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, 2013

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, 2013, was approximately $703 million based on the closing price of theCompany’s common stock as reported that date on the New York Stock Exchange of $5.45 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 21, 2014 — 221,069,911 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, 2013.

2013 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	5
Item 1A.	Risk Factors	30
Item 1B.	Unresolved Staff Comments	47
Item 2.	Properties	47
Item 3.	Legal Proceedings	53
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	59
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	89
Item 8.	Financial Statements and Supplementary Data	90
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	156
Item 9A.	Controls and Procedures	156
Item 9B.	Other Information	158
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	159
Item 11.	Executive Compensation	159
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	160
Item 13.	Certain Relationships and Related Transactions and Director Independence	160
Item 14.	Principal Accountant Fees and Services	160
PART IV
Item 15.	Exhibits and Financial Statement Schedules	160

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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, including demand for U.S. coal exports;

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

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

• our production capabilities and costs;

• inherent risks of coal mining beyond our control, and our ability to utilize our coal assets fully and replace reserves as they are depleted;

• changes in environmental laws and regulations, including those directly affecting our coal mining and production, and those affecting our customers' coal usage, including potential climate change initiatives;

• changes in safety and health laws and regulations and their implementation, and the ability to comply with those changes;

• competition in coal markets;

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

• global economic, capital market or political conditions, including a prolonged economic downturn in the markets in which we operate and disruptions 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, renewal or acquisition of, terms of and performance of customers under coal supply arrangements and the refusal by our customers to receive coal under agreed contract terms;

• 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;

• attracting and retaining key personnel and other employee workforce factors, such as labor relations;

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

• funding for and changes in postretirement benefit obligations, pension obligations, including multi-employer pension plans, and federal and state black lung obligations;

• cybersecurity attacks or failures, threats to physical security, extreme weather conditions or other natural disasters;

• 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;

• our ability to negotiate new United Mine Workers of America ("UMWA") wage agreements on terms acceptable to us, increased unionization of our workforce in the future, and any strikes by our workforce;

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

• inflationary pressures on supplies and labor and significant or rapid increases in commodity prices;

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

• disruption in third party coal supplies;

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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;

• the consummation of financing transactions, acquisitions or dispositions and the related effects on our business and financial position;

• indemnification of certain obligations not being met;

• goodwill impairment charges;

• 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 and other terms in our secured credit facility and the indentures governing our outstanding debt securities;

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

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

• other factors, including the other factors discussed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and “Risk Factors” sections of this report.

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

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. 

We are one of America’s premier coal suppliers, ranked second largest among publicly-traded U.S. coal producers as measured by 2013 consolidated revenues of $5.0 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, 2013, we operated 81 mines and 25 coal preparation plants in Northern and Central Appalachia and the Powder River Basin, with approximately 10,500 employees.

We have two reportable segments: Eastern Coal Operations and Western Coal Operations. Eastern Coal Operations consists of the mines in Northern and Central Appalachia and our coal brokerage activities. Western Coal Operations consists of two Powder River Basin mines in Wyoming. Our All Other segment includes an idled underground mine in Illinois; expenses associated with certain closed mines; Dry Systems Technologies; revenues and royalties from the sale of natural gas; 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 77% of our 2013 coal sales volume. Metallurgical coal, which is used primarily to make coke, a key component in the steel making process, accounted for approximately 23% of our 2013 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.

During the twelve months ended December 31, 2013, we sold a total of 86.9 million tons of steam and metallurgical coal and generated coal revenues of $4.3 billion. EBITDA was ($216.9) million, and we incurred a loss from operations of $1.1 billion. We define and reconcile EBITDA in Item 6-Selected Financial Data. Our coal sales during 2013 consisted of 86.9 million tons of coal, of which 86.0 million tons were produced and processed by us. We also purchased 0.9 million tons from third parties, of which 0.5 million tons we fully processed at our processing plants prior to resale, 0.2 million tons we blended with our coal prior to resale, and 0.2 million tons in raw product we shipped direct to our customers without any further processing or blending on our behalf. Approximately 43% of our total revenues in 2013 was derived from sales made to customers outside the United States, primarily in Turkey, Netherlands, Italy, India, and South Korea.

As of December 31, 2013, we owned or leased approximately 4.3 billion tons of proven and probable coal reserves, of which approximately 1.4 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 the foreseeable future.

During the twelve months ended December 31, 2013, we tested our long-lived assets and goodwill for impairment due to a longer than expected recovery in the metallurgical coal markets and lower production and shipment levels compared with previous estimates. We recorded $253.1 million in goodwill impairment expense related to a reporting unit in our Eastern Coal Operations. Additionally, during 2013, we idled certain mines located in West Virginia and announced a plan to further reduce operating and support expenses by approximately $200.0 million annually in response to weak market conditions and recorded asset impairment and restructuring expenses of $37.3 million, of which $15.8 million was for severance and related benefits, $9.6 million for professional fees and other expenses, $1.9 million for other asset impairment expenses and $10.0 million of reserves for assets that may not be recoverable in the future. We will continue to evaluate market conditions and may make further adjustments to our operations if market conditions warrant. See Notes 10 and 11 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K related to asset impairment and restructuring and goodwill impairment, respectively.

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On July 15, 2013, we announced that production was suspended at our Cumberland mine due to adverse geological conditions in the mine’s headgate area. On August 15, 2013, we announced that production had resumed. The longwall production outage and a longer than scheduled longwall move at the Cumberland mine is estimated to have reduced 2013 Eastern steam coal shipments by approximately 700,000 tons.

History

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.

On June 1, 2011, we completed our acquisition (the “Massey Acquisition”) of Massey Energy Company (“Massey”) for approximately $6.7 billion. 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 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.

In 2010, we entered into a 50/50 joint venture (the “Alpha Shale JV”) with Rice Drilling C LLC, a wholly owned subsidiary of Rice Drilling B LLC, in order to develop a portion of our Marcellus Shale natural gas holdings in southwest Pennsylvania. On December 6, 2013, we, Rice Drilling C LLC and Rice Energy Inc. (“Rice Energy”) entered into a transaction agreement (the “Transaction Agreement”). Pursuant to the Transaction Agreement, we agreed to transfer our 50% interest in the Alpha Shale JV to Rice Energy in exchange for total consideration of $300.0 million, consisting of $100.0 million of cash and the issuance by Rice Energy to us of approximately 9.5 million shares of common stock concurrently with the consummation of Rice Energy’s initial public offering. On January 29, 2014, Rice Energy completed its initial public offering, and on the same date, issued approximately 9.5 million shares of common stock and paid $100.0 million in cash to us.

Competitive Strengths

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

We are the second largest publicly traded coal producer in the United States based on 2013 consolidated revenues and have significant coal reserves. Based on 2013 consolidated revenues of $5.0 billion, we are the second largest publicly traded coal producer in the United States. As of December 31, 2013, we controlled approximately 4.3 billion tons of proven and probable coal reserves.

We have a diverse portfolio of coal mining operations and reserves. As of December 31, 2013, we operated a total of 81 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, together with considerable diversity in the means by which we transport coal provides us with a significant competitive advantage, allowing us maximum optionality and leverage in serving customers and facilitating the most economical means of transportation.

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 are committed to our industry-leading safety program Running Right, an employee engagement safety-based management approach. During 2013, we experienced a 16% improvement in our incident rate and a 28% reduction in our significant and substantial Mine Safety and Health Administration (“MSHA”) citations, as compared to 2012. The Running Right Leadership Academy, which opened in mid-2013, provides a world-class training facility that integrates our Running Right program with other safety, operations improvement and maintenance improvement initiatives.

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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 the third largest metallurgical coal producer in the world with a broad base of international customers. We are the largest producer of metallurgical coal in the United States and serve customers in approximately 26 countries. We have the capacity to export 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 Dominion Terminal Associates (“DTA”), a coal export terminal located in Newport News, Virginia. Our export capacity and our international customer base are important to our metallurgical coal franchise and will facilitate growth of our thermal export franchise. Our industry leading export volumes also afford us a competitive advantage in negotiating transportation rates to move coal to export terminals which enhances our overall net revenues.

We have interests in significant acreage in the Marcellus Shale natural gas field of Southwestern Pennsylvania.In 2010, we contributed a portion of this acreage (approximately 7,500 acres) to the Alpha Shale joint venture with an affiliate of Rice Energy. In January 2014, we exchanged this joint venture interest for $100 million of cash plus $200 million of shares in Rice Energy in connection with Rice Energy’s initial public offering. The balance of our Marcellus Shale acreage consists of approximately 10,000 acres, which we have contributed to a joint venture for development of natural gas production. 

Business Strategy

Our objective is to increase shareholder value and focus on free cash flow generation by creating a durable, sustainable steam coal portfolio, supporting and augmenting our metallurgical coal franchise and addressing 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 and operating cost improvement through our culture of workforce involvement by leveraging our strong base of experienced, well-trained employees. The Running Right Leadership Academy provides us an industry leading facility with which to develop our employees’ job skills while enhancing their knowledge of and commitment to safe work practices.

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 seaborne coal industry are favorable and we believe that the U.S. will continue to consume significant volumes of coal. 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 low natural gas prices and an increasingly stringent regulatory environment, we expect to shift our strategy as necessary to increase export thermal sales.

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 basins, 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.

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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

At certain of our mines in the Northern Appalachia basin we utilize longwall mining techniques which are the most productive underground mining methods 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 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

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purposes. Of our estimated 4.3 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”) 2013 International Energy Outlook, world-wide economically recoverable coal reserves using today’s technology are estimated to be approximately 946 billion tons. Also according to the 2013 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 238 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 2013.

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	Actual (1)			Preliminary (1) (2)	Projected (1)		Annual Growth
Consumption by Sector	2010	2011	2012	2013	2018	2033	2013-2018		2018-2033
	(Tons in millions)
Electric Generation	975	929	828	859	854	963	-0.1	%	0.4	%
Industrial	49	46	50	49	50	50	0.4	%	0.2	%
Steel Production	21	21	25	23	23	19	-0.6	%	-1.8	%
Coal-to-Liquids Processes	—	—	—	—	—	4			6.6	%
Residential/Commercial	3	3	3	3	3	3	-0.2	%	-0.2	%
Export	82	107	123	106	122	151	3.0	%	1.2	%
Total	1,130	1,106	1,029	1,040	1,052	1,190

 ___________________________

⁽¹⁾  Data sourced from the U.S. Department of Energy’s EIA’s 2013 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 50% 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 2013, non-hydropower renewable power generation accounted for 6.2% of all the electricity generated in the United States, and wind and solar power represented 4.3% 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 2018 are as follows:

	Range of Total System Levelized Costs (2010 $/megawatthour) for Plants Entering Service in 2018
Plant Type (1)	Minimum		Average		Maximum
Conventional Coal	$	89.50	$	100.10	$	118.30
Advanced Coal	$	112.60	$	123.00	$	137.90
Conventional Natural Gas Combined Cycle	$	62.50	$	67.10	$	78.20
Conventional Natural Gas Combustion Turbine	$	104.00	$	130.30	$	149.80
Advanced Nuclear	$	104.40	$	108.40	$	115.30
Geothermal	$	81.40	$	89.60	$	100.30
Biomass	$	98.00	$	111.00	$	130.80

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⁽¹⁾  Data sourced from the U.S. Department of Energy’s EIA 2013 Annual Energy Outlook.

Coal Production.  United States coal production was approximately 1 billion tons in 2013. 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.

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	Actual (1)			Preliminary (1) (2)	Projected (1)		Annual Growth
Production by Region	2010	2011	2012	2013	2018	2033	2013-2018		2018-2033
	(Tons in millions)
Powder River Basin	428	426	400	424	397	479	-1.0	%	1.3	%
Central Appalachia	186	185	171	145	114	99	-4.5	%	-0.8	%
Northern Appalachia	130	133	128	139	165	173	3.5	%	0.3	%
Illinois Basin	110	119	123	112	139	161	4.4	%	1.0	%
Other	230	232	201	202	218	240	1.7	%	0.6	%
Total	1,084	1,095	1,023	1,022	1,033	1,152

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⁽¹⁾  Data sourced from the U.S. Department of Energy’s EIA’s 2013 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 2013, imports accounted for a relatively small percentage of total U.S coal consumption. Approximately 1.0% of total U.S. coal consumption in 2013 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 2013 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.

Demand for our metallurgical coal and the prices that we will be able to obtain for metallurgical coal will depend to a large extent on the demand for U.S. and international steel, which is influenced by factors beyond our control, including overall economic activity and the availability and relative cost of substitute materials. In the export metallurgical market we largely compete with producers from Australia, Canada, and other international producers of metallurgical coal on many of the same factors as in the U.S. market. Competition in the export market is also impacted by fluctuations in relative foreign exchange rates and costs of inland and ocean transportation, among other factors.

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, 2013, our operations include 25 preparation plants, each of which receive, blend, process and ship coal that is produced from one or more of our 81 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 2013, most of our preparation plants also processed coal that we purchased from third party producers before reselling it to our customers.

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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, 2013:

Coal Operations

			Preparation Plants/Shipping Points as of December 31, 2013	Number and Type of Mines as of December 31, 2013				2013 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, Holden 29, Homer III / Inman, Kepler, Kingston, Knox Creek, Litwar, Mammoth, Marfork, McClure, Pax, Pigeon Creek, Power Mountain, Rockspring, Roxana, Sidney, Toms Creek, Zigmond	50	13	63	Barge, CSX, NS, RJCC, Truck	36,083
	Northern Appalachia	Pennsylvania	Clymer, Cumberland, Emerald, and Portage	7	9	16	Barge, Truck, CSX, NS	11,546
West	Powder River Basin	Wyoming	Belle Ayr and Eagle Butte	—	2	2	BNSF, UP, Truck	38,164
	Total from active operations			57	24	81		85,793

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⁽¹⁾  Includes coal purchased from third-party producers that was processed at our preparation plants in 2013.

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 902.0 million tons of reserves through our operations in NAPP. Approximately 148.9 million tons are assigned to active mines and 753.1 million tons are unassigned. During 2013, approximately 18% of the shipments were marketed as high volatility metallurgical coal to export customers. There are approximately 1,700 salaried and hourly employees at our operations in NAPP as of December 31, 2013. 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 5.6 million tons of coal in 2013. 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 3.8 million tons of coal in 2013. In the second quarter of 2014, Emerald will move its longwall to the final district within its life-of-mine plan. The time required to complete mining in the new district and its productivity will depend on geologic conditions and the ability to mine under or around surface obstacles. Emerald has the ability to store clean coal and blend variable sulfur products to meet customer requirements. All of Emerald’s coal is processed through a preparation plant before being loaded into unit trains operated by the Norfolk Southern Railway or CSX Transportation. The mine also has the option to ship a portion of its coal by truck.

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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 2013, these operations shipped 2.4 million tons.

Our operations in Central Appalachia (“CAPP”) consist of 50 underground mines, 13 surface mines and 21 preparation plants, a portion of which are operated by independent contractors. Our operations in CAPP collectively shipped 36.6 million tons in 2013. We control approximately 2,647.7 million tons of coal reserves through our operations in CAPP. Approximately 1,234.0 million tons are assigned to active mines and approximately 1,413.7 million tons are unassigned. There are approximately 7,900 salaried and hourly employees at our operations in CAPP as of December 31, 2013. 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, Inman, Kepler, Kingston, Knox Creek, Mammoth, Marfork, Rockspring, Sidney, and Zigmond. In addition, we transport coal by truck and belt to our Homer III loadout.

We transport coal produced at certain of our mines by truck to the following preparation plants: Cave Branch, Erbacon, Green Valley, Litwar, McClure, Pigeon Creek, Power Mountain, Roxanna, and Toms Creek. In addition, we transport coal by truck to our Holden 29 and Pax loadouts.

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 surface mining operations, which collectively shipped 38.2 million tons in 2013. Coal is mined primarily using the truck and shovel mining method. We control approximately 737.1 million tons of coal reserves in the Powder River Basin and all of the coal reserves are assigned to active mines. There are approximately 500 salaried and hourly employees in our Powder River Basin operations.

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 and no washing is necessary. Belle Ayr shipped 18.3 million tons of coal in 2013. 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 and no washing is necessary. Eagle Butte shipped 19.9 million tons of coal in 2013. 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:

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

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patented particulate scrubbers and filters for underground diesel engine applications and rebuilds underground mining equipment for external customers and our subsidiaries.

Natural Gas. We also have interests in significant acreage in the Marcellus Shale natural gas field of Southwestern Pennsylvania, in one of the Marcellus’ most productive regions. In 2010, we contributed a portion of this acreage (approximately 7,500 acres) to the Alpha Shale joint venture with an affiliate of Rice Energy. In January 2014, we exchanged this joint venture interest for $100.0 million of cash plus $200.0 million of shares in Rice Energy in connection with Rice Energy’s initial public offering. The balance of our Marcellus Shale acreage consists of approximately 10,000 acres, which we have contributed to a joint venture for development of natural gas production.

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 2013 we shipped a total of 4.6 milliontons of coal to our customers through the terminal. We make periodic cash payments in respect of the terminal for net operating expenses. We receive fees from third parties for use of our unused throughput. 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 approximately 40 employees as of December 31, 2013, and consists of sales managers, distribution/traffic managers, contract administrators and administrative personnel. In 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 86.9 million tons of coal in 2013, consisting of 86.0 million tons of coal produced and processed by us, and 0.9 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 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. 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.

The breakdown of tons sold for 2013, 2012, and 2011 is set forth in the table below:

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	Steam Coal Sales (1)					Metallurgical Coal Sales (1)
Year	Tons	% of Total Sales  Volume		% of Total Revenues		Tons	% of Total Sales  Volume		% of Total Revenues
	(In millions, except percentages)
2013	66.8	77	%	50	%	20.1	23	%	50	%
2012	88.5	81	%	52	%	20.3	19	%	48	%
2011 (2)	87.1	82	%	46	%	19.2	18	%	54	%

_________________________________

⁽¹⁾  Sales of steam coal during 2013, 2012, and 2011 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 seven month period from June 1, 2011 through December 31, 2011.

We sold coal to approximately 170 different customers in 2013. Our top ten customers in 2013 accounted for approximately 43% of 2013 total revenues and our largest customer during 2013 accounted for approximately 9% of 2013 total revenues. The following table provides information regarding exports in 2013, 2012, and 2011 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
2013	19.5	22	%		$2,151.5	43	%
2012	21.3	20	%		$2,930.6	42	%
2011 (1)	16.3	15	%		$3,096.0	44	%

 ____________________________

⁽¹⁾  The amounts for 2011 include the results of operations for Massey for the seven month period from June 1, 2011 through December 31, 2011.

Export shipments serviced customers in 29 countries across North America, Europe, South America, Asia and Africa during 2013 and customers in 27 countries across North America, Europe, South America, Asia and Africa in 2012 and 2011. Turkey was the largest export market in 2013, with sales to Turkey accounting for approximately 14% of total export revenuesand 6% of total revenues. 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. All of our sales are made in U.S. dollars.

We sometimes enter into long-term contracts (exceeding one year in duration) with our customers. These arrangements, which are most common in the metallurgical coal market and certain portions of the steam coal market, result from bidding and negotiations with customers, and the terms of these contracts therefore vary. Terms of these agreements may address coal quality requirements, quantity parameters, flexibility and adjustment mechanisms, permitted sources of supply, treatment of environmental constraints, options to extend, force majeure, suspension, termination and assignment issues, the allocation between the parties of the cost of complying with future governmental regulations, and many other matters.

Increasingly, these long-term agreements contain price adjustment and price reopener features, provisions permitting renegotiation or modification of coal sale prices, and similar terms. Provisions of this sort make it more difficult for us to predict the prices we will receive for our coal during the course of the agreement.

During 2013, approximately 45% and 69% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts. 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.

Our sales backlog, including backlog subject to price reopener and/or extension provisions, was approximately 104.4 million tons as of January 31, 2014 and approximately 162.7 million tons for the comparable period in 2013. Of these tons, approximately 73% and 49%, respectively, were expected to be filled within one year.

Distribution

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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 each customer’s needs. Our produced and processed coal is loaded from our 25 preparation plants, loadout facilities, and in certain cases directly from our mines. The coal we purchase is loaded in some cases directly from mines and preparation plants operated by third parties or from an export terminal. Virtually all of our coal is transported from the mine to our preparation plants by truck or rail, and then from the preparation plant to the customer by means of railroads, trucks, barge lines, lake-going and ocean-going vessels from terminal facilities. Rail shipments constituted approximately 67% of total shipments of coal volume produced and processed from our mines to the preparation plant to the customer in 2013. The balance was shipped from our preparation plants, loadout facilities or mines via truck. In 2013, approximately 8% of our coal sales volume was delivered to our customers through transport on the Great Lakes and domestic rivers, approximately 6% was moved through the Norfolk Southern export facility at Norfolk, Virginia, approximately 11% was moved through the coal export terminal at Newport News, Virginia operated by DTA, and approximately 4% 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 2013, 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, 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.

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, 2013, we had approximately 10,500 employees. As of December 31, 2013, the UMWA represented approximately 12% of our total employees. Our UMWA-represented employees are located in Kentucky, Virginia, West Virginia and Pennsylvania, and produced approximately 11% of our coal sales volume during the fiscal year ended December 31, 2013. Relations with organized labor are important to our success, and we believe our relations with our employees are 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. During 2013, we incurred capital expenditures of approximately $18.6 million for regulatory compliance. 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

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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.

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 to avoid injuries if a person is too close to the equipment.

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, 2013, 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 2013 and 2012 for our obligations to the Combined Benefit Fund were approximately $0.5million and $0.6 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 2013 and 2012 for our obligation to the 1992 Plan were $1.4 million and $1.5 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 at least a year or more 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; blasting; 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 $0.28 per ton on surface-mined coal and $0.12 per ton on deep-mined coal.

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. Notwithstanding the 2011 and 2012 deadlines, 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 these bonds or their cost 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 some of the coalbed methane is captured at 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. Subsequently, the 18th and 19th UNFCCCs 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. In June 2013, President Obama directed the EPA to develop and issue a new proposed rule regulating carbon emissions from new electric generating units. In September 2013, EPA issued the proposed rule, which remains pending. In addition, President Obama directed the EPA to develop and issue a separate proposed rule, by June 2014, with respect to carbon emissions from existing, modified and reconstructed electric generating units, to issue a final rule by June 2015, and to require states to issue implementation plans for the new rules by June 2016. We cannot predict the financial impact of these proposals on our operations or our customers at this time. 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, the United States Supreme Court is expected to issue a decision by June 2014 determining whether the EPA made a reasonable determination that adoption of the motor vehicle standards triggers the Prevention of Significant Deterioration and the Title V Greenhouse Gas Tailoring Rule permit obligations for stationary sources.

In October 2013, the Treasury Department introduced guidelines indicating that the United States government would generally not support public financing of new foreign coal-fired power plants that did not meet the criteria set forth in the September 2013 proposed regulations for new domestic coal-fired power plants.

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. In February 2013, the RGGI released an updated model rule that reduces the regional CO2 budget beginning in 2014.

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

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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 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 January 2013, 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; however, in September 2013, President Obama instructed the EPA to withdraw its January 2010 proposal. The EPA’s review of the updated science regarding ozone was scheduled for completion in 2013 and may, upon completion, provide the basis for a more stringent ozone NAAQS. 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

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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 has appealed 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. CASPR (if upheld), 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 have up to four years to comply. In 2013, EPA issued technical revisions to the MATS, and EPA is considering further revisions to its provision governing startup and shutdown of generating units. The MATS is subject to a pending court challenge in the U.S. Court of Appeals for the District of Columbia Circuit. 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 embankments, refuse slurry impoundments, valley fills or for conducting certain other activities in or adjacent to streams. 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. In November 2013, the COE and the EPA announced that a draft rule had been sent to the Office of Management and Budget for interagency review in advance of its official release but no timetable for issuance was provided.

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.

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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 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 NWP 21 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 NWP 21 as reissued is of limited value to our operations. In addition, in April 2013, the United States Court of Appeals for the Sixth Circuit invalidated and set aside the NWP 21 issued in 2007 as arbitrary and capricious because the COE did not consider the continuing effects of past permit authorizations or adequately explain how mitigation would reduce the environmental harm of future permitted activities. 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 was 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 not 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 appealed this decision to the United States Court of Appeals, which in April 2013 found in favor of EPA. In November 2013, the mining company submitted a formal request for review by the United States Supreme Court. If the United States Court of Appeals’ decision ultimately stands, 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, 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

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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 23, 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 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 23 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

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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 2013 and 2012, we reduced or halted production at certain of our mines, and we could further reduce our production in the future if coal prices remain depressed or decline further.

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 23% and 19% of our coal sales volume in 2013 and 2012, 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 also depends 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 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.

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 77% and 81% of our coal sales volume during 2013 and 2012, 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, mild North American winters typically result 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

• the coal inventories of 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 will be fired by natural gas. This result is likely because natural gas-fired plants 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

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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.

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 22% and 20% of our coal sales volume in 2013 and 2012, respectively. In addition to the factors described above, demand for and viability of 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, for example the Australian dollar, 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 2013 accounted for approximately 9% of our total revenues, and sales to our ten largest customers accounted for approximately 43%. 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 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, 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 2013, approximately 45% and 69% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts. As of January 31, 2014, 10% of our planned shipments for 2014 were uncommitted. We may not be able to enter into coal supply agreements to sell this uncommitted production on terms, including pricing terms, as favorable to us as under 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 terms, including pricing terms, less favorable to us.

In large part as a result of increasing and frequently changing regulation, as described above, and natural gas pricing, 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, our having fewer customers with a contractual obligation to purchase coal from us increases the risk that we will not have a consistent market for our production and may require us to sell more coal in the spot market, where prices may be lower than we would expect a customer to pay for a contractually 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 have traditionally provided. 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 may 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 43% and 42% of our total revenues from coal sales made to customers outside the United States in 2013 and 2012, respectively.

Regulatory and Legal Risks

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

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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; a September 2013 proposed rule to impose federal limits on GHG emissions from new power plants; and an anticipated June 2014 proposed rule to impose federal limits on GHG emissions from existing, modified and reconstructed power plants;

• Treasury Department guidelines introduced in October 2013 curtailing United States government support for public financing of new foreign coal-fired 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.

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:

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• 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.

We are subject to a number of 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 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. We have reached agreement on all material terms of settlement with the plaintiffs in the securities class brought by Massey stockholders in the wake of the UBB explosion (see “Legal Proceedings”) and the United States District Court for the Southern District of West Virginia (the “Court”) entered an order preliminarily approving the settlement. The settlement, however, remains subject to the final approval of the Court following a settlement hearing. Whether the Court will approve the settlement remains uncertain.

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.

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;

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• 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:

• federal and state agencies and citizen groups have increasingly focused on the amount of selenium and other constituents in our water 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, 2013.

MSHA and state regulators may also order the temporary closing of 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 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 operate and maintain coal slurry impoundments at a number of our mining complexes. 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

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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.

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 render continued operations at certain mines economically unfeasible or impractical or otherwise 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. In some circumstances, regulators could seek to revoke permits previously issued. 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 United States Court of Appeals for the Sixth Circuit has invalidated the Nationwide Permit 21 permits issued in 2007. In addition, 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 claims arising from previously divested businesses, 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

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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 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.

There is litigation 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 coal supply agreements may result in economic penalties upon our failure to meet specifications.

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

As a result of these issues, we may not achieve the revenue or profit we expect to achieve from our coal supply agreements.

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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 in our eastern 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 (for example, we temporarily suspended production at our Cumberland underground longwall mine in Green County, Pennsylvania in 2013 while we addressed adverse geological conditions in the mine);

• 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;

• difficulties associated with mining under or around surface obstacles;

• 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.

In addition, our mining operations are increasingly concentrated in a smaller number of mines. As a result, the effects of any of these conditions or events may be exacerbated and may have a disproportionate impact on our results of operations and 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.

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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 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, and the Plan’s funded status is reviewed by a certifying actuary. 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 2013, we received notice that the plan was considered to be in seriously endangered status for the July 1, 2013 plan year, and the plan was projected to have an accumulated funding deficiency by the plan year beginning July 1, 2019. 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. In April 2013, we received an update to the funding improvement plan that projected a funded percentage of 70% as of July 1, 2014. If the funded status is not adequate as of 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 2013, we did not make any contributions to our pension plans. We currently do not expect to make any contributions in 2014 for our defined benefit retirement plans to maintain a funding ratio of at least 80%.

As of December 31, 2013, our annual measurement date, our defined benefit pension plans were underfunded by $72.8 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, 2013, as reflected in Note 20 to our Consolidated Financial Statements, included $942.7 million of postretirement obligations, $94.1 million of defined benefit pension and supplemental employee retirement plan obligations,$156.7 million of self-insured workers’ compensation obligations and $144.6 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

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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.

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 $799.4 million as of December 31, 2013, 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

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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.

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 due to lost production capacity from diminished or discontinued operations at those mines, as well as lay-offs, write-off charges and other costs, potentially causing an adverse effect 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.

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 2013 coal production came from mines operated by union-free employees, and approximately 88% of our workforce is union-free, as of December 31, 2013. 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.

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 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.

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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 2013, 67% 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 revenues and results of 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 results of operations.

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 0.4 million tons of coal purchased from third parties during 2013, representing approximately 0.5% of our total coal sales volume during 2013. 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.

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.

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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 and strategic partners;

• 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 or other strategic transactions 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 or other strategic transactions.

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 strategic 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 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 $253.1 million during the year ended December 31, 2013 to reduce the carrying value of goodwill to its implied fair value for one of our reporting units in our Eastern 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.

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

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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 to 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 cash flow 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 enter into commodity swap and option agreements for a portion of our diesel fuel needs and a portion of our indexed coal sales agreements to reduce the risk that changes in the market price of these items can have on our operations. None of these agreements have been designated as qualifying cash flow hedges, so we are required 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.

Factors affecting the natural gas and oil industries could adversely impact the value of certain of our assets.

We currently have assets related to the natural gas industry, including shares of common stock of Rice Energy, a natural gas and oil company operating in the Appalachian Basin, which we acquired in January 2014 in connection with Rice Energy’s initial public offering. The natural gas and oil markets have been volatile historically and prices in these markets are subject to wide fluctuation in response to relatively minor changes in supply and demand. Changes in supply and demand could be prompted by any number of factors, such as worldwide and regional economic and political conditions; the level of global exploration, production and inventories; natural gas prices; and transportation availability. Rice Energy is also subject to a number of other operational risks, and as a newly public company, the future performance of Rice Energy stock is uncertain. The value of our various gas assets, including our Rice Energy stock, could decrease as a result of these factors.

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 and a portion of our indexed coal sales agreements. As of December 31, 2013, we had financial swap contracts with respect to approximately 54% and 39% of our calendar year 2014 and 2015 expected diesel fuel needs, respectively, and for approximately 0.1 million tons of coal related to indexed sales agreements. While our hedging strategy provides us protection in the event of price increases in the case for diesel fuel and price decreases in the case of coal, it may also prevent us from participating in beneficial price changes. If prices for diesel fuel decrease significantly below our diesel swap prices or increase significantly above our coal 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, 2013, we had $3,577.7 million of indebtedness outstanding before discounts applied for financial reporting, representing 46% of our total capitalization, of which $258.4 million will mature in the next three years. In addition, at December 31, 2013, we had $134.0 million of letters of credit outstanding under our credit 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;

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• 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.

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 $1.1 billion, with no borrowings outstanding as of December 31, 2013. 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. We regularly evaluate opportunities to enhance our capital structure and financial flexibility through a variety of methods, including repayment or repurchase of outstanding debt, amendment of our credit facility and other facilities, and other methods. As a result of any of these actions, the restrictions and covenants that apply to us may become more restrictive or otherwise change.

Operating results below current levels, or at current levels for an extended period of time, 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 $300 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.

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The need 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, 2013, we had $134.0 million of letters of credit outstanding under our credit 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 $1.1 billion, all of which can be used to issue 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 for additional letters of credit, we may be unable to provide financial assurance for our mining operations.

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 decline in our actual or perceived 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 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.

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.

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

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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.

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

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“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.

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, 2013, we owned or leased total proven and probable coal reserves of approximately 4,316.5 million tons. We believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our current reserves are one of our strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.

Of the 4,316.5 million tons, approximately 2,120.0 million tons were assigned reserves that we expect to be mined in future operations. Approximately 2,196.5 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, 2013, 716.7 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, 2013, of 2,833.0 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, 2013, 16.9 million tons of reserves are owned and require no royalty or per-ton payments. Our remaining Wyoming reserve holdings at December 31, 2013, of 720.2 million tons were leased and were subject to the terms described above.

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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, 2013 were 29.7 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, 2013.

Reportable Segment	Coal Basin	Location	Total Recoverable Reserves Proven & Probable (1)	Proven Reserves		Probable Reserves
East	CAPP	Virginia, West Virginia, Kentucky	2,647.7	1,757.4		890.3
	NAPP	Pennsylvania	902.0	561.1		340.9
West	Powder River Basin	Wyoming	737.1	715.0		22.1
	Totals from active operations		4,286.8	3,033.5		1,253.3
	Percentages from active operations			71	%	29	%
N/A	Illinois Basin(4)	Illinois	29.7	21.5		8.2
	Total from all operations		4,316.5	3,055.0		1,261.5
	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, 2013.

			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	2,647.7	1,862.6		579.4		205.7		2,178.6		469.1
	NAPP	Pennsylvania	902.0	110.7		52.8		738.5		814.3		87.7
West	Powder River Basin	Wyoming	737.1	737.1		—		—		—		737.1
	Totals from active operations		4,286.8	2,710.4		632.2		944.2		2,992.9		1,293.9
	Percentages from active operations			63	%	15	%	22	%	70	%	30	%
N/A	Illinois Basin (4)	Illinois	29.7	—		—		29.7		—		29.7
	Total from all operations		4,316.5	2,710.4		632.2		973.9		2,992.9		1,323.6
	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, 2013.

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			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	2,647.7	1,234.0		1,413.7		280.1		2,367.6		Steam and Metallurgical
	NAPP	Pennsylvania	902.0	148.9		753.1		436.6		465.4		Steam and Metallurgical
West	Powder River Basin	Wyoming	737.1	737.1		—		16.9		720.2		Steam
	Total from active operations		4,286.8	2,120.0		2,166.8		733.6		3,553.2
	Percentage from active operations			49	%	51	%	17	%	83	%
N/A	Illinois Basin (4)	Illinois	29.7	—		29.7		—		29.7		Steam
	Total from all operations		4,316.5	2,120.0		2,196.5		733.6		3,582.9
	Percentage from all operations			49	%	51	%	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.

⁽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 maps show the locations of Alpha’s shipping points as of December 31, 2013:

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

Item 3. Legal Proceedings

For a description of the Company’s legal proceedings, see Note 23 to the Consolidated Financial Statements contained elsewhere in this Annual Report on Form 10-K, which is incorporated herein by reference.

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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.

2013	High	Low
First Quarter	$10.74	$7.37
Second Quarter	$8.40	$4.82
Third Quarter	$6.94	$4.78
Fourth Quarter	$8.30	$5.52

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

As of December 31, 2013, there were 5,361 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

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:

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• 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, 2013.

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 12/31/08 in stock or index, including reinvestment of dividends.

Fiscal year ending December 31

	12/31/2008		7/31/2009		12/31/2009		12/31/2010		6/1/2011		12/31/2011		12/31/2012		12/31/2013
Alpha Natural Resources	$	100.00	$	205.74	$	267.94	$	370.78	$	329.83	$	126.19	$	60.16	$	44.10
S&P 500	$	100.00	$	109.33	$	123.45	$	139.23	$	145.54	$	139.23	$	157.90	$	204.63
S&P 400	$	100.00	$	116.68	$	135.00	$	168.55	$	181.19	$	163.33	$	189.57	$	249.41
Russell 3000	$	100.00	$	110.75	$	125.46	$	143.96	$	151.14	$	142.64	$	162.58	$	212.89
Bloomberg US Coal Index	$	100.00	$	129.85	$	177.00	$	234.39	$	224.48	$	124.81	$	88.12	$	84.79

Repurchase of Common Stock

On August 22, 2011, the Board of Directors authorized a share repurchase program, which permits us to repurchase up to $600 million of our common stock from time to time, as market conditions warrant.

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The following table summarizes information about shares of common stock that were repurchased during the fourth quarter of 2013.

	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, 2013 through October 31, 2013	3,195	$	6.50	—	$	500,002
November 1, 2013 through November 30, 2013	532	$	5.98	—	$	500,002
December 1, 2013 through December 31, 2013	8,759	$	6.69	—	$	500,002
	12,486			—	$	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, 2013, the Company issued 51,000 shares of common stock to employees upon vesting of restricted stock units and repurchased 12,486 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 may 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, 2013 and 2012, and for the years ended December 31, 2013, 2012, and 2011 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 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. 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 seven month period from June 1, 2011 through December 31, 2011. Our consolidated results of operations for the years ended December 31, 2010 and 2009 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,
	2013			2012			2011			2010		2009
	(In thousands)
Statements of Operations Data:
Revenues:
Coal revenues	$	4,257,981		$	6,015,696		$	6,189,434		$	3,497,847	$	2,210,629
Freight and handling revenues	557,846			761,928			662,238			332,559		189,874
Other revenues (1)	137,681			197,260			256,009			86,750		95,004
Total revenues	4,953,508			6,974,884			7,107,681			3,917,156		2,495,507
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)	3,980,744			5,004,516			5,080,921			2,566,825		1,616,905
Freight and handling costs	557,846			761,928			662,238			332,559		189,874
Other expenses(1)	165,485			45,432			142,709			65,498		21,016
Depreciation, depletion and amortization	865,021			1,037,575			770,769			370,895		252,395
Amortization of acquired intangibles, net	5,056			(70,338		)	(114,422		)	226,793		127,608
Selling, general, and administrative expenses (exclusive of depreciation and amortization shown separately above)	158,987			209,788			382,250			180,975		170,414
Asset impairment and restructuring(2)	37,273			1,068,906			—			—		—
Goodwill impairment(3)	253,102			1,713,526			802,337			—		—
Total costs and expenses	6,023,514			9,771,333			7,726,802			3,743,545		2,378,212
Income (loss) from operations	$	(1,070,006	)	$	(2,796,449	)	$	(619,121	)	$	173,611	$	117,295
Income (loss) from continuing operations before income taxes	$	(1,330,048	)	$	(2,987,144	)	$	(766,448	)	$	101,436	$	33,784
Income (loss) from continuing operations (4)	$	(1,113,498	)	$	(2,437,148	)	$	(730,542	)	$	97,218	$	66,807

	Years Ended December 31,
	2013			2012			2011			2010			2009
Earnings (Loss) Per Share Data:
Basic earnings (loss) per common share:
Income (loss) from continuing operations attributable to Alpha Natural Resources, Inc.	$	(5.04	)	$	(11.06	)	$	(4.06	)	$	0.81		$	0.74
Loss from discontinued operations attributable to Alpha Natural Resources, Inc.	—			—			—			(0.01		)	(0.10		)
Net income (loss) per basic share attributable to Alpha Natural Resources, Inc.	$	(5.04	)	$	(11.06	)	$	(4.06	)	$	0.80		$	0.64
Diluted earnings (loss) per common share:
Income (loss) from continuing operations attributable to Alpha Natural Resources, Inc.	$	(5.04	)	$	(11.06	)	$	(4.06	)	$	0.80		$	0.73
Loss from discontinued operations attributable to Alpha Natural Resources, Inc.	—			—			—			(0.01		)	(0.10		)
Net income (loss) per diluted share attributable to Alpha Natural Resources, Inc.	$	(5.04	)	$	(11.06	)	$	(4.06	)	$	0.79		$	0.63

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	Years Ended December 31,
	2013			2012			2011			2010			2009
	(In thousands)
Balance sheet data (at period end):
Cash and cash equivalents	$	619,644		$	730,723		$	585,882		$	554,772		$	465,869
Working capital	$	745,609		$	1,110,614		$	638,827		$	928,691		$	592,403
Total assets (5)	$	11,799,258		$	13,089,806		$	16,594,045		$	5,179,283		$	5,120,343
Notes payable and long-term debt, including current portion, net (6)	$	3,427,603		$	3,386,052		$	2,968,081		$	754,151		$	790,253
Stockholders’ equity (7)	$	4,071,866		$	4,967,815		$	7,375,044		$	2,656,036		$	2,591,289
Statement of cash flows data:
Net cash provided by (used in):
Operating activities	$	109,018		$	518,419		$	686,637		$	693,601		$	356,220
Investing activities	$	(290,657	)	$	(672,976	)	$	(1,147,007	)	$	(508,497	)	$	(281,810	)
Financing activities	$	70,560		$	299,398		$	491,480		$	(96,201	)	$	(284,731	)
Capital expenditures	$	(215,661	)	$	(402,377	)	$	(528,586	)	$	(308,864	)	$	(187,093	)

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

	Years Ended December 31,
	2013			2012			2011(7)			2010			2009
	(In thousands)
Income (loss) from continuing operations	$	(1,113,498	)	$	(2,437,148	)	$	(730,542	)	$	97,218		$	66,807
Interest expense	246,588			198,147			141,914			73,463			82,825
Interest income	(3,517		)	(3,373		)	(3,978		)	(3,458		)	(1,769		)
Income tax expense (benefit)	(216,550		)	(549,996		)	(35,906		)	4,218			(33,023		)
Depreciation, depletion, and amortization	865,021			1,037,575			770,769			370,895			252,395
Amortization of acquired intangibles, net	5,056			(70,338		)	(114,422		)	226,793			127,608
EBITDA from continuing operations(8)	$	(216,900	)	$	(1,825,133	)	$	27,835		$	769,129		$	494,843

⁽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. Other expenses for 2013 includes $109.5 million related to contractual settlements and legal matters.

⁽²⁾  Asset impairment and restructuring charges were recorded during 2013 and 2012. See Note 10 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

⁽³⁾  Goodwill impairment charges were recorded during 2013, 2012 and 2011. See Note 11 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

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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 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.

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 seven month period from June 1, 2011 through December 31, 2011. 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.

Overview

We are one of America’s premier coal suppliers, ranked second largest among publicly-traded U.S. coal producers as measured by consolidated 2013 revenues of $5.0 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, 2013, we operate 81 mines and 25 coal preparation facilities in Northern and Central Appalachia and the Powder River Basin (“PRB”), with approximately 10,500 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 2013, 2012 and 2011 accounted for approximately 77%, 81% and 82%, respectively, of our annual coal sales volume, and our sales of metallurgical coal in 2013, 2012 and 2011, which generally sells at a premium over steam coal, accounted for approximately 23%, 19% and 18%, respectively, of our annual coal sales volume.

Our sales of steam coal during 2013, 2012 and 2011 were made primarily to large utilities and industrial customers throughout the United States, and our sales of metallurgical coal during 2013, 2012 and 2011 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 43%, 42% and 44% of our total revenues in 2013, 2012 and 2011, respectively, were derived from sales made to customers outside the United States, primarily in Turkey, Netherlands, Italy, India, and South Korea.

In addition, we generate other revenues from equipment and parts sales and repair, Dry Systems Technologies equipment and filters, rentals, commissions, coal handling, terminal and processing fees, coal and environmental analysis fees, royalties

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and the sale of 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, and our coal brokerage activities. Western Coal Operations consists of two Powder River Basin mines in Wyoming. Our All Other segment includes an idled underground mine in Illinois; expenses associated with certain closed mines; Dry Systems Technologies; revenues and royalties from the sale of natural gas; 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:

In 2010, we entered into a 50/50 joint venture (the “Alpha Shale JV”) with Rice Drilling C LLC, a wholly owned subsidiary of Rice Drilling B LLC, in order to develop a portion of our Marcellus Shale natural gas holdings in southwest Pennsylvania. On December 6, 2013, we, Rice Drilling C LLC and Rice Energy Inc. (“Rice Energy”) entered into a transaction agreement (the “Transaction Agreement”). Pursuant to the Transaction Agreement, we agreed to transfer our 50% interest in the Alpha Shale JV to Rice Energy in exchange for total consideration of $300.0 million, consisting of $100.0 million of cash and the issuance by Rice Energy to us of approximately 9.5 million shares of common stock concurrently with the consummation of Rice Energy’s initial public offering. On January 29, 2014, Rice Energy completed its initial public offering, and on the same date, issued approximately 9.5 million shares of common stock and paid $100.0 million in cash to us.

In October and December 2013, the parties to the securities class action brought by Massey stockholders in the wake of the explosion at Massey’s Upper Big Branch mine participated in mediation. In December 2013, the parties reached agreement on all material terms of settlement, including a cash payment of $265 million. In February 2014, the parties reached agreement on definitive settlement documentation and the United States District Court for the Southern District of West Virginia (the “Court”) entered an order preliminarily approving the settlement. On February 25, 2014, pursuant to the terms of the settlement, we made an initial payment of $30 million into an escrow account. The settlement, however, remains subject to the final approval of the Court following a settlement hearing. Whether the Court will approve the settlement remains uncertain. We expect insurance recoveries of approximately $70 million to help cover the cost of the settlement.

In December 2013, we issued $345.0 million principal amount of convertible senior notes due 2020 (the “4.875% Convertible Notes”). The 4.875% Convertible Notes bear interest at a rate of 4.875% per annum, and will mature on December 15, 2020. The proceeds from the 4.875% Convertible Notes were used to repurchase approximately $177.1 million of our outstanding 3.25% convertible notes due 2015 (the “3.25% Convertible Notes”) and approximately $36.8 million of our outstanding 2.375% convertible notes due 2015 (the “2.375% Convertible Notes”).

In May 2013, we entered into the Fourth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”) with the lenders party thereto, the issuing banks party thereto, Citicorp North America, Inc., as administrative agent and as collateral agent, and all other parties thereto from time to time, which amends and restates the Company’s Third Amended and Restated Credit Agreement, dated as of May 19, 2011, as amended June 26, 2012 (the “Former Credit Agreement”). The Credit Agreement includes a $625.0 million senior secured term loan B facility (the “Term Loan Facility”), which matures on May 22, 2020. The proceeds of the Term Loan Facility were used to repay the entire $525.0 million aggregate principal amount of our outstanding obligations under our existing term loan A facility under the Former Credit Agreement, which would have matured on June 30, 2016, with the balance used to pay fees and expenses and for general corporate purposes.

The principal changes to the Former Credit Agreement effected by the Amended and Restated Credit Agreement include increasing the existing senior secured revolving facility (the “Revolving Facility”) from $1.0 billion to $1.1 billion through its maturity date of June 30, 2016 and modifying the financial covenants. Simultaneously with our entry into the Credit Agreement, we terminated the Second Amended and Restated Receivables Purchase Agreement, dated as of October 19, 2011 (as amended from time to time, the “A/R Facility”).

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In October 2013, we entered into an amendment to the Credit Agreement which eliminated the interest coverage ratio through the end of 2014, and modified the interest coverage ratio from 2.00 to 1.25 during 2015 and from 2.00 to 1.50 during the first two quarters of 2016.

In May 2013, we issued $345.0 million principal amount of convertible senior notes due 2017 (the “3.75% Convertible Notes”). The proceeds from the 3.75% Convertible Notes, together with cash on hand, were used to repurchase approximately $225.8 million of our outstanding 3.25% Convertible Notes and approximately $181.4 million of our outstanding 2.375% Convertible Notes.

See Liquidity and Capital Resources and Note 14 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K for further information regarding the above financing transactions.

During the twelve months ended December 31, 2013, we tested our long-lived assets and goodwill for impairment due to a longer than expected recovery in the metallurgical coal markets and lower production and shipment levels compared with previous estimates. We recorded $253.1 million in goodwill impairment expense related to a reporting unit in our Eastern Coal Operations. Additionally, during 2013, we idled certain mines located in West Virginia and announced a plan to further reduce operating and support expenses by approximately $200.0 million annually in response to weak market conditions and recorded asset impairment and restructuring expenses of $37.3 million, of which $15.8 million was for severance and related benefits, $9.6 million for professional fees and other expenses, $1.9 million for other asset impairment expenses and $10.0 million of reserves for assets that may not be recoverable in the future. We will continue to evaluate market conditions and will make further adjustments if market conditions warrant. See Note 10 and Note 11 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K relating to asset impairment and restructuring expenses and goodwill impairment, respectively.

In July 2013, we announced that production was suspended at our Cumberland mine due to adverse geological conditions in the mine’s headgate area. On August 15, 2013, we announced that production had resumed. The longwall production outage and a longer than scheduled longwall move at the Cumberland mine is estimated to have reduced 2013 Eastern steam coal shipments by approximately 700,000 tons.

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 were located in Virginia, West Virginia, Pennsylvania, Kentucky and Wyoming. Our reorganization efforts serve to enhance 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 were closed and overhead support functions were consolidated from other locations as well.

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 10 and Note 11 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. 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 Liquidity and Capital Resources and Note 14 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

Coal Pricing Trends, Uncertainties and Outlook

Metallurgical Coal

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While the fourth quarter 2013 Australian hard coking coal settlement showed a $7 per metric tonne improvement over the prior quarter, the pricing environment for met coal softened considerably at the end of the year and into the first part of 2014. Pricing was negatively impacted by the combined effect of: (i) foreign exchange declines in currencies of major producing countries against the US Dollar that drove cost reductions; (ii) seasonal slowdown in Chinese purchasing patterns corresponding with iron production trends; and (iii) increased production of coking coal, primarily in Queensland. These factors combined to reduce the first quarter 2014 benchmark by $9 per ton to $143 per ton. Australian metallurgical coal exports set a record in 2013 and increased more than 15% over 2012 levels, with most of the growth going to satisfy increased Chinese import demand. While the current spot assessments of hard coking coal have shown more downside sentiment in conjunction with the seasonal slow-down in Chinese purchasing patterns, the Company believes that the incremental production increase in global seaborne tons will be more limited in 2014, with the majority of the increase in the Pacific market. At current spot measurements, a significant portion of global metallurgical production is uneconomic. If present market indications were to continue, additional production would be expected to be driven out of the market. However, given the expected limited additional supply growth in 2014 and the World Steel Association’s estimated global steel demand growth of 3.3%, we expect metallurgical coal supply and demand to become more balanced in 2014 resulting in possible price firmness in the latter part of the year and continuing into 2015.

We were able to partially mitigate the impact of lower quarterly benchmark and spot pricing by capturing a greater volume of North American metallurgical business in the first two months of 2014 versus full year 2013 volumes. We have sold and priced more than 6 million tons in the North American metallurgical coal market, which was priced annually for 2014 during the fourth quarter of 2013. This heavier weighting towards North American business will help us avoid some of the impact of intra-quarter and spot volatility related to the Asian hard coking coal benchmark assessments. Also, European economies are showing improved activity which should continue to enhance our metallurgical coal opportunities in the Atlantic export market. After a difficult 2012 and most of 2013, the fundamentals for integrated European steel mills appear to be improving. Europe is the largest export market for us and we view this development as an encouraging sign for the future.

Thermal Coal

While thermal pricing remains challenging in relation to production costs, there have been positive developments.

First, domestic utility inventories dropped significantly in 2013 as coal burn increased as compared with 2012 levels. Overall, domestic inventories declined and measured in days of burn, year-over-year inventories declined below the historical five-year average. Northern Appalachian (“NAAP”) and PRB inventories are the tightest with below-normal December levels compared to five-year averages. Importantly, Central Appalachian (“CAAP”) utility inventories declined meaningfully in 2013, yet they are still above the historical five-year average days of burn. The only region to experience an increase in 2013 inventories was the Illinois basin, which also has above average days of burn in inventory.

The decreasing inventory levels point to improving supply/demand dynamics, which should lead to healthier market conditions in the near to intermediate-term. However, pricing currently remains constrained in both the PRB and NAAP regions. In the PRB, the perception of latent capacity and intense competition among suppliers has resulted in weak, albeit improving, pricing recently. Supply and demand for NAPP coal appears to be in a state of relative balance, but prices remain constrained by the availability of comparatively low-cost coal, primarily from the Illinois Basin.

Second, prompt natural gas prices have increased substantially since early 2013. Combined with lower coal inventory levels, there has been near-term price firmness in most regions, especially in CAPP, where prices, as measured by NYMEX, have risen between late November to late January.

Third, as we approach announced 2015 plant closures due to EPA regulations, such as Mercury and Air Toxics Standards (“MATS”), it is becoming increasingly common for utilities to voice their concerns about grid reliability issues as an unintended consequence of environmental regulations. There is speculation that some power grid operators will designate additional plants, such as the Brayton Point power plant in Massachusetts, as “must run” facilities.

Overall, the outlook for thermal coal markets is more constructive compared with a few months ago. However, CAPP coal will continue to face declining structural domestic demand and continued natural gas competition. We have identified certain export markets, most notably the Atlantic basin, as one of the key opportunities for CAPP coal. We have sold more than 5.0 million tons in the Atlantic export market for 2014; approximately 4.0 million of these tons are indexed to API2.

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In 2014, we expect to complete longwall moves at the Cumberland and Emerald mines in June and April, respectively, which will temporarily reduce production at those mines in the corresponding period.

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, among others, 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. 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.”

Results of Operations

EBITDA is defined as net income (loss) plus interest expense, income tax expense, depreciation, depletion, and amortization, and amortization of acquired intangibles, net, less interest income and income tax benefit. EBITDA is not a financial measure recognized under accounting principles generally accepted in the United States (“GAAP”). It is 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 is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.

The following table reconciles EBITDA to net loss, the most directly comparable GAAP measure: 

	Years Ended December 31,
	2013			2012			2011
	(In thousands)
Net loss	$	(1,113,498	)	$	(2,437,148	)	$	(730,542	)
Interest expense	246,588			198,147			141,914
Interest income	(3,517		)	(3,373		)	(3,978		)
Income tax benefit	(216,550		)	(549,996		)	(35,906		)
Depreciation, depletion, and amortization	865,021			1,037,575			770,769
Amortization of acquired intangibles, net	5,056			(70,338		)	(114,422		)
EBITDA	$	(216,900	)	$	(1,825,133	)	$	27,835

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Summary

Total revenues decreased $2.0 billion, or 29%, for the twelve months ended December 31, 2013 compared to the prior year period. The decrease in total revenues was due to decreased coal revenues of $1.8 billion, decreased freight and handling revenues of $204 million, and decreased other revenues of $60 million. The decrease in coal revenues was due primarily to lower coal sales volumes and lower average coal sales realization per ton for metallurgical and steam coal. The decrease in coal revenues consisted of decreased steam coal revenues of $1.1 billion, or 33%, and decreased metallurgical coal revenues of $661.9 million, or 25%. The decrease in freight and handling revenues was due primarily to decreased export shipments and

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decreased freight rates. The decrease in other revenues was due primarily to changes in fair value adjustments for derivatives and decreased terminal revenues.

Net loss decreased $1.3 billion for the twelve months ended December 31, 2013 compared to the prior year period. The decrease was largely due to lower goodwill impairment and asset impairment and restructuring expenses of $1.5 billion and $1.0 billion, respectively, decreases in certain operating costs and expenses, which are described below, of $1.1 billion, partially offset by the decreased total revenues discussed above, increased other expense, net of $69.3 million, and decreased income tax benefits of $333.4 million.

The decrease in certain operating costs and expenses of $1.1 billion consisted of decreased cost of coal sales of $1.0 billion, or 20%, decreased depreciation, depletion and amortization expenses of $172.6 million, or 17%, and decreased selling, general and administrative expenses of $50.8 million, or 24%, partially offset by increased expenses for amortization of acquired intangibles, net of $75.4 million, and increased other expenses of $120.1 million.

Coal sales volumes decreased 21.9 million tons, or 20%, compared to the prior year period. The decrease in coal sales volumes was due primarily to a decrease of 13.3 million tons of eastern steam coal and a decrease of 8.6 million tons of western steam coal. The decreases in eastern and western steam coal volumes were due primarily to decreased demand and the impacts of production curtailments and mine idlings implemented during 2012 and 2013.

The consolidated average coal sales realization per ton for the twelve months ended December 31, 2013 was $48.99 compared to $55.29 in the prior year period, a decrease of $6.30 per ton, or 11%. The decrease was largely attributable to decreases of $32.01 per ton, or 24%, $3.61 per ton, or 5%, and $0.32 per ton, or 2%, in metallurgical, eastern steam and western steam average coal sales realization per ton, respectively. The average coal sales realization per ton for metallurgical coal and eastern steam coal was $99.01 and $62.31, respectively, for the twelve months ended December 31, 2013 compared to $131.02 and $65.92 in the prior year period. The average coal sales realization per ton for western steam coal was $12.62 for the twelve months ended December 31, 2013 compared to $12.94 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 8% for the twelve months ended December 31, 2013 compared to 18% in the prior year period. Coal margin percentage for our Eastern and Western Coal Operations was 6% and 22%, respectively, for the twelve months ended December 31, 2013 compared to 18% and 22% 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 (excluding cost of coal sales per ton in our All Other segment), was $3.97 for the twelve months ended December 31, 2013 compared to $10.01 in the prior year period. Coal margin per ton for our Eastern and Western Coal Operations was $4.95 and $2.71, respectively, for the twelve months ended December 31, 2013 compared to $15.42 and $2.84 in the prior year period.

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	Years Ended December 31,				Increase (Decrease)
	2013		2012		$ or Tons			%
	(In thousands, except per ton data)
Revenues:
Coal revenues:
Eastern steam	$	1,782,781	$	2,755,474	$	(972,693	)	(35	)%
Western steam	481,747		604,880		(123,133		)	(20	)%
Metallurgical	1,993,453		2,655,342		(661,889		)	(25	)%
Freight and handling revenues	557,846		761,928		(204,082		)	(27	)%
Other revenues	137,681		197,260		(59,579		)	(30	)%
Total revenues	$	4,953,508	$	6,974,884	$	(2,021,376	)	(29	)%
Tons sold:
Eastern steam	28,613		41,797		(13,184		)	(32	)%
Western steam	38,164		46,732		(8,568		)	(18	)%
Metallurgical	20,135		20,267		(132		)	(1	)%
Total	86,912		108,796		(21,884		)	(20	)%
Coal sales realization per ton:
Eastern steam	$	62.31	$	65.92	$	(3.61	)	(5	)%
Western steam	$	12.62	$	12.94	$	(0.32	)	(2	)%
Metallurgical	$	99.01	$	131.02	$	(32.01	)	(24	)%
Average	$	48.99	$	55.29	$	(6.30	)	(11	)%

Coal revenues. Coal revenues decreased $1.8 billion, or 29%, for the twelve months ended December 31, 2013 compared to the prior year period. The decrease in coal revenues consisted of decreases in eastern steam, western steam and metallurgical coal revenues.

Total eastern steam coal revenues decreased $972.7 million, or 35%, which consisted of decreased domestic coal revenues of $887.5 million, or 37%, and decreased export coal revenues of $85.2 million, or 24%, compared to the prior year period. The decrease in eastern steam coal revenues was largely due to fewer coal shipments as a result of decreased demand and the impacts of production curtailments and mine idlings implemented during 2012 and 2013, the impact of a temporary shut down of our Cumberland longwall mine due to difficult mining conditions and geological factors and a longer than expected longwall move, and lower coal sales realization per ton. Eastern steam coal shipments decreased 13.2 million tons, or 32%, which consisted of decreased domestic shipments of 11.9 million tons, or 33%, and decreased export shipments of 1.3 million tons, or 22%, compared to the prior year period. Coal sales realization per ton for eastern steam domestic sales was $62.76 per ton compared to $66.65 per ton in the prior year period and coal sales realization per ton for eastern steam export sales was $59.91 per ton compared to $61.44 per ton in the prior year period.

Total metallurgical coal revenues decreased $661.9 million, or 25%, which consisted of decreased export coal revenues of $504.3 million, or 27%, and decreased domestic coal revenues of $157.6 million, or 20%, compared to the prior year period. The decrease in metallurgical coal revenues was largely due to lower average coal sales realization per ton, which was impacted by weaker market conditions and lower demand, as well as the mix of coal qualities sold as a larger portion of lower quality metallurgical tons were sold in the twelve months ended December 31, 2013 compared to the prior year period. Metallurgical coal shipments decreased 0.1 million tons from the prior year period, which consisted primarily of decreased export shipments of 0.5 million tons, partially offset by increased domestic shipments of 0.4 million tons. Coal sales realization per ton for metallurgical export sales was $92.10 per ton compared to $122.18 per ton in the prior year period and coal sales realization per ton for metallurgical domestic sales was $118.71 per ton compared to $158.78 per ton in the prior year period.

The decrease in western steam coal revenues was primarily due to decreased coal shipments as a result of the impacts of production curtailments and a decrease of $0.32 in average coal sales realization per ton due to decreased demand and weak market conditions. Western coal sales volumes decreased 8.6 million tons, or 18%, compared to the prior year period.

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Our sales mix of metallurgical coal and steam coal based on volume was 23% and 77%, respectively, for the twelve months ended December 31, 2013 compared with 19% and 81% in the prior year period. Our sales mix of metallurgical coal and steam coal based on coal revenues was 47% and 53%, respectively, for the twelve months ended December 31, 2013 compared with 44% and 56%, respectively, in the prior year period.

Freight and handling. Freight and handling revenues and costs were $557.8 million for the twelve months ended December 31, 2013, a decrease of $204.1 million, or 27%, compared to the prior year period. The decrease was primarily due to decreased export shipments and decreased freight rates compared to the prior year period.

Other. Other revenues decreased $59.6 million, or 30%, and other expenses increased $120.1 million, or 264%, for the twelve months ended December 31, 2013 compared to the prior year period, resulting in a net decrease to income from operations of $179.7 million. The net decrease was due primarily to changes in fair value adjustments for derivatives and an increase in loss contingency accruals for litigation (See Note 23 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K regarding litigation).

	Years Ended December 31,						Increase (Decrease)
	2013			2012			$			%
	(In thousands, except per ton data)
Cost of coal sales (exclusive of items shown separately below)	$	3,980,744		$	5,004,516		$	(1,023,772	)	(20	)%
Freight and handling costs	557,846			761,928			(204,082		)	(27	)%
Other expenses	165,485			45,432			120,053			264	%
Depreciation, depletion and amortization	865,021			1,037,575			(172,554		)	(17	)%
Amortization of acquired intangibles, net	5,056			(70,338		)	75,394			107	%
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)	158,987			209,788			(50,801		)	(24	)%
Asset impairment and restructuring	37,273			1,068,906			(1,031,633		)	(97	)%
Goodwill impairment	253,102			1,713,526			(1,460,424		)	(85	)%
Total costs and expenses	$	6,023,514		$	9,771,333		$	(3,747,819	)	(38	)%
Cost of coal sales per ton(1):
Eastern coal operations	$	72.51		$	71.76		$	0.75		1	%
Western coal operations	$	9.91		$	10.10		$	(0.19	)	(2	)%
Average	$	45.02		$	45.28		$	(0.26	)	(1	)%
EBITDA:
Eastern Coal Operations	$	(44,223	)	$	(1,807,515	)	$	1,763,292		98	%
Western Coal Operations	$	90,879		$	65,153		$	25,726		39	%

__________________________

⁽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 $1,023.8 million, or 20%, for the twelve months ended December 31, 2013 compared to the prior year period. The decrease in cost of coal sales was due primarily to decreased supplies and maintenance expenses, including diesel fuel and explosives, decreased merger-related expenses, decreased purchased coal expenses and decreased labor and benefit expenses primarily related to production curtailments and mine idlings implemented during 2012 and the first half of 2013, decreased credit adjustments related to changes in estimates for asset retirement obligations, and other cost control measures, and decreased sales-related and other variable costs associated with decreased metallurgical and steam coal revenues and decreased steam coal production, partially offset by increased expenses for regulatory matters.

Depreciation, depletion and amortization. Depreciation, depletion, and amortization decreased $172.6 million, or 17%, for the twelve months ended December 31, 2013 compared to the prior year period. The decrease was primarily due to decreased depletion and amortization expense due to lower thermal coal production and lower depletion rates at certain mines that recorded asset impairment charges during 2012 and decreased depreciation expense related to lower capital expenditures over the last twelve months compared to the same time period in the prior year.

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Amortization of acquired intangibles, net. Amortization expense of acquired intangibles, net increased $75.4 million, or 107%, for the twelve months ended December 31, 2013 compared to the prior year period. The increase in expense for amortization of acquired intangibles, net, was primarily due to decreased amortization of below-market contracts assumed in the Massey Acquisition due to the completion of shipments under many of the contracts assumed. Amortization of acquired intangibles, net for the next five years is estimated to be $38.3 million, $30.2 million, $24.0 million, $5.6 million, and $1.0 million.

Selling, general and administrative. Selling, general and administrative expenses decreased $50.8 million, or 24%, for the twelve months ended December 31, 2013 compared to the prior year period. The decrease in selling, general and administrative expenses was due primarily to decreased wage and benefits expenses as a result of lower headcount, and decreased merger-related expenses, partially offset by increased stock compensation expenses due to the reversal of stock compensation expenses in 2012 related to performance-based awards.

Asset impairment and restructuring. Asset impairment and restructuring expenses were $37.3 million for the twelve months ended December 31, 2013 and consisted primarily of severance and related benefits, professional fees for consulting, and reserves for other assets that may not be recoverable. Asset impairment and restructuring expenses were $1,068.9 million for the twelve months ended December 31, 2012 and consisted primarily of $1,000.5 million of long-lived asset impairment expenses and $68.4 million for severance and related benefits, professional fees and other expenses, lease termination costs and reserves for other assets that may not be recoverable. See Critical Accounting Policies and Note 10 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

Goodwill impairment. See Critical Accounting Policies and Note 11 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

Interest expense. Interest expense increased $48.4 million, or 24%, during the twelve months ended December 31, 2013 compared to the prior year period due primarily to the issuance of 9.75% senior notes in October 2012 and the issuance of 3.75% convertible senior notes in May 2013, partially offset by repurchases of a portion of outstanding 2.375% Convertible Notes and 3.25% Convertible Notes in May 2013.

Income taxes. Income tax benefit of $216.6 million was recorded for the twelve months ended December 31, 2013 on a loss before income taxes of $1,330.0 million. The benefit rate is lower than the federal statutory rate of 35% primarily due to the impact of an increase in the valuation allowance against deferred tax assets related to operating loss carryforwards and the non-deductible goodwill impairment, partially offset by the impact of the percentage depletion allowance and state income taxes, net of federal tax impact.

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

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 and geological conditions.

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.

Segment EBITDA

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Eastern Coal Operations. EBITDA increased $1.8 billion for the twelve months ended December 31, 2013 compared to the prior year period. The increase in EBITDA was largely due to decreased goodwill impairment and asset impairment and restructuring expenses of $1.5 billion and $1.0 billion, respectively, decreased selling, general and administrative expenses of $40.8 million, and decreased other expenses of $33.5 million, partially offset by decreased coal margin per ton of $10.46, or 68%, and decreased other revenues of $42.9 million. The decrease in coal margin per ton was due primarily to the decreased steam coal sales volumes and decreased steam and metallurgical coal revenues discussed above. The decrease in coal margin per ton consisted of decreased average coal sales realization per ton of $9.71, or 11%, and increased cost of coal sales per ton of $0.75. During the twelve months ended December 31, 2013, cost of coal sales per ton was negatively impacted by reduced shipments and increased costs per ton as a result of a temporary shut down of our Cumberland longwall mine due to difficult mining conditions and geological factors and a longer than expected longwall move.

Western Coal Operations. EBITDA increased $25.7 million, or 39%, for the twelve months ended December 31, 2013 compared to the prior year period. The increase in EBITDA was due primarily to goodwill impairment expense recorded in 2012, partially offset by decreased coal margin per ton of $0.13, or 5%. The decrease in coal margin per ton consisted of decreased average coal sales realization per ton of $0.32, or 2%, partially offset by decreased cost of coal sales per ton of $0.19, or 2%.

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			%
	(In thousands, except per ton data)
Revenues:
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 $474.3 million, or 20%, partially offset by increased domestic coal revenues of $25.7 million, or 3%, compared to the prior year period.

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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			$			%
	(In thousands, except per ton data)
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	)%
EBITDA:
Eastern Coal Operations	$	(1,807,515	)	$	143,649		$	(1,951,164	)	(1,358	)%
Western Coal Operations	$	65,153		$	74,891		$	(9,738	)	(13	)%

_____________________

⁽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 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

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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.

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 10 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 11 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 14 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K).

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

Income tax benefit of $35.9 million was recorded for the twelve months ended December 31, 2011 on loss before income taxes of $766.4 million. The rate is lower than the federal statutory rate of 35% primarily due to the impact of the non-deductible goodwill impairment, partially offset by the impact of the percentage depletion allowance (See Note 19 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K).

Segment EBITDA

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.

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%.

Liquidity and Capital Resources

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Our primary liquidity and capital resource requirements stem from the cost of our coal production and purchases, our capital expenditures, our debt service, our reclamation obligations, our litigation and regulatory costs and settlements and associated costs, and from time to time, our securities repurchases. Our primary sources of liquidity have been from sales of coal, our credit facility and debt arrangements (see “Long-Term Debt - Amendment to Fourth Amended and Restated Credit Agreement”), and to a much lesser extent, 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 Credit Agreement 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, 2013, we had total liquidity of $1,922.7 million, including cash and cash equivalents of $619.6 million, marketable securities of $337.1 million and $966.0 million of unused commitments available under our Credit Agreement’s revolving credit facility, after giving effect to $134.0 million of letters of credit outstanding, as of December 31, 2013, subject to limitations described in our Credit Agreement.

Weak market conditions and depressed coal prices have resulted in operating losses and decreased cash flows from operations. If market conditions do not improve, we expect our liquidity to be adversely affected. In particular, we expect a decrease in cash and cash equivalents to the extent that capital expenditures and other cash obligations exceed cash generated from our operations.

We have worked and are working to enhance our capital structure and financial flexibility as opportunities arise through repayment or repurchase of outstanding debt, amendment of our credit facility, and other methods. We may decide to pursue or not pursue these opportunities at any time. As part of this strategy, we may from time to time repurchase some of our outstanding notes through open market purchases, privately negotiated transactions, tender offers, exchange offers or otherwise, upon such terms and at such prices as permitted by securities laws and other legal requirements, and subject to market conditions and other factors. To facilitate repurchases, we may make purchases pursuant to one or more trading plans under Rule 10b5-1 of the Exchange Act, which allow us to repurchase securities during periods when we otherwise might be prevented from doing so under insider trading laws or because of self-imposed trading blackout periods. Any such plans may be discontinued at any time.

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. Annual funding contributions to the plans are made as recommended by consulting actuaries based upon the Employee Retirement Income Security Act (“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, or sooner under certain circumstances, 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 in our balance sheet and recognize changes in that funded status in the year in which the changes occur through other comprehensive income (loss). 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. Our plans are not currently deemed to be at risk and subject to additional funding requirements under the PPA. We have not made any pension contributions during 2013 and do not anticipate making any material contributions in 2014 for our defined benefit pension plans.

With respect to global economic events, there continues to be uncertainty in the financial markets and weakness in the coal industry. We constantly monitor the creditworthiness of our customers. We believe that the creditworthiness of our current group of customers is sound and represents no abnormal business risk. On October 7th, 2013, Moody’s Investors Service downgraded our ratings, including our Corporate Family Rating (CFR) to B2 from B1, and indicated a stable outlook. The speculative grade liquidity (SGL) rating remains unchanged at SGL-2. Additionally, on December 9, 2013, Standard & Poor’s Ratings Services lowered its corporate credit rating to B from B+. The rating outlook is stable. These issues bring potential liquidity risks for us, including the risks of 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.

In October and December 2013, the parties to the securities class action brought by Massey stockholders in the wake of the explosion at Massey’s Upper Big Branch mine participated in mediation. In December 2013, the parties reached agreement on

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all material terms of settlement, including a cash payment of $265 million. In February 2014, the parties reached agreement on definitive settlement documentation, subject to court approval, and on February 5, 2014, the lead plaintiffs moved the court for preliminary approval of the settlement. On February 25, 2014, pursuant to the terms of the settlement, we made an initial payment of $30 million into an escrow account. If the court approves the settlement, it would result in the dismissal of the action. 

Whether the court will approve the settlement, and the timing of any such approval, remains uncertain. We expect insurance recoveries of approximately $70.0 million to help cover the cost of the settlement.

In 2010, we entered into a 50/50 joint venture (the “Alpha Shale JV”) with Rice Drilling C LLC, a wholly owned subsidiary of Rice Drilling B LLC, in order to develop a portion of our Marcellus Shale natural gas holdings in southwest Pennsylvania. On December 6, 2013, we, Rice Drilling C LLC and Rice Energy Inc. (“Rice Energy”) entered into a transaction agreement (the “Transaction Agreement”). Pursuant to the Transaction Agreement, we agreed to transfer our 50% interest in the Alpha Shale JV to Rice Energy in exchange for total consideration of $300.0 million, consisting of $100.0 million of cash and the issuance by Rice Energy to us of approximately 9.5 million shares of common stock concurrently with the consummation of Rice Energy’s initial public offering. On January 29, 2014, Rice Energy completed its initial public offering, and on the same date, issued approximately 9.5 million shares of common stock and paid $100.0 million in cash to us.

Additionally, see Note 23 in the Notes to Consolidated Financial Statements contained elsewhere in this Annual Report on Form 10-K regarding our commitments for lease by application payments due in 2014 and 2015.

Cash Flows

Cash and cash equivalents decreased by $111.1 million and increased by $144.8 million and $31.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. The net change in cash and cash equivalents was attributable to the following:

Cash Flows	Years Ended December 31,
(in thousands)	2013			2012			2011
Net cash provided by operating activities	$	109,018		$	518,419		$	686,637
Net cash used in investing activities	(290,657		)	(672,976		)	(1,147,007		)
Net cash provided by financing activities	70,560			299,398			491,480
Net change in cash and cash equivalents	$	(111,079	)	$	144,841		$	31,110

Net cash provided by operating activities for the year ended December 31, 2013 was $109.0 million, a decrease of $409.4 million from the $518.4 million of net cash provided by operating activities for the year ended December 31, 2012. 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, cash payments to a trust pursuant to our obligations under a non-prosecution agreement, and cash payments for severance and benefits related to restructuring activities.

Net cash used in investing activities for the year ended December 31, 2013 was $290.7 million, a decrease of $382.3 million from the $673.0 million of net cash used in investing activities for the year ended December 31, 2012. Capital expenditures decreased to $215.7 million in 2013 from $402.4 million in 2012. Cash paid for acquisition of mineral rights decreased to $42.1 million in 2013 from $95.8 million in 2012. Net sales of marketable securities were $43.5 million in 2013 compared to net sales of $203.0 million in 2012. Proceeds from disposition of property, plant and equipment decreased to $10.6 million in 2013 from $38.3 million in 2012.

Net cash provided by financing activities for the year ended December 31, 2013 was $70.6 million, a decrease of $228.8 million from the $299.4 million of net cash provided by financing activities for the year ended December 31, 2012. The primary source of cash for financing activities in 2013 included $1,306.7 million of proceeds from borrowings of long-term debt, offset by principal repayments and repurchases of long-term debt of $1,176.3 million. Debt issuance costs were $36.7 million for the year ended December 31, 2013 compared to $16.4 million in 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 $1.4 million in 2013 compared to $7.5 million in 2012.

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

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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.

Credit Agreement and Long-term Debt

As of December 31, 2013 and 2012, our total long-term indebtedness consisted of the following (in thousands):

	December 31, 2013			December 31, 2012
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			500,000
Term loan due 2020	620,313			—
Term loan due 2016	—			540,000
4.875% convertible senior notes due 2020	345,000			—
3.75% convertible senior notes due 2017	345,000			—
3.25% convertible senior notes due 2015	128,182			536,162
2.375% convertible senior notes due 2015	65,889			287,500
Other	73,305			86,203
Debt discount	(150,086		)	(63,813		)
Total long-term debt	3,427,603			3,386,052
Less current portion	(29,169		)	(95,015		)
Long-term debt, net of current portion	$	3,398,434		$	3,291,037

Fourth Amended and Restated Credit Agreement

On May 22, 2013, we entered into the Fourth Amended and Restated Credit Agreement (as amended, the "Credit Agreement") with the lenders party thereto, the issuing banks party thereto, Citicorp North America, Inc., as administrative agent and as collateral agent, and all other parties thereto from time to time, which amends and restates the Former Credit Agreement.

The Credit Agreement includes a $625.0 million senior secured Term Loan Facility, which matures on May 22, 2020, amortizes in quarterly installments at a rate of 1.0% per year and bears an interest rate at the Company’s option of either LIBOR plus a margin of 2.75% (subject to a LIBOR floor of 0.75%) or an Alternate Base Rate (“ABR”) plus a margin of 1.75% (subject to an ABR floor of 1.75%). The proceeds of the Term Loan Facility were used to repay the entire $525.0 million aggregate principal amount of our outstanding obligations under our existing term loan A facility under the Former Credit Agreement, which would have matured on June 30, 2016, with the balance used to pay fees and expenses and for general corporate purposes.

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The principal changes to the Former Credit Agreement effected by the Credit Agreement include increasing the existing Revolving Facility from $1.0 billion to $1.1 billion through its maturity date of June 30, 2016 and modifying the financial covenants by:

• modifying the interest coverage ratio covenant from 2.25 to 1.50 through 2013, from 2.50 to 1.50 during 2014 and from 2.50 to 2.00 from 2015 through the maturity date of the revolving credit facility (June 30, 2016);

•eliminating the leverage ratio covenant;

• extending the applicability of the senior secured leverage ratio of 2.50 through the maturity date of the revolving credit facility; and

• reducing the minimum liquidity covenant, which applies until December 31, 2014, from $500.0 million to $300.0 million;

Additionally, the terms of the Credit Agreement (i) further restrict our ability and that of our subsidiaries to make investments, loans and acquisitions, incur additional indebtedness, and pay dividends on our capital stock or redeem, repurchase or retire our capital stock; and (ii) require us to provide additional collateral to secure the obligations under the Credit Agreement, consisting of receivables previously securing the A/R Facility.

On October 2, 2013, we entered into an amendment to the Credit Agreement which eliminated the interest coverage ratio through the end of 2014, and modified the interest coverage ratio from 2.00 to 1.25 during 2015 and from 2.00 to 1.50 during the first two quarters of 2016.

Fees. 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 commitments thereunder. The initial commitment fee is 0.50% per annum and is 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.

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;

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• 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.

As of December 31, 2013, the carrying value of the Term Loan Facility was $617.4 million, net of debt discount of $2.9 million, with $6.3 million classified as current portion of long-term debt. As of December 31, 2012, the carrying value of the term loan A 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. There were no borrowings outstanding under the Revolving Facility as of December 31, 2013 or 2012. Letters of credit outstanding at December 31, 2013 and 2012 under the Revolving Facility were $134.0 million and $0.3 million, respectively.

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.

Termination of Account Receivable Securitization Facility

Simultaneously with our entry into the Fourth Amended and Restated Credit Agreement, we terminated the A/R Facility, by and among ANR Receivables Funding, LLC, as seller, Alpha Natural Resources, LLC, as servicer, PNC Bank, National Association, as administrator and LC Bank (as defined therein), and the other parties thereto from time to time. The A/R Facility provided for the issuance of letters of credit in a maximum aggregate amount of $275.0 million. The outstanding letters of credit were transferred to the Credit Agreement and are deemed to be issued thereunder.

Convertible Senior Notes due 2017 and 2020

In May 2013, we issued $345.0 million principal amount of 3.75% Convertible Notes and in December 2013, we issued $345.0 million principal amount of 4.875% Convertible Notes (the 4.875% Convertible Notes together with the 3.75% Convertible Notes, the “Convertible Notes”). The 3.75% Convertible Notes bear interest at a rate of 3.75% per annum, payable semi-annually in arrears on June 15 and December 15 of each year, and will mature on December 15, 2017. The proceeds from the 3.75% Convertible Notes, together with cash on hand, were used to repurchase approximately $225.8 million of our outstanding 3.25% Convertible Notes and approximately $181.4 million of our outstanding 2.375% Convertible Notes. The 4.875% Convertible Notes bear interest at a rate of 4.875% per annum, payable semi-annually in arrears on June 15 and December 15 of each year, and will mature on December 15, 2020. The proceeds from the 4.875% Convertible Notes were used to repurchase approximately $177.1 million of our outstanding 3.25% Convertible Notes and approximately $36.8 million of our outstanding 2.375% Convertible Notes.

We separately account for the liability and equity components of the 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. The related deferred loan costs and discount are being amortized and accreted, respectively, over the respective terms of the Convertible Notes, and provide for effective interest rates of 8.49% in the case of the 3.75% Convertible Notes and 9.48% in the case of the 4.875% Convertible Notes. As of December 31, 2013, the carrying amounts of the debt components were $290.2 million in the case of the 3.75% Convertible Notes and $264.3 million in the case of the 4.875% Convertible Notes, and the unamortized debt discounts were $54.8 million in the case of the 3.75% Convertible Notes and $80.7 million in the case of the 4.875% Convertible Notes.

The Convertible Notes are our senior unsecured obligations and rank equally with all of our existing and future senior unsecured indebtedness. The Convertible Notes are guaranteed on a senior unsecured basis by each of our current and future wholly owned domestic subsidiaries that guarantee our obligations under our 9.75% senior notes due 2018. The Convertible Notes are effectively subordinated to all of our existing and future secured indebtedness and all existing and future liabilities of our non-guarantor subsidiaries, including trade payables.

The Convertible Notes are convertible in certain circumstances and in specified periods at initial conversion rates of 99.0589 shares of common stock per $1,000 of principal amount of notes in the case of the 3.75% Convertible Notes and 107.0893 shares of common stock per $1,000 of principal amount of notes in the case of the 4.875% Convertible Notes, subject to adjustment upon the occurrence of certain events set forth in the fourth and fifth supplemental indentures (the “Supplemental Indentures”) to the indenture dated June 1, 2011 (the “Base Indenture” and, together with the Supplemental Indentures, the “Convertible Notes Indentures”) governing the Convertible Notes, equivalent to an initial conversion price of approximately $10.10 per share of common stock in the case of the 3.75% Convertible Notes and $9.34 per share of common stock in the case

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of the 4.875% Convertible Notes. Upon conversion, the Convertible Notes may be settled, at our election, in cash, shares of our common stock or a combination thereof. Our intention is to settle all conversions using a combination of cash and shares.

The Convertible Notes Indentures contain 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 Convertible Notes then outstanding may declare the principal of the 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 Convertible Notes together with any accrued and unpaid interest thereon will automatically become due and be immediately payable.

The Convertible Notes were not convertible as of December 31, 2013 and, as a result, have been classified as long-term debt as of that date.

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 ASC 470-20 as described above. As of December 31, 2013, the carrying amount of the debt was $125.1 million, net of debt discount of $3.0 million. 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, 2013 and 2012, 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%.

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, 2013 or 2012 and as a result have been classified as long-term at both dates. 

2.375% Convertible Senior Notes due 2015

 As of December 31, 2013 and 2012, we had $65.9 million and $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 as described above. 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, 2013 and 2012, the carrying amounts of the debt component were $60.6 million and $249.3 million, respectively.  As of December 31, 2013 and 2012, the unamortized debt

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discount was $5.2 million and $38.2 million, respectively. As of December 31, 2013 and 2012, 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, 2013 and 2012 and therefore have been classified as long-term debt at both dates.

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, 2013, the carrying values of the 2018 Notes, 2019 Notes and 2021 Notes were $496.5 million, net of discount of $3.5 million, $800.0 million and $700.0 million, respectively. As of December 31, 2012, the carrying values of the 2018 Notes, 2019 Notes and 2021 Notes were $495.2 million, net of debt discount of $4.8 million, $800.0 million and $700.0 million, respectively.

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.

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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.

Capital Leases

Alpha’s liability for capital leases as of December 31, 2013 totaled $58.9 million, with $17.5 million reported as current portion of long-term debt compared to $67.0 million, with $14.6 million reported as current portion of long-term debt as of December 31, 2012.

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, 2013. 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

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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, 2013			Required Covenant Levels
Maximum total senior secured debt less unrestricted cash to Adjusted EBITDA ratio	(0.22		)	2.5x
Minimum consolidated liquidity (in thousands)	$	1,922,738		$	300,000

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 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, 2013
	March 31, 2013			June 30, 2013			September 30, 2013			December 31, 2013
	(In thousands)
Net loss	$	(110,788	)	$	(185,681	)	$	(458,241	)	$	(358,788	)	$	(1,113,498	)
Interest expense	59,401			60,953			62,233			64,001			246,588
Interest income	(1,026		)	(1,099		)	(1,008		)	(384		)	(3,517		)
Income tax expense (benefit)	(76,358		)	(89,527		)	(143,137		)	92,472			(216,550		)
Amortization of acquired intangibles, net	(5,431		)	3,591			2,748			4,148			5,056
Depreciation, depletion and amortization	239,013			214,716			196,292			215,000			865,021
EBITDA	104,811			2,953			(341,113		)	16,449			(216,900		)
Non-cash charges (1) (2)	18,267			74,051			383,535			56,645			532,498
Other adjustments (1) (3)	12,121			20,805			4,682			13,898			51,506
Adjusted EBITDA	$	135,199		$	97,809		$	47,104		$	86,992		$	367,104

___________________________

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⁽¹⁾  Calculated in accordance with the Credit Agreement.

⁽²⁾  Includes $253.1 million for the three months ended September 30, 2013 characterized under the Credit Agreement as goodwill impairment, which corresponds to goodwill impairment described elsewhere in this Annual Report of Form 10-K.

⁽³⁾  Includes $2.9 million for the three months ended December 31, 2013, $2.0 million for the three months ended September 30, 2013, $11.3 million for the three months ended June 30, 2013 and $11.1 million for the three months ended March 31, 2013 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, 2013 is calculated as follows (in thousands):

Interest expense	$	246,588
Less interest income	(3,517		)
Less non-cash interest expense	(54,749		)
Other adjustments	12,499
Net cash interest expense (1)	$	200,821

_____________________

⁽¹⁾  Calculated in accordance with the Credit Agreement. The interest coverage ratio was eliminated through the end of 2014.

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. At December 31, 2013, we had available liquidity of $1.9 billion, including cash and cash equivalents of $619.6 million, marketable securities of $337.1 million and $966.0 million of unused revolving credit facility commitments available under our Credit Agreement.

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 $430.6 million as of December 31, 2013 to secure various obligations and commitments. In addition, we had $134.0 million of letters of credit in place outstanding under the Credit Agreement. 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 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.

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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; acquisitions, dispositions of, or combinations with coal mining companies; or other strategically beneficial transactions. 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 or other strategic 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.

Contractual Obligations

The following is a summary of our significant contractual obligations as of December 31, 2013 (in thousands):

	2014		2015-2016		2017-2018		After 2018		Total
Long-term debt (1)	$	6,250	$	206,571	$	857,500	$	2,434,063	$	3,504,384
Capital lease obligations (2)	17,461		18,179		4,088		19,146		58,874
Other debt (3)	5,458		4,445		4,528		—		14,431
Equipment purchase commitments	14,010		—		—		—		14,010
Transportation commitments	25,928		92,374		48,922		277,935		445,159
Operating leases	18,325		11,257		130		—		29,712
Minimum royalties	41,562		73,773		63,262		90,117		268,714
Federal coal lease	42,130		42,130		—		—		84,260
Coal purchase commitments	8,047		—		—		—		8,047
Total	$	179,171	$	448,729	$	978,430	$	2,821,261	$	4,427,591

 ______________________________

⁽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 $198.0 million in 2014, $394.7 million in 2015 to 2016, $372.9 million in 2017 to 2018 and $217.3 million after 2018.

⁽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 $4.0 million in 2014, $6.4 million in 2015 to 2016, $5.4 million in 2017 to 2018 and $32.2 million after 2018.

⁽³⁾  Other debt includes principal amounts due in the years shown.  Cash interest payable on these obligations, with interest rates ranging between 4.00% and 6.132%, would be approximately $0.9 million in 2014, $0.9 million in 2015 to 2016, and $66K in 2017 to 2018.

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): 

	2014		2015-2016		2017-2018		After 2018		Total
Asset retirement obligation	$	67,477	$	167,413	$	159,552	$	1,200,718	$	1,595,160
Postretirement benefit obligation	46,678		105,647		117,028		1,979,620		2,248,973
Pension benefit obligation (1)	30,030		62,108		66,270		1,459,083		1,617,491
Black lung benefit obligation	8,142		17,032		18,267		374,939		418,380
Workers’ compensation benefit obligation	14,189		20,414		16,459		105,664		156,726
Total	$	166,516	$	372,614	$	377,576	$	5,120,024	$	6,036,730

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⁽¹⁾  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 $1.3 million in 2014, $3.0 million in 2015 and 2016, $2.9 million in 2017 and 2018 and $7.2 million thereafter.

We expect to spend between $250 million and $300 million on capital expenditures during 2014.

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. GAAP. GAAP requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and on various other factors and assumptions, including the current economic environment that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate our estimates and assumptions on an ongoing basis and adjust such estimates and assumptions as facts and circumstances require. Illiquid credit markets, 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.

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, 2013, we had recorded asset retirement obligation liabilities of $799.4 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2013, 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, 2013, we had 4.3 billion tons of proven and probable coal reserves, of which 2.1 billion tons were assigned to our active operations and 2.2 billion 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 20 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 weighted average discount rate used to determine the net periodic benefit cost for postretirement medical benefits was 4.18% for the year ended December 31, 2013. At December 31, 2013, we had total postretirement medical benefit obligations of $942.7 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	$	8,398	$	(6,586	)
Effect on accumulated postretirement benefit obligation	$	117,969	$	(96,947	)

Discount rate	One-Half Percentage Point Increase			One-Half Percentage Point Decrease
	(In thousands)
Effect on total service and interest cost components	$	720		$	(868	)
Effect on accumulated postretirement benefit obligation	$	(55,909	)	$	62,048

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” and, together with our Pension Plans, our “Defined Benefit Retirement Plans”) 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 Pension Plans is in accordance with the requirements of ERISA, and our contributions can be deducted for federal income tax purposes. We contributed $3.0 million to our Defined Benefit Retirement Plans for the year ended December 31, 2013. For the year ended December 31, 2013, we recorded a net periodic benefit credit of $6.1 million for our Defined Benefit Retirement Plans and have recorded net obligations of $94.1 million.

The calculation of the net periodic benefit expense/credit and projected benefit obligation associated with our Defined Benefit Retirement Plans 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

85

investment targets are 44% equity funds, 54% fixed income funds and 2% guarantee insurance contract. Investments are rebalanced on a periodic basis to stay within these targeted guidelines. The long-term rate of return assumption used to determine net periodic benefit expense was 6.75% for the year ended December 31, 2013. The long-term rate of return assumption to be used in 2014 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 weighted average discount rate used to determine pension expense was 4.21% for the year ended December 31, 2013. 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, 2013 by approximately $0.5 million and decrease the projected benefit obligation as of December 31, 2013 by approximately $47.0 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 $0.8 million and increase the projected benefit obligation as of December 31, 2013 by approximately $50.9 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, 2013, we had workers’ compensation obligations of $156.7 million.

Coal Workers’ Pneumoconiosis. We are required by federal and state statutes to provide benefits to employees for awards related to coal workers’ pneumoconiosis disease (black lung). Certain of our subsidiaries are insured for workers’ compensation and black lung obligations by a third-party insurance provider.  Certain subsidiaries in West Virginia are self-insured for workers’ compensation and state black lung obligations. Certain other subsidiaries are self-insured for black lung benefits and fund benefit payments through a Section 501(c)(21) tax-exempt trust fund.  Provisions are made for estimated benefits based on annual evaluations prepared by independent actuaries.  In addition, for our subsidiaries in Wyoming, we participate in a 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, 2013, we had black lung obligations of $144.6 million, which are net of assets of $12.0 million that are held in a tax exempt trust fund.

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 of the alternative minimum tax on the 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, 2013, 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 carryforwards and federal and state net 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, 2013, a valuation allowance of $294.1

86

million has been provided on certain federal net operating losses, state net operating losses, and gross deferred tax assets not expected to provide future tax benefits.

Asset Impairment. 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. During the three months ended September 30, 2013, due primarily to a longer than expected recovery in the metallurgical coal markets and lower production and shipment levels compared with previous estimates, we determined that an indicator of impairment of certain of our long-lived asset groups may exist. 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 the year ended December 31, 2013, we determined that the undiscounted cash flows were greater than the carrying value for all our long-lived asset groups with the exception of one asset group located in our All Other segment. We recorded an asset impairment of approximately $1.9 million to write down the value of the mineral reserves for this asset group. The undiscounted cash flows are dependent upon a number of significant management estimates about future performance including sales volumes and prices, costs to produce, income taxes, and capital spending, among others. Changes in any of these assumptions could materially impact the estimated undiscounted cash flows of our asset groups.

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. 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 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 received for our coal. However, coal prices are influenced by global market conditions beyond our control. 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. However, the costs of the materials and supplies used in our production process such as steel, diesel fuel and explosives are influenced by global market conditions beyond our control. 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. For a further discussion of the factors that could

87

result in a change in our assumptions, see “Risk Factors” in this report and our other filings with the Securities and Exchange Commission.

Due to longer than expected recovery in the metallurgical coal markets and lower production and shipment levels compared with previous estimates, we performed an interim goodwill impairment test during 2013 and recorded $253.1 million of goodwill impairment expense to write down the carrying value of goodwill to its implied fair value for a reporting unit in our Eastern Coal Operations segment. We also performed our annual goodwill test as of October 31, 2013 in which we performed both steps as described above and did not record any additional goodwill impairment.

As of December 31, 2013, the Company’s goodwill totaled $308.7 million, all of which relates to one reporting unit within our Eastern Coal Operations. Continued global economic weakness and in particular further deterioration or continued weakness for an extended period of time in the global metallurgical coal market, as well as other factors that could result in adverse changes in the key assumptions described above, could lead to a reduction in the fair value of the reporting unit. Accordingly, the goodwill associated with this reporting unit may be at risk for further impairment charges.

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 23 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 coal supply agreements. As of January 31, 2014, we had sales commitments for approximately 98% of planned shipments of western steam coal for 2014, all of which is priced, 91% of planned shipments of eastern steam coal for 2014, 75% of which is priced and 71% of planned shipments of metallurgical coal for 2014, 52% of which is priced. Additionally, we have approximately four million tons of CAPP thermal coal for 2014 with various European customers at prices tied to the API 2 index. These market-priced contracts expose us to changes in market prices which we may seek to offset, in part or in whole, by entering into derivative instruments. 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 by requiring us to pay a fixed price and receive a floating price.

We expect to use approximately 48.4 million and 46.7 million gallons of diesel fuel in 2014 and 2015, respectively. Through our derivative swap contracts, we have fixed prices for approximately 54% and 39% of our expected diesel fuel needs for 2014 and 2015, respectively. If the price of diesel fuel were to decrease in 2014, our expense resulting from our diesel fuel derivative swap contracts would increase, which would be offset by a decrease in the cost of our physical diesel fuel purchases.

Credit Risk

Our credit risk is primarily with electric power generators and steel producers. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to 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

We have exposure to changes in interest rates through our Credit Agreement, which has a variable interest rate at LIBOR plus a margin of 2.75% (subject to LIBOR floor of 0.75%), subject, in the case of the revolving credit line, to adjustment based on leverage ratios. As of December 31, 2013, our term loan due 2020 under the Credit Agreement had an outstanding balance of $617.4 million, net of debt discount of $2.9 million. The current portion of the term loan due in the next twelve months was $6.3 million. A 50 basis point increase or decrease in interest rates would increase or decrease our interest expense by $1.9 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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control - Integrated Framework(1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2014 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Roanoke, Virginia

February 28, 2014

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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,
	2013			2012			2011
Revenues:
Coal revenues	$	4,257,981		$	6,015,696		$	6,189,434
Freight and handling revenues	557,846			761,928			662,238
Other revenues	137,681			197,260			256,009
Total revenues	4,953,508			6,974,884			7,107,681
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)	3,980,744			5,004,516			5,080,921
Freight and handling costs	557,846			761,928			662,238
Other expenses	165,485			45,432			142,709
Depreciation, depletion and amortization	865,021			1,037,575			770,769
Amortization of acquired intangibles, net	5,056			(70,338		)	(114,422		)
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization shown separately above)	158,987			209,788			382,250
Asset impairment and restructuring	37,273			1,068,906			—
Goodwill impairment	253,102			1,713,526			802,337
Total costs and expenses	6,023,514			9,771,333			7,726,802
Loss from operations	(1,070,006		)	(2,796,449		)	(619,121		)
Other income (expense):
Interest expense	(246,588		)	(198,147		)	(141,914		)
Interest income	3,517			3,373			3,978
Gain (loss) on early extinguishment of debt	(40,464		)	773			(10,026		)
Miscellaneous income, net	23,493			3,306			635
Total other expense, net	(260,042		)	(190,695		)	(147,327		)
Loss before income taxes	(1,330,048		)	(2,987,144		)	(766,448		)
Income tax benefit	216,550			549,996			35,906
Net loss	$	(1,113,498	)	$	(2,437,148	)	$	(730,542	)
Basic loss per common share	$	(5.04	)	$	(11.06	)	$	(4.06	)
Diluted loss per common share	$	(5.04	)	$	(11.06	)	$	(4.06	)
Weighted average shares - basic	220,883,103			220,261,555			180,126,226
Weighted average shares - diluted	220,883,103			220,261,555			180,126,226

See accompanying Notes to Consolidated Financial Statements.

91

ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Amounts in thousands)

	Years ended December 31,
	2013			2012			2011
Net loss	$	(1,113,498	)	$	(2,437,148	)	$	(730,542	)
Other comprehensive income (loss), net of tax:
Employee benefit plans:
Current year actuarial gain (loss), net of income tax of ($88,803), ($516) and $94,516, for the years ended December 31, 2013, 2012 and 2011, respectively	111,960			(651		)	(156,990		)
Prior service (cost) credit for period, net of income tax of $0, ($16,776) and $6,177, for the years ended December 31, 2013, 2012 and 2011, respectively	—			28,084			(10,260		)
Less: reclassification adjustment for amounts reclassified to earnings due to amortization of actuarial net (gain) loss and settlements, net of income tax of ($1,657), ($2,898) and ($260), for the years ended December 31, 2013, 2012 and 2011, respectively	2,692			4,802			432
Less: reclassification adjustment for amounts reclassified to earnings due to amortization of prior service cost (credit), net of income tax of $1,459, $241 and $229, for the years ended December 31, 2013, 2012 and 2011, respectively	(2,360		)	(400		)	(380		)
Cash flow hedges:
Unrealized gains (losses) related to cash flow hedges, net of income tax of $625, ($8,272) and ($5,291), for the years ended December 31, 2013, 2012 and 2011, respectively	(971		)	13,812			8,297
Less: reclassification adjustment for amounts reclassified to earnings related to settlement of cash flow hedges, net of income tax of $1,244, $6,215 and $9,571, for the years ended December 31, 2013, 2012 and 2011, respectively	(1,843		)	(10,390		)	(15,407		)
Available-for-sale marketable securities:
Unrealized holding gains (losses) arising during the period, net of income tax of $49, ($185), and ($34), for the years ended December 31, 2013, 2012 and 2011, respectively	(74		)	309			56
Less: reclassification adjustment for (gains) losses reclassified to earnings, net of tax of ($30), $200, and ($3), for the years ended December 31, 2013, 2012 and 2011, respectively	46			(334		)	5
Total other comprehensive income (loss), net of tax	109,450			35,232			(174,247		)
Total comprehensive loss	$	(1,004,048	)	$	(2,401,916	)	$	(904,789	)

See accompanying Notes to Consolidated Financial Statements.

92

ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

	December 31, 2013			December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	619,644		$	730,723
Trade accounts receivable, net	287,655			418,166
Inventories, net	304,863			398,060
Short-term marketable securities	337,069			297,452
Prepaid expenses and other current assets	439,193			488,821
Total current assets	1,988,424			2,333,222
Property, equipment and mine development costs (net of accumulated depreciation and amortization of $2,355,425 and $1,910,058, respectively)	1,798,648			2,219,016
Owned and leased mineral rights and land (net of accumulated depletion of $1,167,912 and $908,416, respectively)	7,157,506			7,428,192
Goodwill, net	308,651			567,665
Other acquired intangibles (net of accumulated amortization of $422,737 and $655,047, respectively)	158,465			228,552
Other non-current assets	387,564			313,159
Total assets	$	11,799,258		$	13,089,806
Liabilities and Stockholders’ Equity
Current liabilities:
Current portion of long-term debt	$	29,169		$	95,015
Trade accounts payable	234,951			255,191
Accrued expenses and other current liabilities	978,695			872,402
Total current liabilities	1,242,815			1,222,608
Long-term debt	3,398,434			3,291,037
Pension and postretirement medical benefit obligations	990,124			1,195,187
Asset retirement obligations	728,575			763,482
Deferred income taxes	901,552			971,001
Other non-current liabilities	465,892			678,676
Total liabilities	7,727,392			8,121,991
Commitments and Contingencies (Note 23)
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, 232.8 million issued and 221.0 million outstanding at December 31, 2013 and 232.2 million issued and 220.6 million outstanding at December 31, 2012	2,328			2,322
Additional paid-in capital	8,185,222			8,075,694
Accumulated other comprehensive income (loss)	(57,148		)	(166,598		)
Treasury stock, at cost: 11.8 million and 11.6 million shares at December 31, 2013 and December 31, 2012, respectively	(271,737		)	(270,302		)
Accumulated deficit	(3,786,799		)	(2,673,301		)
Total stockholders’ equity	4,071,866			4,967,815
Total liabilities and stockholders’ equity	$	11,799,258		$	13,089,806

See accompanying Notes to Consolidated Financial Statements.

93

ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)

	Years Ended
	December 31,
	2013			2012			2011
Operating activities:
Net loss	$	(1,113,498	)	$	(2,437,148	)	$	(730,542	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	864,909			1,037,575			770,769
Amortization of acquired intangibles, net	5,056			(70,338		)	(114,422		)
Amortization of debt issuance costs and accretion of debt discount	51,217			43,745			30,263
Mark-to-market adjustments for derivatives	6,213			(2,795		)	(125,391		)
Accretion of asset retirement obligations	60,274			65,548			43,062
Stock-based compensation	25,873			9,881			53,685
Employee benefit plans, net	56,982			72,465			68,157
Loss (gain) on early extinguishment of debt	40,464			(773		)	10,026
Change in future costs of asset retirement obligations	(66,521		)	(157,173		)	37,137
Deferred income taxes	(212,361		)	(554,575		)	(17,084		)
Asset impairment and restructuring	37,273			1,068,906			—
Goodwill impairment	253,102			1,713,526			802,337
Other, net	3,466			(37,188		)	(22,698		)
Changes in operating assets and liabilities:
Trade accounts receivable, net	130,511			229,882			(178,704		)
Inventories, net	89,364			93,962			120,460
Prepaid expenses and other current assets	48,717			230,259			28,199
Other non-current assets	3,233			(7,549		)	(30,191		)
Trade accounts payable	(30,430		)	(246,228		)	84,784
Accrued expenses and other current liabilities	105,199			(407,128		)	(41,763		)
Pension and postretirement medical benefit obligations	(53,527		)	(53,008		)	(105,584		)
Asset retirement obligations	(44,862		)	(50,313		)	(22,833		)
Other non-current liabilities	(151,636		)	(23,114		)	26,970
Net cash provided by operating activities	109,018			518,419			686,637
Investing activities:
Cash paid for acquisition, net of cash acquired	—			—			(711,387		)
Capital expenditures	(215,661		)	(402,377		)	(528,586		)
Acquisition of mineral rights under federal lease	(42,130		)	(95,765		)	(64,900		)
Purchases of marketable securities	(900,471		)	(555,096		)	(374,048		)
Sales of marketable securities	857,000			352,112			547,249
Purchase of equity-method investments	—			(10,100		)	(14,800		)
Proceeds from disposition of property and equipment	10,605			38,250			8,470
Other, net	—			—			(9,005		)
Net cash used in investing activities	(290,657		)	(672,976		)	(1,147,007		)
Financing activities:
Proceeds from borrowings on long-term debt	1,306,677			494,795			2,100,000
Principal repayments of long-term debt	(1,176,332		)	(160,157		)	(1,315,357		)
Principal repayments of capital lease obligations	(16,745		)	(6,602		)	—
Debt issuance costs	(36,659		)	(16,361		)	(85,226		)
Common stock repurchases	(1,435		)	(7,507		)	(212,257		)
Proceeds from exercise of stock options	—			176			4,320
Other, net	(4,946		)	(4,946		)	—
Net cash provided by financing activities	70,560			299,398			491,480
Net (decrease) increase in cash and cash equivalents	(111,079		)	144,841			31,110
Cash and cash equivalents at beginning of period	730,723			585,882			554,772
Cash and cash equivalents at end of period	$	619,644		$	730,723		$	585,882

ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

(Amounts in thousands)

Supplemental cash flow information:
Cash paid for interest	$	191,178	$	144,958	$	92,137
Cash paid for income taxes	$	2,120	$	5,038	$	17,829
Cash received for income tax refunds	$	389	$	38,934	$	—
Supplemental disclosure of non-cash investing and financing activities:
Issuance of equity in connection with mergers and acquisitions	$	—	$	—	$	5,673,092
Capital leases - equipment	$	8,153	$	53,192	$	—

See accompanying Notes to Consolidated Financial Statements.

94

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, 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 of income tax	—	—		—		—			(174,247		)	—			(174,247		)
Equity component of convertible debt assumed in Massey Acquisition, net	—	—		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
Net loss	—	—		—		—			—			(1,113,498		)	(1,113,498		)
Other comprehensive income (loss), net	—	—		—		—			109,450			—			109,450
Equity component of convertible debt, net of income tax	—	—		83,131		—			—			—			83,131
Stock-based compensation and net issuance of common stock for share vesting	578	6		26,396		(1,434		)	—			—			24,968
Balances, December 31, 2013	232,812	$	2,328	$	8,185,221	$	(271,736	)	$	(57,148	)	$	(3,786,799	)	$	4,071,866

See accompanying Notes to Consolidated Financial Statements. 

95

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, 2013, the Company’s coal operations consisted of 57 deep and 24 surface mines located in Virginia, West Virginia, Pennsylvania, Kentucky and Wyoming. At December 31, 2013, the Company had approximately 10,500 employees, of which 12% 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 2012 Consolidated Statement of Cash Flows have been reclassified to conform to the current year presentation.

(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; 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, 2013.

96

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 Note 7 for further disclosures related to marketable securities.

Trade Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company establishes provisions for losses on accounts receivable when it is probable that all or part of the outstanding balance will not be collected. The Company regularly reviews its accounts receivable balances and establishes or adjusts the allowance as necessary primarily using the specific identification method. The allowance for doubtful accounts was $6,206 and $7,845 at December 31, 2013 and 2012, 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.

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 8 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 royalties. 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 they are no longer recoupable.

97

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, 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
Provision for non-recoupable advance mining royalties	3,425
Write-offs of advance mining royalties	(3,883		)
Balance at December 31, 2013	$	27,344

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. 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 $266,642, $325,999, and $253,622 for the years ended December 31, 2013, 2012, and 2011, respectively.

Acquired Intangibles

Application of acquisition accounting resulted in the recognition of assets for above market-priced coal supply and transportation agreements and liabilities 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. Coal supply and transportation agreement assets are reported in other acquired intangibles and coal supply agreement liabilities are reported in other non-current liabilities in the Consolidated Balance Sheets.

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 $71,867, $113,750, and $179,761 of expense and amortization of coal supply agreement liabilities was a credit to expense of ($66,811), ($184,088), and ($294,183), equating to a net (credit) expense of $5,056, ($70,338) and ($114,422) for the years ended December 31, 2013, 2012 and 2011, 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:

98

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

2014	$	38,298
2015	30,183
2016	23,970
2017	5,567
2018	792
Thereafter	5,409
Total net future amortization expense	$	104,219

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 or asset group to the estimated undiscounted future cash flows expected to be generated by the asset or asset group. If the carrying amount of an asset or asset group exceeds its estimated future cash flows, an impairment charge is recognized equal to the amount by which the carrying amount of the asset or asset group exceeds the fair value of the asset or asset group. 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 10 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 performs its goodwill impairment testing as of October 31 of each year or sooner if indicators of impairment are present. During 2013 and 2012, the Company performed interim goodwill impairment tests as of August 1, 2013 and June 1, 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 in two steps. Step one compares the fair value of each reporting unit to its carrying amount. If step one indicates that the carrying value of a reporting unit exceeds its fair value, 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 11 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 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 15 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

99

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 of the alternative minimum tax on the 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 19 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 natural gas and intercontinental commodity transportation services. With the exception of 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 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.

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 generally 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 20 for further disclosures related to workers’ compensation liabilities.

Black Lung Benefits

The Company is required by federal and state statutes to provide benefits to employees for awards related to black lung. The Company is self-insured at certain locations and covered by a third party insurance provider at other locations. Charges are made to operations for self-insured black lung claims, as determined by an independent actuary at the present value of the actuarially computed liability for such benefits over the employee’s applicable term of service. The Company recognizes in its balance sheet the amount of the Company’s unfunded Accumulated Benefit Obligation (“ABO”) at the end of the year. Amounts recognized in accumulated other comprehensive income (loss) are adjusted out of accumulated other comprehensive income (loss) when they are subsequently recognized as components of net periodic benefit cost. See Note 20 for further disclosures related to other postretirement benefits.

100

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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.

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 20 for further disclosures related to pension and 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 5 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 21 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 may designate a qualifying derivative instrument as a hedge of the variability of cash flows to be received or paid related to a recognized asset or liability or forecasted transaction (cash flow hedge). The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash flow hedges to specific firm commitments or forecasted transactions. The Company also formally assesses both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of the related hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Company discontinues hedge accounting prospectively and records all future changes in fair value in current period earnings or losses.

For derivative instruments that have not been designated as cash flow hedges, changes in fair value are recorded in current period earnings or losses. For derivative instruments that have been designated as cash flow hedges, the effective portion of the changes in fair value are recorded in accumulated other comprehensive income (loss) and any portion that is ineffective is recorded in current period earnings or losses. Amounts recorded in accumulated other comprehensive income (loss) are reclassified to earnings or losses in the period the underlying hedged transaction affects earnings or when the underlying hedged transaction is probable of not occurring. See Note 18 for further disclosures related to derivative financial instruments and hedging activities.

101

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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, net, with a corresponding entry to increase or decrease the carrying value of the investment.

New Accounting Pronouncements Adopted

In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 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 and the income statement line items affected by the reclassification. If a component is not required to be reclassified to net income in its entirety, companies would instead cross reference to the related footnote for additional information. The Company adopted the provisions of the new guidance during the first quarter of 2013.

In July 2013, the FASB issued ASU 2013-11, Presentation of Unrecognized Tax Benefits (“ASU 2013-11”). The standard requires an entity to present an unrecognized tax benefit as a reduction of a deferred tax asset for a net operating loss (NOL) carryforward, or similar tax loss or tax credit carryforward, rather than as a liability when the uncertain tax position would reduce the NOL or other carryforward under the tax law of the applicable jurisdiction and the entity intends to use the deferred tax asset for that purpose. ASU 2013-11 is effective for fiscal periods beginning after December 15, 2013. The Company is already in compliance with this standard.

(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 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 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.

102

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Year Ended  December 31, 2011
Total revenues:
As reported	$	7,107,681
Pro forma	$	8,642,096
Loss from operations:
As reported	$	(730,542	)
Pro forma	$	(834,645	)
Loss per share from operations-basic and diluted:
As reported	$	(4.06	)
Pro forma	$	(3.73	)

(4)    Accumulated Other Comprehensive Income (Loss)

The following table summarizes the changes to accumulated other comprehensive income (loss) during the year ended December 31, 2013:

	Balance December 31, 2012			Other comprehensive income (loss) before reclassifications			Amounts reclassified from accumulated other comprehensive income (loss)			Balance December 31, 2013
Employee benefit costs	$	(171,394	)	$	111,960		$	332		$	(59,102	)
Cash flow hedges	4,755			(971		)	(1,843		)	1,941
Available-for-sale marketable securities	41			(74		)	46			13
	$	(166,598	)	$	110,915		$	(1,465	)	$	(57,148	)

The following table summarizes the amounts reclassified from accumulated other comprehensive income (loss) and the Consolidated Statement of Operations line items affected by the reclassification during the year ended December 31, 2013:

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Details about accumulated other comprehensive income (loss) components	Amounts reclassified from accumulated other comprehensive income (loss)			Affected line item in the Consolidated Statements of Operations
	Year Ended December 31, 2013
Employee benefit costs:
Amortization of actuarial loss	$	4,561		(1)
Amortization of prior service credit	(3,819		)	(1)
Other	(212		)	(1)
Total before income tax	530
Income tax expense	(198		)	Income tax benefit
Total, net of income tax	$	332
Cash flow hedges:
Commodity swaps-coal	$	(4,111	)	Coal revenues
Commodity swaps-diesel fuel	2,777			Cost of coal sales
Commodity swaps-natural gas	(1,865		)	Other revenues
Commodity options-natural gas	112			Other revenues
Total before income tax	(3,087		)
Income tax benefit	1,244			Income tax benefit
Total, net of income tax	$	(1,843	)
Available-for-sale marketable securities:
Unrealized gains and losses	$	76		Interest income
Income tax expense	(30		)	Income tax benefit
Total, net of income tax	$	46

⁽¹⁾ These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit costs for pension, other postretirement benefit plans and black lung. See Note 20.

(5) Earnings Per Share

The number of shares used to calculate basic earnings 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 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 4.875% convertible senior notes due 2020 (the “4.875% Convertible Notes”), 3.75% convertible senior notes due 2017 (the “3.75% Convertible Notes”), 2.375% convertible senior notes due 2015 (the “2.375% Convertible Notes”), and 3.25% convertible senior notes due 2015 issued by Alpha Appalachia Holdings, Inc. (the “3.25% Convertible Notes”). The 4.875% Convertible Notes, 3.75% Convertible Notes, 2.375% Convertible Notes and 3.25% Convertible Notes become dilutive for earnings per common share calculations in certain circumstances and in specified periods. 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. In periods of net loss, the number of shares used to calculate diluted earnings per share is the same as basic earnings per share.

(6) Inventories, net

Inventories, net consisted of the following:

104

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	December 31,
	2013		2012
Raw coal	$	39,830	$	58,382
Saleable coal	171,240		233,550
Materials and supplies and other, net	93,793		106,128
Total inventories, net	$	304,863	$	398,060

(7) Marketable Securities

Short-term marketable securities consisted of the following:

	December 31, 2013
			Unrealized
	Cost		Gain		Loss			Fair value
Short-term marketable securities:
U.S. treasury and agency securities (a)	$	81,484	$	17	$	(4	)	$	81,497
Corporate debt securities (a)	255,567		49		(44		)	255,572
Total short-term marketable securities	$	337,051	$	66	$	(48	)	$	337,069

	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

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

Long-term marketable securities, with maturity dates between one and three years, included in other non-current assets, consisted of the following:

	December 31, 2013
			Unrealized
	Cost		Gain		Loss			Fair value
Long-term marketable securities:
Mutual funds held in rabbi trust (b)	$	7,261	$	3,637	$	(1,568	)	$	9,330

	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

105

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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

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

(8) Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consisted of the following:

	December 31,
	2013		2012
Prepaid insurance	$	12,273	$	21,292
Insurance and indemnification receivables (1)	195,228		196,074
Notes and other receivables	10,381		37,201
Deferred income taxes - current	118,757		117,692
Deferred long wall move expenses	10,766		11,159
Refundable income taxes	19,708		11,369
Derivative financial instruments	8,898		21,981
Prepaid freight	26,445		36,174
Deposits	13,671		15,923
Other prepaid expenses	23,066		19,956
Total prepaid expenses and other current assets	$	439,193	$	488,821

⁽¹⁾  See Note 13.

(9) Property, Equipment and Mine Development Costs

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

	December 31,
	2013		2012
Plant and mining equipment	$	3,731,282	$	3,688,516
Mine development	299,334		304,765
Office equipment, software and other	61,000		89,510
Construction in progress	62,457		46,283
Total property, equipment and mine development costs	4,154,073		4,129,074
Less accumulated depreciation and amortization	2,355,425		1,910,058
Total property, equipment and mine development costs, net	$	1,798,648	$	2,219,016

Included in plant and mining equipment are assets under capital leases totaling $92,105 with accumulated depreciation of $26,715 as of December 31, 2013. Included in plant and mining equipment are assets under capital lease totaling $84,044 with accumulated depreciation of $8,174 as of December 31, 2012.

Depreciation and amortization expense associated with property, equipment and mine development costs was $598,380, $711,577 and $517,222 for the years ended December 31, 2013, 2012 and 2011, respectively.

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

As of December 31, 2013 the Company had commitments to purchase approximately $14,010 of new equipment, expected to be acquired at various dates in 2014.

(10) Asset Impairment and Restructuring

106

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

A long-lived asset group that is held and used is 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 a longer than expected recovery in the metallurgical coal markets and lower production and shipment levels compared with previous estimates and announcements made 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 during the years ended December 31, 2013 and 2012. 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 assumptions. To the extent that the carrying values of the asset groups exceeded their fair value, the Company recorded an asset impairment charge.

For the year ended December 31, 2013, the Company recorded asset impairment charges totaling $1,890 related to mineral reserves in an asset group in its All Other segment. The Company also recorded severance expenses of $15,756, professional fees and other expenses of $9,627, and reserved $10,000 for other assets which may not be recoverable.

For the year ended December 31, 2012, the Company recorded asset impairment charges totaling $1,000,453, of which $994,876 was recorded for asset groups in its Eastern Coal Operations segment and $5,577 was recorded for an asset group in its All 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 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.

(11) Goodwill and Other Acquired Intangibles, Net

	Balance as of December 31, 2012			Impairments/Disposals			Balance as of December 31, 2013
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		$	(5,912	)	$	3,077,616
Accumulated impairment losses:
Eastern operations	$	(2,462,555	)	$	(253,102	)	$	(2,715,657	)
Western operations	(53,308		)	—			(53,308		)
All other	—			—			—
Total accumulated impairment losses	$	(2,515,863	)	$	(253,102	)	$	(2,768,965	)
Goodwill, net:
Eastern operations	$	561,753		$	(253,102	)	$	308,651
Western operations	—			—			—
All other	5,912			(5,912		)	—
Total goodwill, net	$	567,665		$	(259,014	)	$	308,651

107

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Balance as of December 31, 2011			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

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 in 2012. Additionally, during 2013, the Company performed an interim goodwill impairment test due primarily to a longer than expected recovery in the metallurgical coal markets and lower production and shipment levels compared with previous estimates and the Company’s assessment of its long-lived assets for impairment as of August 1, 2013.

The Company performed its interim and annual goodwill impairment tests 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 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 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 interim impairment testing date of August 1, 2013, its annual impairment testing date of October 31, 2012 and 2011 and the interim impairment testing date of June 1, 2012, the Company recorded impairment charges of $253,102, $188,194, $802,337 and $1,525,332, respectively, to reduce the carrying value of goodwill to its implied fair value. The impairment charges related to the Company’s Eastern Coal Operations were $253,102,

108

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

$188,194, $802,337 and $1,472,024 at August 1, 2013, October 31, 2012 and 2011, and June 1, 2012, respectively. The impairment charge related to the Company’s Western Coal Operations was $53,308 at June 1, 2012.

Other Acquired Intangibles:

	December 31, 2013
	Acquisition value		Accumulated amortization			Balance, net
Assets:
Above-market coal supply and transportation agreements	$	479,361	$	(365,448	)	$	113,913
Mining permits	101,841		(57,289		)	44,552
Total(1)	$	581,202	$	(422,737	)	$	158,465
Liabilities:
Below-market coal supply agreements(2)	$	605,281	$	(551,035	)	$	54,246

	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

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

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

(12) Other Non-current Assets

Other non-current assets consisted of the following:

	December 31,
	2013		2012
Marketable securities - long term (1)	$	9,330	$	8,888
Unamortized deferred financing costs, net	94,672		85,662
Advance mining royalties, net	60,310		61,604
Virginia tax credit, net	22,124		20,759
Equity-method investments	151,382		55,570
Derivative financial instruments	1,772		4,718
Insurance receivables	24,281		25,677
Other	23,693		50,281
Total other non-current assets	$	387,564	$	313,159

109

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

⁽¹⁾  See Note 7.

(13) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following:

	December 31,
	2013		2012
Wages and employee benefits	$	117,561	$	126,760
Current portion of asset retirement obligations	70,851		93,219
Taxes other than income taxes	123,361		131,291
Freight	4,650		9,090
Current portion of self insured workers’ compensation obligations	14,189		26,700
Interest payable	22,321		27,884
Derivative financial instruments	634		3,154
Current portion of postretirement medical benefit obligations	46,678		42,250
Deferred revenue	41,250		43,185
Litigation (a)	447,214		316,766
Other	89,986		52,103
Total accrued expenses and other current liabilities	$	978,695	$	872,402

^(a)  The Company has recorded related receivables of $195,228 and $196,074 from insurance coverage and indemnifications in prepaid expenses and other current assets at December 31, 2013 and 2012, respectively.

(14) Long-Term Debt

Long-term debt consisted of the following:

	December 31,
	2013			2012
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			500,000
Term loan due 2020	620,313			—
Term loan due 2016	—			540,000
4.875% convertible senior notes due 2020	345,000			—
3.75% convertible senior notes due 2017	345,000			—
3.25% convertible senior notes due 2015	128,182			536,162
2.375% convertible senior notes due 2015	65,889			287,500
Other	73,305			86,203
Debt discount	(150,086		)	(63,813		)
Total long-term debt	$	3,427,603		$	3,386,052
Less current portion	(29,169		)	(95,015		)
Long-term debt, net of current portion	$	3,398,434		$	3,291,037

110

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Fourth Amended and Restated Credit Agreement

On May 22, 2013, the Company entered into a Fourth Amended and Restated Credit Agreement, which was amended in October 2013 by Amendment No. 1 thereto (as amended, the “Credit Agreement”) with the lenders party thereto, the issuing banks party thereto, Citicorp North America, Inc., as administrative agent and as collateral agent, and all other parties thereto from time to time, which amended and restated the Company’s Third Amended and Restated Credit Agreement, dated as of May 19, 2011, as amended June 26, 2012 (the “Former Credit Agreement”).

The Credit Agreement includes a $625,000 senior secured term loan B facility (the “Term Loan Facility”), which matures on May 22, 2020, amortizes in quarterly installments at a rate of 1.0% per year and bears an interest rate at the Company’s option of either LIBOR plus a margin of 2.75% (subject to a LIBOR floor of 0.75%) or an Alternate Base Rate (ABR) plus a margin of 1.75% (subject to an ABR floor of 1.75%). The interest rate in effect as of December 31, 2013 was 3.50%. 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 senior secured revolving facility (the “Revolving Facility”) in respect of the unutilized commitments thereunder. The initial commitment fee is 0.50% per annum, 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.

The proceeds of the Term Loan Facility were used to repay the entire $525,000 aggregate principal amount of the Company’s outstanding obligations under its term loan A facility under the Former Credit Agreement, which would have matured on June 30, 2016, with the balance used to pay fees and expenses and for general corporate purposes. The Company recorded a loss on early extinguishment of debt of $9,044, primarily related to certain fees incurred in the transactions and the write off of certain outstanding deferred fees.

The principal changes to the Former Credit Agreement effected by the Credit Agreement include increasing the existing Revolving Facility from $1,000,000 to $1,100,000 through its maturity date of June 30, 2016 and modifying the financial covenants by:

• modifying the interest coverage ratio covenant from 2.25 to 1.50 through 2013, from 2.50 to 1.50 during 2014 and from 2.50 to 2.00 from 2015 through the maturity date of the revolving credit facility. Subsequently, on October 2, 2013, the Company entered into an amendment to the Credit Agreement which eliminated the interest coverage ratio through the end of 2014 and reduced the interest coverage ratio from 2.00 to 1.25 during 2015 and from 2.00 to 1.50 during the first two quarters of 2016;

• eliminating the leverage ratio covenant;

• extending the applicability of the senior secured leverage ratio of 2.50 through the maturity date of the revolving credit facility; and

• reducing the minimum liquidity covenant, which applies until December 31, 2014, from $500,000 to $300,000;

Additionally, the terms of the Credit Agreement (i) further restrict the ability of the Company and its subsidiaries to make investments, loans and acquisitions, incur additional indebtedness, and pay dividends on its capital stock or redeem, repurchase or retire its capital stock; and (ii) require the Company to provide additional collateral to secure the obligations under the Credit Agreement, consisting of receivables previously securing the Second Amended and Restated Receivables Purchase Agreement.

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 (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

111

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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.

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.

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.

Third Amended and Restated Credit Agreement

On May 19, 2011, in connection with the Massey Acquisition, Alpha entered into the Former Credit Agreement to amend and restate in its entirety the credit agreement dated as of July 30, 2004, as amended. The terms of the Former Credit Agreement amended and restated and superseded the credit agreement dated as of July 30, 2004, as amended, 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 credit agreement dated as of July 30, 2004, as amended, remained in full force and effect until the occurrence of the initial Credit Event.

Upon the occurrence of the initial Credit Event, the Former Credit Agreement provided for a $600,000 senior secured term loan A facility and a $1,000,000 senior secured revolving credit facility. Pursuant to the Former Credit Agreement, Alpha was able to 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 were not under any obligation to provide any such incremental loans or commitments, and any such addition of or increase in such loans or commitments were subject to certain customary conditions precedent.

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

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

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

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

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

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

112

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

As of December 31, 2013, the carrying value of the Term Loan Facility was $617,460, net of debt discount of $2,853, with $6,250 classified as current portion of long-term debt. As of December 31, 2012, the carrying value of the senior secured term loan A facility was $539,481, net of debt discount of $519, with $75,000 classified as current portion of long-term debt. There were no borrowings outstanding under the Revolving Facility as of December 31, 2013 or 2012. Letters of credit outstanding at December 31, 2013 and 2012 under the Revolving Facility were $133,975 and $300, respectively.

Termination of Account Receivable Securitization Facility

Simultaneously with its entry into the Fourth Amended and Restated Credit Agreement, the Company also terminated the Second Amended and Restated Receivables Purchase Agreement, dated as of October 19, 2011 (as amended from time to time, the “A/R Facility”), by and among ANR Receivables Funding, LLC, as seller, Alpha Natural Resources, LLC, as servicer, PNC Bank, National Association, as administrator and LC Bank (as defined therein), and the other parties thereto from time to time. The A/R Facility provided for the issuance of letters of credit in a maximum aggregate amount of $275,000. All previously outstanding letters of credit under the A/R Facility were transferred to the Credit Agreement and were deemed to be issued thereunder. The Company recorded a loss on early extinguishment of debt of $1,358 in connection with the termination, primarily related to the write off of outstanding deferred fees.

Convertible Senior Notes

In May 2013, the Company issued $345,000 principal amount of 3.75% Convertible Notes and in December 2013, the Company issued $345,000 principal amount of 4.875% Convertible Notes (the 4.875% Convertible Notes, and together with the 3.75% Convertible Notes, the “Convertible Notes”). The 3.75% Convertible Notes bear interest at a rate of 3.75% per annum, payable semi-annually in arrears on June 15 and December 15 of each year, and will mature on December 15, 2017. The 4.875% Convertible Notes bear interest at a rate of 4.875% per annum, payable semi-annually in arrears on June 15 and December 15 of each year, and will mature on December 15, 2020.

The proceeds from the 3.75% Convertible Notes, together with cash on hand, were used to repurchase $225,787 of the Company’s outstanding 3.25% Convertible Notes and $181,403 of the Company’s outstanding 2.375% Convertible Notes. The Company recorded a loss on early extinguishment of debt of $22,795, primarily related to the write off of outstanding debt discounts. The proceeds from the 4.875% Convertible Notes were used to repurchase $177,093 of the Company’s outstanding 3.25% Convertible Notes and $36,808 of the Company’s outstanding 2.375% Convertible Notes. The Company recorded a loss on early extinguishment of debt of $7,425, primarily related to the write off of outstanding debt discounts.

The Company separately accounts for the liability and equity components of the Convertible Notes in a manner reflective of its’ nonconvertible debt borrowing rate. The related deferred loan costs and discount are being amortized and accreted, respectively, over the terms of the Convertible Notes, and provide for an effective interest rate of 8.49% in the case of the 3.75% Convertible Notes and 9.48% in the case of the 4.875% Convertible Notes. As of December 31, 2013, the carrying amount of the debt component was $290,219 in the case of the 3.75% Convertible Notes and $264,283 in the case of the 4.875% Convertible Notes, and the unamortized debt discount was $54,781 in the case of the 3.75% Convertible Notes and $80,717 in the case of the 4.875% Convertible Notes. As of December 31, 2013, the carrying amount of the equity component was $61,949 in the case of the 3.75% Convertible Notes and $81,114 in the case of the 4.875% Convertible Notes. 

The Convertible Notes are the Company’s senior unsecured obligations and rank equally with all of its existing and future senior unsecured indebtedness. The Convertible Notes are guaranteed on a senior unsecured basis by each of the Company’s current and future wholly owned domestic subsidiaries that guarantee the Company’s obligations under its 9.75% senior notes due 2018. The Convertible Notes are effectively subordinated to all of the Company’s existing and future secured indebtedness and all existing and future liabilities of its non-guarantor subsidiaries, including trade payables.

The Convertible Notes are convertible in certain circumstances and in specified periods at an initial conversion rate of 99.0589 shares of common stock per $1 of principal amount of notes in the case of the 3.75% Convertible Notes and 107.0893 shares of common stock per $1 of principal amount of notes in the case of the 4.875% Convertible Notes, subject to adjustment upon the occurrence of certain events set forth in the fourth and fifth supplemental indentures (the “Supplemental Indentures”) to the indenture dated June 1, 2011 (the “Base Indenture” and, together with the Supplemental Indentures, the “Convertible Notes Indentures”) governing the Convertible Notes, equivalent to an initial conversion price of approximately $10.10 per share of common stock in the case of the 3.75% Convertible Notes and $9.34 in the case of the 4.875% Convertible Notes. Upon conversion, the notes may be settled, at the Company’s election, in cash, shares of our common stock or a combination thereof. The Company intends to settle conversions, if any, using a combination of cash and shares.

113

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The Convertible Notes Indentures contain 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 Convertible Notes then outstanding may declare the principal of the Convertible Notes and any accrued and unpaid interest thereon immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to the Company, the principal amount of the Convertible Notes together with any accrued and unpaid interest thereon will automatically become due and be immediately payable.

The Convertible Notes were not convertible as of December 31, 2013 and, as a result, have been classified as long-term debt as of that date.

Other Repurchases of 2.375% and 3.25% Convertible Senior Notes due 2015

In August 2013, the Company repurchased approximately $3,400 of its outstanding 2.375% Convertible Notes and approximately $5,100 of its outstanding 3.25% Convertible Notes and recorded a gain on early extinguishment of debt of $158.

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, 2013, the carrying values of the 2018 Notes, 2019 Notes and 2021 Notes were $496,547, net of discount of $3,453, $800,000 and $700,000, respectively. 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.

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 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,

114

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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.

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, 2013, the carrying amount of the debt was $125,142, net of debt discount of $3,040. As of December 31, 2012 the carrying amount of the debt was $515,901, net of debt discount of $20,261. December 31, 2013 and 2012, 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%

115

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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, 2013 or 2012 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, 2013 and 2012, the Company had $65,889 and $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, 2013 and 2012, the carrying amounts of the debt component were $60,647 and $249,306, respectively. As of December 31, 2013 and 2012, the unamortized debt discount was $5,242 and $38,194, respectively. As of December 31, 2013 and 2012, 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, 2013 and 2012 and therefore have been classified as long-term debt at both dates.

Capital Leases

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The Company entered into capital leases for certain property and other equipment during 2013 and 2012. The Company’s liability for capital leases as of December 31, 2013 and 2012 totaled $58,874 and $66,976, respectively.

Future Maturities

Future maturities of long-term debt as of December 31, 2013 are as follows:

2014	$	29,169
2015	216,601
2016	12,594
2017	14,629
2018	851,487
Thereafter	2,453,209
Total long-term debt	$	3,577,689

(15) Asset Retirement Obligations

As of December 31, 2013 and 2012, the Company had recorded asset retirement obligation accruals for mine reclamation and closure costs totaling $799,426 and $856,701, respectively. The portion of the costs expected to be paid within a year of $70,851 and $93,219, as of December 31, 2013 and 2012, 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, 2013 or 2012. 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.

Changes in the asset retirement obligations were as follows:

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(1)	(95,294		)
Expenditures for the period	(50,313		)
Total asset retirement obligations at December 31, 2012	856,701
Accretion for the period	60,274
Sites added during the period	1,667
Revisions in estimated cash flows(2)	(74,354		)
Expenditures for the period	(44,862		)
Total asset retirement obligations at December 31, 2013	$	799,426
Less current portion	(70,851		)
Long-term portion	$	728,575

⁽¹⁾  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.

⁽²⁾  Amount includes a reduction of $66,521 primarily related to changes in the discount rate, which was recorded as a reduction to cost of coal sales in the Consolidated Statements of Operations for the year ended December 31, 2013.

(16) Other Non-current Liabilities

Other non-current liabilities consisted of the following:

117

	December 31,
	2013		2012
Self insured workers’ compensation obligations	$	142,537	$	153,283
Black lung obligations	136,457		135,879
Below-market and other contract-related obligations, net (1)	85,728		255,031
Deferred coal revenue	33,138		43,539
Derivative financial instruments	31		972
Other	68,001		89,972
Total other non-current liabilities	$	465,892	$	678,676

⁽¹⁾ During the year ended December 31, 2013, the Company recorded a credit of ($55,454) to other expense for the settlement of a contract-related matter.

(17) 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 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.

The following tables set forth by level, within the fair value hierarchy, the Company’s long-term debt at fair value as of December 31, 2013 and 2012, respectively:

	December 31, 2013
	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	$	602,000	$	602,000	$	—	$	—
6.00% senior notes due 2019	800,000		694,872		694,872		—		—
9.75% senior notes due 2018(4)	496,547		560,250		560,250		—		—
Term loan due 2020(5)	617,460		617,291		—		617,291		—
4.875% convertible senior notes due 2020(7)	264,283		372,606		372,606		—		—
3.75% convertible senior notes due 2017(6)	290,219		360,956		360,956		—		—
3.25% convertible senior notes due 2015(2)	125,142		126,904		126,904		—		—
2.375% convertible senior notes due 2015(3)	60,647		65,882		65,882		—		—
Total long-term debt	$	3,354,298	$	3,400,761	$	2,783,470	$	617,291	$	—

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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
	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	$	—

⁽¹⁾  Net of debt discount of $519 as of December 31, 2012.

⁽²⁾  Net of debt discount of $3,040 and $20,261 as of December 31, 2013 and 2012, respectively.

⁽³⁾  Net of debt discount of $5,242 and $38,194 as of December 31, 2013 and 2012, respectively.

⁽⁴⁾  Net of debt discount of $3,453 and $4,839 as of December 31, 2013 and 2012, respectively.

⁽⁵⁾  Net of debt discount of $2,853 as of December 31, 2013.

⁽⁶⁾  Net of debt discount of $54,781 as of December 31, 2013.

⁽⁷⁾  Net of debt discount of $80,717 as of December 31, 2013.

ASC 820 requires disclosures about how fair value is determined for assets and liabilities and a hierarchy for which these assets and liabilities must be grouped, based on significant levels of inputs as follows:

Level 1 - Quoted prices in active markets for identical assets or liabilities;

Level 2 - Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and

Level 3 - Unobservable inputs in which there is little or no market data which require the reporting entity to develop its own assumptions.

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

The following tables set forth by level, within the fair value hierarchy, the Company’s financial and non-financial assets and liabilities that were accounted for at fair value on a recurring and non-recurring basis as of December 31, 2013 and 2012, respectively. 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, 2013
	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	$	81,497		$	81,497	$	—		$	—
Mutual funds held in rabbi trust	$	9,330		$	9,330	$	—		$	—
Corporate debt securities	$	255,572		$	—	$	255,572		$	—
Forward coal sales	$	(398	)	$	—	$	(398	)	$	—
Commodity swaps	$	10,403		$	—	$	10,403		$	—

119

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	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		$	—

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 is based on observable market data.

6.25% senior notes due 2021, 6.00% senior notes due 2019, 9.75% senior notes due 2018, 4.875% Convertible Notes, 3.75% Convertible Notes, 2.375% Convertible Notes, and 3.25% Convertible Notes — The fair value is based on observable market data.

Level 2 Fair Value Measurements

Corporate Debt Securities — The fair values of the Company’s corporate debt securities are obtained from a third-party pricing service provider. The fair values provided by the pricing service provider are estimated using pricing models, where the inputs to those models are based on observable market inputs including credit spreads and broker-dealer quotes, among other inputs. The Company classifies the prices obtained from the pricing services within Level 2 of the fair value hierarchy because the underlying inputs are directly observable from active markets. However, the pricing models used do entail a certain amount of subjectivity and therefore differing judgments in how the underlying inputs are modeled could result in different estimates of fair value.

Forward Coal Purchases 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 credit risk, when applicable.

Commodity Options — The fair values of the commodity options were estimated using an option pricing model that incorporates data on the historical volatility of the underlying commodity, the strike price and notional amount of the option, the current market price of the option and a risk free interest rate. The fair values are adjusted for counter-party credit risk, when applicable.

Term Loans due 2016and 2020 — The fair values of the term loans due 2016 and 2020 were estimated based on market rates of interest offered for debt of similar maturities.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

(18) 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.

Commodity Swaps

The Company uses diesel fuel in its production process and incurs significant expenses for its purchases. Diesel fuel expenses represented approximately 6%, 6%, and 5% of cost of coal sales for the years ended December 31, 2013, 2012, and 2011, respectively. The Company is subject to the risk of price volatility for this commodity 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, 2013, the Company had swap agreements outstanding to hedge the variable cash flows related to 54% and 39% of anticipated diesel fuel usage for calendar years 2014 and 2015, respectively. The average fixed price for these diesel fuel swaps is $2.82 per gallon and $2.75 per gallon for calendar years 2014 and 2015, 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, 2013, 2012, and 2011. 

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	Statement of Financial Position Location	December 31, 2013		December 31, 2012
Commodity swaps	Prepaid expenses and other current assets	$	—	$	6,484
Commodity swaps	Other non-current assets	—		4,718
Commodity options	Prepaid expenses and other current assets	—		138
		$	—	$	11,340
Derivatives not designated as  cash flow hedging instruments	Statement of Financial Position Location	December 31, 2013		December 31, 2012
Commodity swaps	Prepaid expenses and other current assets	$	8,898	$	—
Commodity swaps	Other non-current assets	1,772		—
Forward coal sales	Prepaid expenses and other current assets	—		15,359
		$	10,670	$	15,359
Total asset derivatives		$	10,670	$	26,699

121

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

		Liability Derivatives
Derivatives designated as  cash flow hedging instruments	Statement of Financial Position Location	December 31, 2013		December 31, 2012
Commodity swaps	Accrued expenses and other current liabilities	$	—	$	2,457
Commodity swaps	Other non-current liabilities	—		972
		$	—	$	3,429
Derivatives not designated as  cash flow hedging instruments	Statement of Financial Position Location	December 31, 2013		December 31, 2012
Commodity swaps	Other non-current liabilities	$	31	$	—
Commodity swaps	Accrued expenses and other current liabilities	236		693
Forward coal sales	Accrued expenses and other current liabilities	398		—
Forward coal purchases	Accrued expenses and other current liabilities	—		4
		$	665	$	697
Total liability derivatives		$	665	$	4,126

The following table presents the gains and losses from derivative instruments for the years ended December 31, 2013, 2012, and 2011 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	2013			2012		2011		2013			2012			2011
Commodity swaps (1) (3)	$	1,911		$	10,390	$	15,407	$	(908	)	$	13,831		$	8,277
Commodity options (2) (3)	(68		)	—		—		(63		)	(19		)	20
Total	$	1,843		$	10,390	$	15,407	$	(971	)	$	13,812		$	8,297

 __________________

⁽¹⁾  Amounts recorded in cost of coal sales in the Consolidated Statements of Operations

⁽²⁾  Amounts recorded in other revenues in the Consolidated Statements of Operations.

⁽³⁾  Net of income tax.

	Gain (loss) recorded in earnings
Derivatives not designated as  cash flow hedging instruments	2013			2012			2011
Forward coal sales (1)	$	(15,756	)	$	(11,887	)	$	149,252
Forward coal purchases (1)	4			15,452			(22,408		)
Commodity swaps (2)	9,539			348			(436		)
Commodity options-coal (1)	—			17			246
Interest rate swaps (3)	—			(400		)	(1,263		)
Total	$	(6,213	)	$	3,530		$	125,391

_________________________________

⁽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.

122

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Unrealized losses recorded in accumulated other comprehensive income (loss) are reclassified to income or loss as the financial swaps settle and the Company purchases the underlying items that are being hedged. During the next twelve months, the Company expects to reclassify approximately $2,317, net of tax, to earnings.

During the third quarter of 2013, the Company elected to cease applying hedge accounting to outstanding commodity swaps. Changes in fair value of those derivative instruments are now recorded in earnings. Amounts previously recognized in accumulated other comprehensive income (loss) will be recognized in income when the underlying transactions are consummated.

(19) Income Taxes

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

	Years Ended December 31,
	2013			2012			2011
Current tax expense (benefit):
Federal	$	(3,949	)	$	(1,686	)	$	(12,915	)
State	(240		)	6,265			(5,906		)
	$	(4,189	)	$	4,579		$	(18,821	)
Deferred tax expense (benefit):
Federal	$	(203,560	)	$	(482,015	)	$	(18,743	)
State	(8,801		)	(72,560		)	1,658
	$	(212,361	)	$	(554,575	)	$	(17,085	)
Total income tax expense (benefit):
Federal	$	(207,509	)	$	(483,701	)	$	(31,658	)
State	(9,041		)	(66,295		)	(4,248		)
	$	(216,550	)	$	(549,996	)	$	(35,906	)

A reconciliation of the statutory federal income tax benefit at 35% to the actual income tax benefit is as follows:

	Years Ended December 31,
	2013			2012			2011
Federal statutory income tax expense (benefit)	$	(465,517	)	$	(1,045,500	)	$	(268,257	)
Increases (reductions) in taxes due to:
Percentage depletion allowance	(34,702		)	(76,252		)	(60,166		)
State taxes, net of federal tax impact	(49,523		)	(25,748		)	(10,168		)
State tax rate and NOL change, net of federal tax benefit	(2,524		)	(8,180		)	(8,180		)
Change in valuation allowances	207,681			43,885			3,479
Non-deductible fines and penalties	14,513			3,996			4,468
State apportionment change, net of federal tax impact	15,425			(18,654		)	13,166
Non-deductible goodwill impairment	88,586			572,503			280,818
Reversal of reserves for uncertain tax positions (1)	—			—			(1,057		)
Other, net	9,511			3,954			9,991
Income tax benefit	$	(216,550	)	$	(549,996	)	$	(35,906	)

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

123

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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,
	2013			2012
Deferred tax assets:
Asset retirement obligations	$	297,405		$	316,440
Reserves and accruals not currently deductible	145,870			97,361
Pension and postretirement medical obligations	374,662			457,072
Alternative minimum tax credit carryforwards	210,742			215,308
Goodwill	31,700			34,791
Workers’ compensation obligations	104,424			109,399
Acquired intangibles, net	6,469			48,759
Deferred revenue	28,080			35,058
Other	36,101			17,479
Net operating loss carryforwards	797,284			544,244
Gross deferred tax assets	2,032,737			1,875,911
Less valuation allowance	(294,073		)	(86,392		)
Total net deferred tax assets	1,738,664			1,789,519
Deferred tax liabilities:
Property, equipment and mineral reserves	(2,367,180		)	(2,535,035		)
Debt discount	(53,490		)	(21,783		)
Prepaid expenses	(57,411		)	(54,439		)
Other	(43,378		)	(31,571		)
Total deferred tax liabilities	(2,521,459		)	(2,642,828		)
Net deferred tax liability	$	(782,795	)	$	(853,309	)

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

	December 31,
	2013			2012
Current asset	$	118,757		$	117,692
Noncurrent liability	(901,552		)	(971,001		)
Total net deferred tax liability	$	(782,795	)	$	(853,309	)

Changes in the valuation allowance during the years ended December 31, 2013 and 2012 were as follows: 

	December 31,
	2013		2012
Valuation allowance beginning of period	$	86,392	$	41,940
Increase in valuation allowance not affecting income tax expense	—		567
Increase in valuation allowance recorded as an increase to income tax expense	207,681		43,885
Valuation allowance end of period	$	294,073	$	86,392

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.

124

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The Company recorded an increase to the valuation allowance of $207,681, primarily related to net operating losses generated during 2013. Based on available evidence, it is more likely than not that the net operating losses generated during 2013 will not be realized.

At December 31, 2013, the Company has regular tax net operating loss carryforwards for Federal income tax purposes of approximately $2,000,000 which are available to offset regular Federal taxable income. The net operating losses generated will not start to expire until 2023. A valuation allowance has been provided for $546,000 of the federal net operating losses. The Company has gross net operating loss carryforwards for state income taxes of approximately $2,400,000 which are available to offset future state taxable income generally through 2033. A valuation allowance has been provided for approximately $1,700,000 of the state net operating losses. The Company also has alternative minimum tax credit carryforwards of approximately $210,742, 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, 2013. The Company believes that it is reasonably possible that a decrease in unrecognized tax benefits of $28,741 may be necessary during the next twelve months, as a result of settlements with taxing authorities.

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, 2013, the Company has recorded accrued interest and penalties of $826 and $514, respectively.

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

	December 31,
	2013		2012		2011
Unrecognized tax benefits — beginning of period	$	28,741	$	28,741	$	25,442
Gross adjustments — Massey Acquisition	—		—		2,721
Gross increases — tax positions in prior periods	—		—		1,590
Reduction as a result of a lapse of the applicable statute of limitations	—		—		(1,012		)
Unrecognized tax benefits - end of period	$	28,741	$	28,741	$	28,741

Tax years 2009-2013 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.

(20) Employee Benefit Plans

The Company provides several types of benefits 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 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 already having taken effect, and with additional changes extending over the next several years through 2018 and beyond. Plan standard changes that 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.

125

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 $29,710 as of December 31, 2013 for the estimated impact of the PPACA, which is included in the liability for postretirement medical benefit obligations. 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.

(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. 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 post-65 union retirees were enrolled in an Employer Group Waiver Plan (“EGWP”), and the majority of the Company’s post-65 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:

126

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	December 31,
	2013			2012
Change in benefit obligations:
Accumulated benefit obligation-beginning period:	$	1,006,193		$	1,079,368
Service cost	13,785			16,408
Interest cost	40,170			42,122
Actuarial gain	(84,769		)	(47,753		)
Benefits paid	(32,686		)	(39,117		)
Change in plan provisions	—			(44,835		)
Accumulated benefit obligation-end of period	$	942,693		$	1,006,193
Change in fair value of plan assets:
Employer contributions	$	32,686		$	39,117
Benefits paid	(32,686		)	(39,117		)
Fair value of plan assets at December 31	—			—
Funded status	$	(942,693	)	$	(1,006,193	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	(46,678	)	$	(42,250	)
Long-term liabilities	(896,015		)	(963,943		)
	$	(942,693	)	$	(1,006,193	)
Amounts recognized in accumulated other comprehensive (income) loss:
Prior service credit	$	(24,521	)	$	(28,340	)
Net actuarial loss	64,288			151,929
	$	39,767		$	123,589

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

	Years Ended December 31,
	2013			2012			2011
Service cost	$	13,785		$	16,408		$	12,728
Interest cost	40,170			42,122			43,212
Amortization of net actuarial loss	2,872			4,656			2,302
Amortization of prior service credit	(3,819		)	(641		)	(609		)
Net periodic benefit cost	$	53,008		$	62,545		$	57,633

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

127

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Years Ended December 31,
	2013			2012			2011
Current year actuarial (gain) loss	$	(84,769	)	$	(47,753	)	$	142,936
Prior service cost (credit) for period	—			(44,835		)	16,437
Amortization of net actuarial (loss)	(2,872		)	(4,656		)	(2,302		)
Amortization of prior service credit	3,819			641			609
Total recognized in other comprehensive (income) loss	$	(83,822	)	$	(96,603	)	$	157,680
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$	(30,815	)	$	(34,058	)	$	215,313

The estimated amount that will be amortized from accumulated other comprehensive (income) loss into net period benefit cost in 2014 is as follows: 

Prior service credit $ (3,819 )

The weighted-average assumptions used to determine the postretirement plans’ benefit obligation as of December 31, 2013 and 2012 were as follows: 

	December 31,
	2013		2012
Discount rate	4.68	%	3.89	%

The weighted average discount rates used in determining net periodic postretirement medical benefit cost for the years ended December 31, 2013, 2012, and 2011 were as follows: 

	Years Ended December 31,
	2013	2012	2011
Discount rate	4.18%	4.10%	5.03%

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	2020

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, 2013: 

	One Percentage Point Increase		One Percentage Point Decrease
Effect on total service and interest cost components	$	8,398	$	(6,586	)
Effect on accumulated postretirement benefit obligation	$	117,969	$	(96,947	)

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: 

128

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Postretirement Medical and Life Insurance Benefits
2014	$	46,678
2015	51,005
2016	54,642
2017	57,372
2018	59,657
2019-2023	302,810
	$	572,164

(b) Company Administered Defined Benefit Pension Plans

The Company has three qualified non-contributory defined benefit pension plans, which cover certain salaried and non-union hourly employees. Participants accrued benefits either based on certain formulas, the participant’s compensation prior to retirement, or plan specified amounts for each year of service with the Company. Benefits are frozen under these plans.

In addition to the qualified defined benefit plan noted above, the Company also has a nonqualified restoration plan for certain salaried employees. Participants in this nonqualified plan accrued benefits based on the qualified plan formula, however, where the benefit or pensionable earnings were capped by the Internal Revenue Service (“IRS”) limitations, this nonqualified plan restores benefits in excess of the IRS limits. The Company also has a non-qualified Supplemental Executive Retirement Plan (“SERP”). Benefits are based on the employee’s compensation prior to retirement or the plan becoming frozen. Benefits are frozen under these plans and they are unfunded.

The qualified non-contributory defined benefit pension plans are collectively referred to as the “Pension Plans”. The non-qualified supplement benefit pension plans 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:

129

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	December 31,
	2013			2012
Change in benefit obligation:
Accumulated benefit obligation at beginning of period	$	792,383		$	716,289
Interest cost	29,497			31,990
Actuarial (gain) loss	(135,832		)	97,854
Benefits paid	(23,607		)	(20,398		)
Settlements	(33,062		)	(33,352		)
Accumulated benefit obligation at end of period	$	629,379		$	792,383
Change in fair value of plan assets:
Fair value of plan assets at beginning of period	$	561,151		$	541,555
Actual return on plan assets	27,786			69,610
Employer contributions	3,002			3,736
Benefits paid	(23,607		)	(20,398		)
Settlements	(33,062		)	(33,352		)
Fair value of plan assets at end of period	535,270			561,151
Funded status	(94,109		)	(231,232		)
Accrued benefit cost at end of year	$	(94,109	)	$	(231,232	)

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

	Years Ended December 31,
	2013		2012
Net actuarial loss	$	12,631	$	140,660

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

	Years Ended December 31,
	2013			2012			2011
Service cost	$	—		$	—		$	8,380
Interest cost	29,497			31,990			24,465
Expected return on plan assets	(36,199		)	(38,798		)	(29,984		)
Amortization of net actuarial (gain) loss	822			1,837			(97		)
Settlement (gain) loss	(212		)	1,207			(2,431		)
Total	$	(6,092	)	$	(3,764	)	$	333

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

	Years Ended December 31,
	2013			2012			2011
Current year actuarial (gain) loss	$	(127,419	)	$	67,042		$	93,332
Amortization of net actuarial (loss) gain	(822		)	(1,837		)	97
Settlement gain (loss)	212			(1,207		)	2,431
Total recognized in other comprehensive (income) loss	$	(128,029	)	$	63,998		$	95,860
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$	(134,121	)	$	60,234		$	96,193

130

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

No amounts are expected to be amortized from accumulated other comprehensive (income) loss into net period benefit cost in 2014.

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

	December 31,
	2013		2012
Projected benefit obligation	$	629,379	$	792,383
Accumulated benefit obligation	$	629,379	$	792,383
Fair value of plan assets	$	535,270	$	561,151

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, 2013 and 2012.

The weighted-average actuarial assumptions used in determining the benefit obligations as of December 31, 2013 and 2012 were as follows: 

	December 31,
	2013	2012
Discount rate	4.87%	3.95%

The weighted-average actuarial assumptions used to determine net periodic benefit cost for the years ended December 31, 2013 and 2012 were as follows: 

	December 31,
	2013	2012	2011
Discount rate	4.21%	4.22%	5.06%
Rate of increase in future compensation (a)	N/A	N/A	3.00%
Expected long-term return on plan assets	6.75%	7.25%	7.75%
Measurement date	December 31, 2013	December 31, 2012	December 31, 2011

^(a) These Pension Plans are frozen.

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 2014, 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 2014 and the actual asset allocation as reported at December 31, 2013 is as follows:

131

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Target Allocation Percentages 2014		Percentage of Plan Assets 2013
Equity funds	44.0	%	44.7	%
Fixed income funds	54.0	%	52.5	%
Private equity funds/guaranteed insurance contract	2	%	2.8	%
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, 2013, 2012 and 2011, $3,002, $3,736 and $70,374, respectively, of cash contributions were made to the Pension Plans and SERP. The Company expects to contribute $1,313 to the SERPs in 2014.

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

2014	$	30,030
2015	30,894
2016	31,213
2017	32,851
2018	33,419
2019-2023	181,464
	$	339,871

The fair values of the Company’s Pension Plans’ assets as of December 31, 2013, 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)
Equity securities:
Multi-asset fund (a)	$	238,699	$	—	$	238,699	$	—
Fixed income securities:
Bond fund (b)	280,434		—		280,434		—
Other types of investments:
Private equity funds (c)	5,480		—		—		5,480
Guaranteed insurance contract	9,732		—		—		9,732
Total	$	534,345	$	—	$	519,133	$	15,212
Receivable (d)	925
Total	$	535,270

^(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.

132

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

^(d)  Receivable for investments sold at December 31, 2013, which approximates fair value.

The fair values of the Company’s Pension Plans’ assets as of December 31, 2012, 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)
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.

Changes in level 3 plan assets for the year ended December 31, 2013 were as follows: 

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Private Equity Funds			Guaranteed Insurance Contract		Total
Beginning balance, December 31, 2012	$	5,608		$	9,600	$	15,208
Actual return on plan assets:
Relating to assets still held at the reporting date	571			—		571
Relating to assets sold during the period	331			—		331
Purchases, sales, and settlements	(1,030		)	132		(898		)
Ending balance, December 31, 2013	$	5,480		$	9,732	$	15,212

Changes in level 3 plan assets for the year ended December 31, 2012 were as follows:

133

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	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

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.

(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, 2013, 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, 2013. Even though the 1974 Plan is projected to have an accumulated funding deficiency within six plan years after the plan year beginning July 1, 2013, 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. In 2013, an updated 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 provided the funded status remains below the percentage noted above. The Plan’s funded status is reviewed annually by the certifying actuary. For the years ended December 31, 2013, 2012, and 2011, the Company incurred expenses related to the 1974 Plan of $21,282, $23,102, and $15,140. The contributions to the 1974 Plan made by two of the Company’s 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, 2013, 2012, and 2011 was $1,392, $1,540 and $1,026, respectively. As required under the Coal Act, the Company’s obligation to pay retiree medical benefits to its UMWA retirees is secured by letters of credit in the amount of $9,710 as of December 31, 2013.

134

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

(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 estimated by an independent actuary by prorating the accrual of actuarially projected benefits over the employee's applicable term of service. Adjustments to the probable ultimate liability for workers’ compensation and black lung are made annually based on actuarial valuations.

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, 2013, 2012, and 2011 was $29,068, $42,566, and $36,506, respectively.

For the Company’s subsidiaries that are self-insured for workers’ compensation claims, the liability at December 31, 2013 and 2012 was $156,726 and $179,984, respectively, including a current portion of $14,189 and $26,700, respectively. Self-insured workers’ compensation expense for the years ended December 31, 2013, 2012, and 2011 was $12,399, $3,271, and $16,601, respectively.  Certain of the Company’s subsidiaries’ self-insured workers’ compensation obligations are secured by letters of credit in the amount of $83,552 and surety bonds in the amount of $11,204.  In addition, certain of the Company’s subsidiaries’ self-insured workers’ compensation obligations are secured by $7,706 of deposits.

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, 2013 and 2012:

135

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	December 31,
	2013			2012
Change in benefit obligation:
Accumulated benefit obligation at beginning of period	$	145,271		$	160,595
Service cost	2,708			8,114
Interest cost	6,577			5,612
Actuarial (gain) loss	11,294			(19,228		)
Benefits paid	(9,242		)	(9,822		)
Accumulated benefit obligation at end of period	$	156,608		$	145,271
Change in fair value of plan assets:
Fair value of plan assets at beginning of period	$	3,431		$	3,089
Actual return on plan assets	(19		)	(23		)
Benefits paid	(9,242		)	(9,822		)
Employer contributions	17,839			10,187
Fair value of plan assets at end of period (1)	12,009			3,431
Funded status	(144,599		)	(141,840		)
Accrued benefit cost at end of year	$	(144,599	)	$	(141,840	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	8,142		$	5,961
Long-term liabilities	136,457			135,879
	$	144,599		$	141,840

⁽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, 2013 and 2012: 

	December 31,
	2013		2012
Net actuarial loss	$	18,146	$	7,614

The following table details the components of the net periodic benefit cost for black lung obligations: 

	Years Ended December 31,
	2013			2012			2011
Service cost	$	2,708		$	8,114		$	4,171
Interest cost	6,577			5,612			5,143
Expected return on plan assets	(87		)	(52		)	(37		)
Amortization of net actuarial loss	868			—			918
Net periodic expense	$	10,066		$	13,674		$	10,195

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

136

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Years Ended December 31,
	2013			2012			2011
Current year actuarial (gain) loss	$	11,400		$	(19,154	)	$	15,238
Amortization of net actuarial (loss)	(868		)	—			(918		)
Total recognized in other comprehensive (income) loss	$	10,532		$	(19,154	)	$	14,320
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$	20,598		$	(5,480	)	$	24,516

The weighted-average assumptions related to black lung obligations used to determine the benefit obligation as of December 31, 2013 and 2012 were as follows: 

	2013		2012
Discount rate	4.74	%	3.84%
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,
	2013	2012	2011
Discount rate	4.14%	4.14%	5.00%
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, 2013 are as follows: 

Year ending December 31:
2014	$	8,142
2015	8,363
2016	8,669
2017	8,978
2018	9,289
2019-2023	50,596
	$	94,037

(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, 2013, 2012, and 2011 were $48,327, $79,257, and $46,866, 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. 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, 2013, 2012, and 2011, the Company incurred total claims expense of $199,257, $219,707, and $145,517, respectively, which represents claims processed and an estimate for claims incurred but not reported.

137

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

(21) 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. On May 22, 2013, the Board of Directors authorized an additional 3,600,000 shares of common stock for issuance under the 2012 LTIP Plan. The 2012 LTIP is currently authorized for the issuance of awards of up to 10,000,000 shares of common stock, and as of December 31, 2013, 4,536,795 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 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.

The Board of Directors has 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 share units (both time-based and performance-based). During the years ended December 31, 2013, 2012, and 2011, the Company repurchased 178,195, 441,923, and 221,553 common shares, respectively, from employees at an average price paid per share of $8.05, $16.99, and $55.32, respectively. Shares that are repurchased to satisfy the employees’ minimum statutory tax withholdings are recorded in Treasury stock at cost.

At December 31, 2013, 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 totaled $25,873, $9,881, and $53,685, for the years ended December 31, 2013, 2012, and 2011, respectively. For the years ended December 31, 2013, 2012, and 2011, approximately 78%, 51%, and 72%, respectively, of stock-based compensation expense is reported as selling, general and administrative expenses and approximately 22%, 49%, and 28%, respectively, of the stock-based compensation expense was recorded as a component of cost of coal sales. The total excess tax benefit recognized for stock-based compensation was $0 for the years ending December 31, 2013, 2012, and 2011.

Restricted Stock Awards

No awards were granted during the years ended December 31, 2013, 2012 and 2011 and no awards were outstanding as of the years ended December 31, 2013 and 2012. The fair value of restricted stock awards that vested for the years ended December 31, 2013, 2012, and 2011 was $0, $11,142, and $13,987, respectively. As of December 31, 2013 and 2012, there was no unrecognized compensation cost related to non-vested restricted stock awards.

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 from grant (with accelerated vesting in certain instances, including in the event of a qualifying employment termination in connection with a change of control). Time-based restricted share units currently granted to the Company’s non-employee directors generally vest on the one-year anniversary of grant (with accelerated in certain circumstances including in connection with 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.

138

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

During the years ended December 31, 2013 and 2012, the Company granted time-based share units under the 2012 LTIP to certain executive officers, directors and key employees in the amount of 1,752,075 and 1,016,733, respectively, of which 2,468,555 remained outstanding at December 31, 2013.

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 91,267 remained outstanding at December 31, 2013.

During the years ended December 31, 2012 and 2011, 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 and 357,455, respectively, of which 474,705 remained outstanding at December 31, 2013. 

Time-based share unit activity for the year ended December 31, 2013 is summarized in the following table:

	Number of  Shares		Weighted- Average  Grant Date  Fair Value
Non-vested shares outstanding at December 31, 2012	2,057,939		$	19.30
Granted	1,752,075		$	8.05
Vested	(568,336	)	$	27.12
Forfeited or Expired	(142,389	)	$	13.10
Non-vested shares outstanding at December 31, 2013	3,099,289		$	11.66

The fair value of time-based share unit awards that vested in the years ended December 31, 2013, 2012, and 2011 was $4,536, $13,775, and $10,218, respectively. As of December 31, 2013, there was $11,883 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 of1.82 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, total shareholder return goals, and cash flow from operations 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 with performance conditions 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 with market conditions 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 2013, the Company awarded 1,531,787 performance-based share units, of which 1,507,503 remain outstanding as of December 31, 2013. At December 31, 2013, the Company had assessed the total shareholder return and cash flow performance targets as probable of achievement. As of December 31, 2013, there was $14,153 of unrecognized compensation cost related to the 2013 performance-based share units which is expected to be recognized as expense over a weighted-average period of 2.00 years.

During 2012, the Company awarded 1,149,392 performance-based share units, of which 1,048,807 remain outstanding as of December 31, 2013. At December 31, 2013, the Company had assessed the total shareholder return target as probable of achievement. As of December 31, 2013, there was $5,736 of unrecognized compensation cost related to the 2012 performance-based share units which is expected to be recognized as expense over a weighted-average period of 1.00 years.

139

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

During 2011, the Company awarded 227,199 performance-based share units, of which 212,093 remain outstanding as of December 31, 2013. At December 31, 2013, there was no unrecognized 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.

Performance-based share unit activity for the year ended December 31, 2013 is summarized in the following table:

	Number of  Shares		Weighted- Average  Grant Date  Fair Value
Non-vested shares outstanding at December 31, 2012	3,125,182		$	28.40
Granted	3,063,574		$	8.05
Earned	—		$	—
Forfeited or expired	(622,598	)	$	43.97
Non-vested shares outstanding at December 31, 2013	5,566,158		$	15.25

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.

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, 2013, 615,042 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.

Stock option activity for the year ended December 31, 2013 is summarized in the following table:

140

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Number of Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (Years)
Outstanding at December 31, 2012	1,010,101		$	21.71
Exercised	—		$	—
Forfeited or Expired	(72,124	)	$	20.86
Outstanding at December 31, 2013	937,977		$	21.77	3.40
Exercisable at December 31, 2013	937,977		$	21.77	3.40

As of December 31, 2013, the options outstanding and exercisable had an aggregate intrinsic value of $53. Cash received from the exercise of stock options during the years ended December 31, 2013, 2012, and 2011 was $0, $176, and $4,320, respectively. As of December 31, 2013, there was no unrecognized compensation cost related to stock options.

The total intrinsic value of options exercised during the years ended December 31, 2013, 2012, and 2011 was $0, $253, and $12,952, 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, 2013 follows:

	Options Outstanding and Exercisable
Exercise Price	Shares	Weighted- Average Remaining Life (yrs)	Weighted- Average Exercise Price
$ 4.31-$7.87	171,580	0.60	$	7.47
$ 11.15-$20.44	356,381	3.13	$	16.95
$ 23.93-$34.76	285,357	3.90	$	27.98
$ 40.82-$48.26	124,659	6.88	$	41.04
	937,977	3.40	$	21.77

(22) Related Party Transactions

For the years ended December 31, 2013, 2012, and 2011, there were no material related party transactions.

(23) Commitments and Contingencies

(a) General

Estimated losses from loss contingencies 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

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, 2013, aggregate future minimum non-cancelable lease payments under operating leases and minimum royalties under coal leases were as follows:

141

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

	Operating  Leases		Coal  Royalties
Year Ending December 31:
2014	$	18,325	$	41,562
2015	11,257		37,625
2016	130		36,148
2017	—		36,035
2018	—		27,227
Thereafter	—		90,117
Total	$	29,712	$	268,714

For the years ended December 31, 2013, 2012, and 2011, net rent expense under operating leases was $44,087, $81,021, and $73,092 respectively, and coal royalty expense was $222,875, $336,068, and $322,890 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, 2013:

	Capital Leases
Year Ending December 31:
2014	$	21,446
2015	15,762
2016	8,776
2017	6,633
2018	2,909
Thereafter	51,387
Total minimum lease payments	$	106,913
Less: Amount representing interest (rates range from 2.13% to 13.86%)	(48,039		)
Present value of net minimum lease payments	$	58,874

Other Commitments

As of December 31, 2013, the Company had commitments to purchase 87,000 tons of coal at a cost of approximately $8,047 during 2014.

In September 2011, the Company entered into a federal coal lease, which contained an estimated 130.2 million 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 million 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. Two of these installments were paid in November 2012 and 2013. Also as a result of the exchange, the Company recorded a note payable, which had a present value of $6,862 as of December 31, 2013, of which $3,946 is recorded as current portion of long-term debt and $2,916 is recorded as long-term debt in the Company’s Consolidated Balance Sheet as of December 31, 2013. The note is payable in four annual installments of $3,946 due each November through 2015. The Company paid the first two installments in November 2012 and 2013.

The Company also has obligations under certain coal transportation agreements that contain minimum quantities to be shipped each year. Minimum amounts due under these contracts for the next five years and beyond are $25,928, $64,688, $27,686, $26,382, $22,540 and $277,935 respectively.

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(Dollars in thousands, except per share data)

Also, see Note 14 regarding the Company’s Other debt and Note 9 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.

During the normal course of business, contract-related matters arise between the Company and its customers. When a loss related to such matters is considered probable and can reasonably be estimated, the Company records a liability. During the year ended December 31, 2013, the Company recorded a gain of $55,454 in other expenses in the Company’s Consolidated Statement of Operations related to the resolution of a contract-related matter.

(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, 2013 is $395,423.

Letters of Credit

As of December 31, 2013, the Company had $133,975 of letters of credit outstanding under its senior secured revolving facility.

(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 $350,000 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

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(Dollars in thousands, except per share data)

underlying the estimated range will change from time to time, and actual results may vary significantly from the current 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 $212,233, $15,406 and $2,100 during the years ended December 31, 2013, 2012 and 2011, 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 (the “Court”) 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. The Court has extended the stay several times; most recently, on July 18, 2013, the court further extended the existing discovery stay until January 15, 2014.

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.

In October and December 2013, the parties participated in mediation. In December 2013, the parties reached agreement on all material terms of settlement, including a cash payment of $265,000. In February 2014, the parties reached agreement on definitive settlement documentation, subject to court approval, and on February 5, 2014, the lead plaintiffs moved the court for preliminary approval of the settlement. On February 19, 2014, the Court entered an order preliminarily approving the settlement subject to a final determination following a settlement hearing on June 4, 2014. On February 25, 2014, pursuant to the terms of the settlement, the Company made an initial payment of $30,000 into an escrow account. Pending final determination, the plaintiffs may not further prosecute the action. If the Court approves the settlement, it would result in the dismissal of the action. Whether the Court will approve the settlement remains uncertain. The Company expects insurance recoveries of approximately $70,000 to help cover the cost of the settlement.

Emerald Purported Securities Class Action

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 acquisition of Massey by the Company (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.

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 defendants filed motions to dismiss the amended complaint on March 22, 2013 and March 29, 2013, which motions are currently pending. The Boone County Circuit Court has set a preliminary trial date of June 24, 2014.

UBB Explosion and Related Investigations and Litigation

On April 5, 2010, before the Massey Acquisition 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.

On February 10, 2014, the Company announced that it had fully complied with the terms of the Agreement and that the Office and the United States Department of Justice had closed the Agreement.

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 was initially idled. 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

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(Dollars in thousands, except per share data)

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. On May 10, 2013, the court dismissed the amended complaint. On July 17, 2013, the plaintiffs filed another complaint seeking “criminal restitution” under the Agreement, which defendants moved to dismiss on August 16, 2013. The same plaintiffs filed their appeal of the May dismissal with the United States Court of Appeals for the Fourth Circuit on July 29, 2013. On October 18, 2013, the Court of Appeals dismissed the appeal for lack of jurisdiction. On October 30, 2013, the court granted defendants’ motion to dismiss the complaint filed on July 17, 2013 with prejudice. The plaintiffs filed a notice of appeal of this latest dismissal order on November 26, 2013, and plaintiffs filed their opening appellate brief on February 10, 2014.

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 July 19, 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.

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. On August 19, 2013, at the request of the United States Attorney, the stay was extended until the earlier of either the completion of the United States’ criminal investigation of the UBB explosion or January 15, 2014. Mediation efforts in August 2012 successfully resolved all but two of the personal injury and emotional distress claims. On June 26, 2013, the court granted the Company’s motion to dismiss in part, dismissing plaintiffs’ claims alleging the tort of outrage and negligent infliction of emotional distress. Plaintiffs’ two remaining claims have been resolved. 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.

On June 17, 2013 and August 29, 2013 two complaints were filed in Boone County Circuit Court alleging personal injury claims relating to the UBB explosion. The Company moved to dismiss both complaints on July 17, 2013 and October 16, 2013 respectively.

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

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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.

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. The court has extended the stay several times; most recently, on July 29, 2013, the court further extended the existing discovery stay until the earlier of the completion of the United States’ criminal investigation of the UBB explosion or January 15, 2014. On January 14, 2014, defendants moved to further extend the stay until the earlier of the completion of the United States’ criminal investigation or July 15, 2014. That motion was granted on February 4, 2014.

West Virginia State Court Derivative Suit

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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.

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. On November 14, 2013, the court denied the West Virginia Plaintiffs’ motion to amend and granted defendants’ motion to dismiss. The West Virginia Plaintiffs have appealed the denial of motion to amend and dismissal to the Supreme Court of Appeals of West Virginia.

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.

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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. On September 12, 2013, the Supreme Court of Appeals of West Virginia affirmed the September 29, 2011 order granting defendants’ motion to dismiss the contempt petitions.

Mine Water Discharge Suits

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, the West Virginia Department of Environmental Protection 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 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.

On March 27, 2013, the Company’s subsidiary Alex Energy, Inc. (“Alex”) was served with a complaint from the Sierra Club, and others, alleging improper discharges by Alex into Spruce Run and Road Fork of Robinson Creek in Nicholas County, West Virginia. Alex has appropriate permits for discharges into those tributaries, and the discharges discussed in the plaintiffs’ complaint are undertaken by Alex in compliance with its permits.

On April 10, 2013, the Company’s subsidiary Bandmill Coal Co. (“Bandmill”) was served with a complaint from the Sierra Club, and others, alleging discharges of selenium from the site of Bandmill’s former Tower Mountain surface mine into waters of the United States without a proper permit. The Tower Mountain site is closed, the property has been reclaimed and West Virginia regulators previously determined that Bandmill no longer needs a National Pollutant Discharge Elimination System (“NPDES”) permit for the Tower Mountain site at issue. Bandmill was also released from its obligations to monitor and treat water discharging from the site. Bandmill believes it has operated in compliance with all laws and regulations regarding discharges from the Tower Mountain site.

On July 23, 2013, the Company’s subsidiary, Alex Energy, Inc., was served with a complaint alleging that discharges from the PGM No. 1 surface mine into Hardway Branch of Twentymile Creek violated state water quality standards for selenium.

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NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

On July 29, 2013, the Company’s subsidiary, Pigeon Creek Processing Co. (“Pigeon Creek”), was notified by environmental groups that they intend to sue Pigeon Creek for discharging selenium from the Stonega impoundment area without the proper authorization in the NPDES permit.

On October 3, 2013, Bandmill was notified by environmental groups that they intend to sue Bandmill for alleged discharges from the Right Hand Fork Surface Mine in connection with state water quality standards for selenium.

The Company is currently in discussions with the EPA about addressing certain of these and other matters.

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 in the Circuit Court of Mingo County, West Virginia by a former NCI employee (the “NCI Employee Litigation”). The plaintiff in the NCI Employee Litigation 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.

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 in relation to the NCI Employee Litigation.  The Company believes that NCI has meritorious defenses to the claims asserted in the NCI Employee Litigation.

NCI filed its answer to the complaint in the NCI Employee Litigation on March 4, 2013.  On April 23, 2013, the Circuit Court of Kanawha County, West Virginia, granted NCI’s motion to transfer and entered an agreed order transferring the NCI Employee Litigation from the Circuit Court of Mingo County to the Circuit Court of Kanawha County.

On November 14, 2013, the Circuit Court of Kanawha County granted NCI’s Motion to Certify Questions of Law to the Supreme Court of Appeals of West Virginia, where the case is now pending. Briefing before the Supreme Court of Appeals of West Virginia should be completed by March 13, 2014, and a decision on the certified questions is expected later in 2014.

Fluor Litigation

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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, in the consolidated balance sheet at December 31, 2013. 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.

Harman Litigation

In December 1997, Wellmore Coal Corporation (“Wellmore”), then a subsidiary of A. T. Massey Coal Company (“A. T. Massey”), which is now a subsidiary of the Company, declared force majeure under its coal supply agreement with Harman Mining Corporation (“Harman”) and reduced the amount of coal to be purchased from Harman.  In October 1998, Harman and several entities affiliated with it, as well as their ultimate sole shareholder (together “Harman plaintiffs”), sued A.T. Massey and five of its subsidiaries (the “Massey Defendants”) in the Circuit Court of Boone County, West Virginia, alleging that the Massey Defendants tortiously interfered with Wellmore’s agreement with Harman, causing Harman to go out of business.  In August 2002, the jury awarded the plaintiffs $50,000 in compensatory and punitive damages.

In October 2006, the Massey Defendants appealed the case to the Supreme Court of Appeals of West Virginia (“WV Supreme Court”).  In November 2007, the WV Supreme Court issued a 3-2 majority opinion reversing the judgment against the Massey Defendants and remanding the case to the Circuit Court of Boone County with directions to enter an order dismissing

151

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

the case, with prejudice, in its entirety.  On motion by the Harman plaintiffs, the WV Supreme Court agreed to rehear the case but, in April 2008, it again reversed the judgment against the Massey Defendants and remanded the case with direction to enter an order dismissing the case, with prejudice, in its entirety.

In July 2008, the Harman plaintiffs petitioned the United States Supreme Court (the “U.S. Supreme Court”) to review the WV Supreme Court’s dismissal of their claims. In December 2008, the U.S. Supreme Court agreed to review the case based on the question of whether a justice of the WV Supreme Court should have recused himself from the appeal. The U.S. Supreme Court found that the justice should have recused himself and ruled in June 2009 that the matter should be reheard by the WV Supreme Court.  

The WV Supreme Court heard oral arguments on the matter in September 2009, and in November 2009 reversed the lower court’s decision, ruling that all claims brought in connection with the parties dealings must be brought in Virginia.  The Harman plaintiffs subsequently requested that the WV Supreme Court reconsider its decision; the WV Supreme Court denied that request.

In November 2010, Harman plaintiffs re-filed their claims in the Circuit Court of Buchanan County, Virginia, this time solely against A.T. Massey, seeking compensatory damages of approximately $44,000, plus pre- and post-judgment interest and punitive damages. A. T. Massey filed a plea of res judicata, and in December 2011 the Buchanan County Circuit Court granted the plea and dismissed the Harman plaintiffs’ claims. The Harman plaintiffs appealed that decision to the Virginia Supreme Court, and on April 18, 2013, the Virginia Supreme Court reversed the decision of the Buchanan County Circuit Court, finding that res judicata did not bar the Harman plaintiffs’ claims. The matter was remanded to the Buchanan County Circuit Court for further proceedings, and that court has set a trial date in late April 2014.

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. 

(24) 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, 2013, 2012, and 2011, the Company’s ten largest customers accounted for approximately 43%, 42%, and 41% of total revenues, respectively. Sales to the Company’s largest customer accounted for approximately 9% of total revenues in each case for the years ended December 31, 2013, 2012, and 2011. Steam coal accounted for approximately 77%, 81%, and 82% of the Company’s coal sales volume during 2013, 2012, and 2011, respectively. Metallurgical coal accounted for approximately 23%, 19%, and 18% of the Company’s coal sales volume during 2013, 2012, and 2011, respectively.

(25) Segment Information

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 Northern and Central Appalachia and the Powder River Basin. The Company has two reportable segments: Western Coal Operations, which consists of two Powder River Basin surface mines as of December 31, 2013, and Eastern Coal Operations, which consists of 57 underground mines and 22 surface mines in Northern and Central Appalachia as of December 31, 2013, as well as 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 natural gas; 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, which the Company defines as net income (loss) plus interest expense, income tax expense, amortization of acquired intangibles, net, and depreciation, depletion and amortization, less interest income and income tax benefit.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Segment operating results and capital expenditures for the year ended December 31, 2013 were as follows:

	Eastern Coal Operations			Western Coal Operations			All Other			Consolidated
Total revenues	$	4,412,334		$	487,324		$	53,850		$	4,953,508
Depreciation, depletion and amortization	$	780,120		$	54,265		$	30,636		$	865,021
Amortization of acquired intangibles, net	$	7,916		$	(2,878	)	$	18		$	5,056
EBITDA	$	(44,223	)	$	90,879		$	(263,556	)	$	(216,900	)
Capital expenditures	$	207,503		$	5,369		$	2,789		$	215,661
Acquisition of mineral rights under federal lease	$	—		$	42,130		$	—		$	42,130

The following table presents a reconciliation of EBITDA to net loss for the year ended December 31, 2013:

	Eastern Coal Operations			Western Coal Operations			All Other			Consolidated
EBITDA	$	(44,223	)	$	90,879		$	(263,556	)	$	(216,900	)
Interest expense	(2,830		)	(534		)	(243,224		)	(246,588		)
Interest income	1,396			3			2,118			3,517
Income tax (expense) benefit	(10		)	—			216,560			216,550
Depreciation, depletion and amortization	(780,120		)	(54,265		)	(30,636		)	(865,021		)
Amortization of acquired intangibles, net	(7,916		)	2,878			(18		)	(5,056		)
Net income (loss)	$	(833,703	)	$	38,961		$	(318,756	)	$	(1,113,498	)

Segment operating results and capital expenditures 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	$	(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 to net loss 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)

	Eastern Coal Operations			Western Coal Operations			All Other			Consolidated
EBITDA	$	(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
Net income (loss)	$	(2,670,032	)	$	(11,596	)	$	244,480		$	(2,437,148	)

Segment operating results and capital expenditures 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	$	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

The following table presents a reconciliation of EBITDA to net loss for the year ended December 31, 2011:

	Eastern Coal Operations			Western Coal Operations			All Other			Consolidated
EBITDA	$	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
Net loss	$	(416,494	)	$	(21,498	)	$	(292,550	)	$	(730,542	)

The following table presents total assets and goodwill:

	Total Assets						Goodwill, net
	December 31, 2013		December 31, 2012		December 31, 2011		December 31, 2013		December 31, 2012		December 31, 2011
Eastern Coal Operations	$	9,566,687	$	10,691,029	$	14,427,166	$	308,651	$	561,753	$	2,221,971
Western Coal Operations	645,175		647,292		657,419		—		—		53,308
All Other	1,587,396		1,751,485		1,509,460		—		5,912		5,912
Total	$	11,799,258	$	13,089,806	$	16,594,045	$	308,651	$	567,665	$	2,281,191

The Company sells produced, processed and purchased coal to customers in the United States and in international markets, primarily Turkey, Netherlands, Italy, India, and South Korea. Export coal revenues, which include freight and handling

154

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

revenues, totaled $2,151,464 or approximately 43% of total revenues for the year ended December 31, 2013, $2,930,557 or approximately 42% of total revenues for the year ended December 31, 2012; and $3,095,927 or approximately 44% of total revenues for the year ended December 31, 2011.

(26) Guarantor and Non-Guarantor Information

The Company has issued Senior Notes, 3.75% Convertible Notes and 4.875% Convertible 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”). The Company’s Non-Guarantor Subsidiaries are comprised of ANR Receivables Funding, LLC, Shannon-Pocahontas Mining Company, Gray Hawk Insurance Company and Rockridge Coal Company, which were not guarantors of the Senior Notes or the 3.75% and the 4.875% Convertible Notes and would not be guarantors of the New Notes.

As the Company’s parent company has no independent assets or operations, the guarantees are full and unconditional and joint and several, and the subsidiaries of the parent company other than the subsidiary guarantors are minor as of December 31, 2013, separate consolidated financial statements and other disclosures are not presented because management believes that such information would not be material to holders of the Senior Notes, the 3.75% Convertible Notes and the 4.875% Convertible Notes or any New Notes or related guarantees that may be issued by the Company.

(27) Quarterly Financial Information (Unaudited)

	Year Ended December 31, 2013
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Total revenues	$	1,333,591		$	1,335,123		$	1,191,094		$	1,093,700
Net loss (1)	$	(110,788	)	$	(185,681	)	$	(458,241	)	$	(358,788	)
Basic loss per share	$	(0.50	)	$	(0.84	)	$	(2.07	)	$	(1.62	)
Diluted loss per share	$	(0.50	)	$	(0.84	)	$	(2.07	)	$	(1.62	)

⁽¹⁾  Net loss includes asset impairment and restructuring charges of $11,076, $11,265, $2,017 and $12,915 in the first, second, third and fourth quarters of 2013, respectively. Net loss also includes goodwill impairment charges of $253,102 in the third quarter of 2013.

	Year Ended December 31, 2012
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Total revenues	$	1,934,613		$	1,848,109		$	1,633,809		$	1,558,353
Net loss (1)	$	(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⁾  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.

(28) Subsequent Events

In 2010, the Company entered into a 50/50 joint venture (the “Alpha Shale JV”) with Rice Drilling C LLC, a wholly owned subsidiary of Rice Drilling B LLC, in order to develop a portion of Alpha’s Marcellus Shale natural gas holdings in

155

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

southwest Pennsylvania. On December 6, 2013, the Company, Rice Drilling C LLC and Rice Energy Inc. (“Rice Energy”) entered into a transaction agreement (the “Transaction Agreement”). Pursuant to the Transaction Agreement, the Company agreed to transfer its 50% interest in the Alpha Shale JV to Rice Energy in exchange for total consideration of $300,000, consisting of $100,000 of cash and the issuance by Rice Energy to the Company of 9,523,810 shares of common stock concurrently with, and contingent upon, the consummation of Rice Energy’s initial public offering (the “Offering”). On January 29, 2014, Rice Energy completed the Offering, and on the same date, issued 9,523,810 shares of common stock to the Company.

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.

156

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, 2013.  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 (1992). 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, 2013.

157

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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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, 2013 and 2012, 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, 2013, and our report dated February 28, 2014 expressed an unqualified opinion on those consolidated financial statements. 

/s/ KPMG LLP

Roanoke, Virginia

February 28, 2014

Item 9B. Other Information

Item 5.02 Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

On February 26, 2014, the Compensation Committee (the “Committee”) of the Company's Board of Directors (the “Board”) approved retention bonuses (each a “Retention Bonus”) to be made to Messrs. Kevin S. Crutchfield, the Company’s Chief Executive Officer, and Paul H. Vining, the Company’s President, and, in the case of Mr. Crutchfield, the Board ratified his award, subject to each of their execution and delivery of retention bonus agreements (the “Retention Agreements”) that were both fully executed on February 28, 2014 (the “Signing Date”).

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The Retention Agreements were entered into to ensure stability in the Company’s senior management team and to retain their service through particularly difficult market and regulatory conditions which could affect the Company and the coal industry generally in the coming years. The Committee and Board recognized the challenges ahead for the Company and determined that the Retention Bonuses were necessary to retain the Company’s two top executives who are critical to the Company’s execution of strategic priorities given current and anticipated market and business conditions.

Except as described below, the Retention Agreements provide that each executive must be employed on a full-time basis by the Company or its subsidiaries on the applicable vesting dates of each Retention Bonus to receive the related payments made on such dates.

On the Signing Date, each of Messrs. Crutchfield and Vining received $500,000 (provided that such amounts must be repaid to the Company if the executive resigns from, or is terminated for cause by, the Company prior to the six-month anniversary of the Signing Date). If the executive is employed with the Company and its subsidiaries on the first anniversary of the Signing Date, Messrs. Crutchfield and Vining will receive $500,000 and $750,000, respectively, on such date; provided, however, that if the executive resigns from, or is terminated for cause by, the Company within six months following the first anniversary of the Signing Date, the executive must repay the bonus amount paid on that date to the Company. If Mr. Crutchfield is employed with the Company and its subsidiaries on August 28, 2016, he will receive $1,000,000 and, if Mr. Vining is employed with the Company and its subsidiaries on February 28, 2016, he will receive $750,000.

If either executive’s employment with the Company and its subsidiaries terminates due to death or disability during the applicable retention period, he (or his estate) will be entitled to a pro-rata portion of the Retention Bonus equal to the number of complete months he was employed with the Company and its subsidiaries during such period. If his employment is terminated without cause by the Company or in the event of a change in control of the Company, the executive will be entitled to receive the full Retention Bonus.

The Retention Agreements also include a non-solicitation covenant providing that, during employment with the Company and its subsidiaries and for twelve months after the earlier to occur of Messrs. Crutchfield’s or Vining’s (i) termination of employment with the Company and any Company subsidiary or (ii) August 28, 2016 or February 28, 2016, respectively, the executive will not solicit certain employees of the Company and its subsidiaries.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The sections of our Proxy Statement entitled “Proposal 1—Election of Directors—Nominees for Directors,” “Corporate Governance And Related Matters—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 2013,” “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 2013,” “ 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 2013,” “Executive Compensation—Option Exercises and Stock Vested in 2013,” “Executive Compensation—Pension Benefits in 2013,” “Executive Compensation—Additional Information Regarding Our Pension Benefits Table,” “Executive Compensation—Nonqualified Deferred Compensation in 2013,” “Executive

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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

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, 2013 and 2012

Consolidated Statements of Operations, Years ended December 31, 2013, 2012 and 2011

Consolidated Statements of Comprehensive Income (Loss), Years ended December 31, 2013, 2012 and 2011

Consolidated Statements of Stockholders’ Equity, Years ended December 31, 2013, 2012 and 2011

Consolidated Statements of Cash Flows, Years ended December 31, 2013, 2012 and 2011

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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.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ALPHA NATURAL RESOURCES, INC.
By:	/s/ Frank J. Wood
Name:	Frank J. Wood
Title:	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

Date: February 28, 2014

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.

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Signature	Date	Title
/s/ Kevin S. Crutchfield	February 28, 2014	Chief Executive Officer (Principal Executive Officer), Chairman of the Board of Directors and Director
Kevin S. Crutchfield
/s/ Frank J. Wood	February 28, 2014	Executive Vice President and Chief Financial Officer, (Principal Financial and Accounting Officer)
Frank J. Wood
/s/ Angelo C. Brisimitzakis	February 28, 2014	Director
Angelo C. Brisimitzakis
/s/ William J. Crowley, Jr.	February 28, 2014	Director
William J. Crowley, Jr.
/s/ E. Linn Draper, Jr.	February 28, 2014	Director
E. Linn Draper, Jr.
/s/ Glenn A. Eisenberg	February 28, 2014	Director
Glenn A. Eisenberg
/s/ Deborah M. Fretz	February 28, 2014	Director
Deborah M. Fretz
/s/ P. Michael Giftos	February 28, 2014	Director
P. Michael Giftos
/s/ L. Patrick Hassey	February 28, 2014	Director
L. Patrick Hassey
/s/ Joel Richards, III	February 28, 2014	Director
Joel Richards, III

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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 on 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.)

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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 6.00% Senior Note due 2019 (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 6.25% Senior Note due 2021 (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 9.75% Senior Note due 2018 (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	Fourth Supplemental Indenture, dated as of May 13, 2013, 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 May 13, 2013.)
4.16	Form of 3.75% Convertible Senior Note due 2017 (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 May 13, 2013.)

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4.17	Fifth Supplemental Indenture, dated as of December 18, 2013, 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 December 18, 2013.)
4.18	Form of 4.875% Convertible Senior Note due 2020 (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 December 18, 2013.)
4.19	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.)
4.20	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.)
4.21	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.)
4.22	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.)
4.23	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.)
4.24	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.)
4.25	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.)
4.26	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 (Incorporated by reference to Exhibit 4.22 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2013.)
4.27	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 (Incorporated by reference to Exhibit 4.23 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2013.)
4.28	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 (Included in Exhibit 10.9.)
4.29	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. (Included in Exhibit 10.10.)

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4.30	Fourth Amended and Restated Credit Agreement, dated as of May 22, 2013, among Alpha Natural Resources, Inc., the lenders party thereto and Citicorp North America, Inc., as administrative agent and collateral agent (Included in Exhibit 10.11.)
4.31	Amendment No. 1 to Fourth Amended and Restated Credit Agreement, dated as of October 2, 2013, among Alpha Natural Resources, Inc., the lenders party thereto and Citicorp North America, Inc., as administrative agent and collateral agent (Included in Exhibit 10.12.)
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	Stipulation and Agreement of Settlement, dated as of February 5, 2014 by and among Alpha, Alpha Appalachia Holdings, Inc. (fka Massey Energy Company) and the various Massey Energy Company officers and directors named as defendants, and the plaintiffs in the matter In re Massey Energy Co. Securities Litigation, Case No. 5:10-cv-00689-ICB (S.D. W. Va.)
10.3	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.)
10.4	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.)
10.5	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.)
10.6	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.)
10.7	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).
10.8	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).
10.9	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.)
10.10	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.)
10.11	Fourth Amended and Restated Credit Agreement, dated as of May 22, 2013, among Alpha Natural Resources, Inc., 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 May 22, 2013.)

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10.12	Amendment No. 1 to Fourth Amended and Restated Credit Agreement, dated as of October 2, 2013, among Alpha Natural Resources, Inc., 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 October 3, 2013.)
10.13	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.)
10.14	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.)
10.15	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.)
10.16*‡	Alpha Natural Resources, Inc. Amended and Restated Annual Incentive Bonus Plan.
10.17‡	Non-EmployeeDirectorCompensatoryArrangements(IncorporatedbyreferencetoExhibit10.27oftheAnnualReportonForm10-KofAlphaNaturalResources,Inc.(FileNo.1-32331)filedonFebruary25,2011.)
10.18‡	Alpha Natural Resources, Inc. Key Employee Separation Plan, As Amended and Restated Effective 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.)
10.19‡	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.)
10.20‡	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. 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.)
10.22‡	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.)
10.23‡	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.)
10.24‡	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.)
10.25‡	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.)
10.26‡	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.)
10.27‡	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.)

168

10.28‡	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.)
10.29‡	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.)
10.30‡	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.)
10.31‡	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.)
10.32‡	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.)
10.33‡	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.)
10.34‡	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.)
10.35‡	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.)
10.36‡	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.)
10.37‡	Third Amended and Restated Employment Agreement by and between Alpha Natural Resources Services, LLC and Kevin S. Crutchfield, dated as of July 31, 2009 (Incorporated by reference to Exhibit 10.29 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.38‡	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.)
10.39‡	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.)
10.40‡	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.)
10.41‡	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.)
10.42‡	Alpha Natural Resources, Inc. Amended and Restated 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. 333-188748) filed on May 22, 2013.)

169

10.43‡	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.)
10.44‡	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.)
10.45‡	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.)
10.46‡	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.)
10.47‡	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) Incorporated by reference to Exhibit 10.69 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2013.)
10.48‡	Form of Alpha Natural Resources, Inc. Non-Employee Director Deferral Elections (effective January 1, 2013) (Incorporated by reference to Exhibit 10.70 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2013.)
10.49‡	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.)
10.50‡	Form of Performance-Based Incentive Compensation Award Agreement for Employees under the Alpha Natural Resources, Inc. 2012 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 7, 2013.)
10.51‡	Form of 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 Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on May 7, 2013.)
10.52‡	Form of Performance Share Unit Award Agreement for Employees under the Alpha Natural Resources, Inc. 2012 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 7, 2013.)
10.53‡	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.)
10.54‡	Separation Agreement and General Release, dated September 18, 2012, by and between Alpha Natural Resources, Inc. and Randy 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.)
10.55*‡	Foundation Coal Supplemental Executive Retirement Plan, dated as of July 30, 2004.
10.56*‡	Amendment No. 1 to the Foundation Coal Supplemental Executive Retirement Plan, dated as of March 16, 2007.
10.57*‡	Amendment No. 2 to the Foundation Coal Supplemental Executive Retirement Plan, dated as of December 11, 2008.
10.58*‡	Amendment No. 3 to the Foundation Coal Supplemental Executive Retirement Plan, dated as of July 27, 2009.
10.59*‡	Amendment No. 4 to the Foundation Coal Supplemental Executive Retirement Plan, dated as of January 28, 2014.

170

10.60‡	Alpha Natural Resources, Inc. Amended and Restated 2012 Long-Term Incentive Plan (Incorporated by reference to Exhibit 99.1 to Registration Statement on Form S-8 of Alpha Natural Resources, Inc. (File No. 333-188748) filed on May 22, 2013.)
10.61‡	Alpha Natural Resources, Inc. Amended and Restated Annual Incentive Bonus Plan (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 May 24, 2013.)
10.62	Transaction Agreement, dated as of December 6, 2013, among Foundation PA Coal Company, LLC, Rice Drilling C LLC and Rice Energy Inc. (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 December 9, 2013.)
10.63	Registration Rights Agreement, dated as of January 29, 2014, among Foundation PA Coal Company, LLC, Rice Energy Inc., NGP Rice Holdings, LLC, Rice Energy Holdings LLC, and Rice Energy Family Holdings, LP (Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Rice Energy Inc. (File No. 001-36273) filed with the Commission on February 4, 2014.)
10.64	Stockholders’ Agreement, dated as of January 29, 2014, among Alpha Natural Resources, Inc., Rice Energy Inc., NGP Rice Holdings, LLC, Rice Energy Holdings LLC, and Rice Energy Family Holdings, LP (Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Rice Energy Inc. (File No. 001-36273) filed with the Commission on February 4, 2014.)
12.1*	Computation of Ratio of Earnings to Fixed Charges
12.2*	Computation of Other Ratios
21*	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

171