v) there may be significant factual issues to be resolved. As a result, the Company may be unable to estimate a range of possible loss for matters that have not yet progressed sufficiently through discovery and development of important factual information and legal issues. Other matters have progressed sufficiently that the Company is able to estimate a range of possible loss. Accordingly, for those legal proceedings and governmental examinations disclosed below as to which a loss is reasonably possible in future periods and for which the Company is able to estimate a range of possible loss, the current estimated range is up to $500,000 in excess of the accrued liability (if any) related to those matters. This aggregate range represents the Company's estimate of additional possible loss in excess of the accrued liability (if any) with respect to these matters and net of third party indemnification arrangements (if any, other than insurance) as described below related to those matters, based on currently available information, including any damages claimed by the plaintiffs, and is subject to significant judgment and a variety of assumptions and inherent uncertainties. For example, at the time of making an estimate, the Company may have only preliminary, incomplete, or inaccurate information about the facts underlying a claim; its assumptions about the future rulings of the court or other tribunal on significant issues, or the behavior and incentives of adverse parties, regulators, indemnitors or co-defendants, may prove to be wrong; and the outcomes it is attempting to predict are often not amenable to the use of statistical or other quantitative analytical tools. In addition, from time to time an outcome may occur that the Company had not accounted for in its estimate because it had considered that outcome to be remote. Furthermore, as noted above, the aggregate range does not include any matters for which the Company is not able to estimate a range of possible loss. Accordingly, the estimated aggregate range of possible loss does not represent the Company's maximum loss exposure. The legal proceedings and governmental examinations underlying the estimated range will change from time to time, and actual results may vary significantly from the current

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(Dollars in thousands, except per share data)

estimate. The Company intends to defend these legal proceedings vigorously, litigating or settling cases where in the Company's judgment it would be in the best interest of shareholders to do so.

For purposes of FASB ASC Topic 450 (“ASC 450”), an event is “reasonably possible” if “the chance of the future event or events occurring is more than remote but less than likely” and an event is “remote” if “the chance of the future event or events occurring is slight.” ASC 450 requires accrual for a liability when it is (a) “probable that one or more future events will occur confirming the fact of loss” and (b) “the amount of loss can be reasonably estimated.” If a range of loss is estimated, the best estimate within the range is required to be accrued. If no amount within the range is a better estimate, the minimum amount of the range is required to be accrued.

The Company evaluates, on a quarterly basis, developments in legal proceedings and governmental examinations that could cause an increase or decrease in the amount of the reserves previously recorded. Excluding fees paid to external legal counsel, the Company recognized expense, net of expected insurance recoveries, associated with litigation-related reserves of $15,406, $2,100 and $1,100 during the years ended December 31, 2012, 2011 and 2010, respectively.

Federal Securities Class Actions

Upper Big Branch (“UBB”) Purported Securities Class Action

On April 29, 2010 and May 28, 2010, two purported class actions that were subsequently consolidated into one case were brought against, among others, Massey, now the Company's subsidiary Alpha Appalachia Holdings, Inc. (“Alpha Appalachia”), in the United States District Courtfor the Southern District of West Virginia in connection with alleged violations of the federal securities laws. The lead plaintiffs allege, purportedly on behalf of a class of former Massey stockholders, that (i) Massey and certain former Massey directors and officers violated Section 10(b) of the Securities and Exchange Act of 1934, as amended, (the “Exchange Act”), and Rule 10b-5 thereunder by intentionally misleading the market about the safety of Massey's operations and that (ii) Massey's former officers violated Section 20(a) of the Exchange Act by virtue of their control over persons alleged to have committed violations of Section 10(b) of the Exchange Act. The lead plaintiffs seek a determination that this action is a proper class action; certification as class representatives; an award of compensatory damages in an amount to be proven at trial, including interest thereon; and an award of reasonable costs and expenses, including counsel fees and expert fees.

On February 16, 2011, the lead plaintiffs moved to partially lift the statutory discovery stay imposed under the Private Securities Litigation Reform Act of 1995. On March 3, 2011, the United States moved to intervene and to stay discovery until the completion of criminal proceedings allegedly arising from the same facts that allegedly give rise to this action. On July 9, 2012, the Court entered an order maintaining the stay of discovery until the earlier of either the completion of the United States' criminal investigation of the UBB explosion or January 15, 2013. On January 17, 2013, the Court further extended the existing discovery stay until the earlier of April 15, 2013 or the conclusion of the United States' criminal investigation of the UBB explosion.

On April 25, 2011, the defendants moved to dismiss the operative complaint. On March 27, 2012, the court denied the defendants' motion to dismiss. On July 16, 2012, the Company filed its answer to the consolidated amended class action complaint.

Emerald Purported Securities Class Action

On July 13, 2012, a purported class action brought on behalf of a putative class of former Massey stockholders was filed in Boone County, West Virginia Circuit Court. The complaint asserts claims under the Securities Act of 1933, as amended, against the Company and certain of its officers and current and former directors, and generally asserts that the defendants made false statements about the Company's Emerald mine in its public filings associated with the Massey Acquisition. The plaintiff seeks, among other relief, an award of compensatory damages in an amount to be proven at trial.

On August 16, 2012, the defendants removed the case to the United States District Court for the Southern District of West Virginia. On August 30, 2012, the plaintiff filed a motion to remand the case back to the Circuit Court of Boone County, West Virginia. On September 13, 2012, the defendants filed an opposition to the plaintiff's motion to remand.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The defendants filed a motion to dismiss the action on October 19, 2012, and the plaintiff filed an opposition to that motion on November 2, 2012. On November 5, 2012, the federal court remanded the case back to the Boone County Circuit Court (without ruling on the pending motion to dismiss). The plaintiff filed an amended complaint in the Boone County Circuit Court on February 6, 2013. The parties have agreed that the defendants have 45 days from the date the plaintiff filed her amended complaint to answer, move to dismiss or otherwise respond to the amended complaint. The Boone County Circuit Court set a preliminary trial date of June 24, 2014.

UBB Explosion and Related Investigations and Litigation

On April 5, 2010, before the acquisition of Massey by the Company, an explosion occurred at the UBB mine, resulting in the deaths of 29 miners. The Federal Mine Safety and Health Administration (“MSHA”), the Office of Miner's Health, Safety, and Training of the State of West Virginia (“State”), and the Governor's Independent Investigation Panel (“GIIP”) initiated investigations into the cause of the UBB explosion and related issues. Additionally, the U.S. Attorney for the Southern District of West Virginia (the “Office”) commenced a grand jury investigation. The GIIP published its final report on May 19, 2011; MSHA released its final report on December 6, 2011; and the State released its final report on February 23, 2012.

On December 6, 2011, the Company, the Office and the United States Department of Justice entered into a Non-Prosecution Agreement (the “Agreement”) resolving the criminal investigation against Massey and its affiliates relating to the UBB explosion and other health and safety related issues at Massey, and the Company also reached a comprehensive settlement with MSHA resolving outstanding civil citations, violations, and orders related to MSHA's investigation arising from the UBB explosion and other non-UBB related matters involving legacy Massey entities prior to the Massey Acquisition. The Agreement does not resolve individual responsibilities related to the UBB explosion.

Under the terms of the Agreement and MSHA settlement, the Company has agreed to pay outstanding MSHA fines, and has agreed to invest in additional measures designed to improve miner health and safety, provide restitution to the families of the fallen miners and two individuals injured in the UBB explosion, and create a charitable organization to research mine safety. The Company has further agreed to cooperate fully with all governmental agencies in all continuing investigations and prosecutions against any individuals that arise out of the UBB explosion and related conduct described in the Agreement until such investigations and prosecutions are concluded.

The Company cannot predict the outcome of these investigations, including whether or not any individual will become subject to possible criminal and civil penalties or enforcement actions. In order to accommodate these investigations, the UBB mine had been idled since the explosion. On April 20, 2012, the Company was authorized by regulatory authorities to close the UBB mine permanently, and on June 19, 2012, the sealing of the mine was completed.

On June 28, 2012, sixteen individuals who claim to have been injured in the UBB explosion filed a petition in the United States District Court for the Southern District of West Virginia to amend or set aside the Agreement. On July 27, 2012, Alpha and Alpha Appalachia filed a motion to dismiss. The injury claims of those sixteen individuals were separately settled in August 2012, and on August 29, 2012, the court ordered that the action be dismissed and stricken from the docket.

On October 19, 2012, the administrators for the estates of three miners who died in the UBB explosion filed an action against Alpha and Alpha Appalachia in the United States District Court for the Southern District of West Virginia claiming they are entitled to “criminal restitution” under the Agreement. On November 27, 2012, the defendants filed their motion to dismiss the complaint. The plaintiffs were subsequently granted leave to amend their complaint, which they filed on January 23, 2013, rendering the defendants' previously filed motion to dismiss moot. The defendants filed their motion to dismiss the amended complaint on February 11, 2013.

Wrongful Death and Personal Injury Suits

Twenty of the twenty-nine families of the deceased miners filed wrongful death suits against Massey and certain of its subsidiaries in Boone County Circuit Court and Wyoming County Circuit Court. In addition, as of February 21, 2013, two seriously injured employees had filed personal injury claims against Massey and certain of its subsidiaries in Boone County Circuit Court seeking damages for physical injuries and/or alleged psychiatric injuries, and thirty-nine employees had filed lawsuits against Massey and certain of its subsidiaries in Boone County Circuit Court and Wyoming County Circuit Court alleging emotional distress or personal injuries due to their proximity to the explosion. On April 19, 2012, the Company filed a motion to transfer the Wyoming County lawsuits to Boone County.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

On October 19, 2011, the Boone County Circuit Court ordered that the cases pending before it be mediated by a panel of three mediators.  These mediations are, per order of the court, strictly confidential. The Company reached agreements to settle with all twenty-nine families of the deceased miners as well as the two employees who were seriously injured. The settlements reached with the families of the deceased miners have received court approval. The settlements relating to the two serious injuries did not require court approval.

On May 4, 2012, the Boone County Circuit Court ordered that the remaining personal injury and emotional distress claims continue to be mediated through July 6, 2012. Until that date, a stay was in place for all remaining cases until further order from the court. The stay was lifted on July 6, 2012 but mediation was ordered to continue. On July 20, 2012, the stay was reinstated for discovery-related activities at the request of the United States Attorney and by agreement of the parties. This stay is expected to remain in effect until the United States' criminal investigation of the UBB explosion is completed. Mediation efforts in August 2012 successfully resolved all but two of the personal injury and emotional distress claims. A motion to dismiss these two claims is pending before the Boone County Circuit Court. The Wyoming County lawsuits were settled and dismissed prior to the court ruling on the Company's motion to transfer.

On April 5, 2012, one of the families of the deceased miners filed a class action suit in Boone County Circuit Court, purportedly on behalf of the families that settled their claims prior to the mediation, alleging fraudulent inducement into a contract, naming as defendants Massey, the Company and certain of its subsidiaries, the Company's CEO and the Company's Board of Directors.

Uniform Fraudulent Transfers Act Action

On June 1, 2011, certain of the plaintiffs who had filed wrongful death cases filed a complaint against Massey, Massey Coal Services, Inc., Performance Coal Company, and certain individuals in the Circuit Court of Boone County, West Virginia, alleging that the Massey Acquisition represented a fraudulent transfer intended to prevent plaintiffs from recovering damages in their wrongful death actions. Plaintiffs request that the court order defendants to post a bond of at least $500,000. Each plaintiff in this action has agreed to settle their wrongful death cases, as discussed above, and as part of those settlements, has also agreed to dismiss this action. On May 14, 2012, the Court entered an order dismissing this case with prejudice.

Derivative and Related Class Action Litigation

UBB-Related Derivative Actions

A number of purported former Massey stockholders have brought lawsuits derivatively, purportedly on behalf of Massey, in West Virginia and Delaware state courts, in connection with the April 5, 2010 explosion at the UBB mine and in connection with claims allegedly arising out of the Massey Acquisition. Certain of these former stockholders have also initiated contempt proceedings in West Virginia state court in connection with alleged violations of the settlement of a previous derivative lawsuit. In addition, these and other purported former Massey stockholders have asserted class action claims allegedly arising out of the Massey Acquisition in Delaware and West Virginia state courts and Virginia federal court. These cases are summarized below.

Delaware Chancery Court Suit

In a case filed on April 23, 2010 in Delaware Chancery Court, In re Massey Energy Company Derivative and Class Action Litigation (“In re Massey”), a number of purported former Massey stockholders (the “Delaware Plaintiffs”) allege, purportedly on behalf of Massey, that certain former Massey directors and officers breached their fiduciary duties by failing to monitor and oversee Massey's employees, allegedly resulting in fines against Massey and the explosion at UBB, and by wasting corporate assets by paying allegedly excessive and inflated amounts to former Massey Chairman and Chief Executive Officer Don L. Blankenship as part of his retirement package. The Delaware Plaintiffs also allege, on behalf of a purported class of former Massey stockholders, that certain former Massey directors breached their fiduciary duties by agreeing to the Massey Acquisition. The Delaware Plaintiffs allege that defendants breached their fiduciary duties by failing to secure the best price possible, by failing to secure any downside protection for the acquisition consideration, and by purportedly eliminating the possibility of a superior proposal by agreeing to a “no shop” provision and a termination fee. In addition, the Delaware Plaintiffs allege that defendants agreed to the Massey Acquisition to eliminate the liability that defendants faced on the Delaware Plaintiffs' derivative claims. Finally, the Delaware Plaintiffs allege that defendants failed to fully disclose all material information necessary for Massey stockholders to cast an informed vote on the Massey Acquisition.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The Delaware Plaintiffs also name the Company and Mountain Merger Sub, Inc. (“Merger Sub”), the Company's wholly-owned subsidiary created for purposes of effecting the Massey Acquisition, which, at the effective time of the Massey Acquisition, was merged with and into Massey, as defendants. The Delaware Plaintiffs allege that the Company and Merger Sub aided and abetted the former Massey directors' alleged breaches of fiduciary duty and agreed to orchestrate the Massey Acquisition for the purpose of eliminating the former Massey directors' potential liability on the derivative claims. Two additional putative class actions were brought against Massey, certain former Massey directors and officers, the Company and Merger Sub in the Delaware Court of Chancery following the announcement of the Massey Acquisition, which were consolidated for all purposes with In re Massey on February 9, 2011 and February 24, 2011, respectively.

The Delaware Plaintiffs seek an award against each defendant for restitution and/or compensatory damages, plus pre-judgment interest; an order establishing a litigation trust to preserve the derivative claims asserted in the complaint; and an award of costs, disbursements and reasonable allowances for fees incurred in this action. The Delaware Plaintiffs also sought to enjoin consummation of the Massey Acquisition. The court denied their motion for a preliminary injunction on May 31, 2011.

On June 10, 2011, Massey moved to dismiss the Delaware Plaintiffs' derivative claims on the ground that the Delaware Plaintiffs, as former Massey stockholders, lacked the legal right to pursue those claims, and the Company and Alpha Appalachia Merger Sub moved to dismiss the purported class action claim against them for failure to state a claim upon which relief may be granted. On June 10 and 13, 2011, certain former Massey director and officer defendants moved to dismiss the derivative claims and filed answers to the remaining direct claims.

On September 14, 2011, the parties submitted a Stipulation Staying Proceedings, which stayed the matter until March 1, 2012, without prejudice to the parties' right to seek an extension or a termination of the stay by application to the court. The court approved the stipulation and entered the stay that same day. On January 31, 2012, the Company and Alpha Appalachia requested that the Delaware Plaintiffs consent to a six-month extension of the stay order (the “Stay Order”); the Delaware Plaintiffs refused to do so. On February 21, 2012, the Company and Alpha Appalachia filed a motion to extend the Stay Order. On June 15, 2012, the Court held a hearing on Defendants' motion to extend the Stay Order and granted the motion, extending the stay of proceedings until the earlier of either the completion of the United States' criminal investigation of the UBB explosion or January 15, 2013. On January 16, 2013, the Court further extended the Stay Order until the earlier of July 15, 2013 or the conclusion of the United States' criminal investigation of the UBB explosion.

West Virginia State Court Derivative Suit

In a case filed on April 15, 2010 in West Virginia state court, three purported former Massey stockholders (the “West Virginia Plaintiffs”) allege, purportedly on behalf of Massey, that certain former Massey directors and officers breached their fiduciary duties by failing to monitor and oversee Massey's employees, allegedly resulting in fines against Massey and the explosion at UBB. The West Virginia Plaintiffs seek an award against each defendant and in favor of Massey for the amount of damages sustained by Massey as a result of defendants' alleged breaches of fiduciary duty and an award to the West Virginia Plaintiffs of the costs and disbursements of the action, including reasonable attorneys' fees, accountants' and experts' fees, costs, and expenses.

On May 2, 2011, the West Virginia Plaintiffs moved for leave to amend their complaint to add Alpha and Merger Sub as additional defendants and to add claims allegedly arising out of the then-proposed Massey Acquisition. In their proposed amended complaint, the West Virginia Plaintiffs allege that certain former Massey directors breached their fiduciary duties by failing to obtain the highest price reasonably available for Massey and by failing to disclose material information to Massey's then-stockholders in connection with the stockholder vote on the Massey Acquisition. The West Virginia Plaintiffs also allege that Massey, Merger Sub and the Company aided and abetted the former Massey directors' breaches of fiduciary duty. The West Virginia Plaintiffs further allege that certain former Massey directors wasted corporate assets by failing to maintain sufficient internal controls over Massey's safety and environmental reporting; failing to properly consider the interests of Massey and its stockholders, including the value of the derivative claims asserted by the West Virginia Plaintiffs in the Massey Acquisition; failing to conduct proper supervision; paying undeserved incentive compensation to certain Massey executive directors, particularly former Massey Chairman and CEO Don L. Blankenship during Massey's alleged years of noncompliance with safety regulations and more recently as part of Blankenship's retirement package; incurring millions of dollars in fines due to safety and environmental violations; and incurring potentially hundreds of millions of dollars of legal liability and/or legal costs to defend defendants' allegedly unlawful actions. Finally, the West Virginia Plaintiffs' proposed amended complaint alleges that certain former Massey directors were unjustly enriched by their compensation as directors.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

On May 25, 2011, the West Virginia Plaintiffs filed a petition with the West Virginia Supreme Court for a preliminary injunction against the consummation of the Massey Acquisition, which was denied on May 31, 2011.

On June 24, 2011, the defendants moved to dismiss the West Virginia Plaintiffs' original complaint on the grounds that plaintiffs, as former Massey stockholders, lacked the legal right to pursue those claims, or, alternatively, to stay this case in favor of In re Massey, described above. Defendants also filed an opposition to the West Virginia Plaintiffs' motion to amend. On August 19, 2011, the West Virginia Plaintiffs filed a combined memorandum in opposition to defendants' motion to dismiss or stay and in further support of their motion to amend. On August 22, 2011, defendants filed a memorandum in further support of their motion to dismiss or stay and in further opposition to plaintiffs' motion to amend. On August 23, 2011, the court held a hearing on defendants' motion to dismiss and plaintiffs' motion to amend. Without deciding the motions, the court requested the parties to submit competing proposed orders containing findings of fact and conclusions of law and proposed scheduling orders for the court's consideration, which the parties did on September 9, 2011. The motions remain pending.

West Virginia State Court - Contempt Proceedings

On April 16, 2010, Manville Personal Injury Settlement Trust (“Manville”), one of the West Virginia Plaintiffs, filed a petition in the Circuit Court of Kanawha County, West Virginia, requesting that the court initiate civil contempt proceedings against certain of the then-current members of Massey's board of directors with respect to alleged violations of a settlement agreement. In July 2007, Manville filed a complaint, purportedly on behalf of Massey, alleging that certain of Massey's then directors and officers breached their fiduciary duties. On May 20, 2008, the parties executed a stipulation of settlement, which the court subsequently approved. The settlement provided for a release of all claims that were or could have been asserted on behalf of Massey in exchange for, among other things, certain corporate governance reforms and an agreement that the Massey board of directors would make a Corporate Social Responsibility Report to its stockholders on an annual basis that would include, among other things, a report on Massey's environmental and worker safety compliance. Manville alleges that Massey's 2009 Corporate Social Responsibility Report did not contain a sufficient report on worker safety compliance. On April 22, 2010, the court issued an order for a rule to show cause, initiating the contempt proceedings.

On May 31, 2011, Manville, now joined by the other two West Virginia Plaintiffs, filed a new petition for civil contempt, requesting that the court initiate civil contempt proceedings against certain of the then-current members of Massey's board of directors and certain then-current Massey officers in connection with certain additional alleged violations of the settlement.

On June 22, 2011, the individual defendants that had been served with the new petition filed a motion to dismiss that petition, as well as the original April 16 petition, and also moved to vacate the 2008 order, in which the court approved the settlement, as against them. On June 28, 2011, nominal defendant Alpha Appalachia joined in the individual defendants' motions to dismiss and vacate. On July 21, 2011, the court held a hearing on the defendants' motions to dismiss and vacate.

On September 29, 2011, the court granted the individual defendants' motions to dismiss and vacate and ordered that the contempt proceedings be terminated in their entirety. The plaintiffs appealed the dismissal of the contempt proceedings to the Supreme Court of Appeals of West Virginia. That appeal remains pending. Oral argument has been scheduled for September 4, 2013.

U.S. District Court - Eastern District of Virginia - Purported Stockholder Class Action

In the United States District Court for the Eastern District of Virginia, purported former Massey stockholder Benjamin Mostaed (“Mostaed”) alleges in a suit filed on February 2, 2011, and amended thereafter, purportedly on behalf of a class of former Massey stockholders, that Massey, Alpha and certain former Massey directors violated Sections 14(a) of the Exchange Act and Rule 14a-9 thereunder by filing a false and misleading preliminary proxy statement in connection with the then-proposed Massey Acquisition; that Massey and certain former Massey directors violated Section 20(a) of the Exchange Act by virtue of their control over persons alleged to have committed violations of Section 14(a) of the Exchange Act; that certain former Massey directors violated their fiduciary duties by causing Massey to enter into the Merger Agreement with Alpha pursuant to an unfair process that resulted in an unfair offer with preclusive deal protection devices that allegedly inhibited superior proposals; and that Massey and Alpha aided and abetted the former Massey directors' alleged breaches of fiduciary duty. Mostaed sought an injunction preventing the consummation of the Massey Acquisition; rescission of the Merger Agreement; and an award of the costs and disbursements of the action, including reasonable attorneys' and experts' fees.

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

On February 4, 2011, William D. Perkins (“Perkins”), another purported former Massey stockholder, filed a suit in the Eastern District of Virginia similar to Mostaed's. On February 17, 2011, Mostaed requested that the court consolidate the two pending actions, along with any subsequently filed actions challenging the proposed transaction. Defendants did not oppose the motion. On June 3, 2011, the court granted the motion.

On June 24, 2011, Mostaed informed the court that, aside from a motion for an award of attorneys' fees, he did not intend to prosecute the action further and would voluntarily dismiss his claims.

On July 13, 2011, Mostaed and Perkins moved for an award of attorneys' fees, reimbursement of expenses and incentive awards, contending that voluntary remedial measures implemented by defendants and sought by Mostaed (i.e., additional disclosure) had mooted Mostaed's claims. On July 26, 2011, defendants filed their opposition and on August 4, 2011, Mostaed and Perkins filed their reply brief. The court subsequently denied plaintiffs' request for oral argument.

On September 10, 2012, the court denied plaintiffs' motion for attorneys' fees, reimbursement of expenses and incentive awards. On September 24, 2012, the court dismissed the action with prejudice.

Mine Water Discharge Suits

The West Virginia Department of Environmental Protection (“WVDEP”) has brought civil enforcement actions against two of the Company's subsidiaries, Paynter Branch Mining, Inc. and Pioneer Fuel Corporation, in various West Virginia state courts seeking civil penalties based on alleged discharge of selenium, and in one case, other additional materials, in excess of permitted levels. The Company has reached agreements to resolve both claims with WVDEP. The circuit court has approved the Pioneer Fuel consent decree, and Pioneer Fuel has paid the civil penalty. The Paynter Branch Mining consent decree has been granted court approval, and the civil penalty payment has been made without material effect to the Company's results of operations.

The estimated future costs to treat for selenium discharges on specific permits involved include costs to build and to maintain water treatment systems. For permits that are active, capital costs (expected to be approximately $4,000) will be capitalized as property and equipment and depreciated over the expected lives and annual water treatment costs (expected to be approximately $550 annually) will be expensed as incurred. For post-mine closing periods on active permits as well as non-active permits, estimated future treatment costs have been included in asset retirement obligations.

On March 20, 2012, three environmental groups filed a citizen's suit against two of the Company's subsidiaries, Alex Energy, Inc. and Elk Run Coal Company, Inc., in federal court in the Southern District of West Virginia alleging violations of the terms of the subsidiaries' water discharge permits. The plaintiffs seek a civil penalty as well as injunctive relief.

On April 16, 2012, three environmental groups filed a citizen's suit in federal court in the Southern District of West Virginia against one of the Company's subsidiaries, Boone East Development Company (“Boone East”), which owns land previously mined and reclaimed by other companies, alleging that Boone East is discharging pollutants without a permit. Plaintiffs have since voluntarily terminated this action.

On May 9, 2012, three environmental groups filed a citizen's suit in federal court in the Southern District of West Virginia against two of the Company's subsidiaries alleging violations of the terms of the subsidiaries' water discharge permits. The plaintiffs seek a civil penalty as well as injunctive relief.

On May 15, 2012, WVDEP filed a civil enforcement action against the Company's subsidiary Riverside Energy Company, LLC, in McDowell County Circuit Court in West Virginia seeking civil penalties and injunctive relief based on alleged discharge of selenium in excess of permitted levels.

On July 16, 2012, three environmental groups filed a filed a citizen's suit in federal court in the Southern District of West Virginia against seven of the Company's subsidiaries alleging violations of the terms of the subsidiaries' water discharge permits. The plaintiffs seek a civil penalty as well as injunctive relief.

On December 31, 2012 and January 2, 2013, two separate environmental groups filed citizen's suits in federal court in the Western District of Pennsylvania against Emerald Coal Resources, L.P., and other of the Company's subsidiaries, alleging

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

violations of the terms of the subsidiaries' water discharge permits. The first of these cases has since been voluntarily dismissed by the plaintiffs. The plaintiffs in the remaining case seek a civil penalty as well as injunctive relief.

Nicewonder Litigation

In December 2004, prior to the Company's acquisition of Nicewonder in October 2005, the Affiliated Construction Trades Foundation (“ACTF”), a division of the West Virginia State Building and Construction Trades Council, brought an action against the West Virginia Department of Transportation, Division of Highways (“WVDOH”) and Nicewonder Contracting, Inc. (“NCI”), which became the Company's 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 and sought to enjoin performance of the contract, but did not seek monetary damages.

On September 30, 2009, the District 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 the Circuit Court of Kanawha County, West Virginia for resolution. On May 7, 2010, the Circuit Court of Kanawha County entered summary judgment in favor of NCI. On June 22, 2011, the West Virginia Supreme Court of Appeals reversed the Circuit Court order granting summary judgment in favor of NCI, and remanded the case back to the Circuit Court for further proceedings. Following remand, ACTF filed a motion for summary judgment, which the Circuit Court denied on November 9, 2011. ACTF challenged the order denying its summary judgment motion to the West Virginia Supreme Court of Appeals.

On June 21, 2012, the West Virginia Supreme Court of Appeals issued an opinion finding that ACTF has standing to pursue its claims and remanded the case back to the Circuit Court of Kanawha County, West Virginia for further proceedings. NCI's portion of the highway project under the contract is complete.

The case is now pending in the Circuit Court of Kanawha County, West Virginia. A settlement between NCI and ACTF was agreed upon in early January 2013, prior to the scheduled trial date, January 14, 2013. The Company does not expect to incur any out-of-pocket expenditures in connection with the settlement. The trial proceeded among the remaining parties.

On February 7, 2013, the Company received notice of a purported class action lawsuit against NCI filed by a former NCI employee. The former employee is represented by the same attorney who represents the plaintiff in the ACTF litigation, and the complaint's allegations raise issues similar to those in the ACTF litigation. NCI's answer is due by March 4, 2013.

On February 26, 2013, the Circuit Court of Kanawha County ruled that the contract in dispute in the ACTF litigation, as well as the awarding and implementation, of the contract were in violation of West Virginia law. The Company is reviewing the Court's ruling and evaluating its implications.

Fluor Litigation

Alpha Appalachia and certain of its subsidiaries are also parties to a number of lawsuits and other legal proceedings related to certain non-coal businesses (the “Prior Business”) previously conducted by its former affiliate Fluor Corporation. These lawsuits include the Alexander-Pederson-Helig cases in which two of Alpha Appalachia's subsidiaries, Appalachia Holding Company (“Appalachia Holding”) and DRIH Corporation (“DRIH”), were named defendants along with Fluor. In July 2011, those cases resulted in a jury award in the City of St. Louis Circuit Court in favor of the plaintiffs for $38,500 in compensatory and economic damages and $320,000 in punitive damages. The total aggregate judgment against Alpha Appalachia's subsidiaries is $118,500.

Under the terms of the Distribution Agreement entered into by Alpha Appalachia and Fluor as of November 30, 2000 in connection with the spin-off of Fluor by Massey, Fluor agreed to indemnify Massey with respect to all such legal proceedings and assumed defense of the proceedings. Consistent with that agreement, in September 2011, Fluor submitted to the Court a number of surety bonds covering the full amount of the judgments against Fluor and Alpha Appalachia's subsidiaries in the Alexander-Pederson-Helig cases. On January 24, 2012, Fluor moved for a reduction in the surety bond amount pending appeal. The Missouri Court of Appeals granted Fluor's motion on March 1, 2012 and reduced the amount of the surety bonds required to be submitted by the defendants collectively to $150,000, which Fluor has submitted on behalf of itself and Alpha Appalachia's subsidiaries. The Company has recorded an indemnity receivable of $118,500 and has accrued a liability of $118,500, included in prepaid expenses and other current assets and accrued expenses and other current liabilities, respectively,

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

in the consolidated balance sheet at December 31, 2012. The appeal of the judgments in the Alexander-Pederson-Helig cases remains pending.

In connection with Fluor's sale of the Prior Business to a group of purchasers (the “Rennert Entities”) in 1994, the Rennert Entities had agreed to indemnify Fluor and its affiliates for losses and liabilities arising from the Prior Business. In late 2010, the Rennert Entities settled with the plaintiffs in the Alexander-Pederson-Helig cases without indemnifying or obtaining a release for the benefit of Fluor and Alpha Appalachia's subsidiaries.

In January 2012, the Rennert Entities filed suit against Fluor and two of Alpha Appalachia's subsidiaries in the United States District Court for the Eastern District of Missouri seeking return of funds previously paid by the Rennert Entities to settle personal injury and property damage claims against Fluor and Alpha Appalachia's subsidiaries allegedly arising out of the Prior Business and a declaration of non-liability for indemnification with respect to the Alexander-Pederson-Helig cases and any future claims or judgments against Fluor and Alpha Appalachia's subsidiaries arising out of the Prior Business. Also in January 2012, Fluor filed suit against the Rennert Entities in Missouri state court alleging various breach of contract and tort claims and seeking a declaratory judgment regarding the Rennert Entities' indemnification obligations to Fluor and Alpha Appalachia's subsidiaries against claims arising out of the Prior Business. On February 21, 2012, Appalachia Holding and DRIH joined Fluor as plaintiffs in this suit. At the same time, Fluor, Appalachia Holding and DRIH moved to dismiss, or in the alternative, to stay the suit pending in federal court in Missouri in favor of the Missouri state court action. On June 21, 2012, Missouri federal court stayed the case before it in favor of the suit pending in the Missouri state court.

On April 4, 2012, the Rennert entities moved to dismiss the Missouri state court action. On July 13, 2012, the Missouri state court scheduled an expedited hearing on the Rennert entities' pending motions to dismiss for August 15, 2012. On October 5, 2012, the court denied the Rennert entities' motions to dismiss each of Fluor's and Alpha Appalachia's subsidiaries' claims except for one claim for contribution, which the court dismissed. All defendants answered on October 25, 2012. Discovery has commenced and is ongoing.

Other Legal Proceedings

In addition to the matters disclosed above, the Company and its subsidiaries are involved in a number of legal proceedings and governmental examinations 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. 

(22) 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. For the years ended December 31, 2012, 2011, and 2010, the Company’s ten largest customers accounted for approximately 42%, 41%, and 42% of total revenues, respectively. Sales to the Company’s largest customer accounted for approximately 9%, 9% and 9% of total revenues for the years ended December 31, 2012, 2011, and 2010, respectively. Steam coal accounted for approximately 81%, 82%, and 86% of the Company’s coal sales volume during 2012, 2011, and 2010, respectively. Metallurgical coal accounted for approximately 19%, 18%, and 14% of the Company’s coal sales volume during 2012, 2011, and 2010, respectively.

(23) 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. Based on a review of the required economic characteristics, the Company aggregates its operating segments into two reportable segments: Western Coal Operations, which consists of two Powder River Basin surface mines as of December 31, 2012 and Eastern Coal Operations, which consists of 74

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

underground mines and 31 surface mines in Central and Northern Appalachia as of December 31, 2012, 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 certain closed mines; Dry Systems Technologies; revenues and royalties from the sale of coalbed methane at the Company’s Coal Gas Recovery business 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 (loss) from continuing operations plus interest expense, income tax expense, amortization of acquired intangibles, net and depreciation, depletion and amortization, less interest income and income tax benefit.

Segment operating results and capital expenditures from continuing operations for the year ended December 31, 2012 were as follows:

	Eastern Coal Operations			Western Coal Operations		All Other			Consolidated
Total revenues	$	6,290,289		$	611,329	$	73,266		$	6,974,884
Depreciation, depletion, and amortization	$	949,064		$	62,729	$	25,782		$	1,037,575
Amortization of acquired intangibles, net	$	(87,875	)	$	13,644	$	3,893		$	(70,338	)
EBITDA from continuing operations	$	(1,807,515	)	$	65,153	$	(82,771	)	$	(1,825,133	)
Capital expenditures	$	368,838		$	18,082	$	15,457		$	402,377
Acquisition of mineral rights under federal lease	$	—		$	95,765	$	—		$	95,765

The following table presents a reconciliation of EBITDA from continuing operations to income from continuing operations for the year ended December 31, 2012:

	Eastern Coal Operations			Western Coal Operations			All Other			Consolidated
EBITDA from continuing operations	$	(1,807,515	)	$	65,153		$	(82,771	)	$	(1,825,133	)
Interest expense	(2,696		)	(380		)	(195,071		)	(198,147		)
Interest income	1,395			4			1,974			3,373
Income tax (expense) benefit	(27		)	—			550,023			549,996
Depreciation, depletion and amortization	(949,064		)	(62,729		)	(25,782		)	(1,037,575		)
Amortization of acquired intangibles, net	87,875			(13,644		)	(3,893		)	70,338
Income (loss) from continuing operations	$	(2,670,032	)	$	(11,596	)	$	244,480		$	(2,437,148	)

Segment operating results and capital expenditures from continuing operations for the year ended December 31, 2011 were as follows:

	Eastern Coal Operations			Western Coal Operations		All Other			Consolidated
Total revenues	$	6,423,805		$	602,157	$	81,719		$	7,107,681
Depreciation, depletion, and amortization	$	688,068		$	61,401	$	21,300		$	770,769
Amortization of acquired intangibles, net	$	(152,565	)	$	34,919	$	3,224		$	(114,422	)
EBITDA from continuing operations	$	143,649		$	74,891	$	(190,705	)	$	27,835
Capital expenditures	$	438,319		$	35,593	$	54,674		$	528,586
Acquisition of mineral rights under federal lease	$	—		$	64,900	$	—		$	64,900

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The following table presents a reconciliation of EBITDA from continuing operations to income from continuing operations for the year ended December 31, 2011:

	Eastern Coal Operations			Western Coal Operations			All Other			Consolidated
EBITDA from continuing operations	$	143,649		$	74,891		$	(190,705	)	$	27,835
Interest expense	(25,648		)	(69		)	(116,197		)	(141,914		)
Interest income	1,008			—			2,970			3,978
Income tax benefit	—			—			35,906			35,906
Depreciation, depletion and amortization	(688,068		)	(61,401		)	(21,300		)	(770,769		)
Amortization of acquired intangibles, net	152,565			(34,919		)	(3,224		)	114,422
Loss from continuing operations	$	(416,494	)	$	(21,498	)	$	(292,550	)	$	(730,542	)

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 intangibles, 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 intangibles, net	(136,501		)	(90,292		)	—			(226,793		)
Income (loss) from continuing operations	$	194,433		$	(52,961	)	$	(44,254	)	$	97,218

The following table presents total assets and goodwill:

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Total Assets						Goodwill, net
	December 31, 2012		December 31, 2011		December 31, 2010		December 31, 2012		December 31, 2011		December 31, 2010
Eastern Coal Operations	$	10,691,029	$	14,427,166	$	3,382,335	$	561,753	$	2,221,971	$	323,220
Western Coal Operations	647,292		657,419		651,479		—		53,308		53,308
All Other	1,751,485		1,509,460		1,145,469		5,912		5,912		5,912
Total	$	13,089,806	$	16,594,045	$	5,179,283	$	567,665	$	2,281,191	$	382,440

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, which include freight and handling revenues, totaled $2,930,557 or approximately 42% of total revenues from continuing operations for the year ended December 31, 2012, $3,095,927 or approximately 44% of total revenues from continuing operations for the year ended December 31, 2011; and $1,351,001 or approximately 34% of total revenues from continuing operations for the year ended December 31, 2010.

(24) Supplemental Guarantor and Non-Guarantor Financial Information

On June 1, 2011 and October 11, 2012, the Company issued the Senior Notes and may issue new registered debt securities (the “New Notes”) in the future that are and will be, respectively, fully and unconditionally guaranteed, jointly and severally, on a senior or subordinated unsecured basis by certain of the Company’s 100% owned subsidiaries (the “New Notes Guarantor Subsidiaries”).

Presented below are condensed consolidating financial statements as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011, and 2010, respectively, based on the guarantor structure that was put in place in connection with the issuance of the Senior Notes, and would be put in place in the event the Company issues New Notes in the future. The tables below refer to the Company as issuer of the Senior Notes and of any New Notes that may be issued in the future. “Non-Guarantor Subsidiaries” refers, for the tables below, to ANR Receivables Funding, LLC, Alpha Australia Pty. Limited, Alpha Coal India Private Limited, Coalsolv, LLC, Gray Hawk Insurance Company and Rockridge Coal Company, that were not guarantors of the Senior Notes and would not be guarantors 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.

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Balance Sheet

December 31, 2012

	Parent (Issuer)		New Notes Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Total Consolidated
Assets
Current assets:
Cash and cash equivalents	$	277	$	729,662	$	784	$	—		$	730,723
Trade accounts receivable, net	—		19,222		398,944		—			418,166
Inventories, net	—		398,060		—		—			398,060
Prepaid expenses and other current assets	—		783,578		2,695		—			786,273
Total current assets	277		1,930,522		402,423		—			2,333,222
Property, equipment and mine development costs, net	—		2,219,016		—		—			2,219,016
Owned and leased mineral rights and land, net	—		7,428,192		—		—			7,428,192
Goodwill, net	—		567,665		—		—			567,665
Other acquired intangibles, net	—		228,552		—		—			228,552
Other non-current assets	9,202,925		9,342,804		5,083		(18,237,653		)	313,159
Total assets	$	9,203,202	$	21,716,751	$	407,506	$	(18,237,653	)	$	13,089,806
Liabilities and Stockholders’ Equity
Current liabilities:
Current portion of long-term debt	$	75,000	$	20,015	$	—	$	—		$	95,015
Trade accounts payable	8,291		246,838		62		—			255,191
Accrued expenses and other current liabilities	3,130		869,248		24		—			872,402
Total current liabilities	86,421		1,136,101		86		—			1,222,608
Long-term debt	2,708,948		582,089		—		—			3,291,037
Pension and postretirement medical benefit obligations	—		1,195,187		—		—			1,195,187
Asset retirement obligations	—		763,482		—		—			763,482
Deferred income taxes	—		971,001		—		—			971,001
Other non-current liabilities	1,440,018		1,726,255		392,441		(2,880,038		)	678,676
Total liabilities	4,235,387		6,374,115		392,527		(2,880,038		)	8,121,991
Stockholders’ Equity
Total stockholders’ equity	4,967,815		15,342,636		14,979		(15,357,615		)	4,967,815
Total liabilities and stockholders’ equity	$	9,203,202	$	21,716,751	$	407,506	$	(18,237,653	)	$	13,089,806

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Balance Sheet

December 31, 2011

	Parent (Issuer)		New Notes Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Total Consolidated
Assets
Current assets:
Cash and cash equivalents	$	613	$	584,273	$	996	$	—		$	585,882
Trade accounts receivable, net	—		284,675		357,300		—			641,975
Inventories, net	—		492,022		—		—			492,022
Prepaid expenses and other current assets	—		825,348		2,848		—			828,196
Total current assets	613		2,186,318		361,144		—			2,548,075
Property, equipment and mine development costs, net	—		2,812,069		—		—			2,812,069
Owned and leased mineral rights and land, net	—		8,284,328		—		—			8,284,328
Goodwill, net	—		2,281,191		—		—			2,281,191
Other acquired intangibles, net	—		347,889		—		—			347,889
Other non-current assets	11,627,250		11,772,085		4,272		(23,083,114		)	320,493
Total assets	$	11,627,863	$	27,683,880	$	365,416	$	(23,083,114	)	$	16,594,045
Liabilities and Stockholders’ Equity
Current liabilities:
Current portion of long-term debt	$	45,000	$	1,029	$	—	$	—		$	46,029
Trade accounts payable	5,018		499,016		25		—			504,059
Accrued expenses and other current liabilities	9,151		1,349,986		23		—			1,359,160
Total current liabilities	59,169		1,850,031		48		—			1,909,248
Long-term debt	2,274,580		647,472		—		—			2,922,052
Pension and postretirement medical benefit obligations	—		1,214,724		—		—			1,214,724
Asset retirement obligations	—		743,613		—		—			743,613
Deferred income taxes	—		1,507,923		—		—			1,507,923
Other non-current liabilities	1,919,070		2,494,411		346,099		(3,838,139		)	921,441
Total liabilities	4,252,819		8,458,174		346,147		(3,838,139		)	9,219,001
Stockholders’ Equity
Total stockholders’ equity	7,375,044		19,225,706		19,269		(19,244,975		)	7,375,044
Total liabilities and stockholders’ equity	$	11,627,863	$	27,683,880	$	365,416	$	(23,083,114	)	$	16,594,045

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Consolidating Statement of Operations

Year Ended December 31, 2012

	Parent (Issuer)			New Notes Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Total Consolidated
Revenues:
Coal revenues	$	—		$	6,015,696		$	—		$	—	$	6,015,696
Freight and handling revenues	—			761,928			—			—		761,928
Other revenues	—			184,017			13,243			—		197,260
Total revenues	—			6,961,641			13,243			—		6,974,884
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)	—			5,004,516			—			—		5,004,516
Freight and handling costs	—			761,928			—			—		761,928
Other expenses	—			45,432			—			—		45,432
Depreciation, depletion and amortization	—			1,037,575			—			—		1,037,575
Amortization of acquired intangibles, net	—			(70,338		)	—			—		(70,338		)
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization shown separately above)	—			205,156			4,632			—		209,788
Asset impairment and restructuring	—			1,068,906			—			—		1,068,906
Goodwill impairment	—			1,713,526			—			—		1,713,526
Total costs and expenses	—			9,766,701			4,632			—		9,771,333
Income (loss) from operations	—			(2,805,060		)	8,611			—		(2,796,449		)
Other income (expense):
Interest expense	(170,111		)	(25,063		)	(2,973		)	—		(198,147		)
Interest income	—			3,347			26			—		3,373
Gain on early extinguishment of debt	—			773			—			—		773
Miscellaneous expense, net	—			3,349			(43		)	—		3,306
Total other expense, net	(170,111		)	(17,594		)	(2,990		)	—		(190,695		)
Income (loss) from continuing operations before income taxes and equity in earnings of investments in Issuer and Guarantor Subsidiaries	(170,111		)	(2,822,654		)	5,621			—		(2,987,144		)
Income tax benefit (expense)	66,343			485,845			(2,192		)	—		549,996
Equity in earnings of investments in Issuer and Guarantor Subsidiaries	(2,333,380		)	—			—			2,333,380		—
Net income (loss)	$	(2,437,148	)	$	(2,336,809	)	$	3,429		$	2,333,380	$	(2,437,148	)

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Consolidating Statement of Operations

Year Ended December 31, 2011

	Parent (Issuer)			New Notes Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Total Consolidated
Revenues:
Coal revenues	$	—		$	6,189,434		$	—		$	—	$	6,189,434
Freight and handling revenues	—			662,238			—			—		662,238
Other revenues	—			245,329			10,680			—		256,009
Total revenues	—			7,097,001			10,680			—		7,107,681
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)	—			5,080,921			—			—		5,080,921
Freight and handling costs	—			662,238			—			—		662,238
Other expenses	—			142,709			—			—		142,709
Depreciation, depletion and amortization	—			770,769			—			—		770,769
Amortization of acquired intangibles, net	—			(114,422		)	—			—		(114,422		)
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization shown separately above)	—			378,537			3,713			—		382,250
Goodwill impairment	—			802,337			—			—		802,337
Total costs and expenses	—			7,723,089			3,713			—		7,726,802
Income (loss) from operations	—			(626,088		)	6,967			—		(619,121		)
Other income (expense):
Interest expense	(107,971		)	(31,735		)	(2,208		)	—		(141,914		)
Interest income	—			3,978			—			—		3,978
Loss on early extinguishment of debt	(4,751		)	(5,275		)	—			—		(10,026		)
Miscellaneous income, net	—			635			—			—		635
Total other expense, net	(112,722		)	(32,397		)	(2,208		)	—		(147,327		)
Income (loss) from continuing operations before income taxes and equity in earnings of investments in Issuer and Guarantor Subsidiaries	(112,722		)	(658,485		)	4,759			—		(766,448		)
Income tax benefit (expense)	43,962			(6,301		)	(1,755		)	—		35,906
Equity in earnings of investments in Issuer and Guarantor Subsidiaries	(661,782		)	(23,745		)	—			685,527		—
Net income (loss)	$	(730,542	)	$	(688,531	)	$	3,004		$	685,527	$	(730,542	)

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Consolidating Statement of Operations

Year Ended December 31, 2010

	Parent (Issuer)			New Notes Guarantor Subsidiaries			Non-Guarantor Subsidiaries			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 intangibles, 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	0			(821		)	—			—			(821		)
Total other expense, net	(19,570		)	(49,689		)	(2,916		)	—			(72,175		)
Income 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 (expense) benefit	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

166

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Alpha Natural Resources, Inc. and Subsidiaries
Supplemental Condensed Consolidating Statements of Comprehensive Income (Loss)
For the Year Ended December 31, 2012
	Parent (Issuer)			New Notes Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Total Consolidated
Net income (loss)	$	(2,437,148	)	$	(2,336,809	)	$	3,429	$	2,333,380	$	(2,437,148	)
Total comprehensive income (loss)	$	(2,401,916	)	$	(2,372,041	)	$	3,429	$	2,368,612	$	(2,401,916	)

Alpha Natural Resources, Inc. and Subsidiaries
Supplemental Condensed Consolidating Statements of Comprehensive Income (Loss)
For the Year Ended December 31, 2011
	Parent (Issuer)			New Notes Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Total Consolidated
Net income (loss)	$	(730,542	)	$	(688,531	)	$	3,004	$	685,527	$	(730,542	)
Total comprehensive income (loss)	$	(904,789	)	$	(514,284	)	$	3,004	$	511,280	$	(904,789	)

Alpha Natural Resources, Inc. and Subsidiaries
Supplemental Condensed Consolidating Statements of Comprehensive Income (Loss)
For the Year Ended December 31, 2010
	Parent (Issuer)		New Notes Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Total Consolidated
Net income (loss)	$	95,551	$	108,163	$	1,691	$	(109,854	)	$	95,551
Total comprehensive income (loss)	$	62,156	$	141,558	$	1,691	$	(143,249	)	$	62,156

167

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2012

	Parent (Issuer)			New Notes Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Total Consolidated
Net cash (used in) provided by operating activities	$	(2,748	)	$	521,115		$	52		$	518,419
Investing activities:
Capital expenditures	—			(402,377		)	—			(402,377		)
Acquisition of mineral rights under federal lease	—			(95,765		)	—			(95,765		)
Purchases of marketable securities, net	—			(202,984		)	—			(202,984		)
Purchase of equity-method investment	—			(10,100		)	—			(10,100		)
Other, net	—			38,250			—			38,250
Net cash used in investing activities	—			(672,976		)	—			(672,976		)
Financing activities:
Proceeds from borrowings on long-term debt	494,795			—			—			494,795
Principal repayments on long-term debt	(45,000		)	(115,157		)	—			(160,157		)
Principal repayments of capital lease obligations	—			(10,548		)	—			(10,548		)
Debt issuance costs	(15,767		)	—			(594		)	(16,361		)
Common stock repurchases	(7,507		)	—			—			(7,507		)
Proceeds from exercise of stock options	176			—			—			176
Other, net	—			(1,000		)	—			(1,000		)
Transactions with affiliates	(424,285		)	423,955			330			—
Net cash (used in) provided by financing activities	2,412			297,250			(264		)	299,398
Net increase (decrease) in cash and cash equivalents	(336		)	145,389			(212		)	144,841
Cash and cash equivalents at beginning of period	613			584,273			996			585,882
Cash and cash equivalents at end of period	$	277		$	729,662		$	784		$	730,723

168

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2011

	Parent (Issuer)			New Notes Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Total Consolidated
Net cash (used in) provided by operating activities	$	10,651		$	675,990		$	(4	)	$	686,637
Investing activities:
Cash paid for acquisition, net of cash acquired	(711,387		)	—			—			(711,387		)
Capital expenditures	—			(528,586		)	—			(528,586		)
Acquisition of mineral rights under federal lease	—			(64,900		)	—			(64,900		)
Sales of marketable securities, net	—			173,201			—			173,201
Purchase of equity-method investment	—			(14,800		)	—			(14,800		)
Other, net	—			(535		)	—			(535		)
Net cash used in investing activities	(711,387		)	(435,620		)	—			(1,147,007		)
Financing activities:
Proceeds from borrowings on long-term debt	2,100,000			—			—			2,100,000
Principal repayments on long-term debt	(242,896		)	(1,072,461		)	—			(1,315,357		)
Debt issuance costs	(85,226		)	—			—			(85,226		)
Common stock repurchases	(212,257		)	—			—			(212,257		)
Proceeds from exercise of stock options	4,320			—			—			4,320
Transactions with affiliates	(882,923		)	881,923			1,000			—
Net (cash used) provided by financing activities	681,018			(190,538		)	1,000			491,480
Net increase (decrease) in cash and cash equivalents	(19,718		)	49,832			996			31,110
Cash and cash equivalents at beginning of period	20,331			534,441			—			554,772
Cash and cash equivalents at end of period	$	613		$	584,273		$	996		$	585,882

169

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2010

	Parent (Issuer)			New Notes Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Total 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		)
Purchases of marketable securities	—			(158,550		)	—			(158,550		)
Purchase of equity-method investment	—			(5,000		)	—			(5,000		)
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 financing activities	(41,568		)	(45,949		)	(8,684		)	(96,201		)
Net increase (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

(25) Discontinued Operations

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 year ended December 31, 2010:

170

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	For the Year Ended December 31,
	2010
Total revenues	$	17
Total costs and expenses	(2,736		)
Loss from operations	(2,719		)
Income tax benefit from discontinued operations	1,052
Loss from discontinued operations	$	(1,667	)

(26) Quarterly Financial Information (Unaudited)

	Year Ended December 31, 2012
	First Quarter(1)			Second Quarter			Third Quarter			Fourth Quarter
Total revenues	$	1,934,613		$	1,848,109		$	1,633,809		$	1,558,353
Net loss (2)	$	(28,768	)	$	(2,234,656	)	$	(46,146	)	$	(127,578	)
Basic loss per share	$	(0.13	)	$	(10.14	)	$	(0.21	)	$	(0.58	)
Diluted loss per share	$	(0.13	)	$	(10.14	)	$	(0.21	)	$	(0.58	)

⁽¹⁾  Amounts have been adjusted from previously reported amounts to reflect the impact of retrospective adjustments made as a result of applying acquisition accounting for Massey.

⁽²⁾  Net loss includes asset impairment and restructuring charges of $4,056, $1,010,878, $13,676 and $40,296 in the first, second, third and fourth quarters of 2012, respectively. Net loss also includes goodwill impairment charges of $1,525,332 and $188,194 in the second and fourth quarters of 2012, respectively.

The following table illustrates the effects of the adjustments:

	First Quarter 2012
	Previously reported			Adjustments			As adjusted
Total revenues	$	1,934,648		$	(35	)	$	1,934,613
Net loss	$	(29,117	)	$	349		$	(28,768	)
Basic loss per share	$	(0.13	)	$	—		$	(0.13	)
Diluted loss per share	$	(0.13	)	$	—		$	(0.13	)

	Year Ended December 31, 2011
	First Quarter		Second Quarter			Third Quarter		Fourth Quarter (1)
Total revenues	$	1,130,738	$	1,598,038		$	2,308,753	$	2,070,152
Net income (loss) (2)	$	49,848	$	(50,068	)	$	62,604	$	(792,926	)
Basic earnings (loss) per share	$	0.42	$	(0.32	)	$	0.28	$	(3.62	)
Diluted earnings (loss) per share	$	0.41	$	(0.32	)	$	0.28	$	(3.62	)

⁽¹⁾  Amounts have been adjusted from previously reported amounts to reflect the impact of retrospective adjustments made as a result of applying acquisition accounting for Massey and immaterial corrections.

⁽²⁾  Net loss includes a goodwill impairment charge of $802,337 in the fourth quarter of 2011.

171

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The following table illustrates the effects of the adjustments:

	Fourth Quarter 2011
	Previously reported			Adjustments			As adjusted
Total revenues	$	2,070,643		$	(491	)	$	2,070,152
Net loss	$	(733,334	)	$	(59,592	)	$	(792,926	)
Basic loss per share	$	(3.34	)	$	(0.28	)	$	(3.62	)
Diluted loss per share	$	(3.34	)	$	(0.28	)	$	(3.62	)

(27) Share Repurchase Program

On May 19, 2010, the Board of Directors authorized a share repurchase program, which permits the Company to repurchase up to $125,000 of its outstanding common stock, par value $0.01 per share (“Shares”).  The program enables the Company to repurchase Shares from time to time, as market conditions warrant. The program was completed during 2011.  On August 22, 2011, the Board of Directors authorized an additional share repurchase program, which permits the Company to repurchase up to $600,000 of Shares from time to time, as market conditions warrant. During 2010, the Company repurchased $24,999 of Shares under the programs. During 2011, the Company repurchased $200,000 of Shares under the programs. No Shares were repurchased under the programs in 2012.

172

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 internalcontrolsover 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 onInternalControl 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, 2012.  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, 2012.

173

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Alpha Natural Resources, Inc.:

We have audited Alpha Natural Resources, Inc.'s (the Company) internal control over financial reporting as of December 31, 2012, 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 authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, 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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated March 1, 2013 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Roanoke, Virginia

March 1, 2013

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

174

The sections of our Proxy Statement entitled “Proposal 1—Election of Directors—Nominees for Directors,” “Corporate Governance And Related Matters—The Board of Directors 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 and Accounting 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 and Accounting 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 2012,” “Corporate Governance And Related Matters—Additional Information Regarding Our Director Compensation Table,” “Executive Compensation—Compensation Discussion and Analysis,” “Executive Compensation—Compensation Committee Report,” “Executive Compensation—Compensation and Risk,” “Executive Compensation—Summary Compensation Table,” “Executive Compensation—Grants of Plan-Based Awards in 2012,” “ Executive Compensation— Additional Information Regarding Our Summary Compensation Table and Grants of Plan-Based Awards Table,” “Executive Compensation—Outstanding Equity Awards at Fiscal Year-End 2012,” “Executive Compensation—Option Exercises and Stock Vested in 2012,” “Executive Compensation—Pension Benefits in 2012,” “Executive Compensation—Additional Information Regarding Our Pension Benefits Table,” “Executive Compensation—Nonqualified Deferred Compensation in 2012,” “Executive Compensation—Additional Information Regarding Our Nonqualified Deferred Compensation Plan Table,” “Executive Compensation —Potential Payments Upon Termination or Change in Control,” and “Executive Compensation—Additional Information Regarding the Tables Relating to Potential Payments Upon Employment Termination or Change in Control” 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 “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 “Independent Registered Public Accounting Firm—Fees of Independent Registered Public Accounting Firm” and “Independent Registered Public Accounting Firm—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 16429, Bristol, Virginia 24209, attention: Investor Relations.

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

175

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:

Reports of Independent Registered Public Accounting Firm

Consolidated Balance Sheets, December 31, 2012 and 2011

Consolidated Statements of Operations, Years ended December 31, 2012, 2011 and 2010

Consolidated Statements of Comprehensive Income (Loss), Years ended December 31, 2012, 2011 and 2010

Consolidated Statements of Stockholders’ Equity, Years ended December 31, 2012, 2011 and 2010

Consolidated Statements of Cash Flows, Years ended December 31, 2012, 2011 and 2010

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.

176

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: March 1, 2013

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.

177

Signature	Date	Title
/s/ Kevin S. Crutchfield	March 1, 2013	Chief Executive Officer (Principal Executive Officer), Chairman of the Board of Directors and Director
Kevin S. Crutchfield
/s/ Frank J. Wood	March 1, 2013	Executive Vice President and Chief Financial Officer, (Principal Financial and Accounting Officer)
Frank J. Wood
/s/ Angelo C. Brisimitzakis	March 1, 2013	Director
Angelo C. Brisimitzakis
/s/ William J. Crowley, Jr.	March 1, 2013	Director
William J. Crowley, Jr.
/s/ E. Linn Draper, Jr.	March 1, 2013	Director
E. Linn Draper, Jr.
/s/ Glenn A. Eisenberg	March 1, 2013	Director
Glenn A. Eisenberg
/s/ Deborah M. Fretz	March 1, 2013	Director
Deborah M. Fretz
/s/ P. Michael Giftos	March 1, 2013	Director
P. Michael Giftos
/s/ L. Patrick Hassey	March 1, 2013	Director
L. Patrick Hassey
/s/ Joel Richards, III	March 1, 2013	Director
Joel Richards, III
/s/ James F. Roberts	March 1, 2013	Director
James F. Roberts
/s/ Ted G. Wood	March 1, 2013	Director
Ted G. Wood

178

10-K EXHIBIT INDEX

Exhibit No.	Description of Exhibit
2.1	Agreement and Plan of Merger, dated as of January 28, 2011, among Mountain Merger Sub, Inc., Alpha Natural Resources, Inc. and Massey Energy Company (Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on January 31, 2011.)
2.2	Agreement and Plan of Merger, dated as of May 11, 2009, by and between 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.)
2.3	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.)
2.4	Membership Unit Purchase Agreement dated as of September 23, 2005 among Premium Energy, LLC and the unit holders 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.)
2.5	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.)
2.6	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.)
2.7	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.)
2.8	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, Inc. /Old (File No. 1-32423) filed on October 31, 2005.)
2.9	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	Certificate of Amendment of the Restated Certificate of Incorporation 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 June 1, 2011.)
3.3	Amended and Restated Bylaws of Alpha Natural Resources, Inc. (Incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on December 27, 2011.)

179

Exhibit No.	Description of Exhibit
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.)
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	Indenture, dated as of June 1, 2011, among Alpha Natural Resources, Inc., the Guarantors named therein and Union Bank, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.9	First Supplemental Indenture, dated as of June 1, 2011, among Alpha Natural Resources, Inc., the Guarantors named therein and Union Bank, N.A., as trustee (Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.10	Form of 2019 Note (included in Exhibit 4.9) (Incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.11	Form of 2021 Note (included in Exhibit 4.9) (Incorporated by reference to Exhibit 4.4 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.12	Second Supplemental Indenture, dated as of June 1, 2011, among Alpha Natural Resources, Inc., the Guarantors named therein and Union Bank, N.A., as trustee (Incorporated by reference to Exhibit 4.5 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.13	Third Supplemental Indenture, dated as of October 11, 2012, among Alpha Natural Resources, Inc., the Guarantors named therein and Union Bank, N.A., as trustee (Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on October 11, 2012).
4.14	Form of 2018 Note (included in Exhibit 4.13) (Incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on October 11, 2012.)
4.15	Senior Indenture, dated as of August 12, 2008, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.6 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)

180

Exhibit No.	Description of Exhibit
4.16	First Supplemental Indenture, dated as of August 12, 2008, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.7 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.17	Second Supplemental Indenture, dated as of July 20, 2009, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.8 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.18	Third Supplemental Indenture, dated as of August 28, 2009, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.9 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.19	Fourth Supplemental Indenture, dated as of April 30, 2010, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.10 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.20	Fifth Supplemental Indenture, dated as of June 29, 2010, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.11 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.21	Sixth Supplemental Indenture dated as of June 1, 2011, among Alpha Natural Resources, Inc., Massey Energy Company, the Guarantors named therein and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.12 to the Amendment No. 1 to Current Report to Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 3, 2011.)
4.22*	Seventh Supplemental Indenture dated as of December 31, 2012, among Alpha Natural Resources, Inc., Alpha Appalachia Holdings, Inc. (fka Massey Energy Company), Mill Branch Coal Corporation, the Guarantors named therein and Wilmington Trust Company, as Trustee.
4.23*	Eighth Supplemental Indenture dated as of December 31, 2012, among Alpha Natural Resources, Inc., Alpha Appalachia Holdings, Inc. (fka Massey Energy Company), North Fork Coal Corporation, the Guarantors named therein and Wilmington Trust Company, as Trustee.
4.24	Third Amended and Restated Credit Agreement, dated as of May 19, 2011, by and among Alpha, the lenders party thereto, the issuing banks party thereto, Citicorp North America, Inc. as administrative and collateral agent and Citigroup Global Markets Inc. and Morgan Stanley Senior Funding, Inc. as joint lead arrangers and joint book managers (Incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on May 20, 2011.)
4.25	Amendment No. 1 to Third Amended and Restated Credit Agreement, dated as of June 26, 2012, among Alpha Natural Resources, Inc., the guarantors party thereto, the lenders party thereto and Citicorp North America, Inc., as administrative agent and collateral agent. (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 27, 2012).
10.1	Non-Prosecution Agreement, dated as of December 6, 2011, between Alpha and Alpha Appalachia Holdings, Inc. (fka Massey Energy Company) and the United States Attorney’s Office for the Southern District of West Virginia and the United States Department of Justice, and settlement with MSHA (Incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on December 6, 2011.)
10.2	Second Amended and Restated Receivables Purchase Agreement, dated as of October 19, 2011, by and among ANR Receivables Funding, LLC, Alpha Natural Resources, LLC, the various financial institutions party thereto and PNC Bank, National Association (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on October 21, 2011.)

181

Exhibit No.	Description of Exhibit
10.3	First Amendment, dated as of December 21, 2011, to the Second Amended and Restated Receivables Purchase Agreement, by and among ANR Receivables Funding, LLC, Alpha Natural Resources, LLC, the various financial institutions party thereto and PNC Bank, National Association (Incorporated by reference to Exhibit 10.3 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on February 29, 2012.)
10.4	Limited Waiver dated as of February 14, 2012 pursuant to that certain Second Amended and Restated Receivables Purchase Agreement, dated as of October 19, 2011 (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 10, 2012.)
10.5	Second Amendment to the Second Amended and Restated Receivables Purchase Agreement, dated as of May 1, 2012, among ANR Receivables Funding, LLC, Alpha Natural Resources, LLC, the various financial institutions party thereto and PNC Bank, National Association (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 August 9, 2012.)
10.6	Third Amendment to the Second Amended and Restated Receivables Purchase Agreement, dated as of June 26, 2012, among ANR Receivables Funding, LLC, Alpha Natural Resources, LLC, the various financial institutions party thereto and PNC Bank, National Association (Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 27, 2012).
10.7	Fourth Amendment to the Second Amended and Restated Receivables Purchase Agreement, dated as of November 14, 2012, among ANR Receivables Funding, LLC, Alpha Natural Resources, LLC, the various financial institutions party thereto and PNC Bank, National Association (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on November 20, 2012).
10.8	Amended and Restated Guarantee and Collateral Agreement, dated as of June 1, 2011, made by each of the Guarantors 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 (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
10.9	Distribution Agreement between Fluor Corporation and Massey Energy Company dated as of November 30, 2000 (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Massey Energy Company (File No. 1-7775) filed on December 15, 2000.)
10.10	Tax Sharing Agreement between Fluor Corporation, Massey Energy Company and A.T. Massey Coal Company, Inc. dated as of November 30, 2000 (Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Massey Energy Company (File No. 1-7775) filed on December 15, 2000.)
10.11‡	Alpha Natural Resources, Inc. 2008 Annual Incentive Bonus Plan (effective May 14, 2008, and last amended on November 16, 2010) (Incorporated by reference to Exhibit 10.25 of the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on February 25, 2011.)
10.12‡	Non-EmployeeDirectorCompensatoryArrangements(IncorporatedbyreferencetoExhibit10.27oftheAnnualReportonForm10-KofAlphaNaturalResources,Inc.(FileNo.1-32331)filedonFebruary25,2011.)
10.13‡	Alpha Natural Resources, Inc. Key Employee Separation Plan, as amended and restated on April 6, 2012 (Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on April 11, 2012.)
10.14‡	Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan, As Amended and Restated Effective August 1, 2012 (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 8, 2012.)
10.15‡	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 filed by Alpha Natural Resources, Inc. (File No. 1-32331) on November 5, 2010.)
10.16‡	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.)

182

Exhibit No.	Description of Exhibit
10.17‡	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 on November 5, 2010.)
10.18‡	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 on November 5, 2010.)
10.19‡	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 on November 5, 2010.)
10.20‡	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 on March 1, 2010.)
10.21‡	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. (Filed No. 1-32331) filed on March 1, 2010.)
10.22‡	Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.1 to Registration Statement on Form S-8 (File No. 333-166959) filed on May 19, 2010.)
10.23‡	Form of Restricted Stock Unit Award Agreement for Employees (Grades 22-30) under the Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on February 29, 2012.)
10.24‡	Form of Restricted Stock Unit Award Agreement for Employees (Alternative) (Grades 22-30) under the Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan (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 10, 2012.)
10.25‡	Form of Performance Share Unit Award Agreement for Employees (Grades 22-30) under the Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.22 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on February 29, 2012.)
10.26‡	Form of Performance Share Unit Award Agreement for Employees (Alternative) (Grades 22-30) under the Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan (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 10, 2012.)
10.27‡	Form of Performance-Based Incentive Compensation Award Agreement for Employees (Grades 22-30) under the Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan (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 May 10, 2012.)
10.28‡	Form of Restricted Stock Unit Award Agreement for Non-Employee Directors under the Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.23 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on February 29, 2012.)
10.29‡	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.)
10.30‡	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.)
10.31‡	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.)

183

Exhibit No.	Description of Exhibit
10.32‡	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.)
10.33‡	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.)
10.34‡	Form of Amendment to Director Deferred Compensation Agreement (Incorporated by reference to Exhibit 10.38 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 27, 2009.)
10.35‡	Form of Performance Share Award Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (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.)
10.36‡	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.)
10.37‡	Form of Restricted Stock Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (for grants after March 3, 2006) (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.)
10.38‡	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.)
10.39‡	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.)
10.40‡	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.)
10.41‡	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.)
10.42‡	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 filed by Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010.)
10.43‡	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.)
10.44‡	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.)

184

Exhibit No.	Description of Exhibit
10.45‡	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.)
10.46‡	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.)
10.47‡	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.)
10.48‡	Form of Rollover Nonqualified Stock Option Agreement for Employees 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.)
10.49‡	Form of Rollover Restricted Stock Unit Agreement for Employees under the Alpha Natural Resources, Inc. Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 99.5 to the Registration Statements on Form S-8 (File No. 333-160937) of Alpha Natural Resources, Inc. filed on July 31, 2009.)
10.50‡	Form of Rollover Restricted Stock Unit Agreement for Employees under the Alpha Natural Resources, Inc. Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 99.6 to the Registration Statements on Form S-8 (File No. 333-160937) of Alpha Natural Resources, Inc. filed on July 31, 2009.)
10.51‡	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.)
10.52‡	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.)
10.53‡	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.)
10.54‡	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.)
10.55‡	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.)
10.56‡	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.)
10.57‡	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.)
10.58‡	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.)

185

Exhibit No.	Description of Exhibit
10.59‡	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.)
10.60‡	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.)
10.61‡	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.)
10.62‡	Alpha Natural Resources, Inc. 2006 Stock and Incentive Compensation Plan (Incorporated by reference to Exhibit 99.1 of the Post-Effective Amendment No. 1 on Form S-8 of Alpha Natural Resources, Inc. (File No. 333-172888) filed on June 1, 2011.)
10.63‡	Form of Restricted Stock Unit Award Agreement for Non-Employee Directors under the Alpha Natural Resources, Inc. 2006 Stock and Incentive Compensation Plan (Incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (Filed No. 1-32331) filed on May 10, 2012.)
10.64‡	Alpha Natural Resources, Inc. 2012 Long-Term Incentive Plan (Incorporated by reference to Exhibit 99.1 to the Registration Statement on Form S-8 of Alpha Natural Resources, Inc. (File No. 333-181478) filed on May 17, 2012).
10.65‡	Form of Alpha Natural Resources, Inc. Performance Share Unit Award Agreement for Employees (Grades 22-30) under the 2012 Long-Term Incentive Plan (Incorporated by reference to Exhibit 99.2 to the Registration Statement on Form S-8 of Alpha Natural Resources, Inc. (File No. 333-181478) filed on May 17, 2012).
10.66‡	Form of Alpha Natural Resources, Inc. Performance Share Unit Award Agreement for Employees under the 2012 Long-Term Incentive Plan (Alternative) (Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on May 17, 2012).
10.67‡	Form of Alpha Natural Resources, Inc. Restricted Stock Unit Award Agreement for Employees (Grades 22-30) under the 2012 Long-Term Incentive Plan (Incorporated by reference to Exhibit 99.3 to the Registration Statement on Form S-8 of Alpha Natural Resources, Inc. (File No. 333-181478) filed on May 17, 2012).
10.68‡	Form of Alpha Natural Resources, Inc. Restricted Stock Unit Award Agreement for Non-Employee Directors under the 2012 Long-Term Incentive Plan (Incorporated by reference to Exhibit 99.4 to the Registration Statement on Form S-8 of Alpha Natural Resources, Inc. (File No. 333-181478) filed on May 17, 2012).
10.69*‡	Form of Alpha Natural Resources, Inc. Restricted Stock Unit Award Agreement for Non-Employee Directors under the Alpha Natural Resources, Inc. 2012 Long-Term Incentive Plan (for grants after January 1, 2013).
10.70*‡	Form of Alpha Natural Resources, Inc. Non-Employee Director Deferral Elections (effective January 1, 2013).
10.71‡	Form of Retention Restricted Stock Unit Award Agreement for Employees under the Alpha Natural Resources, Inc. 2012 Long-Term Incentive Plan (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 8, 2012.)
10.72‡	Separation of Employment Agreement and General Release dated April 11, 2012, by and between Alpha Natural Resources, Inc. and Kurt D. Kost (Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on April 11, 2012).
10.73‡	Separation Agreement and General Release, dated September 18, 2012, by and between Alpha Natural Resources, Inc. and Randy L. McMillion, (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on September 18, 2012).
12.1*	Computation of Ratio of Earnings to Fixed Charges

186

Exhibit No.	Description of Exhibit
12.2*	Computation of Other Ratios
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
95*	Mine Safety Disclosure Exhibit
101.INS*	XBRL instance document
101.SCH*	XBRL taxonomy extension schema
101.CAL*	XBRL taxonomy extension calculation linkbase
101.LAB*	XBRL taxonomy extension label linkbase
101.PRE*	XBRL taxonomy extension presentation linkbase

*     Filed herewith.

‡      Management contract of compensatory plan or arrangement

187