UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-K

 

 

Commission File Number: 001-33466

 

 

 

 

PATRIOT COAL CORPORATION

(Exact name of registrant as specified in its charter)

 

 

(314) 275-3600
(Registrant’s telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)

 

Securities Registered Pursuant to Section 12(b) of the Act:

 

 

Securities Registered Pursuant to Section 12(g) of the Act:
None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act  Yes o     No þ

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act  Yes  o     No þ

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o     No þ

 

Aggregate market value of the voting stock held by non-affiliates (shareholders who are not directors or executive officers) of the Registrant, calculated using the closing price on June 30, 2008: Common Stock, par value $0.01 per share, $4.1 billion.

 

Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 20, 2009: Common Stock, par value $0.01 per share, 78,141,376 shares outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Company’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company’s Annual Meeting of Stockholders to be held on May 12, 2009 (the “Company’s 2009 Proxy Statement”) are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.

 

 

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

 

This report and other materials filed or to be filed by Patriot Coal Corporation include statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. You can identify these forward-looking statements by the use of forward-looking words such as “outlook,” “believes,” “expects,” “potential,” “continues,” “may,” “will,” “should,” “seeks,” “approximately,” “predicts,” “intends,” “plans,” “estimates,” “anticipates,” “foresees” or the negative version of those words or other comparable words and phrases. Any forward-looking statements contained in this report are based upon our historical performance and on current plans, estimates and expectations. The inclusion of this forward-looking information should not be regarded as a representation by us or any other person that the future plans, estimates or expectations contemplated by us will be achieved.

 

Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are subject to a wide range of uncertainties and business risks and actual risks may differ materially from those discussed in the statements. Among the factors that could cause actual results to differ materially are:

 

 

 

These factors should not be construed as exhaustive and should be read in conjunction with the other cautionary statements that are included in Item 1A. Risk Factors of this report. If one or more of these or other risks or uncertainties materialize, or if our underlying assumptions prove to be incorrect, actual results may vary materially from what we projected. Consequently, actual events and results may vary significantly from those included in or contemplated or implied by our forward-looking statements. We do not undertake any obligation to update the forward-looking statements, except as required by federal securities laws.

PART I

 

Unless the context indicates otherwise, all references in this report to Patriot, the Company, us, we, or our include Patriot Coal Corporation and its subsidiaries (Patriot).

 

 

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:

 

 

The following table provides the location and summary information of our operations as of December 31, 2008.

 

 

 

 

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.

 

 

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.

 

 

None.

 

 

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.

 

 

 

 

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:

 

 

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

 

 

 

 

 

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

 

2001 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.

 

2004 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.

 

 

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

 

 

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.

 

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. 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.