Filed with the SEC from May 26 to June 01:
International Coal Group (ICO)
Gamco Investors (ticker: GBL) disclosed that it now owns 10,349,652 shares (5.07%). The firm invested a little under $150 million, paying an average of $14.49 per share, to acquire the holding.
We are a leading producer of coal in Northern and Central Appalachia with a broad range of mid- to high-Btu, low- to medium-sulfur steam and metallurgical coal. Our 12 Appalachian mining complexes are located in West Virginia, Kentucky, Virginia and Maryland. We also have a complementary mining complex of mid- to high-sulfur steam coal strategically located in the Illinois Basin. We market our coal to a diverse customer base of largely investment grade electric utilities, as well as domestic and international industrial customers. The high quality of our coal and the availability of multiple transportation options, including rail, truck and barge, throughout the Appalachian region enable us to participate in both the domestic and international coal markets. Coal markets, particularly Appalachian coal markets, have exhibited significant price volatility in recent years and may continue to do so due to a number of factors, including regulatory and other actions delaying the issuance of necessary permits, general economic conditions and customer usage of coal.
As of December 31, 2010, management estimates that we owned or controlled approximately 318 million tons of metallurgical quality coal reserves and approximately 770 million tons of steam coal reserves. Managementâ€™s estimates were developed considering an initial evaluation, as well as subsequent acquisitions, dispositions, depleted reserves, changes in available geological or mining data and other factors. Further, we own or control approximately 434 million tons of non-reserve coal deposits. Our assets are high-quality reserves strategically located in Appalachia and the Illinois Basin.
For the year ended December 31, 2010, we sold 16.3 million tons of coal, of which approximately 15.8 million tons were produced from our mining activities and approximately 0.5 million tons were purchased through brokered coal contracts (coal purchased from third parties for resale), at an average sale price of $66.38 and $53.85, respectively. Of the tons sold, 14.0 million tons were steam coal and 2.3 million tons were metallurgical coal. Our steam coal sales volume in 2010 consisted of mid- to high-quality, high-Btu (greater than 12,000 Btu/lb.), low- to medium-sulfur (1.5% or less) coal, which typically sells at a premium to lower quality, lower Btu, higher sulfur steam coal. Our three largest customers for the year ended December 31, 2010 were Progress Energy, Dominion Energy and Santee Cooper, and we derived approximately 34% of our revenues from sales to our five largest customers. We did not derive more than 10% of our revenues from any single customer in 2010.
International Coal Group, Inc. was incorporated in Delaware in 2005. We have three reportable business segments, which are based on the coal regions in which we operate: (i) Central Appalachian, comprised of both surface and underground mines, (ii) Northern Appalachian, comprised of both surface and underground mines and (iii) Illinois Basin, representing one underground mine. Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States of America, as of and for the years ended December 31, 2010, 2009 and 2008 is included in Note 20 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
The Coal Industry
A major contributor to the world energy supply, coal represents over 27% of the worldâ€™s primary energy consumption according to the World Coal Institute. The primary use for coal is to fuel electric power generation. In 2009, coal-fired plants generated approximately 45% of the electricity produced in the United States, according to the Energy Information Administration (â€śEIAâ€ť), a statistical agency of the U.S. Department of Energy.
Coal produced in the United States is used primarily by utilities to generate electricity, by the steel industry to produce coke for use in blast furnaces and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. Significant quantities of coal are also exported from both East and West Coast terminals. Coal used as fuel to generate electricity is commonly referred to as â€śsteam coalâ€ť or â€śthermal coal.â€ť
Coal has long been favored as an electricity generating fuel by regulated utilities because of its basic economic advantage. The largest cost component in electricity generation is fuel. According to the National Mining Association, coal is the most affordable source of power fuel per million Btu, historically averaging less than one-quarter the price of both petroleum and natural gas.
The other major market for coal is the steel industry. The type of coal used in steel making is referred to as â€śmetallurgical coalâ€ť and is distinguished by special quality characteristics that include high carbon content, favorable coking characteristics and various other chemical attributes. Metallurgical coal is also generally higher in heat content (as measured in Btus), and therefore is also desirable to utilities as fuel for electricity generation. Consequently, metallurgical coal producers have the ongoing opportunity to select the market that provides maximum revenue and margins. The premium price offered by steel makers for the metallurgical quality attributes is typically higher than the price offered by utility coal buyers that value only the heat content.
Coal Mining Methods
We produce coal using two mining methods: underground room-and-pillar mining using continuous mining equipment and surface mining, which are explained as follows:
Underground mines in the United States are typically operated using one of two different mining methods: room-and-pillar or longwall. In 2010, approximately 52% of our produced and processed coal volume came from underground mining operations using the room-and-pillar method with continuous mining equipment.
Room-and-pillar mining. In room-and-pillar mining, rooms are cut into the coal seam leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of air. Continuous mining equipment is used to cut the coal from the mining face. Generally, openings are driven 20 feet wide and the pillars are rectangular in shape measuring 35-50 feet wide by 35-80 feet long. As mining advances, a grid-like pattern of entries and pillars is formed. Shuttle cars are used to transport coal from the continuous mining machine to the conveyor belt for transport to the surface. When mining advances to the end of a panel, retreat mining may begin. In retreat mining, as much coal as is feasible is mined from the pillars that were created in advancing the panel, allowing the roof to cave. When retreat mining is completed to the mouth of the panel, the mined panel is abandoned. The room-and-pillar method is often used to mine smaller coal blocks or thinner seams. It is also employed whenever subsidence is prohibited. Seam recovery ranges from 35% to 70%, with higher seam recovery rates applicable where retreat mining is combined with room-and-pillar mining.
Longwall mining. The other underground mining method commonly used in the United States is longwall mining. We do not currently have any longwall mining operations, but we expect to use this mining method in the development of our Tygart Valley property in Taylor County, West Virginia. In longwall mining, a rotating drum is trammed mechanically across the face of coal and a hydraulic system supports the roof of the mine while it advances through the coal. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface.
Surface mining is used when coal is found close to the surface. In 2010, approximately 48% of our produced and processed coal volume came from surface mines. This method involves the removal of overburden (earth and rock covering the coal) with heavy earth moving equipment and explosives, extraction of the coal, replacing the overburden and topsoil to restore the land after the coal has been removed, reestablishing vegetation and frequently making other improvements that have local community and environmental benefit.
Overburden is typically removed at our mines using large, rubber-tired diesel loaders or hydraulic shovels. Coal is loaded into haul trucks for transportation to a preparation plant or unit train loadout facility. Seam recovery for surface mining is typically between 80% and 90%. Productivity depends on equipment, geological composition and mining ratios.
Area mining. Area mining is a surface mining method that removes all or part of the coal seam(s) in the upper fraction of a mountain, ridge or hill and the disturbed areas are subsequently restored to approximate original contour, or an approved alternate configuration.
Cross-ridge mining. Cross-ridge mining is a form of area mining that is employed where the terrain is dominated by long narrow ridges.
Contour mining . Contour mining is a surface mining method used in mountainous terrain that recovers coal along the outcrop of the coal seam by progressively excavating the overburden from above the coal seam to create a narrow bench, removing the coal and then replacing the overburden to restore the approximate original contour of the mined area.
Mountaintop removal mining . Mountaintop removal mining is a surface mining method that removes the entire coal seam(s) in an upper fraction of a mountain, ridge or hill and creates a level plateau or a gently rolling contour with no highwalls. This mining method is limited in application to sites where the approved post-mining land use requires relatively flat terrain. We do not currently have any mountaintop removal operations.
Highwall mining. Highwall mining is a surface mining method generally utilized in conjunction with contour surface mining. We do not currently have any highwall mining operations. At a highwall contour mining operation, a modified continuous miner with an attached beltline system cuts horizontal passages from the highwall into a seam. These passages can penetrate to a depth of up to 1,600 feet. This method typically can recover up to 65% of the reserve block penetrated.
Coal Preparation and Blending
Depending on coal quality and customer requirements, raw coal may in some cases be shipped directly from the mine to the customer. Generally, raw coal from surface mines can be shipped in this manner. However, the quality of most underground raw coal does not allow it to be shipped directly to the customer without processing in a preparation plant. Preparation plants physically separate impurities from coal. This processing upgrades the quality and heating value of the coal by removing or reducing sulfur and ash-producing materials, but entails additional expense and results in some loss of coal. Coals of various sulfur and ash contents can be mixed, or â€śblended,â€ť at a preparation plant or loading facility to meet the specific combustion and environmental needs of customers. Coal blending helps increase profitability by meeting the quality requirements of specific customer contracts, while maximizing revenue through optimal use of coal inventories.
In general, coal of all geological composition is characterized by end use as either steam coal or metallurgical coal. Heat value and sulfur content are the most important variables in the profitable marketing and transportation of steam coal, while ash, sulfur and various coking characteristics are important variables in the profitable marketing and transportation of metallurgical coal. We mine, process, market and transport bituminous steam and metallurgical coal, characteristics of which are described below.
The heat value of coal is commonly measured in Btus per pound of coal. A Btu is the amount of heat needed to raise one pound of water one degree Fahrenheit. Coal found in the eastern and Midwestern regions of the United States tends to have a heat content ranging from 10,000 to 14,000 Btus per pound, as received. As received Btus per pound includes the weight of moisture in the coal on an as sold basis. Most coal found in the western United States ranges from 8,000 to 10,000 Btus per pound, as received.
Bituminous coal is a relatively soft black coal with a heat content that ranges from 10,000 to 14,000 Btus per pound. This coal is located primarily in Appalachia, Arizona, Colorado, the Midwest and Utah, and is the type most commonly used for electricity generation in the United States. Bituminous coal is also used for industrial steam purposes by utility and industrial customers, and as metallurgical coal in steel production.
Sulfur content can vary from coal seam to coal 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. Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus and complies with the requirements of the Clean Air Act Acid Rain Program. Low-sulfur coal is coal which, when burned, emits approximately 1.6 pounds or less of sulfur dioxide per million Btus. Mid-sulfur coal is characterized as coal which, when burned, emits greater than 1.6 pounds of sulfur dioxide per million Btus, but less than 2.5 pounds of sulfur dioxide per million Btus. High-sulfur coal is generally characterized as coal which, when burned, emits greater than 2.5 pounds per million Btus.
High-sulfur coal can be burned in electric utility plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by up to 99%. Plants without scrubbers can burn high-sulfur coal by blending it with lower sulfur coal or by purchasing emission allowances on the open market. Each emission allowance permits the user to emit a ton of sulfur dioxide. Additional scrubbing will provide new market opportunities for our medium- to high- sulfur coal. All new coal-fired electric utility generation plants built in the United States will use clean coal-burning technology.
Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from coal seam to coal seam. Ash content is an important characteristic of coal because it increases transportation costs and electric generating plants must handle and dispose of ash following combustion.
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 per pound of coal, thereby increasing the delivered cost per Btu. Moisture content in coal, as sold, can range from approximately 5% to 30% of the coalâ€™s weight.
As of December 31, 2010, we operated a total of 13 underground and 10 surface coal mines located in West Virginia, Kentucky, Maryland, Virginia and Illinois. Approximately 52% of our 2010 production came from underground mines, and the remaining 48% of our production came from our surface mines. These mining facilities include 11 preparation plants, each of which receive, blend, process and ship coal that is produced from one or more of our 23 active mines. 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, roof bolters and various ancillary equipment. Our surface mines are a combination of area, contour and cross-ridge operations using truck/loader equipment fleets along with large production tractors. Most of our preparation plants are modern heavy media plants that generally have both coarse and fine coal cleaning circuits. We currently own most of the equipment utilized in our mining operations. We employ preventive maintenance and rebuild programs to ensure that our equipment is modern and well maintained. The mobile equipment utilized at our mining operations is replaced on an on-going basis with new, more efficient units based on equipment age and mechanical condition. Each year we endeavor to replace the oldest units, thereby maintaining productivity while minimizing capital expenditures.
Our Northern and Central Appalachian mining facilities and reserves are strategically located across West Virginia, Kentucky, Maryland, Virginia and Ohio and are used to produce and ship coal to our customers located primarily in the eastern half of the United States.
Our mines in Central Appalachia produced 9.0 million tons of coal in 2010 and our mines in Northern Appalachia produced 4.0 million tons of coal in 2010. The quality of the produced coal was, on average, 12,316 Btu/lb., 1.35% sulfur and 12.19% ash by content. Shipments bound for electric utilities accounted for approximately 99% of the thermal coal shipped by these mines in 2010 compared to 92% of shipments in 2009. Within each mining complex, mines have been developed at strategic locations in proximity to our preparation plants and rail shipping facilities. The mines located in Central Appalachia ship the majority of their coal via the CSX railroad and, to a lesser extent, via the Norfolk Southern rail system. Some shipments may also be delivered by truck or barge, depending on the customer. Northern Appalachia shipments are primarily via CSX rail with some barge and truck to customer shipments.
Eastern operates the Birch River surface mine, located 60 miles east of Charleston, near Cowen in Webster County, West Virginia. Birch River is extracting coal from the Freeport, Upper Kittanning, Middle Kittanning, Upper Clarion and Lower Clarion coal seams. Birch River controls an estimated 7.7 million tons of coal reserves, of which approximately 2.0 million tons are deep minable. Easternâ€™s first underground mine will be developed in 2011. Additional potential reserves, mineable by both surface and deep mining methods, have been identified in the immediate vicinity of the Birch River mine and exploration activities are currently being conducted in order to add those potential reserves to the reserve base.
The coal reserves are predominantly leased. The leases are retained by annual minimum payments and by tonnage-based royalty payments. Most of the leased reserves are held by five lessors. Most of the leases can be renewed until all mineable and merchantable coal has been exhausted. Overburden is removed by an excavator, front-end loaders, end dumps and bulldozers. Approximately one-third of the total coal sales are run-of-mine, while the other two-thirds are washed at Birch Riverâ€™s preparation plant. Coal is transported by conveyor belt from the preparation plant to Birch Riverâ€™s rail loadout, which is served by CSX via the A&O Railroad, a short-line carrier that is partially owned by CSX.
Hazard currently operates four surface mines, a unit train loadout (Kentucky River Loading) and other support facilities in eastern Kentucky, near Hazard. Hazardâ€™s four surface mines include East Mac & Nellie, Rowdy Gap, Bearville and Thunder Ridge. The coal from these mines is being extracted from the Hazard 10, Hazard 9, Hazard 8, Hazard 7 and Hazard 5A seams. Nearly all of the coal is marketed as a blend of run-of-mine product with the remainder being washed. Overburden is removed by front-end loaders, end dumps, bulldozers and cast blasting. East Mac & Nellie also utilizes a large capacity hydraulic shovel. Coal is transported by on-highway trucks from the mines to the Kentucky River Loading rail loadout, which is served by CSX. Some coal is direct shipped to the customer by truck from the mine pits.
We estimate that Hazard controls 75.5 million tons of coal reserves, including approximately 10.4 million tons of deep mineable reserves. Hazard also controls 10.3 million tons of coal that is classified as non-reserve coal deposits. Most of the property has been adequately explored, but additional core drilling will be conducted within specified locations to better define the reserves.
Approximately 63% of Hazardâ€™s reserves are leased. Most of the leased reserves are held by seven lessors. In several cases, Hazard has multiple leases with each lessor. The leases are retained by annual minimum payments and by tonnage-based royalty payments. Most of the leases can be renewed until all mineable and merchantable coal has been exhausted.
Flint Ridge, located near Breathitt County, Kentucky, operates one underground mine and one preparation plant. The mine operates in the Hazard 8 seam.
Flint Ridgeâ€™s underground mine is a room-and-pillar operation, utilizing continuous miners and shuttle cars. All of the run-of-mine coal is processed at the Flint Ridge preparation plant. Since July 2005, it has been processing coal from the Hazard and Flint Ridge mining complexes.
The majority of the processed coal is trucked to the Kentucky River Loading rail loadout. Some processed coal is trucked directly to the customer from the preparation facility.
We estimate that Flint Ridge controls 20.3 million tons of coal reserves, plus 0.1 million tons of non-reserve coal deposits. Approximately 97% of Flint Ridgeâ€™s reserves are leased, while 3% are owned in fee. The leases are retained by annual minimum payments and by tonnage-based royalty payments. Most of the leases can be renewed until all mineable and merchantable coal has been exhausted.
Knott County operates two underground mines, the Supreme Energy preparation plant and rail loadout and other facilities necessary to support the mining operations near Kite, Kentucky. Knott County is producing coal from the Elkhorn 3 coal seam in the Classic and Kathleen mines. Mining of the Calvary mine was completed in 2010. Two additional properties are in the process of being permitted for underground mine development. We estimate Knott County controls 18.1 million tons of coal reserves. A significant portion of the property has been explored, but additional core drilling will be conducted within specified locations to better define the reserves.
Approximately 13% of Knott Countyâ€™s reserves are owned in fee, while approximately 87% are leased. The leases are retained by annual minimum payments and by tonnage-based royalty payments. The leases typically can be renewed until all mineable and merchantable coal has been exhausted.
Knott Countyâ€™s two underground mines are room-and-pillar operations, utilizing continuous miners and shuttle cars. The coal is processed at the Supreme Energy preparation plant. All of Knott Countyâ€™s coal is transported by rail from loadouts served by CSX.
Raven, located in Knott County, Kentucky, operates three underground mines (Raven #1, Slones Branch and Lige Hollow) and the Raven preparation plant. Raven #1 and Slones Branch are producing coal from the Elkhorn 2 coal seam and Lige Hollow is producing coal from the Amburgy seam. Two additional properties are in the process of being permitted for underground mine development. We estimate Raven controls 19.5 million tons of coal reserves. Most of the property has been extensively explored, but additional core drilling will be conducted within specified locations to better define the reserves.
The Raven #1 and Slones Branch reserves are all leased from one lessor, Penn Virginia Resource Partners, L.P. Lige Hollowâ€™s leased reserves are held by multiple lessors. The leases are retained by annual minimum payments and by tonnage-based royalty payments.
Ravenâ€™s three underground mines are room-and-pillar operations, utilizing continuous miners and shuttle cars. The coal is processed at the Raven preparation plant. Nearly all of Ravenâ€™s coal is transported by rail via CSX.
East Kentucky is a surface mining operation located in Martin and Pike Counties, Kentucky, near the Tug Fork River. East Kentucky currently operates the Mt. Sterling surface mine and the Sandlick loadout. The loadout is serviced by Norfolk Southern railroad. Mining of the Peelpoplar surface mine was completed in 2010.
Mt. Sterling is a surface mine that produces coal from the Taylor, Coalburg, Winifrede, Buffalo and Stockton coal seams. All of the coal is sold run-of-mine. We estimate that the Mt. Sterling mine controls 0.9 million tons of coal reserves, of which 84% are owned. No additional exploration is required. Overburden at the Mt. Sterling mine is removed by front-end loaders, end dumps, bulldozers and cast blasting. Coal from the pits is transported by truck to the Sandlick loadout. Leased reserves are retained by annual minimum payments and by tonnage-based royalty payments. Most of the leases can be renewed until all mineable and merchantable coal has been exhausted.
The Beckley Pocahontas Mine, located near Beckley in Raleigh County, West Virginia, was placed into production in the fall of 2008 and accesses a 30.2 million-ton deep reserve of high quality low-volatile metallurgical coal in the Pocahontas No. 3 seam. Most of the 16,800 acre Beckley reserve is leased from three land companies: Western Pocahontas Properties, Crab Orchard Coal and Land Company and Beaver Coal Company.
Underground production is by means of the room-and-pillar method with continuous miners and shuttle cars. Coal produced from the Beckley operation is marketed to domestic steel producers and for export. Additionally, we have the ability to produce metallurgical coal by reprocessing a nearby coal refuse pile located at Eccles, West Virginia.
Acquired in 2008, Powell Mountain, located in Lee County, Virginia and Harlan County, Kentucky, currently operates the Darby mine, a room-and-pillar mine operating two sections with continuous miners and shuttle cars. The mine is operating in the Darby seam with all coal being trucked to the Mayflower preparation plant for processing. Coal is shipped by rail through the dual service rail loadout facility with rail service provided by both the Norfolk Southern and CSX railroads. Some purchased coal is brought into the facility for processing and blending. We plan to begin operation of the new Middle Splint mine in 2011.
Vindex Energy Corporation
Vindex Energy Corporation operates three surface mines: Carlos, Island and Jackson Mountain, located in Garrett and Allegany Counties, Maryland. The reserves at Vindex are leased from multiple landowners. All surface mines operated by Vindex Energy are truck-and-shovel/loader mining operations which extract coal from the Upper Freeport, Middle Kittanning, Pittsburgh, Little Pittsburgh and Redstone seams. In 2007, Vindex added the Cabin Run property and the Buffalo properties to its reserve base. The total surface mineable reserves at Vindex amount to approximately 10.4 million tons.
MANAGEMENT DISCUSSION FROM LATEST 10K
The following discussion contains forward-looking statements that include numerous risks and uncertainties. Actual results could differ materially from those discussed in the forward-looking statements as a result of these risks and uncertainties, including those set forth in this Annual Report on Form 10-K under â€śSpecial Note Regarding Forward-Looking Statementsâ€ť and under â€śRisk Factors.â€ť You should read the following discussion in conjunction with â€śSelected Financial Dataâ€ť and the audited and unaudited consolidated financial statements and notes thereto of International Coal Group, Inc. and its subsidiaries appearing elsewhere in this Annual Report on Form 10-K.
We produce, process and sell coal from 13 regional mining complexes, which, as of December 31, 2010 were supported by 13 active underground mines, 10 active surface mines and 11 preparation plants located throughout West Virginia, Kentucky, Virginia, Maryland and Illinois. We have three reportable business segments, which are based on the coal regions in which we operate: (i) Central Appalachian, comprised of both surface and underground mines, (ii) Northern Appalachian, also comprised of both surface and underground mines and (iii) Illinois Basin, representing one underground mine. For more information about our reportable business segments, please see our audited consolidated financial statements and the notes thereto included in Item 15 of this Annual Report on Form 10-K. We also broker coal produced by others, the majority of which is shipped directly from the third-party producer to the ultimate customer. Our coal sales are primarily to large utilities and industrial customers in the eastern region of the United States and domestic and international steel companies and brokers. In addition, we generate other revenues from contract mining income, coalbed methane sales, ash disposal services, equipment and parts sales, equipment rebuild and maintenance services, royalties and coal handling and processing income.
Our primary expenses are wages and benefits, repair and maintenance, diesel fuel, blasting supplies, coal transportation, purchased coal, royalties, freight and handling and taxes incurred in selling our coal.
Certain Trends and Economic Factors Affecting the Coal Industry
Our revenues depend on the price at which we are able to sell our coal. The pricing environment for domestic steam and metallurgical coal during 2010 strengthened from the weak pricing experienced throughout most of 2009. Thermal coal prices and demand began to rapidly recover by mid-2010 driven by economic recovery, favorable weather and declining supply. Despite some weakening during the fourth quarter, thermal prices closed 2010 at significantly higher levels when compared to 2009. Metallurgical pricing also rebounded strongly throughout the year from the recessionary levels of 2009, again driven by global economic recovery. At the end of 2010, massive flooding in Australia created metallurgical supply shortages that continued to drive prices even higher. Conversely, continued regulatory constraints and rapidly increasing global commodity prices may significantly increase our costs, resulting in lower margins.
For additional information regarding some of the risks and uncertainties that affect our business and the industry in which we operate, see Item 1A. Risk Factors.
Critical Accounting Policies and Estimates
Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities. Management evaluates its estimates on an on-going basis. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Actual results may differ from the estimates used. Our actual results have generally not differed materially from our estimates. However, we monitor such differences and, in the event that actual results are significantly different from those estimated, we disclose any related impact on our results of operations, financial position and cash flows. Note 2 to our audited consolidated financial statements included in Item 15 of this Annual Report on Form 10-K provides a description of our significant accounting policies. We believe that of these significant accounting policies, the following involve a higher degree of judgment or complexity:
Coal revenues result from sales contracts (long-term coal agreements or purchase orders) with electric utilities, industrial companies or other coal-related organizations, primarily in the eastern United States. Revenue is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable and the title or risk of loss has passed in accordance with the terms of the sales agreement. Under the typical terms of these agreements, risk of loss transfers to the customers at the mine or port, when the coal is loaded on the rail, barge, truck or other transportation sources that deliver coal to its destination.
Coal sales revenues also result from the sale of brokered coal produced by others. The revenues related to brokered coal sales are included in coal sales revenues on a gross basis and the corresponding cost of the coal from the supplier is recorded in cost of coal sales in accordance with ASC Subtopic 605-45, Principal Agent Considerations (â€śASC 605-45â€ť).
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.
Other revenues primarily consist of contract mining income, coalbed methane sales, ash disposal services, equipment and parts sales, equipment rebuild and maintenance services, royalties and coal handling and processing income. With respect to other revenues recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and do not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the sellerâ€™s price to the buyer is fixed or determinable and collectibility is reasonably assured. Advance payments received are deferred and recognized in revenue when earned.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts represents managementâ€™s best estimate of the amount of probable credit losses in our existing accounts receivable. We establish provisions for losses on accounts receivable when it is probable that all or part of the outstanding balance will not be collected. Management regularly reviews collectability and establishes or adjusts the allowance as necessary. Although we believe the estimate of credit losses we have made is reasonable and appropriate, inability to collect outstanding accounts receivable amounts could materially impact our reported financial results.
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. We record these reclamation obligations according to the provisions of ASC Topic 410, Asset Retirement and Environmental Obligations (â€śASC 410â€ť). ASC 410 requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which the legal obligation associated with the retirement of the long-lived asset is incurred. Fair value of reclamation liabilities is determined based on the present value of the estimated future expenditures. When the liability is initially recorded, the offset is capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its future value, and the capitalized cost is depreciated over the useful life of the related asset. If the assumptions used to estimate the liability do not materialize as expected or regulatory changes were to occur, reclamation costs or obligations to perform reclamation and mine closure activities could be materially different than currently estimated. To settle the liability, the mine property is reclaimed and, to the extent there is a difference between the liability and the amount of cash paid to perform the reclamation, a gain or loss upon settlement is recognized. On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures and revisions to cost estimates and productivity assumptions to reflect current experience. At December 31, 2010, we had recorded asset retirement obligation liabilities of $79.1 million, including amounts reported as current liabilities. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2010, we estimate that the aggregate undiscounted cost of final mine closure is approximately $155.5 million.
We are required, under certain royalty lease agreements, to make minimum royalty payments whether or not mining activity is being performed on the leased property. These minimum payments may be recoupable once mining begins on the leased property. The recoupable minimum royalty payments are capitalized and amortized based on the units-of-production method at a rate defined in the lease agreement once mining activities begin. Unamortized deferred royalty costs are expensed when mining has ceased or a decision is made not to mine on such property. We have recorded an allowance for such circumstances based upon managementâ€™s plans for the continuing operation of existing mine sites or for when properties will be developed and/or mined. We believe the estimate for losses is appropriate. However, actual amounts that we recoup through mining activity could vary resulting in a material impact to our financial results.
Coal inventories are stated at lower of average cost or market and represent coal contained in stockpiles, including those tons that have been mined and hauled to our loadout facilities, but not yet shipped to customers. These inventories are stated in clean coal equivalent tons and take into account any loss that may occur during the processing stage. Coal must be of a quality that can be sold on existing sales orders to be carried as coal inventory. Coal inventory volumes are determined through survey procedures. The surveys involve assumptions, inherent uncertainties and the application of management judgment.
Parts and supplies inventories are valued at average cost, less an allowance for obsolescence. We establish provisions for losses in parts and supplies inventory values through analysis of turnover of inventory items and adjust the allowance as necessary.
Although we believe the estimates we have made with respect to the valuation of our coal and parts and supplies inventories are reasonable and appropriate, changes in assumptions (coal inventories) or actual utilization of items (parts and supplies inventories) could materially impact our reported financial results.
Depreciation, Depletion and Amortization
Property, plant, equipment and mine development, which includes coal lands and mineral rights, are recorded at cost, which includes construction overhead and interest, where applicable. Expenditures for major renewals and betterments are capitalized, while expenditures for maintenance and repairs are expensed as incurred.
Mine development, coal lands and mineral rights costs are amortized or depleted using the units-of-production method, based on estimated recoverable tons. There are uncertainties inherent in estimating quantities of recoverable tons related to particular mine development, coal lands and mineral rights areas. Recoverable tons contained in an area are based on engineering estimates which can, and often do, change as the tons are mined. Any change in the number of recoverable tons contained in mine development, coal lands and mineral rights areas will result in a change in the depletion or amortization rate and corresponding expense. For the year ended December 31, 2010, we recognized $7.8 million of depletion expense.
Other property, plant and equipment are depreciated using the straight-line method based on estimated useful lives.
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. Reserve estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Acquisitions, sales or dispositions of coal properties will also change the amount of economically recoverable coal reserves. 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 in fact 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 the 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 these reserves will likely vary from estimates, and these variances may be material. At December 31, 2010, we estimate that we had 1.1 billion tons of coal reserves.
We follow ASC Subtopic 360-10-45, Impairment or Disposal of Long-Lived Assets , which requires that projected future cash flows from use and disposition of assets be compared with the carrying amounts of those assets when impairment indicators are present. When the sum of projected cash flows is less than the carrying amount, impairment losses are indicated. If the fair value of the assets is less than the carrying amount of the assets, an impairment loss is recognized. In determining such impairment losses, discounted cash flows or asset appraisals are utilized to determine the fair value of the assets being evaluated. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mineâ€™s underlying costs are not recoverable in the future, reclamation and mine closure obligations are accelerated and the mine closure accrual is increased accordingly. To the extent it is determined asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized. Recognition of an impairment will decrease asset values, increase operating expenses and decrease net income. In December 2008, we made the decision to permanently close our Sago mine during the first quarter of 2009. Upon making this decision, we performed an impairment test of related mine development costs, which resulted in a $7.2 million non-cash impairment charge to reduce the carrying amount of these assets to their estimated fair value. There were no other impairment charges related to long-lived assets recognized in the periods covered by this Annual Report on Form 10-K as a result of our impairment tests.
Pursuant to ASC Subtopic 470-20, Debt with Conversion and Other Options , our convertible notes are accounted for as convertible debt and the embedded conversion option in the convertible notes has been accounted for as a component of equity.
Coal Supply Agreements
Our below-market coal supply agreements (sales contracts) represent coal supply agreements acquired through acquisitions accounted for as business combinations for which the prevailing market price for coal specified in the contract was in excess of the contract price. In accordance with ASC Topic 805, Business Combinations , value was based on discounted cash flows resulting from the difference between the below-market contract price and the prevailing market price at the date of acquisition. The below-market coal supply agreements are amortized on the basis of tons shipped over the term of the respective contract. Determination of fair value requires management judgment and often involves the use of significant estimates and assumptions.
Share Based Compensation
We account for our share based awards in accordance with ASC Topic 718, Compensation â€” Stock Compensation (â€śASC 718â€ť). Share based compensation expense is generally measured at the grant date and recognized as expense over the vesting period of the award. We utilize restricted stock and stock options as part of our share based compensation program. Determining fair value requires us to make a number of assumptions, including expected volatility, expected term and risk-free interest rate. Expected volatility is estimated using both historical and market data. Expected term is based on historical data and expected behavior. Risk-free interest rates are based on the rates of zero coupon U.S. Treasury bonds with similar maturities on the date of grant. The assumptions used in calculating the fair value of share based awards represent our best estimates and involve inherent uncertainties and the application of management judgment. Although we believe the assumptions and estimates we have made are reasonable and appropriate, different assumptions could materially impact our reported financial results.
Debt Issuance Costs
Debt issuance costs reflect fees incurred to obtain financing. Debt issuance costs related to our outstanding debt are amortized over the life of the related debt. From time to time, we write-off deferred financing fees as a result of amending or canceling related debt and/or credit agreements. Such write-offs could be material and occur in the period that the amendment or cancellation occurs.
We account for income taxes in accordance with ASC Topic 740, Income Taxes (â€śASC 740â€ť), which requires the recognition of 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. ASC 740 also requires that deferred tax assets, if it is more likely than not that some portion or all of the deferred tax asset will not be realized, be reduced by a valuation allowance. In evaluating the need for a valuation allowance, we take into account various factors, including the timing of the realization of deferred tax liabilities, the expected level of future taxable income and available tax planning strategies. If future taxable income is lower than expected or if expected tax planning strategies are not available as anticipated, we may record a change to the valuation allowance through income tax expense in the period the determination is made.
A tax position is initially recognized in the financial statements when it is more likely than not the position will be sustained upon examination by applicable tax authorities. Such tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with the tax authority assuming full knowledge of the position and all relevant facts.
Postretirement Medical Benefits
Some of our subsidiaries have liabilities for postretirement benefit cost obligations. Liabilities for postretirement benefits are not funded. The liability is actuarially determined and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for postretirement benefits. The discount rate assumption reflects the rates available on a hypothetical portfolio of high-quality fixed income debt instruments whose cash flows match the timing and amount of expected benefit payments. Our estimates of these costs are adjusted based upon actuarially determined amounts using a rate of 5.50% as of December 31, 2010. If we were to decrease our estimate of the discount rate to 4.50%, the present value of our postretirement liability would increase by approximately $8.9 million. If we were to increase our estimate of the discount rate to 6.50%, the present value of our postretirement liability would decrease by approximately $7.0 million. We make assumptions related to future trends for medical care costs in the estimates of retiree healthcare and work-related injury and illness obligations. The future healthcare cost trend rate represents the rate at which healthcare costs are expected to increase over the life of the plan. The healthcare cost trend rate assumptions are determined primarily based upon our, and our predecessorâ€™s, historical rate of change in retiree healthcare costs. The postretirement expense in the operating period ended December 31, 2010 was based on an assumed heath care inflationary rate of 7.1% in the operating period decreasing to 4.7% in 2081, which represents the ultimate healthcare cost trend rate for the remainder of the plan life. A one-percentage point increase in the assumed ultimate healthcare cost trend rate would increase the service and interest cost components of the postretirement benefit expense for the year ended December 31, 2010 by $1.6 million and increase the accumulated postretirement benefit obligation at December 31, 2010 by $9.4 million. A one-percentage point decrease in the assumed ultimate healthcare cost trend rate would decrease the service and interest cost components of the postretirement benefit expense for the year ended December 31, 2010 by $1.3 million and decrease the accumulated postretirement benefit obligation at December 31, 2010 by $7.6 million. If our assumptions do not materialize as expected or if regulatory changes were to occur, actual cash expenditures and costs that we incur could differ materially from our current estimates.
Workersâ€™ 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 workersâ€™ compensation laws are administered by state agencies with each state having its own rules and regulations regarding compensation that is owed to an employee who is injured in the course of employment or the beneficiary of an employee that suffers fatal injuries in the course of employment. Our operations are covered through a combination of participation in a state run program and insurance policies. Our estimates of these costs are adjusted based upon actuarially determined amounts using a discount rate of 4.5% as of December 31, 2010. The discount rate assumption reflects the rates available on a hypothetical portfolio of high-quality fixed income debt instruments whose cash flows match the timing and amount of expected benefit payments. If we were to decrease our estimate of the discount rate to 3.5%, the present value of our workersâ€™ compensation liability would increase by approximately $0.5 million. If we were to increase our estimate of the discount rate to 5.5%, the present value of our workersâ€™ compensation liability would decrease by approximately $0.4 million. At December 31, 2010, we have recorded an accrual of $10.4 million for workersâ€™ compensation benefits. Actual losses may differ from these estimates, which could increase or decrease our costs.
MANAGEMENT DISCUSSION FOR LATEST QUARTER
Cautionary Note Regarding Forward-Looking Statements
Statements in this Quarterly Report on Form 10-Q that are not historical facts are forward-looking statements within the â€śsafe harborâ€ť provision of the Private Securities Litigation Reform Act of 1995 and may involve a number of risks and uncertainties. We have used the words â€śanticipate,â€ť â€śbelieve,â€ť â€ścould,â€ť â€śestimate,â€ť â€śexpect,â€ť â€śintend,â€ť â€śmay,â€ť â€śplan,â€ť â€śpredict,â€ť â€śprojectâ€ť and similar terms and phrases, including references to assumptions, in this report to identify forward-looking statements. These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to various risks, uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those matters expressed in or implied by these forward-looking statements. The following factors are among those that may cause actual results to differ materially from our forward-looking statements:
market demand for coal, electricity and steel;
availability of qualified workers;
future economic or capital market conditions;
weather conditions or catastrophic weather-related damage;
our production capabilities;
consummation of financing, acquisition or disposition transactions and the effect thereof on our business;
a significant number of conversions of our convertible senior notes prior to maturity;
our plans and objectives for future operations and expansion or consolidation;
our relationships with, and other conditions affecting, our customers;
availability and costs of key supplies or commodities such as diesel fuel, steel, explosives and tires;
availability and costs of capital equipment;
prices of fuels which compete with or impact coal usage, such as oil and natural gas;
timing of reductions or increases in customer coal inventories;
long-term coal supply arrangements;
reductions and/or deferrals of purchases by major customers;
risks in or related to coal mining operations, including risks relating to third-party suppliers and carriers operating at our mines or complexes;
unexpected maintenance and equipment failure;
adoption by Appalachian states of EPA guidance regarding stringent water quality-based limitations in CWA Section 402 wastewater discharge permits and CWA Section 404 dredge and fill permits;
environmental, safety and other laws and regulations, including those directly affecting our coal mining and production, and those affecting our customersâ€™ coal usage;
ability to obtain and maintain all necessary governmental permits and authorizations;
competition among coal and other energy producers in the United States and internationally;
railroad, barge, trucking and other transportation availability, performance and costs;
employee benefits costs and labor relations issues;
replacement of our reserves;
our assumptions concerning economically recoverable coal reserve estimates;
availability and costs of credit, surety bonds and letters of credit;
title defects or loss of leasehold interests in our properties which could result in unanticipated costs or inability to mine these properties;
the impact of the mine explosion at a competitorâ€™s mine on federal and state authoritiesâ€™ decisions to enact laws and regulations that result in more frequent mine inspections, stricter enforcement practices and enhanced reporting requirements;
future legislation and changes in regulations or governmental policies or changes in interpretations or enforcement thereof, including with respect to safety enhancements and environmental initiatives relating to global warming and climate change;
impairment of the value of our long-lived and deferred tax assets;
our liquidity, including our ability to adhere to financial covenants related to our borrowing arrangements;
adequacy and sufficiency of our internal controls; and
legal and administrative proceedings, settlements, investigations and claims, including those related to citations and orders issued by regulatory authorities, and the availability of related insurance coverage.
You should keep in mind that any forward-looking statements made by us in this Quarterly Report on Form 10-Q or elsewhere speaks only as of the date on which the statements were made. New risks and uncertainties arise from time to time, and it is impossible for us to predict these events or how they may affect us or anticipated results. We have no duty to, and do not intend to, update or revise the forward-looking statements in this report after the date of this report, except as may be required by law. In light of these risks and uncertainties, you should keep in mind that any forward-looking statement made in this report might not occur. When considering these forward-looking statements, you should keep in mind the cautionary statements in this Quarterly Report on Form 10-Q and in our other SEC filings, including the more detailed discussion of these factors, as well as other factors that could affect our results, contained in Item 3, â€śQuantitative and Qualitative Disclosures About Market Risk,â€ť as well as in the â€śRisks Relating to Our Businessâ€ť section of Item 1A of our 2010 Annual Report on Form 10-K.
Coal sales revenues â€”Coal sales revenues increased for the three months ended March 31, 2011 compared to the three months ended March 31, 2010 due to an increase in sales realization of $11.10 per ton resulting primarily from favorable pricing of metallurgical coal in the first quarter of 2011. Partially offsetting the effect of increased prices was an 11% decrease in tons sold, largely due to weaker thermal coal demand and inconsistent rail service.
Central Appalachian. Coal sales revenues from our Central Appalachian segment for the three months ended March 31, 2011 remained relatively consistent despite increased sales realization of $7.71 per ton due to increased participation in the metallurgical market. Favorable pricing was offset by a 9% decrease in tons sold under thermal coal supply agreements.
Northern Appalachian . For the three months ended March 31, 2011, our Northern Appalachian coal sales revenues increased compared to the three months ended March 31, 2010 as a result of increased sales realization of $26.22 per ton due to increased sales of metallurgical coal, partially offset by a 10% decrease in total tons sold.
Illinois Basin . The increase in coal sales revenues from our Illinois Basin segment for the three months ended March 31, 2011 was primarily due to an increase in sales realization of $2.47 per ton as a result of increased prices that went in effect in January 2011 on certain coal supply agreements, while tons sold remained relatively consistent compared to the three months ended March 31, 2010.
Ancillary . Our Ancillary segmentâ€™s coal sales revenues represent coal sold under brokered coal contracts, all of which were legacy contracts obtained in conjunction with business combinations. For the three months ended March 31, 2011, we had no Ancillary coal sales revenues as all such coal supply agreements expired subsequent to the three months ended March 31, 2010.
Freight and handling revenues â€”Freight and handling revenues represent reimbursement of freight and handling costs for certain shipments for which we initially pay the costs and are then reimbursed by the customer. Freight and handling revenues and costs decreased for the three months ended March 31, 2011 compared to the three months ended March 31, 2010, primarily due to a decrease in sales volumes on shipments with related freight and handling.
Other revenues â€”The increase in other revenues for the three months ended March 31, 2011 compared to the three months ended March 31, 2010 was primarily due to an increase in contract mining revenue of $1.4 million, as well as a $0.9 million increase related to the sale of parts and supplies during the three months ended March 31, 2011.
Cost of coal sales â€”For the three months ended March 31, 2011, cost of coal sales decreased compared to the three months ended March 31, 2010 as a result of an 11% decrease in tons sold. Partially offsetting the effect of decreased tons sold was an 11% increase in cost of coal sales per ton.
Central Appalachian . Cost of coal sales from our Central Appalachian segment increased due to an increase in cost of coal sales per ton from $56.71 per ton for the three months ended March 31, 2010 to $63.74 per ton for the three months ended March 31, 2011, partially offset by a 9% decrease in tons sold. The increase in cost of coal sales per ton is primarily due to increases in fuel, lubricants and chemicals, labor, operating supplies and site maintenance and roof control and ventilation costs. Fuel, lubricants and chemicals increased on a per ton basis due to increased diesel fuel costs. Labor costs per ton increased primarily as a result of increased wages, as well as from hampered production resulting from enhanced regulatory oversight. Operating supplies and site maintenance costs per ton increased due to increased safety supplies and sediment pond maintenance costs, while roof control and ventilation costs per ton increased due to increased commodity pricing over the three months ended March 31, 2010. Additionally, cost of coal sales increased on a per ton basis as a result of fluctuations in the value of stockpile inventories. Partially offsetting this increase in cost per ton was a decrease in royalties, taxes and fees as a result of reduced severance tax expense.
Roger L. Nicholson
Thank you. Welcome to International Coal Groupâ€™s first quarter 2011 earnings conference call. Iâ€™m Roger Nicholson, Senior Vice President, Secretary and General Counsel of ICG. We released our earnings report yesterday after the market closed.
With me on the call today are Ben Hatfield, President and CEO of International Coal Group; Brad Harris, Senior Vice President, CFO and Treasurer; Mike Hardesty, Senior Vice President, Sales and Marketing and Ross Mazza, Director of Financial Reporting and Investor Relations.
Before we get started, please let me remind you that various remarks we may make on this call concerning future expectations, plans and prospects for the company constitute forward-looking statements for purposes of the Safe Harbor provisions under the Private Securities Litigation Reform Act of 1995.
These statements are made on the basis of managementâ€™s views and assumptions regarding feature events and business performance as of the time the statements were made. Because these forward-looking statements are subject to various risks and uncertainties, actual results may differ materially from those implied.
Factors that could cause actual results to differ materially are contained in our filings from time to time with the Securities and Exchange Commission and are also contained in our press release dated April 27, 2011.
Non-GAAP financial measures will also be discussed. You will find a reconciliation of the differences between the non-GAAP financial measures and the most directly comparable GAAP financial measures at the end of our press release, a copy of which has been posted on our website.
At this time Iâ€™d like to turn the call over to Ben Hatfield for his opening remarks.
Bennett K. Hatfield
Thank you for joining us this morning. Increasing metallurgical coal production and steady operating performance at virtually all of our business units provided strong first quarter results. Despite weather related production challenges at Vindex unscheduled contract customer outages at ICG Illinois and erratic rail service that delayed shipments at several operations, we were able to expand metallurgical sales and achieve record per ton margins.
Improving demand for coking coal has lead to remarkably strong metallurgical pricing, a trend that we anticipate will continue into 2012. Although we expect the thermal market to strengthen in the second half of this year, low natural gas prices will likely continue to suppress coal-fired electricity output through mid-year.
At this time, Iâ€™d like to turn the call over to Brad Harris, our Chief Financial Officer.
Bradley W. Harris
Thanks Ben. For the first quarter of 2011, we reported total revenues of $302 million including $283.7 million attributable to coal sales of 3.9 million tons. First quarter 2010 revenues totalled $288.6 million, of which $270.5 million was attributable to coal sales of 4.3 million tons.
Adjusted EBITDA for the first quarter of 2011 was $65.1 million, which represents a 39% increase over the $46.9 million of adjusted EBITDA reported in the same period of 2010.
Net income for the first quarter of 2011 was $22 million or $0.10 per share on a diluted basis, compared to a net loss of $8.9 million or $0.05 per share on a diluted basis during the first quarter of 2010.
Net loss for the first quarter of 2010 included a $22 million pre-tax loss on extinguishment of debt related to the companyâ€™s capital restructuring. Excluding this loss, first quarter 2010 net income would have been $6.2 million or $0.03 per share on diluted basis.
Average coal sales revenue per ton for the first quarter was $73.67 compared to $62.57 for the comparable period in 2010, while cost per ton sold was $56.60 versus $50.90 for the same period in 2010. Cost per ton for the first quarter of 2011 was adversely impacted by rising diesel fuel prices and continuing regulatory issues that hampered production.
Also contributing to the increase in cost per ton over the prior year was our expanded metallurgical production, as these reserves are generally more expensive to mine than thermal serves.
Margin per ton increased by 46% to $17.07 for the quarter compared to $11.67 per ton for the first quarter of 2010, primarily due to higher price realization on increased metallurgical sales. Metallurgical shipments of 718,000 tons during the quarter represented a 53% increase versus the first quarter of 2010.
Depreciation, depletion and amortization expense totaled $25.7 million for the first quarter compared to $26.4 million for the same quarter last year. Corporate SG&A for the first quarter was $11.2 million compared to $8.6 million for the same period in 2010, primarily due to increased labor and legal cost and a reserve for potential bad debt.
Gain on the sale of assets totaled $6.7 million in the current quarter compared to $3.5 million in the same period of 2010. The current quarter included a $6.5 million gain related to the sale of an idle drag mine previously used at our ICG Easternâ€™s Birch River mine.
Our effective income tax rate for the quarter of 30% reflects the benefit of excess depletion. As of March 31, 2011 we had $186.6 million in cash and $39.2 million available in borrowing capacity under our credit facility.
At quarter end debt outstanding was $333.6 million, net of a $32.3 million discount, consisting primarily of $115 million aggregate principal amount of our 4% convertible notes and $200 million aggregate principal amount of our 9.125% senior notes.
On March 31, 2011 we announced that $115 million of our 4% convertible notes and $731,000 of our 9% convertible senior notes became convertible at the auction of the holders beginning April 1, 2011. Although the convertible notes are now classified as a current liability, we do not believe that a significant number of conversions are likely at this time and to-date have not received any notices to exercise. We do not expect the triggering of these conversion rates to have a material affect on our financial position.
Our total assets were $1.5 billion as of March 31, 2011, compared to $1.6 billion a year ago. Capital expenditures for the first quarter totaled $41.2 million.
At this time, Iâ€™ll turn the call back over to Ben.
Bennett K. Hatfield
Thank you, Brad. Now I would like to provide an update on key developments in the first quarter. Construction at the new Tygart Valley No. 1 deep mine complex is proceeding on schedule. Excavation of slope portal and two ventilation (inaudible) is ongoing and progressing as planned.
Foundation construction for the state-of-the-art coal preparation facility is also underway with steel erection expected to begin in June 2011.
Initial coal production is projected for late fourth quarter of this year. At full output, currently projected for early 2014, Tygart Valley No. 1 is expected to produce approximately 3.5 million tons per year. Although topping 2011 met tonnage guidance has not changed, the lower end has been adjusted upward as we have resumed limited processing of the (inaudible) resource at our Beckley complex. We expect to complete a $2 million coal handling system expansion during the third quarter in order to allow increased sales of this low volatile metallurgical product.
The company continues to wait a ruling from the trial court and the lawsuit with Allegheny Energy concerning the coal supply agreement serviced by the Sycamore No. 2 mine. While the ruling was expected in mid-March, the timing of the ruling is within the judgeâ€™s discretion. The company anticipates receiving the courtâ€™s ruling in the near future and will promptly disclose the ruling upon its entry.
Turning now to our current guidance. For 2011, coal production and sales are expected to be between 16.1 million tons and 16.5 million tons, including 3.2 million tons to 3.5 million tons of metallurgical coal. The average selling price is projected to be between $76 per ton and $79 per ton, with an average cost ranging from $56.50 per ton to $58.50 per ton excluding selling, general and administrative expenses.
Committed and price sales for 2011 totaled approximately 13.9 million tons or 85% of planned shipments, at an average price of $75.75 per ton. Unpriced tonnage includes approximately 1.8 million tons of thermal coal and 600,000 tons of metallurgical coal.
Adjusted EBITDA for 2011 is now expected to be in the range of $290 million to $320 million. Capital expenditures for 2011 are expected to be between $225 million and $245 million, including approximately $145 million related to development projects, primarily at our Tygart Valley No.1, Illinois and Vindex operations.
We expect to fund all of our 2011 CapEx with cash flow from operations. We project our 2011 effective tax rate to be approximately 30%.
Now shifting to 2012 guidance, coal production and sales are expected to be in a range of 16.5 million tons to 17.5 million tons, including 3.3 million tons to 3.7 million tons of metallurgical coal. The average selling price is projected to be between $83 and $89 per ton.
Committed and price sales for 2012 totaled approximately 4.2 million tons or 25% of planned shipments at an average price of $60 per ton. Unpriced tonnage includes approximately 9.6 million tons of thermal coal and 3.2 million tons of metallurgical coal. Most of the 2012 committed sales consist of lower priced Illinois Basin and Northern Appalachian legacy contracts.
At this time, Iâ€™ll open the call to your questions.