Item 1.
Business.
Overview
We are a leading producer of thermal coal in the eastern United States, with operations and coal reserves in Appalachia and the Illinois Basin. We are also a leading U.S. producer of metallurgical quality coal. We and our predecessor companies have operated in these regions for more than 50 years. Our operations consist of sixteen mining complexes which include company-operated mines, contractor-operated mines and coal preparation facilities. One of our mining complexes is located in northern West Virginia, twelve are located in southern West Virginia and three are located in western Kentucky. We ship coal to electric utilities, industrial users and metallurgical coal customers via various company-owned and third-party loading facilities and multiple rail and river transportation routes.
In 2008, we sold 28.5 million tons of coal, of which 79% was sold to domestic electric utilities and 21% was sold to domestic and global steel producers. We control approximately 1.8 billion tons of proven and probable coal reserves. Our proven and probable coal reserves include metallurgical coal and medium and high-Btu thermal coal, with low, medium and high sulfur content. We believe we are well-positioned to meet customers’ demand for various products, given the diverse coal qualities available in our proven and probable coal reserves.
Effective October 31, 2007, Patriot was spun-off from Peabody Energy Corporation (Peabody) and became a separate, public company traded on the New York Stock Exchange (symbol PCX). This transaction is referred to in this Form 10-K as the “distribution” or the “spin-off.” Prior to the spin-off, we were wholly-owned subsidiaries of Peabody and our operations were a part of Peabody’s operations. Many of our subsidiaries were acquired during the 1980s and 1990s, when Peabody grew through expansion and acquisition. The spin-off from Peabody, including coal assets and operations in Appalachia and the Illinois Basin, was accomplished through a dividend of all outstanding shares of Patriot. Distribution of the Patriot stock to Peabody’s stockholders occurred on October 31, 2007, at a ratio of one share of Patriot stock for every 10 shares of Peabody stock.
On April 2, 2008, Patriot entered into an agreement to acquire Magnum Coal Company (Magnum). Magnum was one of the largest coal producers in Appalachia, operating 11 mines and 7 preparation plants with production from surface and underground mines and controlling more than 600 million tons of proven and probable coal reserves. Magnum results are included as of the date the acquisition was consummated, July 23, 2008, and all Magnum operations are located in Appalachia.
Mining Operations
Our mining operations and coal reserves are as follows:
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Appalachia. In southern West Virginia, we have twelve active mining complexes located in Boone, Clay, Lincoln, Logan and Kanawha counties. In northern West Virginia, we have one complex located in Monongalia County. As part of a comprehensive strategic review of operations upon acquisition of Magnum, we announced plans to idle operations at our Jupiter mining complex (December 2008) and our Remington mining complex (currently planned for March 2009). In Appalachia, we sold 20.6 million tons of coal in the year ended December 31, 2008. As of December 31, 2008, we controlled 1.18 billion tons of proven and probable coal reserves in Appalachia, of which 468 million tons were assigned to current operations.
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Illinois Basin. In the Illinois Basin, we have three complexes located in Union and Henderson counties in western Kentucky. In the Illinois Basin, we sold 7.9 million tons of coal in the year ended December 31, 2008. As of December 31, 2008, we controlled 655 million tons of proven and probable coal reserves in the Illinois Basin, of which 136 million tons were assigned to current operations.
The following table provides the location and summary information of our operations as of December 31, 2008.
(1)
LW = Longwall, CM = Continuous Miner, TS = Truck-and-Shovel, DL = Dragline, HW = Highwall.
(2)
Tons sold, presented in thousands, for each plant were the same as actual annual plant production in 2008, subject to stockpile variations.
(3)
The Jupiter complex was idled December 31, 2008.
(4)
The Remington complex will be idled in March 2009.
(5)
We expect the Blue Creek complex will be operational in 2009.
Longwall mining. Longwall mining is an underground mining method that uses hydraulic shields, varying from five feet to twelve feet in height, to support the roof of the mine while a shearing machine traverses the coal face removing a two to three foot slab of coal with each pass. An armored face conveyer then moves the coal to a standard deep mine conveyer system for delivery to the surface. Longwall mining is highly productive, but it is effective only for large blocks of medium to thick coal seams.
Continuous miner mining. Continuous miner mining is an underground method in which airways and transportation entries are developed by continuous mining machines, leaving “pillars” to support the roof. Pillars may subsequently be extracted to maximize the reserve recovery. This method is often used to mine smaller coal reserves or thin seams.
Truck-and-shovel mining. Truck-and-shovel mining is a surface mining method that uses large electric- or diesel-powered shovels to remove overburden, which is used to backfill pits after coal removal. Loading equipment is used to load coal into haul trucks for transportation to the preparation plant or transportation loading facility. Productivity depends on equipment, geological composition and the ratio of overburden to coal.
Dragline mining. Dragline mining is an efficient surface method that uses large capacity draglines to remove overburden to expose the coal seams. In Central Appalachia, the seams to be mined above the dragline are pre-stripped with support equipment in order to create a bench upon which the dragline can operate. The coal is loaded into haul trucks for transportation to a preparation plant or transportation loading facility.
Highwall mining. Highwall mining is a surface mining method generally utilized in conjunction with truck-and-shovel/loader surface mining. As the highwall is exposed by the truck-and-shovel/loader operation, a modified continuous miner with an attached auger conveyor system cuts horizontal passages from the highwall into the coal seam. These passages can penetrate to a depth of up to 1,600 feet.
Appalachian Mining Operations
Our Appalachian Mining Operations include thirteen mining complexes in West Virginia.
Appalachia
Big Mountain
The Big Mountain mining complex is sourced by one company-operated underground mine, Big Mountain No. 16, and multiple contractor-operated underground mines located in southern West Virginia. Coal is produced utilizing continuous mining methods. The coal is sold on the thermal market and is transported via the CSX railroad. Coal is produced from the Coalburg seam with average thickness of eight feet, and the Dorothy seam with average thickness of six feet. Most of the employees at the Big Mountain mining complex are represented by the United Mine Workers of America (UMWA).
Campbell’s Creek
The Campbell’s Creek mining complex consists of two underground mines located in southern West Virginia. The Campbell’s Creek No. 7 mine operates in the Winifrede seam, with an average mining thickness of seven and one half feet. The Campbell’s Creek No. 6 mine is a contract mine in the Stockton seam, and has an average mining thickness of six and one half feet. All mines in the Campbell’s Creek mining complex utilize the room-and-pillar continuous mining method. After processing, the coal is transported by truck to the Kanawha River for loading onto barges that deliver the coal to customers. Coal produced at Campbell’s Creek mining complex is sold on the thermal market. The employees at the Campbell’s Creek mining complex are not represented by a union.
Corridor G
The Corridor G mining complex, previously referred to as Hobet, consists of one surface mine located in southern West Virginia, with another surface mine, Hill Fork, expected to begin production during first quarter 2009. Coal is sourced from the Kittanning, Stockton and Coalburg seams, with a 16-to-1 average overburden to coal ratio. Corridor G utilizes truck-and-shovel/loader and dragline mining. Coal produced at this complex is transferred by belt to the on-site preparation plant and loadout facility. After processing, the coal is transported to customers by CSX rail. Coal produced at the Corridor G mining complex is sold on the thermal market. Most of the employees at the Corridor G mining complex are represented by the UMWA.
Jupiter
The Jupiter mining complex consisted of one underground mine and one surface mine located in southern West Virginia. Coal was sourced from the Coalburg seam, with an average mining thickness of nine feet. IO underground mine utilized the room-and-pillar continuous mining method and Thunderhill mine utilized the truck-and-shovel/loader method. Coal was processed at this complex through an on-site preparation plant and sold on the thermal market. After the coal was processed, it was transferred to a rail loadout facility located at the preparation plant, and the coal was shipped to customers via the CSX railroad. As part of a comprehensive strategic review of operations upon the acquisition of Magnum, we idled the operations at the Jupiter complex in late December 2008 due to its unacceptably high cost structure, coupled with softer market conditions.
Kanawha Eagle
The Kanawha Eagle complex is located in southern West Virginia, and is sourced by three company-owned underground mines utilizing continuous mining methods. Processed coal is sold on both metallurgical and thermal markets and is transported via the CSX railroad and via barge on the Kanawha River. Coal is produced from the Coalburg seam, with average thickness of six feet, and the Eagle seam, with average thickness of four feet. The labor force is contracted through a third party and is not represented by a union.
Logan County
The Logan County mining complex, formerly referred to as Apogee, consists of one surface mine located in southern West Virginia. Coal from this complex is sold on the thermal market. The Guyan mine utilizes the truck-and-shovel/loader mining method. Coal produced at this complex is transferred by truck to its on-site preparation plant and loadout facility. Coal is transported from the loadout facility to customers by CSX rail. Coal is sourced from the Freeport, Kittanning, Stockton and Coalburg seams, with a 15-to-1 average overburden to coal ratio. Certain employees at the Logan County complex are represented by the UMWA.
Paint Creek
The Paint Creek mining complex, formerly referred to as Samples, consists of one surface mine and one underground mine located in southern West Virginia. The surface mine, Samples, utilizes truck-and-shovel/loader and highwall mining methods, while the underground mine, Winchester, utilizes the room-and-pillar continuous mining method. The Winchester mine operates in the Hernshaw seam, with an average mining thickness of six and one half feet. Coal from Samples is sourced from the Freeport, Kittanning, Stockton and Coalburg seams, with a 16.5-to-1 average overburden to coal ratio. After processing, coal is transported from the on-site preparation plant and loadout facility to customers by CSX rail, or coal can also be trucked approximately 14 miles to the Kanawha River and transported by barge. Coal from this complex can be sold on both the metallurgical and thermal markets. The employees at the Paint Creek complex are not represented by a union.
Panther
The Panther mining complex consists of one underground mine located in southern West Virginia. Coal is produced utilizing the longwall mining and room-and-pillar continuous mining methods. All coal is processed at an on-site preparation plant and then transported via truck to barges on the Kanawha River. Coal produced at the Panther complex may be sold as a thermal or metallurgical product. Coal is produced from the Eagle seam, with an average mining thickness of five and three quarter feet. The employees at the Panther complex are not represented by a union.
Remington
The Remington mining complex is located in southern West Virginia and consists of two underground mines and one surface mine. The two underground mines operate in the upper and lower Coalburg seam. The Stockburg No. 2 mine has an average mining thickness of six feet and the Deskins mine has an average mining thickness of six and one half feet. The room-and-pillar continuous mining method is utilized by the two underground mines. The Wildcat surface mine operates in the Kittanning, Clarion, Stockton and Coalburg seams. The surface mining operation utilizes the truck-and-shovel/loader method and a highwall miner. Coal from the Remington complex is processed through an on-site preparation plant. After processing, the coal is loaded onto trucks, which are owned and operated by third party contractors, for transportation to a barge loading site on the Kanawha River within ten miles of the Remington mining complex. All coal produced at the Remington mining complex is sold on the thermal market. The employees at the Remington complex are not represented by a union. As part of a comprehensive strategic review of operations upon the acquisition of Magnum, we currently plan to idle the operations at the Remington complex in March 2009 due to its unacceptably high cost structure, coupled with softer market conditions.
Rocklick
The Rocklick mining complex is located in southern West Virginia and is sourced by two company-operated underground mines, Harris No. 1 and Black Oak, and multiple contractor-operated underground and surface mines. Coal at the Rocklick mining complex is produced utilizing continuous mining methods. The contractor-operated surface mines at Rocklick utilize the truck-and-shovel/loader mining method. All Harris No. 1 coal is sold on the metallurgical market and most of the contractor processed coal is sold on the thermal market. Rocklick has the capability to transport coal on both the CSX and the Norfolk Southern railroads. Metallurgical coal at Harris No. 1 is produced from the Eagle seam, with average thickness of three feet if only the lower split is mined, or five feet if both seam splits are mined. Thermal coal is produced from the Winifrede seam, with average thickness of four feet, or surface mined from the Kittanning, Stockton, Clarion and Coalburg seams, with an 18-to-1 average overburden to coal ratio. Operations at the Harris No. 1 mine utilized the longwall mining method through the second quarter of 2008, but switched to continuous miner methods to deplete its final reserves. Due to the recent economic recession and significant reduction in steel production, operations at the Black Oak mine will be suspended in the first quarter of 2009 until demand increases for metallurgical coal. Most of the employees at the Rocklick mining complex are represented by the UMWA.
Wells
The Wells mining complex is located in southern West Virginia and is sourced by one company-operated underground mine, Rivers Edge, and multiple contractor-operated underground mines. Coal is produced utilizing continuous mining methods. The majority of coal currently produced at Wells is sold on the metallurgical market and is transported by the CSX railroad. Thermal coal can also be produced and processed at this operation. Rivers Edge mine produces coal from the Powellton seam, with average thickness of five feet. Coal is also produced from the Black Stallion contract mine in the Eagle seam, with average thickness of five feet. Contract mines produce coal from the No. 2 Gas, Winifrede, Powellton and Dorothy seams, each with an average thickness of four feet. Most of the employees at the company-owned and operated facilities of the Wells mining complex are represented by the UMWA.
Blue Creek
The Blue Creek mining complex is located in southern West Virginia. The complex is in the development stage and we anticipate it will open as soon as April 2009. The Blue Creek complex will consist of two underground mines in the Stockton seam, with an average thickness of eight feet. The complex will utilize room-and-pillar continuous mining methods and a third-party-owned on-site preparation facility. Coal produced at the Blue Creek complex will be sold on the thermal market and will be loaded onto trucks for transportation to a barge loading site on the Kanawha River.
Federal
The Federal mining complex is located in northern West Virginia and is sourced by one company-operated underground mine, Federal No. 2, utilizing longwall and continuous mining methods. All coal is sold on the high-Btu thermal market and is transported via the CSX and Norfolk Southern railroads. Coal is produced from the Pittsburgh seam, with average thickness of seven feet. Most of the employees at the Federal mining complex are represented by the UMWA.
Illinois Basin Mining Operations
Our Illinois Basin Mining Operations include three mining complexes in western Kentucky.
Illinois Basin
Bluegrass
The Bluegrass mining complex is located in western Kentucky and is sourced by two company-operated mines, Freedom and Patriot. Coal at Freedom is produced utilizing underground continuous mining methods, while coal at Patriot is produced utilizing the truck-and-shovel surface mining method. All coal is sold on the thermal market and is transported via truck and barge on the Green River. Coal is produced from the Kentucky No. 9 seam, with average thickness of four feet for the Freedom underground mine, and with a 15-to-1 average overburden to coal ratio for the Patriot surface mine. The employees at the Bluegrass mining complex are not represented by a union.
Dodge Hill
The Dodge Hill mining complex is located in western Kentucky and is sourced by one company-operated underground mine, utilizing continuous mining methods. All coal is sold on the thermal market and transported via barge on the Ohio River. Coal is produced from the Kentucky No. 6 seam, with average thickness of four feet. The employees at the Dodge Hill mining complex are not represented by a union.
Highland
The Highland mining complex is located in western Kentucky and is sourced by one company-operated underground mine, Highland No. 9, utilizing continuous mining methods. All coal is sold on the thermal market and is transported via barge on the Ohio River. Coal is produced from the Kentucky No. 9 seam, with average thickness of five feet. Most of the employees at the Highland complex are represented by the UMWA.
Customers and Backlog
As of December 31, 2008, we had a sales backlog of 95.1 million tons of coal, including backlog subject to price reopener and/or extension provisions, and our coal supply agreements have remaining terms up to 9 years and an average volume-weighted remaining term of approximately 2.5 years.
These commitments represent approximately 97%, 58% and 35% of our estimated production for 2009, 2010 and 2011, respectively.
In 2008, approximately 78% of our coal sales were under long-term (one year or greater) contracts. Also in 2008, our coal was sold to over 90 electricity generating and industrial plants in 17 countries, including the United States, which is where we have our primary customer base.
We expect to continue selling a significant portion of our coal under supply agreements with terms of one year or longer. Our approach is to selectively renew, or enter into new, coal supply contracts when we can do so at prices we believe are favorable. We continue to supply coal to Peabody under contracts that existed at the date of spin-off and certain of these contracts have terms into 2012. As of December 31, 2008, approximately 25% and 16% of our projected 2009 and 2010 total production, respectively, was committed under pre-existing customer relationships with various Peabody subsidiaries. As of December 31, 2008, we had approximately 14% and 6% of our projected metallurgical coal production in 2009 and 2010, respectively, committed under these contracts with Peabody.
Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices, while we seek stable sources of revenue to support the investments required to open, expand and maintain or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure, and termination and assignment provisions.
Each contract sets a base price. Some contracts provide for a predetermined adjustment to base price at times specified in the agreement. Base prices may also be adjusted quarterly, annually or at other periodic intervals for changes in production costs and/or changes due to inflation or deflation. Changes in production costs may be measured by defined formulas that may include actual cost experience at the mine as part of the formula. The inflation/deflation adjustments are measured by public indices, the most common of which is the implicit price deflator for the gross domestic product as published by the U.S. Department of Commerce. In most cases, the components of the base price represented by taxes, fees and royalties which are based on a percentage of the selling price are also adjusted for any changes in the base price and passed through to the customer.
Most long-term contracts contain provisions to adjust the base price due to new statutes, ordinances or regulations that impact our cost of performance. Additionally, some contracts contain provisions that allow for the recovery of costs impacted by modifications or changes in the interpretation or application of existing statutes or regulations. Some agreements provide that if the parties fail to agree on a price adjustment caused by cost increases due to changes in applicable laws and regulations, either party may terminate the agreement.
Price reopener provisions are present in some of our multi-year coal contracts. These provisions may allow either party to commence a renegotiation of the contract price at various intervals. In a limited number of agreements, if the parties do not agree on a new price, the purchaser or seller has an option to terminate the contract. Under some contracts, we have the right to match lower prices offered to our customers by other suppliers.
Quality and volumes for the coal are stipulated in coal supply agreements, and in some limited instances buyers have the option to vary annual or monthly volumes if necessary. Variations to the quality and volumes of coal may lead to adjustments in the contract price. Most coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content (Btu), sulfur and ash content,
grindability and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Coal supply agreements typically stipulate procedures for quality control, sampling and weighing.
Contract provisions in some cases set out mechanisms for temporary reductions or delays in coal volumes in the case of a force majeure event, including strikes, adverse mining conditions, labor shortages, permitting or serious transportation problems that affect the seller or unanticipated plant outages that may affect the buyer. More recent contracts stipulate that this tonnage can be made up by mutual agreement. Buyers often negotiate similar clauses covering changes in environmental laws. We often negotiate the right to supply coal that complies with a new environmental requirement to avoid contract termination. Coal supply agreements typically contain termination clauses if either party fails to comply with the terms and conditions of the contract, although most termination provisions provide the opportunity to cure defaults.
In some of our contracts, we have a right of substitution, allowing us to provide coal from different mines, including third-party production, as long as the replacement coal meets the contracted quality specifications and will be sold at the same delivered cost.
Sales and Marketing
We sell coal produced by our operations and third-party producers. Our sales and marketing group includes personnel dedicated to performing sales functions, market research, contract administration, credit/risk management activities and transportation and distribution functions.
Transportation
Coal consumed domestically is typically sold at the mine, and transportation costs are borne by the purchaser. At certain locations, we utilize truck, conveyor belt and rail to transport coal from our mines to river docks for barge transportation. Export coal is usually sold at the loading port, with purchasers paying ocean freight. Producers usually pay shipping costs from the mine to the port, trans-loading fees at the port and any applicable vessel demurrage costs associated with delayed loadings.
Of our 28.5 million tons sold in 2008, we shipped approximately 56% by rail, 41% by barge and 3% by truck. Our transportation staff manages the loading of coal via these transportation modes.
Suppliers
The main types of goods we purchase are mining equipment and replacement parts, steel-related (including roof control) products, belting products, lubricants, fuel and tires. Although we have many long, well-established relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers other than for purchases of certain underground mining equipment. The supplier base providing mining materials has been relatively consistent in recent years, although there has been some consolidation. Purchases of certain underground mining equipment are concentrated with one principle supplier; however, supplier competition continues to develop.
Technical Innovation
We continue to place great emphasis on the application of technical innovation to improve new and existing equipment performance, which leads to enhanced productivity, safety improvements and cost control measures. This research and development effort is typically undertaken and funded by equipment manufacturers using our input and expertise. Our engineering, maintenance and purchasing personnel work together with manufacturers to design and produce equipment that we believe will add value to our operations.
We have successfully implemented this strategy in the past through a number of key initiatives. For example, we were the first company to introduce underground diesel equipment in West Virginia. We also were instrumental in developing state-of-the-art continuous coal haulage equipment, now in use at one of our western Kentucky complexes. We operate two longwall systems which mine certain of our larger, contiguous reserves. In addition, we operate coal preparation plants capable of producing a wide range of products to meet specific customer demands.
Maintenance standards based on condition-based maintenance practices are being implemented at all operations. Using these techniques allows us to increase equipment utilization and reduce capital spending by extending the equipment life, while minimizing the risk of premature failures. Benefits from lubrication analysis and quality-control include lower lubrication consumption, optimum equipment performance and extended component life.
We use advanced coal quality analyzers to allow continuous analysis of certain coal quality parameters, such as sulfur content. Their use helps ensure consistent product quality and helps customers meet stringent air emission requirements.
Competition
The United States coal industry is highly competitive, both within each region and on a national basis. Coal production in Appalachia and the Illinois Basin totaled approximately 480 million tons in 2008, with the largest five producers (Alpha Natural Resources, Inc., CONSOL Energy, Inc., Massey Energy Company, Patriot and Peabody) accounting for 40% of production. In addition to competition within the eastern U.S. region, coal is transported into the region from the western United States and international producers for purchase by utility customers.
A number of factors beyond our control affect the markets in which we sell our coal. Continued demand for our coal and the prices obtained by us depend primarily on the coal consumption patterns of the electricity and steel industries in the United States and elsewhere around the world; the availability, location, cost of transportation and price of competing coal; and other electricity generation and fuel supply sources such as natural gas, oil, nuclear and hydroelectric. Coal consumption patterns are affected primarily by the demand for electricity, environmental and other governmental regulations, and technological developments. The most important factors on which we compete are delivered price (i.e., including transportation costs, which are paid by our customers), coal quality characteristics and reliability of supply.
Employees & Labor Relations
Relations with our employees and, where applicable, organized labor, are important to our success. As of December 31, 2008, we had approximately 4,300 employees. Approximately 47% of our employees at our company operations were represented by an organized labor union and these operations generated approximately 41% of our 2008 sales volume. Union labor is represented by the United Mine Workers of America (UMWA) under labor agreements which expire December 31, 2011. Our represented employees are in Appalachia and at the Illinois Basin Highland complex.
We operate a training center in Appalachia. Our training center educates our workforce, particularly our most recent hires, in our rigorous safety standards, the latest in mining techniques and equipment, and serves as a center for dissemination of mining best practices across all of our operations. Our training efforts are designed with the intent of attracting new miners, in large part to replace miners expected to retire in the next few years, and to develop and retain a productive and safety-oriented workforce.
Certain Liabilities
We have significant long-term liabilities for reclamation (also called asset retirement obligations), work-related injuries and illnesses, and retiree healthcare. In addition, labor contracts with the UMWA and voluntary arrangements with non-union employees include long-term benefits, notably healthcare coverage for retired employees and future retirees and their dependents.
Asset Retirement Obligations
Asset retirement obligations primarily represent the present value of future anticipated costs to restore surface lands to levels equal to or greater than pre-mining conditions, as required by the Surface Mining Control and Reclamation Act of 1977 (SMCRA). Asset retirement obligation expense (which includes liability accretion and asset amortization) for the years ended December 31, 2008, 2007 and 2006 was $19.3 million, $20.1 million, and $24.3 million, respectively. As of December 31, 2008, our asset retirement obligations of $224.2 million included
$171.8 million related to locations with active mining operations and $52.4 million related to locations that are closed or inactive.
Workers’ Compensation
These liabilities represent the estimates for compensable, work-related injuries (traumatic claims) and occupational disease, principally black lung disease (pneumoconiosis) based primarily on actuarial valuations. The Federal Black Lung Benefits Act requires employers to pay black lung awards to former employees who filed claims after June 1973. These liabilities were $216.4 million as of December 31, 2008, $28.2 million of which was a current liability. Expense for the years ended December 31, 2008, 2007 and 2006 was $25.1 million, $28.0 million and $32.4 million, respectively.
Retiree Healthcare
Retiree healthcare obligations primarily represent the estimated cost of providing retiree healthcare benefits to current retirees and active employees who will retire in the future. Provisions for active employees represent the amount recognized to date, based on their service to date. Additional amounts are accrued periodically so that the total estimated liability is accrued when the employee retires.
Our retiree healthcare liabilities were $1.1 billion as of December 31, 2008, of which $61.7 million was a current liability. Expense for the years ended December 31, 2008, 2007 and 2006 was $66.0 million, $99.9 million and $87.3 million, respectively.
In connection with the spin-off, a subsidiary of Peabody assumed certain of our pre-spin-off obligations associated with the Coal Industry Retiree Health Benefits Act of 1992 (the Coal Act), the 2007 National Bituminous Coal Wage agreement (2007 NBCWA) and certain salaried employee retiree healthcare benefits, assuming the liability at spin-off, totaling $597.6 million at December 31, 2008. We will continue to administer these benefits and certain Patriot subsidiaries will remain jointly and severally liable for the Coal Act obligations, and remain secondarily liable for the 2007 NBCWA obligations and the salaried employee obligations.
The Coal Act provides for the funding of health benefits for certain UMWA retirees. The Coal Act established the United Mine Workers of America Combined Fund (Combined Fund) into which “signatory operators” and “related persons” are obligated to pay annual premiums for beneficiaries. This multi-employer fund provides healthcare benefits to a closed group of our retired former employees who last worked prior to 1976, as well as orphaned beneficiaries of bankrupt companies who were receiving benefits as orphans prior to the 1992 law. No new retirees will be added to this group. The liability is subject to increases or decreases in per capita healthcare costs, offset by the mortality curve in this aging population of beneficiaries. The Coal Act also created a second benefit fund, the 1992 Benefit Plan, for miners who retired between July 21, 1992, and September 30, 1994, and whose former employers are no longer in business. Beneficiaries may continue to be added to this fund as employers default in providing their former employees with retiree medical benefits, but the overall exposure for new beneficiaries into this fund is limited to retirees covered under their employer’s plan who retired prior to October 1, 1994. A third fund, the 1993 Benefit Plan, was established through collective bargaining and provides benefits to qualifying former employees (who retired after September 30, 1994) of certain signatory companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries may continue to be added to this fund as employers go out of business. The collective bargaining agreement with the UMWA, which specifies the payments to be made to the 1993 Benefit Plan, expires on December 31, 2011.
In December 2006, the Surface Mining Control and Reclamation Act Amendments of 2006 (2006 Act) was enacted. Prior to the enactment of this new law, federal statutes required certain of our subsidiaries to make contributions to the Combined Fund and the 1992 Benefit Plan for costs of “orphans” who are retirees and their dependents of bankrupt companies that defaulted in providing their healthcare benefits. Under the 2006 Act, these orphan benefits will be the responsibility of the federal government on a phased-in basis. The legislation authorizes $490 million per year in general fund revenues to pay for these and other benefits under the bill. In addition, future interest from the federal Abandoned Mine Land (AML) trust fund and previous unused interest from the AML trust fund will be available to offset orphan retiree healthcare costs. Under current projections from the health funds, these available resources are sufficient to cover all anticipated costs of orphan retirees. These amounts are also in addition to
any amounts that may be appropriated by Congress at its discretion. The legislation also reduces AML fees currently paid by us on coal production. Beginning in October 2007, those fees were reduced by ten percent from 2007 levels for five years, and then 20% from 2007 levels for ten years, at which point the authority to collect fees will expire.
The 2006 Act specifically amended the federal laws establishing the Combined Fund, the 1992 Benefit Plan and the 1993 Benefit Plan. The 2006 Act provides new and additional funding to all three programs, subject to the limitations described below. The 2006 Act guarantees full funding of all beneficiaries in the Combined Fund by supplementing the annual transfers of interest earned on the AML trust fund. The 2006 Act further provides funding for the annual orphan health costs under the 1992 Benefit Plan on a phased-in basis: 25%, 50% and 75% in the years 2008, 2009 and 2010, respectively. Thereafter, federal funding will pay for 100% of the orphan health costs. The coal producers that signed the 1988 labor agreement, including some of our subsidiaries, remain responsible for the costs of the 1992 Benefit Plan. The 2006 Act also included the 1993 Benefit Plan as one of the statutory funds and authorizes the trustees of the 1993 Benefit Plan to determine the contribution rates through 2010 for pre-2007 beneficiaries. During calendar years 2008 through 2010, federal funding will pay a portion of the 1993 Benefit Plan’s annual health costs on a phased-in basis: 25%, 50% and 75% in the years 2008, 2009 and 2010, respectively. The 1993 Benefit Plan trustees have set a $1.44 per hour statutory contribution rate for 2009. Under the 2006 Act, these new and additional federal expenditures to the Combined Fund, 1992 Benefit Plan, 1993 Benefit Plan and certain Abandoned Mine Land payments to the states and Indian tribes are collectively limited by an aggregate annual cap of $490 million as described above. To the extent that (i) the annual funding of the programs exceeds this amount (plus the amount of interest from the AML trust fund paid with respect to the Combined Benefit Fund), and (ii) Congress does not allocate additional funds to cover the shortfall, contributing employers and affiliates, including some of our subsidiaries, would be responsible for the additional costs. Those of our subsidiaries that have agreed to the 2007 NBCWA will pay $0.50 per hour worked to the 1993 Benefit Plan to provide benefits for post 2006 beneficiaries. To the extent the $0.50 per hour payment exceeds the amount needed for this purpose, the difference will be credited against the $1.44 per hour statutory payment.
The actuarially-determined liability for these benefit plans was $49.1 million as of December 31, 2008, $6.6 million of which was a current liability. Expenses for the years ended December 31, 2008, 2007 and 2006 were $2.6 million, $2.9 million and $2.5 million, respectively. Cash payments to these funds were $6.1 million, $5.5 million and $8.3 million for 2008, 2007 and 2006, respectively. The benefit plans that qualify as multi-employer plans are expensed as payments are made and no liability was recorded other than amounts due and unpaid. Expense related to these funds was $11.8 million, $15.9 million and $6.9 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Regulatory Matters
Federal and state authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, the protection of the environment, plants and wildlife, the reclamation and restoration of mining properties after mining has been completed, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. We have in the past, and will in the future, be required to incur significant costs to comply with these laws and regulations.
Future legislation and regulations are expected to become increasingly restrictive, and there may be more rigorous enforcement of existing and future laws and regulations. Depending on the development of future laws and regulations, we may experience substantial increases in equipment and operating costs and may experience delays, interruptions or termination of operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines or penalties, the acceleration of cleanup and site restoration costs, the issuance of injunctions to limit or cease operations and the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations.
Mine Safety and Health
Our goal is to achieve excellent mine safety and health performance. We measure our progress in this area primarily through the use of accident frequency rates. We believe that it is our responsibility to our employees to
provide a superior safety and health environment. We seek to implement this goal by: training employees in safe work practices; openly communicating with employees; establishing, following and improving safety standards; involving employees in the establishment of safety standards; and recording, reporting and investigating all accidents, incidents and losses to avoid reoccurrence. We utilize best practices in emergency preparedness, which includes maintaining multiple mine rescue teams. A portion of the annual performance incentives for our mining personnel is tied to their safety record.
Our approach to safety has resulted in a steady decline in incidence numbers and their severity rates. We received three awards from the Kentucky Department of Natural Resources in 2008. The awards were for best safety performance in the western Kentucky region. Our training center educates our employees in safety best practices and reinforces our company-wide belief that productivity and profitability follow when safety is a cornerstone of all of our operations.
Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 (MSHA) significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. Congress enacted The Mine Improvement and New Emergency Response Act of 2006 (The MINER Act) as a result of an increase in fatal accidents primarily at U.S. underground mines in 2006. Among the new requirements, each miner must have at least two, one-hour Self Contained Self Rescue (SCSR) devices for their use in the event of an emergency (each miner had at least one SCSR device prior to The MINER Act) and additional caches of SCSR devices in the escape routes leading to the surface. Our evacuation training programs have been expanded to include more comprehensive training with the SCSR devices and frequent escape drills, as well as mine-wide simulated disaster training. The MINER Act also requires installation of two-way communications systems that allow communication between rescue workers and trapped miners following an accident as mine operators must have the ability to locate each miner’s last known position immediately before and after a disaster occurs. Our underground mines currently track and communicate with miners via existing mine communications telephone systems. We are in the process of installing new wireless tracking and communication devices and providing two mine rescue teams located within one hour of each mine by ground. Rescue chambers are in place at certain of our underground mines and have been ordered for the remaining underground mines. Compliance with the new regulation has and will continue to result in additional expense. Furthermore, Congress has been considering legislation known as the S-MINER Act which may increase our operating costs. The legislation may require certain additional safety measures, including changes in mine seals, ventilation systems and conveyer belts, and may also increase the maximum assessed penalty amounts currently authorized and penalty payment obligations.
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 the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. As a result of fatal accidents in recent years, primarily at underground mines, several states including West Virginia and Kentucky have adopted new safety regulations. In addition, regulatory authorities under MSHA have passed numerous emergency regulations including emergency notification and response plans, increased fines for violations and added mine rescue coverage requirements. While these changes have had a significant effect on our operating costs, our U.S. competitors with underground mines are subject to the same degree of regulation.
Black Lung
In the United States, under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator must pay federal black lung benefits and medical expenses to claimants who are current and former employees and last worked for the operator after July 1, 1973. Coal mine operators must also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Historically, less than 7% of the miners currently seeking federal black lung benefits are awarded these benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for coal from underground mines and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.
Environmental Laws
We are subject to various federal and state environmental laws and regulations that impose significant requirements on our operations. The cost of complying with current and future environmental laws and regulations and our liabilities arising from past or future releases of, or exposure to, hazardous substances, may adversely affect our business, results of operations or financial condition. In addition, environmental laws and regulations particularly relating to air emissions can reduce the demand for coal. Significant public opposition has been raised with respect to the proposed construction of certain new coal-fueled electricity generating plants due to the potential air emissions that would result. Such regulation and opposition could reduce the demand for coal.
Numerous federal and state governmental permits and approvals are required for mining operations. When we apply for these permits or approvals, we may be required to prepare and present to federal or state authorities data pertaining to the effect or impact that a proposed exploration for or production or processing of coal may have on the environment. Compliance with these requirements can be costly and time-consuming and can delay exploration or production operations. A failure to obtain or comply with permits could result in significant fines and penalties and could adversely affect the issuance of other permits for which we may apply.
Certain key environmental issues, laws and regulations facing us are described further below.
Surface Mining Control and Reclamation Act
The Surface Mining Control and Reclamation Act (SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement (OSM), establishes mining, environmental protection and reclamation standards for all aspects of U.S. surface mining as well as many aspects of underground mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from the OSM. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the regulatory authority. States in which we have active mining operations have achieved primary control of enforcement through federal authorization.
SMCRA permit provisions include requirements for 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; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and revegetation.
The U.S. mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mining environmental condition of the permit area. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. Our mine and reclamation plans incorporate the provisions of SMCRA, the state programs and the complementary environmental programs that impact 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, and documents required of the OSM’s Applicant Violator System, including the mining and compliance history of officers, directors and principal stockholders of the applicant.
Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Some SMCRA mine permit applications take over a year to prepare, depending on the size and complexity of the mine and often take six months to two years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including public hearings and through intervention in the courts.
SMCRA stipulates compliance with many other major environmental programs. These programs include the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act (RCRA), the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and employee right-to-know provisions. Besides OSM, other Federal regulatory agencies are involved in monitoring or permitting specific aspects of mining operations. The U.S. Environmental Protection Agency (EPA) is the lead agency for states with no authorized programs under the Clean Water Act, RCRA and CERCLA. The U.S. Army Corps of Engineers regulates activities
affecting navigable waters and the U.S. Bureau of Alcohol, Tobacco and Firearms regulates the use of explosive blasting.
We could face substantial matters that pose a risk to maintaining our existing mining permits or that could hinder our ability to acquire future mining permits. As such, we cannot be sure that we will not experience meaningful delays or other difficulties in obtaining mining permits in the future.
Mine Closure Costs
Various federal and state laws and regulations, including SMCRA, require us to obtain surety bonds or other forms of financial security to secure payment of certain long-term obligations, including mine closure or reclamation costs, federal and state workers’ compensation costs and other miscellaneous obligations. Many of these bonds are renewable on a yearly basis. Surety bond costs have increased in recent years. As of December 31, 2008, we had outstanding surety bonds and total letters of credit of $505.8 million including: $227.7 million for post-mining reclamation; $189.5 million related to workers’ compensation obligations; $49.9 million for retiree health obligations; $13.4 million for coal lease obligations; and $25.3 million for other obligations (including collateral for surety companies and bank guarantees, road maintenance and performance guarantees). Changes in these laws and regulations could require us to obtain additional surety bonds or other forms of financial assurance.
The AML Fund, which is part of SMCRA, requires a fee on all coal produced in the U.S. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay healthcare benefit costs of orphan beneficiaries of the Combined Fund. From October 1, 2007 through September 30, 2012, the fee is $0.315 per ton for surface-mined coal and $0.135 per ton for underground-mined coal. From October 1, 2012 through September 30, 2021, the fee will be $0.28 per ton for surface-mined coal and $0.12 per ton for underground-mined coal.
Clean Air Act
The Clean Air Act and the corresponding state laws that regulate the emissions of materials into the air affect U.S. coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter. The Clean Air Act indirectly affects the coal industry by extensively regulating the air emissions of sulfur dioxide, nitrogen oxide, mercury and other compounds emitted by coal-fueled electricity generating plants, and state or federal regulation may be imposed in the future on the emission of carbon dioxide and possibly other greenhouse gases. In recent years Congress has also considered legislation that would require increased reductions in emissions of sulfur dioxide, nitrogen oxide and mercury. Existing and new legislation may lead to some electricity generating customers switching to other sources of fuel the use of which would result in lower levels of regulated emissions.
Clean Air Act requirements that may directly or indirectly affect our operations include the following:
Acid Rain
Title IV of the Clean Air Act regulates sulfur dioxide emissions by all coal-fueled power plants generating greater than 25 megawatts. The affected electricity generators have sought to meet these requirements by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances. Title IV also requires that certain categories of electric generating stations install certain types of nitrogen oxide controls. At this time, we believe that these requirements may have resulted in upward pressure on the price of lower sulfur coal as compared to higher sulfur coal. We cannot predict the effect of these provisions of the Clean Air Act on us in future years.
Clean Air Interstate Rule (CAIR)
The EPA promulgated CAIR in 2005. CAIR requires the reduction of sulfur dioxide and nitrogen oxide emissions from electricity generating plants in 28 eastern states and the District of Columbia. CAIR has been subject to a complex series of legal challenges since its promulgation which have alleged, among other things, that it
failed to meet the requirements of the Federal Clean Air Act. However, as of December 2008, based on an order issued by the U.S. Court of Appeals for the D.C. Circuit, CAIR is currently in effect while the EPA develops a new clean air program for power plants that is consistent with the Clean Air Act. It is unknown what additional or different obligations the EPA will place on power plant air emissions as it revisits the obligations of the Clean Air Act. However, the existing CAIR obligations are expected to require many coal-fueled power sources to install additional pollution control equipment, such as wet scrubbers, or to incur costs to purchase the right to emit from other sources who do reduce their emissions, and it is possible that further changes in the rules, including those relating to emissions limitations and the right to purchase and trade allowances, will require power plants to incur even more costs. All of the foregoing could cause our customers to reduce their purchase of coal, and particularly of high sulfur coal.
Clean Air Mercury Rule (CAMR)
The EPA also promulgated CAMR in March 2005. CAMR permanently caps and reduces nationwide mercury emissions from coal-fueled power plants. The rule established standards limiting mercury emissions from new and existing coal-fueled power plants and created a model, market-based cap-and-trade program to reduce nationwide utility emissions of mercury in two distinct phases. CAMR was vacated on February 8, 2008 by the U.S. Court of Appeals for the D.C. Circuit. A group of utilities has filed a petition for review by the Supreme Court of the decision vacating CAMR. However, if the existing request for review is denied, the EPA, which withdrew in February 2009 its own earlier request seeking review, will be required to promulgate a new mercury emissions rule. It is anticipated that any new EPA rule will require power plants to implement maximum achievable control technology (MACT) to reduce their mercury emissions. In January 2009, the EPA issued a memorandum stating that any new electric steam generating units that began construction while CAMR was effective will be subject to a MACT determination on a case-by-case basis. These decisions and future regulations could further limit mercury emissions from power plants, which could adversely affect the demand for coal.
Particulate Matter
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for pollutants considered harmful to public health and the environment. States must develop and maintain state implementation plans (SIPs) that explain how they will comply with established NAAQS. These SIPs are subject to public comment and must be approved by the EPA. Areas not in compliance with NAAQS must take steps to reduce emission levels, and as a result states that are affected must update their SIPs accordingly. Our mining operations are subject to NAAQS and the operations of some of our customers are also subject to NAAQS. In addition, the Clean Air Act allows states to assert claims against a source in an “upwind” state if the source, which could include coal-fueled power plants, is emitting pollutants in an amount and manner that the downwind state believes is preventing it from attaining its NAAQS.
In October 2006, the EPA issued a final rule revising and updating NAAQS for various forms of particulate matter (PM) (the “PM Standards”). Specifically, the PM Standards were updated for fine PM and coarse PM. Sources of fine PM include power generation, residential fuel burning, and motor vehicles. Coarse PM can be generated by, among other things, mining operations and construction and demolition activities. Three groups of petitioners filed for review of the 2006 PM Standards. On February 24, 2009, the U.S. Court of Appeals for the D.C. Circuit issued its opinion, and while it refused to review the petitioners’ challenges to the coarse PM standards, it remanded certain aspects of the fine PM standards for reconsideration by the EPA. As a result, the PM Standards related to fine PM, which may affect many of our power plant customers and are currently in effect, will now be subject to further review by the EPA, and therefore these PM Standards could become more stringent. If that occurs, some states will likely need to change their existing SIPs to impose measures designed to ensure compliance with any new PM Standards.
Existing and possible future restrictions, including any that arise out of the EPA’s reconsideration described above, on the emission of fine or coarse PM could adversely affect our ability to develop new mines, could require us to modify our existing operations and could result in additional and expensive control requirements for coal-fueled power plants, which could adversely affect the demand for coal.
Ozone
Nitrogen oxides, which are a by-product of coal combustion, can lead to the creation of ozone. In March 2008, the EPA issued a rule in which it lowered the eight-hour ozone standard from the current 0.0884 parts per million to 0.075 parts per million. The rule became effective on May 27, 2008. Attainment dates for the new standards range between 2013 and 2030, depending on the severity of the non-attainment. The revised standard may require more stringent emissions controls on sources of nitrogen oxides, including coal-fueled electric generating plants. Demand for coal from our mining operations may be adversely affected when the more stringent standard is implemented.
New Source Review Regulations
A number of pending regulatory changes and court actions will affect the scope of the EPA’s new source review (NSR) program, which under certain circumstances requires existing coal-fueled power plants to install the more stringent air emissions control equipment required of new plants. For example, in April 2007, the U.S. Supreme Court ruled, in Environmental Defense et al. v. Duke Energy Corp. et al., against a generator in an NSR enforcement proceeding, reversing the decision of the appellate court. This decision could potentially expose numerous electricity generators to government or citizen actions based on a failure to obtain NSR permits for changes to emissions sources and could effectively increase the costs to them of continuing to use coal. Our customers are among the electricity generators subject to enforcement actions and, if found not to be in compliance, our customers could be required to install additional control equipment at the affected plants or they could decide to close some or all of those plants. Changes to the NSR program and/or its enforcement may adversely impact demand for coal. If our customers decide to install additional pollution control equipment at the affected plants, we believe we will have the ability to supply coal from either of the regions in which we operate to meet any new coal requirements.
Regional Haze
The EPA published the final regional haze rule on July 1, 1999. This rule established planning and emissions reduction timelines for states to use to improve visibility in national parks throughout the United States. On June 22, 2001, the EPA signed a proposed rule to guide states in implementing the 1999 rule and in controlling power plant emissions that cause regional haze problems. The proposed rule set guidelines for states in setting Best Alternative Retrofit Technology (BART) at older power plants. On May 5, 2004, the EPA published a proposed rule with new BART provisions and re-proposed the BART guidelines. On June 15, 2005, the EPA finalized amendments to the July 1999 regional haze rule. The EPA determined that states which adopt the CAIR cap-and-trade program for sulfur dioxide and nitrogen oxide will be allowed to apply CAIR controls as a substitute for those required by BART.
Carbon Dioxide Emissions
The U.S. Supreme Court’s April 2007 ruling in Massachusetts v. EPA clarified that the EPA does have the authority to regulate carbon dioxide emissions as a “pollutant” under the Clean Air Act insofar as motor vehicles are concerned. In response to this decision, in July 2008, the EPA issued an Advance Notice of Proposed Rulemaking that sought comments on the framework and direction of EPA’s actions to regulate greenhouse gas emissions from a wide range of facilities, including electric generating facilities. Furthermore, although in December 2008 the EPA issued an interpretive memo declaring that carbon dioxide is not currently subject to regulation under the Clean Air Act’s Prevention of Significant Deterioration (PSD) permit program, in February of 2009 the EPA announced that it plans to reconsider that interpretative memo and will publish a related notice of proposed rulemaking in the near future. If the EPA ultimately determines it should regulate greenhouse gases under the Clean Air Act, as currently anticipated, either through direct regulation of carbon dioxide or through new PSD requirements, it may ultimately affect coal-fueled power plants in particular, and the amount of coal our customers purchase from us could decrease, which could adversely affect our results of operations.
State Laws
Several states have recently proposed or adopted legislation or regulations further limiting emissions of sulfur dioxide, nitrogen oxide, mercury and carbon dioxide. Limitations imposed by states on emissions of any of these
substances could cause our customers to switch to other fuels to the extent it becomes economically preferable for them to do so.
Global Climate Change
One by-product of burning coal is carbon dioxide, which has been linked in certain studies as a contributor to climate change. Legislators are considering the passage of significant new laws, regulators are considering using existing laws to limit greenhouse gas emissions, and other measures are being imposed or offered with the ultimate goal of reducing greenhouse gas emissions. For instance, in addition to the potential for the EPA to impose regulations on carbon dioxide emissions as described above, we also anticipate that Congress will evaluate greenhouse gas legislation in the short-term.
In the absence of federal legislation or regulation, many states, regions and local authorities have adopted greenhouse gas regulations and initiatives. Several northeastern states are part of the Regional Greenhouse Gas Initiative agreement, or RGGI. The RGGI program calls for signatory states to stabilize carbon dioxide emissions to current levels from 2009 to 2015, followed by a 2.5% reduction each year from 2015 to 2018. Auctions for carbon dioxide allowances under the program began in September 2008 and occur on a quarterly basis.
In November 2007, the governors of Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Ohio, South Dakota and Wisconsin and the premier of Manitoba signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions.
In August 2008, Massachusetts also adopted legislation that established a program to reduce greenhouse gas emissions significantly over the next 40 years. After a reporting and verification system for statewide greenhouse gas emissions is established, the Massachusetts Executive Office of Energy and Environmental Affairs (MAEEA) will set statewide greenhouse gas emissions limits effective beginning in 2020 that will reduce such emissions from the 1990 levels by 10% to 25% beginning in 2020, with the reduction increasing to 80% below 1990 levels by 2050. In setting these limits, the MAEEA is to consider the potential costs and benefits of various reduction measures, including emissions limits for electric generating facilities, and may consider the use of market-based compliance mechanisms.
These and other state and regional climate change rules will likely require additional controls on coal-fueled power plants and industrial boilers and may even cause some users of coal to switch from coal to a lower carbon fuel. In addition, some states, municipalities and individuals have initiated common law nuisance suits against oil, coal, electric generating and automobile manufacturing companies, arguing that they have been damaged by the effects of climate change. If successful, there could be reductions in or other limitations on the amount of coal our customers could utilize.
The permitting of new coal-fueled power plants has also recently been contested by state regulators and environmental organizations based on concerns relating to greenhouse gas emissions. As a result, certain power generating companies may reconsider short-term or long-term plans to build coal-fueled plants or may elect to build capacity using alternative forms of electrical generation.
Demand for and use of coal also 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 met in Bali, Indonesia in December 2007 to discuss a program to limit greenhouse gas emissions after 2012. The United States participated in the conference. The convention adopted what is called the “Bali Action Plan.” The Bali Action Plan contains no binding commitments, but concludes that “deep cuts in global emissions will be required” and provides a timetable for two years of talks to shape the first formal addendum to the 1992 United Nations Framework Convention on Climate Change treaty since the Kyoto Protocol. The ultimate outcome of the Bali Action Plan, and any treaty or other arrangement ultimately adopted by the United States or other countries, may have a material adverse impact on the global supply and demand for coal, which in turn could have an adverse impact on our business.
Clean Water Act
The federal Clean Water Act and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the United States. The Clean Water Act provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. Recent court decisions and regulatory actions have created uncertainty over jurisdiction and permitting requirements that could increase the cost and time we expend on compliance with water pollution regulations.
These and other regulatory requirements, which are constantly changing due to legal challenges filed by regulators or other parties and other developments, increase the cost of, or could even prohibit, certain mountaintop removal mining operations. Some of the requirements relate to management of current or future mining operations, others may even go beyond our ordinary course activities.
Our operations may not always be able to remain in full compliance with all Clear Water Act obligations and permit requirements, and as a result we have, at times, been subject to compliance orders and private party litigation seeking fines or penalties or changes to our operations.
Clean Water Act requirements that may directly or indirectly affect our operations include the following:
National Pollutant Discharge Elimination System (NPDES)
The Clean Water Act requires effluent limitations and treatment standards for wastewater discharge through the NPDES program. NPDES permits govern the discharge of pollutants into water and require regular monitoring and reporting and performance standards. States are empowered to develop and enforce “in stream” water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. “In stream” standards vary from state to state. Additionally, through the Clean Water Act Section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.
Total Maximum Daily Load (TMDL) regulations establish a process by which states designate stream segments as impaired (i.e., not meeting present water quality standards). Industrial dischargers, including coal mining operations, may be required to meet new TMDL effluent standards for these stream segments.
States must also conduct an anti-degradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality. A state’s anti-degradation regulations would prohibit the diminution of water quality in these streams. Several environmental groups and individuals recently challenged, in part successfully, West Virginia’s anti-degradation policy. As a result, in general, waters discharged from coal mines to high quality streams in West Virginia will be required to meet or exceed new “high quality” standards. This could cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits, and could adversely affect our coal production.
Section 404
Section 404 of the Clean Water Act requires mining companies to obtain U.S. Army Corps of Engineers (ACOE) permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. As is the case with other coal mining companies operating in Appalachia, our construction and mining activities, including our mountaintop removal mining operations, frequently require Section 404 permits. ACOE issues two types of permits pursuant to Section 404 of the CWA: general (or “nationwide”) and “individual” permits. Nationwide permits are issued to streamline the permitting process for dredging and filling activities that have minimal adverse environmental impacts. An individual permit typically requires a more comprehensive application process, including public notice and comment, but an individual permit can be issued for ten years (and may be extended thereafter upon application).
The issuance of permits to construct valley fills and refuse impoundments under Section 404 of the Clean Water Act , whether individual permits or general permits commonly described as the Nationwide Permit 21, has been the subject of many recent court cases, the results of which may increase our permitting and operating costs, result in permitting delays, suspend current operations or prevent the opening of new mines. In particular, a July 2004 decision by the Southern District of West Virginia enjoined the Huntington District of the ACOE from issuing further permits pursuant to Nationwide Permit 21. While the decision was vacated by the Fourth Circuit Court of Appeals in November 2005, and remanded to the district court for additional proceedings, no final decision has been issued in that case. A similar lawsuit was also filed in federal court in the Eastern District of Kentucky. To date, the judge in the Kentucky case has not rendered any rulings on the merits.
Additionally, individual permits issued pursuant to Section 404 of the Clean Water Act are also subject to court challenge. The Ohio Valley Environmental Coalition (OVEC) and other environmental groups sued the ACOE in the U.S. District Court for the Southern District of West Virginia in 2005, asserting that the ACOE unlawfully issued individual permits to construct mining fills to certain subsidiaries of another coal company. In February 2009, the Fourth Circuit Court of Appeals overturned two decisions of the district court and held that the permits were appropriately issued and that ACOE’s interpretation of the Clean Water Act was correct.
In the event that challenges to Nationwide Permit 21 or individual permits are successful, obtaining required Section 404 permits could become more difficult and expensive, which could in turn have an adverse effect on our revenues and operations.
Resource Conservation and Recovery Act (RCRA)
RCRA established comprehensive requirements for the treatment, storage and disposal of hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous waste materials under RCRA. In 1993 and 2000, the EPA declined to impose hazardous waste regulatory controls under subtitle C of RCRA on the disposal of some coal combustion by-products (CCB), including the practice of using CCB as mine fill. However, under pressure from environmental groups, the EPA has continued evaluating the possibility of placing additional regulatory requirements on the disposal of such materials.
On March 14, 2007, OSM issued an advanced notice of proposed rulemaking seeking comment on the development of rules for the disposal of CCB in active and abandoned mines. OSM’s regulatory step reflects a decision by the EPA to defer to OSM on the rulemaking for coal ash disposal in mines instead of taking regulatory action under RCRA; however, the EPA published in the Federal Register in August 2007 a Notice of Data Availability (NODA) of analyses of the disposal of CCB that have become available since the EPA’s RCRA regulatory determination in 2000. The NODA is not a proposed rule and does not include a timeframe for issuing a proposed rule.
Any regulations that increase the costs associated with handling or disposal of CCB could impact our customers’ operating costs and potentially reduce their purchase of coal.
Federal and State Superfund Statutes
CERCLA and similar state laws impose liability for investigation and clean-up of contaminated properties and for damages to natural resources. Under CERCLA or similar state laws, strict, joint and several liability may be imposed on waste generators, site owners or operators and others regardless of fault. Thus, coal mines or other sites that we currently own or have previously owned or operated and sites to which we have sent waste material may be subject to liability under CERCLA and similar state laws. We have been identified as a potentially responsible party at some sites, but based on current information we do not believe any liability under CERCLA or similar state laws will be material.
Toxic Release Reporting
Under the EPA’s Toxic Release Inventory process, companies are required to annually report the use, manufacture or processing of listed toxic materials that exceed defined thresholds, including chemicals used in
equipment maintenance, reclamation, water treatment and ash received for mine placement from power generation customers.
Additional Information
We file annual, quarterly and current reports, and our amendments to those reports, proxy statements and other information with the Securities and Exchange Commission (SEC). You may access and read our SEC filings free of charge through our website, at www.patriotcoal.com, or the SEC’s website, at www.sec.gov. You may 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, free of charge, by telephone at (314) 275-3680 or by mail at: Patriot Coal Corporation, 12312 Olive Boulevard, St. Louis, Missouri 63141, attention: Investor Relations.
Item 1A.
Item 1A.
Risk Factors.
RISK FACTORS
You should carefully consider the risks described below, together with all of the other information included in this report, in evaluating our company and our common stock. If any of the risks described below actually occurs, our business, financial results, financial condition and stock price could be materially adversely affected.
Risk Factors Relating to Our Business
Our operations are subject to geologic, equipment and operational risks, including events beyond our control, which could result in higher operating expenses and/or decreased production and sales and adversely affect our operating results.
Our coal mining operations are conducted in underground and surface mines. The level of our 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 at particular mines for varying lengths of time and have a significant impact on our operating results. Adverse operating conditions and events that coal producers have experienced in the past include changes or variations in geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit; mining and processing equipment failures and unexpected maintenance problems; adverse weather and natural disasters, such as snowstorms, ice storms, heavy rains and flooding; accidental mine water inflows and unexpected mine safety accidents, including fires and explosions from methane and other sources.
Our Federal mine experienced two roof falls during the first quarter of 2008 and experienced hard cutting and soft floor conditions in the second half of 2008, leading to reduced productivity. Also in the second half of 2008, our Panther mine experienced sandstone intrusions that led to hard cutting conditions. The decrease in production caused by each of these events resulted in us invoking the force majeure provisions of several coal sales contracts, requiring us to make up lost tonnages in certain instances during 2009.
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, delay or halt production at particular mines, or negatively impact sales to our customers either permanently or for varying lengths of time, which could adversely affect our results of operations, cash flows and financial condition. We cannot assure you that these risks would be fully covered by our insurance policies.
In addition, the geological characteristics of underground coal reserves in Appalachia and the Illinois Basin, such as rock intrusions, overmining, undermining and coal seam thickness, make these coal reserves complex and costly to mine. As mines become depleted, replacement reserves may not be mineable at costs comparable to those characteristic of the depleting mines. These factors could materially and adversely affect the mining operations and the cost structures of, and customers’ willingness to purchase coal produced by, our mines.
A decline in coal prices could reduce our revenues and the value of our coal reserves.
Our results of operations are dependent upon the prices we charge for our coal as well as our ability to maximize productivity and control costs. 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 fund our existing operations and obligations, improve our productivity and reinvest in our business. The prices we receive for coal depend upon numerous factors beyond our control, including coal and power market conditions, weather patterns affecting energy demand, competition in our industry, availability and costs of competing energy resources, worldwide economic and political conditions, economic strength and political stability in the U.S. and countries in which we have customers, the outcome of commercial negotiations involving sales contracts or other transactions, customer performance and credit risk, availability and costs of transportation, our ability to respond to changing customer preferences, reductions of purchases by major customers, and legislative and regulatory developments, including new environmental regulations affecting the use of coal, such as mercury and carbon dioxide-related limitations. Any material decrease in demand would cause coal prices to decline and require us to decrease costs in order to maintain our margins.
The recent downturn in the domestic and international financial markets, and the risk of prolonged global recessionary conditions, could adversely affect our financial condition and results of operations.
Because we sell substantially all of our coal to electric utilities and steel mills, our business and results of operations remain closely linked to global demand for electricity and steel production. The recent downturn in the domestic and international financial markets has created economic uncertainty and raised the risk of prolonged global recessionary conditions. Historically, global demand for basic inputs, including electricity and steel production, has decreased during periods of economic downturn. If the recent downturn in the domestic and international financial markets, or the onset of global recessionary conditions, decreases global demand for electricity and steel production, our financial condition and results of operations could be adversely affected.
Our operations may depend on the availability of additional financing and access to funds under our credit facility.
We expect to have sufficient liquidity to support the development of our business. In the future, however, we may require additional financing for liquidity, capital requirements and growth initiatives. We are dependent on our ability to generate cash flows from operations and to borrow funds and issue securities in the capital markets to maintain and expand our business. We may need to incur debt on terms and at interest rates that may not be as favorable as they were in the past.
Our current credit facility is comprised of a group of lenders, each of which has severally agreed to make loans to us under the facility. Currently each of these lenders has met their individual obligation; however, based on the recent instability related to financial institutions we can make no assurances that all future obligations will be met. A failure by one or more of the participants to meet its obligation in the future could have a materially adverse impact on our liquidity, results of operations and financial condition.
The credit markets have been experiencing extreme volatility and disruption for more than 12 months. The market for new debt financing is extremely limited and in some cases not available at all. Any inability by us to obtain financing in the future on favorable terms could have a negative effect on our results of operations, cash flows and financial condition.
As our coal supply agreements expire, our revenues and operating profits could be negatively impacted if we are unable to extend existing agreements or enter new long-term supply agreements due to competition, changing coal purchasing patterns or other variables.
As our coal supply agreements expire, we will compete with other coal suppliers to obtain business. If we cannot renew these coal supply agreements with our customers or find alternate customers willing to purchase our coal at market prices, our revenue and operating profits could suffer. We continue to supply coal to Peabody under contracts that existed at the date of spin-off. Contracts with Peabody to purchase coal sourced from our operations accounted for 43% of our combined revenues for 2008, compared to 96% of our revenue in 2007.
Our customers may decide not to extend existing agreements or enter into new long-term contracts or, in the absence of long-term contracts, may decide to purchase fewer tons of coal than in the past or on different terms, including under different pricing terms. The recent global recession has resulted in decreased demand worldwide for steel and electricity. This decrease in demand may cause our customers to delay negotiations for new contracts and request lower pricing terms. Furthermore, uncertainty caused by laws and regulations affecting electric utilities could deter our customers from entering into long-term coal supply agreements. Some long-term contracts contain provisions for termination due to environmental changes if these changes prohibit utilities from burning the contracted coal. To the degree that we operate outside of long-term contracts, our revenues are subject to pricing in the spot market that can be significantly more volatile than the pricing structure negotiated through a long-term coal supply agreement. This volatility could adversely affect the profitability of our operations if spot market pricing for coal becomes unfavorable.
In a limited number of contracts, failure of the parties to agree on price adjustments may allow either party to terminate the contract. Coal supply agreements typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as heat value, sulfur content, ash content, chlorine content, hardness and ash fusion temperature in the case of thermal coal. Failure to meet these specifications could result in economic penalties, including price adjustments, purchasing replacement coal in a higher priced open market, the rejection of deliveries or termination of the contracts.
Many agreements also contain provisions that permit the parties to adjust the contract price upward or downward for specific events, including inflation or deflation, changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the law regulating the timing, production, sale or use of coal. Moreover, some of these agreements permit the customer to terminate the contract if transportation costs, which are typically borne by the customer, increase substantially or in the event of changes in regulations affecting the coal industry, that increase the price of coal beyond specified amounts.
Any change in coal consumption patterns, in particular by United States electric power generators or steel producers, could result in a decrease in the use of coal by those consumers, which could result in lower prices for our coal, a reduction in our revenues and an adverse impact on our earnings and the value of our coal reserves.
Thermal coal accounted for approximately 79%, 77% and 77% of our coal sales volume during 2008, 2007 and 2006, respectively. The majority of our sales of thermal coal was to U.S. electric power generators. The amount of coal consumed for U.S. 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 wind and hydroelectric power; technological developments; limitations on financings for coal-fueled power plants and governmental regulations, including increasing difficulties in obtaining permits for coal-fueled power plants and more burdensome restrictions in the permits received for such facilities. In addition, the increasingly stringent requirements of the Clean Air Act or other laws and regulations, including tax credits that have been or may be provided for alternative energy sources and renewable energy mandates that have been or may be imposed on utilities, may result in more electric power generators shifting away from coal-fueled generation, the closure of existing coal-fueled plants and the building of more non-coal power electrical generating sources in the future. All of the foregoing could reduce demand for our coal, which could reduce our revenues, earnings and the value of our coal reserves.
Weather patterns can greatly affect electricity generation. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increased generating requirements from all sources. Mild temperatures, on the other hand, result in lower electrical demand, which allows generators to choose the lowest-cost sources of power generation when deciding which sources to utilize. Accordingly, significant changes in weather patterns could reduce the demand for our coal.
Overall economic activity and the associated demands for power by industrial users can also have significant effects on overall electricity demand. Deterioration in U.S. electric power demand would reduce the demand for our thermal coal and could impact the collectability of our accounts receivable from electric utility customers.
Metallurgical coal accounted for approximately 21%, 23% and 23% of our coal sales volume during 2008, 2007 and 2006, respectively. A significant portion of our sales of metallurgical coal was to the U.S. steel industry. The majority of our metallurgical coal production is priced annually, and as a result, a decrease in near term metallurgical coal prices could decrease our profitability. The recent global recession has resulted in decreased demand worldwide for steel and electricity. Deterioration in global steel production reduces the demand for our metallurgical coal and resulted in customer deferrals and cancellations of deliveries in the fourth quarter of 2008. In addition, the steel industry increasingly relies on electric arc furnaces or pulverized coal processes to make steel. These processes do not use furnace coke, an intermediate product produced from metallurgical coal. Therefore, growth in future steel production may not represent increased demand for metallurgical coal. If the demand or pricing for metallurgical coal decreases in the future, the amount of metallurgical coal we sell and prices that we receive for it could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.
Because we sell substantially all of our coal to electric utilities and steel producers, our business and results of operations are closely linked to the global demand for electricity and steel production. Historically, global demand for basic inputs, including for electricity and steel production, has decreased during periods of economic downturn. The recent recession has created economic uncertainty, and electric utilities and steel producers have responded by decreasing production.
If the recent global recession results in sustained decreases in the global demand for electricity and steel production, our financial condition, results of operations and cash flows could be materially and adversely affected. Any downward pressure on coal prices, whether due to increased use of alternative energy sources, changes in weather patterns, decreases in overall demand or otherwise, would likely reduce our revenues and adversely impact our earnings and the value of our coal reserves.
Failures of contractor-operated sources to fulfill the delivery terms of their contracts with us could reduce our profitability.
Within our normal mining operations, we utilize third party sources for some coal production, including contract miners, to fulfill deliveries under our coal supply agreements. Approximately 13% of our total sales volume for 2008 was attributable to contractor-operated mines. Certain of our contractor-operated mines have experienced adverse geologic conditions, escalated operating costs and/or financial difficulties that have made their delivery of coal to us at the contracted price difficult or uncertain and, in many instances, these costs have been passed along to us. Our profitability or exposure to loss on transactions or relationships such as these is dependent upon a variety of factors, including the availability and reliability of the third-party supply; the price and financial viability of the third-party supply; our obligation to supply coal to our customers in the event that adverse geologic conditions restrict deliveries from our suppliers; our willingness to reimburse temporary cost increases experienced by third-party coal suppliers; our ability to pass on temporary cost increases to customers; our ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market; and other factors.
A shortage of skilled labor and qualified managers in our operating regions could pose a risk to labor productivity and competitive costs and could adversely affect our profitability.
Efficient coal mining using modern techniques and equipment requires skilled laborers with mining experience and proficiency as well as qualified managers and supervisors. In recent years, a shortage of experienced coal miners and managers in Appalachia and the Illinois Basin has at times negatively impacted our production levels and increased our costs. A shortage of experienced labor could have an adverse impact on our 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.
A decrease in the availability or increase in costs of key supplies, capital equipment or commodities used in our mining operations could decrease our profitability.
Our purchases of some items of underground mining equipment are concentrated with one principal supplier. Further, our coal mining operations use significant amounts of steel, diesel fuel, explosives and tires. The price of each of these materials and supplies rose significantly in the first half of 2008, but prices declined by the end of 2008. Steel is used in roof control for roof bolts that are required by the room-and-pillar method of mining. If the
cost of any of these inputs increases significantly, or if a source for such mining equipment or supplies was unavailable to meet our replacement demands, our profitability could be reduced.
Increased competition both within the coal industry, and outside of it, such as competition from alternative fuel providers, may adversely affect our ability to sell coal, and any excess production capacity in the industry could put downward pressure on coal prices.
The coal industry is intensely competitive both within the industry and with respect to other fuels. The most important factors with which we compete are price, coal quality and characteristics, transportation costs from the mine to the customer and reliability of supply. Our principal competitors include Alliance Resource Partners, L.P., Alpha Natural Resources, Inc., Arch Coal, Inc., CONSOL Energy, Inc., Foundation Coal Holdings, Inc., International Coal Group, Inc., James River Coal Company, Massey Energy Company and Peabody Energy Corporation. We also compete directly with all other Central Appalachian coal producers, as well as producers from other basins including Northern and Southern Appalachia, the Western United States and the Interior United States, and foreign countries, including Colombia, Venezuela, Australia and Indonesia.
Depending on the strength of the U.S. dollar relative to currencies of other coal-producing countries, coal from such origins could enjoy cost advantages that we do not have. Several domestic coal-producing regions have lower-cost production than Central Appalachia, including the Powder River Basin in Wyoming. Coal with lower delivered production costs shipped east from western coal mines and from offshore sources can result in increased competition for coal sales in regions historically sourced from Appalachian producers.
During the mid-1970s and early 1980s, a growing coal market and increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in production capacity in excess of market demand throughout the industry. We could experience decreased profitability if future coal production is consistently greater than coal demand. Increases in coal prices could encourage the development of expanded coal producing capacity in the United States and abroad. Any resulting overcapacity from existing or new competitors could reduce coal prices and, therefore, our revenue.
We also face competition from renewable energy providers, like wind and solar, and other alternative fuel sources, like natural gas. At the end of 2008, increases in natural gas production and decreases in industrial demand for natural gas caused natural gas prices to decrease and negatively affected U.S. thermal coal prices. Should renewable energy sources become more competitively priced, which may be more likely to occur given the federal tax incentives for alternative fuel sources that are already in place and that may be expanded in the future, or sought after as an energy substitute for fossil fuels, the demand for such fuels may adversely impact the demand for coal.
We could be negatively affected if we fail to maintain satisfactory labor relations.
As of December 31, 2008, Patriot had approximately 4,300 employees. Approximately 47% of the employees at company operations were represented by an organized labor union and they generated approximately 41% of the 2008 sales volume. Relations with our employees and, where applicable organized labor, are important to our success. Union labor is represented by the UMWA under labor agreements which expire December 31, 2011. Our represented workers are in Appalachia and at the Illinois Basin Highland complex.
Due to the increased risk of strikes and other work-related stoppages that may be associated with union operations in the coal industry, our competitors who operate without union labor may have a competitive advantage in areas where they compete with our unionized operations. If some or all of our current non-union operations or those of third party contract miners were to become organized, we could incur an increased risk of work stoppages.
Our future success depends upon our ability to develop our existing coal reserves and to acquire additional reserves that are economically recoverable.
Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our proven and probable coal reserves that are economically recoverable. Furthermore, we may not be able to mine all of our proven and probable coal reserves as profitably as we do at our current operations. Our future success depends upon our conducting successful exploration and development activities and acquiring properties containing economically recoverable proven and probable coal
reserves. Our current strategy includes using our existing properties and increasing our proven and probable coal reserves through acquisitions of leases and producing properties.
Our planned mine development projects and acquisition activities may not result in significant additional proven and probable coal reserves and we may not have continuing success developing additional mines. A substantial portion of our proven and probable coal reserves is not located adjacent to current operations and will require significant capital expenditures to develop. In order to develop our proven and probable coal reserves, we must receive various governmental permits. We make no assurances that we will be able to obtain the governmental permits that we would need to continue developing our proven and probable coal reserves.
Our mining operations are conducted on properties owned or leased by us. We may not be able to negotiate new leases from private parties or obtain mining contracts for properties containing additional proven and probable coal reserves or maintain our leasehold interest in properties on which mining operations are not commenced during the term of the lease.
Fluctuations in transportation costs, the availability or reliability of transportation facilities and our dependence on a single rail carrier for transport from certain of our mining complexes could affect the demand for our coal or temporarily impair our ability to supply coal to our customers.
Coal producers depend upon rail, barge, truck, overland conveyor, ocean-going vessels and port facilities to deliver coal to customers. While our coal customers typically arrange and pay for transportation of coal from the mine or port to the point of use, disruption of these transportation services because of weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, transportation delays, lack of port capacity or other events could temporarily impair our ability to supply coal to customers and thus could adversely affect our results of operations, cash flows and financial condition.
Transportation costs represent a significant portion of the total cost of coal for our customers, and the cost of transportation is an important factor in a customer’s purchasing decision. Increases in transportation costs, including increases resulting from emission control requirements and fluctuations in the price of diesel fuel and demurrage, could make coal a less competitive source of energy when compared to alternative fuels such as natural gas, or could make Appalachian or Illinois Basin coal production less competitive than coal produced in other regions of the United States or abroad. One of our coal supply agreements, which accounts for less than 10% of 2008 tons sold, permits the customer to terminate such agreement if the barge transportation rates applicable to our shipments increase by more than a specified amount and we do not agree to reduce our selling price by the excess over such amount.
Significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country and from abroad. Coordination of the many eastern loading facilities, the large number of small shipments, terrain and labor issues all combine to make shipments originating in the Eastern United States inherently more expensive on a per ton-mile basis than shipments originating in the Western United States. Historically, high coal transportation rates from the western coal producing areas into Central Appalachian markets limited the use of western coal in those markets. However, a decrease in rail rates from the western coal producing areas to markets served by eastern U.S. producers could create major competitive challenges for eastern producers. Increased competition due to changing transportation costs could have an adverse effect on our business, financial condition and results of operations.
Coal produced at certain of our mining complexes is transported to its customers by a single rail carrier. If there are significant disruptions in the rail services provided by that carrier or if the rail rates rise significantly, then costs of transportation for our coal could increase substantially. Additionally, if there are disruptions of the transportation services provided by the railroad and we are unable to find alternative transportation providers to ship our coal, our business and profitability could be adversely affected.
Failure to obtain or renew surety bonds in a timely manner and on acceptable terms could affect our ability to secure reclamation and employee-related obligations, which could adversely affect our ability to mine coal.
U.S. federal and state laws require us to secure certain of our obligations relating to reclaiming lands used for mining, paying federal and state workers’ compensation, and satisfying other miscellaneous obligations. The
primary method for us to meet those obligations is to provide a third-party surety bond or letters of credit. As of December 31, 2008, we had outstanding surety bonds and letters of credit aggregating $505.8 million, of which $227.7 million was for post-mining reclamation, $189.5 million related to workers’ compensation obligations, $49.9 million was for retiree health obligations, $13.4 million was for coal lease obligations and $25.3 million was for other obligations (including collateral for surety companies and bank guarantees, road maintenance and performance guarantees). These bonds are typically renewable on an annual basis and the letters of credit are available through our credit facility.
The current economic recession and volatility and disruption in the credit markets could result in surety bond issuers deciding not to continue to renew the bonds or to demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds or to provide a suitable alternative would have a material adverse effect on us. That failure could result from a variety of factors including lack of availability, higher expense or unfavorable market terms of new surety bonds, restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our credit facility and the exercise by third-party surety bond issuers of their right to refuse to renew the surety.
If our business does not generate sufficient cash for operations, we may not be able to repay borrowings under our credit facility or fund other liquidity needs, and the amount of our indebtedness could affect our ability to grow and compete.
Our ability to pay principal and interest on our debt and to refinance our debt, if necessary, will depend upon the operating performance of our subsidiaries. Our business may not generate sufficient cash flows from operations, and future borrowings may not be available to us under our credit facility or otherwise in an amount sufficient to enable us to repay any borrowings under our credit facility or convertible debt or to fund our other liquidity needs. We also have significant lease and long-term royalty obligations. Our ability to meet our debt, lease and royalty obligations will depend upon the operating performance of our subsidiaries, which will be affected by economic conditions and a variety of other business factors, many of which are beyond our control.
The amount of our indebtedness, as well as the recent global recession, could have significant consequences, including, but not limited to: (i) limiting our ability to pay principal on our obligations; (ii) limiting our ability to refinance the revolver under our credit facility, which expires October 2011, or our convertible debt, which matures on May 31, 2013, on commercially reasonable terms, or terms acceptable to us or at all; (iii) limiting our ability to obtain additional financing to fund capital expenditures, future acquisitions, working capital or other general corporate requirements; (iv) placing us at a competitive disadvantage with competitors with lower amounts of debt; and (v) limiting our flexibility in planning for, or reacting to, changes in the coal industry. Any inability by us to obtain financing in the future on favorable terms could have a negative effect on our results of operations, cash flows and financial condition.
The acquisition of Magnum presents integration challenges and incremental costs.
The acquisition of Magnum was consummated on July 23, 2008. While we have made significant progress towards the integration of the two companies, we may face challenges in combining Magnum’s operations into our operations in a timely and efficient manner. The integration of the two companies requires resources and management attention in the areas of information technology, human resources, land management and finance. The failure to successfully integrate Magnum and to successfully manage the challenges presented by the integration process may result in us not achieving the anticipated benefits of the merger. Although we expect that the realization of efficiencies related to the integration of the businesses will offset incremental integration and restructuring costs over time, we cannot give any assurance that this net benefit will be achieved in the near term, if at all.
The covenants in our credit facility and other debt indentures impose restrictions that could limit our operational and financial flexibility.
The credit facility contains certain customary covenants, including financial covenants limiting our total indebtedness (maximum leverage ratio of 2.75) and requiring minimum EBITDA coverage of interest expense (minimum interest coverage ratio of 4.0), as well as certain limitations on, among other things, additional debt, liens, investments, acquisitions and capital expenditures, future dividends, common stock repurchases and asset
sales. Compliance with debt covenants may limit our ability to draw on our credit facility. In addition, the indenture for our convertible notes prohibits us from engaging in certain mergers or acquisitions unless, among other things, the surviving entity assumes our obligations under the notes. These and other provisions could prevent or deter a third party from acquiring us even where the acquisition could be beneficial to our stockholders.
Inaccuracies in our estimates of economically recoverable coal reserves could result in lower than expected revenues, higher than expected costs or decreased profitability.
We base our proven and probable coal reserve information on engineering, economic and geological data assembled and analyzed by our staff, which includes various engineers and geologists, and 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 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 relating to geological and mining conditions, relevant historical production statistics, the assumed effects of regulation and taxes, future coal prices, operating costs, mining technology improvements, development costs and reclamation costs.
For these reasons, estimates of the economically recoverable quantities and qualities attributable to any particular group of properties, classifications of coal 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. Actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our proven and probable coal reserves may vary materially from estimates. These estimates, thus, may not accurately reflect our actual coal reserves. Any inaccuracy in our estimates related to our proven and probable coal 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 lose key personnel or fail to attract qualified personnel.
We manage our business with a number of key personnel, the loss of a number of whom could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. We cannot be certain that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. Failure to retain or attract key personnel could have a material adverse effect on us.
We could be adversely affected by a decline in the creditworthiness or financial condition of our customers.
A substantial portion of our revenues is generated through sales to a marketing affiliate of Peabody, and we supply coal to Peabody on a contract basis so Peabody can meet its commitments under pre-existing customer agreements sourced from our operations. Our remaining sales are made directly to electric utilities, industrial companies and steelmakers.
Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base has changed with deregulation as some utilities have sold their power plants to their non-regulated affiliates or third parties. These new power plant owners or other customers may have credit ratings that are below investment grade. If the creditworthiness of our customers declines significantly and customers fail to stay current on their payments, our business could be adversely affected.
In addition, many companies are struggling to maintain their business given the current economic conditions. If any of our customers are significantly and negatively impacted by the current economic conditions, or by other business factors, our results of operations and financial condition could be materially adversely affected.
Any defects in title of leasehold interests in our properties could limit our ability to mine these properties or could result in significant unanticipated costs.
We conduct a significant part of our mining operations on properties that we lease. These leases were entered into over a period of many years by certain of our predecessors and title to our leased properties and mineral rights
may not be thoroughly verified until a permit to mine the property is obtained. Our right to mine some of our proven and probable coal reserves may be materially adversely affected if there were 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, which could adversely affect our profitability.
The ownership and voting interest of Patriot stockholders could be diluted as a result of the issuance of shares of our common stock to the holders of convertible notes upon conversion.
The issuance of shares of our common stock upon conversion of the convertible notes could dilute the interests of Patriot’s existing stockholders. The convertible notes are convertible at the option of the holders during the period from issuance to February 15, 2013 into a combination of cash and shares of our common stock, unless we elect to deliver cash in lieu of the common stock portion. The number of shares of our common stock that we may deliver upon conversion will depend on the price of our common stock during an observation period as described in the indenture. Specifically, the number of shares deliverable upon conversion will increase as the common stock price increases above the conversion price of $67.67 per share during the observation period. The maximum number of shares that we may deliver is 2,955,560. However, if certain fundamental changes occur in our business that are deemed “make-whole fundamental changes” as defined by the indenture, the number of shares deliverable on conversion may increase, up to a maximum amount of 4,137,788 shares. These maximum amounts, the conversion rate and conversion price are subject to adjustment for certain dilutive events, such as a stock split or a distribution of a stock dividend.
The net share settlement feature of our convertible notes may have adverse consequences on our liquidity.
We will pay an amount in cash equal to the aggregate principal portion of our convertible notes calculated as described under the indenture for the convertible notes. Because we must settle at least a portion of the conversion obligation with regard to the convertible notes in cash, the conversion of our convertible notes may significantly reduce our liquidity.
Peabody and its shareholders who received Patriot shares at the time of the spin-off could be subject to material amounts of taxes if the spin-off is determined to be a taxable transaction.
On September 26, 2007, Peabody received a ruling from the IRS to the effect that the spin-off qualified as a tax-free transaction under Section 355 of the Code. The IRS did not rule on whether the spin-off satisfied certain requirements necessary to obtain tax-free treatment under Section 355 of the Code. Therefore, in addition to obtaining the ruling from the IRS, Peabody received a favorable opinion from Ernst & Young LLP as to the satisfaction of these qualifying conditions required for the application of Section 355 to the spin-off. Ernst & Young LLP’s tax opinion is not binding on the IRS or the courts.
The letter ruling and the Ernst & Young LLP opinion relied on certain representations, assumptions and undertakings, including those relating to the past and future conduct of our business, and neither the letter ruling nor the Ernst & Young LLP opinion would be valid if such representations, assumptions and undertakings were incorrect. Moreover, the letter ruling did not address all of the issues that are relevant to determining whether the distribution would qualify for tax-free treatment. Notwithstanding the letter ruling and the Ernst & Young LLP opinion, the IRS could determine that the distribution should be treated as a taxable transaction if it determines that any of the representations, assumptions or undertakings that were included in the request for the letter ruling are false or have been violated or if it disagrees with the conclusions in the Ernst & Young LLP opinion that are not covered by the letter ruling. If, notwithstanding the letter ruling and opinion, the spin-off is determined to be a taxable transaction, Peabody shareholders who received Patriot shares at the time of the spin-off and Peabody could be subject to material amounts of taxes.
Patriot could be liable to Peabody for adverse tax consequences resulting from certain change in control transactions and therefore could be prevented from engaging in strategic or capital raising transactions.
Peabody could recognize taxable gain if the spin-off is determined to be part of a plan or series of related transactions pursuant to which one or more persons acquire, directly or indirectly, stock representing a 50% or greater interest in either Peabody or Patriot. Under the Code, any acquisitions of Peabody or Patriot within the four-year period beginning two years before the date of the spin-off are presumed to be part of such a plan unless they are
covered by at least one of several mitigating rules established by IRS regulations. Nonetheless, a merger, recapitalization or acquisition, or issuance or redemption of Patriot common stock after the spin-off could, in some circumstances, be counted toward the 50% change of ownership threshold. The tax separation agreement precludes Patriot from engaging in some of these transactions unless Patriot first obtains a tax opinion acceptable to Peabody or an IRS ruling to the effect that such transactions will not result in additional taxes. The tax separation agreement further requires Patriot to indemnify Peabody for any resulting taxes regardless of whether Patriot first obtains such opinion or ruling. As a result, Patriot may not be able to engage in strategic or capital raising transactions that stockholders might consider favorable, or to structure potential transactions in the manner most favorable to Patriot.
Although not required pursuant to the terms of the tax separation agreement, in connection with the execution of the Magnum merger agreement, Patriot obtained an opinion dated April 2, 2008 from Ernst & Young LLP to the effect that the issuance of the Patriot common stock pursuant to the merger agreement would not result in an acquisition of a 50% or greater interest in Patriot within the meaning of Sections 355(d)(4) and (3)(4)(A) of the Code.
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.
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 or the economy as a whole may materially adversely affect our operations or 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. Any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
Risks Related to Environmental and Other Regulation
Concerns about the environmental impacts of air emissions relating to coal mining and coal combustion, particularly the impact of greenhouse gas emissions on global climate change, are resulting in increased regulation of our industry and could significantly affect demand for our products and adversely affect our results of operations, cash flows and financial condition.
Our operations and those of our customers are subject to extensive environmental regulation relating to air emissions of pollutants, including sulfur dioxide, nitrogen oxide, mercury, and particulate matter. Costs related to these requirements can be significant, particularly for our customers. As environmental regulation and enforcement becomes more stringent over time, these costs are likely to increase and could have an adverse effect on our results of operations, cash flows and financial condition.
Considerable and increasing government attention in the United States and elsewhere is being paid to reducing greenhouse gas emissions, particularly from coal combustion power plants, which are the largest end-users of our coal. Legislators are considering the passage of significant new laws and regulators are considering using existing laws, including the Clean Air Act, to limit greenhouse gas emissions, and tax incentives and other measures are being imposed or offered by various laws and governmental agencies with the ultimate goal of reducing greenhouse gas emissions. For instance, Congress is expected to evaluate greenhouse gas legislation, perhaps in the coming year, and the EPA currently is seeking public comment on the feasibility of regulating greenhouse gas emissions under the Clean Air Act. The EPA has also announced that it will reconsider an interpretive memo it had released in December 2008 declaring that carbon dioxide is not currently subject to regulation under the Clean Air Act’s Prevention of Significant Deterioration permit program, and will publish a notice of proposed rulemaking relating to that reconsideration in the near future. Many states have adopted measures, sometimes as part of a regional collaboration, to reduce greenhouse gases generated within their own jurisdiction. These measures include emission regulations, mandates for utilities to generate a portion of their electricity without using coal, incentives or goals for generating electricity using renewable resources, and moratoriums on new coal fueled power plants. Some
municipalities have also adopted similar measures. As new requirements are imposed, we and our customers may be materially adversely affected.
Demand for and use of coal also 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 met in Bali, Indonesia in December 2007 to discuss a program to limit greenhouse gas emissions after 2012. The United States participated in the conference. The convention adopted what is called the “Bali Action Plan.” The Bali Action Plan contains no binding commitments, but concludes that “deep cuts in global emissions will be required” and provides a timetable for two years of talks to shape the first formal addendum to the 1992 United Nations Framework Convention on Climate Change treaty since the Kyoto Protocol. The ultimate outcome of the Bali Action Plan, and any treaty or other arrangement ultimately adopted by the United States or other countries, may have an adverse impact on the global supply and demand for coal, which in turn could have an adverse impact on our business.
In addition, proposed coal-fueled electric generating facilities are facing both increasing opposition, including through litigation, from environmental groups who are concerned with, among other things, global climate change as well as the uncertain financial impact of potential greenhouse gas regulations.
As a result of all of the above, certain power generating companies may reconsider plans to build or significantly modify coal-fueled plants or may elect to build capacity using alternative forms of electrical generation in the near-term and beyond. Any movement away from the use of coal could adversely affect our results of operations, cash flows and financial condition.
We may be unable to obtain, renew or comply with permits necessary for our operation, which could reduce our production, cash flows and profitability.
Mining companies must obtain numerous permits and approvals that impose strict requirements relating to environmental and safety matters. These include permits issued by various federal and state agencies and regulatory bodies. We have at times been unable to comply with all applicable requirements, and such failure has resulted in the past, and may in the future result in, lawsuits against us by regulators or private parties and has in the past and may in the future require us to pay material fines or penalties. In addition, because the permitting rules are complex, change frequently and have become more stringent over time, it may be even more difficult or even impossible to obtain, renew or comply with applicable requirements in the future, which could preclude continuing or future mining operations.
Private individuals and the public have certain rights to comment upon, submit objections to, and otherwise engage in the permitting process, including through court intervention. Some permit programs necessary to the operation of coal companies, such as the authorizations issued under Section 404 of the Clean Water Act, have been subject to recent and significant legal challenges. In addition, companies in the coal industry, including some of our subsidiaries, have been subject to a number of governmental investigations and court cases relating to a failure to comply with the terms of existing Clean Water Act permits or objecting to the issuance or terms of Clean Water Act permits. As a result of the foregoing, it has become more difficult, takes longer and costs more to obtain and maintain permits necessary for our operations, and in some cases the permits we need may not be issued, maintained or renewed in a timely fashion, may be subject to additional future challenges and may impose extremely burdensome conditions on our operations and activities. In addition, we have recently been issued court orders or have settled cases relating to Clean Water Act permits and we may in the future be issued additional court orders or be required to enter into new settlements, all of which may require us to pay material fines or penalties, undertake time-consuming and expensive investigations, and make changes or shutdown some of our operations. Any of the foregoing could materially adversely affect our production, results of operations, cash flows and financial condition.
Like many of our competitors, we cannot always completely comply with permit restrictions relating to the discharge of selenium into surface water, which has led to court challenges and related orders and settlements, has required us to pay fines and penalties, is requiring us to incur other significant costs and may be difficult to resolve in a timely basis given current technology.
Selenium is a naturally occurring substance that is discharged to surface water when our mine tailings are exposed to rain and other natural elements. Many coal companies that have surface mining operations in Appalachia have similar risks relating to the discharge of selenium. Some of our permits have currently effective limits on the selenium that can be discharged, and other permits have limits that will be effective in the future. There is currently no reasonably available technology that has been proven to effectively address selenium exceedances in permitted water discharges, and as a result the West Virginia Department of Environmental Protection (WVDEP) deferred most of the obligations of our company and of other coal companies to comply with any selenium discharge limit obligations until April 2010. However, a federal court decision determined that the deferral of the obligations with respect to a permit of Apogee Coal Company, LLC (Apogee), one of Magnum’s subsidiaries, failed to meet certain procedural requirements, and as a result ordered Apogee to develop and implement a treatment plan relating to the outfalls governed by that permit, or to show cause of its inability to do so. In addition, as a result of a lawsuit filed by the WVDEP in state court in West Virginia, Hobet Mining, LLC (Hobet), a subsidiary of Magnum, has entered into a settlement agreement with the WVDEP requiring Hobet to pay fines and penalties with respect to past violations of selenium limitations under four NPDES permits, to meet permit limitations on selenium by December 31, 2009 with respect to one permit, and to study potential treatments to address the selenium discharges.
As a result of the above, we are actively engaged in studying potential solutions to controlling selenium discharges and we have been installing test treatment facilities at various permitted outfalls. Because the levels and frequency of selenium discharges at any given outfall will be different, the solution for each outfall may be very different and a variety of solutions will therefore ultimately be required. The potential solutions identified to date, some of which have been provided to the federal court in West Virginia, have not been proven to be effective and otherwise may not be feasible due to a range of problems concerning technological issues, prohibitive implementation costs and other issues. While we are actively continuing to explore options, there can be no assurance as to when a definitive solution will be identified and implemented. As a result, it is possible that we will be unable to meet either the court order or WVDEP settlement deadlines or the ultimate April 2010 deadline. While these selenium discharge issues generally relate to historical rather than ongoing mining operations, any failure to meet the deadlines or to otherwise comply with selenium limits in our permits could result in further litigation against us, an inability to obtain new permits or to maintain existing permits, the incurrence of significant and material fines and penalties or other costs and could otherwise materially adversely affect our results of operations, cash flows and financial condition.
Any restrictions on the disposal of mining spoil material could significantly increase our operating costs and materially harm our financial condition and operating results.
As is the case with other coal mining companies operating in Appalachia, our construction and mining activities, including our mountaintop removal mining operations, frequently require, and depend on, the use of valley fills for the disposal of excess spoil (rock and soil material). These operations require us to obtain Section 404 Clean Water Act permits from ACOE to construct and operate valley fills and surface impoundments.
During the last few years, certain environmental groups have filed lawsuits challenging the ACOE’s authority to issue Section 404 Clean Water Act permits relating to valley fills and surface impoundments and, in some instances, environmental groups have also sought to enjoin the use of such permits previously issued by the ACOE. While a recent federal court decision held that ACOE had the authority to issue certain 404 Clean Water Act permits known as individual permits, other court cases permitting the issuance of certain 404 Clean Water Act permits known as nationwide permits are still under appeal. As a result, there can be no assurance that future laws or judicial rulings will not adversely affect the issuance of or the renewal or ongoing use of valley fill or surface impoundment permits under the Clean Water Act. If these mining methods are limited or prohibited, it could significantly increase our operational costs and make it more difficult to economically recover a significant portion of our reserves. In the event that we cannot increase the price we charge for coal to cover the higher production costs without reducing customer demand for our coal, there could be an adverse effect on our financial condition and results of operations.
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.
Certain of our current and historical coal mining operations have used hazardous materials and, to the extent that such materials are not recycled, they could become hazardous waste. We may be subject to claims under federal and state statutes and/or common law doctrines for toxic torts and other damages, as well as for natural resource damages and the investigation and remediation of soil, surface water, groundwater, and other media under laws such as CERCLA, commonly known as Superfund. Such claims may arise, for example, out of current or former conditions at sites that we own or operate currently, as well as at sites that we and companies we acquired owned or operated in the past, and at contaminated sites that have always been owned or operated by third parties. Liability may be without regard to fault and may be strict, 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 coal slurry impoundments at a number of our mines. Such impoundments are subject to extensive regulation. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as streams or bodies of water and wildlife, as well as related personal injuries and property damages which in turn can give rise to extensive liability. Some of our impoundments overlie areas where some mining has occurred, 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. A recent well publicized failure of an ash slurry impoundment maintained by the Tennessee Valley Authority has led to new legislative and regulatory proposals that, if enacted, may impose significant obligations on us or our customers. In addition, the EPA administrator has publicly called for more inspections of coal slurry impoundments.
These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could adversely affect us.
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.
Federal and state authorities regulate the coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, the protection of the environment, plants and wildlife, reclamation and restoration of mining properties after mining is completed, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. In addition, significant legislation mandating specified benefits for retired coal miners affects our industry. The costs, liabilities and requirements associated with these regulations are often costly and time-consuming and may delay commencement or continuation of exploration or production. New or revised legislation or administrative regulations (or judicial or administrative interpretations of existing laws and regulations), including proposals related to the protection of the environment or employee health and safety that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs, which may materially adversely affect our mining operations and our cost structure. 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. These factors could have a material adverse effect on our results of operations, cash flows and financial condition.
In the event of certain violations of safety rules, the Mine Safety and Health Administration may order the temporary closure of mines. Our customers may challenge our issuance of force majeure notices in connection with such closures. If these challenges are successful, we could be obligated to make up lost shipments, to reimburse customers for the additional costs to purchase replacement coal, or, in some cases, to terminate certain sales contracts.
We are involved in legal proceedings that if determined adversely to us, could significantly impact our profitability, financial position or liquidity.
We are involved in various legal proceedings that arise in the ordinary course of business. Some of the lawsuits seek fines or penalties and damages in very large amounts, or seek to restrict our business activities. In particular, we are subject to legal proceedings relating to our receipt of and compliance with permits under the Clean Water Act and to other legal proceedings relating to environmental matters involving current and historical operations and ownership of land. It is currently unknown what the ultimate resolution of these proceedings will be, but the costs of resolving these proceedings could be material, and could result in an obligation to change our operations in a manner that could have an adverse effect on us.
We have significant reclamation and mine closure obligations. If the assumptions underlying our accruals are inaccurate, we could be required to expend greater amounts than anticipated.
The Surface Mining Control and Reclamation Act of 1977, or SMCRA, establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. We calculated the total estimated reclamation and mine-closing liabilities according to the guidance provided by U.S. accounting standards. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. As of December 31, 2008, we had accrued reserves of $121.6 million for reclamation liabilities and mine closures and an additional $102.6 million for medical benefits for employees due to mine closure. The estimate of ultimate reclamation liability is reviewed annually by our management and engineers. The estimated liability could change significantly if actual costs vary from assumptions, if the underlying facts change or if governmental requirements change significantly.
If our assumptions regarding our likely future expenses related to employee benefit plans are incorrect, then expenditures for these benefits could be materially higher than we have assumed.
We provide post-retirement health and life insurance benefits to eligible union and non-union employees. We calculated the total accumulated postretirement benefit obligation according to the guidance provided by U.S. accounting standards. We estimated the present value of the obligation to be $1.1 billion as of December 31, 2008. We have estimated these unfunded obligations based on actuarial assumptions described in the notes to our consolidated financial statements. If our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially higher.
Due to our participation in multi-employer pension plans and statutory retiree healthcare plans, we may have exposure that extends beyond what our obligations would be with respect to our employees.
Certain of our subsidiaries participate in two defined benefit multi-employer pension funds that were established as a result of collective bargaining with the UMWA pursuant to the 2007 NBCWA as periodically negotiated. These plans provide pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked prior to January 1, 1976, in the case of the UMWA 1950 Pension Plan, or after December 31, 1975, in the case of the UMWA 1974 Pension Plan. In December 2006, the 2007 NBCWA was signed, which required funding of the 1974 Pension Plan through 2011 under a phased funding schedule. The funding is based on an hourly rate for active UMWA workers. Under the labor contract, the per hour funding rate increased to $3.50 in 2008 and will increase each year thereafter until reaching $5.50 in 2011. Our subsidiaries with UMWA-represented employees are required to contribute to the 1974 Pension Plan at the new hourly rates. Contributions to these funds could increase as a result of future collective bargaining with the UMWA, a shrinking contribution base as a result of the insolvency of other coal companies who currently contribute to these funds, lower than expected returns on pension fund assets or other funding deficiencies.
The 2006 Act authorized $490 million in general fund revenues to pay for certain benefits, including the healthcare costs under the Combined Fund, 1992 Benefit Plan and 1993 Benefit Plan for “orphans” who are retirees and their dependents. Under the 2006 Act, these orphan benefits will be the responsibility of the federal government on a phased-in basis through 2012. If Congress were to amend or repeal the 2006 Act or if the $490 million authorization were insufficient to pay for these healthcare costs, certain of our subsidiaries, along with other contributing employers and their affiliates, would be responsible for the excess costs. Our aggregate cash payments
to the Combined Fund, 1992 Benefit Plan and 1993 Benefit Plan were $17.9 million and $21.4 million during 2008 and 2007, respectively.
We could be liable for certain retiree healthcare obligations to be assumed by Peabody in connection with the spin-off.
In connection with the spin-off, a Peabody subsidiary assumed certain retiree healthcare obligations of Patriot and its subsidiaries having a present value of $597.6 million as of December 31, 2008. These obligations arise under the Coal Act, the 2007 NBCWA and predecessor agreements and a subsidiary’s salaried retiree healthcare plan.
Although the Peabody subsidiary is obligated to pay such obligations, certain Patriot subsidiaries also remain jointly and severally liable for the Coal Act obligations, and secondarily liable for the assumed 2007 NBCWA obligations and retiree healthcare obligations for certain participants under a subsidiary’s retiree healthcare plan. As a consequence, Patriot’s recorded retiree healthcare obligations and related cash costs could increase substantially if the Peabody subsidiary would fail to perform its obligations under the liability assumption agreements. These additional liabilities and costs, if incurred, could have a material adverse effect on our results of operations, cash flows and financial condition.
Item 1B.
Item 1B.
Unresolved Staff Comments.
None.
Item 2.
Item 2.
Properties.
Coal Reserves
We had an estimated 1.8 billion tons of proven and probable coal reserves as of December 31, 2008 located in Appalachia and the Illinois Basin. Fifteen percent of our proven and probable coal reserves, or just over 279 million tons, are compliance coal and 1,560 million tons are non-compliance coal. We own approximately 36% of these reserves and lease property containing the remaining 64%. Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu and complies with certain requirements of the Clean Air Act. Electricity generators are able to use non-compliance coal by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.
Below is a table summarizing the locations and reserves of our major operating regions.
(1)
Reserves have been adjusted to take into account recoverability factors in producing a saleable product.
Reserves are defined by 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 and probable coal reserves are defined by SEC Industry Guide 7 as follows:
•
Proven (Measured) Reserves. Reserves for which (a) quantity is computed from dimensions defined by outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so close and the geologic character is so well defined that size, shape, depth and mineral content of coal reserves are well-established.
•
Probable (Indicated) Reserves. 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.
Our estimates of 1,088 million tons of proven and 751 million tons of probable coal reserves are established within these guidelines. Patriot does not include sub-economic coal within these proven and probable reserve estimates. Proven reserves require the coal to lie within one-quarter mile of a valid point of measure or point of observation, such as exploratory drill holes or previously mined areas. Estimates of probable reserves may lay more than one-quarter mile, but less than three-quarters of a mile, from a point of thickness measurement. Estimates within the proven category have the highest degree of assurance, while estimates within the probable category have only a moderate degree of geologic assurance. Further exploration is necessary to place probable reserves into the proven reserve category. Our active properties generally have a much higher degree of reliability because of increased drilling density.
Reserve estimates as of December 31, 2008 were prepared by Patriot’s Director of Geology, a certified Geologist, by updating the December 31, 2007 estimates and incorporating a reserve statement from an outside consultant for the newly-acquired Magnum operations. The reserve estimation process includes evaluating select reserve areas, updating estimates to reflect remodeling and additional available drilling information and coordinating third-party reviews when deemed necessary. This process confirmed that Patriot had approximately 1.8 billion tons of proven and probable reserves as of December 31, 2008.
Our reserve estimates are predicated on information obtained from an ongoing drilling program, which totals more than 35,000 individual data points. We compile data from individual data points in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the quality of the coal are determined. The density of the data determines whether the reserves will be classified as proven or probable. The reserve estimates are then input into a computerized land management system, which overlays the geological data with data on ownership or control of the mineral and surface interests to determine the extent of our proven and probable coal reserves in a given area. The land management system contains reserve information, including the quantity and quality (where available) of coal reserves as well as production rates, surface ownership, lease payments and other information relating to our coal reserves and land holdings. We periodically update our reserve estimates to reflect production of coal from the reserves and new drilling or other data received. Accordingly, reserve estimates will change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings, modification of mining methods and other factors.
Our estimate of the economic recoverability of our proven and probable coal reserves is based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to existing market prices for the quality of coal expected to be mined and take into consideration typical contractual sales agreements for the region and product. Where possible, we also review production by competitors in similar mining areas. Only coal reserves expected to be mined economically are included in our reserve estimates. Finally, our coal reserve estimates include reductions for recoverability factors to estimate a saleable product.
With respect to the accuracy of our reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average. Our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to move reserves from the probable to the proven classification. The expected degree of variance from reserve estimate to tons produced is lower in the Illinois Basin due to the continuity of the coal seams as confirmed by the mining history. Appalachia has a higher degree of risk due to the mountainous nature of the topography which makes exploration drilling more difficult. Our proven and probable reserves in Appalachia are less predictable and may vary by an additional one to two percent above the threshold discussed above.
Private coal leases normally have terms of between 10 and 20 years and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments.
The terms of our private leases are normally extended by active production on or near the end of the lease term. Leases containing undeveloped reserves may expire or these leases may be renewed periodically. With a portfolio of approximately 1.8 billion tons, we believe that we have sufficient reserves to replace capacity from depleting mines for an extensive period of time and that our significant base of proven and probable coal reserves is one of our strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.
Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves.
The following chart provides a summary, by geographic region and mining complex, of production for the years ended December 31, 2008, 2007 and 2006, tonnage of coal reserves assigned to our operating mines, property interest in those reserves and other characteristics of the facilities. Production for the newly-acquired Magnum operations is included from the date the acquisition was consummated, July 23, 2008.
PRODUCTION AND ASSIGNED RESERVES(1)
The following chart provides a summary of the amount of our proven and probable coal reserves in each U.S. state, the predominant type of coal mined in the applicable location, our property interest in the reserves and other characteristics of the facilities.
ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES(1)
AS OF DECEMBER 31, 2008
(1)
Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2008. Unassigned reserves represent coal at suspended locations and coal that has not been committed. These reserves would require new mine development, mining equipment or plant facilities before operations could begin on the property.
(2)
Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu and complies with the Clean Air Act. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal.
(3)
As-received Btu per pound includes the weight of moisture in the coal on an as-sold basis. The average moisture content used in the determination of as-received Btu in Appalachia was 7%. The moisture content used in the determination of as received Btu in Illinois Basin ranged from 9% to 14%.
Item 3.
Item 3.
Legal Proceedings.
From time to time, Patriot and its subsidiaries are involved in legal proceedings, arbitration proceedings and administrative procedures arising in the ordinary course of business.
Environmental Claims and Litigation
We are subject to applicable federal, state and local environmental laws and regulations where we conduct operations. Current and past mining operations are primarily covered by SMCRA, the Clean Water Act and the Clean Air Act, but are also covered by, among other laws, CERCLA (also known as Superfund) and RCRA.
Clean Water Act Permit Issues
The federal Clean Water Act and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the United States. In particular, the Clean Water Act requires effluent limitations and treatment standards for wastewater discharge through the NPDES program. NPDES permits, which we must obtain for both active and historical mining operations, govern the discharge of pollutants into water and require regular monitoring and reporting and set forth performance standards. States are empowered to develop and enforce “in stream” water quality standards, which are subject to change and must be approved by the EPA. In stream standards vary from state to state.
Environmental claims and litigation in connection with our various NPDES permits, and related Clean Water Act issues, include the following:
EPA Consent Decree
In February 2009, we announced that we entered into a consent decree with the EPA and the WVDEP to resolve certain claims under the Clean Water Act and the West Virginia Water Pollution Control Act relating to our NPDES permits at several mining operations in West Virginia. The consent decree does not cover issues related to discharge limits for selenium, and it is subject to public comment, which could result in delays, modifications, or even withdrawal of the consent decree. Under the current terms of the consent decree, we are obligated to pay a civil penalty of $6.5 million in 2009. We also could be subject to stipulated penalties in the future for failure to comply with certain permit requirements as well as certain other terms of the consent decree. Because our operations are complex and we periodically experience exceedances of our permit limitations, it is possible that we will have to pay stipulated penalties in the future, but we do not expect the amounts of any such penalties would be material.
The consent decree also requires us to implement an enhanced company-wide environmental management system, which will include regular compliance audits, electronic tracking and reporting, and annual training for all employees and contractors with environmental responsibilities. In addition, we will complete several stream restoration projects in consultation with the EPA and WVDEP. These latter requirements could result in incremental operating costs in addition to the $6.5 million civil penalty. The initial incremental estimate ranging from $3 million to $6 million could increase or decrease as we implement the various requirements.
In a separate administrative proceeding with the WVDEP, we have agreed to pay a civil penalty of $315,000 for past violations of NPDES permits held by certain subsidiaries.
Apogee
In 2007, Apogee, one of our subsidiaries, was sued in the U.S. District Court for the Southern District of West Virginia by the Ohio Valley Environmental Coalition, Inc. (OVEC) and another environmental group (pursuant to the citizen suit provisions of the Clean Water Act). We refer to this lawsuit as the Federal Apogee Case. This lawsuit alleges that Apogee has violated water discharge limits for selenium set forth in one of its NPDES permits. The lawsuit seeks fines and penalties as well as injunctions prohibiting Apogee from further violating laws and its permit.
Currently, there is no reasonably available technology that has been proven effective at addressing selenium exceedances in mining outfalls similar to ours. As a result, the WVDEP has deferred the obligations to comply with the selenium discharge limits in most permits related to mining outfalls until April 2010. However, on May 28, 2008, the judge in the Federal Apogee Case determined that the attempted deferral of the selenium discharge limits set forth in the relevant Apogee permit failed to meet certain procedural requirements and ordered Apogee to develop and implement a treatment plan or to show cause of its inability to do so. After a July 2008 hearing, the judge ordered Apogee to submit a report specifying an explanation of the treatment alternatives under consideration. After Apogee submitted its report, the judge entered an order requiring complete installation of treatment no later than May 31, 2009, and final compliance with the selenium discharge limits in Apogee’s NPDES permit no later than June 30, 2009.
We are actively engaged in studying potential solutions to controlling selenium discharges and is installing treatment facilities at various permitted outfalls in an effort to comply with the deadlines established in the Federal Apogee Case. The potential solutions identified to date, some of which have been provided to the court, have not been proven to be effective and otherwise may not be feasible due to a range of problems concerning technological issues, prohibitive implementation costs and other issues. While we are actively continuing to explore options, there can be no assurance as to when a definitive solution will be identified and implemented. As a result, it is possible that we will be unable to meet the court order. While these selenium discharge issues generally relate to historical rather than ongoing mining operations, any failure to meet the deadlines or to otherwise comply with selenium limits in our permits could result in further litigation against us, an inability to obtain new permits or to maintain existing permits, the incurrence of significant and material fines and penalties or other costs and could otherwise materially adversely affect our results of operations, cash flows and financial condition.
Penalties related to our violations of the selenium discharge limits under its NPDES permit will be addressed at a separate hearing before the court in November 2009, and we may be subject to further penalties in the event we are unable to comply with the deadlines established by the court’s August 2008 order. Finally, we will likely incur significant costs related to the investigations and ultimate installation and maintenance of treatment facilities designed to control selenium discharges. The amount of these civil penalties and other costs may be significant, although we are unable to reasonably estimate such costs at this time.
The outcome of this litigation is subject to numerous uncertainties. Based on our evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated.
Hobet
In 2007, Hobet, another one of our subsidiaries, was sued for exceedances of effluent limits contained in its NPDES permits in state court in Boone County by the WVDEP. We refer to this case as the WVDEP Action. In 2008, OVEC and another environmental group filed a lawsuit against Hobet and WVDEP in the U.S. District Court for the Southern District of West Virginia (pursuant to the citizen suit provisions of the Clean Water Act). We refer to this case as the Federal Hobet Case. The Federal Hobet Case involves the same NPDES permits that are the subject of the WVDEP Action in state court. However, the Federal Hobet Case is focused exclusively on selenium exceedances in permitted water discharges, while the WVDEP Action addresses several pollutant discharge limits including selenium.
The WVDEP Action was resolved by a settlement and consent order entered in the Boone County circuit court on September 5, 2008. As part of the settlement, we agreed to pay approximately $1.5 million in civil penalties, with $500,000 due immediately and the remaining approximately $1 million payable in ten monthly installments. The settlement also requires us to complete five supplemental environmental projects estimated to cost approximately $2.6 million, many of which focus on identifying methods for treatment of selenium discharges and studying the effects of selenium on aquatic wildlife. Finally, we agreed to make gradual reductions in its selenium discharges from its Hobet Job 21 surface mine, achieving full compliance with its NPDES permits by April 2010, and to study potential treatments for wastewater runoff.
Following the WVDEP Action settlement, motions to dismiss and for summary judgment have been filed by both sides and are pending in the Federal Hobet Case. To date, the federal court has dismissed all injunctive claims asserted by the plaintiffs as moot because of the WVDEP Action settlement. However, the federal court is still considering a pending motion to dismiss plaintiffs’ claims for civil penalties. We expect to pay an additional penalty relating to the period of time not covered by the WVDEP Action settlement, which could exceed $100,000, but which we do not anticipate will be material. It is also possible that the federal court would hold that the plaintiffs continue to maintain viable claims for additional civil penalties.
As a result of the litigation involving Apogee and Hobet, the process of applying for new permits has become more time-consuming and complex, the review and approval process is taking longer, and in certain cases, new permits may not be issued. The lack of proven treatment methods for selenium discharges also causes uncertainty as to the magnitude of our future liability. Based on our evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated.
CERCLA
CERCLA and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to natural resources. Under CERCLA and many similar state statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault. These regulations could require us to do some or all of the following: (i) remove or mitigate the effects on the environment at various sites from the disposal or release of certain substances; (ii) perform remediation work at such sites; and (iii) pay damages for loss of use and non-use values.
Although waste substances generated by coal mining and processing are generally not regarded as hazardous substances for the purposes of CERCLA and similar legislation and are generally covered by SMCRA, some products used by coal companies in operations, such as chemicals, and the disposal of these products are governed
by CERCLA. Thus, coal mines currently or previously owned or operated by us, and sites to which we have sent waste materials, may be subject to liability under CERCLA and similar state laws. A predecessor of one of our subsidiaries has been named as a potentially responsible party at a third-party site, but given the large number of entities involved at the site and our anticipated share of expected cleanup costs, we believe that our ultimate liability, if any, will not be material to our financial condition and results of operations.
Flood Litigation
Flood Litigation
One of our subsidiaries, Catenary Coal Company, LLC (Catenary), has been named as defendant, along with various other property owners, coal companies, timbering companies and oil and natural gas companies, in connection with alleged damages arising from flooding that occurred on July 8, 2001 in various watersheds primarily located in southern West Virginia (referred to as the 2001 flood litigation). Pursuant to orders from the West Virginia Supreme Court of Appeals, the cases are being handled as mass litigation, and a panel of three judges was appointed to handle the matters that have been divided between the judges pursuant to the various watersheds.
One of the cases, in the Upper Guyandotte River watershed, went to trial against two defendants, both of which were land holding companies, to determine whether the plaintiffs could establish liability. The jury found in favor of the plaintiffs, but the judge in this matter set aside the verdict stating he committed reversible error by allowing certain testimony of the plaintiffs’ experts. The judge went on to address the core foundation necessary to prevail in the flood litigation in his order, which is whether the plaintiffs can scientifically establish that a certain flood event caused and/or contributed to injury and, if so, who caused the injury and what persons were injured by such conduct. An appeal of this order was filed with the West Virginia Supreme Court of Appeals. The West Virginia Supreme Court issued its decision reversing the trial judge’s order and remanded the matter to the Mass Litigation Panel for further disposition.
In the Coal River watershed of the 2001 flood litigation, another judge in the panel provided an opportunity for the plaintiffs to amend their complaints to more specifically identify, among other things, the defendants’ specific injury-causing conduct, and the amount of damages sustained by each plaintiff. The plaintiffs were unable to meet the pleading standard announced by the judge and in January 2007, the judge entered an order that granted defendants’ motions to dismiss with prejudice. An appeal of this order was filed with the West Virginia Supreme Court of Appeals. The West Virginia Supreme Court issued its decision reversing the trial judge’s order and remanded the matter to the Mass Litigation Panel for further disposition.
Pursuant to the purchase and sale agreement related to Magnum, Arch Coal, Inc. (Arch) indemnifies us against claims arising from certain pending litigation proceedings, including the 2001 flood litigation, which obligation will continue indefinitely. The failure of Arch to satisfy its indemnification obligations under the purchase agreement could have a material adverse effect on us.
Flood Litigation
In 2006, Hobet and Catenary, were named as defendants along with various other property owners, coal companies, timbering companies and oil and natural gas companies, arising from flooding that occurred on May 30, 2004 in various watersheds primarily located in southern West Virginia. This litigation is pending before two different judges in the Circuit Court of Logan County, West Virginia.
In the first action, the plaintiffs have asserted that (i) Hobet failed to maintain an approved drainage control system for a pond on land on, near, and/or contiguous to the sites of flooding; and (ii) Hobet participated in the development of plans to grade, blast, and alter the land on, near, and/or contiguous to the sites of the flooding. Hobet has filed a motion to dismiss both claims based upon the assertion that insufficient facts have been stated to support the claims of the plaintiffs.
In the second action, on behalf of Catenary and Hobet, motions to dismiss have been filed, asserting that the allegations asserted by the plaintiffs are conclusory in nature and likely deficient as a matter of law. Most of the other defendants also filed motions to dismiss. Both actions were stayed during the pendency of the appeals to the West Virginia Supreme Court of Appeals in the 2001 flood litigation.
Other Environmental Litigation
Apogee has been sued, along with eight other defendants, including Monsanto Company, Pharmacia Corporation and Akzo Nobel Chemicals, Inc. by certain plaintiffs in state court in Putnam County, West Virginia. The lawsuits were filed in October 2007, but not served on Apogee until February 2008, and each are identical except for the named plaintiff. They each allege personal injury occasioned by exposure to dioxin generated by a plant owned and operated by certain of the other defendants during production of a chemical, 2,4,5-T, from 1949-1969. Apogee is alleged to be liable as the successor to the liabilities of a company that owned and /or controlled a dump site known as the Manila Creek landfill, which allegedly received and incinerated dioxin-contaminated waste from the plant. The lawsuits seek class action certification as well as compensatory and punitive damages for personal injury. Under the terms of the governing lease, Monsanto has assumed the defense of these lawsuits and has agreed to indemnify Apogee for any related damages. The failure of Monsanto to satisfy its indemnification obligations under the lease could have a material adverse effect on us.
One of our subsidiaries operated the Eagle No. 2 mine located near Shawneetown, Illinois from 1969 until closure of the mine in July of 1993. In 1999, the State of Illinois brought a proceeding before the Illinois Pollution Control Board against our subsidiary alleging that groundwater contamination due to leaching from a coal waste pile at the mine site violated state standards. Our subsidiary has developed a remediation plan with the State of Illinois and is in litigation with the Illinois Attorney General’s office with respect to its claim for a civil penalty of $1.3 million.
On December 31, 2008, 45 related lawsuits were filed by 116 plaintiffs against several coal companies, including one of our subsidiaries in the Circuit Court of Boone County, West Virginia. The plaintiffs in each case allege contamination of their drinking water wells from slurry impoundments in Boone County. The lawsuits seek property damages, personal injury damages and medical monitoring costs. Because of the early stage of the lawsuits, we are unable to predict the likelihood of success of the plaintiffs’ claims, though we intend to vigorously defend ourselves against all claims.
The outcome of this other environmental litigation is subject to numerous uncertainties. Based on our evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, we believe these matters are likely to be resolved without a material adverse effect on our financial condition, results of operations and cash flows.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders.
No matters were submitted to a vote of security holders during the quarter ended December 31, 2008.
Executive Officers
Set forth below are the names, ages as of February 20, 2009 and current positions of our executive officers. Executive officers are appointed by, and hold office at, the discretion of our Board of Directors.
Richard M. Whiting
Chief Executive Officer and Director
Richard M. Whiting, age 54, serves as Chief Executive Officer and as a Director. Whiting joined Peabody’s predecessor company in 1976 and has held a number of operations, sales and engineering positions both at the corporate offices and at field locations. Prior to the spin-off, Mr. Whiting was Peabody’s Executive Vice President & Chief Marketing Officer from May 2006 to 2007, with responsibility for all marketing, sales and coal trading operations, as well as Peabody’s joint venture relationships. He previously served as President & Chief Operating Officer and as a director of Peabody from 1998 to 2002. He also served as Executive Vice President - Sales, Marketing & Trading from 2002 to 2006, and as President of Peabody COALSALES Company from 1992 to 1998.
Whiting is the former Chairman of National Mining Association’s Safety and Health Committee, the former Chairman of the Bituminous Coal Operators’ Association, and a past board member of the National Coal Council. He is currently a director of the Society of Mining Engineers Foundation. Whiting holds a Bachelor of Science degree in mining engineering from West Virginia University.
Irl F. Engelhardt
Chairman of the Board of Directors, Executive Advisor and Director
Irl F. Engelhardt, age 62, serves as Chairman of the Board of Directors and Executive Advisor. Prior to the spin-off, Mr. Engelhardt served as Chairman and as a director of Peabody from 1998 until October 2007. Mr. Engelhardt also served as Chief Executive Officer of Peabody from 1998 to 2005 and as Chief Executive Officer of a predecessor of Peabody from 1990 to 1998. He also served as Chairman of a predecessor of Peabody from 1993 to 1998 and as President from 1990 to 1995. After joining a predecessor of Peabody in 1979, he held various officer level positions in the executive, sales, business development and administrative areas, including Chairman of Peabody Resources Ltd. (Australia) and Chairman of Citizens Power LLC. Mr. Engelhardt also served as Co-Chief Executive Officer and executive director of The Energy Group from February 1997 to May 1998, Chairman of Cornerstone Construction & Materials, Inc. from September 1994 to May 1995 and Chairman of Suburban Propane Company from May 1995 to February 1996. He served as a director and Group Vice President of Hanson Industries from 1995 to 1996. He also previously served as Chairman of the Federal Reserve Bank of St. Louis, the National Mining Association (NMA), the Coal Industry Advisory Board of the International Energy Agency, the Center for Energy and Economic Development and the Coal Utilization Research Council, as well as Co-Chairman of the Coal Based Generation Stakeholders Group. He serves on the Boards of Directors of Valero Energy Corporation and The Williams Companies, Inc.
Paul H. Vining
President & Chief Operating Officer
Paul H. Vining, age 54, serves as President and Chief Operating Officer. Prior to the Magnum acquisition, Mr. Vining served as President and Chief Executive Officer of Magnum since 2006. Prior to joining Magnum, Mr. Vining was Senior Vice President of Marketing and Trading at Arch Coal. Prior to that, from 2002 to 2006, he was President of Ellett Valley CC Inc., a coal trading, marketing and consulting company based in Williamsburg, Virginia. From 1999 to 2002, Mr. Vining was Executive Vice President for Sales and Trading at Peabody. From 1996 to 1999, he was President of Peabody COALTRADE. From 1995 to 1996, Mr. Vining was Senior Vice President of Peabody COALSALES. Earlier in his career, he held leadership positions with Guasare Coal America, Agipcoal USA, Island Creek Coal and A.T. Massey Energy.
Mr. Vining currently serves as Treasurer and board member of the West Virginia Coal Association. Mr. Vining holds a Bachelor of Science degree in chemistry from the College of William and Mary, and a Bachelor of Science in mineral engineering and a Master of Science degree in extractive metallurgy from Columbia University’s Henry Krumb School of Mines in New York.
Mark N. Schroeder
Senior Vice President & Chief Financial Officer
Mark N. Schroeder, age 52, serves as Senior Vice President & Chief Financial Officer. Prior to the spin-off, Schroeder held several key management positions in his career at Peabody which began in 2000. These positions included President of Peabody China (2006 to 2007), Vice President of Materials Management (2004 to 2006), Vice President of Business Development (2002 to 2004) and Vice President and Controller (2000 to 2002). He has more than 28 years of business experience, including as Chief Financial Officer of Behlmann Automotive Group (1997 to 1998), Chief Financial Officer of Franklin Equity Leasing Company (from 1998 to 2000) and financial management positions with McDonnell Douglas Corporation and Ernst & Young, LLP.
Schroeder is a certified public accountant and holds a Bachelor of Science degree in business administration from Southern Illinois University - Edwardsville.
Charles A. Ebetino, Jr.
Senior Vice President - Corporate Development
Charles A. Ebetino, Jr., age 56, serves as Senior Vice President - Corporate Development. Prior to the spin-off, Ebetino was Senior Vice President - Business and Resource Development for Peabody since May 2006. Ebetino also served as Senior Vice President - Market Development for Peabody’s sales and marketing subsidiary from 2003 to 2006. Ebetino joined Peabody in 2003 after more than 25 years with American Electric Power Company, Inc. (AEP) where he served in a number of management roles in the fuel procurement and supply group, including Senior Vice President of Fuel Supply and President & Chief Operating Officer of AEP’s coal mining and coal-related subsidiaries from 1993 until 2002. In 2002, he formed Arlington Consulting Group, Ltd., an energy industry consulting firm.
Ebetino is a past board member of NMA, former Chairman of the NMA Environmental Committee, a former Chairman and Vice Chairman of the Edison Electric Institute’s Power Generation Subject Area Committee, a former Chairman of the Inland Waterway Users Board, and a past board member and president of the Western Coal Transportation Association. Ebetino has a Bachelor of Science degree in civil engineering from Rensselaer Polytechnic Institute. He also attended the New York University School of Business for graduate study in finance.
Joseph W. Bean
Senior Vice President - Law & Administration, General Counsel & Corporate Secretary
Joseph W. Bean, age 46, serves as Senior Vice President - Law & Administration, General Counsel & Corporate Secretary since February 2009. Prior to that, Bean served as Senior Vice President, General Counsel & Corporate Secretary for Patriot. Prior to the spin-off, Bean served as Peabody’s Vice President & Associate General Counsel and Assistant Secretary (2005 to 2007) and as Senior Counsel (2001 to 2005). During his tenure at Peabody, Bean directed the company’s legal and compliance activities related to mergers and acquisitions, corporate governance, corporate finance and securities matters.
Bean has 22 years of corporate law experience, including 18 years as in-house legal counsel. Bean was counsel and assistant corporate secretary for The Quaker Oats Company prior to its acquisition by PepsiCo in 2001 and assistant general counsel for Pet Incorporated prior to its 1995 acquisition by Pillsbury. Bean also served as a corporate law associate with the law firms of Mayer, Brown & Platt in Chicago and Thompson & Mitchell in St. Louis. Bean holds a Bachelor of Arts degree from the University of Illinois and a Juris Doctorate from Northwestern University School of Law.
Michael V. Altrudo
Senior Vice President & Chief Marketing Officer
Michael V. Altrudo, age 61, serves as Senior Vice President & Chief Marketing Officer. Prior to the spin-off, Altrudo served as marketing advisor to Peabody’s COALTRADE International subsidiary since 2005, with executive advisory responsibilities for its international sales, marketing, trading and brokerage activities. Altrudo previously served as President of Peabody COALTRADE International (2004 to 2005), Senior Vice President, International Sales & Trading, for Peabody COALSALES Company (2004) and Senior Vice President of Sales & Marketing for Appalachia (1999 to 2004). Mr. Altrudo has 29 years of coal industry experience, including sales, marketing, trading and brokerage in the Appalachian thermal coal markets as well as sales and purchases of Appalachian metallurgical coal. He has extensive sales experience in both utility and industrial markets. Prior to joining Peabody in 1999, Altrudo held executive level sales and marketing positions with Zeigler Coal Holding Company, Drummond Company, Nerco Coal Company and Derby Coal Company. Altrudo holds a Bachelor of Science degree in finance from Duquesne University.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
On October 31, 2007, Peabody effected the spin-off of Patriot and its subsidiaries. The spin-off was accomplished through a dividend of all outstanding shares of Patriot Coal Corporation. Our common stock is listed on the New York Stock Exchange, under the symbol “PCX.” As of February 20, 2009, there were 756 holders of record of our common stock.
Effective August 11, 2008, Patriot implemented a 2-for-1 stock split effected in the form of a 100% stock dividend. All share and per share amounts in this Annual Report on Form 10-K reflect this stock split.
The table below sets forth the range of quarterly high and low sales prices for our common stock on the New York Stock Exchange during the calendar quarters indicated.
Dividend Policy
We have not and we do not anticipate that we will pay cash dividends on our common stock in the near term. The declaration and amount of future dividends, if any, will be determined by our Board of Directors and will depend on our financial condition, earnings, capital requirements, financial covenants, regulatory constraints, industry practice and other factors our Board deems relevant.
Stock Performance Graph
The following performance graph compares the cumulative total return on our common stock with the cumulative total return of the following indices: (i) the S&P Smallcap 600 Index and (ii) the Custom Composite Index comprised of Alpha Natural Resources, Inc., Arch Coal, Inc., CONSOL Energy, Inc., Foundation Coal Holding Inc., International Coal Group Inc., James River Coal Co., Massey Energy Company, Peabody Energy Corp. and Westmoreland Coal Company. These indices are included for comparative purposes only and do not necessarily reflect management’s opinion that such indices are an appropriate measure of the relative performance of the stock involved, and are not intended to forecast or be indicative of possible future performance of the common stock.
COMPARISON OF 14 MONTH CUMULATIVE TOTAL RETURN*
Among Patriot Coal Corporation, the S&P Smallcap 600 Index
and a Custom Composit Index
*$100 invested on 11/1/07 in stock & 10/31/07 in index-including reinvestment of dividends.
Fiscal year ending December 31.
Copyright ©
2009 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.
In accordance with SEC rules, the information contained in the Stock Performance Graph above, shall not be deemed to be “soliciting material,” or to be “filed” with the SEC or subject to the SEC’s Regulation 14A or 14C, other than as provided under Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended, except to the extent that the Company specifically requests that the information be treated as soliciting material or specifically incorporates it by reference into a document filed under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.
Item 6.
Item 6.
Selected Consolidated Financial Data.
The following table presents selected financial and other data about us for the most recent five fiscal years. The historical financial and other data have been prepared on a consolidated basis derived from Patriot’s consolidated financial statements using the historical results of operations and bases of the assets and liabilities of Patriot’s businesses and give effect to allocations of expenses from Peabody in 2007, 2006, 2005 and 2004. For periods prior to the spin-off, the historical consolidated statements of income data set forth below do not reflect changes that occurred in the operations and funding of our company as a result of our spin-off from Peabody. Magnum results are consolidated as of the date the acquisition was consummated, July 23, 2008. The historical consolidated balance sheet data set forth below reflect the assets and liabilities that existed as of the dates and the periods presented.
The selected consolidated financial data should be read in conjunction with, and are qualified by reference to, Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the historical financial statements and the accompanying notes thereto of us and our consolidated subsidiaries included elsewhere in this report. The consolidated statements of operations and cash flow data for each of the three years in the period ended December 31, 2008 and the consolidated balance sheet data as of December 31, 2008 and 2007 are derived from our audited consolidated financial statements included elsewhere in this report, and should be read in conjunction with those consolidated financial statements and the accompanying notes. The consolidated balance sheet data as of December 31, 2005 and the consolidated statement of operations for the year ended December 31, 2004 were derived from audited consolidated financial statements that are not presented in this report. The consolidated balance sheet data as of December 31, 2004 was derived from our unaudited financial statements. In management’s opinion, these unaudited consolidated financial statements have been prepared on substantially the same basis as the audited financial statements and include all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the financial data for the periods presented.
The financial information presented below may not reflect what our results of operations, cash flows and financial position would have been had we operated as a separate, stand-alone entity for the years ended December 31, 2007, 2006, 2005 and 2004 or what our results of operations, financial position and cash flows will be in the future. In addition, the Risk Factors section of Item 1A of this report includes a discussion of risk factors that could impact our future results of operations.
(1)
Net gain on disposal or exchange of assets included a $37.4 million gain from an exchange of coal reserves as part of a dispute settlement with a third-party supplier in 2005, gains of $66.6 million from sales of coal reserves and surface lands in 2006 and gains of $78.5 million from the sales of coal reserves and surface land in 2007.
(2)
In March 2006, we increased our 49% interest in KE Ventures, LLC to an effective 73.9% interest and began combining KE Ventures, LLC’s results with ours effective January 1, 2006. In 2007, we purchased the remaining interest. Prior to 2006, KE Ventures, LLC was accounted for on an equity basis and included in income from equity affiliates in our consolidated statements of operations.
(3)
All share and per share amounts reflect the 2-for-1 stock split effected in the form of a 100% stock dividend effective August 11, 2008.
(4)
We adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” on December 31, 2006, and as a result, increased noncurrent liabilities and decreased total invested capital (accumulated other comprehensive loss) by $322.1 million.
(5)
Adjusted EBITDA is defined as net income (loss) before deducting net interest income and expense; income taxes; minority interests; asset retirement obligation expense; depreciation, depletion and amortization; and net sales contract accretion excluding back-to-back coal purchase and sales contracts. The net contract accretion on the back-to-back coal purchase and sale contracts reflects the net accretion related to certain coal purchase and sales contracts existing prior to July 23, 2008, whereby Magnum purchased coal from third parties to fulfill tonnage commitments on sales contracts. Adjusted EBITDA is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. The term Adjusted EBITDA does not purport to be an alternative to operating income, net income or cash flows from operating activities as determined in accordance with GAAP as a measure of profitability or liquidity. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.
Adjusted EBITDA is calculated as follows (unaudited):
(1)
Net sales contract accretion resulted from the below market coal sale and purchase contracts acquired in the Magnum acquisition and was recorded at preliminarily-determined fair values in purchase accounting. The net liability generated from applying fair value to these contracts is being accreted over the life of the contracts as the coal is shipped.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Overview
We are a leading producer of thermal coal in the eastern United States, with operations and coal reserves in Appalachia and the Illinois Basin, our operating segments. We are also a leading U.S. producer of metallurgical quality coal. Our principal business is the mining, preparation and sale of thermal coal, sold primarily to electric utilities, as well as the mining of metallurgical coal, sold to coke producers for use in the steelmaking process. In 2008, we sold 28.5 million tons of coal, of which 79% was sold to electric utilities and 21% was sold to domestic and global steel producers. In 2007, we sold 22.1 million tons of coal, of which 77% was sold to domestic electric utilities and 23% was sold to domestic and global steel producers. We typically sell coal to utility and steel-making customers under contracts with terms of one year or more. Approximately 78% and 83% of our sales were under such contracts during 2008 and 2007, respectively.
Our operations consist of sixteen mining complexes, which include company-operated mines, contractor-operated mines and coal preparation facilities. The Appalachia and Illinois Basin segments consist of our operations in West Virginia and Kentucky, respectively. We ship coal to electric utilities, industrial users and metallurgical coal customers via various company-owned and third-party loading facilities and multiple rail and river transportation routes.
Effective October 31, 2007, Patriot was spun off from Peabody Energy Corporation (Peabody). The spin-off was accomplished through a dividend of all outstanding shares of Patriot, resulting in Patriot becoming a separate, public company traded on the New York Stock Exchange (symbol PCX).
On July 23, 2008, Patriot completed the acquisition of Magnum Coal Company (Magnum). Magnum was one of the largest coal producers in Appalachia, operating 11 mines and 7 preparation plants with production from surface and underground mines and controlling more than 600 million tons of proven and probable coal reserves. Magnum’s results are included as of the date the acquisition was consummated, July 23, 2008.
Effective August 11, 2008, Patriot implemented a 2-for-1 stock split effected in the form of a 100% stock dividend. All share and per share amounts in this Annual Report on Form 10-K reflect this stock split.
Basis of Presentation Related to Periods Prior to the Spin-Off from Peabody
The statements of operations and cash flows for the twelve months ended December 31, 2007 and 2006, and related discussions below primarily relate to our historical results prior to the spin-off from Peabody. These results may not necessarily reflect what our results of operations and cash flows would have been as a stand-alone company. The consolidated financial statements presented herein for these periods include allocations of Peabody expenses, assets and liabilities through the date of the spin-off, including the following items:
Selling and Administrative Expenses
For the periods prior to spin-off, our historical selling and administrative expenses were based on an allocation of Peabody general corporate expenses to all of its mining operations, both foreign and domestic, based on principal activity, headcount, tons sold or revenues as appropriate. The allocated expenses generally reflect service costs for marketing and sales, general accounting, legal, finance and treasury, public relations, human resources, environmental, engineering and internal audit.
Interest Expense
For the periods prior to the spin-off, our historical interest expense primarily related to fees for letters of credit and surety bonds used to guarantee our reclamation, workers’ compensation, retiree healthcare and lease obligations as well as interest expense related to intercompany notes with Peabody. Our capital structure changed following our spin-off from Peabody, and effective October 31, 2007, we entered into a four-year revolving credit facility. See Liquidity and Capital Resources - Credit Facility for information about our credit facility. The intercompany notes totaling $62.0 million with Peabody were forgiven at spin-off.
Income Tax Provision
Income taxes are accounted for using a balance sheet approach in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). We account for deferred income taxes by applying statutory tax rates in effect at the date of the balance sheet to differences between the book and tax basis of assets and liabilities. A valuation allowance is established if it is “more likely than not” that the related tax benefits will not be realized. In determining the appropriate valuation allowance, we consider projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies and the overall deferred tax position.
SFAS No. 109 specifies that the amount of current and deferred tax expense for an income tax return group are to be allocated among the members of that group when those members issue separate financial statements. For purposes of the consolidated financial statements prepared for the twelve months ended December 31, 2007 and for the other periods prior to the spin-off, our income tax expense has been recorded as if we filed a consolidated tax return separate from Peabody, notwithstanding that a majority of the operations were historically included in the U.S. consolidated income tax return filed by Peabody. Our valuation allowance for these periods was also determined on the separate tax return basis. Additionally, our tax attributes (i.e. net operating losses and Alternative Minimum Tax credits) for these periods have been determined based on U.S. consolidated tax rules describing the apportionment of these items upon departure (i.e. spin-off) from the Peabody consolidated group.
Peabody was managing its tax position for the benefit of its entire portfolio of businesses. Peabody’s tax strategies are not necessarily reflective of the tax strategies that we would have followed or will follow as a stand-alone company, nor were they necessarily strategies that optimized our stand-alone position.
Results of Operations
Segment Adjusted EBITDA
The discussion of our results of operations below includes references to and analysis of our Appalachia and Illinois Basin Segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as net income (loss) before deducting net interest income and expense; income taxes; minority interests; asset retirement obligation expense; depreciation, depletion and amortization; and net sales contract accretion excluding back-to-back coal purchase and sales contracts. The net contract accretion on the back-to-back coal purchase and sale contracts reflects the net
accretion related to certain coal purchase and sales contracts existing prior to July 23, 2008, whereby Magnum purchased coal from third parties to fulfill tonnage commitments on sales contracts. Segment Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Because Segment Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is reconciled to its most comparable measure under generally accepted accounting principles in Item 6. Selected Consolidated Financial Data. Segment Adjusted EBITDA excludes selling, general and administrative expenses, past mining obligation expense and gain on disposal or exchange of assets and is reconciled to its most comparable measure below under Net Income (Loss).
Geologic Conditions
Our results of operations are impacted by geologic conditions as they relate to coal mining, and these conditions refer to the physical nature of the coal seam and surrounding strata and its effect on the mining process. Geologic conditions that can have an adverse effect on underground mining include thinning coal seam thickness, rock partings within a coal seam, weak roof or floor rock, sandstone channel intrusions, groundwater and increased stresses within the surrounding rock mass due to over mining, under mining and overburden changes. The term “adverse geologic conditions” is used in general to refer to these and similar situations where the geologic setting can negatively affect the normal mining process. Adverse geologic conditions would be markedly different from those that would be considered typical geological conditions for a given mine. Since approximately 75% of our 2008 production is sourced from underground operations, geologic conditions are a major factor in our results of operations.
Year ended December 31, 2008 compared to year ended December 31, 2007
Summary
Revenues were $1,654.6 million, an increase of $581.3 million, and Segment Adjusted EBITDA was $186.1 million, an increase of $84.4 million, for the year ended December 31, 2008. Net income was $146.9 million in 2008 compared to a net loss of $106.9 million in the prior year. The increase in revenue, Segment Adjusted EBITDA and net income was mainly driven by the newly-acquired Magnum operations including the impact of purchase accounting. The results of operations of Magnum are included in the Appalachia Mining Operations segment from the date of acquisition.
2008 was a volatile year in the coal markets. Coal prices significantly increased during the first half of the year, peaked in July and then declined in the later part of the year in conjunction with the overall economic downturn. Sales for our Appalachia and Illinois Basin segments reflected higher contract and spot prices. Offsetting this increase, several of our mining complexes experienced adverse geologic conditions that impacted production levels as well as higher costs related to labor, fuel, and materials and supplies.
Tons Sold and Revenues
The increase in Appalachia revenue for the year ended December 31, 2008 compared to the prior year primarily related to $413.0 million of sales associated with the newly-acquired Magnum operations. Excluding the impact of Magnum, revenues were also affected by higher average sales prices, partially offset by lower sales volumes at the Federal and Rocklick mining complexes.
Average sales prices increased at our mining complexes, reflecting higher sales contract pricing, including the repricing of a major coal supply agreement with Peabody as part of the spin-off, and cost recovery under certain contracts for increased regulatory costs.
Sales volumes in the Appalachia segment increased in 2008, primarily due to 7.2 million tons sold from the newly-acquired Magnum operations. Excluding Magnum, sales volume decreased primarily due to production shortfalls at our Federal complex, the completion of the final longwall panel at the Harris mine during the second quarter, labor shortages for much of the year and reduced productivity at several mines.
Illinois Basin revenue increased in 2008 primarily related to higher average sales prices. Compared to the prior year, sales volumes increased slightly.
Other Appalachia revenues increased in 2008. In addition to increased royalty income, other revenues included a structured settlement on a property transaction, a settlement for past due coal royalties, which had previously been fully reserved due to the uncertainty of collection, and gains on the sale of purchased coal in the first quarter.
Segment Adjusted EBITDA
Segment Adjusted EBITDA for Appalachia increased in 2008 from the prior year primarily due to the contribution from the newly-acquired Magnum operations and, to a lesser extent, higher sales prices, partially offset by lower sales volumes and higher operating costs. Higher operating costs related to start-up costs as we ramped up production at our Big Mountain and Kanawha Eagle mining complexes, as well as higher contract mining costs primarily related to higher material and supply and labor costs. Material and supply costs were primarily impacted
by higher fuel, explosives and steel-related costs. Higher labor costs were reflective of an overall labor shortage in the Appalachia region. Segment Adjusted EBITDA for Appalachia also increased in 2008 due to the previously mentioned gains on the sale of purchased coal in the first quarter and the structured settlements in the second quarter.
Segment Adjusted EBITDA for the Illinois Basin increased in 2008 primarily due to higher average sales prices, offset by increased labor costs and higher fuel, explosives and steel-related costs.
Net Income (Loss)
Past Mining Obligation Expense
Past mining obligation expenses were lower in 2008 than the prior year primarily due to the retention by Peabody of a portion of the retiree healthcare liability at spin-off and a higher discount rate associated with the 2008 expenses. Past mining obligation expense at the newly-acquired Magnum operations totaled $19.0 million for the period beginning July 23, 2008, the acquisition date, primarily associated with retiree healthcare liabilities.
Net Gain on Disposal or Exchange of Assets
Net gain on disposal or exchange of assets was $74.5 million lower for 2008 compared to the prior year. The net gain on disposal or exchange of assets for 2008 included a $6.3 million gain on the exchange/sale of certain leasehold mineral interests. The net gain on disposal or exchange of assets for 2007 included coal reserve transactions that resulted in gains of $78.5 million.
Selling and Administrative Expenses
Our historical selling and administrative expenses for the year ended December 31, 2007 were based on an allocation of Peabody general corporate expenses to all of its mining operations, both foreign and domestic. Selling and administrative expenses for the year ended December 31, 2008 represent our actual expenses incurred as a
stand-alone company, including expenses from the newly-acquired Magnum operations, which overall were lower than the prior year allocation.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for 2008 increased compared to the prior year primarily due to the additional sales volume associated with the acquisition of Magnum.
Sales Contract Accretion
Sales contract accretion resulted from the below market coal sale and purchase contracts acquired in the Magnum acquisition and recorded at preliminarily-determined fair values in purchase accounting. The net liability generated from applying fair value to these contracts is being accreted over the life of the contracts as the coal is shipped.
Asset Retirement Obligation Expense
Asset retirement obligation expense decreased in 2008 compared to the prior year primarily due to accelerated reclamation work at closed mines in the first half of 2007, the acceleration of a mine closure in early 2007, and the extension of the life of our Federal mine in mid-2007 as a result of the acquisition of adjoining coal reserves, largely offset by expenses related to the newly-acquired Magnum operations.
Interest Expense (Income)
Interest expense increased for 2008 compared to the prior year primarily due to interest and amortized origination debt fees related to our credit facility, put in place at the time of the spin-off, as well as interest and amortized origination debt fees related to our newly-issued convertible debt and a commitment fee expensed in the second quarter due to the termination of a bridge loan facility related to the Magnum acquisition. This increase was partially offset by a reduction to interest expense in 2008 as a demand note with Peabody was forgiven at the spin-off, resulting in no similar interest expense in 2008. See Liquidity and Capital Resources for details concerning our outstanding debt and credit facility.
Interest income increased in 2008 compared to the prior year due to interest on a Black Lung excise tax refund. In addition, the Company recognized a full year of interest income on notes receivable that resulted from the sale of coal reserves in the first half of 2007.
Income Tax Provision
For the years ended December 31, 2008 and 2007, no income tax provision was recorded due to net operating losses for the year and our full valuation allowance recorded against deferred tax assets. For 2008, the primary difference between book and taxable income was the treatment of the net sales contract accretion on the below market purchase and sales contracts acquired in the Magnum acquisition, with such amounts being included in the computation of book income but excluded from the computation of taxable income.
Minority Interests
We acquired an effective controlling interest in KE Ventures, LLC during the first quarter of 2006, and began consolidating KE Ventures, LLC in our results in 2006. The portion of earnings that represents the interests of the minority owners was deducted from our income (loss) before income taxes and minority interests to determine net income (loss). The minority interest recorded in 2007 represented the share of KE Ventures, LLC earnings in which the minority holders were entitled to participate. In the fourth quarter of 2007, we increased our ownership in KE Ventures to 100%.
Effect of Minority Purchase Arrangement
At the spin-off, the minority interest holders of KE Ventures, LLC held an option that could require Patriot to purchase the remaining 18.5% of KE Ventures, LLC upon a change in control. Upon the spin-off from Peabody, the minority owners of KE Ventures, LLC exercised this option, and we acquired the remaining minority interest in KE
Ventures, LLC on November 30, 2007 for $33.0 million. Because the option requiring Patriot to purchase KE Ventures, LLC is considered a mandatorily redeemable instrument outside of our control, amounts paid to the minority interest holders in excess of carrying value of the minority interests in KE Ventures, LLC, or $15.7 million, was reflected as an increase in net loss attributable to common stockholders in 2007. This obligation was fully redeemed as of December 31, 2007.
Year ended December 31, 2007 compared to year ended December 31, 2006
Summary
Revenues were $1,073.4 million and Segment Adjusted EBITDA was $101.7 million for the year ended December 31, 2007, both lower than the prior year primarily driven by lower sales volumes due to production shortfalls. Production shortfalls resulted from a delayed longwall move at one of our mines and increased levels of adverse geologic conditions including excessive groundwater from heavy spring rains, roof falls and roof partings. Net loss was $106.9 million in 2007 compared to $13.5 million in the prior year. The increased net loss was mainly driven by the lower sales volumes and higher operating costs.
Tons Sold and Revenues
The decrease in the Appalachia revenue for the year ended December 31, 2007 compared to the prior year reflected lower sales volumes driven by adverse geologic conditions, a delayed longwall move at one of our mines, and the loss of a coal supplier in late 2006, partially offset by additional volumes from the Black Stallion contract mine, which began production in the third quarter of 2006. Adverse geologic conditions included roof falls and partings that reduced saleable coal yields.
The decrease in the Illinois Basin revenue for the year ended December 31, 2007 compared to the prior year reflected reduced sales volumes associated mainly with the closure of the Big Run mine, partially offset by higher pricing principally resulting from a price increase on a long-term contract under the market price adjustment provision of the contract.
Segment Adjusted EBITDA
Segment Adjusted EBITDA for Appalachia decreased in 2007 from the prior year primarily due to lower sales volume as described above and higher operating costs primarily due to additional materials and supplies required for the delayed longwall move at one of our mines, roof control, equipment repair and maintenance, as well as higher labor expenses related to a labor agreement that became effective on January 1, 2007, partially offset by lower revenue-based taxes and royalties.
Segment Adjusted EBITDA for the Illinois Basin increased in 2007 from the prior year primarily due to the higher average sales price as discussed above. Operating costs decreased in 2007 compared to the prior year primarily due to the closure of the Big Run mine, partially offset by higher costs related to preparation plant maintenance and additional equipment requirements at one of our mines associated with roof falls and excessive water.
Net Income (Loss)
Past Mining Obligation Expense
Past mining obligation expenses were higher in 2007 than the prior year primarily due to higher retiree healthcare costs resulting from higher amortization of actuarial loss and increased funding for multi-employer healthcare and pension plans in accordance with provisions of 2006 legislation and the 2007 NBCWA (effective January 1, 2007). Our 2007 and 2006 operating costs included approximately $51.9 million and $46.1 million, respectively, for certain retiree healthcare obligation expenses that would have been assumed by Peabody had the proposed spin-off occurred at the beginning of each period.
Net Gain on Disposal of Assets
Net gain on disposal of assets was $2.8 million higher for 2007. The net gain for the 2007 period was attributable principally to the sale of 88 million tons of coal reserves, and surface land in Kentucky and the Big Run mine for $26.5 million in cash and $69.4 million in notes receivable which resulted in a gain of $78.5 million. The
net gain for the 2006 period was primarily attributable to the sale of coal reserves and surface land located in Kentucky and West Virginia for proceeds of $84.9 million, including cash of $31.8 million and notes receivable of $53.1 million which resulted in a gain of $66.6 million. Property sales in 2007 and 2006 are not indicative of the level we would expect on an ongoing basis.
Selling and Administrative Expenses
For the period prior to the spin-off, our historical selling and administrative expenses are based on an allocation of Peabody general corporate expenses to all of its mining operations, both foreign and domestic. The decrease of $2.8 million in 2007 compared to 2006 reflected changes in Peabody’s allocable selling and administrative expenses as well as changes to the allocation base. These allocated expenses are not necessarily indicative of the costs we would incur as a stand-alone company.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for 2007 decreased slightly compared to 2006 primarily due to the closure of the Big Run mine.
Asset Retirement Obligation Expense
Asset retirement obligation expense decreased in 2007 compared to the prior year primarily due to accelerated reclamation work at closed mines in 2006 with less activity in 2007.
Interest Expense (Income)
Third party interest expense decreased in 2007 as KE Ventures, LLC repaid $23.8 million in bank loans in the second half of 2006 and replaced the bank debt with a Peabody note which was subsequently forgiven at spin-off.
Interest income increased in 2007 compared to the prior year due to additional interest income on notes receivable that resulted from the sale of Kentucky coal reserves in the second half of 2006 and the first half of 2007.
Income Tax Provision
In 2006, we incurred $8.4 million of tax obligation for federal taxes from the disposal of assets and the preference limitation on percentage depletion. Patriot was included in Peabody’s consolidated group during 2006 and the consolidated group had sufficient net operating losses available to offset the taxable income of Patriot, so this tax obligation did not require Patriot to make cash payments.
Minority Interests
We acquired an effective controlling interest in KE Ventures, LLC during the first quarter of 2006, and began consolidating KE Ventures, LLC in our results in 2006. The portion of earnings that represents the interests of the minority owners was deducted from our income (loss) before income taxes and minority interests to determine net income (loss). The minority interest recorded in 2007 and 2006 represented the share of KE Ventures, LLC earnings in which the minority holders were entitled to participate. In the fourth quarter of 2007, we increased our ownership in KE Ventures to 100%.
Effect of Minority Purchase Arrangement
Upon the spin-off from Peabody, the minority interest holders of KE Ventures, LLC held an option that could require Patriot to purchase the remaining 18.5% of KE Ventures, LLC upon a change in control. The minority owners of KE Ventures, LLC exercised this option in 2007, and we acquired the remaining minority interest in KE Ventures, LLC on November 30, 2007 for $33.0 million. Because the option requiring Patriot to purchase KE Ventures, LLC is considered a mandatorily redeemable instrument outside of our control, amounts paid to the minority interest holders in excess of carrying value of the minority interests in KE Ventures, LLC, or $15.7 million, was reflected as an increase in net loss attributable to common stockholders in 2007. This obligation was fully redeemed as of December 31, 2007.
Outlook
Market
The recent global recession resulted in decreased demand worldwide for steel and electricity beginning in the third quarter of 2008. Since the beginning of the fourth quarter, production utilization at U.S. steel mills has dropped from approximately 83% to 44%. Globally, blast furnace iron production decreased 16% during the fourth quarter. As a result, domestic and international steel mills have significantly reduced coal purchases.
Historically, during periods of economic downturn, world demand for basic inputs, including for electricity and steel production, have decreased. Traded prices for thermal coal delivered into northern Europe decreased 45% during the fourth quarter of 2008. U.S. producers that previously sold into the export thermal market are now selling their coals into the U.S. thermal market. Additionally, increased production and decreased industrial demand of natural gas have caused natural gas prices to decrease 25% during the fourth quarter of 2008. At the same time, electricity consumption declined 1.6% in the fourth quarter of 2008 compared to the prior year. As a result of the redirected export and metallurgical coal shipments, decreased natural gas prices and lower coal-fueled electricity demand, traded U.S. thermal coal prices have fallen approximately 50% since the beginning of the fourth quarter.
Throughout the industry, mines will likely close and expansions will be curtailed if coal prices fall below marginal costs. In the U.S. and internationally, approximately 37 and 22 million tons, respectively, of production cuts for 2009 have been announced. In the U.S., mine closures have been a mix of thermal and metallurgical coal, while most international mine closures have been at Australian, Canadian and Russian metallurgical coal mines. Additional reductions are expected during 2009 as suppliers react to lower demand and pricing.
As the result of lower coal-fueled generation, eastern U.S. utility coal stockpiles grew 20% during the fourth quarter of 2008. However, eastern coal inventories were only 1.9 million tons higher than a year ago and are at the approximate mid-point of their five year range.
While the weak global economy is negatively affecting the coal industry in the short-term, coal’s long-term future remains positive. Prior to the recent economic recession, international coal markets had been growing, driven by increased demand from the growing economies of China and India where coal is both the primary domestic source of fuel and the lowest-cost imported fuel for electricity generation. We do not currently sell coal into China, but Chinese demand is important in determining worldwide coal prices and global supply. Prior to the recent economic recession, domestic demand increases in South Africa, Vietnam, and Russia had also resulted in lower exports from those countries. Brazil had been experiencing increased steel production resulting in the need for more coal imports. Additionally, the coal industries in Germany and Poland have been shutting down as their coal reserves deplete, and coal exports from Australia, a major coal producer, have been impacted by infrastructure limitations driven by rail and port constraints. We believe that as the economy recovers, supply and demand will come back into balance. Further, mine closures in 2009 should accelerate the return to market equilibrium.
Patriot Operations
As discussed more fully under Item 1A. Risk Factors, our results of operations in the near-term could be negatively impacted by unforeseen adverse geologic conditions or equipment problems at mining locations; increased labor costs due to the shortage of skilled labor; the inability of contract miners to fulfill delivery terms of their contracts; delays in obtaining required permits for new mining operations; coal mining laws and regulations; rising prices of key supplies, mining equipment and commodities; the unavailability of transportation for coal shipments; the availability and costs of credit, surety bonds and letters of credit; and the recent economic recession. On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves; our ability to attract and retain skilled employees and contract miners; our ability to find replacement buyers for coal under contracts with comparable terms to existing contracts; and the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs, or limit our customers’ ability to utilize coal as fuel for electricity generation. If 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. In 2008, we experienced higher costs related to steel-related products (including roof control), replacement parts, belting products, fuel, explosives, contract mining and healthcare. However, these prices
declined during the second half of 2008. In conjunction with a comprehensive strategic review of operations upon acquisition of Magnum, management has continued to focus on controlling costs and optimizing performance.
In light of the Magnum acquisition, we have performed a comprehensive strategic review of our mining complexes and their relative cost structures. We announced the idling of our Jupiter mining complex in October 2008. In January 2009, we announced the idling of our Remington mining complex and Black Oak mine and reduced activity at the Rocklick preparation plant. We are reacting to the changes in demand by refining our production plans and optimizing our mining complexes with the goal of becoming more cost-competitive.
Operationally, we have experienced adverse geologic conditions that have impacted our Federal and Panther longwall operations and accordingly, our financial results during 2008. In the fourth quarter of 2008, we upgraded our longwall shearer at the Panther complex. We anticipate improved mining conditions at both the Federal and Panther complexes by the end of the first quarter of 2009. We have adjusted the mine plan for future panels at both complexes to minimize the impact of difficult geology.
Our industry continues to face new regulations and more aggressive enforcement surrounding both environmental and mining statutes. With this more costly regulatory landscape, we are aggressively seeking customer reimbursement under applicable coal supply agreements. We are also actively pursuing the restructuring of certain below-market legacy coal supply agreements.
We are targeting 2009 sales volume of 36 to 38 million tons. As of December 31, 2008, our total unpriced planned production for 2009 included up to 2.0 million tons of met volumes and up to 1.0 million tons of thermal volumes. Of expected 2010 volumes, up to 7.0 million tons of met and up to 12.0 million tons of thermal volumes remained unpriced as of December 31, 2008.
The guidance provided under the caption Outlook should be read in conjunction with the section entitled Cautionary Notice Regarding Forward Looking Statements on page 2 and Item 1A. Risk Factors. Actual events and results may vary significantly from those included in or contemplated or implied by the forward-looking statements under Outlook. For additional information regarding some of the risks and uncertainties that affect our business, see Item 1A. Risk Factors.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require 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 evaluate our estimates on an on-going basis. We base our estimates on historical experience and on various other assumptions 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. Actual results may differ from these estimates.
Employee-Related Liabilities
We have significant long-term liabilities for our employees’ postretirement benefit costs and workers’ compensation obligations. Detailed information related to these liabilities is included in Notes 15 and 17 to our consolidated financial statements. Expense for the year ended December 31, 2008 for these liabilities totaled $91.1 million, while payments were $70.3 million.
Our postretirement benefit and certain components of our workers’ compensation obligations are actuarially determined, and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for these items. Our discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service our liabilities. We make assumptions related to future trends for medical care costs in the estimates of retiree healthcare and work-related injuries and illness obligations. Our medical trend assumption is developed by annually examining the historical trend of our cost per claim data.
If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our obligation to satisfy these or additional obligations. Our most significant employee liability is postretirement healthcare. Assumed discount rates and healthcare cost trend rates have a significant effect on the expense and liability amounts reported for healthcare plans. Below we have provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.
Healthcare cost trend rate:
Discount rate:
Asset Retirement Obligations
Our asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both underground and surface mines in accordance with federal and state reclamation laws as defined by each mining permit. Asset retirement obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage, the timing of these cash flows, and a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of the reclamation activities), the obligation and asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Asset retirement obligation expense for the year ended December 31, 2008, was $19.3 million, and payments totaled $6.5 million. See detailed information regarding our asset retirement obligations in Note 14 to our consolidated financial statements.
Income Taxes
We account for income taxes in accordance with SFAS No. 109, which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be 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 our annual evaluation of the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in our annual evaluation of our valuation allowance, we may record a change in valuation allowance through income tax expense in the period this determination is made. As of December 31, 2008 and 2007, we maintained a full valuation allowance against our net deferred tax assets.
We have also adopted Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” (FIN No. 48). This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.
Additional detail regarding how we account for income taxes and the effect of income taxes on our consolidated financial statements is available in Note 12.
Revenue Recognition
In general, we recognize revenues when they are realizable and earned. We generated substantially all of our revenue in 2008 from the sale of coal to our customers. Revenue from coal sales is realized and earned when risk of loss passes to the customer. Coal sales are made to our customers under the terms of coal supply agreements, most of which have a term of one year or more. Under the typical terms of these coal supply agreements, risk of loss transfers to the customer at the mine or port, where coal is loaded to the rail, barge, ocean-going vessel, truck or other transportation source that delivers coal to its destination.
With respect to other revenues, other operating income, or gains on asset sales recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and apply the relevant accounting literature as appropriate. We 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 seller’s price to the buyer is fixed or determinable; and collectability is reasonably assured.
Share-Based Compensation
We have an equity incentive plan for employees and eligible non-employee directors that allows for the issuance of share-based compensation in the form of restricted stock, incentive stock options, nonqualified stock options, stock appreciation rights, performance awards, restricted stock units and deferred stock units. We recognize share-based compensation expense in accordance with SFAS No. 123(R), “Share-Based Payment”. We utilize the Black-Scholes option pricing model to determine the fair value of stock options. Determining the fair value of share-based awards requires judgment, including estimating the expected term that stock options will be outstanding prior to exercise, the associated volatility, and a risk-free rate. Judgment is also required in estimating the amount of share-based awards expected to be forfeited prior to vesting. If actual forfeitures differ significantly from these estimates, share-based compensation expense could be materially impacted.
Impairment of Long-Lived Assets
Impairment losses on long-lived assets used in operations are recorded when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those assets under various assumptions are less than the carrying amounts of those assets. Impairment losses are measured by comparing the estimated fair value of the impaired asset to its carrying amount. There were no impairment losses recorded during the periods covered by the consolidated financial statements.
Business Combinations
We account for our business acquisitions using the purchase method of accounting consistent with the requirements of SFAS No. 141, “Business Combinations”. Under this method of accounting, the purchase price is allocated to the fair value of the net assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including, but not limited to, assumptions with respect to future cash flows, discount rates and asset lives.
Liquidity and Capital Resources
Our primary sources of cash include sales of our coal production to customers, sales of non-core assets and financing transactions. Our primary uses of cash include our cash costs of coal production, capital expenditures, interest costs and costs related to past mining obligations as well as acquisitions. Our ability to service our debt (interest and principal) and acquire new productive assets or businesses is dependent upon our ability to continue to generate cash from the primary sources noted above in excess of the primary uses. We expect to fund our capital expenditure requirements with cash generated from operations or borrowed funds as necessary.
Net cash provided by operating activities was $63.4 million for the year ended December 31, 2008, an increase of $143.1 million compared to the prior year. This increase in net cash provided related to improved operating results of $82.1 million, as well as positive working capital changes of $61.0 million.
Net cash used in investing activities was $138.7 million for the year ended December 31, 2008, a decrease of $193.4 million compared to cash provided by investing activities of $54.7 million in the prior year. The increase in cash used reflected higher capital expenditures of $65.8 million, a decrease to net transactions with Peabody of $132.6 million, and lower cash proceeds from disposals of assets of $27.3 million, partially offset by an increase in cash provided by acquisitions of $59.2 million. Additionally in 2008, $16.3 million was used for investment in joint ventures.
Net cash provided by financing activities was $72.1 million for the year ended December 31, 2008, an increase of $41.6 million compared to the prior year. In 2008 we received $200.0 million in gross proceeds from the convertible note as well as $23.0 million in short-term borrowings on our credit facility, offset by the termination of Magnum’s debt facility of $136.8 million and a net decrease in cash contributions from Peabody of $43.7 million.
Promissory Notes
In conjunction with an exchange transaction involving the acquisition of Illinois Basin coal reserves in 2005, the Company entered into Promissory Notes. Annual installments of $1.7 million on the Promissory Notes for principal and interest are payable beginning in January 2008 and running through January 2017. At December 31, 2008, the balance on the Promissory Notes was $11.4 million, $1.0 million of which was a current liability.
Credit Facility
Effective October 31, 2007, we entered into a $500 million, four-year revolving credit facility, which includes a $50 million swingline sub-facility and a letter of credit facility. This facility is available for our working capital requirements, capital expenditures and other corporate purposes. As of December 31, 2008 the balance of outstanding letters of credit issued against the credit facility totaled $351 million, and $23 million short-term borrowings were outstanding under the facility. Availability under the credit facility as of December 31, 2008 was $126 million.
The obligations under our credit facility are secured by a first lien on substantially all of our assets, including but not limited to certain of our mines and coal reserves and related fixtures and accounts receivable. The credit facility contains certain customary covenants, including financial covenants limiting our total indebtedness (maximum leverage ratio of 2.75) and requiring minimum EBITDA coverage of interest expense (minimum interest coverage ratio of 4.0), as well as certain limitations on, among other things, additional debt, liens, investments, acquisitions and capital expenditures, future dividends and asset sales. The credit facility calls for quarterly reporting of compliance with financial covenants. The financial covenants are calculated based on pro forma results as if we acquired Magnum on January 1, 2008 and EBITDA as defined by the credit agreement. The terms of the credit facility also contain certain customary events of default, which will give the lender the right to accelerate payments of outstanding debt in certain circumstances. Customary events of default include breach of covenants, failure to maintain required ratios, failure to make principal payments or to make interest or fee payments within a grace period, and default, beyond any applicable grace period, on any of our other indebtedness exceeding a certain amount.
In connection with the merger agreement with Magnum, Patriot entered into an amendment dated as of April 2, 2008 to the credit facility. The amendment among other things, (i) permitted the merger with Magnum and the transactions contemplated by the merger agreement, (ii) increased the rate of interest applicable to loans and letters of credit fees under the credit facility and (iii) modified certain covenants and related definitions to allow for changes in permitted indebtedness, permitted liens, permitted capital expenditures and other changes in respect of us and our subsidiaries in connection with the acquisition. The increase in the interest rate and the covenant modifications were effective with the closing of the acquisition. In connection with Patriot’s issuance of the convertible notes discussed below, Patriot entered into an amendment to the credit facility dated as of May 19, 2008, allowing the issuance of the convertible notes and modifying certain covenants for the period prior to the closing of the Magnum acquisition. On September 25, 2008, Patriot entered into an amendment to the credit facility allowing,
among other things, permitted securitization programs without adjusting the capacity of the credit facility. At December 31, 2008, we were in compliance with the covenants of our amended credit facility.
Private Convertible Notes Issuance
On May 28, 2008, Patriot completed a private offering of $200 million in aggregate principal amount of 3.25% Convertible Senior Notes due 2013 (the notes), including $25 million related to the underwriters’ overallotment option. The net proceeds of the offering were $193.5 million after deducting the initial purchasers’ commissions and fees and expenses of the offering.
Interest on the notes is payable semi-annually in arrears on May 31 and November 30 of each year, beginning November 30, 2008. The notes mature on May 31, 2013, unless converted, repurchased or redeemed in accordance with their terms prior to such date. The notes are senior unsecured obligations and rank equally with all of our existing and future senior debt and are senior to any subordinated debt. Patriot used the proceeds of the offering to repay Magnum’s existing senior secured indebtedness and acquisition related fees and expenses. All remaining amounts were used for other general corporate purposes.
The notes are convertible into cash and, if applicable, shares of Patriot’s common stock during the period from issuance to February 15, 2013, subject to certain conditions of conversion as described below. The conversion rate for the notes is 14.7778 shares of Patriot’s common stock per $1,000 principal amount of notes, which is equivalent to a conversion price of approximately $67.67 per share of common stock. The conversion rate and the conversion price are subject to adjustment for certain dilutive events, such as a future stock split or a distribution of a stock dividend.
The notes require Patriot to settle all conversions by paying cash for the lesser of the principal amount or the conversion value of the notes, and by settling any excess of the conversion value over the principal amount in cash or shares, at our option.
Holders of the notes may convert their notes prior to the close of business on the business day immediately preceding February 15, 2013, only under the following circumstances: (1) during the five trading day period after any ten consecutive trading day period (the measurement period) in which the trading price per note for each trading day of that measurement period was less than 97% of the product of the last reported sale price of Patriot’s common stock and the conversion rate on each such trading day; (2) during any calendar quarter after the calendar quarter ending September 30, 2008, and only during such calendar quarter, if the last reported sale price of Patriot’s common stock for 20 or more trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the conversion price in effect on each such trading day; (3) if such holder’s notes have been called for redemption or (4) upon the occurrence of corporate events specified in the indenture. The notes will be convertible, regardless of the foregoing circumstances, at any time from, and including, February 15, 2013 until the close of business on the business day immediately preceding the maturity date.
The number of shares of Patriot’s common stock that we may deliver upon conversion will depend on the price of its common stock during an observation period as described in the indenture. Specifically, the number of shares deliverable upon conversion will increase as the common stock price increases above the conversion price of $67.67 per share during the observation period. The maximum number of shares that Patriot may deliver is 2,955,560. However, if certain fundamental changes occur in Patriot’s business that are deemed “make-whole fundamental changes” in the indenture, the number of shares deliverable on conversion may increase, up to a maximum amount of 4,137,788 shares. These maximum amounts are subject to adjustment for certain dilutive events, such as a stock split or a distribution of a stock dividend.
Holders of the notes may require Patriot to repurchase all or a portion of their notes upon a fundamental change in Patriot’s business, as defined in the indenture. The holders would receive cash for 100% of the principal amount of the notes, plus any accrued and unpaid interest.
Patriot may redeem (i) some or all of the notes at any time on or after May 31, 2011, but only if the last reported sale price of Patriot’s common stock for 20 or more trading days in a period of 30 consecutive trading days ending on the trading day prior to the date Patriot provides the relevant notice of redemption exceeds 130% of the
conversion price in effect on each such trading day, or (ii) all of the notes if at any time less than $20 million in aggregate principal amount of notes remain outstanding. In both cases, notes will be redeemed for cash at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus any accrued and unpaid interest up to, but excluding, the relevant redemption date.
Under the indenture for the notes, if Patriot fails to timely file any document or report required to be filed with the Securities and Exchange Commission pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, (other than reports on Form 8-K), Patriot is required to pay additional interest on the notes of 0.50% of the principal balance of the notes. Per the guidance set forth in SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), this additional interest feature is considered an embedded derivative. Management has determined the fair value of this embedded derivative is de minimis as the probability of reports not being filed timely is remote and we have no history of late submissions.
The notes and any shares of common stock issuable upon conversion have not been registered under the Securities Act of 1933, as amended (the Securities Act), or any state securities laws. The notes were only offered to qualified institutional buyers pursuant to Rule 144A promulgated under the Securities Act.
See Note 3 for additional information regarding changes in the accounting for Patriot’s convertible notes pursuant to recent accounting pronouncements.
Bridge Loan Facility
In connection with the Magnum acquisition agreement, Patriot obtained a subordinated bridge loan financing commitment, allowing us to draw up to $150 million under the related bridge loan facility at the effective date of the acquisition to repay a portion of the outstanding debt of Magnum. Patriot terminated the financing commitment on May 30, 2008, as a result of the notes issuance. Patriot paid $1.5 million in commitment fees in connection with the financing commitment, which were included in “Interest expense” in the consolidated statements of operations.
Other
We do not anticipate that we will pay cash dividends on our common stock in the near term. The declaration and amount of future dividends, if any, will be determined by our Board of Directors and will be dependent upon covenant limitations in our credit facility and other debt agreements, our financial condition and future earnings, our capital, legal and regulatory requirements, and other factors our Board deems relevant.
Contractual Obligations
(1)
Represents long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses and mine reclamation and end-of-mine closure costs.
As of December 31, 2008, we had $68.1 million of purchase obligations for capital expenditures. Total capital expenditures for 2009 are expected to range from $100 million to $125 million and relate to replacement, improvement, or expansion of existing mines as well as the development of the Blue Creek and Hill Fork mines. Approximately $14 million of the expected capital expenditures relate to safety equipment that will be utilized to comply with recently issued federal and state regulations.
Off-Balance Sheet Arrangements and Guarantees
In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, 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, and we do not expect any material adverse effect on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.
Patriot has used a combination of surety bonds and letters of credit to secure our financial obligations for reclamation, workers’ compensation, postretirement benefits and lease obligations as follows as of December 31, 2008:
(1)
Includes collateral for surety companies and bank guarantees, road maintenance and performance guarantees.
Additionally, as of December 31, 2007, Peabody continued to guarantee certain bonds (self bonding) related to Patriot liabilities that had not yet been replaced by our surety bonds. As of December 31, 2007, Peabody self bonding related to Patriot liabilities aggregated $22.8 million, of which $19.9 million was for post-mining reclamation and $2.9 million was for other obligations. Patriot replaced these Peabody self bonds in 2008.
As of December 31, 2008, Arch Coal, Inc. (Arch) held surety bonds of $93.6 million related to properties acquired by Patriot in the Magnum acquisition, of which $91.9 million related to reclamation. As a result of the acquisition, Patriot is required to post letters of credit in Arch’s favor at an increasing percentage of the accrued reclamation liabilities beginning August 2009 through February 2011.
In relation to an exchange transaction involving the acquisition of Illinois Basin coal reserves in 2005, we guaranteed bonding for a partnership in which we formerly held an interest. The aggregate amount that we guaranteed was $2.8 million and the fair value of the guarantee recognized as a liability was $0.3 million as of December 31, 2008. Our obligation under the guarantee extends to September 2015.
In connection with the spin-off, Peabody assumed certain of Patriot’s retiree healthcare liabilities. These liabilities totaled $597.6 million as of December 31, 2008. These liabilities included certain obligations under the Coal Act for which Peabody and Patriot are jointly and severally liable, obligations under the 2007 NBCWA for which we are secondarily liable, and obligations for certain active, vested employees of Patriot.
Newly Adopted Accounting Pronouncements
FASB Statement No. 157
In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measures. SFAS No. 157 clarifies that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. SFAS No. 157 establishes a three-level fair value hierarchy for fair value to be measured based on the observability of the inputs utilized in the valuation. The levels are: Level 1 - inputs from quoted prices in an active market, Level 2 - inputs other than a quoted price market that are directly or indirectly observable through market corroborated inputs and Level 3 - inputs that are unobservable and require assumptions about pricing by market participants. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We elected to implement SFAS No. 157 with the one-year deferral permitted by FASB issued Staff Position FAS 157-2 (FSP SFAS 157-2) for nonfinancial assets and nonfinancial liabilities, except for those items that are recognized or
disclosed at fair value in the financial statements on a recurring basis. The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination.
In October 2008, the FASB issued FASB Staff Position (FSP) No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (FSP SFAS 157-3), which clarified the application of SFAS No. 157 in an inactive market and demonstrated how the fair value of a financial asset is determined when the market for that financial asset is inactive. FSP SFAS 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued. The adoption of FSP SFAS 157-3 did not have a material effect on our results of operations or financial condition since we did not have any financial assets in inactive markets.
FASB Statement No. 159
In February 2007, the FASB issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Entities electing the fair value option are required to recognize changes in fair value in earnings and to expense upfront costs and fees associated with each item for which the fair value option is elected. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We adopted SFAS No. 159 on January 1, 2008, with no impact to the financial statements upon adoption since we did not elect fair value treatment for any items not currently required to be measured at fair value.
Pending Adoption of Recent Accounting Pronouncements
FASB Statement No. 141(R)
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which replaces SFAS No. 141 and retains the fundamental requirements in SFAS No. 141, including that the purchase method be used for all business combinations and for an acquirer to be identified for each business combination. This standard defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control instead of the date that the consideration is transferred. SFAS No. 141(R) requires an acquirer in a business combination to recognize the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions. It also requires the recognition of assets acquired and liabilities assumed arising from certain contractual contingencies as of the acquisition date, measured at their acquisition-date fair values. SFAS No. 141(R) becomes effective for us for any business combination with an acquisition date on or after January 1, 2009. We will evaluate the potential impact of SFAS No. 141(R) on our operating results, cash flows and financial condition for applicable transactions subsequent to 2008.
FASB Statement No. 161
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 161 expands the disclosure requirement for derivative instruments and hedging activities. This statement specifically requires entities to provide enhanced disclosures about its use of derivative instruments, the accounting for derivatives and related hedge items, and the related affect on an entity’s financial condition, results of operations and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008 (January 1, 2009 for us). While we are currently evaluating the impact SFAS No. 161 will have on our disclosures, the adoption of SFAS No. 161 will not affect our results of operations or financial condition.
FASB Staff Position APB 14-1
In May 2008, the FASB issued FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (FSP APB 14-1). FSP APB 14-1 changes the accounting for our convertible notes, specifying that issuers of convertible debt instruments that may settle in cash upon conversion must bifurcate the proceeds from the debt issuance between debt and equity components in a manner that reflects the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The equity component would reflect the value of the conversion feature of the notes. FSP APB 14-1 is
effective for fiscal years beginning after December 15, 2008 (January 1, 2009 for us). FSP APB 14-1 requires retrospective application to all periods presented and does not grandfather existing debt instruments.
We are currently evaluating the potential impact of FSP APB 14-1 on our operating results, cash flows and financial condition. The preliminary estimate of our nonconvertible debt borrowing rate is approximately 8.5% to 9.5% as compared to the 3.25% coupon rate of the notes. The adoption of this position will result in an increase in stockholders’ equity for the equity component of the notes and a corresponding decrease or discount to the $200.0 million face value of the notes. The amortization of the convertible debt discount will result in an increase to interest expense over the remaining life of the notes.
FASB Staff Position EITF 03-6-1
In June 2008, the FASB issued FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP EITF 03-6-1). FSP EITF 03-6-1 addresses whether instruments granted in share-based payment awards that entitle their holders to receive nonforfeitable dividends or dividend equivalents before vesting should be considered participating securities and need to be included in the earnings allocation in computing earnings per share under the “two-class method”. The two-class method of computing earnings per share is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008 (January 1, 2009 for us) with all prior period earnings per share data being adjusted retrospectively. We are currently evaluating the effect FSP EITF 03-6-1 will have on our calculation of earnings per share.
EITF 08-6
In November 2008, the Emerging Issues Task Force (EITF) issued Issue 08-6, “Accounting for Equity Method Investments” (FSP EITF 08-6), because of questions raised regarding the application of the equity method after FASB Statement 160 and FASB Statement 141(R) were issued. This EITF issue addresses other-than-temporary impairment, the accounting for gains or losses on issuance of shares by the investee and the loss of significant influence such that the accounting method must change. EITF 08-06 is effective on a prospective basis for transactions in an investee’s shares occurring or impairments recognized in fiscal years, beginning after December 15, 2008. We do not expect EITF 08-6 to have a significant impact on the accounting for our equity investments.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
Commodity Price Risk
The potential for changes in the market value of our coal portfolio is referred to as “market risk.” Due to lack of quoted market prices and the long term, illiquid nature of the positions, we have not quantified market risk related to our portfolio of coal supply agreements. We manage our commodity price risk for our coal contracts through the use of long-term coal supply agreements, rather than through the use of derivative instruments. We sold 78% of our sales volume under coal supply agreements with terms of one year or more during 2008. As of December 31, 2008 our total unpriced planned production for 2009 was up to 3 million tons and for 2010 was up to 19 million tons.
In connection with the spin-off, we entered into long-term coal contracts with marketing affiliates of Peabody. The arrangements, except as described below under Credit Risk, have substantially similar terms and conditions as the pre-existing contractual obligations of Peabody’s marketing affiliate. These arrangements may be amended or terminated only with the mutual agreement of Peabody and Patriot.
With the addition of Magnum, our commodity risk profile has changed as our annual usage of diesel fuel has increased significantly. To manage this risk, we have entered into swap contracts with financial institutions. These derivative contracts have been designated as cash flow hedges of anticipated diesel fuel purchases. As of December 31, 2008, the notional amounts outstanding for these swaps included 9.5 million gallons of heating oil, which expire throughout 2009 and 9.0 million gallons of heating oil expiring throughout 2010. We expect to purchase approximately 25 million gallons of diesel fuel annually. Aside from these hedging activities, a $0.10 per gallon change in the price of diesel fuel would impact our annual operating costs by approximately $2 million.
Credit Risk
A major portion of our revenues is generated through sales to a marketing affiliate of Peabody, and we will continue to supply coal to Peabody on a contract basis as described above, so Peabody can meet its commitments under pre-existing customer agreements sourced from our operations. One of these arrangements with Peabody provides for the adjustment of a major existing coal sales agreement sourced from Patriot’s operations to increase the price paid to us thereunder. The term of the last pre-existing customer arrangement between Patriot and Peabody will expire on December 31, 2012. Our remaining sales are made directly to electric utilities, industrial companies and steelmakers. Therefore, our concentration of credit risk is with Peabody, as well as electric utilities and steelmakers.
Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor the credit extended. In the event that we engage in a transaction with a counterparty that does not meet our credit standards, we will protect our position by requiring the counterparty to provide appropriate credit enhancement. When appropriate (as determined by our credit management function), we have taken steps to mitigate our credit exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps may include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay. While the economic recession may affect our customers, we do not anticipate that it will significantly affect our overall credit risk profile due to our credit policies.
Additionally, as of December 31, 2008, we had $142.3 million in notes receivable outstanding, arising out of the sale of coal reserves and surface land discussed above. Of this amount, 98% is from a single counterparty. Each of these notes contains a cross-collaterization provision secured primarily by the underlying coal reserves and surface land.
Item 8.
Item 8.
Financial Statements and Supplementary Data.
See Part IV, Item 15 of this report for information required by this Item.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A.
Controls and Procedures.
As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer have each concluded that our disclosure controls and procedures were effective in alerting them in a timely manner to material information relating to Patriot and our consolidated subsidiaries required to be included in our periodic SEC filings. There were no changes in our internal control over financial reporting identified during the quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s assessment of internal control over financial reporting at December 31, 2008 excludes the operations of Magnum acquired on July 23, 2008, as allowed by SEC guidance related to internal controls of recently acquired entities. We are in the process of integrating these operations into our control environment, thus making it impractical to complete an assessment by December 31, 2008. These operations constituted $2.4 billion and $1.0 billion of total and net assets, respectively, as of December 31, 2008 and $413.0 million and $205.2 million of revenues and net income, respectively, for the year then ended.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for maintaining and establishing adequate internal control over financial reporting. Our internal control framework and processes were designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
Because of inherent limitations, any system of 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 conducted an assessment of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on this assessment, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2008.
Management’s assessment of internal control over financial reporting at December 31, 2008 excludes the operations of Magnum acquired on July 23, 2008, as allowed by SEC guidance related to internal controls of recently acquired entities. We are in the process of integrating these operations into our control environment, thus making it impractical to complete an assessment by December 31, 2008. These operations constituted $2.4 billion and $1.0 billion of total and net assets, respectively, as of December 31, 2008 and $413.0 million and $205.2 million of revenues and net income, respectively, for the year then ended.
Our Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited our internal control over financial reporting, as stated in their unqualified opinion report included herein.
/s/ Richard M. Whiting
Richard M. Whiting
Chief Executive Officer
February 25, 2009
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for maintaining and establishing adequate internal control over financial reporting. Our internal control framework and processes were designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
Because of inherent limitations, any system of 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 conducted an assessment of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on this assessment, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2008.
Management’s assessment of internal control over financial reporting at December 31, 2008 excludes the operations of Magnum acquired on July 23, 2008, as allowed by SEC guidance related to internal controls of recently acquired entities. We are in the process of integrating these operations into our control environment, thus making it impractical to complete an assessment by December 31, 2008. These operations constituted $2.4 billion and $1.0 billion of total and net assets, respectively, as of December 31, 2008 and $413.0 million and $205.2 million of revenues and net income, respectively, for the year then ended.
Our Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited our internal control over financial reporting, as stated in their unqualified opinion report included herein.
/s/ Mark N. Schroeder
Mark N. Schroeder
Chief Financial Officer
February 25, 2009
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Patriot Coal Corporation
We have audited Patriot Coal Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Patriot Coal Corporation’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, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and 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.
As indicated in Management’s Report on Internal Control Over Financial Reporting management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of Magnum Coal Company, which is included in the 2008 consolidated financial statements of Patriot Coal Corporation and constituted $2.4 billion and $1.0 billion of total and net assets, respectively, as of December 31, 2008 and $413.0 million and $205.2 million of revenues and net income, respectively, for the year then ended. Our audit of internal control over financial reporting of Patriot Coal Corporation also did not include an evaluation of the internal control over financial reporting of Magnum Coal Company.
In our opinion, Patriot Coal Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Patriot Coal Corporation as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008 and our report dated February 25, 2009 expressed an unqualified opinion thereon.
February 25, 2009
Item 9B.
Item 9B.
Other Information.
None.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance.
The information required by Item 401 of Regulation S-K is included under the caption Election of Directors in our Proxy Statement and in Part I of this report under the caption Executive Officers of the Company. Such information is incorporated herein by reference. The information required by Items 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is included under the captions Section 16(a) Beneficial Ownership Reporting Compliance, Corporate Governance Matters and Executive Compensation, respectively, in our Proxy Statement and is incorporated herein by reference.
Item 11.
Item 11.
Executive Compensation.
The information required by Items 402 and 407 (e)(4) and (e)(5) of Regulation S-K is included in our Proxy Statement under the caption Executive Compensation and is incorporated herein by reference.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by Item 403 of Regulation S-K is included under the caption Ownership of Company Securities in our Proxy Statement and is incorporated herein by reference.
As required by Item 201(d) of Regulation S-K, the following table provides information regarding our equity compensation plans as of December 31, 2008:
Equity Compensation Plan Information
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
The information required by Item 404 of Regulation S-K is included under the captions Certain Relationships and Related Party Transactions, Director Independence and Policy for Approval of Related Person Transactions in our Proxy Statement and is incorporated herein by reference. The information required by Item 407(a) of Regulation S-K is included under the caption Executive Compensation in our Proxy Statement and is incorporated herein by reference.
Item 14.
Item 14.
Principal Accounting Fees and Services.
The information required by Item 9(e) of Schedule 14A is included under the caption Fees Paid to Independent Registered Public Accounting Firm in our Proxy Statement and is incorporated herein by reference.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
(a) Documents Filed as Part of the Report
(1) Financial Statements.
The following consolidated financial statements of Patriot Coal Corporation are included herein on the pages indicated:
(2) Financial Statement Schedule.
The following financial statement schedule of Patriot Coal Corporation is at the page indicated:
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted.
(3) Exhibits.
See Exhibit Index hereto.
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.
PATRIOT COAL CORPORATION
/s/ RICHARD M. WHITING
Richard M. Whiting
Chief Executive Officer and Director
Date: February 27, 2009
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.
*
Filed herewith.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Patriot Coal Corporation
We have audited the accompanying consolidated balance sheets of Patriot Coal Corporation as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of KE Ventures (an LLC in which the Company had a 73.9% ownership interest for 2006) for the year ended December 31, 2006. KE Ventures, LLC was a consolidated entity for the year ended December 31, 2006. KE Ventures, LLC’s total revenues were $103.8 million for the year ended December 31, 2006. KE Ventures, LLC’s statements for the year ended December 31, 2006, were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for KE Ventures, LLC, is based solely on the reports of other auditors.
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, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Patriot Coal Corporation at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, 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), Patriot Coal Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2009, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
St. Louis, Missouri
February 25, 2009
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Members of
KE Ventures, LLC
In our opinion, the consolidated balance sheet and the related consolidated statements of operations, of members’ capital and of cash flows (not presented herein) present fairly, in all material respects, the financial position of KE Ventures, LLC (the “Company”) and its subsidiaries at December 31, 2006, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Charlotte, North Carolina
February 19, 2007
PATRIOT COAL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to the consolidated financial statements.
PATRIOT COAL CORPORATION
CONSOLIDATED BALANCE SHEETS
See accompanying notes to the consolidated financial statements.
PATRIOT COAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to the consolidated financial statements.
PATRIOT COAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
See accompanying notes to the consolidated financial statements.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2008
(1)
Basis of Presentation
Description of Business
Effective October 31, 2007, Patriot Coal Corporation (Patriot) was spun-off from Peabody Energy Corporation (Peabody) and became a separate, public company traded on the New York Stock Exchange (symbol PCX). The spin-off from Peabody, including coal assets and operations in Appalachia and the Illinois Basin, was accomplished through a dividend of all outstanding shares of Patriot.
Patriot is engaged in the mining of thermal coal, also known as steam coal, for sale primarily to electric utilities and metallurgical coal, for sale to steel mills and independent coke producers. Patriot’s mining operations and coal reserves are located in the eastern and midwestern United States, primarily in West Virginia and Kentucky.
On April 2, 2008, Patriot entered into an agreement to acquire Magnum Coal Company (Magnum). Magnum was one of the largest coal producers in Appalachia, operating 11 mines and 7 preparation plants with production from surface and underground mines and controlling more than 600 million tons of proven and probable coal reserves. On July 23, 2008, Patriot consummated the acquisition of Magnum. See Note 4 for additional information on the acquisition. In conjunction with the acquisition, Patriot issued debt in order to repay Magnum’s existing senior secured indebtedness. See Note 13 for additional information.
Basis of Presentation
The consolidated financial statements include the accounts of Patriot and its wholly-owned affiliates. All significant transactions, profits and balances have been eliminated between Patriot and its subsidiaries. Patriot operates in two domestic coal segments; Appalachia and the Illinois Basin (see Note 21).
The statements of operations and cash flows and related discussions for the years ended December 31, 2007 and 2006 relate to Patriot’s historical results and may not necessarily reflect what its results of operations and cash flows will be in the future or would have been as a stand-alone company. Upon the completion of the spin-off, Patriot’s capital structure changed significantly. At the spin-off date, Patriot entered into various operational agreements with Peabody, including certain on-going agreements that enhance both the financial position and cash flows of Patriot. Such agreements include the assumption by Peabody of certain retiree healthcare liabilities and the repricing of a major coal supply agreement to be more reflective of the then current market pricing for similar quality coal.
Effective August 11, 2008, Patriot implemented a 2-for-1 stock split effected in the form of a 100% stock dividend. All share and per share amounts in these consolidated financial statements and related notes reflect this stock split, including share information related to the Convertible Senior Notes and the Magnum acquisition.
(2)
Summary of Significant Accounting Policies
Sales
Patriot’s revenue from coal sales is realized and earned when risk of loss passes to the customer. Coal sales are made to customers under the terms of supply agreements, most of which are long-term (greater than one year). Under the typical terms of these coal supply agreements, title and risk of loss transfer to the customer at the mine, where coal is loaded onto the rail, barge, truck or other transportation source that delivers coal to its destination. Shipping and transportation costs are generally borne by the customer. In relation to export sales, Patriot holds inventories at port facilities where title and risk of loss do not transfer until the coal is loaded into an ocean-going vessel. The Company incurs certain “add-on” taxes and fees on coal sales. Coal sales are reported including taxes and fees charged by various federal and state governmental bodies.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Other Revenues
Other revenues include royalties related to coal lease agreements and farm income. Royalty income generally results from the lease or sublease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced. Certain agreements require minimum annual lease payments regardless of the extent to which minerals are produced from the leasehold, although revenue is only recognized on these payments as the mineral is mined. The terms of these agreements generally range from specified periods of 5 to 15 years, or can be for an unspecified period until all reserves are depleted.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.
Inventories
Materials and supplies and coal inventory are valued at the lower of average cost or market. Saleable coal represents coal stockpiles that will be sold in current condition. Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Coal inventory costs include labor, supplies, equipment, operating overhead and other related costs.
Property, Plant, Equipment and Mine Development
Property, plant, equipment and mine development are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period, including $0.1 million, $0.5 million and $0.3 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Expenditures which extend the useful lives of existing plant and equipment assets are capitalized. Maintenance and repairs are charged to operating costs as incurred. Costs incurred to develop coal mines or to expand the capacity of operating mines are capitalized. Costs incurred to maintain current production capacity at a mine and exploration expenditures are charged to operating costs as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves. Costs to acquire computer hardware and the development and/or purchase of software for internal use are capitalized and depreciated over the estimated useful lives.
Coal reserves are recorded at cost, or at fair value in the case of acquired businesses. Coal reserves are included in “Land and coal interests” on the consolidated balance sheets. As of December 31, 2008 and 2007, the fair value of coal reserves totaled $2.5 billion and $545.5 million, respectively. The Company is still in the process of determining the fair value of the coal reserves related to Magnum, which is preliminarily valued at $1.9 billion at December 31, 2008. For further discussion related to the acquisition see Note 4, Business Combinations. Excluding Magnum, these coal reserve amounts included $287.8 and $287.6 million at December 31, 2008 and 2007, respectively, attributable to properties where the Company was not currently engaged in mining operations or leasing to third parties and, therefore, the coal reserves were not currently being depleted. Included in the book value of coal reserves are mineral rights for leased coal interests including advance royalties. The net book value of these mineral rights, excluding Magnum, was $373.9 million and $380.1 million at December 31, 2008 and 2007, respectively. The remaining net book value of the coal reserves relates to coal reserves held by fee ownership.
Depletion of coal reserves and amortization of advance royalties are computed using the units-of-production method utilizing only proven and probable reserves (as adjusted for recoverability factors) in the depletion base. Mine development costs are principally amortized ratably over the estimated lives of the mines.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Depreciation of plant and equipment (excluding life of mine assets) is computed ratably over the estimated useful lives as follows:
In addition, certain plant and equipment assets associated with mining are depreciated ratably over the estimated life of the mine. Remaining lives vary from less than one year up to 29 years. The charge against earnings for depreciation of property, plant, equipment and mine development was $87.8 million, $60.3 million and $65.1 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Purchased Contract Rights
In connection with the Magnum acquisition, the Company acquired certain below market coal purchase contracts. These below market purchase contracts were recorded at their preliminarily-determined fair value, resulting in a gross asset of $42.9 million and accumulated amortization of $33.4 million as of December 31, 2008. The purchase contracts are amortized into earnings as the coal is sold to the end customer, expected to be within a year from the acquisition date and included in “Operating costs and expenses” in the consolidated statements of operations. The Company also has gross purchased contract rights associated with the KE Ventures, LLC acquisition of $6.2 million, with accumulated amortization of $4.0 million as of December 31, 2008. The current portion of these acquired contract rights is reported in “Below market purchase contracts acquired” and the long-term portion is recorded in “Investments and other assets” in the consolidated balance sheets.
Joint Ventures
The Company applies the equity method to investments in joint ventures when it has the ability to exercise significant influence over the operating and financial policies of the joint venture. The Company reviews the documents governing each joint venture to assess if it has a controlling financial interest in the joint venture to determine if the equity method is appropriate or if the joint venture should be consolidated. Investments accounted for under the equity method are initially recorded at cost, and any difference between the cost of the Company’s investment and the underlying equity in the net assets of the joint venture at the investment date is amortized over the lives of the related assets that gave rise to the difference. The Company’s pro rata share of earnings from joint ventures and basis difference amortization was expense of $0.9 million for the year ended December 31, 2008 and income of $0.1 million and $0.1 million for the years ended December 31, 2007 and 2006, respectively, which is reported in “Operating costs and expenses” in the consolidated statements of operations. The book values of the Company’s equity method investments as of December 31, 2008, and 2007 were $21.2 million and $0.7 million, respectively, and are reported in “Investments and other assets” in the consolidated balance sheets.
Sales Contract Liability
In connection with the Magnum acquisition, the Company recorded liabilities related to below market sales contracts. The below market supply contracts were recorded at their preliminarily-determined fair value when allocating the purchase price, which is accreted into earnings as the coal is shipped over a weighted average period of approximately three years. Net sales contract accretion related to the below market coal supply contracts acquired is included as a reduction of “Operating costs and expenses” in the consolidated statements of operations. The net liability at December 31, 2008 relating to these below market sales contracts was $641.1 million, including accumulated accretion of $313.3 million. The current portion of the liability is recorded in “Below market sales contracts acquired” in the consolidated balance sheets and the long-term portion of the liability is recorded in “Below market sales contracts acquired, noncurrent” in the consolidated balance sheets.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Asset Retirement Obligations
Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The Company’s asset retirement obligations (ARO) primarily consist of spending estimates related to reclaiming surface land and support facilities at both surface and underground mines in accordance with federal and state reclamation laws as defined by each mining permit.
ARO liabilities for final reclamation and mine closure are estimated based upon detailed engineering calculations of the amount and timing of the future cash spending for a third-party to perform the required work. Spending estimates are escalated for inflation and then discounted at the credit-adjusted, risk-free rate. Patriot records an ARO asset associated with the discounted liability for final reclamation and mine closure. The obligation and corresponding asset are recognized in the period in which the liability is incurred. The ARO asset is amortized on the units-of-production method over its expected life and the ARO liability is accreted to the projected spending date. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free rate. The Company also recognizes an obligation for contemporaneous reclamation liabilities incurred as a result of surface mining. Contemporaneous reclamation consists primarily of grading, topsoil replacement and revegetation of backfilled pit areas.
Environmental Liabilities
Included in “Other noncurrent liabilities” are accruals for other environmental matters that are recorded in operating expenses when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Accrued liabilities are exclusive of claims against third parties and are not discounted. In general, costs related to environmental remediation are charged to expense.
Income Taxes
Income taxes are accounted for using a balance sheet approach in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). Deferred income taxes are accounted for by applying statutory tax rates in effect at the date of the balance sheet to differences between the book and tax basis of assets and liabilities. A valuation allowance is established if it is “more likely than not” that the related tax benefits will not be realized. In determining the appropriate valuation allowance, projected realization of tax benefits is considered based on expected levels of future taxable income, available tax planning strategies and the overall deferred tax position.
SFAS No. 109 specifies that the amount of current and deferred tax expense for an income tax return group shall be allocated among the members of that group when those members issue separate financial statements. For purposes of the consolidated financial statements prepared for the twelve months ended December 31, 2007 and for the other periods prior to the spin-off, the Company’s income tax expense has been recorded as if it filed a consolidated tax return separate from Peabody, notwithstanding that a majority of the operations were historically included in the U.S. consolidated income tax return filed by Peabody. The Company’s valuation allowance for these periods was also determined on the separate tax return basis. Additionally, the Company’s tax attributes (i.e. net operating losses and AMT credits) for these periods have been determined based on U.S. consolidated tax rules describing the apportionment of these items upon departure (i.e. spin-off) from the Peabody consolidated group.
Peabody was managing its tax position for the benefit of its entire portfolio of businesses. Peabody’s tax strategies were not necessarily reflective of the tax strategies that the Company would have followed or will follow as a stand-alone company, nor were they necessarily strategies that optimized the Company’s stand-alone position.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Postretirement Healthcare Benefits
Postretirement benefits other than pensions are accounted for in accordance with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (SFAS No. 106), which requires the costs of benefits to be provided to be accrued over the employees’ period of active service. These costs are determined on an actuarial basis. The consolidated balance sheets as of December 31, 2008 and 2007 fully reflect the funded status of postretirement benefits.
Multi-Employer Benefit Plans
The Company has an obligation to contribute to two plans established by the Coal Industry Retiree Health Benefits Act of 1992 (the Coal Act) - the “Combined Fund” and the “1992 Benefit Plan.” A third fund, the 1993 Benefit Fund (the 1993 Benefit Plan), was established through collective bargaining, but is now a statutory plan under legislation passed in 2006. A portion of these obligations are accounted for in accordance with Emerging Issues Task Force (EITF) No. 92-13, “Accounting for Estimated Payments in Connection with the Coal Industry Retiree Health Benefit Act of 1992,” as determined on an actuarial basis. The remainder of these obligations qualify as multi-employer plans under SFAS No. 106, and expense is recognized as contributions are made.
Pension Plans
Prior to the spin-off, Patriot participated in a non-contributory defined benefit pension plan (the Peabody Pension Plan) accounted for in accordance with SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS No. 87), which requires that the cost to provide the benefits be accrued over the employees’ period of active service. The Peabody Pension Plan was sponsored by one of Peabody’s subsidiaries and covered certain salaried employees and eligible hourly employees of Peabody. In connection with the spin-off, Patriot employees no longer participate in a defined benefit pension plan, and Patriot did not retain any of the assets or liabilities for the Peabody Pension Plan. Accordingly the assets and liabilities of the Peabody Pension Plan are not allocated to Patriot and are not presented in the accompanying balance sheets. However, annual contributions to the Peabody Pension Plan were made as determined by consulting actuaries based upon the Employee Retirement Income Security Act of 1974 minimum funding standard. Patriot recorded expense of $1.1 million and $3.7 million for the years ended December 31, 2007 and 2006, respectively, as a result of its participation in the Peabody Pension Plan, reflecting Patriot’s proportional share of Peabody’s expense based on the number of plan participants.
Patriot also participates in two multi-employer pension plans, the United Mine Workers of America 1950 Pension Plan (the 1950 Plan) and the United Mine Workers of America 1974 Pension Plan (the 1974 Plan). These plans qualify as multi-employer plans under SFAS No. 87, and expense is recognized as contributions are made. The plan assets of the 1950 Plan and the 1974 Plan are managed by the UMWA. See Note 16 for additional information.
Postemployment Benefits
Postemployment benefits are provided to qualifying employees, former employees and dependents, and Patriot accounts for these items on the accrual basis in accordance with SFAS No. 112 “Employers’ Accounting for Postemployment Benefits.” Postemployment benefits include workers’ compensation occupational disease, which is accounted for on the actuarial basis over the employees’ periods of active service; workers’ compensation traumatic injury claims, which are accounted for based on estimated loss rates applied to payroll and claim reserves determined by independent actuaries and claims administrators; disability income benefits, which are accrued when a claim occurs; and continuation of medical benefits, which are recognized when the obligation occurs. The Company’s consolidated balance sheets as of December 31, 2008 and 2007 fully reflect the funded status of postemployment benefits.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Use of Estimates in the Preparation of the Consolidated Financial Statements
The preparation of financial statements in conformity with generally accepted accounting principles 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 financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
In particular, Patriot has significant long-term liabilities relating to retiree healthcare and work-related injuries and illnesses. Each of these liabilities is actuarially determined and uses various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for these items. In addition, the Company has significant asset retirement obligations that involve estimations of costs to remediate mining lands and the timing of cash outlays for such costs. If these assumptions do not materialize as expected, actual cash expenditures and costs incurred could differ materially from current estimates. Moreover, regulatory changes could increase the obligation to satisfy these or additional obligations.
Finally, in evaluating the valuation allowance related to deferred tax assets, various factors are taken into account, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in the evaluation of the valuation allowance, a change in valuation allowance may be recorded through income tax expense in the period such determination is made.
Share-Based Compensation
The Company has an equity incentive plan for employees and eligible non-employee directors that allows for the issuance of share-based compensation in the form of restricted stock, incentive stock options, nonqualified stock options, stock appreciation rights, performance awards, restricted stock units and deferred stock units. The Company recognizes share-based compensation expense in accordance with SFAS No. 123(R), “Share-Based Payment”. The Company recognized compensation cost for awards with only service conditions that have a graded vesting schedule on a straight line basis over the requisite service period for each separately vesting portion of the award.
Derivatives
The Company has utilized derivative financial instruments to manage exposure to certain commodity prices. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), and related interpretive guidance require the recognition of derivative financial instruments at fair value on the consolidated balance sheet. For derivatives that are not designated as hedges, the periodic change in fair value is recorded directly to earnings. For derivative instruments that are eligible and qualify as cash flow hedges, the periodic change in fair value is recorded to “Accumulated other comprehensive income (loss)” until the contract settles or the relationship ceases to qualify for hedge accounting. In addition, if a portion of the change in fair value for a cash flow hedge is deemed ineffective during a reporting period, as defined in SFAS No. 133, the ineffective portion of the change in fair value is recorded directly to earnings. In 2008, the Company entered heating oil swap contracts to manage its exposure to diesel fuel prices. The changes in diesel fuel and heating oil prices are highly correlated thus allowing the swap contracts to be designated as cash flow hedges.
Impairment of Long-Lived Assets
Impairment losses on long-lived assets used in operations are recorded when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those assets under various assumptions are less than the carrying amounts of those assets. Impairment losses are measured by comparing the estimated fair value of the impaired asset to its carrying amount. No impairment losses were recorded during the periods covered by the consolidated financial statements.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Business Combinations
The Company accounts for its business acquisitions using the purchase method of accounting consistent with the requirements of SFAS No. 141, “Business Combinations”. Under this method of accounting, the purchase price is allocated to the fair value of the net assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including, but not limited to, assumptions with respect to future cash flows, discount rates and asset lives.
Deferred Financing Costs
The Company capitalizes costs incurred in connection with borrowings or establishment of credit facilities and issuance of debt securities. These costs are amortized as an adjustment to interest expense over the life of the borrowing or term of the credit facility using the interest method.
Reclassifications
Certain amounts in prior periods have been reclassified to conform to the 2008 presentation.
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New Accounting Pronouncements
Newly Adopted Accounting Pronouncements
FASB Statement No. 157
In September 2006, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measures. SFAS No. 157 clarifies that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. SFAS No. 157 establishes a three-level fair value hierarchy for fair value to be measured based on the observability of the inputs utilized in the valuation. The levels are: Level 1 - inputs from quoted prices in an active market, Level 2 - inputs other than a quoted price market that are directly or indirectly observable through market corroborated inputs and Level 3 - inputs that are unobservable and require assumptions about pricing by market participants. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. The Company elected to implement SFAS No. 157 with the one-year deferral permitted by FASB issued Staff Position FAS 157-2 (FSP SFAS 157-2) for nonfinancial assets and nonfinancial liabilities, except for those items that are recognized or disclosed at fair value in the financial statements on a recurring basis. The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination. The Company utilized SFAS No. 157 for an exchange transaction described in Note 6.
In October 2008, the FASB issued FASB Staff Position (FSP) No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (FSP SFAS 157-3), which clarified the application of SFAS No. 157 in an inactive market and demonstrated how the fair value of a financial asset is determined when the market for that financial asset is inactive. FSP SFAS 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued. The adoption of FSP SFAS 157-3 did not have a material effect on the Company’s results of operations or financial condition since it did not have any financial assets in inactive markets.
FASB Statement No. 159
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Entities electing the fair value option are
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
required to recognize changes in fair value in earnings and to expense upfront costs and fees associated with each item for which the fair value option is elected. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company adopted SFAS No. 159 on January 1, 2008, with no impact to the financial statements upon adoption since the Company did not elect fair value treatment for any items not currently required to be measured at fair value.
Pending Adoption of Recent Accounting Pronouncements
FASB Statement No. 141(R)
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which replaces SFAS No. 141 and retains the fundamental requirements in SFAS No. 141, including that the purchase method be used for all business combinations and for an acquirer to be identified for each business combination. This standard defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control instead of the date that the consideration is transferred. SFAS No. 141(R) requires an acquirer in a business combination to recognize the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions. It also requires the recognition of assets acquired and liabilities assumed arising from certain contractual contingencies as of the acquisition date, measured at their acquisition-date fair values. SFAS No. 141(R) will be effective for the Company for any business combination with an acquisition date on or after January 1, 2009.
FASB Statement No. 161
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 161 expands the disclosure requirement for derivative instruments and hedging activities. This statement specifically requires entities to provide enhanced disclosures about its use of derivative instruments, the accounting for derivatives and related hedge items, and the related affect on an entity’s financial condition, results of operations and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008 (January 1, 2009 for the Company). While the Company is currently evaluating the impact SFAS No. 161 will have on its disclosures, the adoption of SFAS No. 161 will not affect the Company’s results of operations or financial condition.
FASB Staff Position APB 14-1
In May 2008, the FASB issued FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (FSP APB 14-1). FSP APB 14-1 changes the accounting for the Company’s convertible notes, specifying that issuers of convertible debt instruments that may settle in cash upon conversion must bifurcate the proceeds from the debt issuance between debt and equity components in a manner that reflects the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The equity component would reflect the value of the conversion feature of the notes. FSP APB 14-1 is effective for fiscal years beginning after December 15, 2008 (January 1, 2009 for the Company). FSP APB 14-1 requires retrospective application to all periods presented and does not grandfather existing debt instruments.
The Company is currently evaluating the potential impact of FSP APB 14-1 on its operating results, cash flows and financial condition. The preliminary estimate of the Company’s nonconvertible debt borrowing rate is approximately 8.5% to 9.5% as compared to the 3.25% coupon rate of our Convertible Senior Notes (see Note 13). The adoption of this position will result in an increase in stockholders’ equity for the equity component of our Convertible Senior Notes and a corresponding decrease or discount to the $200 million face value of our Convertible Senior Notes. The amortization of the convertible debt discount will result in an increase to interest expense over the remaining life of the Convertible Senior Notes.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
FASB Staff Position EITF 03-6-1
In June 2008, the FASB issued FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP EITF 03-6-1). FSP EITF 03-6-1 addresses whether instruments granted in share-based payment awards that entitle their holders to receive nonforfeitable dividends or dividend equivalents before vesting should be considered participating securities and need to be included in the earnings allocation in computing earnings per share under the “two-class method”. The two-class method of computing earnings per share is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008 with all prior period earnings per share data being adjusted retrospectively. The Company is currently evaluating the effect FSP EITF 03-6-1 will have on its calculation of earnings per share.
EITF 08-6
In November 2008, the EITF issued Issue 08-6, “Accounting for Equity Method Investments” (EITF 08-6), because of questions raised regarding the application of the equity method after FASB Statement 160 and FASB Statement 141(R) were issued. This EITF issue addresses other-than-temporary impairment, the accounting for gains or losses on issuance of shares by the investee and the loss of significant influence such that the accounting method must change. EITF 08-06 is effective on a prospective basis for transactions in an investee’s shares occurring or impairments recognized in fiscal years, beginning after December 15, 2008. The Company does not expect EITF 08-6 to have a significant impact on the accounting for its equity investments.
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Business Combinations
Magnum Coal Company
On July 23, 2008, Patriot consummated the acquisition of Magnum. Magnum stockholders received 23,803,312 shares of newly-issued Patriot common stock and cash in lieu of fractional shares. The fair value of $25.29 per share of Patriot common stock issued to the Magnum shareholders was based on the average of Patriot stock price for the five business days surrounding and including the merger announcement date, April 2, 2008. The total purchase price was $739.0 million, including the assumption of $148.6 million of long-term debt, $11.8 million of which related to capital lease obligations. In conjunction with the acquisition, Patriot issued debt in order to repay Magnum’s existing senior secured indebtedness as discussed in Note 13. Magnum was one of the largest coal producers in Appalachia, operating 11 mines and 7 preparation plants with production from surface and underground mines and controlling more than 600 million tons of proven and probable coal reserves.
The results of operations of Magnum are included in the Appalachia Mining Operations segment from the date of acquisition. The acquisition was accounted for using the purchase method of accounting. Under this method of accounting, the purchase price is allocated to the fair value of the net assets acquired. The excess purchase price over the fair value of the assets acquired, if any, is allocated to goodwill.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes the preliminary estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition:
As of December 31, 2008, the accounting for the acquisition is preliminary. The Company is conducting reserve studies on the acquired properties, the outcome of which will determine the fair value to be allocated to reserve assets. Additionally, the Company is in the process of preparing estimates, as well as obtaining third party estimates of fair value of coal reserves, property, plant and equipment, intangible assets and environmental liabilities.
In connection with the Magnum acquisition, the Company recorded liabilities and assets related to below market coal sales and purchase contracts. The below market supply contracts were recorded at their preliminarily-determined fair value when allocating the purchase price, resulting in a liability of $957.7 million, which is being accreted into earnings as the coal is shipped over a weighted average period of approximately three years. The below market purchase contracts were recorded at their preliminarily-determined fair value, resulting in an asset of $42.9 million, which is being amortized into earnings as the coal is acquired, expected to be within a year from the acquisition date. Net sales contract accretion related to the below market coal supply and purchase contracts acquired is included as a reduction of “Operating costs and expenses” in the consolidated statements of operations.
Based on the preliminary estimated fair values set forth above as compared to the carryover tax basis in assets and liabilities, $67.0 million of net deferred tax liability would be recorded on Magnum’s opening balance sheet. As part of the business combination, these Magnum deferred tax liabilities have impacted management’s view as to the realization of Patriot deferred tax assets, against which a full valuation allowance had previously been recorded. In such situations, SFAS 109 requires that any reduction in the acquiring company’s valuation allowance be accounted for as part of the business combination. As such, preliminary deferred tax liabilities have been offset against a release of $67.0 million of valuation allowance within purchase accounting. Any final determination of the net deferred tax liability (or net deferred tax asset) associated with the business combination will not be complete until the value of all Magnum assets and liabilities is finalized.
Upon the acquisition of Magnum, the Company performed a comprehensive strategic review of all mining complexes and their relative cost structure in order to optimize performance. As a result of this review, the Company announced plans to idle operations of both the acquired Jupiter and Remington mining complexes. The Jupiter
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
mining complex ceased operations in December 2008 and the Remington mining complex is scheduled to cease operations in March 2009. The fair value of the assets and liabilities acquired for these two mining complexes will reflect their status as idled in final purchase accounting.
The following unaudited pro forma financial information presents the combined results of operations of the Company and Magnum, on a pro forma basis, as though the companies had been combined as of January 1, 2007 and January 1, 2008, respectively.
Patriot’s historical financial information has been adjusted in the pro forma amounts above to present the results as if the spin-off from Peabody occurred on January 1, 2007 instead of October 31, 2007. The combined pro forma financial information has been further adjusted to exclude non-recurring transaction-related expenses and include purchase accounting adjustments for preliminarily-determined fair values impacting coal inventories, net sales contract accretion, depletion of coal reserves and depreciation of property, plant and equipment. This unaudited pro forma financial information does not necessarily reflect the results of operations that would have occurred had the Company and Magnum constituted a single entity during those periods.
KE Ventures, LLC
As of December 31, 2005, the Company owned a 49% interest in KE Ventures, LLC and accounted for the interest under the equity method of accounting. In March 2006, Patriot increased its ownership interest in the joint venture to an effective 73.9% and accordingly, fully consolidated KE Ventures, LLC effective January 1, 2006. The purchase price for the additional 24.9% interest was $44.5 million plus assumed debt. The purchase price was allocated over the various assets and liabilities in proportion to the additional ownership percentage with an additional $52.8 million allocated to coal reserves and plant and equipment included in “Property, plant, equipment and mine development” and customer contracts included in “Investments and other assets.”
In September 2007, Patriot acquired an additional 7.6% interest in KE Ventures, LLC for $13.6 million, increasing effective ownership to 81.5%. The minority holders of KE Ventures, LLC held an option which could require Patriot to purchase the remaining 18.5% of KE Ventures, LLC upon a change in control. This option became fully exercisable upon the spin-off from Peabody. The minority owners of KE Ventures, LLC exercised this option in 2007, and the Company acquired the remaining minority interest in KE Ventures, LLC on November 30, 2007 for $33.0 million. The additional purchase price of $46.6 million was allocated to the proportional percentage of assets and liabilities acquired in 2007. The purchase price was primarily allocated to coal reserves as it was the most significant asset acquired.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Because the option requiring Patriot to purchase KE Ventures, LLC was considered a mandatorily redeemable instrument outside of the Company’s control, amounts paid to the minority interest holders in excess of carrying value of the minority interests in KE Ventures, LLC was reflected as an increase in net loss attributable to common stockholders of $15.7 million in 2007. This treatment is consistent with the guidance in SEC ASR 268 “Redeemable Preferred Stock” and EITF Topic D-98 “Classification and Measurement of Redeemable Securities.” This obligation was fully redeemed as of December 31, 2007.
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Risk Management and Financial Instruments
Patriot is exposed to various types of risk in the normal course of business, including fluctuations in commodity prices and interest rates. These risks are actively monitored to ensure compliance with the Company’s risk management policies. The Company manages its commodity price risk related to the sale of coal through the use of long-term, fixed-price contracts, rather than financial instruments.
Credit Risk
Patriot’s concentration of credit risk is substantially with utility customers and Peabody. In 2008, Patriot sold more than 40% of its production through a marketing affiliate of Peabody at prices paid by third-party customers (see Note 18 for additional discussion of related party transactions). Allowance for doubtful accounts was $540,000 and $251,000 at December 31, 2008 and 2007, respectively and reflects specific amounts for which risk of collection has been identified based on the current economic environment and circumstances of which the Company is aware. The Company also has $142.3 million in notes receivable as of December 31, 2008 outstanding from counterparties from the sale of coal reserves and surface lands discussed in Note 6. The current portion of these receivables was $11.1 million as of December 31, 2008 and is included in “Accounts receivable and other” on the consolidated balance sheets. Each of these notes contain a cross-collaterization provision secured primarily by the underlying coal reserves and surface lands.
The Company’s policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor the credit extended. In the event that a transaction occurs with a counterparty that does not meet the Company’s credit standards, the Company may protect its position by requiring the counterparty to provide appropriate credit enhancement. When appropriate, steps have been taken to reduce credit exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk, as determined by the credit management function, of failure to perform under their contractual obligations. These steps might include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for the Company’s benefit to serve as collateral in the event of failure to pay.
Commodity Price Risk
With the Magnum acquisition, the Company’s commodity risk profile changed as its annual usage of diesel fuel increased significantly. To manage this risk, the Company entered into heating oil swap contracts with financial institutions in the fourth quarter of 2008. These derivative contracts have been designated as cash flow hedges of anticipated diesel fuel purchases such that the changes in fair value of these derivatives are recorded through other comprehensive income. As of December 31, 2008, the notional amount outstanding for these swap contracts included 9.5 million gallons of heating oil, which expire throughout 2009, and 9.0 million gallons of heating oil expiring throughout 2010. At December 31, 2008, the fair value of these derivatives was a liability of $9.7 million. The Company did not recognize any gains or losses in earnings in the year ended December 31, 2008, for hedge ineffectiveness or realized gains or losses on these contracts.
Employees
As of December 31, 2008, Patriot had approximately 4,300 employees. Approximately 47% of the employees at Company operations were represented by an organized labor union and they generated approximately 41% of the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
2008 sales volume. Relations with our employees and, where applicable, organized labor, are important to the Company’s success. Union labor is represented by the United Mine Workers of America (UMWA) under labor agreements which expire December 31, 2011.
Fair Value of Financial Instruments
The Company’s heating oil swap contracts discussed above were the only financial instruments that were measured and recorded at fair value on a recurring basis at December 31, 2008. The unrealized loss of $9.7 million was recorded as a liability at December 31, 2008. The Company utilized NYMEX quoted market prices for the fair value measurement of these contracts, which reflects a Level 2 input as defined in SFAS No. 157 and discussed in Note 3.
Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses have carrying values which approximate fair value due to the short maturity or the financial nature of these instruments. The fair value of notes receivable approximates the carrying value as of December 31, 2008 and 2007. At December 31, 2008, the estimated fair market value of the Company’s Convertible Senior Notes due 2013 was $100 million compared to a face value of $200 million. These notes were valued using a Level 2 input as defined in SFAS No. 157.
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Net Gain on Disposal or Exchange of Assets and Other Commercial Transactions
In June 2008, Patriot entered into an agreement to swap certain leasehold coal mineral rights with another coal producer. Additionally, Patriot sold approximately 2.7 million tons of adjacent leasehold coal mineral rights in Appalachia for $1.0 million. Patriot recognized gains totaling $6.3 million on these transactions. The swap transaction was recorded at fair value in accordance with SFAS No. 153 “Exchanges of Nonmonetary Assets” and SFAS No. 157. The Company utilized Level 3 inputs as defined by SFAS No. 157 in a discounted cash flows model to calculate the fair value of the coal reserve swap due to the lack of an active, quoted market and due to the inability to use other transaction comparisons because of the unique nature of each coal seam.
Also in the second quarter of 2008, Patriot recorded a $4.9 million gain related to a structured settlement on a property transaction and received a $4.5 million settlement for past due coal royalties, which had previously been fully reserved due to the uncertainty of collection. Both transactions were recorded as “Other revenues” in the consolidated statements of operations. Additionally, in the second quarter of 2008, Patriot entered into two joint ventures for which it has contributed cash totaling $16.4 million and committed certain coal reserve rights. Patriot holds a 49% interest in each joint venture and accounts for the interests under the equity method of accounting. Patriot’s maximum exposure to loss is the value contributed plus additional future committed capital contributions, which, for one of the joint ventures, is capped at $4.1 million. The investment in these joint ventures was recorded in “Investments and other assets” in the consolidated balance sheets. One of the joint ventures commenced coal mining operations in the third quarter of 2008 and the other is expected to commence coal mining operations in 2009.
During 2007, Patriot sold approximately 88 million tons of non-strategic coal reserves and over 18,000 acres of surface land located in Kentucky for cash of $26.5 million and notes receivable of $69.4 million. Patriot recognized gains totaling $78.5 million on these transactions.
During 2006, Patriot sold coal reserves and surface land located in Kentucky and West Virginia for proceeds of $84.9 million including cash of $31.8 million and notes receivable of $53.1 million which resulted in a gain of $66.6 million. The gain from these transactions is included in “Net gain on disposal or exchange of assets” in the consolidated statements of operations.
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Earnings per Share
Basic earnings per share is computed by dividing net income by the number of weighted average common shares outstanding during the reporting period. Diluted earnings per share is calculated to give effect to all
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
potentially dilutive common shares that were outstanding during the reporting period. Earnings (loss) per share is not presented for periods prior to October 31, 2007, because Patriot was wholly-owned by Peabody and its affiliates prior to the spin-off.
For the year ended December 31, 2008 the effect of dilutive securities includes the dilutive impact of stock options and restricted stock awards. For the year ended December 31, 2008, the Company had additional potential dilutive securities outstanding representing 0.3 million common shares related to share-based compensation awards as described in Note 23 and 3.0 million common shares related to the convertible notes issuance described in Note 13 that were not included in the computation of dilutive securities because they were anti-dilutive for that period. For the year ended December 31, 2007, 65,858 shares related to share-based compensation awards were excluded from the diluted earnings per share calculation for the Company’s common stock because they were anti-dilutive for that period.
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Inventories
Inventories consisted of the following:
Saleable coal represents coal stockpiles that will be sold in current condition. Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Coal inventory costs include labor, supplies, equipment, operating overhead and other related costs. Materials, supplies and coal inventory are valued at the lower of average cost or market. The increase in inventories from December 31, 2007 to December 31, 2008 is primarily attributable to the Magnum acquisition.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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Accumulated Other Comprehensive Loss
The following table sets forth the components of comprehensive loss:
Comprehensive loss differs from net income (loss) by the amount of unrealized gain or loss resulting from valuation changes of the Company’s diesel fuel hedge and adjustments related to the change in funded status of various benefit plans during the periods. For the year ended December 31, 2006, comprehensive loss was impacted by the adjustment required by SFAS No. 158 to initially record the funded status of the Company’s pension and other post-retirement benefit plans.
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Leases
Patriot leases equipment and facilities, directly or through Peabody, under various non-cancelable operating lease agreements. Certain lease agreements require the maintenance of specified ratios and contain restrictive covenants that limit indebtedness, subsidiary dividends, investments, asset sales and other actions by both Peabody and Patriot. Rental expense under operating leases was $39.5 million, $30.9 million and $28.4 million for the years ended December 31, 2008, 2007 and 2006, respectively.
A substantial amount of the coal mined by Patriot is produced from mineral reserves leased from third-party land owners. Patriot leases these coal reserves under agreements that require royalties to be paid as the coal is mined. Certain of these lease agreements also require minimum annual royalties to be paid regardless of the amount of coal mined during the year. Total royalty expense was $71.6 million, $43.2 million and $51.0 million for the years ended December 31, 2008, 2007 and 2006, respectively.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Future minimum lease and royalty payments as of December 31, 2008, are as follows:
During 2002, Peabody entered into a transaction with Penn Virginia Resource Partners, L.P. (PVR) whereby two Peabody subsidiaries sold 120 million tons of coal reserves in exchange for $72.5 million in cash and 2.76 million units, or 15%, of the PVR master limited partnership. Patriot participated in the transaction, selling approximately 40 million tons of coal reserves with a net book value of $14.3 million in exchange for $40.0 million. Patriot leased back the coal from PVR and pays royalties as the coal is mined. A $25.7 million gain was deferred at the inception of this transaction, and $3.2 million of the gain was recognized in each of the years 2008, 2007 and 2006. The remaining deferred gain of $6.4 million at December 31, 2008 is intended to provide for potential exposure to loss resulting from continuing involvement in the properties and will be amortized to “Operating costs and expenses” in the consolidated statements of operations over the minimum remaining term of the lease, which ends December 31, 2010.
As of December 31, 2008, certain of the Company’s lease obligations were secured by $13.4 million outstanding letters of credit under Patriot’s Credit Facility.
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Trade Accounts Payable and Accrued Expenses
Trade accounts payable and accrued expenses consisted of the following:
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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Income Taxes
Net income (loss) before income taxes and minority interests was income of $146.9 million, loss of $102.1 million, and income of $6.0 million for the years ended December 31, 2008, 2007 and 2006, respectively, and consisted entirely of domestic results.
The income tax rate differed from the U.S. federal statutory rate as follows:
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities consisted of the following:
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” (FIN No. 48). This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.
Patriot adopted the provisions of FIN No. 48 on January 1, 2007, with no impact to retained earnings. At adoption and at December 31, 2008, the unrecognized tax benefits in our consolidated financial statements were immaterial, and if recognized, would not currently affect the Company’s effective tax rate as any recognition would be offset by valuation allowance. The Company does not expect any significant increases or decreases to our unrecognized tax benefits within 12 months of this reporting date.
Due to the immaterial nature of its unrecognized tax benefits and the existence of net operating loss carryforwards, the Company has not currently accrued interest on any of its unrecognized tax benefits. The Company has considered the application of penalties on its unrecognized tax benefits and has determined, based on several factors, including the existence of net operating loss carryforwards, that no accrual of penalties related to its unrecognized tax benefits is required. If the accrual of interest or penalties becomes appropriate, the Company will record an accrual as part of its income tax provision.
The Company’s deferred tax assets include net operating losses (NOL) carryforwards and alternative minimum tax (AMT) credits of $133.9 million and $20.3 million as of December 31, 2008 and 2007, respectively. The NOL carryforwards and AMT credits represent amounts apportioned to the Company in accordance with the Internal Revenue Code and Treasury Regulations at the time of the Company’s spin-off from Peabody on October 31, 2007, Magnum NOL carryforwards from periods prior to the merger, as well as taxable losses from the Company’s operations for the last two months of 2007 and for the calendar year ended December 31, 2008. The NOL carryforwards begin to expire in 2019, and the AMT credits have no expiration date.
Overall, the Company’s net deferred tax assets are offset by a valuation allowance of $202.4 million and $270.6 million as of December 31, 2008 and 2007, respectively. The valuation allowance decreased by $68.2 million for the year ended December 31, 2008 primarily as a result of the Magnum acquisition. The Company evaluated and assessed the expected near-term utilization of net operating loss carryforwards, book and taxable income trends, available tax strategies and the overall deferred tax position to determine the valuation allowance required as of December 31, 2008 and 2007.
The Federal and state income tax returns for the Magnum companies for the tax years 2005-2008 remain subject to examination by the relevant taxing authorities. The Company and the remainder of its subsidiaries were included in the consolidated Peabody income tax returns prior to November 1, 2007, with Peabody retaining all liability related to these returns. Therefore, for the Company and the remainder of its subsidiaries, Patriot only has examination exposure related to the Federal and state income tax returns for the two month tax year ended December 31, 2007.
The Company made no Federal income tax payments and made only immaterial state and local tax payments for the years ended December 31, 2008 and 2007.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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Long-Term Debt
Patriot’s total indebtedness consisted of the following:
Promissory Notes
In conjunction with an exchange transaction involving the acquisition of Illinois Basin coal reserves in 2005, the Company entered into Promissory Notes. The Promissory Notes and related interest are payable in annual installments of $1.7 million beginning January 2008. The Promissory Notes mature in January 2017. At December 31, 2008, the short-term portion of the Promissory Notes was $1.0 million.
Credit Facility
Effective October 31, 2007, the Company entered into a $500 million, four-year revolving credit facility, which includes a $50 million swingline sub-facility and a letter of credit sub-facility. This facility is available for the Company’s working capital requirements, capital expenditures and other corporate purposes. As of December 31, 2008, the balance of outstanding letters of credit issued against the credit facility totaled $351 million, and $23 million short-term borrowings were outstanding under the sub-facility. As of December 31, 2007, the balance of outstanding letters of credit issued against the credit facility totaled $254 million. Availability under the credit facility was $126 million and $247 million as of December 31, 2008 and 2007, respectively. The weighted-average effective interest rate of the sub-facility was 3.99% as of December 31, 2008.
The obligations under the Company’s credit facility are secured by a first lien on substantially all of our assets, including but not limited to certain of our mines and coal reserves and related fixtures and accounts receivable. The credit facility contains certain customary covenants, including financial covenants limiting the Company’s total indebtedness (maximum leverage ratio of 2.75) and requiring minimum EBITDA coverage of interest expense (minimum interest coverage ratio of 4.0), as well as certain limitations on, among other things, additional debt, liens, investments, acquisitions and capital expenditures, future dividends and asset sales. The credit facility calls for quarterly reporting of compliance with financial covenants. The financial covenants are calculated based on pro forma results as if we acquired Magnum on January 1, 2008 and EBITDA as defined by the credit agreement. The terms of the credit facility also contain certain customary events of default, which will give the lender the right to accelerate payments of outstanding debt in certain circumstances. Customary events of default include breach of covenants, failure to maintain required ratios, failure to make principal payments or to make interest or fee payments within a grace period, and default, beyond any applicable grace period, on any of the Company’s other indebtedness exceeding a certain amount.
In connection with the merger agreement with Magnum, Patriot entered into an amendment dated as of April 2, 2008 to the credit facility. The amendment among other things, (i) permitted the merger with Magnum and the transactions contemplated by the merger agreement, (ii) increased the rate of interest applicable to loans and letters of credit fees under the credit facility and (iii) modified certain covenants and related definitions to allow for changes in permitted indebtedness, permitted liens, permitted capital expenditures and other changes in respect of Patriot and its subsidiaries in connection with the acquisition. The increase in the interest rate and the covenant
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
modifications were effective with the closing of the acquisition. In connection with Patriot’s issuance of the convertible notes discussed below, Patriot entered into an amendment to the credit facility dated as of May 19, 2008, allowing the issuance of the convertible notes and modifying certain covenants for the period prior to the closing of the Magnum acquisition. On September 25, 2008, Patriot entered into an amendment to the credit facility allowing, among other things, permitted securitization programs without adjusting the capacity of the credit facility. At December 31, 2008 the Company was in compliance with the covenants of its amended credit facility.
Private Convertible Notes Issuance
On May 28, 2008, Patriot completed a private offering of $200 million in aggregate principal amount of 3.25% Convertible Senior Notes due 2013 (the notes), including $25 million related to the underwriters’ overallotment option. The net proceeds of the offering were $193.5 million after deducting the initial purchasers’ commissions and fees and expenses of the offering and were used to repay Magnum’s credit facility at the date of acquisition.
Interest on the notes is payable semi-annually in arrears on May 31 and November 30 of each year, beginning November 30, 2008. The notes mature on May 31, 2013, unless converted, repurchased or redeemed in accordance with their terms prior to such date. The notes are senior unsecured obligations and rank equally with all of the Company’s existing and future senior debt and are senior to any subordinated debt. Patriot used the proceeds of the offering to repay Magnum’s existing senior secured indebtedness and acquisition related fees and expenses. All remaining amounts were used for other general corporate purposes.
The notes are convertible into cash and, if applicable, shares of Patriot’s common stock during the period from issuance to February 15, 2013, subject to certain conditions of conversion as described below. The conversion rate for the notes is 14.7778 shares of Patriot’s common stock per $1,000 principal amount of notes, which is equivalent to a conversion price of approximately $67.67 per share of common stock. The conversion rate and the conversion price are subject to adjustment for certain dilutive events, such as a future stock split or a distribution of a stock dividend.
The notes require Patriot to settle all conversions by paying cash for the lesser of the principal amount or the conversion value of the notes, and by settling any excess of the conversion value over the principal amount in cash or shares, at the Company’s option.
Holders of the notes may convert their notes prior to the close of business on the business day immediately preceding February 15, 2013, only under the following circumstances: (1) during the five trading day period after any ten consecutive trading day period (the measurement period) in which the trading price per note for each trading day of that measurement period was less than 97% of the product of the last reported sale price of Patriot’s common stock and the conversion rate on each such trading day; (2) during any calendar quarter after the calendar quarter ending September 30, 2008, and only during such calendar quarter, if the last reported sale price of Patriot’s common stock for 20 or more trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the conversion price in effect on each such trading day; (3) if such holder’s notes have been called for redemption or (4) upon the occurrence of corporate events specified in the indenture. The notes will be convertible, regardless of the foregoing circumstances, at any time from, and including, February 15, 2013 until the close of business on the business day immediately preceding the maturity date.
The number of shares of Patriot’s common stock that it may deliver upon conversion will depend on the price of its common stock during an observation period as described in the indenture. Specifically, the number of shares deliverable upon conversion will increase as the common stock price increases above the conversion price of $67.67 per share during the observation period. The maximum number of shares that Patriot may deliver is 2,955,560. However, if certain fundamental changes occur in Patriot’s business that are deemed “make-whole fundamental changes” in the indenture, the number of shares deliverable on conversion may increase, up to a
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
maximum amount of 4,137,788 shares. These maximum amounts are subject to adjustment for certain dilutive events, such as a stock split or a distribution of a stock dividend.
Holders of the notes may require Patriot to repurchase all or a portion of their notes upon a fundamental change in Patriot’s business, as defined in the indenture. The holders would receive cash for 100% of the principal amount of the notes, plus any accrued and unpaid interest.
Patriot may redeem (i) some or all of the notes at any time on or after May 31, 2011, but only if the last reported sale price of Patriot’s common stock for 20 or more trading days in a period of 30 consecutive trading days ending on the trading day prior to the date Patriot provides the relevant notice of redemption exceeds 130% of the conversion price in effect on each such trading day, or (ii) all of the notes if at any time less than $20 million in aggregate principal amount of notes remain outstanding. In both cases, notes will be redeemed for cash at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus any accrued and unpaid interest up to, but excluding, the relevant redemption date.
Under the indenture for the notes, if Patriot fails to timely file any document or report required to be filed with the Securities and Exchange Commission pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, (other than reports on Form 8-K), Patriot is required to pay additional interest on the notes of 0.50% of the principal balance of the notes. Per the guidance set forth in SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), this additional interest feature is considered an embedded derivative. Management has determined the fair value of this embedded derivative is de minimis as the probability of reports not being filed timely is remote and the Company has no history of late submissions.
The notes and any shares of common stock issuable upon conversion have not been registered under the Securities Act of 1933, as amended (the Securities Act), or any state securities laws. The notes were only offered to qualified institutional buyers pursuant to Rule 144A promulgated under the Securities Act.
See Pending Adoption of Recent Accounting Pronouncements (Note 3) for additional information regarding changes for the accounting of Patriot’s convertible notes.
Bridge Loan Facility
In connection with the Magnum acquisition agreement, Patriot obtained a subordinated bridge loan financing commitment, allowing it to draw up to $150 million under the related bridge loan facility at the effective date of the acquisition to repay a portion of the outstanding debt of Magnum. Patriot terminated the financing commitment on May 30, 2008, as a result of the Convertible Senior Notes issuance. Patriot recognized $1.5 million in commitment fees in connection with the financing commitment, which were included in “Interest expense” in the consolidated statements of operations.
Capital Lease Obligations and Other
Capital lease obligations include obligations assumed in the Magnum acquisition, primarily for mining equipment (see Note 10 for additional information on the Company’s capital lease obligations). As of December 31, 2008, “Property, plant, equipment and mine development” on the consolidated balance sheets includes approximately $7.6 million related to assets subject to capital leases and $13.5 million related to a capital lease for the Blue Creek mining complex preparation plant that is under construction.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The aggregate amounts of long-term debt maturities subsequent to December 31, 2008, including capital lease obligations, were as follows:
Interest paid on long-term debt was $5.2 million for the year ended December 31, 2008. Prior to the spin-off, all cash payments for interest were made by the Company’s former parent, Peabody.
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Asset Retirement Obligations
Reconciliations of Patriot’s liability for asset retirement obligations were as follows:
As of December 31, 2008, asset retirement obligations of $224.2 million consisted of $171.8 million related to locations with active mining operations and $52.4 million related to locations that are closed or inactive. As of December 31, 2007, asset retirement obligations of $134.4 million consisted of $102.7 million related to locations with active mining operations and $31.7 million related to locations that are closed or inactive. The credit-adjusted, risk-free interest rates were 9.00% and 6.60% at January 1, 2008 and 2007, respectively.
For the year ended December 31, 2007, the Company recorded a $1.3 million reduction in its asset retirement obligations and expense associated with the disposal of non-strategic properties and the assumption of the related reclamation liabilities by the purchaser. For the year ended December 31, 2008, no similar reduction was recorded.
As of December 31, 2008 and 2007, Patriot had $135.5 million and $84.1 million, respectively, in surety bonds outstanding to secure the Company’s reclamation obligations or activities. As of December 31, 2007, Peabody had $19.9 million of self bonding outstanding that related to Patriot’s reclamation obligations or activities. In 2008, these self bonds were replaced with Patriot surety bonds.
As of December 31, 2008, Arch Coal, Inc. (Arch) held surety bonds of $91.9 million related to reclamation for properties acquired by Patriot in the Magnum acquisition. As a result of the acquisition, Patriot is required to post
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
letters of credit in Arch’s favor at an increasing percentage of the accrued reclamation liabilities beginning August 2009 through February 2011.
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Workers’ Compensation Obligations
Certain of Patriot’s operations are subject to the Federal Coal Mine Health and Safety Act of 1969, and the related workers’ compensation laws in the states in which the Company operates. These laws require Patriot’s operations to pay benefits for occupational disease resulting from coal workers’ pneumoconiosis (occupational disease). Provisions for occupational disease costs are based on determinations by independent actuaries or claims administrators.
Patriot provides income replacement and medical treatment for work related traumatic injury claims as required by applicable state law. Provisions for estimated claims incurred are recorded based on estimated loss rates applied to payroll and claim reserves determined by independent actuaries or claims administrators. Certain of the Company’s operations are required to contribute to state workers’ compensation funds for second injury and other costs incurred by the state fund based on a payroll-based assessment by the applicable state. Provisions are recorded based on the payroll-based assessment criteria.
The workers’ compensation provision consists of the following components:
The decline in traumatic workers’ compensation costs was primarily driven by the impact of changes in workers’ compensation law in West Virginia. Administrative fees have been reduced as a result of successfully self-administering, at a lower cost, claims that were previously administered by the state. In addition, the law changes have reduced the frequency and magnitude of claims.
The weighted-average assumptions used to determine the workers’ compensation provision were as follows:
Workers’ compensation obligations consist of amounts accrued for loss sensitive insurance premiums, uninsured claims, and related taxes and assessments under black lung and traumatic injury workers’ compensation programs.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The workers’ compensation obligations consisted of the following:
As a result of the adoption of SFAS No. 158 on December 31, 2006, the accrued workers’ compensation liability recorded on the consolidated balance sheets at December 31, 2008 and 2007 reflects the accumulated benefit obligation less any portion that is currently funded. The accumulated actuarial gain that had not yet been reflected in net periodic postretirement benefit costs was included in “Accumulated other comprehensive loss.”
As of December 31, 2008 and 2007, Patriot had $189.5 million and $183.8 million, respectively, in surety bonds and letters of credit outstanding to secure workers’ compensation obligations.
The reconciliation of changes in the occupational disease liability benefit obligation was as follows:
The liability for occupational disease claims represents the actuarially-determined present value of known claims and an estimate of future claims that will be awarded to current and former employees. The liability for occupational disease claims was based on a discount rate of 6.0% and 6.4% at December 31, 2008 and 2007, respectively. Traumatic injury workers’ compensation obligations are estimated from both case reserves and actuarial determinations of historical trends, discounted at 6.1% and 5.8% as of December 31, 2008 and 2007, respectively.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Federal Black Lung Excise Tax Refund Claims
In addition to the obligations discussed above, certain subsidiaries of Patriot are required to pay black lung excise taxes to the Federal Black Lung Trust Fund (the Trust Fund). The Trust Fund pays occupational disease benefits to entitled former miners who worked prior to July 1, 1973. Excise taxes are based on the selling price of coal, up to a maximum of $1.10 per ton for underground mines and $0.55 per ton for surface mines. The Company has a receivable for excise tax refunds of $5.8 million as of December 31, 2008, related to new legislation that allows for excise taxes paid in prior years on export coal and related interest to be refundable to the Company, which is included in “Accounts receivable and other” in the consolidated balance sheets. The refund is reflected in the consolidated statements of operations as a reduction to “Operating costs and expenses” of $2.4 million and an increase to “Interest income” of $3.4 million.
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Pension and Savings Plans
Multi-Employer Pension Plans
Certain subsidiaries participate in multi-employer pension plans (the 1950 Plan and the 1974 Plan), which provide defined benefits to substantially all hourly coal production workers represented by the UMWA. Benefits under the UMWA plans are computed based on service with the subsidiaries or other signatory employers. The 1950 Plan and the 1974 Plan qualify under SFAS No. 106 as multi-employer benefit plans, which allows Patriot to recognize expense as contributions are made. The expense related to these funds was $13.5 million and $6.9 million for the years ended December 31, 2008 and 2007, respectively. There were no contributions to the multi-employer pension plans during the year ended December 31, 2006. In December 2006, the 2007 National Bituminous Coal Wage Agreement was signed, which required funding of the 1974 Plan through 2011 under a phased funding schedule. The funding is based on an hourly rate for certain UMWA workers. Under the labor contract, the per-hour funding rate increased to $2.00 in 2007 and increases each year thereafter until reaching $5.50 in 2011. The Company expects to pay approximately $19.7 million related to these funds in 2009.
Defined Contribution Plans
Patriot sponsors employee retirement accounts under a 401(k) plan for eligible salaried and non-union hourly employees of the Company (the 401(k) Plan). Patriot matches voluntary contributions to the 401(k) Plan up to specified levels. Prior to the spin-off, Peabody also sponsored a similar 401(k) plan in which eligible Patriot employees could participate. A performance contribution feature under both Patriot’s plan and Peabody’s plan allows for additional contributions based upon meeting specified performance targets. The Company recognized expense for these plans of $6.1 million, $3.4 million and $5.6 million for the years ended December 31, 2008, 2007 and 2006, respectively.
In addition, Magnum had three defined contribution plans prior to the acquisition. The first two were the Magnum Coal Company 401(k) Plan and the Day Plan, LLC. These plans matched voluntary employee contributions up to specified levels, similar to Patriot’s 401(k) Plan. Additionally, certain employees were covered by the Magnum Coal Company Defined Contribution Retirement Plan based on age and compensation. Magnum funded the plan in an amount not less than the minimum statutory funding requirements or more than the maximum amount allowed to be deducted for federal income tax purposes. Magnum’s expense under these plans was $2.4 million for the year ended December 31, 2008. These plans were merged into Patriot’s 401(k) Plan effective January 1, 2009.
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Postretirement Healthcare Benefits
The Company currently provides healthcare and life insurance benefits to qualifying salaried and hourly retirees and their dependents from defined benefit plans established by Peabody and continued by Patriot after the spin-off. Plan coverage for health and life insurance benefits is provided to certain hourly retirees in accordance with the applicable labor agreement.
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Net periodic postretirement benefit costs included the following components:
The following table sets forth the plans’ combined funded status reconciled with the amounts shown in the consolidated balance sheets:
Peabody assumed certain of the Company’s retiree healthcare liabilities at the spin-off, which are valued at $597.6 million as of December 31, 2008 and are not reflected above. These liabilities included certain obligations under the Coal Act for which Peabody and Patriot are jointly and severally liable, obligations under the 2007 National Bituminous Coal Wage Act for which the Company is secondarily liable, and obligations for certain active, vested employees of the Company.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
As a result of the adoption of SFAS No. 158 on December 31, 2006, the accrued postretirement benefit liability recorded on the consolidated balance sheets at December 31, 2008 and 2007 reflects the accumulated postretirement benefit obligation less any portion that is currently funded. The accumulated actuarial loss and prior service costs that had not yet been reflected in net periodic postretirement benefit costs were included in “Accumulated other comprehensive loss”.
The Company amortizes actuarial gains and losses using a 0% corridor with an amortization period that covers the average remaining service period of active employees (6.47 years, 6.47 years and 8.47 years utilized for 2008, 2007 and 2006, respectively). For the year ending December 31, 2009, an estimated actuarial loss of $18.4 million and an estimated gain from prior service cost of $0.6 million will be amortized from accumulated comprehensive loss into net periodic postretirement costs.
The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:
The weighted-average assumptions used to determine net periodic benefit cost were as follows:
The discount rate used for Magnum for the five months of 2008 following acquisition was 7.25%. The discount rate above for 2008 was for the full twelve months.
The following presents information about the assumed healthcare cost trend rate:
Assumed healthcare cost trend rates have a significant effect on the amounts reported for healthcare plans. A one percentage-point change in the assumed healthcare cost trend would have the following effects:
Plan Assets
The Company’s postretirement benefit plans are unfunded.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Estimated Future Benefits Payments
The following benefit payments (net of retiree contributions), which reflect expected future service, as appropriate, are expected to be paid by Patriot:
Medicare and Other Plan Changes
Effective January 1, 2007, the Company entered into a new labor relations agreement for certain UMWA represented employees in Appalachia. The provisions of the new agreement resulted in an actuarially determined projected increase in healthcare costs of $11.7 million primarily in relation to the elimination of certain deductibles.
Multi-Employer Benefit Plans
Retirees formerly employed by certain subsidiaries and their predecessors, who were members of the UMWA; last worked before January 1, 1976; and were receiving health benefits on July 20, 1992; receive health benefits provided by the Combined Fund, a fund created by the Coal Act. The Coal Act requires former employers (including certain entities of the Company) and their affiliates to contribute to the Combined Fund according to a formula. The Coal Act also established the 1992 Benefit Plan, which provides medical and death benefits to persons who are not eligible for the Combined Fund, who retired prior to October 1, 1994. A prior national labor agreement established the 1993 Benefit Plan to provide health benefits for retired miners not covered by the Coal Act. The 1993 Benefit Plan provides benefits to qualifying retired former employees, who retired after September 30, 1994, of certain signatory companies which have gone out of business and defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business. The Company expects to pay $19.1 million in 2009 related to these funds.
The Surface Mining Control and Reclamation Act of 2006 (the 2006 Act), enacted in December 2006, amended the federal laws establishing the Combined Fund, 1992 Benefit Plan and the 1993 Benefit Plan. Among other things, the 2006 Act guarantees full funding of all beneficiaries in the Combined Fund, provides funds on a phased-in basis for the 1992 Benefit Plan, and authorizes the trustees of the 1993 Benefit Plan to determine the contribution rates through 2010 for pre-2007 beneficiaries. The new and additional federal expenditures to the Combined Fund, 1992 Benefit Plan, 1993 Benefit Plan and certain Abandoned Mine Land payments to the states and Indian tribes are collectively limited by an aggregate annual cap of $490 million. To the extent that (i) the annual funding of the programs exceeds this amount (plus the amount of interest from the Abandoned Mine Land trust fund paid with respect to the Combined Fund), and (ii) Congress does not allocate additional funds to cover the shortfall, contributing employers and affiliates, including some of the Company’s entities, would be responsible for the additional costs.
The Company has recorded actuarially determined liabilities representing a portion of the amount anticipated to be due to these funds. The noncurrent portion related to these obligations was $42.5 million and $31.1 million as of December 31, 2008 and 2007, respectively, and is reflected in “Obligation to industry fund” in the consolidated balance sheets. The current portion related to these obligations reflected in “Trade accounts payable and accrued expenses” in the consolidated balance sheets was $6.6 million and $5.2 million as of December 31, 2008 and 2007,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
respectively. Expense of $2.6 million was recognized related to these obligations for the year ended December 31, 2008, and consisted of interest discount of $2.7 million and amortization of actuarial gain of $0.1 million. Expense of $2.9 million was recognized related to these obligations for the year ended December 31, 2007, and consisted of interest discount of $2.3 million and amortization of actuarial loss of $0.6 million. Expense of $2.5 million was recognized related to these obligations for the year ended December 31, 2006, and consisted of interest discount of $2.4 million and amortization of actuarial loss of $0.1 million. The Company made payments of $6.1 million, $5.5 million and $8.3 million to these obligations for the years ended December 31, 2008, 2007 and 2006, respectively.
As a result of the adoption of SFAS No. 158 on December 31, 2006, the obligation to industry fund recorded on the consolidated balance sheets at December 31, 2008 and 2007 reflects the obligation less any portion that is currently funded. The accumulated actuarial gain that has not yet been reflected in expense as of December 31, 2008 and 2007 was $0.8 million and $0.6 million, respectively, and is included in “Accumulated other comprehensive loss.”
A portion of these funds qualifies under SFAS No. 106 as multi-employer benefit plans, which allows the Company to recognize expense as contributions are made. The expense related to these funds was $11.8 million, $15.9 million and $6.9 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Pursuant to the provisions of the Coal Act and the 1992 Benefit Plan, the Company was required to provide security in an amount equal to three times the annual cost of providing healthcare benefits for all individuals receiving benefits from the 1992 Benefit Plan who are attributable to the Company, plus all individuals receiving benefits from an individual employer plan maintained by the Company who are entitled to receive such benefits. Beginning in 2007, the amount of security the Company was required to provide for the 1992 Benefit Plan was reduced to one times the annual cost to provide the above mentioned healthcare benefits.
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Related Party Transactions
Prior to the spin-off, Patriot routinely entered into transactions with Peabody and its affiliates. The terms of these transactions were outlined in agreements executed by Peabody and its affiliates.
The Company sold 12.1 million tons of coal resulting in revenues of $578.1 million for the year ended December 31, 2008; 21.6 million tons of coal resulting in revenues of $1.03 billion for the year ended December 31, 2007; and 24.3 million tons of coal resulting in revenues of $1.13 billion for the year ended December 31, 2006 to a marketing affiliate of Peabody, which negotiated and maintained coal sales contracts. These sales were made at prices paid by outside third-party customers, with the exception in 2008 of one major coal supply agreement which was re-priced to reflect the then market price as part of the spin-off from Peabody. As of December 31, 2008, “Accounts receivable and other” on the consolidated balances sheets included $34.8 million of outstanding trade receivables from Peabody related to coal sales. As of December 31, 2007, the majority of the “Accounts receivable and other” on the consolidated balance sheets represented outstanding trade receivables from Peabody related to coal sales.
Selling and administrative expenses include $37.3 million and $47.9 million for the twelve months ended December 31, 2007 and 2006, respectively, for services provided by Peabody and represent an allocation of Peabody general corporate expenses to all of its mining operations, both foreign and domestic, based on principal activity, headcount, tons sold and revenues as applicable to the specific expense being allocated. The allocated expenses generally reflected service costs for: marketing and sales, legal, finance and treasury, public relations, human resources, environmental engineering and internal audit. Different general accounting allocation bases or methods could have been used and could have resulted in significantly different results. The allocation from Peabody was not necessarily indicative of the selling and administrative expenses that would have been incurred if Patriot had been an independent entity.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Patriot recognized interest expense of $4.1 million and $5.0 million for the twelve months ended December 31, 2007 and 2006, respectively, related to a $62.0 million intercompany demand note payable to Peabody, which was forgiven at spin-off.
Patriot entered into certain agreements with Peabody to provide transition services following the spin-off. As of September 30, 2008, Peabody is no longer providing support to Patriot. For the twelve months ended December 31, 2008, transition service expenses were $1.4 million, and are included in “Selling and administrative expenses” in the consolidated statements of operations.
In 2007 and 2006, the Company received contributions from Peabody of $43.6 million and $44.5 million, respectively, primarily for the funding of acquisitions.
In June 2007, Peabody exchanged numerous oil and gas rights and assets owned throughout its operations, including some owned by Patriot, for coal reserves in West Virginia and Kentucky. Peabody did not allocate gain recognized from this transaction to Patriot but contributed to Patriot approximately 28 million tons of West Virginia coal reserves. These reserves are located in the Pittsburgh coal seam adjacent to Patriot’s Federal No. 2 mining operations and were valued at $45.2 million.
ArcLight Energy Partners Fund I L.P. (ArcLight) is a significant stockholder of Patriot due to its former ownership of Magnum. In January 2007, ArcLight purchased from a third party rights to a royalty stream based on coal mined on certain properties, and then leased the rights to one of Magnum’s operations. Royalty payments to ArcLight for the period from July 23, 2008 to December 31, 2008 were approximately $475,000.
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Guarantees
In the normal course of business, Patriot is a party to guarantees and financial instruments with off-balance-sheet risk, such as bank letters of credit, performance or surety bonds and other guarantees and indemnities, which are not reflected in the accompanying consolidated balance sheets. Such financial instruments are valued based on the amount of exposure under the instrument and the likelihood of required performance. Management does not expect any material losses to result from these guarantees or off-balance-sheet instruments.
Letters of Credit and Bonding
The Company’s letters of credit and surety bonds in support of the Company’s reclamation, lease, workers’ compensation and other obligations were as follows as of December 31, 2008:
(1)
Other includes letters of credit and surety bonds related to collateral for surety companies and bank guarantees, road maintenance and performance guarantees.
Additionally, as of December 31, 2007, Peabody continued to guarantee certain bonds (self bonding) related to Patriot liabilities that had not yet been replaced by Patriot surety bonds. Patriot replaced these Peabody self bonds in 2008.
As of December 31, 2008, Arch Coal, Inc. (Arch) held surety bonds of $93.6 million related to properties acquired by Patriot in the Magnum acquisition, of which $91.9 million related to reclamation. As a result of the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
acquisition, Patriot is required to post letters of credit in Arch’s favor at an increasing percentage of the accrued reclamation liabilities beginning August 2009 through February 2011.
In relation to an exchange transaction involving the acquisition of Illinois Basin coal reserves in 2005, the Company guaranteed bonding for a partnership in which it formerly held an interest. The aggregate amount that the Company guaranteed was $2.8 million and the fair value of the guarantee recognized as a liability was $0.3 million as of December 31, 2008. The Company’s obligation under the guarantee extends to September 2015.
Other Guarantees
Patriot is the lessee or sublessee under numerous equipment and property leases. It is common in such commercial lease transactions for Patriot, as the lessee, to agree to indemnify the lessor for the value of the property or equipment leased, should the property be damaged or lost during the course of Patriot’s operations. Patriot expects that losses with respect to leased property would be covered by insurance (subject to deductibles). Patriot and certain of its subsidiaries have guaranteed other subsidiaries’ performance under their various lease obligations. Aside from indemnification of the lessor for the value of the property leased, Patriot’s maximum potential obligations under their leases are equal to the respective future minimum lease payments, assuming no amounts could be recovered from third parties.
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Commitments and Contingencies
Commitments
As of December 31, 2008, purchase commitments for capital expenditures were $68.1 million.
Other
At times Patriot becomes a party to claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business. Management believes that the ultimate resolution of such pending or threatened proceedings is not reasonably likely to have a material effect on Patriot’s financial position, results of operations or cash flows. The Company’s significant legal proceedings are discussed below.
Flood Litigation
Flood Litigation
One of the Company’s subsidiaries, Catenary Coal Company, LLC (Catenary), has been named as defendant, along with various other property owners, coal companies, timbering companies and oil and natural gas companies, in connection with alleged damages arising from flooding that occurred on July 8, 2001 in various watersheds primarily located in southern West Virginia (referred to as the 2001 flood litigation). Pursuant to orders from the West Virginia Supreme Court of Appeals, the cases are being handled as mass litigation, and a panel of three judges was appointed to handle the matters that have been divided between the judges pursuant to the various watersheds.
One of the cases, in the Upper Guyandotte River watershed, went to trial against two defendants, both of which were land holding companies, to determine whether the plaintiffs could establish liability. The jury found in favor of the plaintiffs, but the judge in this matter set aside the verdict stating he committed reversible error by allowing certain testimony of the plaintiffs’ experts. The judge went on to address the core foundation necessary to prevail in the flood litigation in his order, which is whether the plaintiffs can scientifically establish that a certain flood event caused and/or contributed to injury and, if so, who caused the injury and what persons were injured by such conduct. An appeal of this order was filed with the West Virginia Supreme Court of Appeals. The West Virginia Supreme Court issued its decision reversing the trial judge’s order and remanded the matter to the Mass Litigation Panel for further disposition.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In the Coal River watershed of the 2001 flood litigation, another judge in the panel provided an opportunity for the plaintiffs to amend their complaints to more specifically identify, among other things, the defendants’ specific injury-causing conduct, and the amount of damages sustained by each plaintiff. The plaintiffs were unable to meet the pleading standard announced by the judge and in January 2007, the judge entered an order that granted defendants’ motions to dismiss with prejudice. An appeal of this order was filed with the West Virginia Supreme Court of Appeals. The West Virginia Supreme Court issued its decision reversing the trial judge’s order and remanded the matter to the Mass Litigation Panel for further disposition.
Pursuant to the purchase and sale agreement related to Magnum, Arch Coal, Inc. (Arch) indemnifies the Company against claims arising from certain pending litigation proceedings, including the 2001 flood litigation, which obligation will continue indefinitely. The failure of Arch to satisfy its indemnification obligations under the purchase agreement could have a material adverse effect on the Company.
Flood Litigation
In 2006, Hobet Mining, LLC (Hobet) and Catenary, two of the Company’s subsidiaries, were named as defendants along with various other property owners, coal companies, timbering companies and oil and natural gas companies, arising from flooding that occurred on May 30, 2004 in various watersheds primarily located in southern West Virginia. This litigation is pending before two different judges in the Circuit Court of Logan County, West Virginia.
In the first action, the plaintiffs have asserted that (i) Hobet failed to maintain an approved drainage control system for a pond on land on, near, and/or contiguous to the sites of flooding; and (ii) Hobet participated in the development of plans to grade, blast, and alter the land on, near, and/or contiguous to the sites of the flooding. Hobet has filed a motion to dismiss both claims based upon the assertion that insufficient facts have been stated to support the claims of the plaintiffs.
In the second action, on behalf of Catenary and Hobet, motions to dismiss have been filed, asserting that the allegations asserted by the plaintiffs are conclusory in nature and likely deficient as a matter of law. Most of the other defendants also filed motions to dismiss. Both actions were stayed during the pendency of the appeals to the West Virginia Supreme Court of Appeals in the 2001 flood litigation.
The outcome of the West Virginia flood litigation is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes this matter is likely to be resolved without a material adverse effect on its financial condition, results of operations and cash flows.
Clean Water Act Permit Issues
The federal Clean Water Act and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the United States. In particular, the Clean Water Act requires effluent limitations and treatment standards for wastewater discharge through the NPDES program. NPDES permits, which the Company must obtain for both active and historical mining operations, govern the discharge of pollutants into water and require regular monitoring and reporting and set forth performance standards. States are empowered to develop and enforce “in stream” water quality standards, which are subject to change and must be approved by the EPA. In stream standards vary from state to state.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Environmental claims and litigation in connection with our various NPDES permits, and related Clean Water Act issues, include the following:
EPA Consent Decree
In February 2009, the Company announced that it had entered into a consent decree with the EPA and the West Virginia Department of Environmental Protection (WVDEP) to resolve certain claims under the Clean Water Act and the West Virginia Water Pollution Control Act relating to its NPDES permits at several mining operations in West Virginia. The consent decree does not cover issues related to discharge limits for selenium, and it is subject to public comment, which could result in delays, modifications, or even withdrawal of the consent decree. Under the current terms of the consent decree, the Company is obligated to pay a civil penalty of $6.5 million in 2009. The Company also could be subject to stipulated penalties in the future for failure to comply with certain permit requirements as well as certain other terms of the consent decree. Because the Company’s operations are complex and it periodically experiences exceedances of its permit limitations, it is possible that the Company will have to pay stipulated penalties in the future, but the Company does not expect the amounts of any such penalties would be material. The civil penalty of $6.5 million was included in the estimated fair value of acquired environmental liabilities accrued as part of the Magnum acquisition purchase accounting described in Note 4.
The consent decree also requires the Company to implement an enhanced company-wide environmental management system, which will include regular compliance audits, electronic tracking and reporting, and annual training for all employees and contractors with environmental responsibilities. In addition, the Company will complete several stream restoration projects in consultation with the EPA and WVDEP. These latter requirements could result in incremental operating costs in addition to the $6.5 million civil penalty. Initial estimates ranging from $3 million to $6 million of incremental costs could increase or decrease as the Company implements the various requirements.
In a separate administrative proceeding with the WVDEP, the Company has agreed to pay a civil penalty of $315,000 for past violations of NPDES permits held by certain subsidiaries.
Apogee Coal Company, LLC (Apogee)
In 2007, Apogee, a subsidiary of the Company, was sued in the U.S. District Court for the Southern District of West Virginia by the Ohio Valley Environmental Coalition, Inc. (OVEC) and another environmental group (pursuant to the citizen suit provisions of the Clean Water Act). The Company refers to this lawsuit as the Federal Apogee Case. This lawsuit alleges that Apogee has violated water discharge limits for selenium set forth in one of its NPDES permits. The lawsuit seeks fines and penalties as well as injunctions prohibiting Apogee from further violating laws and its permit.
Currently, there is no reasonably available technology that has been proven effective at addressing selenium exceedances in mining outfalls. As a result, the WVDEP has deferred the obligations to comply with the selenium discharge limits in most permits related to mining outfalls until April 2010. However, on May 28, 2008, the judge in the Federal Apogee Case determined that the attempted deferral of the selenium discharge limits set forth in the relevant Apogee permit failed to meet certain procedural requirements and ordered Apogee to develop and implement a treatment plan or to show cause of its inability to do so. After a July 2008 hearing, the judge ordered Apogee to submit a report specifying an explanation of the treatment alternatives under consideration. After Apogee submitted its report, the judge entered an order requiring complete installation of treatment no later than May 31, 2009, and final compliance with the selenium discharge limits in Apogee’s NPDES permit no later than June 30, 2009.
The Company is actively engaged in studying potential solutions to controlling selenium discharges and is installing treatment facilities at various permitted outfalls in an effort to comply with the deadlines established in the Federal Apogee Case. The potential solutions identified to date, some of which have been provided to the court,
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
have not been proven to be effective and otherwise may not be feasible due to a range of problems concerning technological issues, prohibitive implementation costs and other issues. While the Company is actively continuing to explore options, there can be no assurance as to when a definitive solution will be identified and implemented. As a result, it is possible that the Company will be unable to meet the court order. While these selenium discharge issues generally relate to historical rather than ongoing mining operations, any failure to meet the deadlines or to otherwise comply with selenium limits in the Company’s permits could result in further litigation against the Company, an inability to obtain new permits or to maintain existing permits, the incurrence of significant and material fines and penalties or other costs and could otherwise materially adversely affect the Company’s results of operations, cash flows and financial condition.
Penalties related to the Company’s violations of the selenium discharge limits under its NPDES permit will be addressed at a separate hearing before the court in November 2009, and the Company may be subject to further penalties in the event it is unable to comply with the deadlines established by the court’s August 2008 order. Finally, the Company will likely incur significant costs related to the investigations and ultimate installation and maintenance of treatment facilities designed to control selenium discharges. The amount of these civil penalties and other costs may be significant, although the Company is unable to reasonably estimate such costs at this time.
The outcome of this litigation is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated.
Hobet
In 2007, Hobet was sued for exceedances of effluent limits contained in its NPDES permits in state court in Boone County by the WVDEP. The Company refers to this case as the WVDEP Action. In 2008, OVEC and another environmental group filed a lawsuit against Hobet and WVDEP in the U.S. District Court for the Southern District of West Virginia (pursuant to the citizen suit provisions of the Clean Water Act). The Company refers to this case as the Federal Hobet Case. The Federal Hobet Case involves the same NPDES permits that are the subject of the WVDEP Action in state court. However, the Federal Hobet Case is focused exclusively on selenium exceedances in permitted water discharges, while the WVDEP Action addresses several pollutant discharge limits including selenium.
The WVDEP Action was resolved by a settlement and consent order entered in the Boone County circuit court on September 5, 2008. As part of the settlement, the Company agreed to pay approximately $1.5 million in civil penalties, with $500,000 due immediately and the remaining approximately $1 million payable in ten monthly installments. The settlement also requires the Company to complete five supplemental environmental projects estimated to cost approximately $2.6 million, many of which focus on identifying methods for treatment of selenium discharges and studying the effects of selenium on aquatic wildlife. Finally, the Company agreed to make gradual reductions in its selenium discharges from its Hobet Job 21 Surface Mine, achieving full compliance with its NPDES permits by April 2010, and to study potential treatments for wastewater runoff.
Following the WVDEP Action settlement, motions to dismiss and for summary judgment have been filed by both sides and are pending in the Federal Hobet Case. To date, the federal court has dismissed all injunctive claims asserted by the plaintiffs as moot because of the WVDEP Action settlement. However, the federal court is still considering a pending motion to dismiss plaintiffs’ claims for civil penalties. The Company expects to pay an additional penalty relating to the period of time not covered by the WVDEP Action settlement, which could exceed $100,000, but which the Company does not anticipate will be material. It is also possible that the federal court would hold that the plaintiffs continue to maintain viable claims for additional civil penalties.
As a result of the litigation involving Apogee and Hobet, the process of applying for new permits has become more time-consuming and complex, the review and approval process is taking longer, and in certain cases, new
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
permits may not be issued. The lack of proven treatment methods for selenium discharges also causes uncertainty as to the magnitude of the Company’s future liability. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated.
Comprehensive Enviromental Response, Compensation and Liability Act (CERCLA)
CERCLA and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to natural resources. Under CERCLA and many similar state statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault. These regulations could require the Company to do some or all of the following: (i) remove or mitigate the effects on the environment at various sites from the disposal or release of certain substances; (ii) perform remediation work at such sites; and (iii) pay damages for loss of use and non-use values.
Although waste substances generated by coal mining and processing are generally not regarded as hazardous substances for the purposes of CERCLA and similar legislation and are generally covered by SMCRA, some products used by coal companies in operations, such as chemicals, and the disposal of these products are governed by CERCLA. Thus, coal mines currently or previously owned or operated by the Company, and sites to which the Company has sent waste materials, may be subject to liability under CERCLA and similar state laws. A predecessor of one of the Company’s subsidiaries has been named as a potentially responsible party at a third-party site, but given the large number of entities involved at the site and the Company’s anticipated share of expected cleanup costs, the Company believes that its ultimate liability, if any, will not be material to the Company’s financial condition and results of operations.
Other Environmental Litigation
Apogee has been sued, along with eight other defendants, including Monsanto Company, Pharmacia Corporation and Akzo Nobel Chemicals, Inc. by certain plaintiffs in state court in Putnam County, West Virginia. The lawsuits were filed in October 2007, but not served on Apogee until February 2008, and each are identical except for the named plaintiff. They each allege personal injury occasioned by exposure to dioxin generated by a plant owned and operated by certain of the other defendants during production of a chemical, 2,4,5-T, from 1949-1969. Apogee is alleged to be liable as the successor to the liabilities of a company that owned and/or controlled a dump site known as the Manila Creek landfill, which allegedly received and incinerated dioxin-contaminated waste from the plant. The lawsuits seek class action certification as well as compensatory and punitive damages for personal injury. Under the terms of the governing lease, Monsanto has assumed the defense of these lawsuits and has agreed to indemnify Apogee for any related damages. The failure of Monsanto to satisfy its indemnification obligations under the lease could have a material adverse effect on the Company.
One of the Company’s subsidiaries operated the Eagle No. 2 mine located near Shawneetown, Illinois from 1969 until closure of the mine in July of 1993. In 1999, the State of Illinois brought a proceeding before the Illinois Pollution Control Board against the subsidiary alleging that groundwater contamination due to leaching from a coal waste pile at the mine site violated state standards. The subsidiary has developed a remediation plan with the State of Illinois and is in litigation with the Illinois Attorney General’s office with respect to its claim for a civil penalty of $1.3 million.
On December 31, 2008, 45 related lawsuits were filed by 116 plaintiffs against several coal companies, including one of the Company’s subsidiaries in the Circuit Court of Boone County, West Virginia. The plaintiffs in each case allege contamination of their drinking water wells from slurry impoundments in Boone County. The lawsuits seek property damages, personal injury damages and medical monitoring costs. Because of the early stage of the lawsuits, we are unable to predict the likelihood of success of the plaintiffs’ claims, though the Company intends to vigorously defend against all claims.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The outcome of this other environmental litigation is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes these matters are likely to be resolved without a material adverse effect on the Company’s financial condition, results of operations and cash flows.
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Segment Information
Patriot reports its operations through two reportable operating segments, Appalachia and Illinois Basin. The Appalachia and Illinois Basin segments primarily consist of Patriot’s mining operations in West Virginia and Kentucky, respectively. The principal business of the Appalachia segment is the mining, preparation and sale of thermal coal, sold primarily to electric utilities and metallurgical coal, sold to steel and coke producers. The principal business of the Illinois Basin segment is the mining, preparation and sale of thermal coal, sold primarily to electric utilities. For the twelve months ended December 31, 2008, 79% of Patriot’s sales were to electricity generators and 21% to steel and coke producers. For the twelve months ended December 31, 2008 and 2007, Patriot’s revenues attributable to foreign countries, based on where the product was shipped, were $241.3 million and $120.8 million, respectively. Patriot utilizes underground and surface mining methods and produces coal with high and medium Btu content. Patriot’s operations have relatively short shipping distances from the mine to most of its domestic utility customers and certain metallurgical coal customers. “Corporate and Other” includes selling and administrative expenses, net gains on disposal or exchange of assets and costs associated with past mining obligations.
Patriot’s chief operating decision makers use Adjusted EBITDA as the primary measure of segment profit and loss. Adjusted EBITDA is defined as net income (loss) before deducting net interest expense; income taxes; minority interests; asset retirement obligation expense; depreciation, depletion and amortization; and net sales contract accretion excluding back-to-back coal purchase and sales contracts. The net contract accretion on the back-to-back coal purchase and sale contracts reflects the net accretion related to certain coal purchase and sales contracts existing prior to July 23, 2008, whereby Magnum purchased coal from third parties to fulfill tonnage commitments on sales contracts. Because Segment Adjusted EBITDA is not calculated identically by all companies, Patriot’s calculation may not be comparable to similarly titled measures of other companies.
Operating segment results for the year ended December 31, 2008 were as follows:
Operating segment results for the year ended December 31, 2007 were as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Operating segment results for the year ended December 31, 2006 were as follows:
(1)
Corporate and Other results include the gains on disposal of assets discussed in Note 6.
A reconciliation of Adjusted EBITDA to net income (loss) follows:
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Stockholders’ Equity
Common Stock
On October 31, 2007, the spin-off of Patriot from Peabody was completed and holders of Peabody common stock received a dividend of one share of Patriot common stock for each ten shares of Peabody common stock that they owned. The Company has 100 million authorized shares of $0.01 par value common stock. Each share of common stock will be entitled to one vote in the election of directors and all other matters submitted to stockholder vote. Except as otherwise required by law or provided in any resolution adopted by the Board of Directors with respect to any series of preferred stock, the holders of common stock will possess all voting power. The holders of common stock do not have cumulative voting rights. In general, all matters submitted to a meeting of stockholders, other than as described below, shall be decided by vote of a majority of the shares of Patriot’s common stock. Directors are elected by a plurality of the shares of Patriot’s common stock.
Subject to preferences that may be applicable to any series of preferred stock, the owners of Patriot’s common stock may receive dividends when declared by the Board of Directors. Common stockholders will share equally in the distribution of all assets remaining after payment to creditors and preferred stockholders upon liquidation, dissolution or winding up of the Company, whether voluntarily or not. The common stock will have no preemptive or similar rights.
Effective August 11, 2008, the Company implemented a two-for-one stock split on all shares of its common stock. All share and per share amounts in these consolidated financial statements and related notes reflect the stock split.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes common share activity from October 31, 2007 to December 31, 2008:
Preferred Stock
In addition to the common stock, the Board of Directors is authorized to issue up to 10 million shares of $0.01 par value preferred stock. The authorized preferred shares include one million shares of Series A Junior Participating Preferred Stock. Patriot’s certificate of incorporation authorizes the Board of Directors, without the approval of the stockholders, to fix the designation, powers, preferences and rights of one or more series of preferred stock, which may be greater than those of the common stock. Patriot believes that the ability of the Board to issue one or more series of preferred stock will provide the Company with flexibility in structuring possible future financings and acquisitions and in meeting other corporate needs that might arise. The issuance of shares of preferred stock, or the issuance of rights to purchase shares of preferred stock, could be used to discourage an unsolicited acquisition proposal. There were no outstanding shares of preferred stock as of December 31, 2008.
Preferred Share Purchase Rights Plan and Series A Junior Participating Preferred Stock
The Board of Directors of Patriot adopted a stockholders rights plan pursuant to the Rights Agreement with American Stock Transfer & Trust Company (the Rights Agreement). In connection with the Rights Agreement, on October 31, 2007, the Company filed the Certificate of Designations of Series A Junior Participating Preferred Stock (the Certificate of Designations) with the Secretary of State of the State of Delaware. Pursuant to the Certificate of Designations, the Company designated 1,000,000 shares of preferred stock as Series A Junior Participating Preferred Stock having the designations, rights, preferences and limitations set forth in the Rights Agreement. Each preferred share purchase right represents the right to purchase one-half of one-hundredth of a share of Series A Junior Participating Preferred Stock.
The rights have certain anti-takeover effects. If the rights become exercisable, the rights will cause substantial dilution to a person or group that attempts to acquire Patriot on terms not approved by the Board of Directors, except pursuant to any offer conditioned on a substantial number of rights being acquired. The rights should not interfere with any merger or other business combination approved by the Board since the rights may be redeemed by the Company at a nominal price prior to the time that a person or group has acquired beneficial ownership of 15% or more of common stock. Thus, the rights are intended to encourage persons who may seek to acquire control of the Company to initiate such an acquisition through negotiations with the Board. However, the effect of the rights may be to discourage a third party from making a partial tender offer or otherwise attempting to obtain a substantial equity position in Patriot’s equity securities or seeking to obtain control of the Company. To the extent any potential acquirers are deterred by the rights, the rights may have the effect of preserving incumbent management in office. There were no outstanding shares of Series A Junior Participating Preferred Stock as of December 31, 2008.
The Company has not paid cash dividends and does not anticipate that it will pay cash dividends on its common stock in the near term. The declaration and amount of future dividends, if any, will be determined by the Company’s Board of Directors and will be dependent upon covenant limitations in the Company’s credit facility and other debt
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
agreements, the Company’s financial condition and future earnings, the Company’s capital, legal and regulatory requirements, and other factors the Board deems relevant.
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Stock-Based Compensation
The Company has one equity incentive plan for employees and eligible non-employee directors that allows for the issuance of share-based compensation in the form of restricted stock, incentive stock options, nonqualified stock options, stock appreciation rights, performance awards, restricted stock units and deferred stock units. Members of the Company’s Board of Directors are eligible for deferred stock unit grants at the date of their election and annually. This plan has 5.2 million shares of the Company’s common stock available for grant, with 2.5 million shares available for grant as of December 31, 2008. Additionally, the Company has established an employee stock purchase plan that provides for the purchase of up to 2.0 million shares of the Company’s common stock, with 1.9 million shares available for grant as of December 31, 2008.
Share-based compensation expense of $7.3 million and $1.3 million was recorded in “Selling and administrative expenses” in the consolidated statements of operations at December 31, 2008 and 2007, respectively, and $0.6 million was recorded in “Operating costs and expenses” for the year ended December 31, 2008. Share-based compensation expense included $1.4 million and $0.3 million related to awards from restricted stock and stock options granted by Peabody to Patriot employees prior to spin-off for the years ended December 31, 2008 and 2007, respectively. As of December 31, 2008, the total unrecognized compensation cost related to nonvested awards granted after the spin-off was $7.5 million, net of taxes, which is expected to be recognized over seven years. As of December 31, 2008, the total unrecognized compensation cost related to nonvested awards granted by Peabody prior to the spin-off was $1.7 million, net of taxes, which is expected to be recognized through 2011.
Restricted Stock
The Company has restricted stock agreements in place for grants to employees and service providers of the Company and its subsidiaries and affiliates. Generally, these agreements provide that restricted stock issued will fully vest on the third anniversary of the date the restricted stock was granted to the employee or service provider. However, the restricted stock will fully vest sooner if a grantee terminates employment with or stops providing services to the Company because of death or disability, or if a change in control occurs (as such term is defined in the Patriot Coal Corporation 2007 Long-Term Equity Incentive Plan (the Equity Plan)).
A summary of restricted stock award activity is as follows:
Extended Long-Term Incentive Restricted Stock Units
The Company has extended long-term incentive restricted stock units agreements in place for grants to employees and service providers. These agreements grant restricted stock units that vest over time as well as restricted stock units that vest based upon the Company’s financial performance. In general, the restricted stock units that vest over time will be 50% vested on the fifth anniversary of the initial date of grant, 75% vested on the sixth such anniversary and 100% vested on the seventh such anniversary. However, the restricted stock units that vest over time will fully vest sooner if a grantee terminates employment with or stops providing services to the
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Company because of death or disability, or if a change in control occurs (as such term is defined in the Equity Plan). The performance-based restricted stock units vest according to a formula described in the form of Extended Long-Term Incentive Restricted Stock Units Agreement, which is primarily based on the Company’s financial performance as measured by EBITDA, return on equity and leverage ratios. The achievements of the performance-based unit calculations is determined on December 31 following the fifth, sixth and seventh anniversaries of the initial grant date. The Company estimated the number of performance-based units that are expected to vest and utilized this amount in the calculation of the stock-based compensation expense related to these awards. Any changes to this estimate will impact stock-based compensation expense in the period the estimate is changed.
In addition, the Company has deferred stock units agreements in place for grants to non-employee directors of Patriot. These agreements provide that the deferred stock units will fully vest on the first anniversary of the date of grant, but only if the non-employee director served as a director for the entire one-year period between the date of grant and the first anniversary of the grant. However, the deferred stock units will fully vest sooner if a non-employee director ceases to be a Patriot director due to death or disability, or if a change in control occurs (as such term is defined in the Equity Plan). Any unvested deferred stock units will be forfeited if a non-employee director terminates service with Patriot for any reason other than death or disability prior to the first anniversary of the grant date. After vesting, the deferred stock units will be settled by issuing shares of Patriot common stock equal to the number of deferred stock units, and the settlement will occur upon the earlier of (i) the non-employee director’s termination of service as a director or (ii) the third anniversary of the grant date or a different date chosen by the non-employee director, provided the date was chosen by the non-employee director prior to January 1 of the year in which the director received the grant.
A summary of restricted stock time units and deferred stock units award activity is as follows:
As of December 31, 2008, there were 37,340 deferred stock units vested that had an aggregate intrinsic value of $0.7 million.
A summary of restricted stock performance units award activity is as follows:
Extended Long-Term Incentive Non-Qualified Stock Option
The Company has extended long-term incentive non-qualified stock option agreements in place for grants to employees and service providers of Patriot. Generally, the agreements provide that any option awarded will become
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
exercisable in three installments. The option shall be 50% exercisable on the fifth anniversary of the date of grant, 75% exercisable on the sixth such anniversary and 100% exercisable on the seventh such anniversary. However, the option will become fully exercisable sooner if a grantee terminates employment with or stops providing services to Patriot because of death or disability, or if a change in control occurs (as such term is defined in the Equity Plan). No option can be exercised more than ten years after the date of grant, but the ability to exercise the option may terminate sooner upon the occurrence of certain events detailed in the form Extended Long-Term Incentive Non-Qualified Stock Option Agreement. Each award will be forfeited if the grantee terminates employment with or stops providing services to Patriot for any reason other than death or disability prior to the time the award becomes vested. As of December 31, 2008, there were no stock options vested or exercisable. There is no intrinsic value for the outstanding options as of December 31, 2008.
A summary of non-qualified stock option outstanding activity is as follows:
The Company recognizes share-based compensation expense in accordance with SFAS No. 123(R), “Share-Based Payment”. The Company used the Black-Scholes option pricing model to determine the fair value of stock options. Determining the fair value of share-based awards requires judgment, including estimating the expected term that stock options will be outstanding prior to exercise and the associated volatility. The Company utilized U.S. Treasury yields as of the grant date for its risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option. The Company utilized a seven-year peer historical lookback to develop its expected volatility. Expected option life assumptions were developed by taking the weighted average time to vest plus the weighted average holding period after vesting.
Employee Stock Purchase Plan
Based on the Company’s employee stock purchase plan, eligible full-time and part-time employees are able to contribute up to 15% of their base compensation into this plan, subject to a fair market value limit of $25,000 per person per year as defined by the Internal Revenue Service (IRS). Effective January 1, 2008, employees are able to purchase Company common stock at a 15% discount to the lower of the fair market value of the Company’s common stock on the initial or final trading dates of each six-month offering period. Offering periods begin on January 1 and July 1 of each year. The fair value of the six-month “look-back” option in the Company’s employee stock purchase plan is estimated by adding the fair value of 0.15 of one share of stock to the fair value of 0.85 of an option on one share of stock. The Company issued 56,654 shares of common stock and recognized $0.7 million expense in “Selling and administrative expenses” and $0.1 million in “Operating costs and expenses” for the year
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
ended December 31, 2008 related to its employee stock purchase plan. The Company issued no shares of common stock and recognized no expense for the year ended December 31, 2007 related to its employee stock purchase plan.
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Summary Quarterly Financial Information (Unaudited)
A summary of the unaudited quarterly results of operations for the years ended December 31, 2008 and 2007, is presented below. Patriot common stock is listed on the New York Stock Exchange under the symbol “PCX.”
PATRIOT COAL CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
DECEMBER 31, 2008
(1)
Reserves utilized, unless otherwise indicated.
(2)
Peabody restructured entities which resulted in the reclassification of advances and related reserves.
(3)
Balance transferred to Peabody as part of Patriot spin-off.
(4)
Balance reflects Magnum activity since acquisition on July 23, 2008.