Alpha Natural Resources, Inc.
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
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.
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.
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
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.
(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:
(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.
(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.
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
(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
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.
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.
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.
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:
(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:
(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,
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.
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.
ENVIRONMENTAL AND OTHER REGULATORY MATTERS
Federal, state and local authorities regulate the United States coal mining and oil and gas industries with respect to matters such as: employee health and safety; permitting and licensing requirements; emissions to air and discharges to water; plant and wildlife protection; the reclamation and restoration of properties after mining or other activity has been completed; the storage, treatment and disposal of wastes; remediation of contaminated soil; protection of surface and groundwater; surface subsidence from underground mining; the effects on surface and groundwater quality and availability; noise; dust and competing uses of adjacent, overlying or underlying lands such as for oil and gas activity, pipelines, roads and public facilities. Ordinances, regulations and legislation (and judicial or agency interpretations thereof) with respect to these matters have had, and will continue to have, a significant effect on our production costs and our competitive position. New laws and regulations, as well as future interpretations or different enforcement of existing laws and regulations, may require substantial increases in equipment and operating costs and may cause delays, interruptions, or a termination of operations, the extent of which we cannot predict. We intend to respond to these regulatory requirements and interpretations thereof at the appropriate time by implementing necessary modifications to facilities or operating procedures or plans. When appropriate, we may also challenge actions in regulatory or court proceedings. Future legislation, regulations, interpretations or enforcement may also cause coal to become a less attractive fuel source for our customers due to factors such as investments in pollution control equipment necessary to meet new and more stringent air, water or solid waste requirements. Similarly, coal may become a less attractive fuel source for our customers if federal, state or local emissions rates or caps on greenhouse gases are enacted, or a tax on carbon is imposed, such as those that may result from climate change legislation or regulations. As a result, future legislation, regulations, interpretations or enforcement may adversely affect our mining or other operations, or our cost structure or may adversely impact the ability or economic desire of our customers to use coal.
We endeavor to conduct our mining and other operations in compliance with all applicable federal, state, and local laws and regulations. However, due in part to the extensive and comprehensive regulatory requirements, violations occur from time to time. It is possible that future liability under or compliance with environmental and safety requirements could have a material effect on our operations or competitive position. Under some circumstances, substantial fines and penalties, including revocation or suspension of mining or other permits or plans, may be imposed under the laws described below. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.
Mine Safety and Health
The Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act of 1977 impose stringent safety and health standards on all aspects of mining operations. Also, the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps one of the most comprehensive and pervasive systems for protection of employee health and safety affecting any segment of U.S. industry. Regulation has a significant effect on our operating costs.
In recent years, legislative and regulatory bodies at the state and federal levels, including MSHA, have promulgated or proposed various statutes, regulations and policies relating to mine safety and mine emergency issues. The MINER Act passed in 2006 mandated mine rescue regulations, new and improved technologies and safety practices in the area of tracking and communication, and emergency response plans and equipment. Although some new laws, regulations and policies are in place, these legislative and regulatory efforts are still ongoing.
In 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.
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
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
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
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
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.
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.
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.
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.
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.
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.
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:
· 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
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.
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.
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.
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.
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.
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.
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.
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
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
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.
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.
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.
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
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
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
· 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
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.
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.
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.
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.
(1) Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law. The reserve numbers set forth in the table exclude reserves for which we have leased our mining rights to third parties. Reserve information reflects a coal moisture factor on an “as received” basis, which means measuring coal in its natural state and not after it has dried in a laboratory setting. We have measured all reserves on an “as received” basis. This moisture factor on our delivered coal can vary depending on the quality of coal and the processing requirements.
(2) Assigned reserves represent recoverable coal reserves that can be mined without a significant capital expenditure for mine development, whereas unassigned reserves will require significant capital expenditures to mine the reserves.
(3) Almost all of our reserves that we currently market as metallurgical coal also possess quality characteristics that would enable us to market them as steam coal.
(4) The Wabash mine, an idled room-and-pillar operation, located in Wabash County, Illinois, has been on long-term idled status since April 2007. Idled facilities include a preparation plant and rail loading facility on the Norfolk Southern Railway. If conditions warrant, the mine could be re-opened with less capital investment than would be required to develop a new underground mine.
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 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.
ALPHA RESERVES, OPERATIONS AND HEADQUARTERS
The following map shows the locations of Alpha’s shipping points as of December 31, 2011:
See Item 1, “Business”, for additional information regarding our coal operations and properties.
Item 3. Legal Proceedings
For a description of the Company’s legal proceedings, see Note 20 to the Consolidated Financial Statements contained elsewhere in this Annual Report on Form 10-K, which is incorporated herein by reference.
Item 4. Mine Safety Disclosures
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Annual Report on Form 10-K.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The initial public offering of Old Alpha’s common stock occurred on February 15, 2005, and its common stock was then listed on the New York Stock Exchange under the symbol “ANR.” There was no public market for the common stock of Old Alpha prior to this date. On July 31, 2009, after the Foundation Merger, the common stock of Foundation, the surviving company of the Foundation Merger, which was renamed Alpha Natural Resources, Inc., replaced the common stock of Old Alpha on the New York Stock Exchange listing under the symbol “ANR”, and the Company’s common stock has since continued to trade under the symbol “ANR”.
Price range of our common stock
The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock reported in the New York Stock Exchange consolidated tape.
As of December 31, 2011, there were 7,241 registered holders of record of our common stock, including 156 unvested restricted stock positions. The transfer agent and registrar for our common stock is Computershare Trust Company, N.A.
Dividend Policy
We do not presently pay dividends on our common stock. Our Board of Directors periodically evaluates the initiation of dividends.
Equity Compensation Plan Information
The section of our Proxy Statement entitled “Equity Compensation Plan Information” is incorporated herein by reference.
Stock Performance Graph
The following stock performance graph compares the cumulative total return to stockholders on an annual basis on our common stock with the cumulative total return to stockholders on an annual basis on three indices, the S&P 500 Index, the Russell 3000 Index and the Bloomberg US Coal Index. In addition, the stock performance graph includes the dates of the Foundation Merger (July 31, 2009) and the Massey Acquisition (June 1, 2011).
The graph assumes that:
·
you invested $100 in Old Alpha common stock and in each index at the closing price on December 31, 2006;
·
all dividends were reinvested; and
·
you continued to hold your investment through December 31, 2011.
You are cautioned against drawing any conclusions from the data contained in this graph, as past results are not necessarily indicative of future performance. The indices used are included for comparative purposes only and do not indicate an opinion of management that such indices are necessarily an appropriate measure of the relative performance of our stock.
* $100 invested on 12/31/06 in stock or index, including reinvestment of dividends.
Fiscal year ending December 31
Repurchase of Common Stock
On May 19, 2010, the Board of Directors authorized a share repurchase program, which permited us to repurchase up to $125 million of our outstanding common stock, par value $0.01 per share (“Shares”). The program enabled us to repurchase Shares from time to time, as market conditions warrant. The program was completed during 2011. On August 22, 2011, the Board of Directors authorized an additional share repurchase program, which permits us to repurchase up to $600 million of Shares from time to time, as market conditions warrant.
The following table summarizes information about shares of common stock that were repurchased during the fourth quarter of 2011.
(1) In November 2008, the Board of Directors authorized us to repurchase common shares from employees to satisfy the employees’ minimum statutory tax withholdings upon the vesting of restricted stock and performance shares. During the three months ended December 31, 2011, the Company issued 21,656 shares of common stock to employees upon vesting of restricted stock and restricted stock units and repurchased 9,577 shares of common stock to satisfy the employees’ minimum statutory tax withholdings.
(2) On May 19, 2010, the Board of Directors authorized us to repurchase up to $125 million of common shares. Additionally, on August 22, 2011, the Board of Directors authorized the company to repurchase up to an additional $600 million of common shares. Under these programs, we may repurchase shares from time to time on the open market or in privately negotiated transactions, including structured or accelerated transactions, at prevailing prices as permitted by securities laws and other legal requirements, and subject to market conditions and other factors. To facilitate repurchases, we make purchases pursuant to a trading plan under Rule 10b5-1 of the Exchange Act, which allows us to repurchase shares during periods when we otherwise might be prevented from doing so under insider trading laws or because of self-imposed trading blackout periods. These programs may be discontinued at any time.
(3) We cannot estimate the number of shares that will be repurchased because decisions to purchase are based on company outlook, business conditions and current investment opportunities.
Item 6. Selected Financial Data
The following table presents selected financial and other data for the most recent five fiscal periods. The selected financial data as of December 31, 2011 and 2010, and for the years ended December 31, 2011, 2010, and 2009 have been derived from the audited Consolidated Financial Statements and related Notes thereto of Alpha Natural Resources, Inc. and subsidiaries included elsewhere in this Annual Report on Form 10-K. You should read the following table in conjunction with the Consolidated Financial Statements and related Notes thereto included elsewhere in this Annual Report on Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.
On July 31, 2009, Alpha Natural Resources, Inc. (“Old Alpha”) and Foundation Coal Holdings, Inc. (“Foundation”) merged (the “Foundation Merger”) with Foundation continuing as the surviving legal corporation of the Foundation Merger which was renamed Alpha Natural Resources, Inc. (“Alpha”). For financial accounting purposes, the Foundation Merger was treated as a “reverse acquisition” and Old Alpha was treated as the accounting acquirer. Accordingly, Old Alpha’s financial statements became the financial statements of Alpha and Alpha’s periodic filings subsequent to the Foundation Merger reflect Old Alpha’s historical financial condition and results of operations shown for comparative purposes. Old Alpha’s results of operations for the years ended December 31, 2008 and 2007 do not include financial results for Foundation. For the year ended December 31, 2009, Foundation’s financial results are included for the five month period from August 1, 2009 through December 31, 2009.
On June 1, 2011, we completed our acquisition of Massey Energy Company (“Massey”). Our consolidated results of operations for the year ended December 31, 2011 include Massey’s results of operations for the period June 1, 2011 through December 31, 2011. Our consolidated results of operations for the years ended December 31, 2010, 2009, 2008 and 2007 do not include amounts related to Massey’s results of operations.
The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, see Item 1A “Risk Factors” of this Annual Report on Form 10-K for a discussion of risk factors that could impact our future results of operations.
EBITDA from continuing operations is calculated as follows (unaudited, in thousands):
(1) Other revenues for 2011 include $127.2 million related to derivative contracts accounted for at fair value. Other revenues for 2009 include $18.1 million for the modification of a coal supply agreement.
(2) Income from continuing operations for 2011 includes the following significant amounts from the Massey Acquisition: Total revenues-$1.9 billion; Cost of coal sales-$1.9 billion; Depreciation, depletion and amortization-$398.3 million; and Amortization of acquired intangibles, net-($215.4) million. Income from continuing operations for 2009 includes the following significant amounts from the Foundation Merger: Total revenues-$716.8 million; Cost of coal sales-$467.5 million; Depreciation, depletion and amortization-$101.4 million; and Amortization of acquired intangibles, net-$127.6 million. See Note 3 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.
(3) Total assets as of December 31, 2011 included the impact of the addition of the following significant assets acquired in the Massey Acquisition: $6.4 billion of owned and leased mineral rights; $1.7 billion of property and equipment; and $2.6 billion of goodwill.
Total assets as of December 31, 2009 included the impact of the addition of the following significant assets acquired in the Foundation Merger: $1.8 billion of owned and leased mineral rights; $716.7 million of property and equipment, $529.5 million of coal supply agreements and $361.9 million of goodwill. See Note 3 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.
(4) Long-term debt, including current portion and debt discount as of December 31, 2011 includes $628.2 million, net of debt discount, assumed in the Massey Acquisition. Long-term debt, including current portion and debt discount as of December 31, 2009 includes $595.8 million, net of debt discount, assumed in the Foundation Merger. See Note 3 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.
(5) Stockholders’ equity as of December 31, 2011 includes approximately $5.7 billion related to the issuance of common shares and other equity consideration for the Massey Acquisition. Stockholders’ equity as of December 31, 2009, includes approximately $1.7 billion related to the issuance of common shares and other equity consideration related to the Foundation Merger. See Note 3 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.
(6) EBITDA from continuing operations is defined as income (loss) from continuing operations attributable plus interest expense, income tax expense (benefit), depreciation, depletion and amortization and amortization of acquired intangibles, net, less interest income. EBITDA from continuing operations is a non-GAAP measure used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because EBITDA from continuing operations is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and related Notes thereto included elsewhere in this Annual Report on Form 10-K.
Explanatory Note
On July 31, 2009, Alpha Natural Resources, Inc. (“Old Alpha”) and Foundation Coal Holdings, Inc. (“Foundation”) merged (the “Foundation Merger”) with Foundation continuing as the surviving legal corporation of the Foundation Merger which was renamed Alpha Natural Resources, Inc. (“Alpha”). For financial accounting purposes, the Foundation Merger was treated as a “reverse acquisition” and Old Alpha was treated as the accounting acquirer. Accordingly, Old Alpha’s financial statements became the financial statements of Alpha and Alpha’s periodic filings subsequent to the Foundation Merger reflect Old Alpha’s historical financial condition and results of operations shown for comparative purposes. For the year ended December 31, 2009, Foundation’s financial results are included for the five month period from August 1, 2009 through December 31, 2009.
Unless we have indicated otherwise, or the context otherwise requires, references in this report to “Alpha,” 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.
On June 1, 2011, we completed our acquisition (the “Massey Acquisition”) of Massey Energy Company (“Massey”). Massey, together with its affiliates, was a major U.S. coal producer operating mines and associated processing and loading facilities in Central Appalachia. Our consolidated results of operations for the year ended December 31, 2011 include Massey’s results of operations for the period June 1, 2011 through December 31, 2011. Our consolidated results of operations for the year ended December 31, 2010 and 2009 do not include amounts related to Massey’s results of operations. See Note 3 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K for additional information regarding the Massey Acquisition.
Overview
We are one of America’s premier coal suppliers, ranked second largest among publicly-traded U.S. coal producers as measured by consolidated 2011 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 operate 145 mines and 35 coal preparation facilities in Northern and Central Appalachia and the Powder River Basin, with approximately 14,500 employees.
We produce, process, and sell steam and metallurgical coal from twelve business units located throughout Virginia, West Virginia, Kentucky, Pennsylvania, and Wyoming. We also sell coal produced by others, the majority of which we process and/or blend with coal produced from our mines prior to resale, providing us with a higher overall margin for the blended product than if we had sold the coals separately. Our sales of steam coal in 2011, 2010 and 2009 accounted for approximately 82%, 86% and 83%, respectively, of our annual coal sales volume, and our sales of metallurgical coal in 2011, 2010 and 2009, which generally sells at a premium over steam coal, accounted for approximately 18%, 14% and 17%, respectively, of our annual coal sales volume.
Our sales of steam coal during 2011, 2010 and 2009 were made primarily to large utilities and industrial customers throughout the United States, and our sales of metallurgical coal during 2011, 2010 and 2009 were made primarily to steel companies in the Northeastern and Midwestern regions of the United States and in several countries in Europe, Asia and South America. Approximately 44%, 34% and 31% of our total revenues in 2011, 2010 and 2009, respectively, were derived from sales made to customers outside the United States, primarily in Brazil, India, Italy, the Netherlands and Turkey.
In addition, we generate other revenues from equipment and parts sales and repair, Dry Systems Technologies equipment and filters, road construction, rentals, commissions, coal handling, terminal and processing fees, coal and environmental analysis fees, royalties and the sale of coalbed methane and natural gas. We also record revenue for freight and handling charges incurred in delivering coal to certain customers, for which we are reimbursed by our customers. As such, freight and handling revenues are offset by equivalent freight and handling costs and do not contribute to our profitability.
Our primary expenses are for operating supply costs, repair and maintenance expenditures, cost of purchased coal, royalties, current wages and benefits, post-employment benefits, freight and handling costs, and taxes incurred in selling our coal. Historically, our cost of coal sales per ton is lower for sales of our produced and processed coal than for sales of purchased coal that we do not process prior to resale.
We have two reportable segments, Eastern Coal Operations and Western Coal Operations. Eastern Coal Operations consists of our operations in Northern and Central Appalachia, our coal brokerage activities and our road construction business. Western Coal Operations
consists of two Powder River Basin mines in Wyoming. Our All Other category includes an idled underground mine in Illinois; expenses associated with certain closed mines; Dry Systems Technologies; revenues and royalties from the sale of coalbed methane and natural gas extraction; equipment sales and repair operations; terminal services; the leasing of mineral rights; general corporate overhead and corporate assets and liabilities.
Business Developments
In addition to the Massey Acquisition completed on June 1, 2011 and the Foundation Merger completed on July 31, 2009, recent business developments included the following:
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.
Coal Pricing Trends, Uncertainties and Outlook
Our long-term outlook for the coal markets remains constructive. Coal exports from the U.S. increased from approximately 82 million tons in 2010 to approximately 107 million tons in 2011 in response to the continued worldwide economic recovery. Export volumes were substantially higher than the historic levels experienced in 2008. According to the EIA’s 2011 International Energy Outlook (“IEO”), global primary energy demand is expected to grow by 47% between 2010 and 2035, with coal demand rising most in absolute terms and fossil fuels accounting for most of the increase in demand between now and 2035. The IEO estimates that half the growth in world energy consumption will come from India and China. In total, coal consumption from non-OECD countries is expected to grow at an annual rate of 2.1%, accounting for nearly all the growth in world coal consumption. The IEO has reached a general conclusion that dependence on coal for power rises strongly in countries with emerging economies and relatively large coal reserves, while it stagnates in the more developed nations and nations with smaller coal reserves.
The Energy Information Administration (“EIA”) in its 2011 Annual Energy Outlook forecasts that coal-fired electrical generation will decrease by an average annual rate of 0.3% through 2015. In 2011, the EIA estimates that electric power generation from coal decreased by 4.2% compared to 2010 as low natural gas prices, increased environmental pressure, and other factors weigh on coal-fired generation. Long-term demand for coal and coal-based electricity generation in the U.S. will likely be driven by various factors such as the economy, increasing population, increasing demand to power residential electronics and plug-in hybrid electric vehicles, public demands for affordable electricity, relative costs for competing fuels for base-load generation such as natural gas and nuclear, the inability of renewable energy sources such as wind and solar to become the base load source of electric power, geopolitical risks associated with importing large quantities of global oil and natural gas resources, increasing demand for coal outside the U.S. resulting in increased exports, and the relatively abundant steam coal reserves located within the United States. As the U.S. and global economies emerge from the recent economic downturn, the International Monetary Fund’s September 2011 World Economic Outlook forecasts U.S. annual GDP to grow 1.8% and 2.5% in 2012 and 2013, respectively. Although the global economy improved as compared with 2010, many economic indicators continue to point to a slow and uneven recovery. High unemployment and a weak housing sector in the United States continue to dampen consumer sentiment domestically, while concerns over European sovereign debt issues and the deficit debate in Washington, D.C., and related downgrade of U.S. government debt continue to plague financial markets and constrain government spending in certain countries.
Ultimately, the global demand for and use of coal may be limited by any global treaties which place restrictions on carbon dioxide emissions. As part of the United Nations Framework Convention on Climate Change, representatives from 187 nations, including the U.S., met in Bali, Indonesia in December 2007 to discuss a program to limit greenhouse gas emissions after 2012. The convention adopted the “Bali Road Map” that detailed a two-year process to finalizing a binding agreement in Copenhagen in 2009. In December 2009 participants gathered in Copenhagen to develop a framework for climate change mitigation beyond 2012. The principal output of the Copenhagen summit was the Copenhagen Accord, a document that is neither legally binding nor voted upon nor signed, but was simply “noted” by the 194 participating countries. The ensuing UN Framework Convention on Climate Change held in Cancun in December 2010 resulted in an agreement that pushes most of the important decisions to future negotiations. Most recently, at the United Nations Climate Change Conference in Durbin, members advanced the implementation of previous agreements and agreed to adopt a universal legal agreement on climate change as soon as possible,
and no later than 2012. Although the results from these summits were considered modest by many participants, the ultimate outcome of future summits, and any treaty or other arrangement ultimately adopted by the United States or other countries, may have a material adverse impact on the global demand for and supply of coal. This is particularly true if cost effective technology for the capture and storage of carbon dioxide is not sufficiently developed.
Proposed coal-fired electric generating facilities that do not include technologies to capture and store carbon dioxide are facing increasing opposition from environmental groups as well as state and local governments, which are concerned with global climate change and uncertain financial impacts of potential greenhouse gas regulations. Coal-fired generating plants incorporating carbon dioxide capture and storage technologies will be more expensive to build than conventional pulverized coal generating plants as the technologies are still in the developmental stages. This dynamic may cause power generating companies to cut back on plans to build coal-fired plants in the near term. Nevertheless, the desire to attain U.S. energy independence suggests the construction of new coal-fired generating facilities is likely to remain a viable option. This desire, coupled with heightened interest in coal gasification and coal liquefaction, is a potential indicator of increasing demand for coal in the United States.
Based on weekly coal production reporting through December 31, 2011 from the EIA, year-over-year Appalachian production increased by approximately 0.6% due to stable global and domestic demand for metallurgical coal. Compared to 2010, Western coal production decreased by approximately 1.2% in 2011. In Central Appalachia, delays with respect to permits to construct valley fills at surface mines are likely to slow the permitting process for surface mining in that region with resultant uncertainties for producers. More stringent safety regulations, and increased MSHA mine inspection activity have also impacted production levels, particularly in Central Appalachia. Average spot market prices for 2011 for Central Appalachian and Northern Appalachian coals increased by approximately 19% and 17%, respectively, compared to 2010 prices. Average spot market prices for Powder River Basin coal increased by approximately 9% from the previous year, with the Powder River Basin offering the least expensive fossil fuel on a dollar per Btu basis. Starting in the second half of 2011 and continuing into the first quarter of 2012, U.S. and international spot market coal prices have declined due to a combination of slowing economies in the U.S. and Europe accompanied by low growth in demand for electricity, increased switching of electricity generation in the U.S. to natural gas due to abundant supply and decade low prices and increases in export volumes from Australia as weather-driven supply disruptions have eased. Long-term, the delicate balance of coal supply and increasing coal demand is expected to result in strong, but potentially volatile, fundamentals for the U.S. coal industry.
The worldwide economic slowdown and the volatility and uncertainty in the credit markets seen through much of the past two years continued to ease in 2011, though slow domestic growth and European debt challenges continue to hamper markets. Steel manufacturers reduced production in the latter half of 2011 after a very strong start to the year. We believe that the steel business will continue to show strength in the long-term despite normal cyclical volatilities. However, depressed natural gas prices are placing competitive pressure on steam coal. A weak economic recovery could slacken demand for metallurgical and steam coals and could negatively influence pricing in the near-term. Longer-term, coal industry fundamentals remain intact and significant additional growth is expected worldwide. Seaborne coal is expected to grow significantly as developing nations rely heavily on coal for their power needs. U.S. exports will be needed to help meet the anticipated increase in worldwide coal demand. We believe these factors should lead to stronger demand for coal, both globally and in the United States, in the coming years.
Our results of operations are dependent upon the prices we obtain for our coal as well as our ability to improve productivity and control costs. Principal goods and services we use in our operations include maintenance and repair parts and services, electricity, fuel, roof control and support items, explosives, tires, conveyance structure, ventilation supplies, and lubricants.
Our management strives to aggressively control costs and improve operating performance to mitigate external cost pressures. We have experienced volatility in operating costs related to fuel, explosives, steel, tires, contract services, and healthcare, and have taken measures to mitigate the increases in these costs at all operations. We have a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods, and to support the business units. The supplier base has been relatively stable for many years, but there has been some consolidation. We are not dependent on any one supplier in any region. We promote competition between suppliers and seek to develop relationships with suppliers that focus on lowering our costs. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. Employee labor costs have historically increased primarily due to the demands associated with attracting and retaining a workforce; however, recent stability in the marketplace has helped ease this situation. We may also continue to
experience difficult geologic conditions, delays in obtaining permits, labor shortages, unforeseen equipment problems, and shortages of critical materials such as tires and explosives that may result in adverse cost increases and limit our ability to produce at forecasted levels.
For additional information regarding some of the risks and uncertainties that affect our business, see Item 1A “Risk Factors.”
Results of Operations
EBITDA from continuing operations is calculated as follows:
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
As noted previously, the financial results for the year ended December 31, 2011 include only seven months of operations related to the acquired Massey operations due to the timing of the closing of the Massey Acquisition on June 1, 2011. The financial results for the year ended December 31, 2010 do not include any amounts related to Massey. To help understand the operating results for the periods, the term “Massey operations” refers to the results of Massey on a stand-alone basis for the seven month period from June 1, 2011 to December 31, 2011 and the term “Alpha operations” refers to the results of Alpha on a stand-alone basis and not inclusive of results from the acquired operations of Massey for twelve months ended December 31, 2011.
Summary
Total revenues increased $3,192.0 million, or 81%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase in total revenues was due to increased coal revenues of $2,691.6 million, increased freight and handling revenues of $329.6 million and increased other revenues of $170.8 million. The increase in coal revenues consisted of an increase from the Alpha operations of $813.0 million, or 23%, and $1,878.6 million from the Massey operations. The increase in freight and handling revenues was primarily related to the Alpha operations. The increase in other revenues consisted of an increase of $144.4 million, or 166%, from the Alpha operations, and $26.4 million from the Massey operations.
Income from continuing operations decreased $774.6 million for the twelve months ended December 31, 2011 compared to the prior year period. The decrease was largely due to a goodwill impairment charge of $745.3 million, increases in certain operating costs and expenses of $2,859.6 million, increased other expenses, net of $75.2 million, partially offset by increased coal revenues and other revenues discussed above and increased tax benefits of $43.1 million.
The increase in certain operating costs and expenses of $2,859.6 million was due to increased cost of coal sales of $2,514.8 million, or 98%, increased depreciation, depletion and amortization expenses of $398.6 million, or 107%, increased other expenses of $86.9 million, or 133%, increased selling, general and administrative expenses of $199.8 million, or 110%, and decreased expenses for amortization of acquired intangibles, net of $340.5 million, or 150%. The increase in cost of coal sales consisted of an increase of $591.2 million, or 23%, from the Alpha operations and $1,923.6 million from the Massey operations. Cost of coal sales in 2011 included $193.5 million of merger-related costs incurred in connection with the Massey Acquisition. The increase in depreciation, depletion and amortization expenses was primarily due to the inclusion of the Massey operations, including the fair value adjustments made in acquisition accounting to property, equipment and owned and leased mineral rights. The increase in other expenses consisted of an increase of $27.6 million, or 42%, from the Alpha operations and $59.3 million from the Massey operations. The increase in selling, general and administrative expenses included $164.0 million in merger-related costs incurred in connection with the Massey Acquisition. The decrease in expense for amortization of acquired intangibles, net, consisted of a decrease in amortization expense of $125.1 million, or 55%, from the Alpha operations and a credit to amortization expense of $215.4 million from the Massey operations.
We sold 106.3 million tons of coal during the twelve months ended December 31, 2011 compared to 84.8 million tons in the prior year period, an increase of 21.5 million tons, or 25%. The 106.3 million tons consisted of 37.2 million tons of steam coal and 19.2 million tons of metallurgical coal from our Eastern Coal Operations and 49.9 million tons of steam coal from our Western Coal Operations. The 84.8 million tons in the prior year consisted of 24.0 million tons of steam coal and 11.8 million tons of metallurgical coal from our Eastern Coal Operations and 49.0 million tons of steam coal from our Western Coal Operations.
The increase in coal sales volumes of 21.5 million tons in 2011 was due to increases of 13.2 million and 7.3 million tons of eastern steam and metallurgical coal, respectively, and an increase of 1.0 million tons of western steam coal. The increases in eastern steam and metallurgical coal were due primarily to the inclusion of 15.9 million tons of eastern steam and 5.0 million tons of metallurgical coal from the Massey operations, a decrease of 2.7 million tons of eastern steam and an increase of 2.3 million tons of metallurgical coal from the Alpha operations.
The average coal sales realization per ton for the twelve months ended December 31, 2011 was $58.22 compared to $41.22 in the prior year period, an increase of $17.00 per ton, or 41%. The increase was largely attributable to the $47.96 per ton, or 42%, increase in metallurgical average coal sales realization per ton. The average coal sales realization per ton for metallurgical coal and eastern steam coal was $161.85 and $66.92, respectively, for the twelve months ended December 31, 2011 compared to $113.89 and $67.07, respectively, in the prior year period. The average coal sales realization per ton for western steam coal was $11.95 for the twelve months ended December 31, 2011 compared to $10.95 in the prior year period.
Consolidated coal margin percentage, calculated as consolidated coal revenues less consolidated cost of coal sales (excluding cost of coal sales in our All Other segment), divided by consolidated coal revenues, was 19% for the twelve months ended December 31, 2011 compared to 27% in the prior year period. Coal margin percentage for our Eastern and Western Coal Operations was 19% and 16%, respectively, for the twelve months ended December 31, 2011 compared to 28% and 22%, respectively, in the prior year period. Consolidated coal margin per ton, calculated as consolidated coal sales realization per ton less consolidated cost of coal sales per ton, was $11.07 for the twelve months ended December 31, 2011 compared to $11.14 in the prior year period. Coal margin per ton for our Eastern and Western Coal Operations was $19.14 and $1.96, respectively, for the twelve months ended December 31, 2011 compared to $23.09 and $2.39, respectively, in the prior year period.
Revenues
Coal revenues. Coal revenues increased $2,691.6 million, or 77%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase in coal revenues consisted of an increase in metallurgical coal revenues of $1,752.0 million, or 130%, an increase in eastern steam coal revenues of $878.9 million, or 55%, and an increase in western steam coal revenues of $60.7 million, or 11%.
The increase in metallurgical coal revenues was largely due to an increase in tons shipped and increased average coal sales realization per ton. Metallurgical tons shipped increased 7.3 million, or 62%, compared to the prior year period and consisted of an increase of 2.3 million tons, or 19%, from the Alpha operations and 5.0 million tons from the Massey operations. The average coal sales realization per ton for metallurgical coal increased $47.96, or 42%, due primarily to increased pricing and demand for metallurgical coal compared to the prior year period.
The increase in eastern steam coal revenues was due to 15.9 million tons and $1,082.6 million from the Massey operations, partially offset by decreases of $203.7 million from the Alpha operations. The decrease in eastern steam coal revenues from the Alpha operations was primarily due to a decrease in eastern steam coal sales volumes, which decreased 2.7 million tons, or 11%, compared to the prior year period due primarily to increased production of metallurgical tons in response to the increase in demand and lower production at our Pennsylvania Services longwall mines.
The increase in western steam coal revenues was due primarily to an increase in average coal sales realization per ton. Average coal sales realization per ton increased $1.00, or 9%, compared to the prior year period as a result of increased pricing on contracted tons shipped.
Our sales mix of metallurgical coal and steam coal based on volume for the twelve months ended December 31, 2011 was 18% and 82%, respectively, compared with 14% and 86% in the prior year period. Our sales mix of metallurgical coal and steam coal based on volume for the Massey operations for the twelve months ended December 31, 2011 was 24% and 76%, respectively, and our sales mix of metallurgical coal and steam coal based on volume for the Alpha operations for the twelve months ended December 31, 2011 was 17% and 83%, respectively, compared to 14% and 86%, respectively, in the prior year period.
Our sales mix of metallurgical coal and steam coal based on revenues for the twelve months ended December 31, 2011 was 50% compared with 39% and 61% in the prior year period. Our sales mix of metallurgical coal and steam coal based on revenues for the Massey operations for the twelve months ended December 31, 2011 was 42% and 58%, respectively, and our sales mix of metallurgical coal and steam coal based on revenues for the Alpha operations for the twelve months ended December 31, 2011 was 54% and 46%, respectively, compared to 39% and 61%, respectively, in the prior year period.
Freight and handling. Freight and handling revenues and costs were $662.2 million for the twelve months ended December 31, 2011, an increase of $329.7 million, or 99%, compared to the prior year period. The increase was due to higher export shipments combined with higher shipping rates compared to the prior year period.
Other revenues. Other revenues increased $170.8 million, or 197%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase in other revenues was largely due to increased revenues of approximately $129.0 million related to derivative contracts accounted for at fair value, a majority of which were assumed in the Massey Acquisition, sublease revenues of approximately $14.4 million related to a sea-going vessel charter that we entered into in December 2010, increased rail load-out refunds of $10.0 million and increased royalty and rental revenues of approximately $6.6 million.
Costs and Expenses
(1) - Cost of coal sales per ton includes only costs associated with our Eastern and Western Coal Operations.
Cost of coal sales. Cost of coal sales increased $2,514.8 million, or 98%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase in cost of coal sales consisted of an increase of $591.2 million, or 23%, from the Alpha operations and $1,923.6 million from the Massey operations. The increases from the Alpha operations were primarily driven by increased production of higher cost metallurgical coal tons, increases in purchased coal expenses, increased costs for commodities used in the production process, higher sales related variable costs such as royalties and production and severance taxes due to higher sales realizations for metallurgical coal, transportation expenses and wages and employee benefits. Cost of coal sales from the Alpha operations included charges of approximately $37.1 million related to changes in asset retirement obligation-related estimates of water treatment costs at certain closed mines. Cost of coal sales from the Massey operations included charges of approximately $152.7 million related to the fair value adjustment made in acquisition accounting to Massey’s beginning inventory, approximately $35.5 million related to accruals made in connection with aligning certain employee benefits for employees from Massey and other employee compensation-related accruals, approximately $40.9 million of operating costs related to an idled mine and approximately $8.0 million related to expenses in connection with mineral lease terminations. The consolidated average cost of coal sales per ton was $47.15 compared to $30.08 in the prior year period. The average cost of coal sales per ton for Eastern and Western Coal Operations was $80.09 and $9.99, respectively, compared to $59.47 and $8.56, respectively, in the prior year period.
Other expenses. Other expenses increased $86.9 million, or 133%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase in other expenses was primarily due to increased expenses of approximately $61.2 million for contract-related matters primarily related to contracts assumed in the Massey Acquisition, an increase of approximately $17.6 million related to sea-going vessel charters that we entered into in the fourth quarter of 2010 and the first half of 2011, and increases of approximately $4.2 million and $3.5 million related to Dry Systems Technologies and sales of natural gas, respectively.
Depreciation, depletion and amortization. Depreciation, depletion, and amortization increased $398.6 million, or 107%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase consisted of depreciation, depletion and amortization of $398.3 million from the Massey operations, which includes impacts of fair value adjustments made to property and equipment and owned and leased mineral rights in acquisition accounting, and increased depreciation, depletion and amortization of $0.3 million from the Alpha operations.
Amortization of acquired intangibles, net. Amortization of acquired intangibles, net decreased $340.5 million, or 150%, for the twelve months ended December 31, 2011 compared to the prior year period. The decrease consisted of a $125.1 million decrease in amortization expense of acquired above-market coal supply agreements from the Alpha operations and a net credit to amortization expense from the Massey operations of $215.4 million related to the amortization of acquired below-market coal supply agreements and amortization of other intangible assets that were valued in the Massey Acquisition. Amortization of acquired intangibles, net for the next five years is estimated to be $(115,642), $30,368, $46,827, $35,065, and $30,180.
Selling, general and administrative expenses. Selling, general and administrative expenses increased $199.8 million, or 110%, for the twelve months ended December 31, 2011 compared to the prior year period. The increase was due primarily to acquisition-related expenses
totaling $164.0 million for a combination of employee compensation, professional fees incurred for legal, valuation and financial services in connection with the Massey Acquisition and related debt financing transactions and increased non-cash stock-based compensation.
Interest expense. Interest expense increased $68.5 million, or 93%, during the twelve months ended December 31, 2011 compared to the prior year period primarily due to a larger average outstanding balance of debt during the period as a result of the debt assumed in the Massey Acquisition and the financing transactions that were completed during the period.
Income tax benefit. Income tax benefit from continuing operations of $(38.9) million was recorded for the twelve months ended December 31, 2011 on loss from continuing operations before income taxes of $716.3 million, which equates to an effective tax rate of 5.4%. The rate is lower than the federal statutory rate of 35% primarily due to the non-deductible goodwill impairment and the impact of percentage depletion deduction.
Income tax expense from continuing operations of $4.2 million was recorded for the year ended December 31, 2010 on income from continuing operations before income taxes of $101.4 million, which equates to an effective tax rate of 4.2%. This rate is lower than the federal statutory rate of 35% due primarily to the tax benefits associated with percentage depletion and the reversal of certain tax reserves of approximately $14.0 million, partially offset by a state rate and net operating loss change and a $25.6 million deferred tax charge required for the legislative change related to the deductibility of retiree prescription drug expenses (Medicare Part D).
Segment Analysis
The price of coal is influenced by many factors that vary by region. Such factors include, but are not limited to: (1) coal quality, which includes energy (heat content), sulfur, ash, volatile matter and moisture content; (2) transportation costs; (3) regional supply and demand; (4) available competitive fuel sources such as natural gas, nuclear or hydro; and (5) production costs, which vary by mine type, available technology and equipment utilization, productivity, geological conditions, and mine operating expenses.
The energy content or heat value of coal is a significant factor influencing coal prices as higher energy coal is more desirable to consumers and typically commands a higher price in the market. The heat value of coal is commonly measured in British thermal units or the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. Coal from the Eastern and Midwest regions of the United States tends to have a higher heat value than coal found in the Western United States.
Powder River Basin coal, with its lower energy content, lower production cost and often greater distance to travel to the consumer, typically sells at a lower price than Northern and Central Appalachian coal that has higher energy content and is often located closer to the end user.
Western Coal Operations - EBITDA from continuing operations for our Western Coal Operations decreased $22.7 million, or 23%, compared to the prior year period. The decrease was due primarily to increased cost of coal sales, selling, general and administrative expenses and other expenses of $80.0 million, $0.4 million and $0.4 million, respectively, partially offset by an increase in total revenues of $58.1 million. Cost of coal sales per ton increased $1.43, or 17% while average coal sales realization per ton increased $1.00, or 9%, resulting in a decrease to coal margin per ton of $0.43, or 18%. The increase in cost of coal sales per ton was due primarily to increased diesel fuel expenses, increased sales-related variable costs due to higher sales realization per ton, a higher ratio of production from the Belle Ayr mine
which incurs higher production costs due to higher stripping ratios, and weather related delays experienced in the second quarter of 2011 that impacted transportation and coal shipments. The increase in total revenues consisted of an increase in coal revenues of $60.7 million, or 11%, partially offset by decreased other revenues of $2.6 million, or 32%. The increase in coal revenues was largely due to the increase in average coal sales realization per ton, which reflected increased shipments and increased contractual pricing during the period compared to the prior year.
Eastern Coal Operations - EBITDA from continuing operations decreased $486.8 million, or 72%, compared to the prior year period. The decrease was due to a goodwill impairment charge of $745.3 million, increased cost of coal sales of $2,380.6 million, increased other expenses of $60.3 million and increased selling, general and administrative expenses of $72.7 million, increased other miscellaneous expenses of $0.6 million and an increase in loss on early extinguishment of debt of $3.1 million, partially offset by increased coal and other revenues of $2,630.9 million and $144.8 million, respectively. Coal revenues and cost of coal sales for the East include $1,878.6 million and $1,923.6 million, respectively, from the Massey operations for the twelve months ended December 31, 2011.
Average coal sales realization per ton increased $16.65, or 20%, compared to the prior year period. The increase in average coal sales realization per ton was due primarily to an increase of $47.96, or 42%, related to metallurgical average coal sales realization. The average coal sales realization per ton for metallurgical coal related to the Alpha operations was $162.92, an increase of $49.03, or 43%, compared to the prior year period. The average coal sales realization per ton for metallurgical coal related to the Massey operations was $158.85.
Average cost of coal sales per ton increased $20.61, or 35%, compared to the prior year period. The increase in cost of coal sales per ton was due primarily to increased production of metallurgical tons in response to the increase in demand, lower production at our longwall mines, increases in royalties and production taxes due to higher average sales realization per ton and inflationary increases to other variable costs. Cost of coal sales from the Alpha operations included charges of approximately $37.1 million related to changes in asset retirement obligation-related estimates of water treatment costs at certain closed mines. Cost of coal sales from the Massey operations included charges of approximately $152.7 million related to the fair value adjustment made in acquisition accounting to Massey’s beginning inventory, approximately $35.5 million related to accruals made in connection with aligning certain employee benefits for employees from Massey and other employee compensation-related accruals, approximately $40.9 million of operating costs related to an idled mine and approximately $8.0 million related to expenses in connection with mineral lease terminations.
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
As noted previously, the financial results for the year ended December 31, 2009 include only five months of operations related to the acquired operations of Foundation due to the timing of the closing of the Foundation Merger on July 31, 2009 and therefore, the year-over-year results are not comparable. To help understand the operating results for the full year, the term “Foundation operations” refers to the results of Foundation on a stand-alone basis for the year ended December 31, 2010 and for the five month period from August 1, 2009 through December 31, 2009 and the term “legacy Alpha operations” refers to the results of Old Alpha on a stand-alone basis for the years ended December 31, 2010 and 2009.
Summary
Total revenues increased $1,421.6 million, or 57%, for the year ended December 31, 2010 compared to the prior year period. The increase in total revenues was due to increased coal revenues of $1,287.2 million and increased freight and handling revenues of $142.7 million, partially offset by decreased other revenues of $8.3 million. The increase in coal revenues consisted of an increase of $1,198.4 million, or 175%, from the Foundation operations as a result of their inclusion for the full year in 2010 and an increase of $88.8 million, or 6%, from the legacy Alpha operations. The increase in freight and handling revenues consisted of an increase of $137.9 million from the legacy Alpha operations and an increase of $4.8 million from the Foundation operations. The decrease in other revenues consisted of a decrease of $16.8 million from the legacy Alpha operations, partially offset by an increase of $8.5 million from the Foundation operations.
Income from continuing operations increased $30.4 million, or 46%, for the year ended December 31, 2010 compared to the prior year period. The increase was largely due to increased coal revenues of $1,287.2 million and a decrease in other income (expense), net, of $11.3 million, partially offset by increased certain operating costs and expenses of $1,222.6 million, a $37.2 million increase in income tax expense and decreased other revenues of $8.3 million.
The increase in certain operating costs and expenses of $1,222.6 million was due to increased cost of coal sales of $949.9 million, increased depreciation, depletion and amortization expenses of $118.5 million, increased amortization of acquired intangibles, net of $99.2 million, increased other expenses of $44.5 million and increased selling, general and administrative expenses of $10.5 million. The increase in cost of coal sales consisted of an increase of $722.9 million, or 155%, from the former Foundation operations and an
increase of $227.0 million, or 20%, from the legacy Alpha operations. The increase in depreciation, depletion and amortization expenses consisted of an increase of $130.1 million from the Foundation operations, partially offset by an $11.6 million decrease from the legacy Alpha operations. The increase in other expenses consisted of an increase of $18.4 million from the Foundation operations and an increase of $26.1 million from the legacy Alpha operations. The increase in selling, general and administrative expenses consisted of an increase of $61.1 million from the Foundation operations partially offset by a decrease of $50.6 million from the legacy Alpha operations.
We sold 84.8 million tons of coal during the year ended December 31, 2010 compared to 47.2 million tons in the prior year period, an increase of 37.6 million tons, or 80%. The 84.8 million tons consisted of 24.0 million tons of steam coal and 11.9 million tons of metallurgical coal from our Eastern Coal Operations and 48.9 million tons of steam coal from our Western Coal Operations. The 47.2 million tons consisted of 18.3 million tons of steam coal and 8.1 million tons of metallurgical coal from our Eastern Coal Operations and 20.8 million tons of steam coal from our Western Coal Operations.
The increase in coal sales volumes of 37.6 million tons was due to increases of 28.2 million, 7.5 million and 1.3 million tons of western steam, eastern steam and metallurgical coal, respectively, from the Foundation operations and an increase of 2.4 million tons of metallurgical coal partially offset by a decrease of 1.8 million tons of eastern steam coal from the legacy Alpha operations.
The consolidated average coal sales realization per ton for the year ended December 31, 2010 was $41.22 compared to $46.84 in the prior year period. The decrease was largely attributable to the inclusion of coal sales for the full year 2010 from our Western Coal Operations, which has a substantially lower coal sales realization per ton due to the difference in pricing between coal in the Powder River Basin and coal in the eastern coal basins. The average coal sales realization per ton for metallurgical coal and eastern steam coal was $113.89 and $67.07, respectively, for the year ended December 31, 2010 compared to $98.08 and $65.30, respectively, in the prior year period. The average coal sales realization per ton for western steam coal was $10.95 for the year ended December 31, 2010 compared to $10.47 in the prior year period.
Consolidated coal margin percentage, calculated as consolidated coal revenues less consolidated cost of coal sales (excluding cost of coal sales in our All Other segment), divided by consolidated coal revenues, was 27% for the years ended December 31, 2010 and 2009. Coal margin percentage for our Eastern and Western Coal Operations was 28% and 22%, respectively, for the year ended December 31, 2010 compared to 28% and 21%, respectively, in the prior year period. Consolidated coal margin per ton, calculated as consolidated coal sales realization per ton less consolidated cost of coal sales per ton, was $11.14 for the year ended December 31, 2010 compared to $12.65 in the prior year period. Coal margin per ton for our Eastern and Western Coal Operations was $23.09 and $2.39, respectively, for the year ended December 31, 2010 compared to $20.87 and $2.17, respectively, in the prior year period.
Revenues
Coal revenues. Coal revenues increased $1,287.2 million, or 58%, for the year ended December 31, 2010 compared to the prior year period. The increase in coal revenues consisted of an increase in metallurgical coal revenues of $554.6 million, an increase in eastern steam coal revenues of $413.7 million and an increase in western steam coal revenues of $318.9 million.
The increase in metallurgical coal revenues was largely due to an increase in tons shipped and coal sales realization per ton. Metallurgical tons shipped increased 3.7 million, or 46%, compared to the prior year period and consisted of an increase of 1.3 million tons from the Foundation operations and an increase of 2.4 million tons from the legacy Alpha operations. The increase in metallurgical tons shipped reflects an increase in demand for coking coal from steel producers in the year ended December 31, 2010 compared to the prior year period and the inclusion of the Foundation operations for the full year 2010. Coal sales realization per ton for metallurgical coal increased $15.81, or 16%, compared to the prior year period as a result of increased pricing due to stronger demand.
The increase in eastern steam coal revenues was largely due to an increase in tons shipped and a 3% increase in average coal sales realization. Eastern steam tons shipped increased 5.7 million, or 31%, compared to the prior year period and consisted of an increase of 7.5 million tons from the Foundation operations partially offset by a decrease of 1.8 million tons from the legacy Alpha operations. The increase from the Foundation operations reflects the inclusion of the Foundation operations for the full year 2010. The decrease from the legacy Alpha operations was due primarily to a mix shift of mining additional metallurgical tons in response to the increase in demand for those tons.
The increase in western steam coal revenues was due to an increase in tons shipped and average coal sales realization per ton. Tons shipped increased 28.2 million primarily due to the inclusion of the Foundation operations for the full year 2010. Coal sales realization per ton increased $0.48, or 5%, compared to the prior year period as a result of increased pricing on contracted tons shipped.
Our sales mix of metallurgical coal and steam coal based on volume for the year ended December 31, 2010 was 14% and 86%, respectively, compared with 17% and 83% in the prior year period. Our sales mix of metallurgical coal and steam coal based on coal revenues for the year ended December 31, 2010 was 39% and 61%, respectively, compared with 36% and 64% in the prior year period.
Freight and handling revenues. Freight and handling revenues were $332.6 million for the year ended December 31, 2010, an increase of $142.7 million, or 75%, compared to the prior year period. The increase was due to higher export and domestic shipments combined with higher shipping rates compared to the prior year period. These revenues are offset by equivalent costs and do not contribute to our profitability.
Other revenues. Other revenues decreased $8.3 million, or 9%, for the year ended December 31, 2010 compared to the prior year period. The decrease consisted of a decrease of $16.8 million from the legacy Alpha operations partially offset by an increase of $8.5 million from the Foundation operations. The decrease from the legacy Alpha operations was due to a decrease in road construction revenues of approximately $24.2 million due to a loss on a construction contract and decreased revenues related to mark-to-market adjustments to coal sales contracts that are reported at fair value, partially offset by increases in royalties, coal processing and other miscellaneous revenues. The increase from the Foundation operations was largely due to the inclusion of the Foundation operations for the full year 2010 and consisted of increased revenues related to Dry Systems Technologies, increased revenues and royalties related to our coalbed methane and natural gas extraction activities, partially offset by decreased other miscellaneous revenues of $18.1 million related to a coal supply agreement modification in 2009.
Costs and expenses
(1) - Cost of coal sales per ton includes only costs associated with our Eastern and Western Coal Operations.
Cost of coal sales. Cost of coal sales increased $949.9 million, or 59%, for the year ended December 31, 2010 compared to the prior year period. The increase consisted primarily of increases in wages and employee benefits, operating supplies, maintenance and repair, purchased coal expenses, outside services, royalties and production and severance taxes. These increases were largely due to the inclusion of the Foundation operations for the full year 2010, which increased by $722.9 million. Additionally, cost of coal sales included non-recurring charges of approximately $15.5 million related to aligning vacation and retirement benefits company-wide and asset impairment charges of approximately $2.7 million related to the idling of the Moss #3 preparation plant. The legacy Alpha operations increased $227.0 million compared to the prior year period. The consolidated average cost of coal sales per ton was $30.08 compared to $34.19 in the prior year period. The average cost of coal sales per ton for Eastern and Western Coal Operations was $59.47 and $8.56, respectively, compared to $54.50 and $8.30, respectively, in the prior year period. The increase in cost of coal sales per ton at our Eastern Operations was largely due to an increase in production of higher cost metallurgical tons as a result of responding to the increase in demand for metallurgical coal and a decrease in production from our lower cost longwall mines due to difficult geological conditions, the impact of our miner vacation schedule, which impacted the current year period more as a result of the inclusion of the Foundation operations for the full year 2010, and a longwall move that began in August 2010. Additionally, we experienced certain weather-related delays and railroad performance issues in the later part of the year that contributed to the increase in cost per ton in the East. An increase in purchased coal volumes also contributed to the increase in cost of coal sales per ton for the Eastern Coal Operations.
Freight and handling costs. Freight and handling costs increased $142.7 million, or 75%, compared to the prior year period. The increase was due to higher export and domestic shipments combined with higher shipping rates compared to the prior year period. These costs are offset by equivalent revenues and do not contribute to our profitability.
Other expenses. Other expenses increased $44.5 million, or 212%, for the year ended December 31, 2010 compared to the prior year period. The increase was due to increased other expenses of $18.4 million from the Foundation operations and $26.1 million from the legacy Alpha operations. Other expenses generally consist of mark-to-market gains and losses on derivatives swap contracts that are not designated as cash flow hedges and expenses associated with our road construction, Dry Systems Technologies and coalbed methane and natural gas extraction activities. The increase in other expenses from the legacy Alpha operations was largely due to mark-to-market gains recorded in earnings during 2009 for derivative instruments that have since been designated as cash flow hedges and for which changes in fair value are now recorded as a part of accumulated other comprehensive (loss) income. The increase in other expenses from the Foundation operations was due to increases in costs related to Dry Systems Technologies and our coalbed methane and natural gas extraction activities, primarily as a result of the inclusion of these costs for the full year 2010.
Depreciation, depletion and amortization. Depreciation, depletion, and amortization increased $118.5 million, or 47%, for the year ended December 31, 2010 compared to the prior year period. The increase consisted of increased depreciation and amortization of $76.4 million primarily related to capital expenditures during the previous twelve months and increased depletion expense of $42.1 million related to increased production compared to the prior year period. These increases were largely due to the inclusion of the Foundation operations for the full year 2010 and the increase in metallurgical production which carries a higher depletion rate. Depreciation, depletion, and amortization for the Foundation operations was $231.6 million for the year ended December 31, 2010.
Amortization of acquired intangibles, net. Application of acquisition accounting in connection with the Foundation Merger resulted in the recognition of a significant asset for above market-priced coal supply agreements and a liability for below market-priced coal supply agreements on the date of the acquisition. The coal supply agreement assets and liabilities are being amortized over the actual amount of tons shipped under each contract. Amortization of acquired intangibles, net was $226.8 million for the year ended December 31, 2010 compared to $127.6 million in the prior year period. Amortization of acquired intangibles, net for future periods is expected to be $119.5 million in 2011, $31.7 million in 2012 and a credit to expense of ($1.7 million) in 2013.
Selling, general and administrative expenses. Selling, general and administrative expenses increased $10.6 million, or 6%, for the year ended December 31, 2010 compared to the prior year period. The increase in selling, general and administrative expenses consisted of an increase of $61.2 million from the Foundation operations partially offset by a decrease of $50.6 million from the legacy Alpha operations. The increase was primarily due to increased employee wages and benefits, increased severance and relocation charges, and increased other miscellaneous overhead expenses due to the inclusion of the Foundation operations for the full year 2010, partially offset by decreased merger related expenses related to legal and other outside services costs incurred for the Foundation Merger, lower expenses recorded for share-based compensation and a portion of a curtailment gain recorded during the year associated with a re-measurement of our defined-benefit pension plan obligations as a result of a plan change due to the alignment of employee benefits company-wide. Consolidated selling, general and administrative expenses included approximately $10.2 million of expenses related to the Foundation Merger.
Interest expense. Interest expense decreased $9.4 million, or 11%, during the year ended December 31, 2010 compared to the prior year period. The decrease in interest expense was primarily related to the decreased interest expense and amortization of deferred loan fees associated with the legacy Alpha term loan that was paid off subsequent to the Foundation Merger, and a decrease in interest expense associated with the realized and unrealized losses due to the changes in fair value of the legacy Alpha interest rate swap that was de-designated as a cash flow hedge as a result of paying off the legacy Alpha term loan in July 2009, partially offset by increased interest expense associated with the long term debt assumed in the Foundation Merger that was included for the full year 2010.
Interest income. Interest income increased by $1.7 million for the year ended December 31, 2010 compared to the prior year period primarily due to a higher average cash balance invested in marketable securities.
Loss on early extinguishment of debt. During the year ended December 31, 2010, we amended our credit facility and prepaid approximately $39.6 million of the outstanding term loan. As a result, we wrote off a portion of the deferred financing costs and recorded a loss of $1.3 million. During the year ended December 31, 2009, we paid off the legacy Alpha term loan and wrote off the remaining deferred loan fees and recorded a loss of $5.6 million.
Income tax expense (benefit). Income tax expense from continuing operations of $4.2 million was recorded for the year ended December 31, 2010 on income from continuing operations before income taxes of $101.4 million, which equates to an effective tax rate of 4.2%. This rate is lower than the federal statutory rate of 35% due primarily to the tax benefits associated with percentage depletion and the reversal of certain tax reserves of approximately $14.0 million, partially offset by the impact of a state rate and net operating loss change and a $25.6 million deferred tax charge required for the legislative change related to the deductibility of retiree prescription drug expenses (Medicare Part D).
Income tax benefit from continuing operations of $33.0 million was recorded for year ended December 31, 2009 on income from continuing operations before income taxes of $33.8 million. The income tax benefit for 2009 was due primarily to the tax benefits associated with percentage depletion and the reversal of $22.2 million of valuation allowance that was triggered by our movement from a net deferred tax asset position to a net deferred tax liability position on our Consolidated Balance Sheet as a result of the Foundation Merger, partially offset by non-deductible transaction costs and the impact from the interest rate swap.
Discontinued operations. Loss from discontinued operations for the year ended December 31, 2010 was $1.7 million, net of tax, compared to a loss from discontinued operations of $8.8 million, net of tax, for the year ended December 31, 2009. The loss from discontinued operations in 2010 and 2009 was related to expenses incurred for Kingwood.
Segment Analysis
Western Coal Operations - EBITDA from continuing operations for our Western Coal Operations increased $58.3 million, or 148%, compared to the prior year period. The increase was due to increased total revenues of $325.5 million, partially offset by increased certain operating expenses of $267.2 million. The increase in total revenues consisted of increased coal and other revenues of $318.9 million and $6.6 million, respectively. The increase in coal revenues was largely due to increased tons shipped of 28.2 million, or 136%, and increased average sales realization per ton of $0.48, or 5%. The increase in certain operating expenses consisted of increased cost of coal sales of $246.8 million and a $20.4 million increase in other operating expenses. These increases were primarily due to the inclusion of the Western Coal Operations for the full year 2010. Cost of coal sales per ton increased $0.26, or 3%.
Eastern Coal Operations - EBITDA from continuing operations increased $154.3 million, or 29%, compared to the prior year period. The increase was due to increased coal revenues of $968.3 million, partially offset by increased certain operating expenses of $773.3 million, decreased other revenues of $35.4 million, increased other miscellaneous expense, net of $3.9 million and a loss on early extinguishment of debt of $1.4 million. The increase in coal revenues was due to increased metallurgical and steam coal revenues of $554.6 million and $413.7 million, respectively. The increase in certain operating expenses consisted of increased cost of coal sales of $692.2 million and increased other operating expenses of $81.1 million.
The increase in metallurgical coal revenues was largely due to an increase in tons shipped and coal sales realization per ton. Metallurgical tons shipped increased 3.7 million, or 46%, compared to the prior year period and consisted of an increase of 1.3 million tons from the Foundation operations and an increase of 2.4 million tons from the legacy Alpha operations. The increase in metallurgical tons shipped reflects an increase in demand for coking coal from steel producers during 2010 compared to the prior year period and the inclusion of the Foundation operations for the full year 2010. Coal sales realization per ton for metallurgical coal increased $15.81, or 16%, compared to the prior year period as a result of increased pricing due to stronger global demand.
The increase in eastern steam coal revenues was largely due to an increase in tons shipped and a 3% increase in average sales realization per ton. Eastern steam tons shipped increased 5.7 million, or 31%, compared to the prior year period and consisted of an increase of 7.5 million tons from the Foundation operations and a decrease of 1.8 million tons from the legacy Alpha operations. The increase from the Foundation operations reflects the inclusion of the Foundation operations for the full year 2010. The decrease from the legacy Alpha operations was due to a mix shift of mining additional metallurgical tons in response to the increase in demand for those tons during the year.
The increase in cost of coal sales was due to increases in wages and employee benefits, operating supplies, maintenance and repair, purchased coal expenses, outside services, royalties and production and severance taxes, all of which experienced increases due in part to the inclusion of the Foundation operations for the full year 2010. Additionally, cost of coal sales in the East included non-recurring charges of approximately $15.3 million related to aligning vacation and retirement benefits company-wide and asset impairment charges of approximately $2.7 million related to the idling of the Moss #3 preparation plant. Cost of coal sales per ton increased $4.97, or 9%, compared to the prior year period largely due to an increase in production of higher cost metallurgical tons as a result of responding to the increase in demand for metallurgical coal and a decrease in production from our lower cost longwall mines due to difficult geological conditions, the impact of our miner vacation schedule, which impacted the current year period more as a result of the inclusion of the Foundation operations for the full year 2010, and a longwall move that began in August of 2010. Additionally, we experienced certain weather-related delays and railroad performance issues in the later part of the year that contributed to the increase in cost per ton in the East. An increase in purchased coal volumes also contributed to the increase in cost of coal sales per ton for the Eastern Coal Operations.
Liquidity and Capital Resources
Our primary liquidity and capital resource requirements stem from the cost of our coal production and purchases, our capital expenditures, our income taxes, our share repurchases and our debt service and reclamation obligations. Our primary sources of liquidity have been from sales of our coal production; borrowings under our credit facility and debt arrangements (see “-Credit Agreement and Long-Term Debt”); and to a much lesser extent, sales of purchased coal to customers, cash from sales of non-core assets and miscellaneous revenues.
We believe that cash on hand, cash generated from our operations and borrowing capacity available under the Third Amended and Restated Credit Agreement and our accounts receivable securitization facility (the “A/R Facility”) will be sufficient to meet our working capital requirements, anticipated capital expenditures, debt service requirements, reclamation obligations, potential share and debt repurchases, and expected settlements and costs related to outstanding litigation for at least the next twelve months.
At December 31, 2011, we had available liquidity of $1,801.4 million, including cash and cash equivalents of $585.9 million, marketable securities of $100.8 million and $1,114.7 million of unused revolving credit facility commitments available under the Third Amended and Restated Credit Agreement and our A/R Facility, after giving effect to $0.3 million and $160.0 million of letters of credit outstanding, respectively, as of December 31, 2011, subject to limitations described in the Third Amended and Restated Credit Agreement and the A/R Facility. Our total long-term debt, net of debt discount and including current portion, was $2,968.1 million at December 31, 2011, see “-Credit Agreement and Long-Term Debt”.
We sponsor pension plans in the United States for salaried and non-union hourly employees. For these plans, the Pension Protection Act of 2006 (“PPA”) requires a funding target of 100% of the present value of accrued benefits. Generally, any such plan with a funding ratio of less than 80% will be deemed at risk and will be subject to additional funding requirements under the PPA. Our pension plans are approximately 76% funded as of December 31, 2011. Annual funding contributions to the plans are made as recommended by consulting actuaries based upon the ERISA funding standards. Plan assets consist of cash and cash equivalents, an investment in a group annuity contract, equity and fixed income funds, and private equity funds. We are required to measure plan assets and benefit obligations as of the date of our fiscal year-end balance sheet and recognize the overfunded or underfunded status of our defined benefit pension and other postretirement plans (other than a multi-employer plan) as an asset or liability on our balance sheet and recognize changes in that funded status in the year in which the changes occur through other comprehensive (loss) income. The volatile financial markets in 2008 and 2009 caused investment income and the value of the investment assets held in our pension trust to decline. As a result, depending on economic recovery and growth in the value of our invested assets, we may be required to increase the amount of cash contributions into the pension trust in order to comply with the funding requirements of the PPA. We currently expect to make contributions in 2012 in the range of $25.0 million to $30.0 million for our defined benefit pension plans.
We have obligations for a federal coal lease, which contains an estimated 224.0 million tons of proven and probable coal reserves in the Powder River Basin. The original lease bonus bid was $180.5 million, payable in five equal annual installments of $36.1 million. The remaining annual installment of $36.1 million is due on May 1, 2012.
In September 2011, we entered into a federal coal lease, which contains an estimated 130.2 million tons of proven and probable coal reserves in the Powder River Basin. The lease bid was $143.4 million, payable in five equal annual installments of $28.7 million. The first installment was paid in September 2011. The remaining four annual installments of $28.7 million are due each September until the obligation is satisfied in 2015.
With respect to global economic events, there continues to be uncertainty in the financial markets and this uncertainty brings potential liquidity risks for us. These risks could include declines in our stock value, less availability and higher costs of additional credit, potential counterparty defaults and further commercial bank failures. The credit worthiness of our customers is constantly monitored by us. We believe that our current group of customers is sound and represents no abnormal business risk.
Financing Relating to the Massey Acquisition
On June 1, 2011, pursuant to the terms of the Agreement and Plan of Merger dated as of January 28, 2011, we completed the Massey Acquisition of Massey. Massey stockholders received 1.025 shares of our common stock and $10.00 in cash for each share of Massey common stock.
The proceeds we received from our term loan facility, revolving credit facility and the issuance of our 2019 and 2021 Notes (as defined below) were used to:
· fund the cash portion of the Massey Acquisition consideration (inclusive of payments due to holders of Massey equity awards);
· repay approximately $227.9 million outstanding under our existing senior secured term loan and replace $1.3 million in letters of credit issued under our revolving credit facility;
· retire $760.0 million of Massey’s 6.875% senior notes due 2013 (the “2013 Notes”) that were outstanding prior to the Massey Acquisition through a combination of a cash tender offer and redemption on July 5, 2011;
· replace Massey’s existing asset-backed revolving credit facility and restricted cash letter of credit facility, which had no borrowings outstanding and approximately $135.4 million of letters of credit outstanding;
· redeem the $298.3 million aggregate outstanding principal amount of the 7.25% notes due 2014 (the “2014 Notes”) of Foundation PA Coal Company LLC (“Foundation PA”), one of our subsidiaries, on August 18, 2011 (the “Redemption Date”) at a redemption price equal to 101.208% of the principal amount of the 2014 Notes, plus any and all accrued and unpaid interest; and
· pay transaction fees and expenses.
During the year ended December 31, 2011, we incurred fees totaling $121.8 million related to the financing of the Massey Acquisition. Of the total incurred, $84.0 million was capitalized as debt issuance costs and will be amortized over the life of the related financing arrangements. The remaining $37.8 million was recognized as selling, general and administrative expense during the year ended December 31, 2011, including $24.7 million related to the commitment fees incurred on the unsecured bridge loan facility which was in place during the process of the Massey Acquisition.
Accounts Receivable Securitization
Alpha and certain of our subsidiaries are parties to the A/R Facility. We formed ANR Receivables Funding, LLC (the “SPE”), a special-purpose, bankruptcy-remote wholly-owned subsidiary to purchase trade receivables generated by certain of our operating and sales subsidiaries, without recourse (other than customary indemnification obligations for breaches of specific representations and warranties), and then transfer senior undivided interests in up to $275.0 million of those accounts receivable to a financial institution for the issuance of letters of credit or for cash borrowings for our ultimate benefit under the A/R Facility.
The SPE is consolidated into our financial statements, and therefore the purchase and sale of trade receivables by the SPE from our operating and sales receivables has no impact on our consolidated financial statements. The assets of the SPE, however, are not available to the creditors of us or any other subsidiary. The SPE pays facility fees, program fees and letter of credit fees (based on amounts of outstanding letters of credit), as defined in the definitive agreements for the A/R Facility. Available borrowing capacity is based on the amount of eligible accounts receivable as defined under the terms of the definitive agreements for the A/R Facility and varies over time. The A/R Facility was amended in June 2011 to increase the capacity of the A/R Facility from $150.0 million to $190.0 million and the A/R Facility was amended and restated in October 2011 to further increase the capacity of the A/R Facility to $275.0 million. Unless extended by the parties, the receivables purchase agreement supporting the borrowings under the A/R Facility expires on October 17, 2014, or earlier upon the occurrence of certain events customary for facilities of this type.
As of December 31, 2011, letters of credit in the amount $160.0 million were outstanding under the A/R Facility and no cash borrowing transactions had taken place. If outstanding letters of credit exceed borrowing capacity, we are required to provide additional collateral in the form of restricted cash to secure outstanding letters of credit. Under the A/R Facility, the SPE is subject to certain affirmative, negative and financial covenants customary for financings of this type, including restrictions related to, among other things, liens, payments, merger or consolidation and amendments to the agreements underlying the receivables pool. Alpha Natural Resources, Inc. has agreed to guarantee the performance by its subsidiaries, other than the SPE, of their obligations under the A/R Facility. We do not guarantee repayment of the SPE’s debt under the A/R Facility. The financial institution, which is the administrator, may terminate the A/R Facility upon the occurrence of certain events that are customary for facilities of this type (with customary grace periods, if applicable), including, among other things, breaches of covenants, inaccuracies of representations and warranties, bankruptcy and insolvency events, changes in the rate of default or delinquency of the receivables above specified levels, a change of control and material judgments. A termination event would permit the administrator to terminate the program and enforce any and all rights and remedies, subject to cure provisions, where applicable.
Cash Flows
Cash and cash equivalents increased by $31.1 million and $88.9 million for the years ended December 31, 2011 and 2010, and decreased $210.3 million for the year ended December 31, 2009. The net change in cash and cash equivalents was attributable to the following:
Net cash provided by operating activities for the year ended December 31, 2011 was $686.6 million, a decrease of $7.0 million from the $693.6 million of net cash provided by operating activities for the year ended December 31, 2010. Non-cash amounts included in net income for the year ended December 31, 2011 were primarily related to an increase in depreciation, depletion, accretion and amortization expense, an increase in amortization of debt issuance costs and accretion of debt discount, a decrease in mark-to-market adjustments for derivatives, an increase in stock-based compensation expense, an increase in employee benefit plan costs, a decrease in deferred taxes, and a goodwill impairment charge. The cash used by changes in operating assets and liabilities for the year ended December 31, 2011 was primarily related to an increase in accounts receivable, net of $178.7 million, a decrease in inventories, net of $120.5 million, and a decrease of $105.6 million in pension and postretirement medical benefit obligations.
Net cash used in investing activities for the year ended December 31, 2011 was $1,147.0 million, an increase of $638.5 million from the $508.5 million of net cash used in investing activities for the year ended December 31, 2010. The increase was primarily due to the cash portion of consideration paid to acquire Massey of $711.4 million, net of cash acquired, and increased capital expenditures of $219.7 million.
Net cash provided by financing activities for the year ended December 31, 2011 was $491.5 million, an increase of $587.7 million from the $96.2 million of net cash used in financing activities for the year ended December 31, 2010. The primary source of cash for financing activities included $2,100.0 million of proceeds from borrowings of long-term debt, offset by principal repayments of long-term debt of $1,315.4 million. In addition, common stock repurchases of $212.3 million and debt issuance costs of $85.2 million account for $297.5 million of the use of cash for financing activities for the year ended December 31, 2011. Common stock repurchases consist of shares repurchased as part of publically announced share repurchase programs and repurchase of common shares from employees to satisfy the employees’ minimum statutory tax withholdings upon the vesting of restricted stock and performance shares. The majority of the financing activities for the year ended December 31, 2011 relate to the Massey Acquisition.
Net cash provided by operating activities, including discontinued operations, during 2010 was $693.6 million, an increase of $337.4 million from the $356.2 million of net cash provided by operations during 2009. This increase was driven by an increase in our net income and by changes in operating assets and liabilities. The cash generated (used) by changes in operating assets and liabilities was primarily related to the increase in accounts receivable, net of $48.5 million, the increase in inventories, net of $21.9 million, the decrease in prepaid expenses and other current assets of $59.1 million, the decrease in accounts payable of $21.8 million, the increase in accrued expenses and other current liabilities of $42.7 million and the decrease in pension and postretirement medical benefit obligations of $70.8 million.
Net cash used in investing activities, including discontinued operations, during 2010 was $508.5 million, an increase of $226.7 million from the $281.8 million of net cash used in investing activities during 2009. The increase in 2010 was primarily due to an increase in capital expenditures of $121.8 million, an increase in net purchases of marketable securities of $39.1 million, and the acquisition of mineral rights under federal lease of $36.1 million.
Net cash used in financing activities, including discontinued operations, during 2010 was $96.2 million, compared to $284.7 million of net cash used in financing activities in 2009. The primary uses of cash for financing activities included $41.7 million of common stock repurchases under our stock repurchase program and to satisfy employees’ minimum statutory tax withholdings upon the vesting of restricted stock and restricted stock units. In addition, we made $56.9 million of principal payments on our long-term debt.
Credit Agreement and Long-term Debt
As of December 31, 2011 and 2010, our total long-term indebtedness consisted of the following (in thousands):
New Notes Indenture and the New Senior Notes
On June 1, 2011, we and certain of our wholly owned domestic subsidiaries (collectively, the “Alpha Guarantors”) and Union Bank, N.A., as trustee, entered into an indenture (the “Base Indenture”) and a first supplemental indenture (the “First Supplemental Indenture” and, together with the Base Indenture, the “New Notes Indenture”) governing our newly issued 6.00% senior notes due 2019 (the “2019 Notes”) and 6.25% senior notes due 2021 (the “2021 Notes” and, together with the 2019 Notes, the “New Senior Notes”).
On June 1, 2011, in connection with the Massey Acquisition, we, the Alpha Guarantors, Massey, and certain wholly owned subsidiaries of Massey (the “Massey Guarantors” and together with the Alpha Guarantors the “Guarantors”), and Union Bank, N.A., as trustee, entered into a supplemental indenture (the “Second Supplemental Indenture”) to the New Notes Indenture pursuant to which Massey and certain wholly owned subsidiaries of Massey agreed to become additional guarantors for the New Senior Notes.
The 2019 Notes bear interest at a rate of 6.00% per annum, payable semi-annually on June 1 and December 1 of each year, beginning on December 1, 2011, and will mature on June 1, 2019. The 2021 Notes bear interest at a rate of 6.25% per annum, payable semi-annually on June 1 and December 1 of each year, beginning on December 1, 2011, and will mature on June 1, 2021.
As of December 31, 2011, the carrying values of the 2019 Notes and 2021 Notes were $800.0 million and $700.0 million, respectively.
We may redeem the 2019 Notes, in whole or in part, at any time prior to June 1, 2014, at a price equal to 100.000% of the aggregate principal amount of the 2019 Notes plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date. We may redeem the 2019 Notes, in whole or in part, at any time during the twelve months commencing June 1, 2014, at 103.000% of the aggregate principal amount of the 2019 Notes, at any time during the twelve months commencing June 1, 2015, at 101.500% of the aggregate principal amount of the 2019 Notes, and at any time after June 1, 2016 at 100.000% of the aggregate principal amount of the 2019 Notes, in each case plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date. In addition, Alpha may redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net cash proceeds from certain equity offerings, at any time prior to June 1, 2014, at a redemption price equal to 106.000% of the aggregate principal amount of the 2019 Notes, plus accrued and unpaid interest, if any, to, but not including the applicable redemption date, provided that at least 65% of the aggregate principal amount of the 2019 notes originally issued under the New Notes Indenture remains outstanding after the redemption and the redemption occurs within 180 days of the closing of such equity offering.
We may redeem the 2021 Notes, in whole or in part, at any time prior to June 1, 2016, at a price equal to 100.000% of the aggregate principal amount of the 2021 Notes plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date. We may redeem the 2021 Notes, in whole or in part, at any time during the twelve months commencing June 1, 2016, at 103.125% of the aggregate principal amount of the 2021 Notes, at any time during the twelve months commencing June 1, 2017, at 102.083% of the aggregate principal amount of the 2021 Notes, at any time during the twelve months commencing June 1, 2018, at 101.042% of the aggregate principal amount of the 2021 Notes, and at any time after June 1, 2019, at 100.000% of the aggregate principal amount of the 2021 Notes, in each case plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date. In addition, we may redeem up to 35% of the aggregate principal amount of the 2021 Notes with the net cash proceeds from certain equity offerings, at any time prior to June 1, 2016, at a redemption price equal to 106.250% of the aggregate principal amount of the 2021 Notes, plus accrued and unpaid interest, if any, to, but not including the applicable redemption date, provided that at least 65% of the aggregate principal amount of the 2021
notes originally issued under the New Notes Indenture remains outstanding after the redemption and the redemption occurs within 180 days of the date of the closing of such equity offering.
Upon the occurrence of a change in control repurchase event with respect to either series of the New Senior Notes, unless we have exercised our right to redeem those New Senior Notes, we will be required to offer to repurchase each holder’s New Senior Notes of such series at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the date of repurchase.
The New Notes Indenture contains covenants that limit, among other things, our ability to:
· incur, or permit its subsidiaries to incur, additional debt;
· issue, or permit its subsidiaries to issue, certain types of stock;
· pay dividends on our or our subsidiaries’ capital stock or repurchase our common stock;
· make certain investments;
· enter into certain types of transactions with affiliates;
· incur liens on certain assets to secure debt;
· limit dividends or other payments by its restricted subsidiaries to us and our other restricted subsidiaries;
· consolidate, merge or sell all or substantially all of its assets; and
· make certain payments on our or our subsidiaries’ subordinated debt.
These covenants are subject to a number of important qualifications and exceptions. These covenants may not apply at any time after the New Senior Notes are assigned a credit grade rating of at least BB+ (stable) from Standard & Poor’s Ratings Services and of at least Ba1 (stable) from Moody’s Investor Service, Inc.
Third Amended and Restated Credit Agreement
On May 19, 2011, in connection with the Massey Acquisition, we entered into a Third Amended and Restated Credit Agreement to amend and restate in its entirety our credit agreement dated as of July 30, 2004, as amended as of November 12, 2004 and as of October 18, 2005, as amended and restated as of July 7, 2006, as amended effective July 31, 2009 and as further amended and restated as of April 15, 2010 (as so amended and restated, the “Former Credit Agreement”; the Former Credit Agreement, as amended and restated by the Third Amended and Restated Credit Agreement, is referred to as the “New Credit Agreement”), with Citicorp North America, Inc., as administrative agent and as collateral agent, Bank of America, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, The Royal Bank of Scotland plc and Union Bank, N.A. and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as co-documentation agents, Morgan Stanley Senior Funding, Inc., as sole syndication agent, Citigroup Global Markets Inc. and Morgan Stanley Senior Funding, Inc., as joint lead arrangers and joint book managers, and various other financial institutions, as lenders. The terms of the New Credit Agreement amended and restated and superseded the Former Credit Agreement in its entirety upon the satisfaction of certain conditions precedent, which included the consummation of the Massey Acquisition (the satisfaction of such conditions precedent is referred to as the “initial Credit Event”). The Former Credit Agreement remained in full force and effect until the occurrence of the initial Credit Event.
Upon the occurrence of the initial Credit Event, the New Credit Agreement provided for a $600.0 million senior secured term loan A facility (the “Term Loan Facility”) and a $1.0 billion senior secured revolving credit facility (the “Revolving Facility”). Pursuant to the New Credit Agreement, we may request incremental term loans or increase the revolving commitments under the Revolving Facility in an aggregate amount of up to $1.3 billion plus an additional $750.0 million subject to compliance with a consolidated senior secured leverage ratio. The lenders under these facilities will not be under any obligation to provide any such incremental loans or commitments, and any such addition of or increase in such loans or commitments will be subject to certain customary conditions precedent.
As of December 31, 2011, the carrying value of the Term Loan Facility was $584.3 million, net of debt discount of $0.7 million, with $45.0 million classified as current portion of long-term debt. There were no borrowings outstanding under the Revolving Facility as of December 31, 2011. Letters of credit outstanding at December 31, 2011 under the Revolving Facility were $0.3 million.
Interest Rate and Fees. Borrowings under the New Credit Agreement bear interest at a rate per annum equal to an applicable margin plus, at our option, either (a) a base rate determined by reference to the highest of (i) the rate that Citibank, N.A. announces from time to time as its prime or base commercial lending rate, (ii) the federal funds effective rate plus 0.50% and (iii) a London Interbank Offer (“LIBO”) rate for a 30-day interest period as determined on such day, plus 1.00%, or (b) a LIBO rate for the interest period relevant to such borrowing adjusted for certain additional costs. The initial applicable margin for borrowings under the New Credit Agreement is 1.50% with respect to base rate borrowings and 2.50% with respect to LIBO rate borrowings. Commencing October 1, 2011, the applicable margin for borrowings under the New Credit Agreement became subject to adjustment each fiscal quarter based on our consolidated leverage ratio for the preceding fiscal quarter. Swingline loans bear interest at a rate per annum equal to the base rate plus the applicable margin. The interest rate in effect at December 31, 2011 was 2.51%. In
addition to paying interest on outstanding principal under the New Credit Agreement, we are required to pay a commitment fee to the lenders under the Revolving Facility in respect of the unutilized commitments thereunder. The initial commitment fee is 0.50% per annum. Commencing October 1, 2011, the commitment fee became subject to adjustment each fiscal quarter based on our consolidated leverage ratio for the preceding fiscal quarter. We must also pay customary letter of credit fees and agency fees.
Mandatory Prepayments. The New Credit Agreement requires us to prepay outstanding loans, subject to certain exceptions, with (i) 100% of the net cash proceeds (including the fair market value of noncash proceeds) from certain asset sales and condemnation events in excess of the greater of $1.5 billion and 15% of consolidated tangible assets as of the end of each fiscal year, (ii) 100% of the aggregate gross proceeds (including the fair market value of noncash proceeds) from certain Intracompany Disposals (as defined in the New Credit Agreement) exceeding $500.0 million during the term of the New Credit Agreement and (iii) 100% of the net cash proceeds from any incurrence or issuance of certain debt, other than debt permitted under the New Credit Agreement. Mandatory prepayments will be applied first to the Term Loan Facility and thereafter to reductions of the commitments under the Revolving Facility. If at any time the aggregate amount of outstanding revolving loans, swingline loans, unreimbursed letter of credit drawings and undrawn letters of credit under the Revolving Facility exceeds the commitment amount, we will be required to repay outstanding loans or cash collateralize letters of credit in an aggregate amount equal to such excess, with no reduction of the commitment amount.
Voluntary Prepayments; Reductions in Commitments. We may prepay, in whole or in part, amounts outstanding under the New Credit Agreement, with prior notice but without premium or penalty (other than customary “breakage” costs with respect to LIBO rate loans) and in certain minimum amounts. We may also repurchase loans outstanding under the Term Loan Facility pursuant to standard reverse Dutch auction and open market purchase provisions, subject to certain limitations and exceptions. We may make voluntary reductions to the unutilized commitments of the Revolving Facility from time to time without premium or penalty.
Amortization and Final Maturity. Beginning on September 30, 2011, we became required to make scheduled quarterly amortization payments with respect to loans under the Term Loan Facility. In the last two quarters of 2011 and the first two quarters of 2012, each quarterly amortization payment was and will be in an amount equal to 1.25% of the original principal amount of the term loans. In the last two quarters of 2012 and the first two quarters of 2013, each quarterly amortization payment will be in an amount equal to 2.5% of the original principal amount of the term loans. In the last two quarters of 2013 and the first two quarters of 2014, each quarterly amortization payment will be in an amount equal to 3.75% of the original principal amount of the term loans. In the last two quarters of 2014 and the first two quarters of 2015, each quarterly amortization payment will be in an amount equal to 5% of the original principal amount of the term loans. In the last two quarters of 2015 and the first two quarters of 2016, each quarterly amortization payment will be in an amount equal to 12.5% of the original principal amount of the term loans. There is no scheduled amortization under the Revolving Facility. The principal amount outstanding on the loans under the Revolving Facility will be due and payable on June 30, 2016. The Term Loan Facility and Revolving Facility will each mature on June 30, 2016.
Guarantees and Collateral. All obligations under the New Credit Agreement are unconditionally guaranteed by certain of our existing wholly owned domestic subsidiaries, and are required to be guaranteed by certain of our future wholly owned domestic subsidiaries. All obligations under the New Credit Agreement and certain hedging and cash management obligations with lenders and affiliates of lenders thereunder are secured, subject to certain exceptions, by substantially all of our assets and the assets of our subsidiary guarantors, in each case subject to exceptions, thresholds and limitations.
Certain Covenants and Events of Default. The New Credit Agreement contains a number of negative covenants that, among other things and subject to certain exceptions, restrict our ability and the ability of our subsidiaries to:
· make investments, loans and acquisitions;
· incur additional indebtedness;
· incur liens;
· consolidate or merge;
· sell assets, including capital stock of its subsidiaries;
· pay dividends on its capital stock or redeem, repurchase or retire its capital stock or its other Indebtedness;
· engage in transactions with its affiliates;
· materially alter the business it conducts; and
· create restrictions on the payment of dividends or other amounts to Alpha from Alpha’s restricted subsidiaries.
In addition, the New Credit Agreement requires us to comply with certain financial ratio maintenance covenants.
The New Credit Agreement also contains customary representations and warranties, affirmative covenants and events of default, including a cross-default provision in respect of any other indebtedness that has an aggregate principal amount exceeding $25.0 million.
Former Credit Agreement
The Former Credit Agreement consisted of term loans and revolving credit facility commitments due on July 31, 2014. During the year ended December 31, 2011, borrowings under the Former Credit Agreement totaling $227.9 million were repaid. The Former Credit Agreement was replaced with the New Credit Agreement as described above. As of December 31, 2010, our secured term loans under the Former Credit Agreement had a carrying value of $226.7 million, net of debt discount of $1.2 million, with $11.8 million classified as current portion of long-term debt.
3.25% Convertible Senior Notes due 2015
As a result of the Massey Acquisition, we became a guarantor of Massey’s 3.25% Convertible Notes, with aggregate principal outstanding at June 1, 2011 of $659.1 million. The 3.25% Convertible Notes bear interest at a rate of 3.25% per annum, payable semi-annually in arrears on August 1 and February 1 of each year. The 3.25% Convertible Notes will mature on August 1, 2015, unless earlier repurchased by us or converted. The 3.25% Convertible Notes had a fair value of $730.9 million at the acquisition date. We account for the 3.25% Convertible Notes under Accounting Standards Codification (“ASC”) 470-20, which requires issuers of convertible debt instruments that may be settled wholly or partially in cash upon conversion to separately account for the liability and equity components in a manner reflective of the issuers’ nonconvertible debt borrowing rate. As of December 31, 2011, the carrying amount of the debt was $624.9 million, net of debt discount of $33.7 million. As of December 31, 2011, the carrying amount of the equity component totaled $110.4 million. The debt discount is being accreted over the four-year term of the 3.25% Convertible Notes, and provides for an effective interest rate of 4.21%.
The 3.25% Convertible Notes are senior unsecured obligations and rank equally with all of our existing and future senior unsecured indebtedness. The 3.25% Convertible Notes are guaranteed on a senior unsecured basis by Massey’s subsidiaries (which are among our subsidiaries), other than certain minor subsidiaries of Massey. The 3.25% Convertible Notes are effectively subordinated to all our existing and future secured indebtedness and all existing and future liabilities of our non-guarantor subsidiaries, including trade payables. The 3.25% Convertible Notes are convertible in certain circumstances and in specified periods at a conversion rate, subject to adjustment, of the value of 11.4560 shares of common stock per $1,000 principal amount of 3.25% Convertible Notes. From and after the effective date of the Massey Acquisition, the consideration deliverable upon conversion of the 3.25% Convertible Notes ceased to be based upon Massey common stock and instead became based upon Reference Property (as defined in the indenture governing the 3.25% Convertible Notes, (the “3.25% Convertible Notes Indenture”)) consisting of 1.025 shares of our common stock (subject to adjustment upon the occurrence of certain events set forth in the 3.25% Convertible Notes Indenture) plus $10.00 in cash per share of Massey common stock. Upon conversion of the 3.25% Convertible Notes, holders will receive cash up to the principal amount of the notes being converted, and any excess conversion value will be delivered in cash, Reference Property, or a combination thereof, at our election. One of the circumstances under which the 3.25% Convertible Notes would become convertible is if the Company’s common stock price exceeds a set threshold during a reference period specified in the 3.25% Convertible Notes Indenture.
The 3.25% Convertible Notes Indenture contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee or the holders of at least 25% in aggregate principal amount of the 3.25% Convertible Notes then outstanding may declare the principal of the 3.25% Convertible Notes and any accrued and unpaid interest immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to the Company, the principal amount of the 3.25% Convertible Notes together with any accrued and unpaid interest thereon will automatically become due and immediately payable.
The 3.25% Convertible Notes were not convertible as of December 31, 2011 and as a result have been classified as long-term.
6.875% Senior Notes due 2013
We assumed Massey’s 2013 Notes with an aggregate principal amount outstanding of $760.0 million as part of the Massey Acquisition. Following a cash tender offer for the 2013 Notes and upon redemption of the 2013 Notes on the redemption date of July 1, 2011, we recorded a loss on early extinguishment of $0.8 million.
7.25% Senior Notes Due August 1, 2014
Foundation PA, one of our subsidiaries, had notes that were scheduled to mature on August 1, 2014 (the “2014 Notes”) in the aggregate principal amount of $298.3 million as of December 31, 2010. The outstanding 2014 Notes were redeemed and became due and payable on August 18, 2011, the Redemption Date, at a redemption price equal to 101.208% of the principal amount of the 2014 Notes, plus any and all accrued and unpaid interest up to but excluding the Redemption Date. We paid $302.9 million, including interest, to redeem the 2014 Notes. We recognized a loss on early extinguishment of debt of $4.4 million, including the premium paid. As of December 31, 2010, the carrying value of the 2014 Notes was $297.3 million, net of debt discount of $1.0 million.
2.375% Convertible Senior Notes Due April 15, 2015
As of December 31, 2011 and 2010, we had $287.5 million aggregate principal amount of 2.375% convertible senior notes due April 15, 2015 (the “2.375% Convertible Notes”). The 2.375% Convertible Notes bear interest at a rate of 2.375% per annum, payable semi-annually in arrears on April 15 and October 15 of each year, and will mature on April 15, 2015, unless previously repurchased by us or converted. We separately account for the liability and
equity components of its 2.375% Convertible Notes under ASC 470-20, which requires issuers of convertible debt instruments that may be settled wholly or partially in cash upon conversion to separately account for the liability and equity components in a manner reflective of the issuers’ nonconvertible debt borrowing rate. The related deferred loan costs and discount are being amortized and accreted, respectively, over the seven-year term of the 2.375% Convertible Notes, and provide for an effective interest rate of 8.64%. As of December 31, 2011 and 2010, the carrying amounts of the debt component were $235.3 million and $222.4 million, respectively. As of December 31, 2011 and 2010, the unamortized debt discount was $52.2 million and $65.1 million, respectively. As of December 31, 2011 and 2010, the carrying amount of the equity component was $69.9 million.
The 2.375% Convertible Notes are our senior unsecured obligations and rank equally with all of our existing and future senior unsecured indebtedness. The 2.375% Convertible Notes are effectively subordinated to all of our existing and future secured indebtedness and all existing and future liabilities of our subsidiaries, including trade payables. The 2.375% Convertible Notes are convertible in certain circumstances and in specified periods at an initial conversion rate of 18.2962 shares of common stock per one thousand principal amount of 2.375% Convertible Notes, subject to adjustment upon the occurrence of certain events set forth in the indenture governing the 2.375% Convertible Notes (the “2.375% Convertible Notes Indenture”). Upon conversion of the 2.375% Convertible Notes, holders will receive cash up to the principal amount of the notes to be converted, and any excess conversion value will be delivered in cash, shares of common stock or a combination thereof, at our election.
The 2.375% Convertible Notes Indenture contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee, Union Bank of California, or the holders of not less than 25% in aggregate principal amount of the 2.375% Convertible Notes then outstanding may declare the principal of 2.375% Convertible Notes and any accrued and unpaid interest thereon immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us, the principal amount of the 2.375% Convertible Notes together with any accrued and unpaid interest thereon will automatically become due and be immediately payable.
The 2.375% Convertible Notes were not convertible as of December 31, 2011 and 2010 and therefore have been classified as long-term debt.
Analysis of Material Debt Covenants
We were in compliance with all covenants under the New Credit Agreement and the indentures governing our notes as of December 31, 2011. A breach of the covenants in the New Credit Agreement or the indentures governing our notes, including the financial covenants under the New Credit Agreement that measure ratios based on Adjusted EBITDA, could result in a default under the New Credit Agreement or the indentures governing our notes and the respective lenders and note holders could elect to declare all amounts borrowed due and payable. Any acceleration under either the New Credit Agreement or one of the indentures governing our notes would also result in a default under the other indentures governing our notes. Additionally, under the New Credit Agreement and the indentures governing our notes our ability to engage in activities such as incurring additional indebtedness, making investments and paying dividends is also tied to ratios based on Adjusted EBITDA.
Covenants and required levels set forth in the New Credit Agreement are:
Adjusted EBITDA is defined as EBITDA further adjusted to exclude certain non-cash items, non-recurring items, and other adjustments permitted in calculating covenant compliance under the New Credit Agreement. EBITDA, a measure used by management to evaluate its ongoing operations for internal planning and forecasting purposes, is defined as net income (loss) from operations plus interest expense, income tax expense, amortization of acquired intangibles, net and depreciation, depletion and amortization, less interest income and income tax benefit. EBITDA is not a financial measure recognized under United States generally accepted accounting principles and does not purport to be an alternative to net income as a measure of operating performance or to cash flows from operating activities as a measure of liquidity. The amounts shown for EBITDA as presented may differ from amounts calculated and may not be comparable to other similarly titled measures used by other companies.
Certain non-cash items that may adjust EBITDA in the compliance calculation are: (a) accretion on asset retirement obligations; (b) amortization of intangibles; (c) any long-term incentive plan accruals or any non-cash compensation expense recorded from grants of stock appreciation or similar rights, stock options or other rights to officers, directors and employees; and (d) gains or losses associated with the change in fair value of derivative instruments. Certain non-recurring items that may adjust EBITDA in the compliance calculation are: (a) business optimization expenses or other restructuring charges; (b) non-cash impairment charges; (c) certain non-cash expenses or charges arising as a result of the application of acquisition accounting; (d) non-cash charges associated with loss on early extinguishment of debt; and (e) charges associated with litigation, arbitration, or contract settlements. Certain other items that may adjust EBITDA in the compliance calculation are: (a) after-tax gains or losses from discontinued operations; (b) franchise taxes; and (c) other non-cash expenses that do not represent an accrual or reserve for future cash expense.
The calculation of adjusted EBITDA shown below is based on our results of operations in accordance with the Facility and therefore, is different from EBITDA presented elsewhere in this Annual Report on Form 10-K.
(1) Calculated in accordance with the New Credit Agreement
Cash interest is calculated in accordance with the New Credit Agreement and is equal to interest expense less interest income and non-cash interest expense plus pro forma interest expense. Cash interest for the twelve months ended December 31, 2011 is calculated as follows (in thousands):
(1) Calculated in accordance with the New Credit Agreement
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, operating leases, indemnifications and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. Liabilities related to these arrangements are not reflected in our Consolidated Balance Sheets. However, the underlying obligations that they secure, such as asset retirement obligations, self-insured workers’ compensation liabilities, royalty obligations and certain retiree medical obligations, are reflected in our Consolidated Balance Sheets.
We are required to provide financial assurance in order to perform the post-mining reclamation required by our mining permits, pay our federal production royalties, pay workers’ compensation claims under self-insured workers’ compensation laws in various states, pay federal black lung benefits, pay retiree health care benefits to certain retired UMWA employees and perform certain other obligations. In order to provide the required financial assurance, we generally use surety bonds and self-bonding for post-mining reclamation and bank letters of credit
for self-insured workers’ compensation obligations and UMWA retiree health care obligations. Federal black lung benefits are paid from a dedicated trust fund to which future contributions will be required. Bank letters of credit are also used to collateralize a portion of the surety bonds.
We had outstanding surety bonds with a total face amount of $942.8 million as of December 31, 2011 to secure various obligations and commitments. In addition, we had $160.3 million of letters of credit in place, of which $0.3 million was outstanding under the New Credit Agreement, and $160.0 million was outstanding under our A/R Facility. These outstanding letters of credit served as collateral for workers’ compensation bonds, reclamation surety bonds, secured UMWA retiree health care obligations, secured workers’ compensation obligations and other miscellaneous obligations. In the event that additional surety bonds or self-bonding capacity become unavailable, we would seek to secure our obligations with letters of credit, cash deposits or other suitable forms of collateral.
Other
As a regular part of our business, we review opportunities for, and engage in discussions and negotiations concerning, the acquisition of coal mining assets and interests in coal mining companies, and acquisitions of, or combinations with, coal mining companies. When we believe that these opportunities are consistent with our growth plans and our acquisition criteria, we will make bids or proposals and/or enter into letters of intent and other similar agreements. These bids or proposals, which may be binding or nonbinding, are customarily subject to a variety of conditions and usually permit us to terminate the discussions and any related agreement if, among other things, we are not satisfied with the results of our due diligence investigation. Any acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. There can be no assurance that additional financing will be available on terms acceptable to us, or at all.
Contractual Obligations
The following is a summary of our significant contractual obligations as of December 31, 2011 (in thousands):
(1) Long-term debt includes principal amounts due in the years shown. Cash interest payable on these obligations, with interest rates ranging between 2.375% and 6.25% on our loans, would be approximately $134.3 million in 2012, $263.7 million in 2013 to 2014, $216.3 million in 2015 to 2016 and $309.0 million after 2016.
(2) Other debt includes principal amounts due in the years shown. Cash interest payable on these obligation, with interest rates ranging between 6.132% and 13.86%, would be approximately $4.4 million in 2012, $4.6 million in 2013 to 2014, $4.4 million in 2015 to 2016, and $29.9 million after 2016.
Additionally, we have long-term liabilities relating to asset retirement obligations, postretirement, pension, workers’ compensation and black lung benefits. The table below reflects the estimated undiscounted cash flows for these obligations (in thousands):
We currently expect to make contributions in 2012 in the range of $25.0 million to $30.0 million for our defined benefit pension plans.
We expect to spend between $550.0 million and $750.0 million on capital expenditures during 2012, which includes a portion of the Company’s commitment to invest $80.0 million for mine safety over the next two years. Additionally, over the next two years, we plan to establish a $48.0 million trust fund to fund research and development projects designed to improve mine health and safety.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). GAAP requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and on various other factors and assumptions, including the current economic environment that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate our estimates and assumptions on an ongoing basis and adjust such estimates and assumptions as facts and circumstances require. Illiquid credit markets, volatile equity, foreign currency and energy markets, and declines in demand for steel products have combined to increase the uncertainty inherent in such estimates and assumptions. As future events and their effects cannot be determined with precision, actual results may differ significantly from these estimates. Changes in these estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Derivatives Instruments and Hedging Activities. We are subject to the risk of price volatility for certain of the materials and supplies used in production, such as diesel fuel and explosives and for the amount we receive for the sale of natural gas. As a part of our risk management strategy, we enter into options and pay fixed, receive variable and pay variable, receive fixed swap agreements with financial institutions to mitigate the risk of price volatility for both diesel fuel and explosives and sales of natural gas, respectively. Options and swap agreements are derivative instruments that we are required to recognize as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The accounting requirements for derivatives are complex and judgment is required in certain areas such as cash flow hedge accounting and hedge effectiveness testing. We assess each option or swap agreement to determine whether or not it qualifies for special cash flow hedge accounting. In performing the assessment, we make estimates and assumptions about the timing and amounts of future cash flows related to the forecasted purchases of diesel fuel and explosives and sales of natural gas. We update our assessments at least on a quarterly basis.
Reclamation. Our asset retirement obligations arise from the federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, sealing portals at deep mines and the treatment of water. We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. We are also faced with increasingly stringent safety standards and governmental regulation, much of which is beyond our control, which could increase our costs and materially increase our asset retirement obligations. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based upon third-party costs. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. Our asset retirement obligations are initially recorded at fair value. In order to determine fair value, we use assumptions including a discount rate and third-party margin. Each is discussed further below:
· Discount Rate. Asset retirement obligations are initially recorded at fair value. We utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.
· Third-Party Margin. The measurement of an obligation is based upon the amount a third party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin was added to the estimated costs of these activities. This margin was estimated based upon our historical experience with contractors performing similar types of reclamation activities. The inclusion of this margin will result in a recorded obligation that is greater than our estimates of our cost to perform the reclamation activities. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is completed.
On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revisions to cost estimates and productivity assumptions, to reflect current experience. At December 31, 2011, we had recorded asset retirement obligation liabilities of $915.7 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2011, we estimate that the aggregate undiscounted cost of final mine closures is approximately $1.3 billion.
Coal Reserves. There are numerous uncertainties inherent in estimating quantities of economically recoverable coal reserves, many of which are beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled by our internal engineers and geologists and reviewed by a third party consultant. Some of the factors and assumptions that impact economically recoverable reserve estimates include:
· geological conditions;
· historical production from the area compared with production from other producing areas;
· the assumed effects of regulations and taxes by governmental agencies;
· assumptions governing future prices; and
· future operating costs.
Each of these factors may vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and these variances may be material. Variances could affect our projected future revenues and expenditures, as well as the valuation of coal reserves and depletion rates. At December 31, 2011, we had 4,677.4 million tons of proven and probable coal reserves, of which 2,337.7 million tons were assigned to our active operations and 2,339.7 million tons were unassigned.
Postretirement Medical Benefits. We have long-term liabilities for postretirement medical benefit cost obligations. Detailed information related to these liabilities is included in Note 17 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K. Liabilities for postretirement medical benefit costs are not funded. The liability is actuarially determined, and we use various actuarial assumptions, including a discount rate and future health care cost trends, to estimate the costs and obligations for postretirement medical benefit costs. The discount rates used to determine the net periodic benefit cost for postretirement medical benefits ranged from 4.37% to 5.28% for the various plans for the year ended December 31, 2011. At December 31, 2011, we had total postretirement medical benefit obligations of $1,079.4 million.
The estimated impact of changes to the healthcare cost trend rate and discount rate is as follows:
Retirement Plans. We have three non-contributory defined benefit retirement plans (the “Pension Plans”) covering certain of our salaried and non-union hourly employees. We also have two unfunded non-qualified Supplemental Executive Retirement Plans (“SERPs”) covering certain eligible employees. Benefits are based on either the employee’s compensation prior to retirement or stated amounts for each year of service with us. Funding of the defined benefit retirement plans is in accordance with the requirements of ERISA, which can be deducted for federal income tax purposes. We contributed $70.4 million to our defined benefit retirement plans for the year ended December 31, 2011. For the year ended December 31, 2011, we recorded net periodic benefit expense of $0.3 million for our Pension Plans and SERPs and have recorded net obligations of $174.7 million.
The calculation of the net periodic benefit expense and projected benefit obligation associated with our Pension Plans and SERPs requires the use of a number of assumptions that we deem to be “critical accounting estimates.” These assumptions are used by our independent actuaries to make the underlying calculations. Changes in these assumptions can result in different net periodic benefit expense and liability amounts, and actual experience can differ from the assumptions.
· The expected long-term rate of return on plan assets is an assumption of the rate of return on plan assets reflecting the average rate of earnings expected on the funds invested or to be invested to provide for the benefits included in the projected benefit obligation. We establish the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The Pension Plans investment targets are 45% equity funds and 55% fixed income funds. Investments are rebalanced on a periodic basis to stay within these targeted guidelines. The long-term rate of return assumption used to determine net periodic benefit expense was 7.75% for the year ended December 31, 2011. Any difference between the actual experience and the assumed experience is deferred as an unrecognized actuarial gain or loss and amortized into expense in future periods.
· The discount rate represents our estimate of the interest rate at which pension benefits could be effectively settled. Assumed discount rates are used in the measurement of the projected, accumulated and vested benefit obligations and the service and interest cost components of the net periodic benefit expense. In estimating that rate, we use rates of return on high quality, fixed income investments. The discount rates used to determine pension expense ranged from 4.32% to 5.51% for the year ended December 31, 2011. The differences resulting from actual versus assumed discount rates are amortized into pension expense over the remaining average life of the active plan participants. A one half percentage-point increase in the discount rate would increase the net periodic pension cost for the year ended December 31, 2011 by less than $1.0 million and decrease the projected benefit obligation as of December 31, 2011 by approximately $54.9 million. The corresponding effects of a one half of one percentage-point decrease in the discount rate would be less than a $1.0 million increase in the net periodic pension cost and approximately a $59.5 million increase in the projected benefit obligation.
Workers’ Compensation. Workers’ compensation is a system by which individuals who sustain personal injuries due to job-related accidents are compensated for their disabilities, medical costs, and on some occasions, for the costs of their rehabilitation, and by which the survivors of workers who suffer fatal injuries receive compensation for lost financial support. The workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee who is injured in the course of employment. Our obligations are covered through a combination of a self-insurance program and third party insurance policies. We accrue for any self-insured liability by recognizing costs when it is probable that a covered liability has been incurred and the cost can be reasonably estimated. Our estimates of these costs are adjusted based upon actuarial studies. Actual losses may differ from these estimates, which could increase or decrease our costs. At December 31, 2011, we had workers’ compensation obligations of $187.6 million.
Coal Workers’ Pneumoconiosis. We are required by federal and state statutes to provide benefits to employees for awards related to coal workers’ pneumoconiosis disease (black lung). Certain of our subsidiaries are insured for workers’ compensation and black lung obligations by a third-party insurance provider. Certain subsidiaries in West Virginia are self-insured for workers’ compensation and state black lung obligations. Certain other subsidiaries are self-insured for black lung benefits and fund benefit payments through a Section 501(c)(21) tax-exempt trust fund. Provisions are made for estimated benefits based on annual evaluations prepared by independent actuaries. In addition, for our subsidiaries in Wyoming, we participate in a compulsory state-run fund.
Charges are made to operations for self-insured black lung claims, as determined by an independent actuary at the present value of the actuarially computed liability for such benefits over the employee’s applicable term of service. As of December 31, 2011, we had black lung obligations of $157.5 million, which are net of assets of $3.1 million that are held in a tax exempt trust fund.
Business Combinations. We account for our business combinations under the acquisition method of accounting. The total cost of acquisitions is allocated to the underlying identifiable net tangible and intangible assets based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, the utilization of independent valuation experts and often involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items.
Income Taxes. We recognize deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In evaluating the need for a valuation allowance, we analyze both positive and negative evidence. Such evidence includes objective evidence obtained from our historical earnings, future sales commitments, outlooks on the coal industry by us and third parties, expected level of future earnings (with sensitivities on expectations considered), timing of temporary difference reversals, ability or inability to meet forecasted earnings, unsettled industry circumstances, ability to utilize net operating losses, available tax planning strategies, limitations on deductibility of temporary differences, and the impact the alternative minimum tax has on utilization of deferred tax assets. The valuation allowance is monitored and reviewed quarterly. If our conclusions change in the future regarding the realization of a portion or all of our net deferred tax assets, we may record a change to the valuation allowance through income tax expense in the period the determination is made, which may have a material impact on our results. As of December 31, 2011, we were in a net deferred tax liability position with tax computed at regular tax rates on the gross temporary differences. Federal tax attributes related to minimum tax credit carry-forwards and federal and state net operating losses offset the tax effect of the temporary differences somewhat. A valuation allowance of $64.5 million has been provided on certain state net operating losses not expected to provide future tax benefits.
Goodwill. Goodwill represents the excess of purchase price over the fair value of the identifiable net assets of acquired companies. Goodwill is not amortized; instead, it is tested for impairment annually or more frequently if indicators of impairment exist. On an ongoing basis, absent any impairment indicators, we perform our goodwill impairment testing as of October 31 of each year.
We test goodwill for impairment using a fair value approach at the reporting unit level. We perform our goodwill impairment test in two steps. Step one compares the fair value of each reporting unit to its carrying value, including goodwill. If the fair value of a reporting unit determined in step one is lower than its carrying value, we proceed to step two, which compares the carrying value of goodwill to its implied fair value. Any excess of carrying value of goodwill over its implied fair value at a reporting unit is recorded as impairment.
The valuation methodology utilized in step one to estimate the fair value of the reporting units is based on both a market and income approach and is within the range of fair values yielded under each approach. The income approach is based on a discounted cash flow methodology in which expected future net cash flows are discounted to present value, using an appropriate after-tax weighted average cost of capital (discount rate). The market approach is based on a guideline company and similar transaction methodology. Under the guideline company approach, certain operating metrics from a selected group of publically traded guideline companies that have similar operations to the Company’s reporting units are used to estimate the fair value of the reporting units. Under the similar transaction approach, recent merger and acquisition transactions for companies that have similar operations to the Company’s reporting units are used to estimate the fair value of the Company’s reporting units.
The income approach is dependent upon a number of significant management estimates about future performance including, sales volumes and prices, costs to produce, income taxes, capital spending, working capital changes and the after-tax weighted average cost of capital. Changes in any of these assumptions could materially impact the estimated fair value of our reporting units. Our forecasts of coal prices generally reflect a long-term outlook of market prices expected to be received for our coal. If actual coal prices are less than our expectations, it could have a material impact on the fair value of our reporting units. Our forecasts of costs to produce coal are based on our operating forecasts and an assumed inflation rate for materials and supplies such as steel, diesel fuel and explosives. If actual costs are higher or if inflation increases above our expectations, it could have a material impact on the fair value of our reporting units. We also are faced with increasingly stringent safety standards and governmental regulation, much of which is beyond our control, which could increase our costs and materially decrease the fair value of our reporting units.
In step two of the goodwill impairment test, we compared the carrying value of goodwill to its implied fair value. In estimating the implied fair value of goodwill at a reporting unit, we assigned the fair value of the reporting unit to all of the assets and liabilities associated with the reporting unit as if the reporting unit had been acquired in a business combination.
We performed our annual goodwill impairment testing as of October 31, 2011 and recorded impairment charges of $745.3 million to reduce the carrying value of goodwill to its implied fair value of $975.1 million for four of our reporting units in Eastern Coal Operations.
The fair values of two of our reporting units in Eastern Coal Operations and our single reporting unit in Western Coal Operations exceeded their carrying values by 5%, 8% and 5%, respectively, and the carrying value of goodwill at those reporting units as of December 31, 2011 was $260.4 million, $258.9 million, and $53.3 million, respectively. A 100 basis point increase or decrease in the discount rate would impact the fair values of these reporting units by approximately $81.5 million, or 4%, and a 1% increase or decrease in the estimated operating margin would impact the fair values of these reporting units by approximately $15.0 million, or 1%.
The fair values of our other reporting units exceeded their carrying values by a total of $1.8 billion, or 63%.
Contingencies. We are parties to a number of legal proceedings. These matters include personal injury claims, environmental issues and other matters more fully described in Note 20 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K. We record accruals based on an estimate of the ultimate outcome of these matters, however these matters are difficult to predict and involve significant judgment by management.
New accounting pronouncements. See Note 2 in the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K for disclosures related to new accounting policies adopted.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
We manage our commodity price risk for coal sales through the use of long-term coal supply agreements. As of February 8, 2012, we had sales commitments for approximately 93% of planned shipments for 2012. Uncommitted and unpriced tonnage was 7%, 49% and 74% for 2012, 2013 and 2014, respectively. The discussion below presents the sensitivity of the market value of selected financial instruments to selected changes in market rates and prices. The range of changes reflects our view of changes that are reasonably possible over a one-year period. Market values are the present value of projected future cash flows based on the market rates and prices chosen.
We have exposure to price risk for supplies that are used directly or indirectly in the normal course of production such as diesel fuel, steel and other items such as explosives. We manage our risk for these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivative instruments from time to time, primarily swap contracts with financial institutions, for a certain percentage of our monthly requirements. Swap agreements essentially fix the price paid for our diesel fuel and explosives by requiring us to pay a fixed price and receive a floating price.
We expect to use approximately 38,101 tons of explosives in 2012. Through our derivative swap contracts, we have fixed prices for approximately 34% of our expected explosive needs in 2012. If the price of natural gas were to decrease in 2012, our expense resulting from our natural gas derivatives would increase, which would be largely offset by a decrease in the cost of our physical explosive purchases.
We expect to use approximately 92.9 million gallons and 91.7 million gallons of diesel fuel in 2012 and 2013, respectively. Through our derivative swap contracts, we have fixed prices for approximately 59% and 34% of our expected diesel fuel needs for 2012 and 2013, respectively. If the price of diesel fuel were to decrease in 2012, our expense resulting from our diesel fuel derivative swap contracts would increase, which would be offset by a decrease in the cost of our physical diesel fuel purchases.
We also sell coalbed methane through our Coal Gas Recovery business. The revenues derived from the sale of coalbed methane are subject to volatility based on the changes in natural gas prices. In order to reduce that risk, we enter into “pay variable, receive fixed” natural gas swaps for a portion of our anticipated gas production in order to fix the selling price for a portion of our production. The natural gas swaps have been designated as qualifying cash flow hedges. As of December 31, 2011, we had swap agreements outstanding to hedge the variable cash flows related to approximately 78% and 64% of anticipated natural gas production in 2012 and 2013, respectively.
Credit Risk
Our credit risk is primarily with electric power generators and steel producers. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor outstanding accounts receivable against established credit limits. When appropriate (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay.
Interest Rate Risk
Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. As we continue to monitor the interest rate environment in concert with our risk mitigation objectives, consideration is being given to future interest rate risk reduction strategies.
We have exposure to changes in interest rates through our New Credit Agreement, which has a variable interest rate of 2.5 percentage points over the LIBO rate, subject, in the case of the revolving credit line, to adjustment based on leverage ratios. As of December 31, 2011, our term loan due 2016 under the New Credit Agreement had an outstanding balance of $584.3 million, net of debt discount of $0.7 million. The current portion of the term loan due in the next twelve months was $45.0 million. A 50 basis point increase or decrease in interest rates would increase or decrease our interest expense by $0.8 million, which would be partially offset by our interest rate swap.
To achieve risk mitigation objectives, we have in the past managed our interest rate exposure through the use of interest rate swaps. To reduce our exposure to rising interest rates, effective May 22, 2006 we entered into an interest rate swap to reduce the risk that changing interest rates could have on our operations. The swap initially qualified for cash flow hedge accounting and changes in fair value were recorded as a component of equity; however, the underlying debt instrument was subsequently paid in 2009 and the swap no longer qualified for cash flow hedge accounting. The amounts that were previously recorded in equity of $17.7 million, net of tax, were recognized in our Consolidated Statements of Operations in 2009. Subsequent changes in fair value of the interest rate swaps are recorded in earnings. If interest rates were to decrease in 2011, our expense resulting from our interest rate swap would increase, which would be partially offset by a decrease in the amount of actual interest paid on our Facility.
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Alpha Natural Resources, Inc.:
We have audited the accompanying consolidated balance sheets of Alpha Natural Resources, Inc. and subsidiaries (the Company) as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Alpha Natural Resources, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 29, 2012 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. In conducting its assessment of the effectiveness of internal control over financial reporting, management of the Company excluded the internal control over financial reporting relating to Massey Energy Company (Massey) (with the exception of sales revenue, income taxes, asset retirement obligations, derivative financial instruments, and long-term debt, which have already been integrated into the Company’s internal control over financial reporting), which the Company acquired on June 1, 2011. Massey’s total assets of $10.8 billion and total revenues of $1.9 billion are included in the Company’s consolidated financial statements as of and for the year ended December 31, 2011. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Massey.
/s/ KPMG LLP
Roanoke, Virginia
February 29, 2012
ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands, except share and per share data)
See accompanying Notes to Consolidated Financial Statements.
ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share and per share data)
See accompanying Notes to Consolidated Financial Statements.
ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
See accompanying Notes to Consolidated Financial Statements.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)
(Amounts in thousands, except per share data)
See accompanying Notes to Consolidated Financial Statements.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(1) Business and Basis of Presentation
Business
Alpha Natural Resources, Inc. and its consolidated subsidiaries (the “Company”) are primarily engaged in the business of extracting, processing and marketing steam and metallurgical coal from surface and deep mines, and mainly sell to electric utilities, steel and coke producers, and industrial customers. The Company, through its subsidiaries, is also involved in marketing coal produced by others to supplement its own production and, through blending, provides its customers with coal qualities beyond those available from its own production.
On July 31, 2009, Alpha Natural Resources, Inc. (“Old Alpha”) and Foundation Coal Holdings, Inc. (“Foundation”) merged (the “Foundation Merger”) with Foundation continuing as the surviving legal corporation of the Foundation Merger. Subsequent to the Foundation Merger, Foundation was renamed Alpha Natural Resources, Inc. (the “Company” or “Alpha”). For financial accounting purposes, the Foundation Merger was treated as a reverse acquisition and Old Alpha was treated as the accounting acquirer. For the year ended December 31, 2009, Foundation’s financial results are included for the five month period August 1, 2009 through December 31, 2009. See Note 3 for further disclosures related to the Foundation Merger.
On June 1, 2011, pursuant to the terms of the previously announced Agreement and Plan of Merger dated as of January 28, 2011 (the “Merger Agreement”), the Company completed its acquisition (the “Massey Acquisition”) of Massey Energy Company, a Delaware corporation (“Massey”). Massey, together with its affiliates, was a major U.S. coal producer operating mines and associated processing and loading facilities in Central Appalachia. For the year ended December 31, 2011, Massey’s financial results are included for the seven month period June 1, 2011 through December 31, 2011. See Note 3 for further disclosures related to the Massey Acquisition.
At December 31, 2011, the Company’s operations consisted of 99 deep and 46 surface mines, which are located in Virginia, West Virginia, Pennsylvania, Kentucky and Wyoming. At December 31, 2011, the Company had approximately 14,500 employees, of which 10% are affiliated with union representation with the United Mine Workers of America (“UMWA”). The Company’s union represented employees are primarily located in Virginia, West Virginia and Pennsylvania.
Basis of Presentation
The consolidated financial statements include Alpha and its majority owned and controlled subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.
Reclassifications
Certain amounts in the December 31, 2010 Consolidated Balance Sheet have been reclassified to conform to the current year presentation.
(2) Summary of Significant Accounting Policies
Use of Estimates
The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of the Company’s consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant items subject to such estimates and assumptions include inventories; mineral reserves; allowance for non-recoupable advanced mining royalties; asset impairments; environmental and reclamation obligations; acquisition accounting; pensions, postemployment, postretirement medical and other employee benefit obligations; useful lives for depreciation, depletion, and amortization; reserves for workers’ compensation and black lung claims; current and deferred income taxes; reserves for contingencies and litigation; and fair value of financial instruments. Estimates are based on facts and circumstances believed to be reasonable at the time; however, actual results could differ from those estimates.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Cash and Cash Equivalents
Cash and cash equivalents consist of cash held with reputable depository institutions and highly liquid, short-term investments with original maturities of three months or less. Cash and cash equivalents are stated at cost, which approximates fair market value. The Company’s cash equivalents consist of money market funds that are maintained in highly rated funds at December 31, 2011.
Marketable Securities
The Company classifies its marketable securities as trading or available-for-sale. These securities are recorded initially at cost and adjusted to fair value at each reporting date. Unrealized gains and losses resulting from fair value adjustments to available-for-sale securities are classified as a separate component of stockholders’ equity. Unrealized gains and losses resulting from fair value adjustments to trading securities are reported in current earnings or loss. Realized gains and losses on available-for-sale securities are computed using the specific identification method. Marketable securities with maturities of one year or less are reported in prepaid expenses and other current assets. Marketable securities with maturities of greater than one year are reported in other non-current assets. See Notes 6 and 9 for further disclosures related to marketable securities.
Trade Accounts Receivable and Allowance for Doubtful Accounts
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company establishes provisions for losses on accounts receivable when it is probable that all or part of the outstanding balance will not be collected. The Company regularly reviews its accounts receivable balances and establishes or adjusts the allowance as necessary using the specific identification method. The allowance for doubtful accounts was $4,663 and $90 at December 31, 2011 and 2010, respectively.
Account balances are written off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Credit losses were insignificant for the three-year period ended December 31, 2011. A decline in current economic conditions, a prolonged global, national or regional economic recession or other similar events that have occurred in the past may significantly impact the creditworthiness of the Company’s customers. If any of those factors change, the estimates made by management could also change, which may affect the level of the Company’s future provision for doubtful accounts. The Company does not have off-balance sheet credit exposure related to its customers.
Inventories
Coal inventories are stated at the lower of average cost or market. The cost of coal inventories is determined based on average cost of production, which includes all costs incurred to extract, transport and process the coal. Market represents the estimated replacement cost, subject to a floor and ceiling, which considers the future sales price of the product as well as remaining estimated preparation and selling costs. Coal is reported as inventory at the point in time the coal is extracted from the mine.
Material and supplies inventories are valued at average cost, less an allowance for obsolete and surplus items.
Deferred Longwall Move Expenses
The Company defers the direct costs, including labor and supplies, associated with moving longwall equipment and the related equipment refurbishment costs in prepaid expenses and other current assets. These deferred costs are amortized on a units-of-production basis into cost of coal sales over the life of the subsequent panel of coal mined by the longwall equipment. See Note 6 for further disclosures related to deferred longwall move expenses.
Advanced Mining Royalties
Lease rights to coal lands are often acquired in exchange for royalty payments. Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable against future production. These advance payments are deferred and charged to operations as the coal reserves are mined. The Company regularly reviews recoverability of advance mining royalties and establishes or adjusts the allowance for advance mining royalties as necessary using the specific identification method. In instances where advance payments are not expected to be offset against future production royalties, the Company establishes a provision for losses on the advance payments that have been paid and the scheduled future minimum payments are expensed and recognized as liabilities. Advance royalty balances are charged off against the allowance when the lease rights are either terminated or expire.
The changes in the allowance for advance mining royalties were as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(1) Includes $4,100 reported in discontinued operations.
(2) See Note 3 for discussion surrounding the Foundation Coal Merger and the Massey Acquisition.
Property, Equipment and Mine Development Costs
Costs for mine development incurred to expand capacity of operating mines or to develop new mines are capitalized and charged to operations on the units-of-production method over the estimated proven and probable reserve tons directly benefiting from the capital expenditures. Mine development costs include costs incurred for site preparation and development of the mines during the development stage less any incidental revenue generated during the development stage. Mobile mining equipment and other fixed assets are stated at cost and depreciated on either a straight-line basis over estimated useful lives ranging from 1 to 20 years; or on a units-of-production basis. Leasehold improvements are amortized using the straight-line method, over the shorter of the estimated useful lives or term of the lease. Major repairs and betterments that significantly extend original useful lives or improve productivity are capitalized and depreciated over the period benefitted. Maintenance and repairs are expensed as incurred. When equipment is retired or disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposal is recognized in cost of coal sales.
The Company also capitalizes certain costs incurred in the development of internal-use software, including external direct material and service costs, and employee payroll and payroll-related costs. All capitalized internal-use software costs are amortized using the straight-line method over the estimated useful life of the asset.
Owned and Leased Mineral Rights and Land
Costs to obtain coal lands and leased mineral rights are capitalized and amortized to operations as depletion expense using the units-of-production method. Only proven and probable reserves are included in the depletion base. Depletion expense is included in depreciation, depletion and amortization on the accompanying Consolidated Statements of Operations and was $227,475, $111,846, and $69,779 for the years ended December 31, 2011, 2010, and 2009, respectively.
Acquired Intangibles
Application of acquisition accounting in connection with the Foundation Merger and the Massey Acquisition resulted in the recognition of an asset for above market-priced coal supply and transportation agreements and a liability for below market-priced coal supply agreements on the date of the acquisitions. The coal supply and transportation agreements were valued based on the present value of the difference between the expected net contractual cash flows based on the stated contract terms, and the estimated net contractual cash flows derived from applying forward market prices at the acquisition dates for new contracts of similar terms and conditions. The coal supply and transportation agreement assets and liabilities are being amortized over the actual amount of tons shipped under each contract. The coal supply and transportation agreement asset is reported in other acquired intangibles and the coal supply agreement liability is reported in other non-current liabilities in the Consolidated Balance Sheets.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
In addition, the application of acquisition accounting also resulted in the Company recording intangible assets related to mining permits and covenants not-to-compete, which are reported in other acquired intangibles in the Consolidated Balance Sheets. Amortization of other acquired intangible assets was $180,437, $234,094, and $133,016 of expense and amortization of coal supply agreement liabilities was a credit to expense of ($294,183), ($7,301), and ($5,408), equating to a net credit of ($113,746), $226,793 and $127,608 for the years ended December 31, 2011, 2010 and 2009, respectively, which is included in amortization of acquired intangibles, net in the Consolidated Statements of Operations. Future net amortization expense related to acquired intangibles is expected to be as follows:
Asset Impairment and Disposal of Long-Lived Assets
Long-lived assets, such as property, equipment, mine development costs, owned and leased mineral rights and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset groups may not be recoverable. Recoverability of assets or asset groups to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset or asset groups. If the carrying amount of an asset or asset groups exceeds its estimated future cash flows, an impairment charge is recognized equal to the amount by which the carrying amount of the asset exceeds the fair value of the asset or asset groups. Assets to be disposed would separately be presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and would no longer be depreciated. The assets and liabilities of a disposal group classified as held for sale would be presented separately in the Consolidated Balance Sheets.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of the net identifiable tangible and intangible assets of acquired companies. Goodwill is not amortized; instead, it is tested for impairment annually or more frequently if indicators of impairment exist. The Company had routinely performed its goodwill impairment testing as of August 31 of each year and in 2010 the Company decided to change its impairment testing date to October 31. The Company believed the change in the impairment testing date more closely aligns the impairment testing date with the Company’s long-range planning and forecasting process. The change in the impairment testing date, which represented a change in the method of applying an accounting principle, was believed by the Company to be preferable. The Company performed its goodwill impairment test as of October 31, 2011. See Note 8.
The Company tests its goodwill for impairment using a fair value approach at the reporting unit level, and performs the goodwill impairment test in two steps. Step one compares the fair value of each reporting unit to its carrying amount. If step one indicates that an impairment potentially exists, the second step is performed to measure the amount of impairment, if any. Goodwill impairment exists when the estimated implied fair value of goodwill is less than its carrying value.
Asset Retirement Obligations
Minimum standards for mine reclamation have been established by various regulatory agencies and dictate the reclamation requirements at the Company’s operations. The Company’s asset retirement obligations consist principally of costs to reclaim acreage disturbed at surface operations, estimated costs to reclaim support acreage, treat mine water discharge and perform other related functions at underground mines. The Company records these reclamation obligations at fair value in the period in which the legal obligation associated with the retirement of the long-lived asset is incurred. When the liability is initially recorded at
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
operations that are not currently being reclaimed, the offset is capitalized by increasing the carrying amount of the related long-lived asset. When the liability is initially recorded at operations that are currently being reclaimed, the offset is recorded to cost of coal sales. Over time, the liability is accreted and any capitalized cost is depreciated over the useful life of the related asset. To settle the liability, the obligation is paid, and to the extent there is a difference between the liability and the amount of cash paid, a gain or loss upon settlement is recorded. The Company annually reviews its estimated future cash flows for its asset retirement obligations. See Note 12 for further disclosures related to the Company’s asset retirement obligations.
Income Taxes
The Company recognizes deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, the Company takes into account various factors, including objective evidence obtained from historical earnings, future sales commitments, the expected level of future taxable income and available tax planning strategies, and the impact the alternative minimum tax has on utilization of deferred tax assets. If future taxable income is lower than expected or if expected tax planning strategies are not available as anticipated, the Company would record a change to the valuation allowance through income tax expense in the period the determination is made. See Note 16 for further disclosures related to the Company’s income taxes.
Revenue Recognition
The Company earns revenues primarily through the sale of coal, but also earns other revenues from sales of parts, equipment, filters, rebuild and refurbishment services, sales of coalbed methane and natural gas, road construction and intercontinental commodity transportation services. With the exception of road construction and intercontinental commodity transportation services revenue, the Company recognizes revenue using the following general revenue recognition criteria: 1) persuasive evidence of an arrangement exists; 2) delivery has occurred or services have been rendered; 3) the price to the buyer is fixed or determinable; and 4) collectability is reasonably assured. Revenue from road construction contracts is recognized under the percentage of completion method of accounting. Revenue from intercontinental commodity transportation services is recognized on a ratable basis over the period of time in which transportation services are provided.
Delivery on our coal sales is determined to be complete for revenue recognition purposes when title and risk of loss has passed to the customer in accordance with stated contractual terms and there are no other future obligations related to the shipment. For domestic shipments, title and risk of loss generally passes as the coal is loaded into transport carriers for delivery to the customer. For international shipments, title generally passes at the time coal is loaded onto the shipping vessel. In the event that a new contract is negotiated with a customer which incorporates an old contract with different pricing, the Company applies a single contract accounting concept and recognizes as revenue the lower of the cumulative amount billed or an amount based on the weighted average price of the new and old contracts applied to the tons sold.
Freight and handling costs paid to third-party carriers and invoiced to coal customers are recorded as freight and handling costs and freight and handling revenues, respectively.
Deferred Financing Costs
The costs to obtain new debt financing or amend existing financing agreements are deferred and amortized to interest expense over the life of the related indebtedness or credit facility using the straight-line method which approximates the effective interest method. Unamortized deferred financing costs are included in other non-current assets in the Consolidated Balance Sheets.
Workers’ Compensation and Pneumoconiosis (Black Lung) Benefits
Workers’ Compensation
The Company is self-insured for workers’ compensation claims at certain of its operations and is covered by a third-party insurance provider at other locations. The liabilities for workers’ compensation claims that are self-insured by the Company are estimates of the ultimate losses incurred based on the Company’s experience, and include a provision for incurred but not reported losses. Adjustments to the probable ultimate liabilities are made either semi-annually or annually based on an actuarial study and adjustments to the liability are recorded based on the results of this study. These obligations are included in the Consolidated Balance Sheets as accrued expenses and other current liabilities and other non-current liabilities. See Note 17.
Black Lung Benefits
The Company is required by federal and state statutes to provide benefits to employees for awards related to black lung. The Company is self-insured at certain locations and covered by a third party insurance provider at other locations. Charges are made to operations for self-
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
insured black lung claims, as determined by an independent actuary at the present value of the actuarially computed liability for such benefits over the employee’s applicable term of service. The Company recognizes in its balance sheet the amount of the Company’s unfunded Accumulated Benefit Obligation (“ABO”) at the end of the year. Amounts recognized in accumulated other comprehensive income (loss) are adjusted out of accumulated other comprehensive income (loss) when they are subsequently recognized as components of net periodic benefit cost. See Note 17.
Pension and Other Postretirement Benefits
The Company is required to recognize the overfunded or underfunded status of a defined benefit pension plan as an asset or liability in its Consolidated Balance Sheets and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income (loss). The Company is required to measure plan assets and benefit obligations as of the date of the Company’s fiscal year-end balance sheet and provide the required disclosures as of the end of each fiscal year. See Note 17 for further disclosures related to pensions.
The Company accounts for health care benefits provided for current and certain retired employees and their dependents by accruing the cost of such benefits over the service lives of employees. Unrecognized actuarial gains and losses are amortized over the estimated average remaining service period for active employees and over the estimated average remaining life for retirees. The Company recognizes in its Consolidated Balance Sheets the amount of the Company’s unfunded Accumulated Postretirement Benefit Obligation (“APBO”) at the end of the year. Amounts recognized in accumulated other comprehensive income (loss) are adjusted out of accumulated other comprehensive income (loss) when they are subsequently recognized as components of net periodic benefit cost. See Note 17 for further disclosures related to other postretirement benefits.
Earnings Per Share
Basic earnings per share is computed by dividing net income by the weighted-average number of outstanding common shares for the period. Diluted earnings per share reflects the potential dilution that could occur if instruments that may require the issuance of common shares in the future were settled and the underlying common shares were issued. Diluted earnings per share is computed by increasing the weighted-average number of outstanding common shares computed in basic earnings per share to include the additional common shares that would be outstanding after issuance and adjusting net income from changes that would result from the issuance. Only those securities that are dilutive are included in the calculation. See Note 4 for further disclosures related to earnings per share.
Stock-Based Compensation
The Company recognizes expense for stock-based compensation awards based on the estimated grant-date fair value. For all grants, the amount of compensation expense to be recognized is adjusted for an estimated forfeiture rate which is based in part on historical data and other relevant factors. Compensation expense for awards with cliff vesting provisions is recognized on a straight-line basis from the measurement date through the vesting date. Compensation expense for awards with graded vesting provisions is recognized using the accelerated attribution method. See Note 18 for further disclosures related to the Company’s stock-based compensation arrangements.
Derivative Instruments and Hedging Activities
Derivative financial instruments are recognized as either assets or liabilities in the Consolidated Balance Sheets and measured at fair value. On the date a derivative instrument is entered into, the Company generally designates a qualifying derivative instrument as a hedge of the variability of cash flows to be received or paid related to a recognized asset or liability or forecasted transaction (cash flow hedge). The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash flow hedges to specific firm commitments or forecasted transactions. The Company also formally assesses both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of the related hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Company discontinues hedge accounting prospectively and records all future changes in fair value in current period earnings or losses.
For derivative instruments that have not been designated as cash flow hedges, changes in fair value are recorded in current period earnings or losses. For derivative instruments that have been designated as cash flow hedges, the effective portion of the changes in fair value are recorded in accumulated other comprehensive income (loss) and any portion that is ineffective is recorded in current period earnings or losses. Amounts recorded in accumulated other comprehensive income (loss) are reclassified to earnings or losses in the period the underlying hedged transaction affects earnings or when the underlying hedged transaction is no longer probable of occurring. See Note 15 for further disclosures related to the Company’s derivative financial instruments and hedging activities.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Equity-Method Investments
Investments in unconsolidated affiliates that the Company has the ability to exercise significant influence over, but not control, the affiliate’s operating activities are accounted for under the equity-method of accounting. Under the equity method of accounting, the Company records its proportionate share of the entity’s net income or loss at each reporting period in the Consolidated Statements of Operations in miscellaneous income (expense), net, with a corresponding entry to increase or decrease the carrying value of the investment.
Other Comprehensive Income (Loss)
In addition to net income, other comprehensive income (loss) includes changes to accumulated other comprehensive income (loss) such as adjustments to unrecognized gains and losses and amortization of employee benefit plan costs, the effective portion of changes in fair value of derivative instruments that qualify as cash flow hedges and changes in fair value of available-for-sale marketable securities.
New Accounting Pronouncements Adopted
In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which amended accounting guidance related to fair value measurements and disclosures with the purpose of converging the fair value measurement and disclosure guidance issued by the FASB and the International Accounting Standards Board (“IASB”). The guidance is effective for reporting periods beginning after December 15, 2011. The guidance includes amendments that clarify the intent of the application of existing fair value measurement requirements along with amendments that change a particular principle or requirement for fair value measurements and disclosures. The Company has concluded that the new guidance will not have a material impact on its Consolidated Financial Statements or related disclosures.
In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”), which amended accounting guidance related to presentation of comprehensive income. The standards update is intended to help financial statement users better understand the causes of an entity’s change in financial position and results of operation. The amendment eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendment requires that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance also requires that reclassification adjustments for items that are reclassified from other comprehensive income to net income be presented on the face of the financial statement where the components of net income and other comprehensive income are presented. In December 2011, the FASB issued ASU 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”), which defers only those changes in ASU 2011-5 that relate to the presentation of reclassification adjustments out of accumulated other comprehensive income. ASU 2011-05 and ASU 2011-12 are effective for reporting periods beginning after December 15, 2011. The Company has concluded that the new guidance will not have a material impact on its Consolidated Financial Statements or related disclosures.
In September 2011, the FASB issued ASU 2011-08, Testing for Goodwill Impairment (“ASU 2011-08”). ASU 2011-08 is intended to simplify how entities test for goodwill impairment by adding a qualitative review step to assess whether the required quantitative impairment analysis is necessary. ASU 2011-08 permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If it is concluded that this is not the case, it is not necessary to perform the two-step impairment test as described in Accounting Standards Codification (“ASC”) Topic 350, Intangibles-Goodwill and Other. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The Company will adopt the provisions of the new guidance in 2012 during its annual goodwill impairment analysis.
In September 2011, the FASB also issued ASU 2011-09, Disclosures about an Employer’s Participation in a Multiemployer Plan (“ASU 2011-09”), which is intended to improve disclosures about an employer’s participation in a multiemployer pension plan. ASU 2011-09 requires additional disclosures about an employer’s participation in a multiemployer pension plan. This guidance is effective for fiscal years ending after December 15, 2011 and is required to be applied retrospectively for all periods presented. The Company adopted the provisions of this standard in December 2011. See Note 17 to the Consolidated Financial Statements for the required disclosures.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(3) Mergers and Acquisitions
Acquisition of Massey Energy Company
On June 1, 2011, the Company completed its acquisition of 100% of the outstanding common stock of Massey, a coal producer with operations located primarily in Virginia, West Virginia, and Kentucky. The Company issued 1.025 shares of Alpha common stock and $10.00 in cash for each share of Massey common stock. Upon closing of the Massey Acquisition, Alpha shareholders owned 54% of the combined company and Massey shareholders owned 46% of the combined company.
The Consolidated Statements of Operations include acquisition related expenses (on a pre-tax basis) of $193,453 in cost of coal sales, $163,959 in selling, general and administrative, and $44,687 of net other expenses for the year ending December 31, 2011. Included in cost of coal sales is $152,733 related to the impact of acquisition accounting and related fair value adjustments to coal inventory, $35,521 of expenses for benefit integration activities and employee severance, and $5,199 of stock compensation expense. Selling, general and administrative includes $117,546 for professional fees related to legal, financing and integration services, $30,396 in expenses for benefits alignment and employee severance, and $16,017 in stock compensation expense. The net other expense of $44,687 was recorded for contract-related matters related to coal contracts assumed in the Massey Acquisition.
Total revenues reported in the Consolidated Statements of Operations for the year ending December 31, 2011 included revenues of $1,878,612 from operations acquired from Massey. The amount of earnings from continuing operations from the operations acquired from Massey included in the consolidated results of operations for the year ending December 31, 2011 is not readily determinable due to various intercompany transactions and allocations that have occurred in connection with the operations of the combined company.
The fair value of the total consideration transferred was approximately $6,714,057. The acquisition date fair value of each class of consideration transferred was as follows:
The Company issued 105,984,847 shares of common stock in the transaction. Fair value of common stock issued was determined by the closing price of Alpha’s common stock on the day of the Massey Acquisition. The fair value of other equity awards was determined in accordance with the provisions of ASC 805. The total purchase price has been preliminarily allocated to the net tangible and intangible assets of Massey as of June 1, 2011 as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The above purchase price allocation includes provisional amounts for certain assets and liabilities. The purchase price allocation will continue to be refined primarily in the areas of income taxes, other contingencies and goodwill. During the measurement period, which will end no later than May 31, 2012, the Company expects to file a final tax return for Massey and otherwise complete the final purchase price allocation. The Company’s provisional estimate of goodwill has been allocated to Eastern Coal Operations. None of the goodwill will be deductible for income tax purposes.
During the seven months ended December 31, 2011, the Company recorded certain adjustments to the provisional opening balance sheet as shown in the table above. Provisional adjustments were made to reflect updated estimates for litigation-related matters for which the Company also recorded increases to other receivables for insurance recoveries, final mineral reserve studies, final property and equipment and asset retirement obligation valuations (including adjustments to asset retirement obligations of $182,065 for post-closing water treatment costs related to selenium discharges), other miscellaneous adjustments and the deferred tax impact of all adjustments made.
The Company updated depletion, depreciation, amortization and accretion amounts previously recorded and restated its results of operations for the three months ended June 30, 2011 and September 30, 2011. See Note 25. These amounts are included in the Company’s results of operations for the year ended December 31, 2011.
Intangible assets and liabilities related to coal supply agreements and transportation agreements will be amortized over the actual amount of tons shipped under each contract. Mine permits will be amortized over a weighted average useful life of approximately 7.5 years and have a weighted average term of approximately 2.3 years before the next renewal or extension.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The following unaudited pro forma information has been prepared for illustrative purposes only and assumes the Massey Acquisition occurred on January 1, 2010. The unaudited pro forma results have been prepared based on estimates and assumptions, which the Company believes are reasonable; however, they are not necessarily indicative of the consolidated results of operations had the Massey Acquisition occurred on January 1, 2010, or of future results of operations.
The unaudited pro forma results for the years ending December 31, 2011 and 2010 are as follows:
Merger with Foundation Coal Holdings, Inc.
On May 11, 2009, Old Alpha and Foundation executed an agreement and plan of merger pursuant to which Old Alpha was to be merged with and into Foundation, with Foundation continuing as the surviving corporation of the Foundation Merger. On July 31, 2009, the Foundation Merger was completed and Foundation was renamed Alpha Natural Resources, Inc.
During the year ended December 31, 2010, the Company finalized the purchase price allocation for the Foundation Merger and recorded an immaterial correction to the December 31, 2009 Consolidated Balance Sheet to reflect the adjustments as if they were recorded on the acquisition date. The increase to goodwill is reported in the Company’s Eastern Coal Operations, Western Coal Operations and All Other category as of December 31, 2010 and December 31, 2009.
The following table presents the details of the preliminary purchase price allocation reported as of December 31, 2009, the adjustments made in the year ended December 31, 2010 and the final purchase price allocation.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(1) Adjustments include an immaterial correction recorded in the year ended December 31, 2010 which increased accrued expenses and goodwill $3,468 and $2,145, respectively, and decreased deferred income taxes $1,323.
The following unaudited pro forma information has been prepared for illustrative purposes only and assumes the Foundation Merger occurred at the beginning of each of the periods being presented. The unaudited pro forma results have been prepared based on estimates and assumptions, which the Company believes are reasonable; however, they are not necessarily indicative of the consolidated results of operations had the Foundation Merger occurred at the beginning of each of the periods presented, or of future results of operations.
The unaudited pro forma results for the year ended December 31, 2009 are as follows:
Total revenues reported in the Consolidated Statements of Operations for the year ended December 31, 2009 included total revenues of $716,764 related to Foundation. The amount of earnings from continuing operations related to Foundation included in the Consolidated
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Statement of Operations for the year ended December 31, 2009 is not readily determinable due to various intercompany transactions and allocations that have occurred in connection with the operations of the combined company.
(4) Earnings Per Share
The number of shares used to calculate basic earnings (loss) per common share is based on the weighted average number of the Company’s outstanding common shares during the respective periods. The number of shares used to calculate diluted earnings per share is based on the number of common shares used to calculate basic earnings (loss) per share plus the dilutive effect of stock options and other stock-based instruments held by the Company’s employees and directors during each period, the Company’s outstanding 2.375% convertible senior notes due 2015 (the “2.375% Convertible Notes”), and for periods subsequent to the Massey Acquisition, the outstanding 3.25% convertible senior notes due 2015 issued by Massey (the “3.25% Convertible Notes”). The 2.375% Convertible Notes and 3.25% Convertible Notes become dilutive for earnings per common share calculations in certain circumstances. The shares that would be issued to settle the conversion spread are included in the diluted earnings per common share calculation when the conversion option is in the money. For the years ended December 31, 2011, 2010 and 2009, the conversion options for the 2.375% Convertible Notes and the 3.25% Convertible Notes were not in the money, and therefore there was no dilutive earnings per share impact.
For the year ended December 31, 2011, there was no dilutive impact on earnings per share as the Company incurred a net loss for the year. For the year ended December 31, 2010, there were 32,795 shares excluded from the computation of year-to-date diluted earnings per share as the shares were anti-dilutive, related to restricted stock awards and restricted stock units.
The following table provides a reconciliation of weighted average shares outstanding used in the basic and diluted earnings per share computations for the periods presented:
(5) Inventories, net
Inventories, net consisted of the following:
(6) Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consisted of the following:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(1) Short-term marketable securities consisted of the following:
(2) See Note 10.
(a) Unrealized gains and losses are recorded as component of stockholders’ equity.
(7) Property, Equipment and Mine Development Costs
Property, equipment, and mine development costs consisted of the following:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Depreciation and amortization expense associated with property, equipment and mine development costs was $542,052, $257,649 and $182,616 for the years ended December 31, 2011, 2010 and 2009, respectively.
Interest costs applicable to major asset additions are capitalized during the construction period. During the years ended December 31, 2011, 2010 and 2009, interest costs of $1,925, $2,152 and $492 were capitalized, respectively.
As of December 31, 2011, the Company had commitments to purchase approximately $235,503 of new equipment, expected to be acquired at various dates in 2012, which includes a portion of the Company’s commitment under the non-prosecution agreement (See Note 20) to invest $80,000 for mine safety over the next two years.
(8) Goodwill and Other Acquired Intangibles, Net
Goodwill:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
During the fourth quarter of 2011, domestic and international coal markets declined as a result of slowing economic activity, fuel switching for electricity generation due to low priced natural gas, recently effective U.S. environmental regulations that discourage the use of coal. As a result of these changes to the near-term market outlook as well as updated projections of production volumes and cash operating costs, the implied fair value of goodwill at several reporting units was determined to be less than its carrying value.
The Company performed its annual goodwill impairment test during the fourth quarter of 2011 using a two-step approach. Step one compared the fair value of each reporting unit to its carrying value. The valuation methodology utilized to estimate the fair value of the reporting units was based on both a market and income approach and is within the range of fair values yielded under each approach. The income approach was based on a discounted cash flow methodology in which expected future net cash flows were discounted to present value, using an appropriate after-tax weighted average cost of capital. The market approach was based on a guideline company and similar transaction approach. Under the guideline company approach, certain operating metrics from a selected group of publically traded guideline companies that have similar operations to the Company’s reporting units was used to estimate the fair value of the reporting units. Under the similar transaction approach, recent merger and acquisition transactions for companies that have similar operations to the Company’s reporting units were used to estimate the fair value of the Company’s reporting units.
In step two of the goodwill impairment test, the Company compared the carrying value of goodwill to its implied fair value. In estimating the implied fair value of goodwill at a reporting unit, the Company assigned the fair value of the reporting unit to all of the assets and liabilities associated with the reporting unit as if the reporting unit had been acquired in a business combination.
The Company performed its annual goodwill impairment testing as of October 31, 2011 and recorded impairment charges of $745,325 to reduce the carrying value of goodwill to its implied fair value of $975,100 for four of its reporting units in Eastern Coal Operations.
As discussed in Note 3, the goodwill recorded in the Massey Acquisition is a provisional amount. Subsequent changes to the provisional amounts recorded for the assets and liabilities of Massey could impact the final goodwill recorded for the Massey Acquisition, which could impact the goodwill impairment recorded for the year ending December 31, 2011.
Other Acquired Intangibles:
(1) In connection with the Massey Acquisition, the Company recorded assets of $245,472 for above-market coal supply and transportation agreements and liabilities of $583,327 for below-market coal supply agreements.
(2) Recorded in connection with the Massey Acquisition.
(3) Reported as other acquired intangibles in the Consolidated Balance Sheets.
(4) Reported in other long-term liabilities in the Consolidated Balance Sheets.
(9) Other Non-current Assets
Other non-current assets consisted of the following:
(1) Long-term marketable securities, with maturity dates between one and three years, consisted of the following:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(a) Unrealized gains and losses are recorded as a component of stockholders’ equity.
(b) Unrealized gains and losses are recorded in current period earnings.
(10) Accrued Expenses and Other Current Liabilities
Accrued expenses and other current liabilities consisted of the following:
(a) The Company has recorded related receivables of $225,519 from insurance coverage and indemnifications in prepaid expenses and other current assets at December 31, 2011.
(11) Long-Term Debt
Long-term debt consisted of the following:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
New Notes Indenture and the New Senior Notes
On June 1, 2011, Alpha, certain of Alpha’s wholly owned domestic subsidiaries (collectively, the “Alpha Guarantors”) and Union Bank, N.A., as trustee, entered into an indenture (the “Base Indenture”) and a first supplemental indenture (the “First Supplemental Indenture” and, together with the Base Indenture, the “New Notes Indenture”) governing Alpha’s newly issued 6.00% senior notes due 2019 (the “2019 Notes”) and 6.25% senior notes due 2021 (the “2021 Notes” and, together with the 2019 Notes, the “New Senior Notes”).
On June 1, 2011, in connection with the Massey Acquisition, Alpha, the Alpha Guarantors, Massey, and certain wholly owned subsidiaries of Massey (the “Massey Guarantors” and together with the Alpha Guarantors the “Guarantors”), and Union Bank, N.A., as trustee, entered into a supplemental indenture (the “Second Supplemental Indenture”) to the New Notes Indenture pursuant to which Massey and certain wholly owned subsidiaries of Massey agreed to become additional guarantors for the New Senior Notes.
The 2019 Notes bear interest at a rate of 6.00% per annum, payable semi-annually on June 1 and December 1 of each year, beginning on December 1, 2011, and will mature on June 1, 2019. The 2021 Notes bear interest at a rate of 6.25% per annum, payable semi-annually on June 1 and December 1 of each year, beginning on December 1, 2011, and will mature on June 1, 2021.
As of December 31, 2011, the carrying values of the 2019 Notes and 2021 Notes were $800,000 and $700,000, respectively.
Alpha may redeem the 2019 Notes, in whole or in part, at any time prior to June 1, 2014, at a price equal to 100.000% of the aggregate principal amount of the 2019 Notes plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date. Alpha may redeem the 2019 Notes, in whole or in part, at any time during the twelve months commencing June 1, 2014, at 103.000% of the aggregate principal amount of the 2019 Notes, at any time during the twelve months commencing June 1, 2015, at 101.500% of the aggregate principal amount of the 2019 Notes, and at any time after June 1, 2016 at 100.000% of the aggregate principal amount of the 2019 Notes, in each case plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date. In addition, Alpha may redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net cash proceeds from certain equity offerings, at any time prior to June 1, 2014, at a redemption price equal to 106.000% of the aggregate principal amount of the 2019 Notes, plus accrued and unpaid interest, if any, to, but not including the applicable redemption date, provided that at least 65% of the aggregate principal amount of the 2019 notes originally issued under the New Notes Indenture remains outstanding after the redemption and the redemption occurs within 180 days of the closing of such equity offering.
Alpha may redeem the 2021 Notes, in whole or in part, at any time prior to June 1, 2016, at a price equal to 100.000% of the aggregate principal amount of the 2021 Notes plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date. Alpha may redeem the 2021 Notes, in whole or in part, at any time during the twelve months commencing June 1, 2016, at 103.125% of the aggregate principal amount of the 2021 Notes, at any time during the twelve months commencing June 1, 2017, at 102.083% of the aggregate principal amount of the 2021 Notes, at any time during the twelve months commencing June 1, 2018, at 101.042% of the aggregate principal amount of the 2021 Notes, and at any time after June 1, 2019, at 100.000% of the aggregate principal amount of the 2021 Notes, in each case plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date. In addition, Alpha may
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
redeem up to 35% of the aggregate principal amount of the 2021 Notes with the net cash proceeds from certain equity offerings, at any time prior to June 1, 2016, at a redemption price equal to 106.250% of the aggregate principal amount of the 2021 Notes, plus accrued and unpaid interest, if any, to, but not including the applicable redemption date, provided that at least 65% of the aggregate principal amount of the 2021 notes originally issued under the New Notes Indenture remains outstanding after the redemption and the redemption occurs within 180 days of the date of the closing of such equity offering.
Upon the occurrence of a change in control repurchase event with respect to either series of the New Senior Notes, unless Alpha has exercised its right to redeem those New Senior Notes, Alpha will be required to offer to repurchase each holder’s New Senior Notes of such series at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the date of repurchase.
The New Notes Indenture contains covenants that limit, among other things, Alpha’s ability to:
· incur, or permit its subsidiaries to incur, additional debt;
· issue, or permit its subsidiaries to issue, certain types of stock;
· pay dividends on Alpha’s or its subsidiaries’ capital stock or repurchase Alpha’s common stock;
· make certain investments;
· enter into certain types of transactions with affiliates;
· incur liens on certain assets to secure debt;
· limit dividends or other payments by its restricted subsidiaries to Alpha and its other restricted subsidiaries;
· consolidate, merge or sell all or substantially all of its assets; and
· make certain payments on Alpha’s or its subsidiaries’ subordinated debt.
These covenants are subject to a number of important qualifications and exceptions. These covenants may not apply at any time after the New Senior Notes are assigned a credit grade rating of at least BB+ (stable) from Standard & Poor’s Ratings Services and of at least Ba1 (stable) from Moody’s Investor Service, Inc.
Third Amended and Restated Credit Agreement
On May 19, 2011, in connection with the Massey Acquisition, Alpha entered into a Third Amended and Restated Credit Agreement to amend and restate in its entirety the credit agreement dated as of July 30, 2004, as amended as of November 12, 2004 and as of October 18, 2005, as amended and restated as of July 7, 2006, as amended effective July 31, 2009 and as further amended and restated as of April 15, 2010 (as so amended and restated, the “Former Credit Agreement”; the Former Credit Agreement, as amended and restated by the Third Amended and Restated Credit Agreement, is referred to as the “New Credit Agreement”), with Citicorp North America, Inc., as administrative agent and as collateral agent, Bank of America, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, The Royal Bank of Scotland plc and Union Bank, N.A. and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as co-documentation agents, Morgan Stanley Senior Funding, Inc., as sole syndication agent, Citigroup Global Markets Inc. and Morgan Stanley Senior Funding, Inc., as joint lead arrangers and joint book managers, and various other financial institutions, as lenders. The terms of the New Credit Agreement amended and restated and superseded the Former Credit Agreement in its entirety upon the satisfaction of certain conditions precedent, which included the consummation of the Massey Acquisition (the satisfaction of such conditions precedent is referred to as the “initial Credit Event”). The Former Credit Agreement remained in full force and effect until the occurrence of the initial Credit Event.
Upon the occurrence of the initial Credit Event, the New Credit Agreement provided for a $600,000 senior secured term loan A facility (the “Term Loan Facility”) and a $1,000,000 senior secured revolving credit facility (the “Revolving Facility”). Pursuant to the New Credit Agreement, Alpha may request incremental term loans or increase the revolving commitments under the Revolving Facility in an aggregate amount of up to $1,250,000 plus an additional $750,000 subject to compliance with a consolidated senior secured leverage ratio. The lenders under these facilities will not be under any obligation to provide any such incremental loans or commitments, and any such addition of or increase in such loans or commitments will be subject to certain customary conditions precedent.
As of December 31, 2011, the carrying value of the Term Loan Facility was $584,330, net of debt discount of $670, with $45,000 classified as current portion of long-term debt. There were no borrowings outstanding under the Revolving Facility as of December 31, 2011. Letters of credit outstanding at December 31, 2011 under the Revolving Facility were $300.
Interest Rate and Fees. Borrowings under the New Credit Agreement bear interest at a rate per annum equal to an applicable margin plus, at Alpha’s option, either (a) a base rate determined by reference to the highest of (i) the rate that Citibank, N.A. announces from time to time as its prime or base commercial lending rate, (ii) the federal funds effective rate plus 0.50% and (iii) a London Interbank Offer (“LIBO”) rate for a 30-day interest period as determined on such day, plus 1.00%, or (b) a LIBO rate for the interest period relevant to such borrowing adjusted for certain
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
additional costs. The initial applicable margin for borrowings under the New Credit Agreement is 1.50% with respect to base rate borrowings and 2.50% with respect to LIBO rate borrowings. Commencing October 1, 2011, the applicable margin for borrowings under the New Credit Agreement became subject to adjustment each fiscal quarter based on Alpha’s consolidated leverage ratio for the preceding fiscal quarter. Swingline loans bear interest at a rate per annum equal to the base rate plus the applicable margin. The interest rate in effect at December 31, 2011 was 2.51%. In addition to paying interest on outstanding principal under the New Credit Agreement, Alpha is required to pay a commitment fee to the lenders under the Revolving Facility in respect of the unutilized commitments thereunder. The initial commitment fee is 0.50% per annum. Commencing October 1, 2011, the commitment fee became subject to adjustment each fiscal quarter based on Alpha’s consolidated leverage ratio for the preceding fiscal quarter. Alpha must also pay customary letter of credit fees and agency fees.
Mandatory Prepayments. The New Credit Agreement requires Alpha to prepay outstanding loans, subject to certain exceptions, with (i) 100% of the net cash proceeds (including the fair market value of noncash proceeds) from certain asset sales and condemnation events in excess of the greater of $1,500,000 and 15% of consolidated tangible assets as of the end of each fiscal year, (ii) 100% of the aggregate gross proceeds (including the fair market value of noncash proceeds) from certain Intracompany Disposals (as defined in the New Credit Agreement) exceeding $500,000 during the term of the New Credit Agreement and (iii) 100% of the net cash proceeds from any incurrence or issuance of certain debt, other than debt permitted under the New Credit Agreement. Mandatory prepayments will be applied first to the Term Loan Facility and thereafter to reductions of the commitments under the Revolving Facility. If at any time the aggregate amount of outstanding revolving loans, swingline loans, unreimbursed letter of credit drawings and undrawn letters of credit under the Revolving Facility exceeds the commitment amount, Alpha will be required to repay outstanding loans or cash collateralize letters of credit in an aggregate amount equal to such excess, with no reduction of the commitment amount.
Voluntary Prepayments; Reductions in Commitments. Alpha may prepay, in whole or in part, amounts outstanding under the New Credit Agreement, with prior notice but without premium or penalty (other than customary “breakage” costs with respect to LIBO rate loans) and in certain minimum amounts. Alpha may also repurchase loans outstanding under the Term Loan Facility pursuant to standard reverse Dutch auction and open market purchase provisions, subject to certain limitations and exceptions. Alpha may make voluntary reductions to the unutilized commitments of the Revolving Facility from time to time without premium or penalty.
Amortization and Final Maturity. Beginning on September 30, 2011, Alpha became required to make scheduled quarterly amortization payments with respect to loans under the Term Loan Facility. In the last two quarters of 2011 and the first two quarters of 2012, each quarterly amortization payment will be in an amount equal to 1.25% of the original principal amount of the term loans. In the last two quarters of 2012 and the first two quarters of 2013, each quarterly amortization payment will be in an amount equal to 2.5% of the original principal amount of the term loans. In the last two quarters of 2013 and the first two quarters of 2014, each quarterly amortization payment will be in an amount equal to 3.75% of the original principal amount of the term loans. In the last two quarters of 2014 and the first two quarters of 2015, each quarterly amortization payment will be in an amount equal to 5% of the original principal amount of the term loans. In the last two quarters of 2015 and the first two quarters of 2016, each quarterly amortization payment will be in an amount equal to 12.5% of the original principal amount of the term loans. There is no scheduled amortization under the Revolving Facility. The principal amount outstanding on the loans under the Revolving Facility will be due and payable on June 30, 2016. The Term Loan Facility and Revolving Facility will each mature on June 30, 2016.
Guarantees and Collateral. All obligations under the New Credit Agreement are unconditionally guaranteed by certain of Alpha’s existing wholly owned domestic subsidiaries, and are required to be guaranteed by certain of Alpha’s future wholly owned domestic subsidiaries. All obligations under the New Credit Agreement and certain hedging and cash management obligations with lenders and affiliates of lenders thereunder are secured, subject to certain exceptions, by substantially all of Alpha’s assets and the assets of Alpha’s subsidiary guarantors, in each case subject to exceptions, thresholds and limitations.
Certain Covenants and Events of Default. The New Credit Agreement contains a number of negative covenants that, among other things and subject to certain exceptions, restrict Alpha’s ability and the ability of Alpha’s subsidiaries to:
· make investments, loans and acquisitions;
· incur additional indebtedness;
· incur liens;
· consolidate or merge;
· sell assets, including capital stock of its subsidiaries;
· pay dividends on its capital stock or redeem, repurchase or retire its capital stock or its other Indebtedness;
· engage in transactions with its affiliates;
· materially alter the business it conducts; and
· create restrictions on the payment of dividends or other amounts to Alpha from Alpha’s restricted subsidiaries.
In addition, the New Credit Agreement requires Alpha to comply with certain financial ratio maintenance covenants.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The New Credit Agreement also contains customary representations and warranties, affirmative covenants and events of default, including a cross-default provision in respect of any other indebtedness that has an aggregate principal amount exceeding $25,000.
Former Credit Agreement
The Former Credit Agreement consisted of term loans and revolving credit facility commitments due on July 31, 2014. During the year ended December 31, 2011, borrowings under the Former Credit Agreement totaling $227,896 were repaid. The Former Credit Agreement was replaced with the New Credit Agreement as described above. As of December 31, 2010, the Company’s secured term loans under the Former Credit Agreement had a carrying value of $226,705, net of debt discount of $1,191, with $11,839 classified as current portion of long-term debt.
3.25% Convertible Senior Notes due 2015
As a result of the Massey Acquisition, the Company became a guarantor of Massey’s 3.25% Convertible Notes, with aggregate principal outstanding at June 1, 2011 of $659,063. The 3.25% Convertible Notes bear interest at a rate of 3.25% per annum, payable semi-annually in arrears on August 1 and February 1 of each year. The 3.25% Convertible Notes will mature on August 1, 2015, unless earlier repurchased by the Company or converted. The 3.25% Convertible Notes had a fair value of $730,900 at the acquisition date. The Company accounts for the 3.25% Convertible Notes under ASC 470-20, which requires issuers of convertible debt instruments that may be settled wholly or partially in cash upon conversion to separately account for the liability and equity components in a manner reflective of the issuers’ nonconvertible debt borrowing rate. As of December 31, 2011, the carrying amount of the debt was $624,946, net of debt discount of $33,727. As of December 31, 2011, the carrying amount of the equity component totaled $110,375. The debt discount is being accreted over the four-year term of the 3.25% Convertible Notes, and provides for an effective interest rate of 4.21%.
The 3.25% Convertible Notes are senior unsecured obligations and rank equally with all of the Company’s existing and future senior unsecured indebtedness. The 3.25% Convertible Notes are guaranteed on a senior unsecured basis by Massey’s subsidiaries (which are among the Company’s subsidiaries), other than certain minor subsidiaries of Massey. The 3.25% Convertible Notes are effectively subordinated to all of the Company’s existing and future secured indebtedness and all existing and future liabilities of the Company’s non-guarantor subsidiaries, including trade payables. The 3.25% Convertible Notes are convertible in certain circumstances and in specified periods at a conversion rate, subject to adjustment, of the value of 11.4560 shares of common stock per $1,000 principal amount of 3.25% Convertible Notes. From and after the effective date of the Massey Acquisition, the consideration deliverable upon conversion of the 3.25% Convertible Notes ceased to be based upon Massey common stock and instead became based upon Reference Property (as defined in the indenture governing the 3.25% Convertible Notes, (the “3.25% Convertible Notes Indenture”)) consisting of 1.025 shares of Alpha common stock (subject to adjustment upon the occurrence of certain events set forth in the 3.25% Convertible Notes Indenture) plus $10.00 in cash per share of Massey common stock. Upon conversion of the 3.25% Convertible Notes, holders will receive cash up to the principal amount of the notes being converted, and any excess conversion value will be delivered in cash, Reference Property, or a combination thereof, at the Company’s election. One of the circumstances under which the 3.25% Convertible Notes would become convertible is if the Company’s common stock price exceeds a set threshold during a reference period specified in the 3.25% Convertible Notes Indenture.
The 3.25% Convertible Notes Indenture contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee or the holders of at least 25% in aggregate principal amount of the 3.25% Convertible Notes then outstanding may declare the principal of the 3.25% Convertible Notes and any accrued and unpaid interest immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to the Company, the principal amount of the 3.25% Convertible Notes together with any accrued and unpaid interest thereon will automatically become due and immediately payable.
The 3.25% Convertible Notes were not convertible as of December 31, 2011 and as a result have been classified as long-term.
6.875% Senior Notes due 2013
The Company assumed Massey’s 6.875% senior notes due 2013 (the “2013 Notes”) with an aggregate principal amount outstanding of $760,000 as part of the Massey Acquisition. Following a cash tender offer for the 2013 Notes and upon redemption of the 2013 Notes on the redemption date of July 1, 2011, the Company recorded a loss on early extinguishment of $752.
7.25% Senior Notes Due August 1, 2014
Foundation PA Coal Company, LLC (“Foundation PA”), one of the Company’s subsidiaries, had notes that were scheduled to mature on August 1, 2014 (the “2014 Notes”) in the aggregate principal amount of $298,285 as of December 31, 2010. The outstanding 2014 Notes were redeemed and became due and payable on August 18, 2011 (the “Redemption Date”) at a redemption price equal to 101.208% of the principal amount of the 2014 Notes, plus any and all accrued and unpaid interest up to but excluding the Redemption Date. The Company paid $302,909, including interest, to redeem the 2014 Notes. The Company recognized a loss on early extinguishment of debt of $4,438, including the premium paid. As of December 31, 2010, the carrying value of the 2014 Notes was $297,272, net of debt discount of $1,013.
2.375% Convertible Senior Notes Due April 15, 2015
As of December 31, 2011 and 2010, the Company had $287,500 aggregate principal amount of 2.375% convertible senior notes due April 15, 2015. The 2.375% Convertible Notes bear interest at a rate of 2.375% per annum, payable semi-annually in arrears on April 15 and October 15 of each year, and will mature on April 15, 2015, unless previously repurchased by the Company or converted. The Company separately accounts for the liability and equity components of its 2.375% Convertible Notes under ASC 470-20, which requires issuers of
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
convertible debt instruments that may be settled wholly or partially in cash upon conversion to separately account for the liability and equity components in a manner reflective of the issuers’ nonconvertible debt borrowing rate. The related deferred loan costs and discount are being amortized and accreted, respectively, over the seven-year term of the 2.375% Convertible Notes, and provide for an effective interest rate of 8.64%. As of December 31, 2011 and 2010, the carrying amounts of the debt component were $235,251 and $222,355, respectively. As of December 31, 2011 and 2010, the unamortized debt discount was $52,249 and $65,145, respectively. As of December 31, 2011 and 2010, the carrying amount of the equity component was $69,851.
The 2.375% Convertible Notes are the Company’s senior unsecured obligations and rank equally with all of the Company’s existing and future senior unsecured indebtedness. The 2.375% Convertible Notes are effectively subordinated to all of the Company’s existing and future secured indebtedness and all existing and future liabilities of the Company’s subsidiaries, including trade payables. The 2.375% Convertible Notes are convertible in certain circumstances and in specified periods at an initial conversion rate of 18.2962 shares of common stock per one thousand principal amount of 2.375% Convertible Notes, subject to adjustment upon the occurrence of certain events set forth in the indenture governing the 2.375% Convertible Notes (the “2.375% Convertible Notes Indenture”). Upon conversion of the 2.375% Convertible Notes, holders will receive cash up to the principal amount of the notes to be converted, and any excess conversion value will be delivered in cash, shares of common stock or a combination thereof, at the Company’s election.
The 2.375% Convertible Notes Indenture contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee, Union Bank of California, or the holders of not less than 25% in aggregate principal amount of the 2.375% Convertible Notes then outstanding may declare the principal of 2.375% Convertible Notes and any accrued and unpaid interest thereon immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to the Company, the principal amount of the 2.375% Convertible Notes together with any accrued and unpaid interest thereon will automatically become due and be immediately payable.
The 2.375% Convertible Notes were not convertible as of December 31, 2011 and 2010 and therefore have been classified as long-term debt.
Accounts Receivable Securitization
The Company and certain of its subsidiaries are parties to an accounts receivable securitization facility with a third party financial institution (the “A/R Facility”). The Company formed ANR Receivables Funding, LLC (the “SPE”), a special-purpose, bankruptcy-remote wholly-owned subsidiary to purchase trade receivables generated by certain of the Company’s operating and sales subsidiaries, without recourse (other than customary indemnification obligations for breaches of specific representations and warranties), and then transfer senior undivided interests in up to $275,000 of those accounts receivable to a financial institution for the issuance of letters of credit or for cash borrowings for the ultimate benefit of the Company.
The SPE is consolidated into the Company’s financial statements, and therefore the purchase and sale of trade receivables by the SPE from the Company’s operating and sales receivables has no impact on the Company’s consolidated financial statements. The assets of the SPE, however, are not available to the creditors of the Company or any other subsidiary. The SPE pays facility fees, program fees and letter of credit fees (based on amounts of outstanding letters of credit), as defined in the definitive agreements for the A/R Facility. Available borrowing capacity is based on the amount of eligible accounts receivable as defined under the terms of the definitive agreements for the A/R Facility and varies over time. The A/R Facility was amended in June 2011 to increase the capacity of the A/R Facility from $150,000 to $190,000 and the A/R Facility was amended and restated in October 2011 to further increase the capacity of the A/R Facility to $275,000. Unless extended by the parties, the receivables purchase agreement supporting the borrowings under the A/R Facility expires October 17, 2014, or earlier upon the occurrence of certain events customary for facilities of this type.
As of December 31, 2011, letters of credit in the amount of $159,987 were outstanding under the A/R Facility and no cash borrowing transactions had taken place. As of December 31, 2010, letters of credit in the amount of $63,805 were outstanding under the A/R Facility and no cash borrowing transactions had taken place. If outstanding letters of credit exceed borrowing capacity, the Company is required to provide additional collateral in the form of restricted cash to secure outstanding letters of credit. Under the A/R Facility, the SPE is subject to certain affirmative, negative and financial covenants customary for financings of this type, including restrictions related to, among other things, liens, payments, merger or consolidation and amendments to the agreements underlying the receivables pool. Alpha Natural Resources, Inc. has agreed to guarantee the performance by its subsidiaries, other than the SPE, of their obligations under the A/R Facility. The Company does not guarantee repayment of the SPE’s debt under the A/R Facility. The financial institution, which is the administrator, may terminate the A/R Facility upon the occurrence of certain events that are customary for facilities of this type (with customary grace periods, if applicable), including, among other things, breaches of covenants, inaccuracies of representations and warranties, bankruptcy and insolvency events, changes in the rate of default or delinquency of the receivables above specified levels, a change of control and material judgments. A termination event would permit the administrator to terminate the program and enforce any and all rights and remedies, subject to cure provisions, where applicable.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Other
In 2010, the Company entered into certain agreements to develop, build and subsequently lease its new corporate headquarters. The Company has provided certain financial guarantees in connection with the development and construction of the building and is considered the owner of the building from an accounting perspective. The Company has recorded $20,291 as a liability in its consolidated financial statements for amounts expended and guaranteed by the Company through December 31, 2011. The Company recorded $7,819 as a liability in its consolidated financial statements for amounts expended and guaranteed by the Company through December 31, 2010.
Old Alpha Credit Agreement
On July 31, 2009, in conjunction with the Foundation Merger (Note 3), Old Alpha terminated its then-existing senior secured credit facilities, which consisted of a $250,000 term loan facility, of which $233,125 was outstanding at July 31, 2009 (and due in 2012), and a $375,000 revolving credit facility. On July 31, 2009, the Company repaid the outstanding balance under the term loan and recorded a loss on early extinguishment of debt to write off the remaining balance of deferred loan costs in the amount of $5,641.
Future Maturities
Future maturities of long-term debt as of December 31, 2011 are as follows:
(12) Asset Retirement Obligations
As of December 31, 2011 and 2010, the Company had recorded asset retirement obligation accruals for mine reclamation and closure costs totaling $915,665 and $222,993, respectively. The portion of the costs expected to be paid within a year of $190,993 and $13,006, as of December 31, 2011 and 2010, respectively, is included in accrued expenses and other current liabilities. There were no assets that were legally restricted for purposes of settling asset retirement obligations at December 31, 2011 or 2010. The Company is self-bonded for its asset retirement obligations in West Virginia and Wyoming, subject to periodic evaluation of the Company’s financial position by the applicable state and meeting certain financial ratios defined by each state. Asset retirement obligations for states other than Wyoming and West Virginia are secured by surety bonds.
Changes in the asset retirement obligations were as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(1) Revisions in estimated cash flows include $4,538 of a reduction in the asset retirement obligation resulting from the transfer of the related property to a third party.
(2) See Note 3.
(3) As a result of matters related to the treatment of mine water discharges for selenium more fully discussed in Note 20, the Company increased its asset retirement obligations by $55,316 out of which $37,137 was related to inactive mines and was recorded as a component of cost of coal sales in the Consolidated Statements of Operations for the year ended December 31, 2011.
(13) Other Non-current Liabilities
Other non-current liabilities consisted of the following:
(14) Fair Value of Financial Instruments and Fair Value Measurements
The estimated fair values of financial instruments are determined based on relevant market information. These estimates involve uncertainty and cannot be determined with precision. The following methods and assumptions are used to estimate the fair value of each class of financial instrument.
The carrying amounts for cash and cash equivalents, trade accounts receivable, net, prepaid expenses and other current assets, trade accounts payable, and accrued expenses and other current liabilities approximate fair value due to the short maturity of these instruments.
Long-term Debt: The fair values of the 2.375% Convertible Notes, 3.25% Convertible Notes and the New Senior Notes were estimated using observable market prices as these securities are traded. The fair values of the 2014 Notes and the term loans are estimated based on a current market rate of interest offered to the Company for debt of similar maturities.
The estimated fair values of long-term debt were as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(1) Net of debt discount of $670 as of December 31, 2011.
(2) Net of debt discount of $1,191 as of December 31, 2010.
(3) Net of debt discount of $33,727 as of December 31, 2011.
(4) Net of debt discount of $1,013 as of December 31, 2010.
(5) Net of debt discount of $52,249 and $65,145 as of December 31, 2011 and 2010, respectively.
ASC 820 requires disclosures about how fair value is determined for assets and liabilities and a hierarchy for which these assets and liabilities must be grouped, based on significant levels of inputs as follows:
Level 1 - Quoted prices in active markets for identical assets or liabilities;
Level 2 - Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and
Level 3 - Unobservable inputs in which there is little or no market data which require the reporting entity to develop its own assumptions.
The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
The following tables set forth by level, within the fair value hierarchy, the Company’s financial and non-financial assets and liabilities that were accounted for at fair value on a recurring and non-recurring basis as of December 31, 2011 and 2010, respectively. As required by ASC 820, financial and non-financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the determination of fair value for assets and liabilities and their placement within the fair value hierarchy levels.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the tables above.
Level 1 Fair Value Measurements
U.S. Treasury and Agency Securities and Mutual Funds Held in Rabbi Trust - The fair value of marketable securities is based on observable market data.
Level 2 Fair Value Measurements
Corporate Debt Securities - The fair values of the Company’s corporate debt securities are obtained from a third-party pricing service provider. The fair values provided by the pricing service provider are estimated using pricing models, where the inputs to those models are based on observable market inputs including credit spreads and broker-dealer quotes, among other inputs. The Company classifies the prices obtained from the pricing services within Level 2 of the fair value hierarchy because the underlying inputs are directly observable from active markets. However, the pricing models used do entail a certain amount of subjectivity and therefore differing judgments in how the underlying inputs are modeled could result in different estimates of fair value.
Forward Coal Purchase and Sales - The fair values of the forward coal purchase and sale contracts were estimated using discounted cash flow calculations based upon actual contract prices and forward commodity price curves. The curves were obtained from independent pricing services reflecting broker market quotes. The fair values are adjusted for counter-party risk, when applicable.
Commodity Swaps - The fair values of commodity swaps are estimated using valuation models which include assumptions about commodity prices based on those observed in the underlying markets. The fair values are adjusted for counter-party risk, when applicable.
Commodity Options - The fair values of the commodity options were estimated using an option pricing model that incorporates historical volatility of the underlying commodity, the strike price, notional amount, current market price and risk free interest rate. The fair values are adjusted for counter-party risk, when applicable.
Interest Rate Swaps - The fair values of the interest rate swaps were estimated using discounted cash flow calculations based upon forward interest-rate yield curves. The curves were obtained from independent pricing services reflecting broker market quotes. The fair values are adjusted for counter-party risk, when applicable.
Freight Swaps - The fair values of freight swaps are estimated using valuation models which include assumptions about freight prices based on those observed in the underlying markets. The fair values are adjusted for counter-party risk, when applicable.
(15) Derivative Financial Instruments
Forward Contracts
The Company manages price risk for coal sales and purchases through the use of coal supply agreements. The Company evaluates each of its coal sales and coal purchase forward contracts to determine whether they meet the definition of a derivative and if so, whether they qualify for the normal purchase normal sale (“NPNS”) exception prescribed by ASC 815-10-10.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
For those contracts that do meet the definition of a derivative, certain contracts also qualify for the NPNS exception based on management’s intent and ability to physically deliver or take physical delivery of the coal. Contracts that meet the definition of a derivative and do not qualify for the NPNS exception are accounted for at fair value and, accordingly, the Company includes the unrealized gains and losses in current period earnings or losses.
Swap Agreements
Commodity Swaps
The Company uses diesel fuel and explosives in its production process and incurs significant expenses for the purchase of these commodities. Diesel fuel and explosives expenses represented approximately 6%, 7%, and 8% of cost of coal sales for the years ended December 31, 2011, 2010, and 2009, respectively. The Company is subject to the risk of price volatility for these commodities and as a part of its risk management strategy, the Company enters into swap agreements with financial institutions to mitigate the risk of price volatility for both diesel fuel and explosives. The terms of the swap agreements allow the Company to pay a fixed price and receive a floating price, which provides a fixed price per unit for the volume of purchases being hedged. As of December 31, 2011, the Company had swap agreements outstanding to hedge the variable cash flows related to 59% and 34% of anticipated diesel fuel usage for calendar years 2012 and 2013, respectively. The average fixed price per swap for diesel fuel hedges is $2.82 per gallon and $3.00 per gallon for calendar years 2012 and 2013, respectively. As of December 31, 2011, the Company had swap agreements outstanding to hedge the variable cash flows related to approximately 34% of anticipated explosives usage in the Powder River Basin for calendar year 2012. All cash flows associated with derivative instruments are classified as operating cash flows in the Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010, and 2009.
The Company also sells coalbed methane through its Coal Gas Recovery business. The revenues derived from the sale of coalbed methane are subject to volatility based on the changes in natural gas prices. In order to reduce that risk, the Company enters into “pay variable, receive fixed” natural gas swaps for a portion of its anticipated gas production in order to fix the selling price for a portion of its production. The natural gas swaps have been designated as qualifying cash flow hedges. As of December 31, 2011, the Company had swap agreements outstanding to hedge the variable cash flows related to approximately 78% and 64% of anticipated natural gas production in 2012 and 2013, respectively.
Interest Rate Swaps
The Company has variable rate debt outstanding and is subject to interest rate risk based on volatility in underlying interest rates. The Company previously entered into pay fixed, receive variable interest rate swaps to convert the Company’s previous variable-rate term loan into fixed-rate debt. The interest rate swaps were designated as qualifying cash flow hedges. During the year ended December 31, 2009, the Company repaid the related term loan and de-designated the swaps as cash flow hedges. Accordingly, the Company reclassified $17,668 (net of income taxes of $5,881) from accumulated other comprehensive income (loss) into interest expense. The Company did not terminate the interest rate swaps due to the swaps’ potential benefit in offsetting a portion of the effect of interest rate changes in the Company’s other variable rate debt. Subsequent changes in fair value are recorded in interest expense.
The following tables present the fair values and location of the Company’s derivative instruments within the Consolidated Balance Sheets:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(1) As of December 31, 2011, $14,436 is recorded in prepaid expenses and other current assets and $2,209 is recorded in other non-current assets in the Consolidated Balance Sheets. As of December 31, 2010, $10,865 is recorded in prepaid expenses and other current assets and $3,045 is recorded in other non-current assets in the Consolidated Balance Sheets.
(2) As of December 31, 2011, $20,891 is recorded in prepaid expenses and other current assets and $6,362 is recorded in other non-current assets in the Consolidated Balance Sheets.
(3) As of December 31, 2010, $2,674 is recorded in prepaid expenses and other current assets in the Consolidated Balance Sheets.
(4) As of December 31, 2010, $19 is recorded in prepaid expenses and other current assets in the Consolidated Balance Sheets.
(1) As of December 31, 2011, $6,222 is recorded in accrued expenses and other current liabilities and $6,652 is recorded in other non-current liabilities in the Consolidated Balance Sheets. As of December 31, 2010, $3,256 is recorded in accrued expenses and other current liabilities and $114 is recorded in other non-current liabilities in the Consolidated Balance Sheets.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(2) As of December 31,2010, $3,958 is recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets.
(3) As of December 31, 2011, $15,456 is recorded in accrued expenses in the Consolidated Balance Sheets
(4) As of December 31, 2011, $436 is recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets. As of December 31, 2010, $36 is recorded in accrued expenses in the Consolidated Balance Sheets.
(5) As of December 31, 2011, $3 is recorded in accrued expenses and other current liabilities and $14 in other non-current liabilities in the Consolidated Balance Sheets. As of December 31, 2010, $40 is recorded in accrued expenses and other current liabilities and $224 is recorded in other non-current liabilities in the Consolidated Balance Sheets.
(6) As of December 31, 2011, $10,097 is recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets. As of December 31, 2010, $12,592 is recorded in accrued expenses and other current liabilities and $8,712 is recorded in other non-current liabilities in the Consolidated Balance Sheets.
(7) As of December 31, 2010, $47 is recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets.
The following table presents the gains and losses from derivative instruments for the years ended December 31, 2011, 2010, and 2009 and their location within the consolidated financial statements:
(1) Amounts recorded in other expenses in the Consolidated Statements of Operations.
(2) Amounts are recorded as a component of interest expense in the Consolidated Statements of Operations.
(3) Net of tax.
(1) Amounts are recorded as a component of other revenues in the Consolidated Statements of Operations.
(2) Amounts are recorded as a component of other expenses in the Consolidated Statements of Operations.
(3) Amounts are recorded as a component of interest expense in the Consolidated Statements of Operations.
Unrealized losses recorded in accumulated other comprehensive income (loss) are reclassified to income or loss as the financial swaps settle and the Company purchases the underlying items that are being hedged. During the next twelve months, the Company expects to reclassify approximately $11,692, net of tax, to earnings. The following table summarizes the changes to accumulated other comprehensive income (loss) related to hedging activities during the years ended December 31, 2011, 2010 and 2009:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(16) Income Taxes
The total income tax expense (benefit) provided on pre-tax income was allocated as follows:
Significant components of income tax expense (benefit) from continuing operations were as follows:
A reconciliation of the statutory federal income tax expense at 35% to income from continuing operations before income taxes and the actual income tax expense (benefit) is as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(1) Includes federal tax expense and state tax expense (net of federal tax benefit) of $23,454 and $2,112, respectively.
(2) Amount for the year ended December 31, 2011 includes federal tax benefits, state tax benefits and interest expense of $0, $1,012, and $45, respectively. Amount for the year ended December 31, 2010 includes federal tax benefits, state tax benefits and interest expense of $11,695, $2,807 and ($484), respectively.
The Patient Protection and Affordable Care Act (the “PPACA”) and the Reconciliation Act were signed into law in March 2010. As a result of these two acts, tax benefits available to employers that receive the Medicare Part D subsidy will be eliminated starting in years ending after December 31, 2012. Since these acts were signed into law during the year ended December 31, 2010, ASC 740 - Income Taxes, required that the effect of the tax law change be recorded immediately as a component of tax expense. The income tax effect related to these acts was a reduction of $25,566 to the deferred tax asset related to the postretirement prescription drug benefits.
IRS examinations for the years 2005-2007 were determined to be effectively settled during the year ended December 31, 2010, in addition to certain statutes of limitations expiring. The reversal of reserves provided an income tax benefit, net of interest, of $14,018.
Deferred income taxes result from temporary differences between the reporting of amounts for financial statement purposes and income tax purposes. The net deferred tax assets and liabilities included in the Consolidated Balance Sheets include the following amounts:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The breakdown of the net deferred tax liability as recorded in the accompanying Consolidated Balance Sheets is as follows:
Changes in the valuation allowance during the years ended December 31, 2011 and 2010 were as follows:
The Company has concluded that it is more likely than not that deferred tax assets, net of valuation allowances, currently recorded will be realized. The Company monitors the valuation allowance each quarter and makes adjustments to the allowance as appropriate.
At December 31, 2011, the Company has regular tax net operating loss carryforwards for Federal income tax purposes of $1,236,659 which are available to offset regular Federal taxable income. The net operating loss generated will not start to expire until 2023. The Company has gross net operating loss carryforwards for state income taxes of $1,310,221 which are available to offset future state taxable income generally through 2031. A valuation allowance has been provided for $897,342 of the state net operating losses. The Company also has alternative minimum tax credit carryforwards of approximately $216,815, which are available to reduce federal regular income tax in excess of the alternative minimum tax, if any, over an indefinite period.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The total amount of unrecognized tax benefits that would affect the Company’s effective tax rate if recognized is $28,741 as of December 31, 2011. The Company believes that it is unlikely that total unrecognized benefits recorded as of December 31, 2011 will significantly change during the next twelve months.
The Company’s policy is to classify interest and penalties related to uncertain tax positions as part of income tax expense. As of December 31, 2011, the Company has recorded accrued interest expense of $142.
The following reconciliation illustrates the Company’s liability for uncertain tax positions:
Tax years 2008-2010 remain open to federal and state examination. The Internal Revenue Service initiated a corporate income tax audit during the second quarter of 2011 for the Company’s 2008 and 2009 tax years.
(17) Employee Benefit Plans
The Company sponsors or participates in several benefit plans for its employees, including postemployment health care and life insurance, defined benefit and defined contribution pension plans, and workers’ compensation and black lung benefits.
In connection with the Massey Acquisition, the Company assumed all of the employee benefit plans of Massey. During the third quarter of 2011, the Company internally announced the comprehensive integration of employee benefits programs to align the employee benefits of Massey and Alpha employees which included a freeze of the Massey defined benefit plan to new participants as of January 1, 2012.
In connection with the Foundation Merger, the Company assumed all of the employee benefit plans of Foundation (the “Foundation Plans”). During the third quarter of 2010, the Company internally announced comprehensive integrated employee benefits programs which aligned the employee benefits of Old Alpha and Foundation employees. As a result, the Company’s defined benefit pension plans and the Supplemental Executive Retirement Plan assumed in the Foundation Merger (the “Plans”) were frozen, resulting in a curtailment gain of $5,051 being recognized in 2010.
In March 2010, the PPACA was enacted, potentially impacting the costs to provide healthcare benefits to the Company’s eligible active and certain retired employees and workers’ compensation benefits related to occupational disease resulting from coal workers’ pneumoconiosis (“Black Lung”). The PPACA has both short-term and long-term implications on healthcare benefit plan standards. Implementation of this legislation is planned to occur in phases, with plan standard changes taking effect beginning in 2010, but to a greater extent with the 2011 benefit plan year and extending through 2018. Plan standard changes that could affect the Company in the short term include raising the maximum age for covered dependents to receive benefits, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual, among other standard requirements. Plan standard changes that are expected to affect the Company in the long term include an excise tax on “high cost” plans and the elimination of annual dollar limits per covered individual, among other standard requirements.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Beginning in 2018, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds the certain dollar thresholds. The Company has accrued $35,224 as of December 31, 2011 for the estimated impact of the PPACA, which is included in pension and postretirement medical benefit obligations on the accompanying Consolidated Balance Sheets, with an offset to accumulated other comprehensive income (loss). The Company anticipates that certain government agencies will provide additional regulations or interpretations concerning the application of this excise tax. The Company will need to continue to evaluate the impact of the PPACA in future periods, and when these regulations or interpretations are published, the Company will evaluate its assumptions in light of the new information.
The PPACA also amended previous legislation related to coal workers’ Black Lung, providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims. The Company evaluated the impact of these changes to its current population of beneficiaries and possible future claimants, and as a result re-measured the obligations for its self-insured black lung plans during the first quarter of 2010. The re-measurement resulted in an estimated $6,658 increase to the obligation included in other non-current liabilities in the accompanying Consolidated Balance Sheets, with an offset to accumulated other comprehensive income (loss).
(a) Company Administered Postretirement Health Care and Life Insurance Benefits
The Company provides postretirement medical and life insurance benefits to certain eligible employees under various plans. Certain of the plans are contributory while others are noncontributory. Additionally, certain of the plans are established by collective bargaining agreements.
The Company assumed defined benefit health care plans as a result of the Massey Acquisition that provide postretirement medical benefits to eligible union and non-union employees. To be eligible, retirees must meet certain age and service requirements. Depending on year of retirement, benefits may be subject to annual deductibles, coinsurance requirements, lifetime limits and retiree contributions. These plans are unfunded.
The components of the change in accumulated benefit obligations of the plans for postretirement medical benefits were as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The following table details the components of the net periodic benefit cost for postretirement medical benefits:
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss are as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The estimated amount that will be amortized from Accumulated other comprehensive (income) loss into net period benefit cost in 2012 is as follows:
The weighted-average assumptions used to determine the postretirement plans’ benefit obligation as of December 31, 2011 and 2010 were as follows:
The discount rates used in determining net periodic postretirement medical benefit cost for the years ended December 31, 2011, 2010, and 2009 were as follows:
The discount rate assumption is determined from a published yield-curve table matched to timing of the Company’s projected cash out flows.
The following presents information about the postretirement plans’ weighted-average annual rate of increase in the per capita cost of covered benefits (i.e., health care cost trend rate):
Assumed health care trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care trend rates would have the following effects as of and for the year ended December 31, 2011:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
In December 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “MMA”) was enacted in the United States. The MMA introduced a prescription drug benefit under Medicare Part D as well as a federal subsidy to sponsors of benefit plans such as the Foundation postretirement plans as long as the provided benefits are actuarially equivalent to Medicare Part D. The MMA reduced the Company’s net periodic benefit cost by less than $1,000 in each of the years ending December 31, 2011 and 2010, and by approximately $2,230 in the year ending December 31,2009.
The Company continues to provide primary prescription drug benefits to Medicare eligible participants in the Massey and Foundation postretirement plans, pursuant to final regulations issued on the MMA by the Centers for Medicare and Medicaid Services (“CMS”) on January 21, 2005. The Company is also a participant in the federal subsidy payment program under the MMA, and the Federal subsidies received in the years ended December 31, 2011, 2010 and 2009 were $1,870, $1,848 and $837, respectively.
Employer contributions for the Company’s postretirement medical and life insurance benefit plans paid for the years ended December 31, 2011, 2010, and 2009 were $29,305, $26,745, and $9,588, respectively, net of federal subsidies received under the MMA. Employee contributions are not expected to be made and the Company’s plans are unfunded. The Company expects to contribute approximately $40,602 to its postretirement medical and life insurance plans in 2012.
The following represents the Company’s expected future postretirement medical and life insurance benefit payments for the next ten years, which reflect expected future service, as appropriate, and the expected federal subsidy related to MMA:
(b) Company Administered Defined Benefit Pension Plans
In conjunction with the Massey Acquisition, the Company assumed a qualified non-contributory defined benefit pension plan, which covers substantially all administrative and non-union employees of Massey. Based on a participant’s entrance date to the plan, the participant may accrue benefits based on one of four benefit formulas.
In addition to the qualified defined benefit pension plan noted above, the Company assumed a nonqualified supplemental benefit pension plan for certain salaried employees. Participants in this nonqualified supplemental benefit pension plan accrue benefits under the same formula as the qualified defined benefit pension plan, however, where the benefit is capped by the Internal Revenue Service (“IRS”) limitations, this nonqualified supplemental benefit pension plan compensates for benefits in excess of the IRS limit. This supplemental benefit pension plan is unfunded.
In conjunction with the Foundation Merger, the Company assumed Foundation’s two non-contributory defined benefit retirement plans (the “Pension Plan(s)”) covering certain salaried and non-union hourly employees and a non-qualified Supplemental Executive Retirement Plan (“SERP”). Benefits are based on either the employee’s compensation prior to retirement or plan specified amounts for each year of service with the Company.
The qualified non-contributory defined benefit pension plans assumed in the Massey Acquisition and in the Foundation Merger are collectively referred to as the “Pension Plans”. The non-qualified supplement benefit pension plan assumed in the Massey Acquisition and the non-qualified Supplement Executive Retirement Plan are collectively referred to as the “SERPs”.
Annual funding contributions to the Pension Plans are made as recommended by consulting actuaries based upon the Employee Retirement Income Security Act (“ERISA”) funding standards. Plan assets consist of equity and fixed income funds, private equity funds and a guaranteed insurance contract.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The following tables set forth the plans’ benefit obligations, fair value of plan assets and funded status:
Gross amounts recognized in accumulated other comprehensive (income) loss were as follows:
The following table details the components of net periodic benefit cost:
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss are as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The estimated amount that will be amortized from Accumulated other comprehensive (income) loss into net period benefit cost in 2012 is as follows:
Actuarial loss
$
The following table presents information applicable to plans with accumulated benefit obligations in excess of plan assets:
The current portion of the Company’s pension liability is the amount by which the actuarial present value of benefits included in the benefit obligation payable in the next twelve months exceeds the fair value of plan assets. However, even though the plan may be underfunded, if there are sufficient plan assets to make expected benefit payments to plan participants in the succeeding twelve months, no current liability is recognized. Accordingly, there was no current pension liability reflected in the Consolidated Balance Sheets as of December 31, 2011 and 2010.
The weighted-average actuarial assumptions used in determining the benefit obligations as of December 31, 2011 and 2010 were as follows:
The weighted-average actuarial assumptions used to determine net periodic benefit cost for the years ended December 31, 2011 and 2010 were as follows:
The discount rate assumption is determined from a published yield-curve table matched to timing of the Company’s projected cash out flows.
The expected long-term return on assets of the Pension Plans is established at the beginning of each year by the Company’s Benefits Committee in consultation with the plans’ actuaries and outside investment advisor. This rate is determined by taking into consideration the
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Pension Plans’ target asset allocation, expected long-term rates of return on each major asset class by reference to long-term historic ranges, inflation assumptions and the expected additional value from active management of the Pension Plans’ assets. For the determination of net periodic benefit cost in 2012, the Company will utilize an expected long-term return on plan assets of 7.25%.
Assets of the Pension Plans are held in trusts and are invested in accordance with investment guidelines that have been established by the Company’s Benefits Committee in consultation with the outside investment advisors. The target allocation for 2012 and the actual asset allocation as reported at December 31, 2011 for the plans assumed in the Foundation Merger are as follows:
The target allocation for 2012 and the actual net asset allocation as reported at December 31, 2011 for the plans assumed in the Massey Acquisition are as follows:
The asset allocation targets have been set with the expectation that the Pension Plans’ assets will fund the expected liabilities within an appropriate level of risk. In determining the appropriate target asset allocations the Benefits Committee considers the demographics of the Pension Plans’ participants, the funding status of each plan, the Company’s contribution philosophy, the Company’s business and financial profile and other associated risk factors. The Pension Plans’ assets are periodically rebalanced among the major asset categories to maintain the asset allocation within a specified range of the target allocation percentage.
For the years ended December 31, 2011, 2010 and 2009, $70,374, $43,478 and $27,986, respectively, of cash contributions were made to the Pension Plans and SERP. The Company expects to contribute between $25,000 and $30,000 to the Pension Plans in 2012.
The following represents expected future pension benefit and SERP payments for the next ten years, which reflect expected future service, as appropriate:
The fair values of the Company’s Pension Plans’ assets at December 31, 2011, by asset category are as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Fair Value Measurements at December 31, 2011
(a) This fund contains bonds representing a diversity of sectors and maturities. This fund also includes mortgage-backed securities and U.S. Treasuries.
(b) This category includes several private equity funds that invest primarily in U.S. and European markets.
(c) Receivable for investments sold at December 31, 2011, which approximates fair value.
The fair values of the Company’s Pension Plans’ assets at December 31, 2010, by asset category are as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Fair Value Measurements at December 31, 2010
(a) This fund contains bonds representing a diversity of sectors and maturities. This fund also includes mortgage-backed securities and U.S. Treasuries.
(b) This category includes several private equity funds that invest primarily in U.S. and European markets.
(c) This fund contains several underlying funds that invest primarily in U.S. markets and other world markets.
(d) Receivable for investments sold at December 31, 2010, which approximates fair value.
Changes in level 3 plan assets for the year ended December 31, 2011 were as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Changes in level 3 plan assets for the year ended December 31, 2010 were as follows:
The following is a description of the valuation methodologies used for assets measured at fair value:
Level 1 Plan Assets: Assets consist of individual security positions which are easily traded on recognized market exchanges. These securities are priced and traded daily, and therefore the fund is valued daily.
Level 2 Plan Assets: Funds consist of individual security positions which are mostly securities easily traded on recognized market exchanges. These securities are priced and traded daily, and therefore the fund is valued daily.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Level 3 Plan Assets: Assets are valued monthly or quarterly based on the Net Asset Value “NAV” provided by managers of the underlying fund investments. The NAVs provided typically reflect the fair value of each underlying fund investment, including unrealized gains and losses.
(c) Multi-Employer Pension Plans
Certain of the Company’s subsidiaries are subject to collective bargaining agreements with expiration dates ranging from December 31, 2016 to June 30, 2017 that require them to participate in a UMWA pension plan (the “1974 Plan”). The plan is a multi-employer pension plan administered by the UMWA and the Company is required to make contributions to the plan at rates defined by the various contracts. The 1974 Plan’s legal name is United Mine Workers of America 1974 Pension Plan and the Employer Identification Number is 52-1050282. The 1974 Plan is considered to be in Seriously Endangered Status for the plan year beginning July 1, 2011, because the actuary determined that the 1974 Plan’s funded percentage is less than 80%, and the 1974 Plan is projected to have an accumulated funding deficiency within six plan years after the plan year beginning July 1, 2011. Even though the 1974 Plan is projected to have an accumulated funding deficiency within six plan years after the plan year beginning July 1, 2011, it is expected to have sufficient assets to pay benefits and expenditures during this time. A funding improvement plan must be adopted by May 25, 2012 and may include increased contributions to the plan and/or modifications to certain future benefit accruals. For the years ended December 31, 2011, 2010 and 2009, the Company incurred expenses related to the 1974 Plan of $15,140, $19,915, and $8,387. The contributions to the 1974 Plan made by two of our wholly-owned subsidiaries, Cumberland Coal Resources, LP and Emerald Coal Resources, LP, represent more than 5% of the total contributions to the 1974 Plan.
In connection with the Massey Acquisition and the Foundation Merger, the Company assumed obligations to the Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”), that provides for the funding of medical and death benefits for certain retired members of the UMWA through premiums to be paid by assigned operators (former employers). The Company treats its obligations under the Coal Act as participation in a multi-employer plan and recognizes the expense as premiums are paid. Expense relative to premiums paid for the years ended December 31, 2011 and 2010 and the five months ended December 31, 2009, was $1,026, $865 and $28, respectively. As required under the Coal Act, the Company’s obligation to pay retiree medical benefits to its UMWA retirees is secured by letters of credit in the amount of $9,911 as of December 31, 2011.
(d) Workers’ Compensation and Pneumoconiosis (Black lung)
The Company is required by federal and state statutes to provide benefits to employees for awards related to workers’ compensation and black lung. In addition, as a result of the Massey Acquisition and the Foundation Merger, the Company assumed obligations related to providing workers’ compensation and black lung benefits to certain employees. The Company’s subsidiaries are insured for worker’s compensation and black lung obligations by a third-party insurance provider in all locations with the exception of West Virginia, where certain subsidiaries are self-insured for workers’ compensation state black lung related obligations and with the exception of Wyoming where the Company participates in a compulsory state-run fund for workers’ compensation. Certain of the Company’s subsidiaries are self-insured for black lung benefits and fund benefit payments through a Section 501(c)(21) tax-exempt trust fund.
The liability for self-insured workers’ compensation claims is an actuarially determined estimate of the undiscounted ultimate losses to be incurred on such claims based on the Company’s experience, and includes a provision for incurred but not reported losses. The liability for self-insured black lung benefits is an estimate of such benefit as determined by an independent actuary at the present value of the actuarially computed liability over the employee’s applicable term of service. Adjustments to the probable ultimate liability for workers’ compensation and black lung are made annually/semi-annually based on actuarial valuations and are included in operations as these are determined.
For the Company’s subsidiaries that are fully insured for workers’ compensation and black lung claims, the insurance premium expense for the years ended December 31, 2011, 2010, and 2009 was $25,766, $16,901, and $19,134, respectively.
For the Company’s subsidiaries that are self-insured for workers’ compensation claims, the liability at December 31, 2011 and 2010 was $187,606 and $51,702, respectively, including a current portion of $21,681 and $7,935, respectively. Self-insured workers’ compensation expense for the years ended December 31, 2011, 2010, and 2009 was $25,460, $15,573, and $6,768, respectively. Certain of the Company’s subsidiaries’ self-insured workers’ compensation obligations are secured by letters of credit in the amount of $72,195 and surety bonds in the amount of $10,133. In addition, certain of the Company’s subsidiaries’ self-insured workers’ compensation obligations are secured by $10,066 of deposits.
The following tables set forth the accumulated black lung benefit obligations, fair value of plan assets and funded status for the years ended December 31, 2011 and 2010:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(1) Assets of the plan are held in a Section 501(c)(21) tax-exempt trust fund and consist primarily of government debt securities. All assets are classified as Level 1 and valued based on quoted market prices.
Gross amounts related to the black lung obligations recognized in accumulated other comprehensive (income) loss consisted of the following as of December 31, 2011 and 2010:
The following table details the components of the net periodic benefit cost for black lung obligations:
Other changes in the black lung plan assets and benefit obligations recognized in other comprehensive (income) loss are as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The estimated amount that will be amortized from accumulated other comprehensive (income) loss into net period benefit cost in 2012 is as follows:
Expected amortization of net loss
$
1,269
The weighted-average assumptions related to black lung obligations used to determine the benefit obligation as of December 31, 2011 and 2010 were as follows:
The weighted-average assumptions related to black lung obligations used to determine net periodic benefit cost were as follows:
Estimated future cash payments related to black lung obligations for the fiscal years ending after December 31, 2011 are as follows:
(e) Defined Contribution and Profit Sharing Plans
The Company sponsors multiple defined contribution and profit sharing plans to assist its eligible employees in providing for retirement. Generally, under the terms of these plans, employees make voluntary contributions through payroll deductions and the Company makes matching and/or discretionary contributions, as defined by each plan. The Company’s total contributions to these plans for the years ended December 31, 2011, 2010, and 2009 were $46,866, $20,205, and $12,352, respectively.
(f) Self-Insured Medical Plan
Certain subsidiaries of the Company are principally self-insured for health insurance coverage provided for all of its active employees. In addition, certain of these subsidiaries utilize commercial insurance to cover specific claims in excess of $500. Estimated liabilities for health and medical claims are recorded based on the Company’s historical experience and include a component for incurred but not reported claims. During the years ended December 31, 2011, 2010, and 2009, the Company incurred total claims expense of $145,517, $92,058, and $63,081, respectively, which represents claims processed and an estimate for claims incurred but not reported.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(18) Stock-Based Compensation Awards
The Company’s primary stock-based compensation plan is the Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan (the “2010 LTIP”), which was approved on May 19, 2010 by the Company’s stockholders. The principal purpose of the 2010 LTIP is to advance the interest of the Company and its stockholders by providing incentives to certain employees and individuals who contribute significantly to the strategic and long-term performance objectives and growth of the Company. The 2010 LTIP provides for a variety of awards, including stock options, stock appreciation rights, restricted stock, restricted stock units and other share-based awards. Awards are granted at 100% of the fair market value of the underlying common stock on the date of grant. Awards generally vest ratably over a three year period or cliff vest after three years. The 2010 LTIP is currently authorized for the issuance of awards for up to 3,250,000 shares of common stock. At December 31, 2011, 2,445,540 shares of common stock were available for grant under the 2010 LTIP. The Company also has stock-based awards outstanding under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (the “2005 LTIP”) and the Foundation Amended and Restated 2004 Stock Incentive Plan (the “2004 SIP”).
Upon vesting of restricted stock and restricted share units (both time-based and performance-based) or the exercise of options, shares are issued from the 2010 LTIP, the 2005 LTIP and the 2004 SIP, respective of which plan the awards were granted.
In November 2008, the Board of Directors authorized the Company to repurchase common shares from employees (upon the election by the employee) to satisfy the employees’ minimum statutory tax withholdings upon the vesting of restricted stock and restricted share units (both time-based and performance-based). During the years ended December 31, 2011, 2010 and 2009, the Company repurchased 221,553, 367,860, and 309,457 common shares, respectively, from employees at an average price paid per share of $55.32, $45.30, and $28.68, respectively. Shares that are repurchased to satisfy the employees’ minimum statutory tax withholdings are recorded in Treasury stock at cost, and these shares are not added back into the pool of shares available for grant of the respective plans the shares were granted.
At December 31, 2011, the Company had three types of stock-based awards outstanding: restricted stock, restricted share units (both time-based and performance-based), and stock options. Stock-based compensation expense from continuing operations totaled $53,685, $33,255, and $37,802, for the years ended December 31, 2011, 2010, and 2009, respectively. For the years ended December 31, 2011, 2010, and 2009, approximately 72%, 75%, and 78%, respectively, of stock-based compensation expense from continuing operations is reported as selling, general and administrative expenses and approximately 28%, 25%, and 22%, respectively, of the stock-based compensation expense from continuing operations was recorded as a component of cost of coal sales. The total excess tax benefit recognized for stock-based compensation for the years ending December 31, 2011, 2010, and 2009 was $0, $5,505, and $434, respectively.
Restricted Stock Awards
Restricted stock awards granted to executive officers and key employees, generally vest ratably over three-years or cliff vest after three years (with accelerated vesting upon a change of control). Restricted stock awards granted to the Company’s directors are restricted until six months after termination of such director’s service on the Company’s Board of Directors (with accelerated vesting upon a change of control).
During the year ended December 31, 2009, the Company granted restricted stock awards to its executive officers, directors and key employees in the amount of 921,901, of which 544,759 remain outstanding at December 31, 2011. No awards were granted for the years ended December 31, 2011 and 2010.
Restricted stock award activity for the year ended December 31, 2011 is summarized in the following table:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The fair value of restricted stock awards that vested for the years ended December 31, 2011, 2010, and 2009 was $13,987, $20,062, and $11,453, respectively. As of December 31, 2011, there was $368 of unrecognized compensation cost related to non-vested restricted stock awards which is expected to be recognized as expense over a weighted-average period of 0.14 years.
Restricted Share Units
Time-Based Share Units
Time-based share units awarded to executive officers and key employees generally vest, subject to continued employment, ratably over three-year periods or cliff vest after three years (with accelerated vesting upon a change of control), depending on the recipients’ position with the Company. Time-based restricted share units granted to the Company’s directors generally vest at the time of grant, but are restricted until six months after termination of such director’s service on the Company’s Board of Directors (with accelerated vesting upon a change of control). Upon vesting of time-based share units, the Company issues authorized and unissued shares of the Company’s common stock to the recipient.
During the years ended December 31, 2011 and 2010, the Company granted time-based share units under the 2010 LTIP to certain executive officers, directors and key employees in the amount of 357,455 and 1,515, respectively, of which 341,118 remained outstanding at December 31, 2011.
During the years ended December 31, 2010, and 2009, the Company granted time-based share units under the 2005 LTIP to certain executive officers, directors and key employee’s in the amount of 221,466, and 218,750, respectively, of which 294,982 remained outstanding at December 31, 2011.
During the years ended December 31, 2010 and 2009, the Company granted time-based share units under the 2004 SIP to certain executive officers, directors and key employee’s in the amount of 141,692 and 139,650, respectively, of which 226,812 remained outstanding at December 31, 2011.
On July 31, 2009, the Company assumed 540,002 former Foundation performance share unit awards that converted to time-based share units upon change of control due to the Foundation Merger. These awards vest over various periods through February 29, 2012. The Company determined the fair value of these share units at the time of the Foundation Merger was $8,541, which is being recognized over the requisite service periods of the awards. At December 31, 2011, 346,920 of these time-based share units remained outstanding.
Time-based share unit activity for the year ended December 31, 2011 is summarized in the following table:
The fair value of time-based share unit awards that vested in the years ended December 31, 2011, 2010, and 2009 was $10,218, $7,754, and $374, respectively. As of December 31, 2011, there was $17,419 of unrecognized compensation cost related to non-vested time-based share units which is expected to be recognized as expense over a weighted-average period of 1.77 years.
Performance-Based Share Units
Performance-based share units awarded to executive officers and key employees generally cliff vest after three years, subject to continued employment (with accelerated vesting upon a change of control). Performance-based share units granted represent the number of shares of common stock to be awarded based on the achievement of targeted performance levels related to pre-established operating income goals,
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
strategic goals, and total shareholder return goals over a three year period and may range from 0 percent to 200 percent of the targeted amount. The grant date fair value of the awards related to operating income and strategic goals targets is based on the closing price of the Company’s common stock on the established grant date and is amortized over the performance period. The grant date fair value of the awards related to the total shareholder return target is based upon a Monte Carlo simulation and is amortized over the performance period. The Company reassesses at each reporting date whether achievement of each of the performance conditions is probable, as well as estimated forfeitures, and adjusts the accruals of compensation expense as appropriate. Upon vesting of performance-based share units, the Company issues authorized and unissued shares of the Company’s common stock to the recipient.
During 2011, the Company awarded 227,199 performance-based share units, of which 226,502 remain outstanding as of December 31, 2011. At December 31, 2011, the Company had assessed the total shareholder return and strategic operations targets as probable of achievement. As of December 31, 2011, there was $7,259 of unamortized compensation cost related to the 2011 performance-based share units which is expected to be recognized as expense over a weighted-average period of 1.99 years.
During 2010, the Company awarded 265,636 performance-based share units, of which 259,990 remain outstanding as of December 31, 2011. At December 31, 2011, the Company had assessed the total shareholder return and strategic operations targets as probable of achievement. As of December 31, 2011, there was $4,567 of unamortized compensation cost related to the 2010 performance-based share units which is expected to be recognized as expense over a weighted-average period of 1.00 years.
During 2009, the Company awarded 355,672 performance-based share units, of which 326,875 remain outstanding as of December 31, 2011. Prior to November 18, 2009, the portion of the awards related to strategic goals did not meet the definition of a grant date. After the successful completion of the Foundation Merger, the Company determined that attainment of the strategic goals of the awards was achieved on November 18, 2009, thus requiring the Company to recognize the associated expense based on the closing stock price on that date. At December 31, 2011, the Company had assessed the strategic goals and total shareholder return targets as probable of achievement. As of December 31, 2011, there was $0 of unrecognized compensation cost related to the 2009 performance-based share.
During the fourth quarter of 2010, the Company modified the performance criteria for certain restricted share units granted in 2009 and 2008 and remeasured the affected stock-based awards. Additional compensation expense of approximately $4,012 was to be recognized over the remaining vesting periods. For the years ended December 31, 2011 and 2010, approximately $2,487 and $1,525, respectively, of the additional compensation expense was recognized.
Performance-based share unit activity for the year ended December 31, 2011 is summarized in the following table:
Shares in the table above are based on the maximum shares that can be awarded based on the achievement of the performance criteria. The fair value of performance-based share unit awards granted in 2008 and vested on February 22, 2011 was $11,293. The fair value of performance-based share unit awards granted in 2007 and vested on February 10, 2010 was $18,841.
Non-Qualified Stock Options
On June 1, 2011, in connection with the Massey Acquisition, the Company issued 912,509 fully vested stock options to Massey employees to replace outstanding Massey options with an estimated fair market value of $29,217, of which $5,717 was expensed immediately and the remainder was treated as part of the purchase consideration for the Massey Acquisition. The Company estimated the fair market value using a trinomial lattice model with assumptions for volatility, expected remaining life of options, expected dividend yield and a risk-free rate of interest. As of December 31, 2011, 807,189 of the options were outstanding and exercisable.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The fair value of the Massey options assumed on June 1, 2011 was estimated using the Black-Scholes option-pricing model using the following assumptions:
· Price of the underlying stock:
· Closing stock price for Massey on June 1, 2011 - $65.14
· Closing stock price for Alpha on June 1, 2011 - $53.40
· Option exercise price:
· Pre-conversion option exercise prices - Ranging from $13.49 to $56.60
· Post-conversion option exercise prices - Ranging from $11.15 to $46.78 (Adjusted for the Massey Acquisition ratio of 1.21)
· Expected life in years - 8.50 years
· Risk-free interest rate - 2.60%
· Dividend yield - 0%
· Expected volatility - 47.66%
Insufficient data existed to develop a reliable expected stock option life, therefore, the simplified method was utilized to estimate the expected life of these options. The expected life in years was determined by using the midpoint between the valuation date and the expiration date. Expected volatility was based on both Alpha’s and Foundation’s pre-merger implied future stock price volatilities derived from exchange traded options and actual historic stock price volatilities.
The weighted-average fair value of the Massey options assumed on June 1, 2011 was $26.00.
On July 31, 2009, in connection with the Foundation Merger, the Company assumed 1,118,546 options from Foundation that were fully vested upon change of control due to the Foundation Merger. Of the 1,118,546 options assumed, 196,457 have a merger ratio adjusted exercise price of $4.50 and 922,089 have a merger ratio adjusted exercise price of $7.87. These options have an expiration date of August 10, 2014. The Company determined the fair value of these options at the time of the Foundation Merger and recognized a one-time charge of $600 for stock-based compensation in the third quarter of 2009. As of December 31, 2011, 19,966 of the $4.50 options were outstanding and exercisable and 151,614 of the $7.87 options were outstanding and exercisable.
The fair value of the Foundation options assumed on July 31, 2009 was estimated using the Black-Scholes option-pricing model using the following assumptions:
· Price of the underlying stock:
· Closing stock price for Foundation on July 31, 2009 - $35.93
· Closing stock price for Alpha on July 31, 2009 - $33.31
· Option exercise price:
· Pre-conversion option exercise prices - $4.87 and $8.53
· Post-conversion option exercise prices - $4.50 and $7.87 (Adjusted for the Foundation Merger ratio of 1.084)
· Expected life in years - 2.51 years
· Risk-free interest rate - 1.38%
· Dividend yield - 0.00%
· Expected volatility - 65.83%
Insufficient data existed to develop a reliable expected stock option life, therefore, the simplified method was utilized to estimate the expected life of these options. The expected life in years was determined by using the midpoint between the valuation date and the expiration date. Expected volatility was based on both Alpha’s and Foundation’s pre-merger implied future stock price volatilities derived from exchange traded options and actual historic stock price volatilities.
The weighted-average fair value of the Foundation options assumed on July 31, 2009 was $26.74.
Stock option activity for the year ended December 31, 2011 is summarized in the following table:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
As of December 31, 2011, the options outstanding and exercisable had an aggregate intrinsic value of $4,103. Cash received from the exercise of stock options during the years ended December 31, 2011, 2010, and 2009 was $4,316, $5,521, and $5,171, respectively. As of December 31, 2011, all compensation cost related to stock options has been recognized as expense.
The total intrinsic value of options exercised during the years ended December 31, 2011, 2010, and 2009 was $12,952, $17,449, and $15,186, respectively. The Company currently uses authorized and unissued shares to satisfy share award exercises.
A summary of the Company’s options outstanding and exercisable at December 31, 2011 follows:
(19) Related Party Transactions
For the years ended December 31, 2011, 2010, and 2009, there were no material related party transactions.
(20) Commitments and Contingencies
(a) General
Estimated losses from loss contingencies and legal expenses associated with the contingency are accrued by a charge to income when information available indicates that it is probable that an asset has been impaired or a liability has been incurred and the amount of the loss can be reasonably estimated. If a loss contingency is not probable or reasonably estimable, disclosure of the loss contingency is made in the consolidated financial statements when it is at least reasonably possible that a loss will be incurred and the loss is material.
(b) Commitments and Contingencies
Commitments
The Company leases coal mining and other equipment under long-term operating leases with varying terms. In addition, the Company leases mineral interests and surface rights from land owners under various terms and royalty rates.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
As of December 31, 2011, aggregate future minimum non-cancelable lease payments under operating leases and minimum royalties under coal leases were as follows:
For the years ended December 31, 2011, 2010, and 2009, net rent expense amounted to $73,092, $18,659, and $11,463, respectively, and coal royalty expense from continuing operations amounted to $322,890, $192,834, and $117,895, respectively.
Other Commitments
As of December 31, 2011, the Company had commitments to purchase 3.8 million tons of coal at a cost of approximately $320,501 during 2012.
In September 2011, the Company entered into a federal coal lease, which contains an estimated 130.2 million tons of proven and probable coal reserves in the Powder River Basin. The lease bid was $143,415, payable in five equal annual installments of $28,683. The first installment was paid in September 2011. The remaining four annual installments of $28,683 are due each September until the obligation is satisfied in 2015.
The Company has another obligation for a federal coal lease, which contains an estimated 224.0 million tons of proven and probable coal reserves in the Powder River Basin. The lease bid was $180,540, payable in five equal annual installments of $36,108. The first two installments were paid in 2009 and 2008 by Foundation. The third and fourth installments have been paid by the Company. The remaining annual installment of $36,108 is due on May 1, 2012.
Also, see Note 11 regarding the Company’s Other debt and Note 7 regarding equipment purchase commitments.
Contingencies
Extensive regulation of the impacts of mining on the environment and of maintaining workplace safety, and related litigation, has had or may have a significant effect on the Company’s costs of production and results of operations. Further regulations, legislation or litigation in these areas may also cause the Company’s sales or profitability to decline by increasing costs or by hindering the Company’s ability to continue mining at existing operations or to permit new operations.
(c) Guarantees and Financial Instruments with Off-Balance Sheet Risk
In the normal course of business, the Company is a party to certain guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit, performance or surety bonds, and other guarantees and indemnities related to the obligations of affiliated entities which are not reflected in the Company’s Consolidated Balance Sheets. Management does not expect any material losses to result from these guarantees or other off-balance sheet financial instruments. The amount of outstanding surety bonds related to the Company’s reclamation obligations as of December 31, 2011 is $440,911.
Letters of Credit
The amount of outstanding bank letters of credit issued under the Company’s accounts receivable securitization program as of December 31, 2011 is presented in Note 11. As of December 31, 2011, the Company had $0.3 million of additional letters of credit outstanding under the Revolving Facility.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(d) Legal Proceedings
The Company’s legal proceedings range from cases brought by a single plaintiff to class actions. These legal proceedings, as well as governmental examinations, involve various business units and a variety of claims including, but not limited to, contract disputes, personal injury claims, property damage claims (including those resulting from blasting, trucking and flooding), environmental and safety issues, and employment matters. While some matters pending against the Company or its subsidiaries specify the damages claimed by the plaintiffs, many seek an unquantified amount of damages or are at very early stages of the legal process. Even when the amount of damages claimed against the Company or its subsidiaries is stated, the claimed amount may be exaggerated or unsupported. As a result, some matters have not yet progressed sufficiently through discovery and development of important factual information and legal issues to enable the Company to estimate a range of possible loss. The Company intends to defend these legal proceedings vigorously, litigating or settling cases where in management’s judgment it would be in the best interest of shareholders to do so.
The Company evaluates, on a quarterly basis, developments in legal proceedings and governmental examinations that could cause an increase or decrease in the amount of the reserves previously recorded. Excluding fees paid to external legal counsel, the Company recognized (income) expense, net of expected insurance recoveries, associated with litigation-related reserves of $2,100 and $1,100 during the years ended December 31, 2011 and 2010, respectively.
Federal Securities Class Action
On April 29, 2010 and May 28, 2010, two purported class actions that were subsequently consolidated into one case were brought against, among others, Massey, now the Company’s subsidiary Alpha Appalachia Holdings, Inc. (“Massey” or “Alpha Appalachia”), in the United States District Court for the Southern District of West Virginia in connection with alleged violations of the federal securities laws. The lead plaintiffs allege, purportedly on behalf of a class of former Massey stockholders, that (i) Massey and certain former Massey directors and officers violated Section 10(b) of the Securities and Exchange Act of 1934, as amended, (the “Exchange Act”), and Rule 10b-5 thereunder by intentionally misleading the market about the safety of Massey’s operations and that (ii) Massey’s former officers violated Section 20(a) of the Exchange Act by virtue of their control over persons alleged to have committed violations of Section 10(b) of the Exchange Act. The lead plaintiffs seek a determination that this action is a proper class action; certification as class representatives; an award of compensatory damages in an amount to be proven at trial, including interest thereon; and an award of reasonable costs and expenses, including counsel fees and expert fees.
On February 16, 2011, the lead plaintiffs moved to partially lift the statutory discovery stay imposed under the Private Securities Litigation Reform Act of 1995 (“PSLRA”). On March 3, 2011, the United States moved to intervene and to stay discovery until the completion of criminal proceedings allegedly arising from the same facts that allegedly give rise to this action. On April 15, 2011, the United States and the lead plaintiffs informed the court that they had reached an agreement regarding the United States’ motions and jointly requested that if the court decided to lift the statutory discovery stay, the court limit the discovery to be provided by Massey in certain respects.
On April 25, 2011, the defendants moved to dismiss the operative complaint. On June 9, 2011, plaintiffs filed a memorandum in opposition to the defendants’ motion to dismiss. The defendants’ motion to dismiss is currently pending.
On September 28, 2011, the court granted plaintiffs’ motion to partially lift the PSLRA discovery stay, granted the United States’ motion to intervene and imposed the conditions on discovery requested by the United States and plaintiffs.
Upper Big Branch (“UBB”) Explosion and Related Investigations
On April 5, 2010, before the acquisition of Massey by the Company, an explosion occurred at the UBB mine, resulting in the deaths of 29 miners and serious physical injuries and/or alleged psychiatric injuries to two others. The Federal Mine Safety and Health Administration (“MSHA”), the Office of Miner’s Health, Safety, and Training of the State of West Virginia (“State”), and the Governor’s Independent Investigation Panel (“GIIP”) initiated investigations into the cause of the UBB explosion and related issues. Additionally, the U.S. Attorney for the Southern District of West Virginia (the “Office”) commenced a grand jury investigation. The GIIP published its final report on May 19, 2011; MSHA released its final report on December 6, 2011; and the State released its final report on February 23, 2012.
On December 6, 2011, the Company, the Office and the United States Department of Justice entered into a Non-Prosecution Agreement (the “Agreement”) resolving the criminal investigation against Massey and its affiliates relating to the UBB explosion and other health and safety related issues at Massey, and the Company also reached a comprehensive settlement with MSHA resolving outstanding civil citations, violations, and orders related to MSHA’s investigation arising from the UBB explosion and other non-UBB related matters involving legacy
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Massey entities prior to the Massey Acquisition. The Agreement does not resolve individual responsibilities related to the UBB explosion.
Under the terms of the Agreement and settlement, the Company has agreed to pay outstanding MSHA fines, and has agreed to invest in additional measures designed to improve miner health and safety, provide restitution to the families of the fallen miners and two individuals injured in the UBB explosion, and create a charitable organization to research mine safety. The Company has further agreed to cooperate fully with all governmental agencies in all continuing investigations and prosecutions against any individuals that arise out of the UBB explosion and related conduct described in the Agreement until such investigations and prosecutions are concluded.
The Company cannot predict the outcome of these investigations, including whether or not any individual will become subject to possible criminal and civil penalties or enforcement actions. In order to accommodate these investigations, the UBB mine has been idled since the explosion. The Company has sought permission to close the UBB mine permanently; regulatory authorities have not yet granted such permission.
Wrongful Death and Personal Injury
As of December 31, 2011, nineteen of the twenty-nine families of the deceased miners had filed wrongful death suits against Massey and certain of its subsidiaries in Boone County Circuit Court. In addition, as of December 31, 2011, two seriously injured employees had filed personal injury claims against Massey and certain of its subsidiaries in Boone County Circuit Court seeking damages for physical injuries and/or alleged psychiatric injuries, and ten employees had filed lawsuits against Massey and certain of its subsidiaries in Boone County Circuit Court alleging emotional distress or personal injuries due to their proximity to the explosion. On October 14, 2011, certain of the individual defendants filed motions to dismiss several of the wrongful death actions. On the same date, Massey and its subsidiaries that are named as defendants answered several of the wrongful death actions. On November 10, 2011, additional answers were served in the wrongful death actions.
On September 22, 2011, the court ordered that the pending wrongful death cases be consolidated with the Uniform Fraudulent Transfer Act action described below and mediated by a panel of three mediators. These mediations are, per order of the court, strictly confidential. The Company has now reached settlements with all twenty-nine families of the deceased miners as well as the two employees who were seriously injured. These settlements remain subject to court approval.
Uniform Fraudulent Transfers Act Action
On June 1, 2011, certain of the plaintiffs who had filed wrongful death cases filed a complaint against Massey, Massey Coal Services, Inc., Performance Coal Company, and certain individuals in the Circuit Court of Boone County, West Virginia, alleging that the Massey Acquisition represented a fraudulent transfer intended to prevent plaintiffs from recovering damages in their wrongful death actions. Plaintiffs request that the court order defendants to post a bond of at least $500,000.
On June 22, 2011, certain of the former Massey directors filed a motion for a more definite statement, requesting that the court order plaintiffs to clarify their allegations and how their allegations constitute a violation of the Uniform Fraudulent Transfer Act. On July 27, 2011, plaintiffs opposed the motion for a more definite statement. On August 24, 2011, the former directors filed a reply brief in further support of their motion. The court heard oral arguments on defendants’ motion on September 22, 2011. At the hearing, the court ordered that this case be mediated with the wrongful death cases, as discussed above.
Derivative and Related Class Action Litigation
A number of purported former Massey stockholders have brought lawsuits derivatively, purportedly on behalf of Massey, in West Virginia and Delaware state courts, in connection with the April 5, 2010 explosion at the UBB mine and related claims. Certain of these former stockholders have also initiated contempt proceedings in West Virginia state court in connection with alleged violations of the settlement of a previous derivative lawsuit. In addition, these and other purported former Massey stockholders have asserted class action claims allegedly arising out of the Massey Acquisition in Delaware and West Virginia state courts and Virginia federal court. These cases are summarized below.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Delaware Chancery Court
In a case filed on April 23, 2010 in Delaware Chancery Court, In re Massey Energy Company Derivative and Class Action Litigation (“In re Massey”), a number of purported former Massey stockholders (the “Delaware Plaintiffs”) allege, purportedly on behalf of Massey, that certain former Massey directors and officers breached their fiduciary duties by failing to monitor and oversee Massey’s employees, allegedly resulting in fines against Massey and the explosion at UBB, and by wasting corporate assets by paying allegedly excessive and inflated amounts to former Massey Chairman and Chief Executive Officer Don L. Blankenship as part of his retirement package. The Delaware Plaintiffs also allege, on behalf of a purported class of former Massey stockholders, that certain former Massey directors breached their fiduciary duties by agreeing to the Massey Acquisition. The Delaware Plaintiffs allege that defendants breached their fiduciary duties by failing to secure the best price possible, by failing to secure any downside protection for the acquisition consideration, and by purportedly eliminating the possibility of a superior proposal by agreeing to a “no shop” provision and a termination fee. In addition, the Delaware Plaintiffs allege that defendants agreed to the Massey Acquisition to eliminate the liability that defendants faced on the Delaware Plaintiffs’ derivative claims. Finally, the Delaware Plaintiffs allege that defendants failed to fully disclose all material information necessary for Massey stockholders to cast an informed vote on the Massey Acquisition.
The Delaware Plaintiffs also name the Company and Mountain Merger Sub, Inc. (“Merger Sub”), the Company’s wholly-owned subsidiary created for purposes of effecting the Massey Acquisition, which, at the effective time of the Massey Acquisition, was merged with and into Massey, as defendants. The Delaware Plaintiffs allege that the Company and Merger Sub aided and abetted the former Massey directors’ alleged breaches of fiduciary duty and agreed to orchestrate the Massey Acquisition for the purpose of eliminating the former Massey directors’ potential liability on the derivative claims.
The Delaware Plaintiffs seek an award against each defendant for restitution and/or compensatory damages, plus pre-judgment interest; an order establishing a litigation trust to preserve the derivative claims asserted in the complaint; and an award of costs, disbursements and reasonable allowances for fees incurred in this action. The Delaware Plaintiffs also sought to enjoin consummation of the Massey Acquisition. The court denied their motion for a preliminary injunction on May 31, 2011.
Two additional putative class actions were brought against Massey, certain former Massey directors and officers, the Company and Merger Sub in the Delaware Court of Chancery following the announcement of the Massey Acquisition. Silverman v. Phillips, et al., filed on February 7, 2011 (“Silverman”), and Goe v. Massey Energy Company, et al., filed on February 14, 2011 (“Goe”), assert allegations that are nearly identical to those made by the Delaware Plaintiffs in In re Massey. Silverman and Goe were consolidated for all purposes with In re Massey on February 9, 2011 and February 24, 2011, respectively.
On June 10, 2011, Massey moved to dismiss the Delaware Plaintiffs’ derivative claims on the ground that the Delaware Plaintiffs, as former Massey stockholders, lacked the legal right to pursue those claims, and the Company and Alpha Appalachia Merger Sub moved to dismiss the purported class action claim against them for failure to state a claim upon which relief may be granted. On June 10 and 13, 2011, certain former Massey director and officer defendants moved to dismiss the derivative claims and filed answers to the remaining direct claims.
On September 14, 2011, the parties submitted a Stipulation Staying Proceedings, which stays the matter until March 1, 2012, without prejudice to the parties’ right to seek an extension or a termination of the stay by application to the court. The court approved the stipulation and entered the stay that same day. On January 31, 2012, the Company and Alpha Appalachia requested that the Delaware Plaintiffs consent to a six month extension of the stay order (the “Stay Order”); the Delaware Plaintiffs refused to do so. On February 21, 2012, the Company and Alpha Appalachia filed a motion to extend the Stay Order for an additional five months through August 1, 2012. The motion remains pending.
West Virginia State Court
In a case filed on April 15, 2010 in West Virginia state court, three purported former Massey stockholders (the “West Virginia Plaintiffs”) allege, purportedly on behalf of Massey, that certain former Massey directors and officers breached their fiduciary duties by failing to monitor and oversee Massey’s employees, allegedly resulting in fines against Massey and the explosion at UBB. The West Virginia Plaintiffs seek an award against each defendant and in favor of Massey for the amount of damages sustained by Massey as a result of defendants’ alleged breaches of fiduciary duty and an award to the West Virginia Plaintiffs of the costs and disbursements of the action, including reasonable attorneys’ fees, accountants’ and experts’ fees, costs, and expenses.
On May 2, 2011, the West Virginia Plaintiffs moved for leave to amend their complaint to add Alpha and Merger Sub as additional defendants and to add claims allegedly arising out of the then-proposed Massey Acquisition. In their proposed amended complaint, the West Virginia Plaintiffs allege that certain former Massey directors breached their fiduciary duties by failing to obtain the highest price reasonably available for Massey and by failing to disclose material information to Massey’s then-stockholders in connection with the
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
stockholder vote on the Massey Acquisition. The West Virginia Plaintiffs also allege that Massey, Merger Sub and the Company aided and abetted the former Massey directors’ breaches of fiduciary duty. The West Virginia Plaintiffs further allege that certain former Massey directors wasted corporate assets by failing to maintain sufficient internal controls over Massey’s safety and environmental reporting; failing to properly consider the interests of Massey and its stockholders, including the value of the derivative claims asserted by the West Virginia Plaintiffs in the Massey Acquisition; failing to conduct proper supervision; paying undeserved incentive compensation to certain Massey executive directors, particularly former Massey Chairman and CEO Don L. Blankenship during Massey’s alleged years of noncompliance with safety regulations and more recently as part of Blankenship’s retirement package; incurring millions of dollars in fines due to safety and environmental violations; and incurring potentially hundreds of millions of dollars of legal liability and/or legal costs to defend defendants’ allegedly unlawful actions. Finally, the West Virginia Plaintiffs’ proposed amended complaint alleges that certain former Massey directors were unjustly enriched by their compensation as directors.
On May 25, 2011, the West Virginia Plaintiffs filed a petition with the West Virginia Supreme Court for a preliminary injunction against the consummation of the Massey Acquisition, which was denied on May 31, 2011.
On June 24, 2011, the defendants moved to dismiss the West Virginia Plaintiffs’ original complaint on the grounds that plaintiffs, as former Massey stockholders, lacked the legal right to pursue those claims, or, alternatively, to stay this case in favor of In re Massey, described above. Defendants also filed an opposition to the West Virginia Plaintiffs’ motion to amend. On August 19, 2011, the West Virginia Plaintiffs filed a combined memorandum in opposition to defendants’ motion to dismiss or stay and in further support of their motion to amend. On August 22, 2011, defendants filed a memorandum in further support of their motion to dismiss or stay and in further opposition to plaintiffs’ motion to amend. On August 23, 2011, the court held a hearing on defendants’ motion to dismiss and plaintiffs’ motion to amend. Without deciding the motions, the court requested the parties to submit competing proposed orders containing findings of fact and conclusions of law and proposed scheduling orders for the court’s consideration, which the parties did on September 9, 2011. The motions remain pending.
U.S. District Court - Eastern District of Virginia
In the United States District Court for the Eastern District of Virginia, purported former Massey stockholder Benjamin Mostaed (“Mostaed”) alleges in a suit filed on February 2, 2011, and amended thereafter, purportedly on behalf of a class of former Massey stockholders, that Massey, Alpha and certain former Massey directors violated Sections 14(a) of the Exchange Act and Rule 14a-9 thereunder by filing a false and misleading preliminary proxy statement in connection with the then-proposed Massey Acquisition; that Massey and certain former Massey directors violated Section 20(a) of the Exchange Act by virtue of their control over persons alleged to have committed violations of Section 14(a) of the Exchange Act; that certain former Massey directors violated their fiduciary duties by causing Massey to enter into the Merger Agreement with Alpha pursuant to an unfair process that resulted in an unfair offer with preclusive deal protection devices that allegedly inhibited superior proposals; and that Massey and Alpha aided and abetted the former Massey directors’ alleged breaches of fiduciary duty. Mostaed sought an injunction preventing the consummation of the Massey Acquisition; rescission of the Merger Agreement; and an award of the costs and disbursements of the action, including reasonable attorneys’ and experts’ fees.
On February 4, 2011, William D. Perkins (“Perkins”), another purported former Massey stockholder, filed a suit in the Eastern District of Virginia similar to Mostaed’s. On February 17, 2011, Mostaed requested that the court consolidate the two pending actions, along with any subsequently filed actions challenging the proposed transaction. Defendants did not oppose the motion. On June 3, 2011, the court granted the motion.
On June 24, 2011, Mostaed informed the court that, aside from a motion for an award of attorneys’ fees, he did not intend to prosecute the action further and would voluntarily dismiss his claims.
On July 13, 2011, Mostaed and Perkins moved for an award of attorneys’ fees, reimbursement of expenses and incentive awards, contending that voluntary remedial measures implemented by defendants and sought by Mostaed (i.e., additional disclosure) had mooted Mostaed’s claims. On July 26, 2011, defendants filed their opposition and on August 4, 2011, Mostaed and Perkins filed their reply brief. The court subsequently denied plaintiffs’ request for oral argument. The motion remains pending.
Contempt Proceedings
On April 16, 2010, Manville Personal Injury Settlement Trust (“Manville”), one of the West Virginia Plaintiffs, filed a petition in the Circuit Court of Kanawha County, West Virginia, requesting that the court initiate civil contempt proceedings against certain of the then-current members of Massey’s board of directors with respect to alleged violations of a settlement agreement. In July 2007, Manville filed a complaint, purportedly on behalf of Massey, alleging that certain of Massey’s then directors and officers breached their fiduciary duties. On May 20, 2008, the parties executed a stipulation of settlement, which the court subsequently approved. The settlement provided for a release of
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
all claims that were or could have been asserted on behalf of Massey in exchange for, among other things, certain corporate governance reforms and an agreement that the Massey board of directors would make a Corporate Social Responsibility Report to its stockholders on an annual basis that would include, among other things, a report on Massey’s environmental and worker safety compliance. Manville alleges that Massey’s 2009 Corporate Social Responsibility Report did not contain a sufficient report on worker safety compliance. On April 22, 2010, the court issued an order for a rule to show cause, initiating the contempt proceedings.
On May 31, 2011, Manville, now joined by the other two West Virginia Plaintiffs, filed a new petition for civil contempt, requesting that the court initiate civil contempt proceedings against certain of the then-current members of Massey’s board of directors and certain then-current Massey officers in connection with certain additional alleged violations of the settlement.
On June 22, 2011, the individual defendants that have been served with the new petition filed a motion to dismiss that petition, as well as the original April 16 petition, and also moved to vacate the 2008 order, in which the court approved the settlement, as against them. On June 28, 2011, nominal defendant Alpha Appalachia joined in the individual defendants’ motions to dismiss and vacate. On July 21, 2011, the court held a hearing on the defendants’ motions to dismiss and vacate.
On September 29, 2011, the court granted the individual defendants’ motions to dismiss and vacate and ordered that the contempt proceedings be terminated in their entirety. The plaintiffs have filed an appeal.
Well Water Suit
Since September 2004, approximately 738 plaintiffs have filed approximately 400 suits against the Company’s subsidiaries Alpha Appalachia and Rawl Sales & Processing Co. in the Circuit Court of Mingo County, West Virginia (“Mingo Court”), for alleged property damage and personal injuries arising out of slurry injection and impoundment practices during the period of 1978 through 1987 allegedly contaminating plaintiffs’ water wells. Plaintiffs sought injunctive relief and compensatory damages in excess of $170,000 and unquantified punitive damages, including medical monitoring for the next 30 years.
A mediation session held on July 25-27, 2011 resulted in settlement of all plaintiffs’ claims. A hearing was held on September 29, 2011 for Court approval of the settlement, and the Company continues to await court approval of the settlement. The Company believes that the terms of the settlement will not result in any material impact on its results of operations.
Mine Water Discharge Suits
The Sierra Club and others have filed two citizens’ suits against several of the Company’s subsidiaries in federal court in the Southern District of West Virginia (“Southern District Court”) alleging violations of the terms of its water discharge permits. The plaintiffs in both cases have sought a civil penalty as well as injunctive relief.
One of the cases is limited to allegations that two of the Company’s subsidiaries, Independence Coal Company and Jacks Branch Coal Company, are violating limits on the allowable concentrations of selenium in their discharges of storm water from several surface mines. In August 2011, the Company’s subsidiaries reached a tentative settlement with plaintiffs on material terms, and in December 2011, the court gave final approval to the settlement agreed upon by the parties. The Company believes that the terms of the settlement will not result in any material impact on its results of operations.
The other action is limited to claims that several of the Company’s subsidiaries are violating discharge limits on substances other than selenium, such as aluminum. The Company reached a tentative settlement with the plaintiffs regarding this case, and in August 2011, the Court approved the final settlement. The Company has made all the civil penalty payments called for under the agreement and believes that the terms of the settlement will not result in any material impact on its results of operations.
The West Virginia Department of Environmental Protection has brought civil enforcement actions against three of the Company’s subsidiaries, Riverside Energy Company, LLC, Paynter Branch Mining, Inc. and Pioneer Fuel Corporation, in various West Virginia state courts seeking civil penalties based on alleged discharge of selenium, and in one case, other additional materials, in excess of permitted levels. In October 2011, Riverside Energy Company, LLC reached a tentative agreement with the plaintiffs to settle the dispute, and in December 2011, the Court approved the final settlement. Riverside has made all the civil penalty payments called for under the agreement, and the Company believes that the terms of the settlement will not result in any material impact on its results of operations. The suits against Paynter Branch Mining, Inc. and Pioneer Fuel Corporation remain ongoing. The Company does not believe that the amounts of any civil penalties fines resulting from the Paynter Branch Mining, Inc. and Pioneer Fuel Corporation cases will be material to its results of operations.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The tentative settlements reached in the selenium cases above include fines and penalties, which the Company believes will not be material to its results of operations, and requirements to comply with selenium discharge limits on specific permits involved in the cases. The estimated future costs to treat for selenium discharges on specific permits involved include costs to build and to maintain water treatment systems. For permits that are active, capital costs (expected to be approximately $23,000) will be capitalized as property and equipment and depreciated over the expected lives and annual water treatment costs (expected to be approximately $2,300 annually) will be expensed as incurred. For post-closing periods on active permits as well as non-active permits, estimated future treatment costs have been included in asset retirement obligations.
Nicewonder Litigation
In December 2004, prior to the Company’s acquisition of Nicewonder in October 2005, the Affiliated Construction Trades Foundation (“ACTF”), a division of the West Virginia State Building and Construction Trades Council, brought an action against the West Virginia Department of Transportation, Division of Highways (“WVDOH”) and Nicewonder Contracting, Inc. (“NCI”), which became the Company’s wholly-owned indirect subsidiary as a result of the Nicewonder acquisition, in the United States District Court in the Southern District of West Virginia. The plaintiff sought a declaration that the contract between NCI and the State of West Virginia related to NCI’s road construction project was illegal as a violation of applicable West Virginia and federal competitive bidding and prevailing wage laws and sought to enjoin performance of the contract, but did not seek monetary damages.
On September 30, 2009, the District Court issued an order that dismissed or denied for lack of standing all of the plaintiff’s claims under federal law and remanded the remaining state claims to the Circuit Court of Kanawha County, West Virginia for resolution. On May 7, 2010, the Circuit Court of Kanawha County entered summary judgment in favor of NCI. On June 22, 2011, the West Virginia Supreme Court of Appeals reversed the Circuit Court order granting summary judgment in favor of NCI, and remanded the case back to the Circuit Court for further proceedings. Following remand, ACTF filed a motion for summary judgment, which the Circuit Court denied on November 9, 2011. ACTF has challenged the order denying its summary judgment motion to the West Virginia Supreme Court of Appeals, and the matter is scheduled for oral argument on April 12, 2012.
Fluor Litigation
Alpha Appalachia and certain of its subsidiaries are also parties to a number of lawsuits and other legal proceedings related to certain non-coal businesses (the “Prior Business”) previously conducted by its former affiliate Fluor Corporation. These lawsuits include the Alexander-Pederson-Helig cases in which two of Alpha Appalachia’s subsidiaries, Appalachia Holding Company (“Appalachia Holding”) and DRIH Corporation (“DRIH”), were named defendants along with Fluor. In July 2011, those cases resulted in a jury award in the City of St. Louis Circuit Court in favor of the plaintiffs for $38,500 in compensatory and economic damages and $320,000 in punitive damages. The total aggregate judgment against Alpha Appalachia’s subsidiaries is $118,500.
Under the terms of the Distribution Agreement entered into by Alpha Appalachia (then called Massey) and Fluor as of November 30, 2000 in connection with the spin-off of Fluor by Massey, Fluor agreed to indemnify Massey with respect to all such legal proceedings and assumed defense of the proceedings. Consistent with that agreement, in September 2011, Fluor submitted to the Court a number of surety bonds covering the full amount of the judgments against Fluor and Alpha Appalachia’s subsidiaries in the Alexander-Pederson-Helig cases. The Company has recorded an indemnity receivable of $118,500 and has accrued a liability of $118,500, included in prepaid expenses and other current assets and accrued expenses and other current liabilities, respectively, in the Consolidated Balance Sheet at December 31, 2011.
In connection with Fluor’s sale of the Prior Business to a group of purchasers (the “Rennert Entities”) in 1994, the Rennert Entities had agreed to indemnify Fluor and its affiliates for losses and liabilities arising from the Prior Business. In late 2010, the Rennert Entities settled with the plaintiffs in the Alexander-Pederson-Helig cases without indemnifying or obtaining a release for the benefit of Fluor and Alpha Appalachia’s subsidiaries.
In January 2012, the Rennert Entities filed suit against Fluor and two of Alpha Appalachia’s subsidiaries in the United States District Court for the Eastern District of Missouri seeking return of funds previously paid by the Rennert Entities to settle personal injury and property damage claims against Fluor and Alpha Appalachia’s subsidiaries allegedly arising out of the Prior Business and a declaration of non-liability for indemnification with respect to the Alexander-Pederson-Helig cases and any future claims or judgments against Fluor and Alpha Appalachia’s subsidiaries arising out of the Prior Business. Also in January 2012, Fluor filed suit against the Rennert Entities in Missouri state court alleging various breach of contract and tort claims and seeking a declaratory judgment regarding the Rennert Entities’ indemnification obligations to Fluor and Alpha Appalachia’s subsidiaries against claims arising out of the Prior Business. On February 21, 2012, Appalachia Holding and DRIH joined Fluor as plaintiffs in this suit. At the same time, Fluor, Appalachia Holding and DRIH moved to dismiss, or in the alternative, to stay the suit pending in federal court in Missouri in favor of the Missouri state court action.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Other Legal Proceedings
In addition to the matters disclosed above, the Company and its subsidiaries are involved in a number of legal proceedings incident to its normal business activities. While the Company cannot predict the outcome of these proceedings, the Company does not believe that any liability arising from these matters individually or in the aggregate should have a material impact upon its consolidated cash flows, results of operations or financial condition.
(21) Concentration of Credit Risk and Major Customers
The Company markets its coal principally to electric utilities in the United States and international and domestic steel producers. Credit is extended based on an evaluation of the customer’s financial condition and collateral is generally not required. Credit losses are provided for in the consolidated financial statements and historically have been minimal. The Company is committed under long-term contracts to supply coal that meets certain quality requirements at specified prices. The prices for some multi-year contracts are adjusted based on economic indices or the contract may include year-to-year specified price changes. Qualities and volume for coal are stipulated in coal supply agreements, and may vary from year to year within certain limits at the option of the customer. For the years ended December 31, 2011, 2010, and 2009, the Company’s ten largest customers accounted for approximately 41%, 42%, and 47% of total revenues, respectively. Sales to the Company’s largest customer accounted for approximately 9%, 9% and 12% of total revenues for the years ended December 31, 2011, 2010 and 2009, respectively. Steam coal accounted for approximately 82%, 86%, and 83% of the Company’s coal sales volume during 2011, 2010, and 2009, respectively. Metallurgical coal accounted for approximately 18%, 14%, and 17% of the Company’s coal sales volume during 2011, 2010, and 2009, respectively.
(22) Segment Information
The Company discloses information about operating segments using the management approach, where segments are determined and reported based on the way that management organizes the enterprise for making operating decisions and assessing performance. The Company periodically evaluates its application of accounting guidance for reporting its segments.
The Company extracts, processes and markets steam and metallurgical coal from surface and deep mines for sale to electric utilities, steel and coke producers, and industrial customers. The Company operates only in the United States with mines in Central Appalachia, Northern Appalachia, and the Powder River Basin. Based on a review of the required economic characteristics, the Company aggregates its operating segments into two reportable segments: Western Coal Operations, which consists of two Powder River Basin surface mines as of December 31, 2011 and Eastern Coal Operations, which consists of 99 underground mines and 46 surface mines in Central and Northern Appalachia as of December 31, 2011, as well as the Company’s road construction business which operates in Central Appalachia and its coal brokerage activities.
In addition to the two reportable segments, the All Other category includes an idled underground mine in Illinois; expenses associated with closed mines; Dry Systems Technologies; revenues and royalties from the sale of coalbed methane at the Company’s Coal Gas Recovery business and natural gas extraction; equipment sales and repair operations; terminal services; the leasing of mineral rights; general corporate overhead and corporate assets and liabilities. The Company evaluates the performance of its segments based on EBITDA from continuing operations, which the Company defines as income (loss) from continuing operations plus interest expense, income tax expense, amortization of acquired intangibles, net and depreciation, depletion and amortization, less interest income and income tax benefit.
Segment operating results and capital expenditures from continuing operations for the year ended December 31, 2011 were as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The following table presents a reconciliation of EBITDA from continuing operations to income from continuing operations for the year ended December 31, 2011:
Segment operating results and capital expenditures from continuing operations for the year ended December 31, 2010 were as follows:
The following table presents a reconciliation of EBITDA from continuing operations to income from continuing operations for the year ended December 31, 2010:
Segment operating results and capital expenditures from continuing operations for the year ended December 31, 2009 were as follows:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The following table presents a reconciliation of EBITDA from continuing operations to income from continuing operations for the year ended December 31, 2009:
The following table presents total assets and goodwill:
The Company sells produced, processed and purchased coal to customers in the United States and in international markets, primarily Brazil, Italy, India, Turkey, and Ukraine. Export coal revenues, which include freight and handling revenues, totaled $3,095,927 or approximately 44% of total revenues for the year ended December 31, 2011, $1,351,001 or approximately 34% of total revenues from continuing operations for the year ended December 31, 2010; and $767,793 or approximately 31% of total revenues from continuing operations for the year ended December 31, 2009.
(23) Supplemental Guarantor and Non-Guarantor Financial Information
On June 1, 2011, the Company issued the New Senior Notes and may issue new registered debt securities (the “New Notes”) in the future that are and will be, respectively, fully and unconditionally guaranteed, jointly and severally, on a senior or subordinated unsecured basis by certain of the Company’s subsidiaries (the “New Notes Guarantor Subsidiaries”).
Presented below are condensed consolidating financial statements as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010, and 2009, respectively, based on the guarantor structure that was put in place in connection with the issuance of the New Senior Notes, and would be put in place in the event the Company issues New Notes in the future. The tables below refer to the Company as issuer of the New Senior Notes and of any New Notes that may be issued in the future. “Non-Guarantor Subsidiaries” refers, for the tables below, to ANR Receivables Funding, LLC, Alpha Australia Pty. Limited, Alpha Coal India Private Limited, Coalsolv, LLC, Gray Hawk Insurance Company and Rockridge Coal Company, that were not guarantors of the New Senior Notes and would not be guarantors of the New Notes. Separate consolidated financial statements and other disclosures concerning the New Notes Guarantor Subsidiaries are not presented because management believes that such information would not be material to holders of any New Notes or related guarantees that may be issued by the Company.
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Alpha Natural Resources, Inc. and Subsidiaries
Supplemental Condensed Consolidating Balance Sheet
December 31, 2011
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Alpha Natural Resources, Inc. and Subsidiaries
Supplemental Condensed Consolidating Balance Sheet
December 31, 2010
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Alpha Natural Resources, Inc. and Subsidiaries
Supplemental Consolidating Statement of Operations
Year Ended December 31, 2011
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Alpha Natural Resources, Inc. and Subsidiaries
Supplemental Consolidating Statement of Operations
Year Ended December 31, 2010
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Alpha Natural Resources, Inc. and Subsidiaries
Supplemental Consolidating Statement of Operations
Year Ended December 31, 2009
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Alpha Natural Resources, Inc. and Subsidiaries
Supplemental Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2011
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Alpha Natural Resources, Inc. and Subsidiaries
Supplemental Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2010
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Alpha Natural Resources, Inc. and Subsidiaries
Supplemental Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2009
(24) Discontinued Operations
Kingwood Mining Company, LLC
On December 3, 2008, the Company announced the permanent closure of Kingwood. The decision was a result of adverse geologic conditions and regulatory requirements that rendered the coal seam unmineable at this location. The mine stopped producing coal in early January 2009 and Kingwood ceased equipment recovery operations at the end of April 2009. Beginning in the first quarter of 2009, the results of operations for the current and prior periods have been reported as discontinued operations.
The following table reflects the activities for Kingwood’s discontinued operations for the years ended December 31, 2010, and 2009:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(25) Quarterly Financial Information (Unaudited)
(1) Amounts have been adjusted from previously reported amounts to reflect the impact of retrospective adjustments made as a result of applying acquisition accounting for Massey.
The following table illustrates the effects of the adjustments:
ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES
NOTES to CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(26) Subsequent Events
On February 3, 2012 the Company announced that subsidiaries in its Eastern Coal Operations located 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 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 Company does not believe these actions will result in a material impact to the Company’s consolidated financial position or consolidated results of operations.
(27) Share Repurchase Program
On May 19, 2010, the Board of Directors authorized a share repurchase program, which permits the Company to repurchase up to $125,000 of its outstanding common stock, par value $0.01 per share (“Shares”). The program enables the Company to repurchase Shares from time to time, as market conditions warrant. The program was completed during 2011. On August 22, 2011, the Board of Directors authorized an additional share repurchase program, which permits the Company to repurchase up to $600,000 of Shares from time to time, as market conditions warrant. During 2011, the Company repurchased $200,000 of Shares under the programs.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Controls and Procedures
Evaluation of disclosure controls and procedures.
Our Disclosure Committee has responsibility for ensuring that there is an adequate and effective process for establishing, maintaining and evaluating disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in our SEC reports is timely recorded, processed, summarized and reported. In addition, we have established a Code of Business Ethics designed to provide a statement of the values and ethical standards to which we require our employees and directors to adhere. The Code of Business Ethics provides the framework for maintaining the highest possible standards of professional conduct. We also maintain an ethics hotline for employees. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.
Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we evaluated the effectiveness of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, as of the end of the period covered by this report, in ensuring that material information relating to Alpha Natural Resources, Inc., required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934, is recorded, processed, summarized and reported within the requisite time periods and is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure.
Changes in internal controls over financial reporting
There were no changes that occurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Our internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Management’s assessment of internal control over financial reporting as of December 31, 2011 excludes the internal control over financial reporting related to Massey (acquired on June 1, 2011), with the exception of those internal controls related to Massey’s sales revenue, income taxes, asset retirement obligations, derivative financial instruments, and long-term debt, which have already been integrated into the Company’s internal control over financial reporting. Massey’s total assets of $10.8 billion and total revenues of $1.9 billion are included in the Consolidated Financial Statement as of and for the year ended December 31, 2011. Based on management’s assessment and those criteria, management has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2011.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Alpha Natural Resources, Inc.:
We have audited Alpha Natural Resources, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
In conducting its assessment of the effectiveness of internal control over financial reporting, management of the Company excluded the internal control over financial reporting relating to Massey Energy Company (Massey) (with the exception of sales revenue, income taxes, asset retirement obligations, derivative financial instruments, and long-term debt, which have already been integrated into the Company’s internal control over financial reporting), which the Company acquired on June 1, 2011. Massey’s total assets of $10.8 billion and total revenues of $1.9 billion are included in the Company’s consolidated financial statements as of and for the year ended December 31, 2011. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Massey.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Alpha Natural Resources, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2011, and our report dated February 29, 2012 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Roanoke, Virginia
February 29, 2012
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
The sections of our Proxy Statement entitled “Proposal 1-Election of Directors-Nominees for Directors,” “Corporate Governance And Related Matters-The Board of Directors and its Committees,” “Corporate Governance And Related Matters-Audit Committee,” “Executive Officers,” “Section 16(a) Beneficial Ownership Reporting Compliance,” and “Corporate Governance And Related Matters-Code of Business Ethics” are incorporated herein by reference.
The Company has a written Code of Business Ethics that applies to the Company’s Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial and Accounting Officer) and others. The Code of Business Ethics is available on the Company’s website at www.alphanr.com. Any amendments to, or waivers from, a provision of our Code of Business Ethics that applies to our Principal Executive Officer, Principal Financial and Accounting Officer or persons performing similar functions and that relates to any element of the code of ethics enumerated in paragraph (b) of Item 406 of Regulation S-K shall be disclosed by posting such information on our website.
Item 11. Executive Compensation.
The sections of our Proxy Statement entitled “Corporate Governance and Related Matters-Director Compensation in 2011,” “Corporate Governance And Related Matters-Additional Information Regarding Our Director Compensation Table,” “Executive Compensation-Compensation Discussion and Analysis,” “Executive Compensation-Compensation Committee Report,” “Executive Compensation-Compensation and Risk,” “Executive Compensation-Summary Compensation Table,” “Executive Compensation-Grants of Plan-Based Awards in 2011,” “ Executive Compensation- Additional Information Regarding Our Summary Compensation Table and Grants of Plan-Based Awards Table,” “Executive Compensation-Outstanding Equity Awards at Fiscal Year-End 2011,” “Executive Compensation-Option Exercises and Stock Vested in 2011,” “Executive Compensation-Pension Benefits in 2011,” “Executive Compensation-Additional Information Regarding Our Pension Benefits Table,” “Executive Compensation-Nonqualified Deferred Compensation in 2011,” “Executive Compensation-Additional Information Regarding Our Nonqualified Deferred Compensation Plan Table,” “Executive Compensation -Potential Payments Upon Termination or Change in Control,” and “Executive Compensation-Additional Information Regarding the Tables Relating to Potential Payments Upon Employment Termination or Change in Control” are incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The sections of our Proxy Statement entitled “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information” are incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions and Director Independence
The sections of our Proxy Statement entitled “Corporate Governance and Related Matters-Director Independence” and “Policy With Respect To Related Person Transactions” are incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
The section of our Proxy Statement entitled “Independent Registered Public Accounting Firm-Fees of Independent Registered Public Accounting Firm” and “Independent Registered Public Accounting Firm-Policy for Approval of Audit and Permitted Non-audit Services” are incorporated herein by reference.
Additional Information
We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You may access and read our SEC filings through our website, at www.alphanr.com, or the SEC’s website, at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. You may also request copies of our filings, at no cost, by telephone at (276) 619-4410 or by mail at: Alpha Natural Resources, Inc., One Alpha Place, P.O. Box 16429, Bristol, Virginia 24209, attention: Investor Relations.
Our Audit Committee Charter, Compensation Committee Charter, Nominating and Corporate Governance Committee Charter, Corporate Governance Practices and Policies, and Code of Business Ethics are also available on our website and available in print to any stockholder who requests them.
PART IV
Item 15. Exhibits and Financial Statement Schedules
Pursuant to the rules and regulations of the Securities and Exchange Commission, the Company has filed certain agreements as exhibits to this Annual Report on Form 10-K. These agreements may contain representations and warranties by the parties. These warranties have been made solely for the benefit of the other party or parties to such agreements and (i) may been qualified by disclosure made to such other party or parties, (ii) were made only as of the date of such agreements or such other date(s) as may be specified in such agreements and are subject to more recent developments, which may not be fully reflected in such Company’s public disclosure, (iii) may reflect the allocation of risk among the parties to such agreements and (iv) may apply materiality standards different from what may be viewed as material to investors. Accordingly, these representations and warranties may not describe the Company’s actual state of affairs at the date hereof and should not be relied upon.
(a) Documents filed as part of this Annual Report on Form 10-K:
(1) The following financial statements are filed as part of this Annual Report on Form 10-K under Item 8 - Financial Statements and Supplementary Data:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets, December 31, 2011 and 2010
Consolidated Statements of Operations, Years ended December 31, 2011, 2010, and 2009
Consolidated Statements of Stockholders’ Equity and Comprehensive Income, Years ended December 31, 2011, 2010 and 2009
Consolidated Statements of Cash Flows, Years ended December 31, 2011, 2010 and 2009
Notes to Consolidated Financial Statements
(2) Financial Statement Schedules. All schedules are omitted because they are not required or because the information is immaterial or provided elsewhere in the Consolidated Financial Statements and Notes thereto.
(3) Listing of Exhibits. See Exhibit Index following the signature page of this Annual Report on Form 10-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ALPHA NATURAL RESOURCES, INC.
By:
/s/ Frank J. Wood
Name:
Frank J. Wood
Title:
Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
Date: February 29, 2012
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Frank J. Wood and Vaughn R. Groves, and each of them, his or her true and lawful attorneys-in-fact, each with full power of substitution, for him or her in any and all capacities, to sign any amendments to this Annual Report on Form 10-K and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorneys-in-fact or their substitute or substitutes may do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Date
Title
/s/ Kevin S. Crutchfield
February 29, 2012
Chief Executive Officer (Principal Executive Officer) and Director
Kevin S. Crutchfield
/s/ Frank J. Wood
February 29, 2012
Executive Vice President and Chief Financial Officer, (Principal Financial and Accounting Officer)
Frank J. Wood
/s/ Michael J. Quillen
February 29, 2012
Chairman of the Board of Directors
Michael J. Quillen
/s/ William J. Crowley, Jr.
February 29, 2012
Director
William J. Crowley, Jr.
/s/ E. Linn Draper, Jr.
February 29, 2012
Director
E. Linn Draper, Jr.
/s/ Glenn A. Eisenberg
February 29, 2012
Director
Glenn A. Eisenberg
/s/ Deborah M. Fretz
February 29, 2012
Director
Deborah M. Fretz
/s/ P. Michael Giftos
February 29, 2012
Director
P. Michael Giftos
/s/ Joel Richards, III
February 29, 2012
Director
Joel Richards, III
/s/ James F. Roberts
February 29, 2012
Director
James F. Roberts
/s/ Ted G. Wood
February 29, 2012
Director
Ted G. Wood
10-K EXHIBIT INDEX
Exhibit No.
Description of Exhibit
2.1
Agreement and Plan of Merger, dated as of January 28, 2011, among Mountain Merger Sub, Inc., Alpha Natural Resources, Inc. and Massey Energy Company (Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on January 31, 2011.)
2.2
Agreement and Plan of Merger, dated as of May 11, 2009, by and among Alpha Natural Resources, Inc. and Foundation Coal Holdings, Inc. (Incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K of Alpha Natural Resources Inc., (File No. 1-32331) filed on May 12, 2009.)
2.3
Acquisition Agreement dated as of September 23, 2005 among Alpha Natural Resources, LLC, Mate Creek Energy of W. Va., Inc., Virginia Energy Company, the unit holders of Powers Shop, LLC, and the shareholders of White Flame Energy, Inc., Twin Star Mining, Inc. and Nicewonder Contracting, Inc. (the “Acquisition Agreement”) (Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on September 26, 2005.)
2.4
Membership Unit Purchase Agreement dated as of September 23, 2005 among Premium Energy, LLC and the unit holders of Buchanan Energy Company, LLC (the “Membership Unit Purchase Agreement”) (Incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on September 26, 2005.)
2.5
Agreement and Plan of Merger dated as of September 23, 2005 among Alpha Natural Resources, Inc., Alpha Natural Resources, LLC, Premium Energy, LLC, Premium Energy, Inc. and the shareholders of Premium Energy, Inc. (the “Premium Energy Shareholders”) (the “Merger Agreement”) (Incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on September 26, 2005.)
2.6
Indemnification Agreement dated as of September 23, 2005 among Alpha Natural Resources, Inc., Alpha Natural Resources, LLC, Premium Energy, LLC, the other parties to the Acquisition Agreement, the Premium Energy Shareholders, and certain of the unit holders of Buchanan Energy Company, LLC (Incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on September 26, 2005.)
2.7
Letter Agreement dated of as September 23, 2005 among Alpha Natural Resources, Inc., Alpha Natural Resources, LLC, Premium Energy, LLC and the other parties to the Acquisition Agreement, the Membership Unit Purchase Agreement and the Merger Agreement (Incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on September 26, 2005.)
2.8
Letter Agreement dated October 26, 2005 (the “Letter Agreement”) among Alpha Natural Resources, Inc., Alpha Natural Resources, LLC, Premium Energy, LLC, Premium Energy, Inc. and the Sellers Representative named therein amending certain provisions of (i) the Acquisition Agreement dated September 23, 2005, among certain parties to the Letter Agreement and certain other parties named therein, (ii) the Agreement and Plan of Merger dated September 23, 2005, among the parties to the Letter Agreement and certain other parties named therein and (iii) the Indemnification Agreement dated September 23, 2005, among the parties to the Letter Agreement and certain other parties named therein. (Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. /Old (File No. 1-32423) filed on October 31, 2005.)
2.9
Assignment of Rights Under Certain Agreements executed as of October 26, 2005 among Alpha Natural Resources, LLC, Mate Creek Energy, LLC, Callaway Natural Resources, Inc., Premium Energy, LLC and Virginia Energy Company, LLC (Incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on October 31, 2005.)
3.1
Amended and Restated Certificate of Incorporation of Alpha Natural Resources, Inc. (Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on August 5, 2009.)
3.2
Certificate of Amendment of the Restated Certificate of Incorporation of Alpha Natural Resources, Inc. (Incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed June 1, 2011.)
3.3
Amended and Restated Bylaws of Alpha Natural Resources, Inc. (Incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on December 27, 2011.)
Exhibit No.
Description of Exhibit
4.1
Form of certificate of Alpha Natural Resources, Inc. common stock (Incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 of Alpha Natural Resources, Inc./Old (File No. 333-121002) filed on February 10, 2005.)
4.2
Indenture, dated as of April 7, 2008, between Alpha Natural Resources, Inc. (File No. 1-32423) and Union Bank of California, N.A., as Trustee (Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on April 9, 2008.)
4.3
Supplemental Indenture No. 1 dated as of April 7, 2008, between Alpha Natural Resources, Inc. (File No. 1-32423) and Union Bank of California, N.A., as Trustee (Incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. /Old (File No. 1-32423) filed on April 9, 2008.)
4.4
Form of 2.375% Convertible Senior Note due 2015 (Incorporated by reference to Exhibit 4.4 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old/ (File No. 1-32423) filed on April 9, 2008.)
4.5
Supplemental Indenture No. 2 dated as of July 31, 2009, between Alpha Natural Resources, Inc. and Union Bank of California, N.A., as Trustee (Incorporated by reference to Exhibit 4.4 of the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on August 5, 2009.)
4.6
Subordinated Indenture dated as of April 7, 2008, between Alpha Natural Resources, Inc. and Union Bank of California, N.A. as Trustee (Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on April 9, 2008.)
4.7
Supplemental Indenture No. 1 dated as of July 31, 2009, between Alpha Natural Resources, Inc. and Union Bank, N.A., as Trustee (Incorporated by reference to Exhibit 4.6 the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on August 7, 2009.)
4.8
Indenture, dated as of June 1, 2011, among Alpha Natural Resources, Inc., the Guarantors named therein and Union Bank, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.9
First Supplemental Indenture, dated as of June 1, 2011, among Alpha Natural Resources, Inc., the Guarantors named therein and Union Bank, N.A., as trustee (Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.10
Form of 2019 Note (included in Exhibit 4.15) (Incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.11
Form of 2021 Note (included in Exhibit 4.15) (Incorporated by reference to Exhibit 4.4 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.12
Second Supplemental Indenture, dated as of June 1, 2011, among Alpha Natural Resources, Inc., the Guarantors named therein and Union Bank, N.A., as trustee (Incorporated by reference to Exhibit 4.5 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.13
Senior Indenture, dated as of August 12, 2008, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.6 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.14
First Supplemental Indenture, dated as of August 12, 2008, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.7 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.15
Second Supplemental Indenture, dated as of July 20, 2009, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.8 to the
Exhibit No.
Description of Exhibit
Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.16
Third Supplemental Indenture, dated as of August 28, 2009, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.9 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.17
Fourth Supplemental Indenture, dated as of April 30, 2010, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.10 to the Current Report on Form 8-Kof Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.18
Fifth Supplemental Indenture, dated as of June 29, 2010, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.11 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
4.19
Sixth Supplemental Indenture dated as of June 1, 2011, among Alpha Natural Resources, Inc., Massey Energy Company, the Guarantors named therein and Wilmington Trust Company, as Trustee (Incorporated by reference to Exhibit 4.12 to the Amendment No. 1 to Current Report to Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 3, 2011.)
4.20
Third Amended and Restated Credit Agreement, dated as of May 19, 2011, by and among Alpha, the lenders party thereto, the issuing banks party thereto, Citicorp North America, Inc. as administrative and collateral agent and Citigroup Global Markets Inc. and Morgan Stanley Senior Funding, Inc. as joint lead arrangers and joint book managers (Incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on May 20, 2011.)
10.1
Non-Prosecution Agreement, dated as of December 6, 2011, between Alpha and Alpha Appalachia Holdings, Inc. (fka Massey Energy Company) and the United States Attorney’s Office for the Southern District of West Virginia and the United States Department of Justice, and settlement with MSHA (Incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on December 6, 2011.)
10.2
Second Amended and Restated Receivables Purchase Agreement, dated as of October 19, 2011, by and among ANR Receivables Funding, LLC, Alpha Natural Resources, LLC, the various financial institutions party thereto and PNC Bank, National Association (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on October 21, 2011.)
10.3*
First Amendment, dated as of December 21, 2011, to the Second Amended and Restated Receivables Purchase Agreement, by and among ANR Receivables Funding, LLC, Alpha Natural Resources, LLC, the various financial institutions party thereto and PNC Bank, National Association
10.4
Amended and Restated Guarantee and Collateral Agreement, dated as of June 1, 2011, made by each of the Guarantors as defined therein, in favor of Citicorp North America, Inc., as administrative agent and as collateral agent for the banks and other financial institutions or entities from time to time parties to the New Credit Agreement (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on June 1, 2011.)
Exhibit No.
Description of Exhibit
10.5
Distribution Agreement between Fluor Corporation and Massey Energy Company dated as of November 30, 2000 (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Massey Energy Company (File No. 1-7775) filed on December 15, 2000.)
10.6
Tax Sharing Agreement between Fluor Corporation, Massey Energy Company and A.T. Massey Coal Company, Inc. dated as of November 30, 2000 (Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Massey Energy Company (File No. 1-7775) filed on December 15, 2000.)
10.7
Alpha Operating Companies Rabbi Trust Agreement, As Amended and Restated Effective January 1, 2011 (Incorporated by reference to Exhibit 10.24 of the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on February 25, 2011.)
10.8
Alpha Natural Resources, Inc. 2008 Annual Incentive Bonus Plan (effective May 14, 2008, and last amended on November 16, 2010) (Incorporated by reference to Exhibit 10.25 of the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on February 25, 2011.)
10.9
Non-Employee Director Compensatory Arrangements (Incorporated by reference to Exhibit 10.27 of the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on February 25, 2011.)
10.10
Alpha Natural Resources, Inc. Key Employee Separation Plan (as Amended and Restated effective July 31, 2009) (Incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
Exhibit No.
Description of Exhibit
10.11
Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan, As Amended and Restated Effective January 1, 2011 (amended as of May 1, 2011) (Incorporated by reference to Exhibit 10.12 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (Filed No. 1-32331) filed on August 9, 2011.)
10.12
Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan - Distribution Election Form, Retirement and SRP Account Balances (Incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q filed by Alpha Natural Resources, Inc. on November 5, 2010.)
10.13
Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan - Distribution Election Form, In-Service Account Balances (Incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc.(File No. 1-32331) filed on November 5, 2010.)
10.14
Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan - Other Compensation Deferral Agreement Form (Incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 5, 2010.)
10.15
Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan - Annual Bonus Deferral Agreement Form (Incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 5, 2010.)
10.16
Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan - Base Salary Deferral Agreement Form (Incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 5, 2010.)
10.17
Amended and Restated Legacy Foundation Rabbi Trust Agreement (Incorporated by reference to Exhibit 10.35 of the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on February 25, 2011.)
10.18
Alpha Natural Resources, Inc. Non-Employee Directors Deferred Compensation Plan (effective January 1, 2010.) (Incorporated by reference to Exhibit 10.33 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010.)
10.19
Alpha Natural Resources, Inc. Non-Employee Directors Deferred Compensation Plan Deferral Commitment and Beneficiary Designation Form (effective January 1, 2010.) (Incorporated by reference to Exhibit 10.34 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (Filed No. 1-32331) filed on March 1, 2010.)
10.20
Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.1 to Registration Statement on Form S-8 (File No. 333-166959) filed on May 19, 2010.)
10.21*
Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan Restricted Stock Unit Award Agreement for Employees (Grades 22-30).
10.22*
Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan Performance Share Unit Award Agreement for Employees (Grades 22-30).
10.23*
Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan Restricted Stock Unit Award Agreement for Non-Employee Directors.
10.24
Alpha Natural Resources, Inc. Amended and Restated 2004 Long-Term Incentive Plan (Restated as of November 8, 2007) (Incorporated by reference to Exhibit 10.17 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 29, 2008.)
10.25
Form of Grantee Stock Option Agreement under the Alpha Natural Resources, Inc. Amended and Restated 2004 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q of Alpha Natural Resources,
Exhibit No.
Description of Exhibit
Inc./Old (File No. 1-32423) filed on August 9, 2007.)
10.26
Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Restated as of May 14, 2008 and as further amended on November 18, 2009.) (Incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010.)
10.27
Form of Grantee Stock Option Agreement under the 2005 Long-Term Incentive Plan (Amended and Restated as of November 8, 2007) (Incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 29, 2008.)
10.28
Form of Restricted Stock Agreement for Non-Employee Directors under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Restated as of November 8, 2007) (Incorporated by reference to Exhibit 10.24 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 29, 2008.)
10.29
Form of Restricted Stock Unit Award Agreement for Non-Employee Directors under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.11 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.30
Form of Director Deferred Compensation Agreement under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Amended and Restated on December 12, 2008) (Incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 27, 2009.)
10.31
Form of Amendment to Director Deferred Compensation Agreement (Incorporated by reference to Exhibit 10.38 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 27, 2009.)
10.32
Form of Performance Share Award Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (For Employees) (Restated as of December 12, 2008) (Incorporated by reference to Exhibit 10.26 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 27, 2009.)
10.33
Form of Performance Share Unit Award Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (for awards effective after January 1, 2010.) (Incorporated by reference to Exhibit 10.44 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010.)
10.34
Form of Restricted Stock Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Restated as of February 10, 2009) (Incorporated by reference to Exhibit 10.24 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 27, 2009.)
10.35
Form of Retention Plan Restricted Stock Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.41 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 27, 2009.)
10.36
Form of Retention Plan Restricted Stock Unit Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.17 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.37
Form of Restricted Stock Unit Award Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.18 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.38
Form of Restricted Stock Unit Award Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (for awards effective after January 1, 2010.) (Incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010.)
10.39
Alpha Natural Resources, Inc. Amended and Restated 2004 Stock Incentive Plan (as amended and restated July 31, 2009 and further amended on November 18, 2009) (Incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K filed
Exhibit No.
Description of Exhibit
by Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010.)
10.40
Award Agreement by and among Foundation Coal Holdings, Inc. and James F. Roberts (effective January 12, 2009) (Incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on January 14, 2009.)
10.41
Award Agreement by and among Foundation Coal Holdings, Inc. and Kurt D. Kost (effective January 12, 2009) (Incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on January 14, 2009.)
10.42
Award Agreement by and among Foundation Coal Holdings, Inc. and Frank J. Wood (effective January 12, 2009) (Incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on January 14, 2009.)
10.43
Award Agreement by and among Foundation Coal Holdings, Inc. and Michael R. Peelish (effective January 12, 2009) (Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on May 7, 2009.)
10.44
Form of Executive Officer Non-Qualified Stock Option Agreement (Incorporated by reference to Exhibit 10.9 of the Form 10-Q of Foundation Coal Holdings, Inc. (File No. 001-32331) filed on November 14, 2005.)
10.45
Form of Amendment Number 1 to Executive Officer Non-Qualified Stock Option Agreement (Incorporated by reference to Exhibit 10.10 of the Form 10-Q of Foundation Coal Holdings, Inc. (File No. 001-32331) filed on November 14, 2005.)
10.46
Form of Rollover Nonqualified Stock Option Agreement under the Alpha Natural Resources, Inc. Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 99.4 to the Registration Statement on Form S-8 (File No. 333-160937) of Alpha Natural Resources, Inc. filed on July 31, 2009.)
10.47
Form of Rollover Restricted Stock Unit Agreement under the Alpha Natural Resources, Inc. Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 99.5 to the Registration Statements on Form S-8 (File No. 333-160937) of Alpha Natural Resources, Inc. filed on July 31, 2009.)
10.48
Form of Rollover Restricted Stock Unit Agreement under the Alpha Natural Resources, Inc. Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 99.6 to the Registration Statements on Form S-8 (File No. 333-160937) of Alpha Natural Resources, Inc. filed on July 31, 2009.)
10.49
Form of Retention Plan Restricted Stock Unit Agreement for Employees under the Alpha Natural Resources, Inc. Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 10.23 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.50
Form of Restricted Stock Unit Award Agreement for Employees under the Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 10.24 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.51
Form of Restricted Stock Unit Award Agreement for Employees under the Amended and Restated 2004 Stock Incentive Plan (for awards effective after January 1, 2010.) (Incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010.)
10.52
Form of Restricted Stock Unit Award Agreement for Non-Employee Directors under the Amended and Restated 2004 Stock Incentive Plan (for awards effective after July 31, 2009) (Incorporated by reference to Exhibit 10.25 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.53
Form of Performance Share Unit Award Agreement for Employees under the Amended and Restated 2004 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.67 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010.)
Exhibit No.
Description of Exhibit
10.54
Agreement by and between Alpha Natural Resources Services, LLC and Michael J. Quillen, dated as of July 31, 2009 (Incorporated by reference to Exhibit 10.27 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.55
Agreement by and between Foundation Coal Corporation and James F. Roberts, dated July 31, 2009 (Incorporated by reference to Exhibit 10.28 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.56
Third Amended and Restated Employment Agreement by and between Alpha Natural Resources Services, LLC and Kevin S. Crutchfield, dated as of July 31, 2009 (Incorporated by reference to Exhibit 10.29 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.57
First Amended and Restated Employment Agreement by and between Alpha Natural Resources, Inc. and Kurt D. Kost, dated as of August 1, 2009 (Incorporated by reference to Exhibit 10.30 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.58
Consent Agreement by and between Foundation Coal Corporation, Alpha Natural Resources, Inc. and Frank J. Wood (Incorporated by reference to Exhibit 10.31 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.59
Form of Indemnification Agreement by and between Alpha Natural Resources, Inc. and each of its current and future directors and officers (Incorporated by reference to Exhibit 10.37 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.60
Alpha Service Companies Rabbi Trust Agreement (amended as of May 1, 2011) (Incorporated by reference to Exhibit 10.13 of the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on August 9, 2011.)
10.61
Alpha Natural Resources, Inc. 2006 Stock and Incentive Compensation Plan (Incorporated by reference to Exhibit 99.1 of the Post-Effective Amendment No. 1 on Form S-8 of Alpha Natural Resources, Inc. (File No. 333-172888) filed on June 1, 2011.)
12.1*
Computation of Ratio of Earnings to Fixed Charges
12.2*
Computation of Other Ratios
21.1*
List of Subsidiaries
23*
Consent of KPMG LLP
31(a)*
Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to §302 of the Sarbanes-Oxley Act of 2002
31(b)*
Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to §302 of the Sarbanes-Oxley Act of 2002
32(a)*
Certification Pursuant to 18 U.S.C. §1350, As Adopted Pursuant to §906 of the Sarbanes-Oxley Act of 2002
32(b)*
Certification Pursuant to 18 U.S.C. §1350, As Adopted Pursuant to §906 of the Sarbanes-Oxley Act of 2002
95*
Mine Safety Disclosure Exhibit
101.INS*
XBRL instance document
101.SCH*
XBRL taxonomy extension schema
Exhibit No.
Description of Exhibit
101.CAL*
XBRL taxonomy extension calculation linkbase
101.LAB*
XBRL taxonomy extension label linkbase
101.PRE*
XBRL taxonomy extension presentation linkbase
* Filed herewith.
 Confidential treatment has been granted with respect to portions of the exhibit. Confidential portions have been omitted from this public filing and have been filed separately with the Securities and Exchange Commission.
 Management contract of compensatory plan or arrangement