10-K 1 a11-29882_110k.htm 10-K

Table of Contents

 

 

 

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, 2011

 

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

 

GRAPHIC

 

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, 2011, was approximately $9.1 billion based on the closing price of the Company’s common stock as reported that date on the New York Stock Exchange of $45.44 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 24, 2012 — 220,018,865 shares.

 

DOCUMENTS INCORPORATED BY REFERENCE

Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2012 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, 2011.

 

 

 



Table of Contents

 

2011 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

 

 

 

Page

PART I

 

 

 

 

Item 1.

Business

5

 

 

 

Item 1A.

Risk Factors

31

 

 

 

Item 1B.

Unresolved Staff Comments

49

 

 

 

Item 2.

Properties

49

 

 

 

Item 3.

Legal Proceedings

57

 

 

 

Item 4.

Mine Safety Disclosures

57

 

 

 

PART II

 

 

 

 

Item 5.

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

57

 

 

 

Item 6.

Selected Financial Data

60

 

 

 

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

63

 

 

 

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

92

 

 

 

Item 8.

Financial Statements and Supplementary Data

93

 

 

 

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

168

 

 

 

Item 9A.

Controls and Procedures

168

 

 

 

Item 9B.

Other Information

170

 

 

 

PART III

 

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

170

 

 

 

Item 11.

Executive Compensation

170

 

 

 

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

170

 

 

 

Item 13.

Certain Relationships and Related Transactions, and Director Independence

170

 

 

 

Item 14.

Principal Accountant Fees and Services

170

 

 

 

PART IV

 

 

 

 

Item 15.

Exhibits and Financial Statement Schedules

171

 

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CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

 

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

 

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

 

·                  worldwide market demand for coal, electricity and steel;

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

·                  decline in coal prices;

·                  our liquidity, results of operations and financial condition;

·                  regulatory and court decisions;

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

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

·                  inherent risks of coal mining beyond our control;

·                  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;

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

·                  competition in coal markets;

·                  our assumptions concerning economically recoverable coal reserve estimates;

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

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

·                  our ability to negotiate new UMWA wage agreements on terms acceptable to us, increased unionization of our work force in the future and any strikes by our work force;

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

·                  potential instability and volatility in worldwide financial markets;

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

·                  disruption in coal supplies;

·                  our production capabilities and costs;

·                  our ability to integrate successfully operations that we have acquired or developed with our existing operations, including those of Massey Energy Company (“Massey”), as well as those operations that we may acquire or develop in the future, or the risk that any such integration could be more difficult, time-consuming or costly than expected;

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

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

·                  uncertainty of the expected financial performance of Alpha following the Massey Acquisition (defined below);

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

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

·                  the final allocation of the acquisition price in connection with the Massey Acquisition to the net assets acquired in accordance with applicable accounting rules and methodologies;

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

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

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

 

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

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

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

·                  availability of mining and processing equipment and parts;

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

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

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

·                  indemnification of certain obligations not being met;

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

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

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

·                  our substantial indebtedness and potential future indebtedness;

·                  significant or rapid increases in commodity prices;

·                  reclamation and mine closure obligations;

·                  terrorist attacks and threats, and escalation of military activity in response to such attacks;

·                  inflationary pressures on supplies and labor;

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

·                  weather conditions or catastrophic weather-related damage; and

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

 

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

 

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PART I

 

Item 1.   Business

 

Overview

 

On June 1, 2011, we completed our acquisition (the “Massey Acquisition”) of Massey Energy Company (“Massey”) for approximately $6.7 billion, of which approximately $1.0 billion was paid in cash and $5.7 billion was paid in common stock and other equity. Massey, together with its affiliates, was a major U.S. coal producer with approximately 2.4 billion tons of proven and probable reserves operating mines and associated processing and loading facilities in Central Appalachia. Our consolidated results of operations for the twelve months ended December 31, 2011 include Massey’s results of operations for the period June 1, 2011 through December 31, 2011. Our consolidated results of operations for the twelve months ended December 31, 2010 and 2009 do not include amounts related to Massey’s results of operations.

 

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

 

Unless we have indicated otherwise, or the context otherwise requires, references in this report to “Alpha”, 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 2011 consolidated revenues of $7.1 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 of December 31, 2011, we operated 145 mines and 35 coal preparation plants in Northern and Central Appalachia and the Powder River Basin, with approximately 14,500 employees.

 

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

 

Steam coal, which is primarily purchased by large utilities and industrial customers as fuel for electricity generation, accounted for approximately 82% of our 2011 coal sales volume. Metallurgical coal, which is used primarily to make coke, a key component in the steel making process, accounted for approximately 18% of our 2011 coal sales volume. Metallurgical coal generally sells at a premium over steam coal because of its higher quality and its value in the steelmaking process as the raw material for coke. We believe that the volume of the coal we sell will grow when and if demand for power and steel increases.

 

During 2011, we sold a total of 106.3 million tons of steam and metallurgical coal and generated coal revenues of $6.2 billion, of which approximately 20.9 million tons and $1.9 billion of coal revenues were related to the acquired operations of Massey. EBITDA from continuing operations was $77.4 million, and we incurred a loss from continuing operations of $677.4 million. EBITDA from continuing operations and our loss from continuing operations in 2011 both included a $745.3 million non-cash goodwill impairment charge recorded in the fourth quarter of 2011 (See Note 8 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.) We define and reconcile EBITDA from continuing operations in Item 6-”Selected Financial Data.” Our coal sales during 2011 consisted of 106.3 million tons of produced coal, of which 100.3 million was processed by us, exclusive of coal purchased from third party brokerages. We also purchased 6.0 million tons from third parties, of which 1.3 million tons we fully processed at our processing plants prior to resale, 3.8 million tons we blended with our coal prior to resale, and 0.9 million tons in raw product we shipped direct to our customers without any further processing or blending on our behalf. We classify raw coal purchases that are fully processed by us as produced and processed coal sales. Approximately 45.2% of our coal revenues combined with freight and handling revenues in 2011 was derived from sales made to customers outside the United States, primarily in Brazil, India, Italy, the Netherlands and Turkey.

 

As of December 31, 2011, we owned or leased approximately 4.7 billion tons of proven and probable coal reserves, of which approximately 1.5 billion tons are classified as metallurgical coal. Of our total proven and probable reserves, approximately 71% are low sulfur

 

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reserves, with approximately 61% having sulfur content below 1%. Approximately 69% of our total proven and probable reserves have a high Btu content which creates more energy per unit when burned compared to coals with lower Btu content. We believe that our total proven and probable reserves will support current production levels for more than 20 years.

 

On February 3, 2012, we announced that subsidiaries in Kentucky and West Virginia planned to idle four mines immediately and two others between the date of announcement and early 2013, while several other mines altered work schedules or reduced the number of production crews.  Altogether ten mining operations are affected, four in eastern Kentucky and six in southern West Virginia. The adjustments are expected to reduce 2012 coal production by approximately 4.0 million tons. The total includes approximately 2.5 million tons of thermal coal and 1.5 million tons of lower quality, high-volatility metallurgical coal.

 

History

 

Old Alpha was formed under the laws of the State of Delaware on November 29, 2004.  On February 15, 2005, an initial public offering of Old Alpha’s common stock occurred and since then, we have grown substantially through a series of acquisitions including the Foundation Merger in 2009 and the Massey Acquisition in 2011, both as discussed above.

 

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

 

During 2008:

 

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

 

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

 

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

 

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

 

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

 

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

 

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 2011 consolidated revenues and have significant coal reserves. Based on 2011 consolidated revenues of $7.1 billion, we are the second largest publicly traded coal producer in the United States. As of December 31, 2011, we controlled approximately 4.7 billion tons of proven and probable coal reserves.

 

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We have a diverse portfolio of coal mining operations and reserves.  As of December 31, 2011, we operate a total of 145 mines and have reserves in the three major U.S. coal producing regions: 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, two U.S. coal production regions for which future demand is expected to increase. We believe that this geographic diversity provides us with a significant competitive advantage, allowing us to source coal from multiple regions to meet the needs of our customers and reduce their transportation costs.

 

We are a recognized industry leader in safety and environmental performance. Our focus on safety and environmental performance results in a lower likelihood of disruption of production at our mines, which leads to higher productivity and improved financial performance. We operate some of the nation’s safest mines, with 2011 underground and surface mine total injury incident rates, as tracked by the Mine Safety and Health Administration (“MSHA”), below industry averages.

 

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

 

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

 

We are the largest producer of metallurgical coal in the United States and have access to international customers. We are the largest producer of metallurgical coal in the United States and have the ability to serve international customers. We have the capacity to ship in the range of 25 to 30 million tons annually through our access to international shipping points on the east and gulf coasts of the United States, including our 41% ownership interest in DTA.

 

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

 

Business Strategy

 

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

 

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

 

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

 

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. by evaluating future growth opportunities, including expansion of production capacity at our existing mining operations, further development of existing significant reserve blocks in Northern and Central Appalachia, and potential strategic acquisition opportunities that arise in the United States or internationally. We will act prudently to support and augment our metallurgical coal franchise, create a sustainable steam coal portfolio, and take appropriate actions to address operations that are unable to contribute to a sustainable portfolio.

 

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

 

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

 

Coal Mining Techniques

 

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

 

Longwall Mining

 

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

 

Room-and-Pillar Mining

 

Our AMFIRE, Coal River East, Coal River West, Brooks Run North, Brooks Run South, Brooks Run West, Virginia, Northern Kentucky and Southern Kentucky business units utilize room-and-pillar mining methods. In this type of mining, main airways and transportation entries are developed and maintained while remote-controlled continuous miners extract coal from so-called rooms by removing coal from the seam, leaving pillars to support the roof. Shuttle cars, 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. Highwall mining is used in connection with surface mining. A highwall mining system consists of a remotely controlled continuous miner, which extracts coal and conveys it via augers or belt conveyors to the portal. The cut is typically a rectangular, horizontal opening in the highwall (the unexcavated face of exposed overburden and coal in a surface mine) 11-feet wide and reaching depths of up to 1,000 feet. Multiple parallel openings are driven into the highwall, separated by narrow pillars that extend the full depth of the hole.

 

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

 

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coal. These characteristics determine the best end use of a particular type of coal. We mine, process, market and transport sub-bituminous and bituminous coal, characteristics of which are described below.

 

Heat Value. The heat value of coal is commonly measured in British thermal units, or “Btus.” A Btu is the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. Alpha mines both sub-bituminous and bituminous coal. Bituminous coal is located primarily in Appalachia, Arizona, the Midwest, Colorado, Wyoming and Utah and is the type most commonly used for electric power generation in the United States. Sub-bituminous coal is used for industrial steam purposes, while bituminous coal, depending on its quality, can be used for both metallurgical and industrial steam purposes. Of our estimated 4.7 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 71% of our proven and probable reserves are low sulfur coal.

 

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

 

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

 

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

 

Business Environment

 

Coal is an abundant, efficient and affordable natural resource used primarily to provide fuel for the generation of electric power. According to the U.S. Department of Energy’s Energy Information Administration (“EIA”) 2011 International Energy Outlook, world-wide economically recoverable coal reserves using today’s technology are estimated to be approximately 948 billion tons. Also according to the 2011 EIA International Energy Outlook, the United States is one of the world’s largest producers of coal and has approximately 27% of global coal reserves, representing about 222 years of supply based on current usage rates. According to the U.S. Department of Energy, the energy content of the United States’ demonstrated recoverable coal reserves exceeds the world’s proven oil reserves.

 

Coal Markets. Coal is primarily consumed by utilities to generate electricity. It is also used by steel companies to make steel products and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. In general, coal is characterized by end use as either steam coal or metallurgical coal. Steam coal is used by electricity generators and by industrial facilities to produce steam, electricity or both. Metallurgical coal is refined into coke, which is used in the production of steel. Over the past forty years, total annual coal consumption in the United States (excluding exports) has more than doubled and remains at over one billion tons in 2011.

 

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Table of Contents

 

 

 

Actual (1)

 

Preliminary (1)

 

Projected (1)

 

Annual Growth

 

Consumption by Sector

 

2008

 

2009

 

2010

 

2011

 

2015

 

2030

 

2011-2015

 

2015-2030

 

 

 

(Tons in millions)

 

Electric Generation

 

1,041

 

937

 

984

 

945

 

928

 

1,094

 

-0.4

%

1.2

%

Industrial

 

54

 

45

 

48

 

49

 

49

 

48

 

0.1

%

-0.1

%

Steel Production

 

22

 

15

 

21

 

24

 

22

 

20

 

-1.6

%

-0.6

%

Coal-to-Liquids Processes

 

 

 

 

 

 

11

 

82

 

 

 

43.0

%

Residential/Commercial

 

4

 

3

 

3

 

3

 

3

 

3

 

0.0

%

0.0

%

Export

 

82

 

59

 

82

 

107

 

70

 

74

 

-8.6

%

0.4

%

Total

 

1,203

 

1,059

 

1,138

 

1,127

 

1,083

 

1,321

 

 

 

 

 

 


(1)                       Data sourced from the U.S. Department of Energy’s EIA’s 2011 Annual Energy Outlook. The 2011 production figures are from the EIA’s weekly production report released January 5, 2012.

 

Much of the nation’s power generation infrastructure is coal-fired. As a result, coal has maintained a 43% to 51% market share during the past 10 years according to the U.S. Department of Energy EIA’s Short-Term Energy Outlook, principally because of its relatively low cost, reliability and domestic abundance. Coal is a low-cost fossil fuel used for base-load electric power generation, typically being considerably less expensive than oil and generally competitive with natural gas. Coal-fired generation is also competitive with nuclear power generation especially on a total cost per megawatt-hour basis. The production of electricity from existing hydroelectric facilities is inexpensive, but its application is limited both by geography and susceptibility to seasonal and climatic conditions. Through 2011, non-hydropower renewable power generation accounted for only 4.7% of all the electricity generated in the United States, and wind and solar power represented only 2.9% 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 2016 are as follows:

 

 

 

Range of Total System Levelized Costs
(2009 $/megawatthour) for Plants Entering
Service in 2016

 

Plant Type (1)

 

Minimum

 

Average

 

Maximum

 

Conventional Coal

 

$

85.60

 

$

95.10

 

$

111.00

 

Advanced Coal

 

$

100.90

 

$

109.70

 

$

122.20

 

Conventional Natural Gas Combined Cycle

 

$

59.20

 

$

65.10

 

$

73.30

 

Conventional Natural Gas Combustion Turbine

 

$

98.40

 

$

123.00

 

$

141.10

 

Advanced Nuclear

 

$

109.80

 

$

114.00

 

$

121.60

 

Wind

 

$

82.30

 

$

96.10

 

$

115.50

 

Wind - Offshore

 

$

187.10

 

$

243.70

 

$

350.00

 

Solar PV

 

$

158.90

 

$

211.00

 

$

324.40

 

Solar Thermal

 

$

192.00

 

$

312.20

 

$

642.50

 

Geothermal

 

$

85.70

 

$

99.80

 

$

115.80

 

Biomass

 

$

99.60

 

$

112.60

 

$

132.50

 

Hydro

 

$

58.60

 

$

90.50

 

$

149.00

 

 


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

 

Coal Production.  United States coal production was approximately 1.1 billion tons in 2011. 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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Table of Contents

 

 

 

Actual (1)

 

Preliminary (1)

 

Projected (1)

 

Annual Growth

 

Production by Region

 

2008

 

2009

 

2010

 

2011

 

2015

 

2030

 

2010-2015

 

2015-2030

 

 

 

(Tons in millions)

 

Powder River Basin

 

452

 

417

 

432

 

436

 

438

 

566

 

0.1

%

1.9

%

Central Appalachia

 

234

 

197

 

194

 

186

 

112

 

103

 

-9.9

%

-0.5

%

Northern Appalachia

 

136

 

128

 

137

 

132

 

141

 

153

 

1.6

%

0.6

%

Illinois Basin

 

102

 

106

 

110

 

114

 

113

 

124

 

0.0

%

0.6

%

Other

 

248

 

227

 

228

 

221

 

235

 

307

 

1.6

%

2.1

%

Total

 

1,172

 

1,075

 

1,100

 

1,089

 

1,040

 

1,252

 

 

 

 

 

 


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

 

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

 

Competition. The coal industry is intensely competitive. With respect to our U.S. customers, we compete with numerous coal producers in the Appalachian region and 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 2011, imports accounted for a relatively small percentage of total U.S coal consumption. Approximately 1.4% of total U.S. coal consumption in 2011 was imported. Excess industry capacity, which has occurred in the past, tends to result in reduced prices for our coal. The most important factors on which we compete are delivered coal price, coal quality and characteristics, 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 2011 domestic coal consumption. These coal consumption patterns are influenced by factors beyond our control, including the demand for electricity, which is significantly dependent upon summer and winter temperatures and commercial and industrial outputs in the United States, environmental and other government regulations, technological developments and the location, availability, quality and price of competing fuels for power, most notably natural gas, but also including nuclear, fuel oil and alternative energy sources such as hydroelectric power. Demand for our low sulfur coal and the prices that we will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances in order to meet Clean Air Act requirements.

 

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

 

Mining Operations

 

We currently operate in five regions located in Virginia, West Virginia, Pennsylvania, Kentucky and Wyoming.  As of December 31, 2011, these regions include 12 business units and 35 preparation plants, each of which receive, blend, process and ship coal that is produced from one or more of our 145 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 three 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 2011, most of our preparation plants also processed coal that we purchased from third party producers before reselling it to our customers. Within each region, mines have been developed at strategic locations 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.

 

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Table of Contents

 

The following table provides location and summary information regarding our five regions and the preparation plants and active mines associated with these regions as of December 31, 2011:

 

Regional Operations

 

 

 

 

 

 

 

 

 

Number and Type of

 

 

 

 

 

 

 

 

 

 

 

Preparation Plants/Shipping

 

Mines as of

 

 

 

2011 Production of

 

Reportable

 

 

 

 

 

Points as of December 31,

 

December 31, 2011

 

 

 

Saleable Tons (in

 

Segment

 

Region/Business Unit

 

Location

 

2011

 

Underground

 

Surface

 

Total

 

Transportation

 

thousands) (1) (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAPP North

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

East

 

Coal River Surface

 

West Virginia

 

Pax, Elk Run, and Mammoth

 

 

6

 

6

 

Barge, CSX, NS, RJCC

 

4,652

 

East

 

Coal River East

 

West Virginia

 

Goals, Elk Run, and Marfork

 

13

 

1

 

14

 

CSX

 

3,631

 

East

 

Coal River West

 

West Virginia

 

Liberty, Omar, and Homer III

 

2

 

1

 

3

 

CSX

 

1,926

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAPP Central

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

East

 

Brooks Run North

 

West Virginia

 

Erbacon, Green Valley, Power Mountain, and Mammoth

 

10

 

2

 

12

 

Barge, NS, CSX

 

4,726

 

East

 

Brooks Run South

 

Virginia, West Virginia

 

Litwar and Kepler

 

15

 

5

 

20

 

NS

 

5,320

 

East

 

Brooks Run West

 

West Virginia

 

Zigmon, Delbarton, and Rockspring

 

5

 

3

 

8

 

NS, CSX

 

5,487

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAPP South

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

East

 

Virginia

 

Virginia

 

Pigeon Creek, Toms Creek and McClure

 

23

 

7

 

30

 

Truck, NS, CSX

 

6,814

 

East

 

Northern Kentucky

 

Kentucky

 

Long Fork, Martin County, and Sidney

 

8

 

3

 

11

 

NS

 

2,191

 

East

 

Southern Kentucky

 

Kentucky

 

Cave Branch, Roxana, Coalgood and Pioneer

 

15

 

3

 

18

 

CSX

 

4,829

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NAPP

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

East

 

Pennsylvania Services

 

Pennsylvania

 

Cumberland and Emerald

 

2

 

 

2

 

Barge, Truck, CSX

 

9,898

 

East

 

AMFIRE

 

Pennsylvania

 

Clymer and Portage

 

6

 

13

 

19

 

NS, Truck

 

2,839

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Powder River Basin

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

West

 

Alpha Coal West

 

Wyoming

 

Belle Ayr and Eagle Butte

 

 

2

 

2

 

BNSF, UP, Truck

 

49,947

 

 

 

Total from active operations

 

 

 

99

 

46

 

145

 

 

 

102,260

 

 


(1)                 Includes coal purchased from third-party producers that was processed at our preparation plants in 2011.

(2)                 Includes Massey operations for the period June 1, 2011 through December 31, 2011.

 

BNSF = BNSF Railway

CSX = CSX Transportation

RJCC = R.J. Corman Railroad Company

NS = Norfolk Southern Railway Company

UP = Union Pacific Railroad Company

 

On February 3, 2011, we announced that subsidiaries in Kentucky and West Virginia planned to idle four mines immediately and two others between the date of the announcement and early 2013, while several other mines altered work schedules or reduced the number of production crews. Altogether 10 mining operations are affected, four in eastern Kentucky and six in southern West Virginia. The adjustments are expected to reduce 2012 coal production by approximately 4.0 million tons. The total includes approximately 2.5 million tons of thermal coal and 1.5 million tons of lower quality, high-volatility metallurgical coal.

 

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.

 

CAPP North

 

Our CAPP North region consists of three business units, Coal River Surface, Coal River East and Coal River West, which collectively shipped 9.9 million tons in 2011.  Coal is mined primarily using continuous miners employing the room-and-pillar method at our underground mines and the truck and front-end loader at our surface mines.  We control approximately 693.2 million tons of coal reserves through our CAPP North region.  Approximately 453.4 million tons are assigned to active mines and approximately 239.8 million tons are unassigned. There are 3,369 salaried and hourly employees in our CAPP North region.

 

Coal River Surface produces coal from six surface mines.  These mines sell high Btu, low, medium, and high sulfur steam coal primarily to eastern utilities and metallurgical coal to steel companies.  The coal produced by the mines is transported by truck and belt to Pax loadout, Elk Run preparation plant, or Mammoth preparation plant, where it is cleaned, blended and loaded onto rail or barge for shipment to

 

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Table of Contents

 

customers. During 2011, Coal River Surface shipped 3.7 million tons.

 

Coal River East produces coal from thirteen underground mines and one surface mine. These mines sell high Btu, low, medium, and high sulfur steam coal primarily to eastern utilities and metallurgical coal to steel companies. The coal produced by the underground mines is transported by truck and belt to Goals preparation plant, Elk Run preparation plant, or Marfork preparation plant. The coal produced by the surface mines is trucked to the Goals and Marfork preparation plants. At the preparation plant, the coal is cleaned, blended and loaded onto rail for shipment to customers. During 2011, Coal River East shipped 4.2 million tons.

 

Coal River West produces coal from two underground mines and one surface mine. These mines sell mostly high Btu, low, medium and high sulfur steam coal primarily to eastern utilities and a small amount of metallurgical coal to steel companies. The coal produced by the mines is transported by truck to Liberty preparation plant, Omar loadout, or Homer III loadout. During 2011, Coal River West shipped 1.9 million tons.

 

CAPP Central

 

Our CAPP Central region consists of three business units, Brooks Run North, Brooks Run South and Brooks Run West, which collectively shipped 15.4 million tons in 2011. Coal is mined primarily using continuous miners employing the room-and-pillar mining method at our underground mines and the truck and front-end loader method at our surface mines. We control approximately 1,236.5 million tons of coal reserves through our CAPP Central region. Approximately 486.9 million tons are assigned to active mines and approximately 749.6 million tons are unassigned. There are 3,892 salaried and hourly employees in our CAPP Central region.

 

Brooks Run North produces coal from ten underground mines and two surface mines. The mines sell high Btu, low sulfur steam coal to eastern utilities and metallurgical coal to steel companies. The coal is transported by truck to either our Erbacon preparation plant, Green Valley preparation plant, Power Mountain preparation plant or Mammoth preparation plant, where it is cleaned, blended and loaded onto rail for shipment to customers.  During 2011, Brooks Run North shipped 4.7 million tons.

 

Brooks Run South produces coal from fifteen underground mines and five surface mines, a portion of which are operated by independent contractors. The mines sell high Btu, low sulfur steam coal to eastern utilities and metallurgical coal to steel companies. The coal is transported by truck or rail to either the Litwar preparation plant, the Kepler preparation plant or the Ben’s Creek loadout, where it is cleaned, blended and loaded onto rail for shipment to customers.  During 2011, Brooks Run South shipped 5.3 million tons. We also recover coal from the road construction business operated by our subsidiary Nicewonder Contracting, Inc. (“NCI”).

 

Brooks Run West produces coal from five underground mines and three surface mines. The mines sell high Btu, low sulfur steam coal to eastern utilities and metallurgical coal to steel companies. The coal is transported by truck and belt to Zigmon Processing, Delbarton Processing, or Rockspring preparation plant, where it is cleaned, blended and loaded onto rail for shipment to customers.  During 2011, Brooks Run West shipped 5.3 million tons.

 

CAPP South

 

Our CAPP South region consists of three business units, Northern Kentucky, Southern Kentucky and Virginia. Coal is mined primarily using continuous miners employing the room-and-pillar mining method at our underground mines, the truck and front-end loader and highwall mining methods at our surface mines. We control approximately 1,026.6 million tons of coal reserves through our CAPP South region. Approximately 461.2 million tons are assigned to active mines and approximately 565.4 million tons are unassigned. There are approximately 3,887 salaried and hourly employees in our CAPP South region.

 

Virginia produces coal from twenty-three underground mines, four of which are operated by independent contractors. Virginia also has seven surface mines, one of which is operated by an independent contractor. These mines sell high Btu, low sulfur steam coal primarily to eastern utilities and metallurgical coal to steel companies. The coal produced by the underground mines is transported by truck to the Pigeon Creek preparation plant operated by Cumberland Resources, the Toms Creek preparation plant operated by Paramont and the McClure preparation plant operated by Dickenson Russell, where it is cleaned, blended and loaded onto rail for shipment to customers. The coal produced by the surface mines is transported to one of our preparation plants where it is blended and loaded onto rail for shipment to customers. During 2011, Virginia shipped 6.8 million tons.

 

Northern Kentucky produces coal from eight underground mines.  Northern Kentucky also operates three surface mines. These mines sell high Btu, low sulfur steam coal primarily to eastern utilities. The coal produced by the underground mines is transported by truck and overland belt to the Long Fork, Martin County, Sidney or Sprouse Creek preparation plants. At the preparation plant, the coal is cleaned, blended and loaded onto rail for shipment to customers. The coal produced by the surface mines is transported to one of our preparation plants or raw coal loading docks where it is blended and loaded onto rail for shipment to customers. During 2011, Northern Kentucky shipped 2.3 million tons.

 

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Table of Contents

 

Southern Kentucky produces coal from fifteen underground mines, six of which are operated by independent contractors. Southern Kentucky also operates three surface mines, one of which is operated by an independent contractor.  These mines sell high Btu, low, medium, and high sulfur steam coal primarily to eastern utilities and metallurgical coal to steel companies. The coal is transported by truck to the Cave Branch preparation plant operated by Black Mountain Resources, or the Roxanna preparation plant operated by Enterprise, where it is cleaned, blended and loaded on rail or truck for shipment to customers. The coal produced by the surface mines is transported to the Coalgood preparation plant operated by Coalgood, the Roxanna preparation plant operated by Enterprise or the Pioneer loading facility operated by Enterprise, where it is blended and loaded onto rail for shipment to customers.  During 2011, Southern Kentucky shipped 4.7 million tons.

 

Powder River Basin

 

Our Alpha Coal West business unit is located in the Powder River Basin. Alpha Coal West consists of our Belle Ayr and Eagle Butte operations, which collectively shipped 49.9 million tons in 2011. Coal is mined primarily using the truck and shovel mining method. We control approximately 740.2 million tons of coal reserves through our Alpha Coal West region and all of the coal reserves are assigned to active mines. There are approximately 679 salaried and hourly employees in our Alpha Coal West business unit.

 

Belle Ayr consists of one mine that produces sub-bituminous, low sulfur steam coal for sale primarily to utility companies. Belle Ayr extracts coal from a coal seam that is 75 feet thick. The mine sells 100% raw coal mined and no washing is necessary. Belle Ayr shipped 24.5 million tons of coal in 2011. Belle Ayr has the advantage of shipping its coal on both of the major western railroads, the BNSF Railway and the Union Pacific Railroad, to power plants located throughout the West, Midwest and the South.

 

Eagle Butte consists of one mine that produces sub-bituminous, low sulfur steam coal for sale primarily to utility companies. Eagle Butte extracts coal from coal seams that total 100 feet thick. The mine sells 100% raw coal mined and no washing is necessary. Eagle Butte shipped 25.4 million tons of coal in 2011. 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.

 

NAPP

 

Our Pennsylvania Services business unit, within our NAPP region, consists of our Cumberland and Emerald mining complexes, which collectively shipped 9.9 million tons in 2011. Coal is mined primarily by using longwall mining systems supported by continuous miners. We control approximately 852.9 million tons of contiguous reserves through our Pennsylvania Services business unit. Approximately 165.4 million tons are assigned to active mines and 687.5 million tons are unassigned. Both mines operate in the Pittsburgh No. 8 Seam, the dominant coal-producing seam in the region, which is six to eight feet thick in the mines. The mines sell high Btu, high sulfur steam coal primarily to eastern utilities. During 2011, approximately 4% of the shipments were marketed as high volatility metallurgical coal to export customers. There are 1,519 salaried and hourly employees at our Pennsylvania Services business unit. The hourly work force at each mine is represented by the United Mine Workers of America (“UMWA”).

 

Cumberland shipped 6.2 million tons of coal in 2011. 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 3.7 million tons of coal in 2011. 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.

 

Our AMFIRE business unit, within our NAPP region, consists of six underground mines operated by AMFIRE employees and thirteen surface mines, six of which are operated by independent contractors. Coal is mined primarily using continuous miners employing the room-and-pillar mining method at the underground mines and the truck and front-end loader method at our surface mines. We control approximately 99.4 million tons of coal reserves through our AMFIRE business unit. Approximately 30.6 million tons are assigned to active mines and approximately 68.8 million tons are unassigned. AMFIRE employs 573 salaried and hourly employees. The mines sell high Btu, low, medium, and high sulfur coal to eastern utilities and steel companies. All of the underground mining operations at AMFIRE are staffed and operated by AMFIRE employees. The underground coal is delivered directly by truck to the customer, or transported to the Clymer or Portage coal preparation plants or raw coal loading docks where it is cleaned, blended and loaded onto rail, belt or truck for shipment to customers. The surface mined coal is delivered directly by truck to the customer or transported to the Clymer or Portage coal preparation plants or raw coal loading docks where it is blended and loaded onto rail, belt or truck for shipment to customers. During 2011, AMFIRE shipped 2.8 million tons.

 

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Table of Contents

 

Other Operations

 

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

 

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

 

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

 

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

 

Dominion Terminal Associates. Through our subsidiary Alpha Terminal Company, LLC, we hold a 41% interest in Dominion Terminal Associates (“DTA”), a 20 million-ton annual capacity coal export terminal located in Newport News, Virginia. The terminal, constructed in 1984, provides the advantages of unloading/transloading equipment with ground storage capability, providing producers with the ability to custom blend export products without disrupting mining operations. During 2011, we shipped a total of 4.4 million tons of coal to our customers through the terminal. We make periodic cash payments in respect of the terminal for operating expenses, which are offset by payments we receive for transportation incentive payments and for renting our unused storage space in the terminal to third parties. In 2011, we received cash payments related to the terminal of $10.8 million partially offset by payments we made for expenses of $20.8 million. The terminal is held in a partnership with subsidiaries of two other companies, Arch Coal, Inc. and Peabody Energy Corp.

 

Coal Handling Joint Venture.  We acquired a 50% interest in a joint venture in the Massey Acquisition 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 60 employees as of December 31, 2011, and consists of sales managers, distribution/traffic managers, contract administrators and administrative personnel. In addition to marketing coal produced in our 12 business units, we are also actively involved in the purchase and resale of coal mined by others, the majority of which we blend with coal produced from our mines. We have coal supply commitments with a wide range of electric utilities, steel manufacturers, industrial customers and energy traders and brokers. Our marketing efforts are centered on customer needs and requirements. By offering coal of both steam and metallurgical grades to provide specific qualities of heat content, sulfur and ash, and other characteristics relevant to our customers, we are able to serve a diverse customer base. This diversity allows us to adjust to changing market conditions and provides us with the ability to sustain high sales volumes and sales prices for our coal. Many of our larger customers are well-established public utilities and steel manufacturers who have been stable long-term customers of ours and our acquired companies.

 

We sold a total of 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. 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 84.8 million tons of coal in 2010, consisting of 81.9 million tons of coal produced and processed by us, and 3.0 million tons of purchased coal. A portion of purchased coal was blended prior to resale, meaning the coal was mixed with coal produced from our mines prior to resale, which generally allows us to realize a higher overall margin for the blended product than we would be able to achieve selling these coals separately. A portion of purchased coal was processed by us and a portion of purchased coal was sold direct to customers.

 

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

 

The breakdown of tons sold for 2011, 2010, and 2009 is set forth in the table below:

 

 

 

Steam Coal Sales (1)

 

Metallurgical Coal Sales (1)

 

Year

 

Tons

 

% of Total Sales Volume

 

Tons

 

% of Total Sales Volume

 

 

 

(In millions, except percentages)

 

 

 

 

 

 

 

 

 

 

 

2011 (2)

 

87.1

 

82

%

19.2

 

18

%

2010

 

73.0

 

86

%

11.8

 

14

%

2009 (3)

 

39.1

 

83

%

8.1

 

17

%

 


(1)                           Sales of steam coal during 2011, 2010, and 2009 were made primarily to large utilities and industrial customers throughout the United States and sales of metallurgical coal during those years were made primarily to steel companies in the Northeastern and Midwestern regions of the United States and in countries in Europe, Asia and South America.

(2)                           The amounts for 2011 include the results of operations for Massey for the period from June 1, 2011 through December 31, 2011. The amounts for 2010 and 2009 do not include the results of operations for Massey.

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

 

We sold coal to over 200 different customers in 2011. Our top ten customers in 2011 accounted for approximately 41% of 2011 total revenues and our largest customer during 2011 accounted for approximately 9% of 2011 total revenues. The following table provides information regarding exports in 2011, 2010, and 2009 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

 

 

 

 

 

 

 

 

 

 

 

2011 (1)

 

16.3

 

15

%

$

3,096.0

 

44

%

2010

 

9.6

 

11

%

$

1,351.0

 

34

%

2009 (2)

 

6.6

 

14

%

$

768.0

 

31

%

 


(1)                           The amounts for 2011 include the results of operations for Massey for the period from June 1, 2011 through December 31, 2011. The amounts for 2010 and 2009 do not include the results of the operations for Massey.

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

 

Export shipments during 2011, 2010, and 2009 serviced customers in 27, 27, and 19 countries, respectively, across North America, Europe, South America, Asia and Africa. India was the largest export market in 2011, with sales to India accounting for approximately 15% of total export revenues and 7% of total revenues. Brazil was the largest export market in 2010 and 2009, with sales to Brazil accounting for approximately 11% and 23%, respectively, of total export revenues and 4% and 7%, respectively, of total revenues. All of our sales are made in U.S. dollars.

 

As is customary in the coal industry, when market conditions are appropriate and particularly in the steam coal market, we enter into long-term contracts (exceeding one year in duration) with many of our customers. These arrangements allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. A majority of our steam coal sales are shipped under long-term contracts. During 2011, approximately 50% and 81% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts. During 2010, approximately 87% and 78% of our steam and metallurgical coal sales volume,

 

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respectively, was delivered pursuant to long-term contracts.  During 2009, approximately 71% and 55% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts.

 

Our sales backlog, including backlog subject to price reopener and/or extension provisions, was approximately 234.9 million tons as of February 8, 2012 and approximately 195.9 million tons for the comparable period in 2011. Of these tons, approximately 48% and 43%, respectively, were expected to be filled within one year.

 

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

 

Distribution

 

We employ transportation specialists who negotiate freight and terminal agreements with various providers, including railroads, trucks, barge lines, and terminal facilities. Transportation specialists also coordinate with customers, mining facilities and transportation providers to establish shipping schedules that meet the customer’s needs. Our produced and processed coal is loaded from our 35 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 75% of total shipments of coal volume produced and processed from our mines to the preparation plant to the customer in 2011. The balance was shipped from our preparation plants, loadout facilities or mines via truck. In 2011, approximately 7% of our coal sales volume was delivered to our customers through transport on the Great Lakes and domestic rivers, approximately 5% was moved through the Norfolk Southern export facility at Norfolk, Virginia, approximately 4% was moved through the coal export terminal at Newport News, Virginia operated by DTA, and approximately 5% was moved through the export terminals at Baltimore, MD and New Orleans, LA. We own a 41% interest in the coal export terminal at Newport News, VA operated by DTA. See “-Other Operations.”

 

Transportation

 

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

 

We depend upon rail, barge, trucking and other systems to deliver coal to markets. In 2011, our produced coal was transported from the mines and to the customer primarily by rail, with the main rail carriers being CSX Transportation, Norfolk Southern Railway Company, BNSF Railway and Union Pacific Railroad Company. The majority of our sales volume is shipped by rail, but a portion of our production is shipped by barge and truck.

 

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

 

Suppliers

 

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

 

Each of our regional mining operations has developed its own supplier base consistent with local needs. We have a centralized sourcing group, 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 regional 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 in any region. 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.

 

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Employees

 

As of December 31, 2011, we had approximately 14,500 employees. As of December 31, 2011, the UMWA represented approximately 10% of our employees located in Kentucky, Virginia, West Virginia and Pennsylvania. UMWA-represented employees produced approximately 10% of our coal sales volume during the fiscal year ended December 31, 2011. Relations with organized labor are important to our success, and we believe our relations with our employees are very good.

 

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ENVIRONMENTAL AND OTHER REGULATORY MATTERS

 

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

 

We endeavor to conduct our mining and other operations in compliance with all applicable federal, state, and local laws and regulations. However, due in part to the extensive and comprehensive regulatory requirements, violations occur from time to time. It is possible that future liability under or compliance with environmental and safety requirements could have a material effect on our operations or competitive position. Under some circumstances, substantial fines and penalties, including revocation or suspension of mining or other permits or plans, may be imposed under the laws described below. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.

 

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

 

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

 

In February 2011, MSHA published proposed changes to its Pattern of Violations (“POV”) program. Under the proposed changes, MSHA will consider all significant and substantial citations and orders issued, including non-final citations and orders, when determining POV status, will post the pattern criteria and compliance date online, and will review mines at least twice annually for POV status.

 

In August 2011, MSHA published a proposed rule to require certain underground mining equipment to be equipped with proximity detection systems that will shut the equipment down if a person is too close to the equipment to avoid injuries where individuals are caught between equipment and blocks of unmined coal.

 

Final action by MSHA on these proposals remains pending. 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, 2011, all of our various payment obligations for federal black lung benefits to claimants entitled to such benefits are either fully secured by insurance coverage or paid from a tax exempt trust established for that purpose. Based on actuarial reports and required funding levels, from time to time we may have to supplement the trust corpus to cover the anticipated liabilities going forward.

 

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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 2011 and 2010 for our obligations to the Combined Benefit Fund were approximately $0.5 million and $0.8 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 2011 and 2010 for our obligation to the 1992 Plan were $1.6 million and $0.9 million, respectively. These per beneficiary premiums for both the Combined Benefit Fund and the 1992 Plan are adjusted annually based on various criteria such as the number of beneficiaries and the anticipated health benefit costs.

 

On December 20, 2006, the Tax Relief and Health Care Act of 2006 (“TRHC”) became law. The TRHC seeks to reduce or eliminate the premium obligation of companies due to the expanded transfers from the Abandoned Mine Land Fund (“AML”). The additional transfer of funds from AML has incrementally eliminated, to the extent the new transfers are adequate, the unassigned beneficiary premium under the Combined Benefit Fund effective October 1, 2007. The additional transfers will also reduce incrementally the pre-funding and assigned beneficiary premium to cover the cost of beneficiaries for which no individual company is responsible (“orphans”) under the 1992 Plan beginning January 1, 2008. For the first time, the 1993 Benefit Plan (“the 1993 Plan”) (all of the beneficiaries 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.

 

Environmental Laws

 

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

 

Mining Permits and Necessary Approvals

 

Numerous governmental permits, licenses or approvals are required for mining, oil and gas operations, and related operations. When we apply for these permits and approvals, we may be required to present data to federal, state or local authorities pertaining to the effect or impact our operations may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining or other operations. These requirements may also be supplemented, modified or re-interpreted from time to time. Regulations also provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position to control another entity that has outstanding mining permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.

 

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

 

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

 

Surface Mining Control and Reclamation Act

 

The Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement within the Department of the Interior (the “OSM”), establishes mining, environmental protection and reclamation standards for all aspects of surface mining, as well as many aspects of deep mining that impact the surface. Where state regulatory

 

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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 (“CERCLA” or “Superfund”). SMCRA permit provisions include requirements for, among other actions, coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; mitigation plans; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation. The permit application process is initiated by collecting baseline data to 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 are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land.

 

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

 

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

 

In December 2008, 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 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.  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; however, 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 the ability to obtain or the cost of bonds in the future.

 

Greenhouse Gas Emissions Impact Initiatives

 

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

 

Considerable and increasing government attention in the United States and other countries is being paid to reducing GHG emissions, including CO2 emissions from coal-fired power plants and methane emissions from mining operations. Although the United States has not ratified the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (“UNFCCC”), which became effective for many countries in 2005 and establishes a binding set of emission targets for GHGs, the United States is actively participating in various international initiatives within and outside of the UNFCCC process to negotiate developed and developing nation commitments for GHG emission reductions and related financing. In particular, the Durban Platform for Enhanced Action, as agreed to by the United States and 193 other countries in December 2011 at the 17th UNFCCC, calls for a second phase of the Kyoto Protocol’s GHG emissions restrictions to be

 

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effective through 2020 and for a new international treaty to come into effect and be implemented from 2020. 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 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. In October 2009, the EPA published its final Mandatory Greenhouse Gas Reporting Rule, which requires power plants and other large sources of GHG to commence data collection in January 2010 and to file their first annual reports disclosing GHG emissions in 2011. In July 2010, the EPA issued amendments that would require underground coal mines and certain other source categories to file their first annual reports disclosing GHG emissions in 2012, covering calendar year 2011. Many of our facilities have already begun reporting the required GHG data, and our remaining facilities are in the process of commencing reporting of such data in accordance with the regulations.

 

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

 

In addition to federal GHG regulations, there are several new state programs to limit GHG emissions and others have been proposed. 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 several emission allowances auctions and will enter its second three-year control period in 2012.

 

On December 17, 2010, the California Air Resources Board (“CARB”) issued a final rule approving a state-wide GHG cap-and-trade program to be implemented pursuant to the California Global Warming Solutions Act of 2006 (known as “AB 32”).  In June 2011, CARB announced that initial cap-and-trade program compliance for the electricity sector would be delayed until January 2013.  Many 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 greenhouse gas emissions impact legislation is difficult given the various alternatives proposed and the complexities of the interactions between economic and environmental issues. Coal-fired generators could switch to other fuels that generate less of these emissions, possibly reducing the construction of coal-fired power plants or causing some users of our coal to switch to a lower CO2 generating fuel, or more generally reducing the demand for coal-fired electricity generation. This could result in an indeterminate decrease in demand for coal nationally, and various mechanisms proposed to limit greenhouse gas emissions could impact the price of coal and the cost of coal-fired generation. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use to comply with applicable ambient air quality standards. In addition, if regulation of GHG emissions does not exempt the release

 

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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.  In 1997, the EPA revised the NAAQS for particulate matter, retaining the existing standard for particulate matter with an aerodynamic diameter less than or equal to 10 microns (“PM10”), and adding a new standard for fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns (“PM2.5” or “fine particulate matter”). In April 2005, the EPA issued final non-attainment designations for 39 areas not achieving the 1997 PM2.5 standards, and in April 2007, the EPA issued its fine particle implementation rule establishing rules and guidance for state implementation plans to meet the standards. Under the Clean Air Act, state implementation plans were due in April 2008, establishing a regulatory program to meet the 1997 PM2.5 standards either by April 2010 or, if the EPA granted an extension, as expeditiously as practicable, but no later than April 2015. Moreover, in October 2006, the EPA issued a revised, more stringent 24-hour PM2.5 standard, triggering another round of non-attainment designations and ultimately regulation. In October 2009, the EPA designated 31 areas as non-attainment for the 2006 PM2.5 standard. Under the EPA’s current timeline, state implementation plans are due by December 2012 and attainment is required by December 2014, or December 2019 if the EPA grants an extension. Meeting the new PM2.5 standard also may require reductions of nitrogen oxide and 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. In 1997, the EPA revised the NAAQS for ozone. Although legal challenges delayed implementation, in April 2004, the EPA announced that counties in 31 states and the District of Columbia failed to meet the new eight-hour standard for ozone and the EPA issued implementation rules in April 2004 and November 2005. At present, the 1997 ozone standard, as amended in 2008, is gradually phasing in. In addition, the EPA proposed a more stringent ozone NAAQS in January 2010, with the EPA’s review of the updated science regarding ozone currently scheduled for completion in 2013. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers may continue to become more demanding in the years ahead.

 

·                  Clean Air Interstate Rule/Cross-State Air Pollution Rule.  In 2005, the EPA issued its final Clean Air Interstate Rule (“CAIR”) for further reducing emissions of sulfur dioxide 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. Although a July 2008 court decision requires the EPA to modify CAIR, it currently remains in effect except in Minnesota, where a stay applies. In July 2011, in response to the court order on CAIR, the

 

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EPA issued a new rule to replace CAIR, called the Cross-State Air Pollution Rule (“CASPR”). CASPR would require additional reductions of power plant emissions in 27 eastern states - by 73% for SO2 and 54% for NOx compared to 2005 levels, according to the EPA. As well, CASPR would severely limit interstate emissions trading as a compliance option. In December 2011, a federal appellate court issued a stay of CASPR pending judicial review. During the stay, CAIR remains in effect. CASPR may ultimately require many coal-fired sources to install additional pollution control equipment for NOx and SO2.

 

·                  Mercury and Air Toxics Standards. Following prolonged regulatory and court proceedings, in December 2009, the EPA announced that it plans to promulgate a rule under section 112 of the Clean Air Act that will establish limits for power plants based on Maximum Available Control Technology (“MACT”) for mercury and other hazardous air pollutants.  In December 2011, the EPA issued the new MACT requirements in final regulations entitled the Mercury and Air Toxics Standards (“MATS”).  The MATS 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 MW or more.  Existing units generally have up to four years to comply.  Accordingly, the MATS may ultimately require many coal-fired sources to install additional pollution control equipment or to close.

 

·                  Regional Haze. In 1999, the EPA promulgated a regional haze rule designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks. The original regional haze rule required designated facilities to install Best Available Retrofit Technology (“BART”) to reduce emissions that contribute to visibility problems. In December 2006, the EPA modified the regional haze rule to allow states the flexibility to evaluate the use of cap-and-trade programs when such programs would result in greater progress toward the EPA’s visibility goals. States were to submit Regional Haze State Implementation Plan (“SIP”) by December 2007. Most states failed to do so, and in June 2011 several environmental groups filed a complaint in the U.S. District Court for the District of Columbia alleging that the EPA failed to promulgate regional haze federal implementation plans (“FIPs”) or approve SIPs for 34 states, and also failed to act on ten regional haze SIPs, as required by the Clean Air Act.  In December 2011, the EPA published a proposed consent decree that would require final EPA action on the plans by deadlines ranging from December 2011 to November 2012. The regional haze program primarily affects the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. It is expected that emission reductions required under other rules will address many, but perhaps not all, of the emission reduction requirements of the regional haze rule.

 

Clean Water Act

 

The Clean Water Act of 1972 (“CWA”) and corresponding state laws affect coal mining operations by imposing restrictions on the discharge of certain pollutants into water and on dredging and filling wetlands. The CWA establishes in-stream water quality standards and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water. These requirements are complex, lengthy and becoming increasingly stringent as new regulations or amendments to existing regulations are adopted. In addition, legal challenges to regulations may impact their content and the 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 for coal companies to conduct dredging or filling activities in jurisdictional waters for the purpose of creating slurry ponds, water impoundments, refuse disposal areas, valley fills or other mining activities. Jurisdictional waters typically include ephemeral, intermittent, and perennial streams. The Supreme Court of the United States 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 refuse, but has implications for the mining industry. Subsequently, in June 2007 the COE and the EPA issued a joint guidance document to attempt to develop a policy that will apply the jurisdictional standards imposed by the Supreme Court. The guidance requires a case-by-case analysis of whether the area to be filled has a sufficient nexus to downstream navigable waters so as to require 404 permits. Review and implementation of this guidance by the COE field offices remains inconsistent; the extent to which decisions made pursuant to this guidance will be challenged remains an open question.

 

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.

 

In March 2007, the U.S. District Court for the Southern District of West Virginia issued a decision concerning 404 permitting for fills. The court held that widely used pre-mining assessments of areas to be impacted required by the COE and conducted by the permit applicants are inadequate and do not accurately assess the nature of the headwater areas being filled. As such, the court found the COE erred in its finding of no significant impact from this activity. Based on this conclusion, the court went on to find that proposed mitigation to offset the adverse impacts of the area to be filled also are not supported by adequate data. In June 2007, the same federal district court also effectively prohibited mine operators from impounding streams below their valley fills for the purpose of constructing sediment ponds. Mine operators are required to route drainage from valley fills to sediment control structures and to meet NPDES permit limits for discharges from those structures. In the steep sloped areas of Central Appalachia, often the only practicable location for those structures is in the stream channel itself downstream of the valley fills. The COE and the EPA had both considered such ponds to be “treatment systems” excluded from the definition of “waters of the United States” to which the CWA applies. The court’s June 2007 opinion, however, held that these ponds remain “waters of the United States” and that mine operators must meet effluent limits for discharges into the ponds as well as from the ponds. Meeting these limits at the point where water first leaves a valley fill or enters the stream or pond would be difficult. In February 2009, the Fourth Circuit Court of Appeals overturned these lower court decisions. 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 the ability to maintain current operations and to permit new operations.

 

The COE is empowered to issue nationwide permits for specific categories of filling activity that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404. Nationwide Permit 21 (“NWP 21”) authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. On October 23, 2003, several citizens groups sued the COE in the United States District Court for the Southern District of West Virginia seeking to invalidate nationwide permits utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. The plaintiffs sought to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators from additional use of existing nationwide permit approvals until they obtain more detailed individual permits. On July 8, 2004, the court issued an order enjoining the further issuance of NWP 21 permits and rescinded certain listed permits where construction of valley fills and surface impoundments had not commenced. On August 13, 2004, the court extended the ruling to all NWP 21 permits within the Southern District of West Virginia. The COE appealed the decision to the United States Court of Appeals for the Fourth Circuit. In November 2005, the Fourth Circuit Court of Appeals overturned the July 2004 decision, thereby allowing the continued use of the NWP 21 permitting process. In June 2010, however, the COE suspended NWP 21 to eliminate its use within a six state region, including Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia, although work under existing NWP 21 permits will be allowed to continue.  In February 2011, COE issued a notice soliciting comment on NWP 21, including the options of reissuing NWP 21 with modifications or not reissuing NWP 21. In February 2012, the COE reauthorized the use, including for the six-state eastern coal region consisting of Ohio, Kentucky, Pennsylvania, Tennessee, Virginia and West Virginia.  For activities authorized under the existing NWP 21, the COE provides an additional 12-month grandfather period for completion of projects that have been commenced or will commence prior to expiration of the existing permit on March 18, 2012. For those authorized activities that will not be completed upon expiration of the grandfather period, the COE will consider reauthorizing without imposing the new limitations upon a written request for reauthorization to the district engineer by February 1, 2013.

 

Availability of the newly issued NWP 21 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 permit is not available for discharges associated with construction of valley fills. The term “valley fill” is broadly defined as a fill structure that is typically constructed within valleys associated with steep, mountainous terrain, associated with surface coal mining activities.  We have not yet determined the impact of this very newly issued NWP21 on our operations.

 

Further, surface coal mine permitting  has been impeded by the Enhanced Surface Coal Mining Pending Permit Coordination Procedures, issued by the EPA and the COE on June 11, 2009 (“ECP”), and guidance contained in a July 2011 Memorandum entitled “Improving EPA Review of Appalachian Surface Coal Mining Operations Under the Clean Water Act, National Environmental Policy Act, and the Environmental Justice Executive Order” (“Detailed Guidance”) , replacing interim guidance that was issued in April 2010. However, in October 2011, 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 ECP through issuance of guidance that did not undergo the notice and comment rulemaking process. In response to the court’s decision, in November 2011 the EPA issued a memorandum suspending use of ECP. Any future application of procedures similar to ECP, such as may be enacted following notice and comment rulemaking, would have the potential to delay issuance of permits for our surface coal mines, or to change the conditions or restrictions imposed in those permits.

 

In September 2009, the EPA announced that 79 pending permit applications would be subject to ECP because of its continuing concerns about water quality and regulatory compliance issues. These included ten of our permit applications, at least six of which have been withdrawn. ECP is now suspended, and the EPA has stated that its identification of these 79 permit applications does not constitute a determination that the mining involved cannot be permitted under CWA and does not constitute a final recommendation from the EPA to the COE on these projects. Nonetheless, it is uncertain how long the further review will take for our remaining subject permit applications, what types of conditions or restrictions will be imposed or what the final outcome will be.  As of November 2011, the EPA had issued eight permits associated with the 79 permit applications. 

 

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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. While our operations are not directly impacted, this could be a further indication that other surface mining water permits could be subject to more substantial review in the future.

 

National Pollutant Discharge Elimination System Permits

 

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

 

When a water discharge occurs and one or more parameters are outside the approved limits permitted in an NPDES permit, these exceedances of permit limits are self-reported to the pertinent agency. The agency may impose penalties for each such release in excess of permitted amounts. If factors such as heavy rains or geologic conditions cause persistent releases in excess of amounts allowed under NPDES permits, costs of compliance can be material, fines may be imposed, or operations may have to be idled until remedial actions are possible. Additionally, the CWA has citizen suit provisions which allow individuals or organized groups to file suit against permit holders or the EPA or state agencies for failure to enforce all aspects of the CWA. As discussed in Note 20 to the Company’s consolidated financial statements, certain of the Company’s subsidiaries have been subject to such proceedings. Likewise, we are aware of potential citizen suit actions against a small number of our permits, however, it is not clear if these actions will proceed. During the past several years, similar actions have been filed against other companies.

 

There also have been renewed efforts by the EPA to examine the coal industry’s record of compliance with NPDES permit limits. This enhanced scrutiny recently resulted in an agreement by Massey to pay a $20 million penalty in 2008 for over 4,000 alleged NPDES permit violations. Subsequently, each of our operating subsidiaries conducted an assessment of their NPDES monitoring and reporting practices, which identified some exceedances of permit limits. In 2009 and 2008, each of our West Virginia subsidiaries entered into Consent Orders with the West Virginia Department of Environmental Protection on this matter.  Future exceedances of permit limits may be unavoidable and future fines may be imposed. To the extent we have been required to pay stipulated penalties under the agreements, we have done so, without any material impact on our operations.

 

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.

 

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Endangered Species Act

 

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

 

Resource Conservation and Recovery Act

 

The RCRA affects coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. Certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management requirements.

 

Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion wastes generated at electric utility and independent power producing facilities, such as coal ash. In May 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under RCRA. The EPA is retaining the hazardous waste exemption for these wastes. However, the EPA has determined that national non-hazardous waste regulations under RCRA Subtitle D are needed for coal combustion wastes disposed in surface impoundments and landfills and used as mine-fill. The EPA also concluded beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. As long as this exemption remains in effect, it is not anticipated that regulation of coal combustion waste will have any material effect on the amount of coal used by electricity generators. However, the failure in 2008 of an ash disposal dam in Tennessee has focused attention on this issue and many environmental groups continue to push for classification of ash as a hazardous waste. In May 2010, the EPA issued proposed regulations governing management and disposal of coal ash from coal-fired power plants. The EPA sought public comment on two regulatory options. Under the more stringent option, the EPA would regulate coal ash as a “special waste” subject to hazardous waste standards when disposed in landfills or surface impoundments, which would be subject to stringent design, permitting, closure and corrective action requirements. Alternatively, coal ash would be regulated as non-hazardous waste under RCRA subtitle D, with national minimum criteria for disposal but no federal permitting or enforcement. Under both options, the EPA would establish dam safety requirements to address the structural integrity of surface impoundments to prevent catastrophic releases. The EPA is expected to issue a final decision during 2012. 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.”

 

Coke. A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel. Its production results in a number of useful byproducts.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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.

 

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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.

 

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

 

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

 

A number of legal actions are pending relating to past safety conditions at former Massey mines, the April 2010 explosion at the Upper Big Branch mine, which we refer to as the UBB explosion, and other related matters, including accusations of securities fraud. Although in December 2011, we entered into a Non-Prosecution Agreement and settlement resolving a number of these matters in which we agreed to various measures and commitments totaling approximately $209 million (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 two purported class actions that allege violations of the federal securities laws, derivative actions against current and former Massey directors and officers and actions brought by certain of the families of the twenty-nine miners that died in the UBB explosion and certain employees and contractors alleging injuries as a result of the UBB explosion.

 

In addition, two former Massey employees have been convicted of federal criminal charges and one former Massey employee, who was hired by a subsidiary of the Company following the Massey Acquisition and has since been placed on administrative leave, has been charged with a federal criminal conspiracy. Massey’s former officers, directors and employees may continue to be subject to future actions and claims. Under the Merger Agreement, we agreed to leave in place and not to modify those provisions granting 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 contained in the organizational documents of Massey and its subsidiaries and certain related indemnification agreements.

 

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.

 

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

 

Steam coal accounted for approximately 82% and 86% of our coal sales volume during 2011 and 2010, respectively. The majority of our sales of steam coal were to U.S. and Canadian electric power generators. The amount of coal consumed for U.S. and Canadian electric power generation is affected primarily by the overall demand for electricity, the location, availability, quality and price of competing fuels for power such as natural gas, nuclear fuel, oil and alternative energy sources such as hydroelectric power, technological developments, and environmental and other governmental regulations. We expect many new power plants will be built to produce electricity during peak periods of demand, when the demand for electricity rises above the “base load demand,” or minimum amount of electricity required if consumption occurred at a steady rate. However, we also expect that many of these new power plants will be fired by natural gas because they are cheaper to construct than coal-fired plants and because natural gas is a cleaner burning fuel with plentiful supplies and low cost at the current time. In addition, the increasingly stringent requirements of the Clean Air Act may result in more electric power generators shifting from coal to natural gas-fired power plants. These factors contributed to our recent decision to reduce coal production at certain mines in the Central Appalachia region. Any further reduction in the amount of coal consumed by North American electric power generators could further reduce the price of steam coal that we mine and sell, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

 

We produce metallurgical coal that is used in both the U.S. and foreign steel industries. Metallurgical coal accounted for approximately 18% and 14% of our coal sales volume during 2011 and 2010, respectively.  Any deterioration in conditions in the U.S. steel industry would reduce the demand for our metallurgical coal and could impact the collectability of our accounts receivable from U.S. steel industry customers. In addition, the U.S. steel industry increasingly relies on electric arc furnaces or pulverized coal processes to make steel. These processes do not use coke. If this trend continues, the amount of metallurgical coal that we sell and the prices that we receive for it could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves. If the demand and pricing for metallurgical coal in international markets decreases in the future, the amount of metallurgical coal that we sell and the prices that we receive for it could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

 

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

 

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

 

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·                  air emission standards for coal-fired power plants;

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

·                  the demand for electricity;

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

·                  interruptions due to transportation delays;

·                  domestic and foreign governmental regulations and taxes;

·                  regulatory, administrative, and judicial decisions;

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

·                  the effect of worldwide energy conservation measures; and

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

 

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

 

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

 

Our operations are subject to a variety of federal, state and local environmental, health and safety, transportation, labor and other laws and regulations. Examples include those relating to employee health and safety; emissions to air and discharges to water; plant and wildlife protection; the reclamation and restoration of properties after mining or other activity has been completed; the storage, treatment and disposal of wastes; remediation of contaminated soil, surface and groundwater; surface subsidence from underground mining; noise; and the effects of operations on surface water and groundwater quality and availability. In addition, we are subject to significant legislation mandating certain benefits for current and retired coal miners. We incur substantial costs to comply with the laws and regulations that apply to our mining and other operations. 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.

 

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

 

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

 

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

 

In recent years, the permitting required for coal mining, particularly under the Surface Mining Control and Reclamation Act and the Clean Water Act to address filling ephemeral and intermittent streams and other valleys with materials from mountaintop coal mining operations and preparation plant refuse disposal has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups against coal mining companies and environmental regulatory authorities. Congress has also considered legislation to impose additional limitations on surface mining. It is unclear at this time how the issues will ultimately be resolved, but for this as well as other issues that may arise involving permits necessary for coal mining and other operation, such requirements could prove costly and time-consuming, and could delay commencing or continuing exploration or production operations. New laws and regulations, as well as future

 

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interpretations or different enforcement of existing laws and regulations, may require substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which we cannot predict.

 

Extensive regulation of these matters has had and will continue to have a significant effect on our costs of production and competitive position. Further legislation, regulations or enforcement may also cause our sales or profitability to decline by hindering our ability to continue our mining operations, by increasing our costs or by causing coal to become a less attractive fuel source. See Item 1 “Business—Environmental and Other Regulatory Matters.”

 

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

 

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

 

Considerable and increasing government attention in the United States and other countries is being paid to reducing 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 GHG, 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.  Any international GHG agreement in which the United States participates, if at all, could adversely affect the price and demand for coal.

 

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

 

Considerable uncertainty is associated with these climate change initiatives. The content of new treaties, legislation or regulation is not yet determined, and many of the new regulatory initiatives remain subject to review by the agencies or the courts. Predicting the economic effects of climate change legislation is difficult given the various alternatives proposed and the complexities of the interactions between economic and environmental issues. Any regulations on GHG emissions, however, are likely to impose significant emissions control expenditures on many coal-fired power plants and industrial boilers and could have the effect of making them unprofitable. As a result, these generators may switch to other fuels that generate less of these emissions, possibly reducing future demand for coal and the construction of coal-fired power plants. In this regard, many of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use to comply with applicable ambient air quality standards. Any switching of fuel sources away from coal, closure of existing coal-fired plants, or reduced construction of new plants could have a material adverse effect on demand for and prices received for our coal and a material adverse effect on our results of operations, cash flows and financial condition. In addition, if regulation of 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 extensive environmental regulations also could affect our customers and could reduce the demand for coal as a fuel source and cause our sales to decline.

 

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

 

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In particular, the Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. See Item 1 “Business—Environmental and Other Regulatory Matters.” A series of more stringent requirements are expected to become effective in coming years. These requirements include implementation of the current and more stringent proposed ambient air quality standards for particulate matter and ozone, the EPA’s projected rule to limit emissions of mercury and other hazardous air pollutants from power plants, and implementation of the EPA’s final Cross-State Air Pollution Transport Rule (the “Rule”) issued in July 2011 to further control nitrogen oxides and sulfur dioxide emissions from power plants in 27 eastern states (including Texas). The EPA estimates that the Rule will impose a 54 percent reduction in nitrogen oxides emissions and a 73 percent reduction in sulfur dioxide emissions from 2005 levels in the covered states. The Rule includes an interstate emissions allowance trading approach and would be phased in during 2012 and 2014; however, the Rule currently is subject to a stay pending judicial review. Further, in December 2011, the EPA issued its final Mercury and Air Toxics Standards that would impose stringent limits on emissions of mercury and other hazardous air pollutants from power plants.

 

Such new regulations may require significant emissions control expenditures for coal-fired power plants and therefore could increase the costs of coal use by our customers. Any switching of fuel sources away from coal because of increased costs of coal use or other reasons, closure of existing coal-fired plants, or reduced construction of new plants could have a material effect on demand for and prices received for our coal, which could adversely affect our financial condition, results of operations and cash flows.

 

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

 

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

 

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

 

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

 

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

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

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

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

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

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

·                  accidental mine water discharges;

·                  coal slurry releases and impoundment failures;

·                  the unavailability of qualified labor;

·                  strikes and other labor-related interruptions; and

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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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. When there is increased demand in the marketplace for coal or certain types of coal, the prices for such coal increases. In such circumstances, any resulting overcapacity could reduce coal prices and therefore reduce our revenues.

 

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

 

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

 

We also compete in international markets against coal produced in other countries. Measured by tons sold, exports accounted for approximately 15% and 11% of our sales in 2011 and 2010, respectively. The demand for U.S. coal exports is dependent upon a number of factors outside of our control, including the overall demand for electricity in foreign markets, currency exchange rates, the demand for foreign-produced steel both in foreign markets and in the U.S. market (which is dependent in part on tariff rates on steel), general economic conditions in foreign countries, technological developments, and environmental and other governmental regulations. For example, if the value of the U.S. dollar were to rise against other currencies in the future, our coal would become relatively more expensive and less competitive in international markets, which could reduce our foreign sales and negatively impact our revenues and net income. In addition, if the amount of coal exported from the United States were to decline, this decline could cause competition among coal producers in the United States to intensify, potentially resulting in additional downward pressure on domestic coal prices.

 

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

 

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

 

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

 

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

 

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

 

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

 

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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.

 

We contribute to a multi-employer defined benefit pension plan (the “Plan”) administered by the UMWA. In 2011, our total contributions to the Plan and other contractual payments under our UMWA wage agreement were approximately $18.9 million.

 

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

 

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

 

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

 

We sponsor defined benefit pension plans in the United States for certain salaried and non-union hourly employees. For these plans, for 2011, 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 such plan with a funding ratio of less than 80% will be deemed at risk and will be subject to even higher funding requirements under the PPA. In addition, the value of existing assets held in our pension trust is affected by changes in the economic environment. As a result, we may be required to make significant cash contributions into the pension trust in order to comply with the funding requirements of the PPA. In 2011 we contributed $70.4 million to our pension plans. We currently expect to make contributions in 2012 in the range of $25.0 million to $30.0 million for our defined benefit retirement plans to maintain at least an 80% funding ratio.

 

As of December 31, 2011, our annual measurement date, our salaried and hourly pension plans were underfunded by $174.7 million. These pension plans are subject to the Employee Retirement Income Security Act of 1974 (“ERISA”). Under ERISA, the Pension Benefit Guaranty Corporation, (“PBGC”), has the authority to terminate an underfunded pension plan under limited circumstances. In the event our U.S. pension plans are terminated for any reason while the plans are underfunded, we may incur a liability to the PBGC that could exceed the entire amount of the underfunding.

 

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.

 

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

 

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

 

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

 

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The healthcare benefits that we provide to our represented employees and retirees are stipulated by law and by labor agreements. Healthcare benefit changes required by the healthcare legislation will be included in any new labor agreements. Beginning in 2018, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of this excise tax. We currently have $35.2 million accrued as of December 31, 2011 for the estimated impact of the PPACA included in our retiree welfare plan obligation. We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of this excise tax. We will need to continue to evaluate the impact of the PPACA in future periods, and when these regulations or interpretations are published, we will evaluate its assumptions in light of the new information.

 

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

 

Approximately 90% of our 2011 coal production came from mines operated by union-free employees. As of December 31, 2011, approximately 90% of our workforce is union-free. However, employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. Any further unionization of our employees, or the employees of third-party contractors who mine coal for us, could adversely affect the stability of our production and reduce our profitability.

 

Two of our Pennsylvania subsidiaries have separate wage agreements with the UMWA. New wage agreements were negotiated in July 2011 that cover 1,116 employees (563 and 553 employees, respectively) and will expire on December 31, 2016. Additionally, there is an agreement between Emerald Coal Resources, LP (“Emerald”) and the UMWA on behalf of the five employees working at the warehouse for Emerald, which was renewed during 2011 and will also expire in December 2016. Another Pennsylvania subsidiary has a wage agreement with the International Brotherhood of Electrical Workers (“IBEW”) covering six employees. This agreement expires in August 2013.

 

One of our Virginia subsidiaries has two contracts with the UMWA that cover 135 employees.  Two new collective bargaining agreements were ratified by those covered employees in May 2010.  Those agreements will expire in December 2014.

 

One of our West Virginia subsidiaries has a wage agreement with the UMWA, covering 19 employees that was re-negotiated during 2011 and will expire on December 31, 2016. Also, another West Virginia subsidiary, which is idle, has a wage agreement with the UMWA that could be terminated by our subsidiary or the UMWA with notice but since it is idle, no employees are affected at this time. However, if the operation becomes active again, these employees could be affected.

 

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

 

Massey had four West Virginia subsidiaries and one Kentucky subsidiary with expired wage agreements with the UMWA at the time of the Massey Acquisition. Since the Massey Acquisition, new wage agreements have been negotiated at each of those subsidiaries. The new agreements with the Goals and Omar subsidiaries in West Virginia and the Long Fork subsidiary in Kentucky cover 40 employees (15, 11 and 14, respectively) and will expire in December 2016. Two other wage agreements covering 50 employees at the Bandmill and Power Mountain subsidiaries (30 and 20 employees, respectively) will expire on June 30, 2017.

 

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

 

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

 

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

 

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

 

We continually seek to expand our operations and coal reserves through acquisitions, and 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 significant acquisitions and several smaller acquisitions and investments. Our ability to complete acquisitions 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.

 

Following an acquisition, there can be no assurance that we will be able to manage effectively the integration of the acquired company, business or properties and the resulting expansion of our operations or that our current personnel, systems, procedures and controls will be adequate to support our expanded operations. If we are unable to successfully integrate the companies, businesses or properties that we acquire, our profitability may decline and we could experience a material adverse effect on our business, financial condition or results of operations. Acquisition transactions, including the Massey Acquisition, involve various inherent risks, including:

 

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

 

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

 

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

 

·                                          problems that could arise from the integration of the acquired business, including coordinating management and personnel, managing different corporate cultures and applying our internal control processes to the acquired business; and

 

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

 

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

 

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

 

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

 

We sell a significant portion of our coal under long-term coal supply agreements, which are contracts with a term greater than 12 months. The execution of a satisfactory long-term coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract. During 2011, approximately 50% and 81% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts. At December 31, 2011, our long-term coal supply agreements had remaining terms of up to 14 years and an average remaining term of approximately three years. When our current contracts with customers expire or are otherwise renegotiated, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including pricing terms less favorable to us.

 

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As of February 8, 2012, 7% of our planned shipments for 2012 and approximately 49% of our planned shipments for 2013 were uncommitted. We may not be able to enter into coal supply agreements to sell this production on terms, including pricing terms, as favorable to us as our existing agreements.

 

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

 

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

 

Price adjustment, “price reopener” and other similar provisions in long-term supply contracts may reduce the protection from short-term coal price volatility traditionally provided by these contracts. Price reopener provisions are particularly common in international metallurgical coal sales contracts. Some of our coal supply contracts contain provisions that allow for the price to be renegotiated at periodic intervals. Generally, price reopener provisions require the parties to agree on a new price based on the prevailing market price, however, some contracts provide that the new price is set between a pre-set “floor” and “ceiling.” In some circumstances, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract or litigation, the outcome of which is uncertain.  In other circumstances when the economy is weak, some of our customers may experience lower demand for their products and services and may be unwilling to take all of their contracted tonnage or request a lower price.  Customers may make similar requests when market prices have dropped significantly, as has occurred recently.  Any adjustment or renegotiation leading to a significantly lower contract price could result in decreased revenues. Accordingly, supply contracts with terms of one year or more may provide only limited protection during adverse market conditions.

 

Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during specified events beyond the control of the affected party. Following the UBB explosion, Massey notified certain of its customers that it was declaring force majeure under certain of its sales contracts impacted by the lost tonnage resulting from the explosion and subsequent shutdown at the Upper Big Branch mine. It is possible that certain of these customers may ultimately challenge the declaration of force majeure or contest whether they received timely or proper allocations or amounts of coal following the declaration of force majeure. 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. In addition, some of these contracts allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that increase the price of coal or the cost of burning coal beyond specified limits.

 

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

 

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

 

Our largest customer during 2011 accounted for approximately 9% of our total revenues. We derived approximately 41% of our 2011 total revenues from sales to our ten largest customers. These customers may not continue to purchase coal from us under our current coal supply agreements, or at all. If these customers were to reduce their purchases of coal from us significantly or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our revenues and profitability could suffer materially.

 

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

 

Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on the prevailing conditions in the metallurgical and steam coal markets. We decide whether to mine, process and market these coals as metallurgical or steam coal based on management’s assessment as to which market is likely to provide us with a higher margin. We consider a number of factors when making this assessment, including the difference between the current and anticipated future market prices of steam coal and metallurgical coal, the lower volume of saleable tons that results from producing a given

 

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quantity of reserves for sale in the metallurgical market instead of the steam market, the increased costs incurred in producing coal for sale in the metallurgical market instead of the steam market, the likelihood of being able to secure a longer-term sales commitment by selling coal into the steam market and our contractual commitments to deliver different types of coals to our customers. A decline in the metallurgical market relative to the steam market could cause us to shift coal from the metallurgical market to the steam market, thereby reducing our revenues and profitability.

 

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

 

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

 

In addition to marketing coal that is produced by our subsidiaries’ employees, we utilize contractors to operate some of our mines. Operational difficulties at contractor-operated mines, changes in demand for contract miners from other coal producers, and other factors beyond our control could affect the availability, pricing, and quality of coal produced for us by contractors. The majority of the coal that we purchase from third parties is blended with coal produced from our mines prior to resale, and we also process (which includes washing, crushing or blending coal at our preparation plants or loading facilities) a portion of the coal that we purchase from third parties prior to resale. We sold 4.7 million tons of coal purchased from third parties during 2011, representing approximately 4% of our total coal sales volume during 2011. Approximately 86% of our purchased coal sales volume in 2011 was blended with coal produced from our mines prior to resale, and approximately 1% of our total coal sales volume in 2011 consisted of coal purchased from third parties that we processed before resale. The availability of specified qualities of this purchased coal may decrease and prices may increase as a result of, among other things, changes in overall coal supply and demand levels, consolidation in the coal industry and new laws or regulations. Disruption in our supply of contractor-produced coal and purchased coal could temporarily impair our ability to fill our customers’ orders or require us to pay higher prices in order to obtain the required coal from other sources. Any increase in the prices we pay for contractor-produced coal or purchased coal could increase our costs and therefore lower our earnings.

 

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

 

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base is changing with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear on payment default. These new power plant owners may have credit ratings that are below investment grade. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default.  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 44% and 34% of our total revenues from coal sales made to customers outside the United States in 2011 and 2010, respectively.

 

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

 

Downturns in the economy and disruptions in the global financial markets in recent years have affected the creditworthiness of our customers from time to time. The extreme market disruption in 2008, among other things, severely limited liquidity and credit availability. Recent concerns about the debt burden of certain Eurozone countries and the overall stability of the euro could adversely affect the creditworthiness of our customers in those countries.  If the current economic conditions worsen or a prolonged global, national or regional economic recession or other similar event occurs, it is likely to significantly impact the creditworthiness of our customers and could increase the risk we bear on payment default.

 

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

 

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

 

We depend upon railroads, trucks, beltlines, ocean vessels and barges to deliver coal to our customers. Disruption of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, terrorist attacks, and other events could temporarily impair our ability to supply coal to our customers, resulting in decreased shipments.  Decreased shipment performance levels over

 

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longer periods of time could cause our customers to look to other sources for their coal needs, negatively affecting our revenues and profitability.

 

In 2011, 75% of our produced and processed coal volume was transported from the load-out or preparation plant to the customer by rail. From time to time in the past, we have experienced deterioration in the reliability of the service provided by rail carriers, which increased our internal coal handling costs. If there is future deterioration of the transportation services provided by the railroad companies we use and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

 

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

 

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

 

Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives and liquid fuels, such as diesel fuel. Some commodities, such as steel, are needed to comply with roof control plans required by regulation. Our operations are dependent on reliable supplies of mining equipment, replacement parts, explosives, diesel fuel, tires, magnetite and steel-related products (including roof bolts). If the cost of any mining equipment or key supplies increases significantly, or if they should become unavailable due to higher industry-wide demand or less production by suppliers, there could be an adverse impact on our cash flows, results of operations or financial condition. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, which has resulted in a situation where we have a limited number of suppliers for certain types of equipment and supplies. In recent years, mining industry demand growth has exceeded supply growth for certain surface and underground mining equipment and heavy equipment tires. As a result, lead times for certain items have generally increased.

 

In addition, the prices we pay for these products are strongly impacted by the global commodities market. A rapid or significant increase in cost of these commodities could impact our mining costs because we have limited ability to negotiate lower prices, and, in some cases, do not have a ready substitute for these commodities.

 

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

 

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

 

We also have outstanding debt that includes a variable interest rate component. We entered into an interest rate swap to reduce the risk that changing interest rates could have on our operations. The swap initially qualified for cash flow hedge accounting and changes in fair value were recorded as a component of equity; however, the debt instrument was subsequently paid and the swap no longer qualified for cash flow hedge accounting. Subsequent changes in fair value of the interest rate swap are recorded in earnings. See Note 15 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

 

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

 

We enter into hedging arrangements, primarily financial swap contracts, for a portion of our anticipated diesel fuel and explosive needs.  As of December 31, 2011, we had financial swap contracts to fix approximately 59% and 34% of our calendar year 2012 and 2013 expected diesel fuel needs, respectively, and 34% of our calendar year 2012 expected explosive needs.  While our hedging strategy provides us protection in the event of price increases to our diesel fuel and explosives, it may also prevent us from the benefits of price decreases.  If prices for diesel fuel and explosives decreased significantly below our swap prices, it could have a material effect on our financial condition, the result of operations and cash flows.

 

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

 

Our profitability depends substantially on our ability to mine coal reserves possessing quality characteristics desired by our customers in a cost-effective manner. As of December 31, 2011, we owned or leased 4.7 billion tons of proven and probable coal reserves that we believe will support current production levels for more than 20 years. We have not yet applied for the permits required, or developed the mines necessary, to mine all of our reserves. Permits are becoming increasingly more difficult and expensive to obtain and the review process continues to lengthen. In addition, we may not be able to mine all of our reserves as profitably as we do at our current operations.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

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

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

 

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

 

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

 

The SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as deep mining. We accrue for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our experience and total $915.7 million as of December 31, 2011. The amounts recorded are dependent upon a number of variables, including the estimated future asset retirement costs, estimated proven reserves, assumptions involving profit margins of third party contractors, inflation rates, 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.

 

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

 

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

 

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

 

We are responsible for certain long-term liabilities under a variety of benefit plans and other arrangements with active and inactive employees. The unfunded status (the excess of projected benefit obligation over plan assets) of these obligations as of December 31, 2011, as reflected in Note 17 to our Consolidated Financial Statements, included $1,079.4 million of postretirement obligations, $174.7 million of defined benefit pension and supplemental employee retirement plan obligations, $187.6 million of self-insured workers’ compensation obligations and $157.5 million of self-insured black lung obligations. These obligations have been estimated based on assumptions including actuarial estimates, discount rates, estimates of mine lives, expected returns on pension plan assets and changes in health care costs. We could be required to expend greater amounts than anticipated. In addition, future regulatory and accounting changes relating to these benefits could result in increased obligations or additional costs, which could also have a material adverse effect on our financial results. Several states in which we operate consider changes in workers’ compensation laws from time to time, which, if enacted, could adversely affect us.

 

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.

 

The inability of companies to fulfill their indemnification obligations to us under certain agreements with us could increase our liabilities and adversely affect our results of operations and financial position.

 

In the acquisition agreements entered into with the sellers of the companies that we have acquired (including Coastal Coal Company, Nicewonder and Progress), and the acquisition or other agreements that companies we have acquired entered into prior to our acquisition, such as the Distribution Agreement entered into by Massey and Fluor as of November 30, 2000 in connection with the spin-off of Fluor by Massey (the “Distribution Agreement”), the respective sellers and, in some cases, their parent companies or other parties, agreed to retain responsibility for and indemnify Alpha against damages resulting from certain third-party claims or other liabilities, such as workers’ compensation liabilities, black lung liabilities, postretirement medical liabilities and certain environmental or mine safety liabilities. The obligations of the sellers and other parties, as applicable, to indemnify us with respect to their retained liabilities will continue for a substantial period of time, and in some cases indefinitely. In other cases, the sellers’ indemnification obligations continue for a shorter period of time, for example with respect to breaches of their representations and warranties in the acquisition agreements terminate upon expiration of the applicable indemnification period (generally 18-24 months from the acquisition date for most representations and warranties, and from two to five years from the acquisition date for environmental representations and warranties).  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.

 

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Recently, litigation has been commenced between Fluor and the purchasers of Fluor’s prior business (the “Prior Business”) regarding the purchasers’ obligation to indemnify Fluor against claims and judgment arising out of the Prior 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.”

 

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 annually to determine if it is impaired or 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 the testing performed 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.

 

Following our annual goodwill impairment testing performed at October 31, 2011, we recorded impairment charges of $745.3 million during the year ended December 31, 2011 to reduce the carrying value of goodwill to its implied fair value for four of our reporting units in 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 for these or other reporting units.  These charges could be significant, which could have a material adverse effect on our business, results of operations or financial condition.

 

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

 

A large percentage of our road construction revenues and contract backlog is typically derived from fixed unit price contracts. Fixed unit price contracts require us to perform the contract for a fixed unit price irrespective of our actual costs. As a result, we realize a profit on these contracts only if we successfully estimate our costs and then successfully control actual costs and avoid cost overruns. If our cost estimates for a contract are inaccurate, or if we do not execute the contract within our cost estimates, then cost overruns may cause us to incur losses or cause the contract not to be as profitable as we expected. Also, if we do not recover the amounts of coal estimated on our construction projects, profitability on our construction contracts could be less than projected. This, in turn, could negatively affect our cash flow, earnings and financial position. During 2011, we recorded an additional loss of approximately $12.2 million due to a change in estimated costs to complete the current project.

 

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

 

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

·                  delays caused by weather conditions;

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

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

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

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

·                  our suppliers’ or subcontractors’ failure to perform;

·                  mechanical problems with our machinery or equipment;

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

·                  difficulties in obtaining required governmental permits or approvals;

·                  changes in applicable laws and regulations; and

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

 

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

 

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

 

As of December 31, 2011, there were:

 

·                  1,149,266 shares of common stock issuable upon the exercise of stock options with a weighted-average exercise price of $21.92; and

·                  2,836,566 restricted share unit awards issued to directors, officers and key employees to be converted to common stock upon the satisfaction of future service and performance conditions (assuming performance at the maximum level).

 

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

 

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

 

In recent years, downturns in the economy 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

 

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and declining valuations of others, including real estate. This occurred in particular 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 products and the restructuring of agreements with certain of our coal customers. Any prolonged global, national or regional economic recession or other similar events could have a material adverse effect on the demand for coal and on our sales, margins, and profitability. We are unable to predict the timing, duration and severity of potential future disruptions in financial markets and potential future adverse economic conditions in the U.S. and other countries and the impact these events may have on our operations and the industry in general.

 

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

 

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

 

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

 

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition, and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may materially adversely affect our operations and those of our customers. As a result, there could be delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. Our business may also be impacted by disruptions, including cybersecurity attacks or failures, threats to physical security, extreme weather conditions or other natural disasters and pandemics or other public health crises. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

 

Provisions in our certificate of incorporation and bylaws and the indentures governing our notes may discourage a takeover attempt even if doing so might be beneficial to our stockholders.

 

Provisions contained in our certificate of incorporation and bylaws could impose impediments to the ability of a third party to acquire us even if a change of control would be beneficial to our stockholders. Provisions of our certificate of incorporation and bylaws impose various procedural and other requirements, which could make it more difficult for stockholders to effect certain corporate actions. For example, our certificate of incorporation authorizes our board of directors to determine the rights, preferences, privileges and restrictions of unissued series of preferred stock, without any vote or action by our stockholders. Thus, our board of directors can authorize and issue shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of our common stock. These 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.

 

We may fail to realize revenue growth and the cost savings estimated as a result of the Massey Acquisition.

 

The ultimate success of the Massey Acquisition will depend, in part, on our ability to continue to realize the anticipated synergies, business opportunities and growth prospects from combining the businesses of Alpha and Massey. We may never realize these anticipated synergies, business opportunities and growth prospects. Integrating operations will be complex and will require significant efforts and expenditures. Employees might leave or be terminated because of the Massey Acquisition. Our management might have its attention diverted while trying to integrate operations and corporate and administrative infrastructures. We might experience increased competition that limits our ability to expand our business, and we might not be able to capitalize on expected business opportunities, including retaining current customers. Our management may be unable to manage successfully our exposure to pending and potential litigation. We may

 

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be required by regulators to undertake certain remedial measures as a result of claims and investigations arising from the UBB explosion, and our management may not be able to implement those and other remedial measures successfully. We may experience difficulties integrating Massey’s system of financial reporting. We are permitted to exclude the operations of Massey from our management certification and auditor attestation regarding the effectiveness of our internal control over financial reporting as of December 31, 2011, so that our first certification of the effectiveness of our internal control over financial reporting may be as of December 31, 2012. We may experience difficulties in applying our Running Right program at legacy Massey mines and facilities. Moreover, assumptions underlying estimates of expected cost savings as a result of the Massey Acquisition may be inaccurate, and general industry and business conditions might deteriorate. If any of these factors limit our ability to integrate the operations of Alpha and Massey successfully or on a timely basis, the expectations of future results of operations, including certain cost savings and synergies expected to result from the Massey Acquisition, might not be met.

 

Our success will also depend on the integration into our operations of Cumberland, which Massey acquired on April 19, 2010. Massey’s integration of Cumberland’s operations was still ongoing at the time of the Massey Acquisition, and we are currently involved in integrating Cumberland’s operations with our operations and those of Massey. This integration is subject to risks similar to those described above related to the integration of Massey and other acquisitions under “Acquisitions that we have completed since our formation, as well as the Massey Acquisition and other acquisitions that we may undertake in the future, involve a number of risks, any of which could cause us not to realize the anticipated benefits.” As a result of those risks, we may fail to realize the benefits of Massey’s acquisition of Cumberland. In particular, prior to its acquisition by Massey, Cumberland was a private company and was not required to comply with many requirements applicable to U.S. public companies, including the documentation and assessment of the effectiveness of its internal control over financial reporting. Establishing, testing and maintaining an effective system of internal control over financial reporting of the merged entity will require significant resources and time commitments on the part of our management and our finance and accounting staff, may require additional staffing and infrastructure investments, could increase our legal, insurance and financial compliance costs and may divert the attention of management. Moreover, if we discover aspects of Cumberland’s internal control over financial reporting that require improvement, we cannot be certain that our remedial measures will be effective. Any failure to implement required new or improved controls, or difficulties encountered in their implementation could adversely affect our financial and operating results, investor’s confidence or increase our risk of material weaknesses in internal control over financial reporting.

 

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

 

Our substantial indebtedness exposes us to various risks.

 

At December 31, 2011, we had $3,054.7 million of indebtedness outstanding before discounts applied for financial reporting, representing 27% of our total capitalization. In addition, at December 31, 2011, we had $0.3 million of letters of credit outstanding under our credit facility and $160.0 million of letters of credit outstanding under our accounts receivable securitization facility.

 

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

 

·                                          make it more difficult for us to pay or refinance our debts, including the notes, 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;

 

·                                          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 cash to fund working capital and 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 the Amended and Restated Credit Agreement, will be at variable rates of interest;

 

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

 

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

 

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·                                          result in a downgrade in the credit rating of our indebtedness which could increase the cost of further borrowings.

 

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful, and repayment of our indebtedness is dependent to a significant extent on cash flow generated by our subsidiaries and their ability to make distributions to us.

 

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance our indebtedness. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such 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.

 

In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness and result in more restrictive borrowing terms, including increased borrowing costs and more restrictive covenants. This, in turn, could affect our internal cost of capital estimates and therefore impact operational and investment decisions.

 

We will be dependent to a significant extent on the generation of cash flow by our subsidiaries and their ability to make such 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 also be able to incur substantially more debt which could further exacerbate the risks associated with our significant indebtedness.

 

We may be able to incur substantial additional indebtedness in the future under the terms of our credit facility and the indentures governing our debt securities. Our credit facility provides for a revolving line of credit of up to $1.0 billion, with no borrowings outstanding as of December 31, 2011. The addition of new debt to our current debt levels could increase the related risks that we now face. For example, the spread over the variable interest rate applicable to loans under our revolving line of credit is dependent on our leverage ratio, and it would increase if our leverage ratio increases. Additional drawings under our revolving line of credit could also limit the amount available for letters of credit in support of our bonding obligations, which we will require as we develop and acquire new mines.

 

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

 

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

 

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

 

At December 31, 2011, we had $160.3 million of letters of credit in place, of which $0.3 million was outstanding under our credit facility and $160.0 million was outstanding under our accounts receivable securitization facility. These outstanding letters of credit supported workers’ compensation bonds, coal mining reclamation obligations, UMWA retiree health care obligations, and other miscellaneous obligations. Our

 

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credit facility provides for revolving commitments of up to $1.0 billion, all of which can be used to issue letters of credit, and our accounts receivable securitization facility provides for the issuance of up to $275.0 million in letters of credit. Obligations secured by letters of credit may increase in the future. Any such increase would limit our available borrowing capacity under our current or future credit facilities and could negatively impact our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements. Moreover, if we do not maintain sufficient borrowing capacity under our revolving credit facility and accounts receivable securitization facility for additional letters of credit, we may be unable to provide financial assurance for our mining operations.

 

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. Our failure to repurchase such notes upon a change of control would cause a default under the indentures governing such notes and a cross default under our credit facility. Our credit facility also provides that a change of control will be an event of default that permits lenders to accelerate the maturity of certain borrowings thereunder. Any of our future debt agreements may contain similar provisions. If a change of control were to occur, it cannot be assured that we would have sufficient funds to purchase our various series of notes, or any other securities that we would be required to offer to purchase. We may require additional financing from third parties to fund any such purchases, but it cannot be assured that we would be able to obtain such financing. In addition, if we experience a change of control (as defined for purposes of our credit facility), resulting in an event of default under our credit facility we may not be able to replace our credit facility on terms equal to or more favorable than the current terms if the commitments are terminated and the loans are repaid under our credit facility upon an event of default.

 

Item 1B. Unresolved Staff Comments

 

None.

 

Item 2. Properties

 

Coal Reserves

 

“Reserves” are defined by the Securities and Exchange Commission (“SEC”) Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. “Proven (Measured) Reserves” are defined by SEC Industry Guide 7 as reserves for which (1) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (2) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. “Probable reserves” are defined by SEC Industry Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

 

Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our internal engineers, geologists and finance associates, as well as third party consultants we retained. We periodically update our reserve estimates to reflect past coal production, new drilling information and other geological or mining data, and acquisitions or sales of coal properties. Coal tonnages are categorized according to coal quality, mining method, permit status, mineability and location relative to existing mines and infrastructure. Further scrutiny is applied using geological criteria and other factors related to profitable extraction of the coal. These criteria include seam height, roof and floor conditions, yield and marketability.

 

We periodically retain outside experts to independently verify our estimates of our coal reserves. Prior to Old Alpha’s initial public offering in 2005, in November 2004 a third party consultant was retained to perform reserve estimates.  Since November 2004, we have retained third party consultants to verify reserves for our major acquisitions, which include the Callaway, Progress Fuels, Mingo Logan Ben’s Creek Complex, Foundation and Massey acquisitions, as well as to conduct ongoing reserve updates, on an annual basis, for specific properties that have undergone substantial modification to the reserve base. Properties that have undergone insignificant or no changes since the original assessment in November 2004 have been carried forward without re-evaluation.  These reviews include the preparation of reserve maps and the development of estimates by certified professional geologists based on data supplied by us and 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.

 

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We estimate that, as of December 31, 2011, we owned or leased total proven and probable coal reserves of approximately 4,677.4 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 4,677.4 million tons, approximately 2,337.7 million tons were assigned reserves that we expect to be mined in future operations. Approximately 2,339.7 million tons were unassigned reserves that we are holding for future development. All of our reserves in Wyoming are assigned. As of December 31, 2011, we had unassigned reserves in our CAPP North, CAPP Central, and CAPP South regions of 239.8 million tons, 749.6 million tons, and 565.4 million tons, respectively, in addition to 687.5 million tons in our Pennsylvania Services business unit and 68.8 million tons in our AMFIRE business unit.  In addition, as of December 31, 2011, we had unassigned reserves at our inactive operation in Illinois of 28.6 million tons.

 

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) and are located throughout all of our regions with the exception of Alpha Coal West and our inactive operations in Illinois. Approximately 61% of our reserves have sulfur content of less than 1% and are located throughout all of our regions, with the exception of our inactive operation in Illinois.

 

As with most coal-producing companies that operate in Appalachia, which include our operations in CAPP North, CAPP Central, CAPP South, Pennsylvania Services and AMFIRE, 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, 2011, 722.8 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, 2011, of 3,185.8 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, 2011, 38.1 million tons of reserves are owned and require no royalty or per-ton payments. Our remaining Wyoming reserve holdings at December 31, 2011, of 702.1 million tons were leased and were subject to the terms described above.

 

Our idled mine in Illinois (“Wabash”) is subject to coal leases and requires payments of minimum royalties, payable in periodic installments. We expect to continue leasing these reserves until future development is feasible. Our reserve holdings attributable to Wabash at December 31, 2011 were 28.6 million tons.

 

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

 

The following table summarizes, by region, our proven and probable coal reserves as of December 31, 2011.

 

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Table of Contents

 

Reportable
Segment

 

Region/Business Unit

 

Location

 

Total Recoverable
Reserves Proven &
Probable 
(1)

 

Proven
Reserves

 

Probable
Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAPP North

 

 

 

 

 

 

 

 

 

East

 

Coal River Surface

 

West Virginia

 

175.3

 

134.7

 

40.6

 

East

 

Coal River East

 

West Virginia

 

328.3

 

229.8

 

98.5

 

East

 

Coal River West

 

West Virginia

 

189.6

 

134.8

 

54.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAPP Central

 

 

 

 

 

 

 

 

 

East

 

Brooks Run North

 

West Virginia

 

267.1

 

167.7

 

99.4

 

East

 

Brooks Run South

 

Virginia, West Virginia

 

275.1

 

157.7

 

117.4

 

East

 

Brooks Run West

 

West Virginia

 

694.3

 

378.2

 

316.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAPP South

 

 

 

 

 

 

 

 

 

East

 

Virginia

 

Virginia

 

419.4

 

320.0

 

99.4

 

East

 

Northern Kentucky

 

Kentucky

 

218.2

 

129.0

 

89.2

 

East

 

Southern Kentucky

 

Kentucky

 

389.0

 

280.0

 

109.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NAPP

 

 

 

 

 

 

 

 

 

East

 

Pennsylvania Services

 

Pennsylvania

 

852.9

 

510.5

 

342.4

 

East

 

AMFIRE

 

Pennsylvania

 

99.4

 

74.0

 

25.4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Powder River Basin

 

 

 

 

 

 

 

 

 

West

 

Alpha Coal West

 

Wyoming

 

740.2

 

729.5

 

10.7

 

 

 

Totals from active operations

 

 

 

4,648.8

 

3,245.9

 

1,402.9

 

 

 

Percentages from active operations

 

 

 

 

 

70

%

30

%

 

 

 

 

 

 

 

 

 

 

 

 

N/A

 

Wabash (4)

 

Illinois

 

28.6

 

20.6

 

8.0

 

 

 

Total from all operations

 

 

 

4,677.4

 

3,266.5

 

1,410.9

 

 

 

Percentage from all operations

 

 

 

 

 

70

%

30

%

 

The following table provides the “quality” (sulfur content and average Btu content per pound) of our proven and probable coal reserves as of December 31, 2011.

 

51



Table of Contents

 

 

 

 

 

 

 

Recoverable

 

Sulfur Content

 

Average BTU

 

Reportable
Segment

 

Region/Business Unit

 

Location

 

Reserves Proven
& Probable
(1)

 

<1%

 

1.0% - 1.5%

 

>1.5%

 

>12,500

 

<12,500

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAPP North

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

East

 

Coal River Surface

 

West Virginia

 

175.3

 

151.4

 

19.5

 

4.4

 

71.6

 

103.7

 

East

 

Coal River East

 

West Virginia

 

328.3

 

229.4

 

86.1

 

12.8

 

287.0

 

41.3

 

East

 

Coal River West

 

West Virginia

 

189.6

 

133.5

 

56.1

 

 

109.6

 

80.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAPP Central

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

East

 

Brooks Run North

 

West Virginia

 

267.1

 

191.0

 

53.1

 

23.0

 

175.8

 

91.3

 

East

 

Brooks Run South

 

Virginia, West Virginia

 

275.1

 

260.3

 

9.9

 

4.9

 

264.8

 

10.3

 

East

 

Brooks Run West

 

West Virginia

 

694.3

 

493.0

 

175.9

 

25.4

 

559.1

 

135.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAPP South

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

East

 

Virginia

 

Virginia

 

419.4

 

283.0

 

100.5

 

35.9

 

380.0

 

39.4

 

East

 

Northern Kentucky

 

Kentucky

 

218.2

 

88.6

 

84.7

 

44.9

 

188.6

 

29.6

 

East

 

Southern Kentucky

 

Kentucky

 

389.0

 

190.0

 

107.0

 

92.0

 

358.0

 

31.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NAPP

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

East

 

Pennsylvania Services

 

Pennsylvania

 

852.9

 

73.6

 

14.9

 

764.4

 

780.7

 

72.2

 

East

 

AMFIRE

 

Pennsylvania

 

99.4

 

34.6

 

31.4

 

33.4

 

72.2

 

27.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Powder River Basin

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

West

 

Alpha Coal West

 

Wyoming

 

740.2

 

740.2

 

 

 

 

740.2

 

 

 

Totals from active operations

 

 

 

4,648.8

 

2,868.6

 

739.1

 

1,041.1

 

3,247.4

 

1,401.4

 

 

 

Percentages from active operations

 

 

 

 

 

62

%

16

%

22

%

70

%

30

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

N/A

 

Wabash (4)

 

Illinois

 

28.6

 

 

 

28.6

 

 

28.6

 

 

 

Total from all operations

 

 

 

4,677.4

 

2,868.6

 

739.1

 

1,069.7

 

3,247.4

 

1,430.0

 

 

 

Percentage from all operations

 

 

 

 

 

61

%

16

%

23

%

69

%

31

%

 

The following table summarizes, by region, 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, 2011.

 

52



Table of Contents

 

 

 

 

 

 

 

Recoverable

 

 

 

 

 

 

 

Reportable

 

 

 

 

 

Reserves Proven 

 

Total Tons

 

Total Tons

 

 

 

Segment

 

Region/Business Unit

 

Location

 

& Probable (1)

 

Assigned (2)

 

Unassigned (2)

 

Owned

 

Leased

 

Coal Type (3)

 

 

 

 

 

 

 

(In millions of tons)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAPP North

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

East

 

Coal River Surface

 

West Virginia

 

175.3

 

151.3

 

24.0

 

22.8

 

152.5

 

Steam and Metallurgical

 

East

 

Coal River East

 

West Virginia

 

328.3

 

151.9

 

176.4

 

39.1

 

289.2

 

Steam and Metallurgical

 

East

 

Coal River West

 

West Virginia

 

189.6

 

150.2

 

39.4

 

32.5

 

157.1

 

Steam and Metallurgical