10-K 1 d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Year Ended December 31, 2010

or

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File Number: 001-33466

 

 

PATRIOT COAL CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware   20-5622045

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

12312 Olive Boulevard, Suite 400

St. Louis, Missouri

  63141
(Address of principal executive offices)   (Zip Code)

(314) 275-3600

(Registrant’s telephone number, including area code)

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

 

Title of Each Class

 

Name of Each Exchange on Which Registered

Common Stock, par value $0.01 per share   New York Stock Exchange
Preferred Share Purchase Rights   New York Stock Exchange

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

None

 

 

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

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  ¨    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  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

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.  ¨

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

 

Large accelerated filer   þ    Accelerated filer   ¨
Non-accelerated filer   ¨    Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)    Yes  ¨    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, 2010: Common Stock, par value $0.01 per share, $1.1 billion.

Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 18, 2011: Common Stock, par value $0.01 per share, 91,309,376 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, 2011 (the “Company’s 2010 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.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

PART I   

Item 1.

  

Business

     4   

Item 1A.

  

Risk Factors

     24   

Item 1B.

  

Unresolved Staff Comments

     36   

Item 2.

  

Properties

     37   

Item 3.

  

Legal Proceedings

     40   

Item 4.

  

Removed and Reserved

     45   

Item 4B.

  

Mine Safety Disclosure

     45   
PART II   

Item 5.

  

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

     45   

Item 6.

  

Selected Consolidated Financial Data

     47   

Item 7.

  

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

     50   

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

     66   

Item 8.

  

Financial Statements and Supplementary Data

     67   

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     67   

Item 9A.

  

Controls and Procedures

     67   

Item 9B.

  

Other Information

     71   
PART III   

Item 10.

  

Directors, Executive Officers and Corporate Governance

     71   

Item 11.

  

Executive Compensation

     71   

Item 12.

  

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

     71   

Item 13.

  

Certain Relationships and Related Transactions, and Director Independence

     71   

Item 14.

  

Principal Accounting Fees and Services

     71   
PART IV   

Item 15.

  

Exhibits and Financial Statement Schedules

     72   

 

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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:

 

   

price volatility and demand, particularly in higher margin products;

 

   

geologic, equipment and operational risks associated with mining;

 

   

changes in general economic conditions, including coal, power and steel market conditions;

 

   

changes in the interpretation, enforcement or application of existing and potential coal mining laws and regulations;

 

   

availability and costs of competing energy resources;

 

   

regulatory and court decisions including, but not limited to, those impacting permits issued pursuant to the Clean Water Act;

 

   

environmental laws and regulations and changes in the interpretation or enforcement thereof, including those affecting selenium-related matters, those affecting our operations and those affecting our customers’ coal usage;

 

   

our ability to identify and implement cost effective solutions for water treatment to eliminate selenium exceedances;

 

   

developments in greenhouse gas emission regulation and treatment, including any development of commercially successful carbon capture and storage techniques or market-based mechanisms, such as a cap-and-trade system, for regulating greenhouse gas emissions;

 

   

negotiation of labor contracts, labor availability and relations;

 

   

the outcome of pending or future litigation;

 

   

changes to the costs to provide healthcare to eligible active employees and certain retirees under postretirement benefit obligations;

 

   

increases to contribution requirements to multi-employer retiree healthcare and pension plans;

 

   

reductions of purchases or deferral of shipments by major customers;

 

   

availability and costs of credit, surety bonds and letters of credit;

 

   

customer performance and credit risks;

 

   

inflationary trends, including those impacting materials used in our business;

 

   

worldwide economic and political conditions;

 

   

downturns in consumer and company spending;

 

   

supplier and contract miner performance, and the availability and cost of key equipment and commodities;

 

   

availability and costs of transportation;

 

   

difficulty in implementing our business strategy;

 

   

our ability to replace proven and probable coal reserves;

 

   

the outcome of commercial negotiations involving sales contracts or other transactions;

 

   

our ability to respond to changing customer preferences;

 

   

sales of coal to Peabody Energy under existing agreements accounted for more than 10% of our revenues;

 

   

failure to comply with debt covenants;

 

   

the effects of mergers, acquisitions and divestitures, including our ability to successfully integrate mergers and acquisitions;

 

   

weather patterns and conditions affecting energy demand or disrupting supply;

 

   

competition in our industry;

 

   

interest rate fluctuation;

 

   

wars and acts of terrorism or sabotage;

 

   

impact of pandemic illness; and

 

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other factors, including those discussed in Legal Proceedings, set forth in Item 3 of this report.

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 (and expressly disclaim any such obligation) to update or revise 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 our subsidiaries (Patriot).

Item 1. Business.

Overview

We are a leading producer of thermal coal in the eastern United States (U.S.), with operations and coal reserves in the Appalachia and the Illinois Basin coal regions. We are also a leading U.S. producer of metallurgical quality coal. Our principal business is the mining and preparation of thermal coal, also known as steam coal, for sale primarily to electricity generators, and metallurgical coal, for sale to steel mills and independent coke producers.

Our operations consist of fourteen active mining complexes, which include company-operated mines, contractor-operated mines and coal preparation facilities. The Appalachia and Illinois Basin segments consist of our operations in West Virginia and Kentucky, respectively. We control approximately 1.9 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 ship coal to electricity generators, industrial users, steel mills and independent coke producers. In 2010, we sold 30.9 million tons of coal, of which 78% was sold to domestic electricity generators and industrial customers and 22% was sold to domestic and global steel and coke producers. Coal is shipped via various company-owned and third-party loading facilities, multiple rail and river transportation routes and ocean-going vessels.

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.” The spin-off from Peabody was accomplished through a dividend of all outstanding shares of Patriot.

On July 23, 2008, Patriot completed the acquisition of Magnum Coal Company (Magnum). Magnum was one of the largest coal producers in Appalachia, operating eight mining complexes with production from surface and underground mines in Appalachia and controlling more than 600 million tons of proven and probable coal reserves. Magnum results are included as of the date of the acquisition.

Mining Operations

Our mining operations and coal reserves are as follows:

 

   

Appalachia. In southern West Virginia, we have ten mining complexes located in Boone, Clay, Lincoln, Logan and Kanawha counties, and in northern West Virginia, we have one complex located in Monongalia County. In Appalachia, we sold 24.3 million tons of coal in the year ended December 31, 2010. As of December 31, 2010, we controlled 1.2 billion tons of proven and probable coal reserves in Appalachia, of which 457 million tons were assigned to current operations.

 

   

Illinois Basin. In the Illinois Basin, we have three complexes located in Union and Henderson counties in western Kentucky. In the Illinois Basin, we sold 6.6 million tons of coal in the year ended December 31, 2010. As of December 31, 2010, we controlled 668 million tons of proven and probable coal reserves in the Illinois Basin, of which 178 million tons were assigned to current operations.

 

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The following table provides the location and summary information of our operations for the year ended December 31, 2010.

 

Location

  

Complex

  

Mine(s)

  

Mining
Method(1)

  

Met/Steam

   2010
Tons
Sold(2)
 

Appalachia

   Big Mountain    Big Mountain No. 16, Contractor    CM    Steam      1,946   
   Blue Creek    Blue Creek No. 1    CM    Steam      746   
   Campbell’s Creek    Campbell’s Creek No. 7, Contractor    CM    Steam      723   
   Corridor G    Job 21, Hill Fork    TS, DL    Steam      3,982   
   Kanawha Eagle    Contractor    CM    Met/Steam      1,494   
   Logan County    Guyan    TS    Steam      2,747   
   Paint Creek    Samples, Winchester    TS, HW, CM    Met/Steam      1,030   
   Panther    Panther    LW, CM    Met/Steam      1,949   
   Rocklick    Harris No. 1, Black Oak, Contractor    CM    Met      691   
   Wells    Rivers Edge, Contractor    CM    Met      3,008   
   Federal    Federal No. 2    LW, CM    Steam      3,797   
   Purchased coal    N/A    N/A    N/A      2,163   
                    
            Subtotal      24,276   
                    

Illinois Basin

              
   Bluegrass    Patriot, Freedom    TS, CM    Steam      2,328   
   Dodge Hill    Dodge Hill No. 1    CM    Steam      882   
   Highland    Highland No. 9    CM    Steam      3,378   
                    
            Subtotal      6,588   
                    
           

Total

     30,864   
                    

 

(1)

LW = Longwall, CM = Continuous Miner, TS = Truck-and-Shovel, DL = Dragline, HW = Highwall.

(2)

Tons sold, presented in thousands, for each complex approximated actual annual production in 2010, subject to stockpile variations.

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. Continuous miner mining is also referred to as “room-and-pillar” mining. 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/loader mining. Truck-and-shovel/loader 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 to a 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 maximum depth of up to 1,600 feet, but generally average 1,000 to 1,200 feet.

 

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Appalachian Mining Operations

Our Appalachian Mining Operations include eleven active mining complexes in West Virginia.

LOGO

Appalachia

Big Mountain

The Big Mountain mining complex is sourced by one company-operated underground mine, Big Mountain No. 16, and two 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 from the preparation plant to customers via CSX rail or trucked to a terminal on the Kanawha River and placed on barges. Coal is produced from the Coalburg and Dorothy seams. Most of the employees at the company-operated mine are represented by the United Mine Workers of America (UMWA).

Blue Creek

The Blue Creek mining complex is located in southern West Virginia and consists of a company-operated underground mine, Blue Creek No. 1. The Blue Creek mining complex became operational in December 2009. Coal at the Blue Creek mining complex is produced from the Stockton seam. The complex utilizes continuous mining methods and a third-party-owned on-site preparation facility. Coal produced at the Blue Creek complex is sold on the thermal market and is loaded onto trucks for transportation to a barge loading facility on the Kanawha River. The employees at the company-operated mine are not represented by a union.

Campbell’s Creek

The Campbell’s Creek mining complex consists of two underground mines located in southern West Virginia. The company-operated Campbell’s Creek No. 7 mine operates in the Winifrede seam. The contractor-operated mine operates in the Stockton seam. All mines in the Campbell’s Creek mining complex utilize the 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 and stoker coal markets. Stoker coal is a type of thermal coal that is processed to a specific size to remove the smaller particles so that it can be used in boilers at industrial plants. The employees at the company-operated mine are not represented by a union.

Corridor G

The Corridor G mining complex consists of two company-operated surface mines, Job 21 and Hill Fork, located in southern West Virginia. Coal is sourced from the Kittanning, Stockton and Coalburg seams. 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 or trucked to a terminal on the Kanawha River and placed on barges. 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.

Kanawha Eagle

The Kanawha Eagle complex, which is contractor-operated, is located in southern West Virginia and is sourced by three underground mines. All three mines utilize continuous mining methods. Processed coal is sold on both metallurgical and thermal markets and is transported via CSX rail directly to the customer or by private line railroad to the Kanawha River and placed on barges. Coal is produced from the Coalburg and Eagle seams.

 

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Logan County

The Logan County mining complex consists of one company-operated surface mine, Guyan, 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 principally transported from the loadout facility to customers by CSX rail. Coal at Logan County is sourced from the Freeport, Kittanning, Stockton and Coalburg seams. Certain employees at the Logan County complex are represented by the UMWA.

Paint Creek

The Paint Creek mining complex consists of one surface mine and one underground mine located in southern West Virginia. Both mines are company-operated. The surface mine, Samples, utilizes truck-and-shovel/loader and highwall mining methods, while the underground mine, Winchester, utilizes the continuous mining method. The Winchester mine operates in the Hernshaw seam. Coal from Samples is sourced from the Freeport, Kittanning, Stockton and Coalburg seams. We announced the idling of our Samples mine in August 2009. After processing, coal is transported from the on-site preparation plant and loadout facility to customers by CSX rail. 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 market. The employees at the Paint Creek complex are not represented by a union.

Panther

The Panther mining complex consists of one underground mine, Panther, located in southern West Virginia. Coal is produced utilizing the longwall mining and continuous mining methods. All coal is processed at an on-site preparation plant and then transported via truck to barges on the Kanawha River or via CSX rail. Coal produced at the Panther complex can be sold into thermal and metallurgical markets, but was sold primarily into the metallurgical market during 2010. Coal at the Panther mining complex is produced from the Eagle seam. The employees at the Panther complex are not represented by a union.

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 one contractor-operated underground mine. Coal at the Rocklick mining complex is produced utilizing continuous mining methods. In 2010, all coal from Harris No. 1, Black Oak and the contractor mine was sold on the metallurgical market. In June 2010, we closed our Harris No. 1 mine due to a roof fall and adverse geologic conditions. The Harris No. 1 mine was nearing the end of its projected mining life and was scheduled for closure in 2011. Although the Black Oak mine was suspended in January 2009, production resumed in September 2010 as metallurgical coal demand increased. Rocklick has the capability to transport coal on both the CSX and the Norfolk Southern railroads. Metallurgical coal at the Black Oak mine is produced from the No. 2 Gas seam. Our contract mine produced coal from the Eagle seam. Most of the employees at the company-operated mines 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. Coal currently produced at the Wells mining complex is sold on the metallurgical market and is transported to customers via CSX rail. Thermal coal can also be processed and sold at this operation. Rivers Edge mine produces coal from the Powellton seam. Contract mines produce coal from the Eagle, No. 2 Gas, Powellton and Lower Chilton seams. Most of the employees at the company-operated facilities of the Wells mining complex are represented by the UMWA.

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 produced at Federal is sold on the high-Btu thermal market and is transported to customers via the CSX and Norfolk Southern railroads or via barges on the Ohio River. Coal is produced from the Pittsburgh seam. Most of the employees at the Federal mining complex are represented by the UMWA.

 

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Illinois Basin Mining Operations

Our Illinois Basin Mining Operations include three mining complexes in western Kentucky.

LOGO

Illinois Basin

Bluegrass

The Bluegrass mining complex is located in western Kentucky and is sourced by two company-operated mines, Freedom, an underground mine, and Patriot, a surface mine. Coal at Freedom is produced utilizing continuous mining methods, while coal at Patriot is produced utilizing the truck-and-shovel/loader mining method. All coal is sold on the thermal market and is transported via truck or via barge loaded on the Green River. Coal is produced from the Kentucky No. 9 seam. 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, Dodge Hill No. 1, utilizing continuous mining methods. All coal is sold on the thermal market and transported via barge on the Ohio River. Coal at the Dodge Hill mining complex is produced from the Kentucky No. 6 seam. 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 barges loaded on the Ohio River. Coal is produced from the Kentucky No. 9 seam. Most of the employees at the Highland complex are represented by the UMWA.

 

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Customers and Backlog

In 2010, our coal was sold to over 70 electricity generating and industrial plants in 10 countries, including the U.S., which is where we have our primary customer base.

As of December 31, 2010, we had a sales backlog of 44.0 million tons of coal, including backlog subject to price reopener and/or extension provisions. Our coal supply agreements have remaining terms up to 7 years and an average volume-weighted remaining term of approximately 2.0 years.

 

     Commitments as of December 31, 2010  
     2011      2012      2013      2014 and
Later
     Total  

Tons (in millions)

     24.5         10.0         2.9         6.6         44.0   

The 2011 commitments represent approximately 82% of our currently estimated production for 2011.

In 2010, approximately 77% of our coal sales were under long-term (greater than one year) agreements. We expect to continue selling a significant portion of our coal under long-term coal supply agreements. Our approach is to selectively renew or enter into new coal supply agreements 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, 2010, approximately 22% and 9% of our current projected 2011 and 2012 total production, respectively, was committed under pre-existing customer relationships with Peabody, all of which are thermal coal contracts.

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 agreements. The terms and conditions of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms and conditions 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, termination and assignment provisions.

Each coal supply agreement sets a base price. Some agreements provide for a predetermined adjustment to base price at times specified in the agreement. Base prices may be adjusted quarterly, annually or at other periodic intervals for changes in production costs and/or changes due to inflation or deflation. 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 coal supply agreements contain provisions to adjust the base price due to new laws or changes in the language, interpretation or application of existing laws that increase our cost of performance under such agreements. Buyers often negotiate similar clauses covering changes in environmental laws. In these instances, we often negotiate the right to supply coal that complies with a new environmental requirement to avoid contract termination.

Price reopener provisions are present in some of our long-term coal supply agreements. These provisions may allow either party to commence a renegotiation of the contract price at various intervals. In most of the agreements with price reopener provisions, if the parties do not agree on a new price, the buyer or seller has an option to terminate the contract. Under some agreements with price reopener provisions, we have the right to match the pricing 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 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, chlorine content, grindability, ash fusion temperature and metallurgical characteristics. 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 sampling, analysis and weighing. In most of our agreements, we have a right of substitution, allowing us to provide coal from different mines, including third-parties, as long as the replacement coal meets the contracted quality specifications and is sold at the same delivered cost.

 

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In most cases, the provisions of coal supply agreements 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. Most force majeure provisions stipulate that this tonnage can be made up by either mutual agreement or at the option of the nonclaiming party.

Coal supply agreements typically contain termination clauses if either party fails to comply with the terms and conditions of the agreement, although most termination provisions provide the opportunity to cure defaults.

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, transportation, distribution, market research, contract management, and credit/risk management activities.

Transportation

Coal consumed domestically is typically sold at the mine and transportation costs are borne by the purchaser. At most Appalachian mine complexes, we load coal from the preparation plant directly onto railcars. At certain locations, we utilize truck, conveyor belt and rail to transport coal from our mines to docks for transportation to customers via barges. Export coal is usually sold at the loading port, with purchasers paying ocean freight. For export coal, we 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 30.9 million tons sold in 2010, approximately 46% was shipped by rail, 43% by barge, 10% by ocean-going vessel and 1% by truck. Our transportation staff manages the loading of coal via these transportation modes.

Suppliers and Contractors

The main types of goods we purchase are mining equipment and replacement parts, steel-related (including roof control) products, belting products, lubricants, fuel, explosives 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. Purchases of certain underground mining equipment are concentrated with one principle supplier; however, supplier competition continues to develop. The supplier base providing mining materials has been relatively consistent in recent years.

We contract with third-party producers to mine our owned or leased coal reserves on a rate per ton or cost plus basis. Third-party contractors accounted for approximately 19% of our total sales volume for the year ended December 31, 2010.

Competition

The U.S. coal industry is highly competitive, both regionally and nationally. Coal production in Appalachia and the Illinois Basin totaled approximately 450 million tons in 2010, with the largest five producers (Alliance, Alpha Natural Resources, Inc., CONSOL Energy, Inc., Massey Energy Company, and Patriot) accounting for 44% of production. In addition to competition within the eastern U.S. region, coal is transported into the region from the western U.S. 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 U.S. and elsewhere around the world; 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. Coal consumption patterns are affected primarily by the demand for electricity and steel, 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, 2010, we had approximately 3,700 employees. Approximately 51% of our employees were represented by an organized labor union and these operations generated approximately 50% of our 2010 sales volume. Union labor is represented by the UMWA under labor agreements which expire December 31, 2011. Our represented employees work at various sites in Appalachia and at the Highland complex in the Illinois Basin.

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.

 

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Certain Liabilities

We have significant long-term liabilities for reclamation (also called asset retirement obligations) and remediation, retiree healthcare and work-related injuries and illnesses. In addition, labor contracts with the UMWA and certain arrangements with non-union employees include long-term benefits, notably healthcare coverage for retired employees and future retirees and their dependents.

Reclamation and Remediation Obligations

Reclamation obligations primarily represent the present value of future anticipated costs to restore surface land to levels equal to or greater than pre-mining conditions, as required by the Surface Mining Control and Reclamation Act (SMCRA). Remediation obligations primarily represent the present value of future anticipated costs for water treatment of selenium discharges in excess of allowable limits, as required by current court orders, consent decrees and mining permits.

Reclamation and remediation expense (which includes liability accretion and asset amortization) for the years ended December 31, 2010, 2009 and 2008 was $63.0 million, $35.1 million, and $19.3 million, respectively. The 2010 expense amount included a $20.7 million charge related to a court ruling as further described below. As of December 31, 2010, our reclamation and remediation obligations of $369.5 million included $63.5 million related to locations that are closed or inactive.

Our remediation obligation for selenium treatment at the Magnum acquisition date was estimated and recorded at June 30, 2009, when the purchase accounting valuation of all assets acquired and liabilities assumed was finalized. Selenium is a naturally occurring element that is encountered in earthmoving operations. The extent of selenium occurrence varies depending upon site specific geologic conditions. Selenium is encountered globally in coal mining, phosphate mining and agricultural operations. In coal mining applications, selenium can be discharged to surface water when mine tailings are exposed to rain and other natural elements. Selenium effluent limits are included in permits issued to us and other coal mining companies.

Despite continued efforts, we have been unable to identify a treatment system that can remove selenium sustainably, consistently and uniformly under all variable conditions experienced at our mining operations. The lack of a known, proven technology to meet selenium effluent limits is an industry-wide issue.

We are currently involved in various legal proceedings related to compliance with the effluent selenium limits in our mining permits. As a result of these legal proceedings, we are subject to various consent decrees and court orders that generally require us, among other things, to meet certain compliance deadlines related to selenium discharge levels and to research, develop and implement pilot projects of potential technologies for the treatment of selenium exceedances at permitted outfalls. In the past, we have paid fines and penalties with respect to violations of selenium effluent limitations.

As a result of a lawsuit filed by the West Virginia Department of Environmental Protection (WVDEP) in state court in West Virginia, Hobet Mining, LLC (Hobet) entered into a settlement agreement with the WVDEP that required Hobet to pay fines and penalties with respect to past violations of selenium limitations under certain of its National Pollutant Discharge Elimination System (NPDES) permits, to meet certain compliance deadlines related to selenium discharge levels and to research, develop and implement pilot projects of potential technologies for the treatment of selenium exceedances at permitted outfalls.

The Ohio Valley Environmental Coalition, Inc. (OVEC) and another environmental group sued Apogee Coal Company, LLC (Apogee) in 2007 and Hobet in 2008 in the U.S. District Court for the Southern District of West Virginia (U.S. District Court) alleging that Apogee and Hobet had violated water discharge limits for selenium set forth in certain of their NPDES permits. On March 19, 2009, the U.S. District Court approved two separate consent decrees, one between Apogee and the plaintiffs and the other between Hobet and the plaintiffs. The consent decrees extended the deadline to comply with water discharge limits for selenium with respect to the permits covered by both lawsuits to April 5, 2010.

On September 1, 2010, the U.S. District Court found Apogee in contempt for failing to comply with the March 19, 2009 consent decree. The court found that Apogee had failed to exercise reasonable diligence in evaluating and identifying viable treatment technologies, which diminished our ability to achieve compliance. Apogee was ordered to install a Fluidized Bed Reactor (FBR) water treatment facility for three mining outfalls and to come into compliance with applicable selenium discharge limits at these outfalls by March 1, 2013. Additionally, Hobet was ordered by the court to come into compliance with applicable selenium discharge limits under the Hobet Surface Mine No. 22 permit by May 1, 2013.

Pursuant to the September 1, 2010 ruling, we will record the costs to install the FBR water treatment facility for the three Apogee outfalls as capital expenditures when incurred. The capital expenditure for the facility is estimated to be approximately $50 million. In addition, the estimated future on-going operating cash flows required to meet our legal obligation for remediation at the three Apogee outfalls have changed from our original estimates based on the September 1, 2010 ruling. As such, we increased the portion of the liability related to Apogee by updating the fair value of the on-going costs related to these three outfalls and recorded the $20.7 million difference between this updated value and our previously recorded liability directly to income, through reclamation and remediation obligation expense in the third quarter of 2010.

 

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We have established a liability for the treatment of outfalls with known selenium exceedances. The liability reflected the estimated total costs of the planned Zero Valent Iron (ZVI) water treatment systems we have been installing and maintaining in consideration of the requirements of our mining permits, court orders and consent decrees. This estimate was prepared considering the dynamics of legislation, capabilities of available technology and our planned remediation strategy. We utilized the cost of the most successful treatment methodology at that time based on our testing results for our best estimate based on uncertainties regarding technology, compliance parameters and deadline extensions.

Our liability to treat selenium discharges at outfalls not addressed in the September 1, 2010 ruling is based on the use of ZVI technology. We are currently continuing to install ZVI systems according to our original remediation strategy, while also performing a further review of other potential water treatment technology or other alternatives. Our remediation strategy reflects implementing scalable ZVI systems at each outfall. The ZVI system is scalable due to its modular design that can be reconfigured as further knowledge and certainty is gained. Initial ZVI testing has identified potential system shortfalls, and to date ZVI has not been demonstrated to perform consistently and sustainably in achieving effluent selenium limitations or in treating the expected flows at these outfalls. However, based on the modular design and resulting flexibility of the scalable ZVI system, we plan to continue to pursue implementation of the ZVI systems and to determine whether modifications to the system could result in its ability to treat selenium successfully.

At this time, there is no plan to install FBR or any technology other than ZVI at the other outfalls not addressed in the September 1, 2010 ruling as neither FBR nor other technologies have been proven effective on a full-scale basis. Because the levels of water flow and selenium discharges at each outfall differ, the solution for each outfall may be very different and a variety of solutions may ultimately be required. We are continuing to research various treatment alternatives in addition to ZVI for the other outfalls. If ZVI is not ultimately successful in treating the effluent selenium exceedances at these additional outfalls, we may be required to install alternative treatment technologies. The cost of other technologies could be materially higher than the costs reflected in our liability. Furthermore, costs associated with potential modifications to ZVI or the scale of the planned ZVI systems to be installed could also cause the costs to be materially higher than the costs reflected in our liability. While we are actively continuing to explore treatment options, there can be no assurances as to when a definitive solution will be identified and implemented or whether we can meet the compliance deadlines.

Retiree Healthcare and Pension

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 $1.3 billion and $1.2 billion as of December 31, 2010 and 2009, respectively, of which $65.6 million and $67.1 million was a current liability, respectively. Expense for the years ended December 31, 2010, 2009 and 2008 was $117.2 million, $92.5 million and $66.0 million, respectively. In 2010 and 2009, our results included a full year of retiree healthcare expense related to the Magnum operations as compared to only five months in 2008.

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. At December 31, 2010 the present value of the liability assumed by Peabody at spin-off was $680.9 million. We continue to administer these benefits. Certain Patriot subsidiaries remain jointly and severally liable for the Coal Act obligations and remain secondarily liable for the 2007 NBCWA obligations and the salaried employee obligations.

In March 2010, the Patient Protection and Affordable Care Act, and a companion bill, the Health Care and Education Reconciliation Act of 2010, (collectively, the 2010 healthcare legislation) were enacted, potentially impacting our costs to provide healthcare benefits to our eligible active and certain retired employees and workers’ compensation benefits related to occupational disease resulting from coal workers’ pneumoconiosis (black lung disease). The 2010 healthcare legislation has both short-term and long-term implications on healthcare benefit plan standards. Implementation of the 2010 healthcare legislation will occur in phases, with plan standard changes taking effect beginning in 2010, but to a greater extent with the 2011 benefit plan year and extending through 2018. Plan standard changes that affect us in the short term include raising the maximum age for covered dependents to continue to receive benefits, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual, among other standard requirements. Plan standard changes that could affect us in the long term include a tax on “high cost” plans (excise tax) and the elimination of annual dollar limits per covered individual, among other standard requirements.

The constitutionality of certain provisions of the 2010 healthcare legislation has been challenged in litigation filed by 26 state attorney generals and others. Additionally, there is uncertainty surrounding the interpretation or refinement of certain long-term plan standards.

Beginning in 2018, the 2010 healthcare legislation will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of this excise tax. Until these regulations or interpretations are published, it is impractical to reasonably estimate the ultimate impact of the excise tax on our future healthcare costs or postretirement benefit obligation. We have incorporated changes to our actuarial assumptions to determine our postretirement benefit obligations utilizing basic assumptions

 

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related to pending interpretations. Based on preliminary estimates and basic assumptions around the pending interpretations of these regulations, the present value of the excise tax does not have a material impact on our postretirement benefit obligation. With the exception of the excise tax, we do not believe any other plan standard changes will be significant to our future healthcare costs for eligible active employees and our postretirement benefit obligation for certain retired employees. However, we will need to continue to evaluate the impact of the 2010 healthcare legislation in future periods as additional information and guidance becomes available.

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. Under the 2006 Act, the orphan benefits paid to the Combined Fund and the 1992 Benefit Plan 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 for 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 revises the AML fees paid by us on coal production, effective in October 2007, with the imposition of such fees currently scheduled to expire in its entirety on September 30, 2021. See additional details about the AML trust fund in Mine Closure Costs below.

The 2006 Act specifically amended the federal laws establishing the Combined Fund, the 1992 Benefit Plan and the 1993 Benefit Plan. The 2006 Act provided new and additional funding to all three programs, subject to the limitations described below. The 2006 Act guaranteed 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 provided federal funding for the annual orphan health costs under the 1992 Benefit Plan on a phased-in basis, reaching 100% in 2011. The coal producers that signed the 1988 labor agreement, including some of our subsidiaries, remain responsible for the costs of their beneficiaries of the 1992 Benefit Plan. The 2006 Act also included the 1993 Benefit Plan as one of the statutory funds and authorized the trustees of the 1993 Benefit Plan to determine the contribution rates through 2010 for pre-2007 beneficiaries. The funding and claims during a guarantee period from January 1, 2007 through December 31, 2010 are currently under review by the trustees. Our subsidiaries that have agreed to the 2007 NBCWA will pay $0.50 per hour worked to the 1993 Benefit Plan in 2011. Under the 2006 Act, these new and additional federal expenditures to the Combined Fund, 1992 Benefit Plan, 1993 Benefit Plan and certain AML 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 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.

The actuarially-determined liability for these benefit plans was $44.9 million as of December 31, 2010, $5.9 million of which was a current liability. The actuarially-determined liability for these benefit plans was $48.5 million as of December 31, 2009, $6.3 million of which was a current liability. Expenses for the years ended December 31, 2010, 2009 and 2008 were $3.2 million, $3.2 million and $2.6 million, respectively. Cash payments to these funds were $6.0 million, $6.3 million and $6.1 million for 2010, 2009 and 2008, 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 $10.0 million, $11.2 million and $11.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.

 

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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 annually, beginning in 2007, 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. Expense related to these funds was $21.0 million, $18.3 million and $13.5 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Workers’ Compensation Obligations

These liabilities represent the estimates for compensable, work-related injuries (traumatic claims) and occupational disease, principally black lung disease and are based primarily on actuarial valuations. The Federal Black Lung Benefits Act requires employers to pay black lung awards to former employees who filed successful claims after June 1973. These liabilities were $246.3 million and $220.3 million as of December 31, 2010 and 2009, respectively, of which $25.5 million and $26.6 million was a current liability, respectively. Expense for the years ended December 31, 2010, 2009 and 2008 was $38.2 million, $31.3 million and $25.1 million, respectively.

The 2010 healthcare legislation also amended previous legislation related to black lung disease, providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims. We were able to evaluate the impact of these changes to our current population of beneficiaries and claimants, resulting in an estimated $11.5 million increase to our obligation. As of March 31, 2010, we recorded this estimate as an increase to our workers’ compensation liability and a decrease to the actuarial gain included in “Accumulated other comprehensive loss” on our balance sheet. We adjusted the amortization of the actuarial gain beginning in the second quarter of 2010. As of December 31, 2010, we were not able to estimate the impact of the 2010 healthcare legislation on our obligations related to future black lung claims due to uncertainty around the number of claims that will be filed and how impactful the new award criteria will be to these claim populations.

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.

Black Lung

In the U.S., 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.

 

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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 incentive for all Patriot personnel is tied to our safety record.

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 (the 1977 Act) significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. In 1978, the Mine Safety and Health Administration (MSHA) was created to carry out the mandates of the 1977 Act.

Congress enacted the Mine Improvement and New Emergency Response Act of 2006 (MINER Act) as a result of an increase in fatal accidents. 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 communication 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. Congressman George Miller, Chairman, House Committee on Labor & Education proposed a bill titled the Mine Safety and Health Act of 2010 which addressed additional considerations that were not included in the MINER Act. Although the bill did not reach the House of Representatives floor for a vote, some of the contents, as edited, have resurfaced in the Robert C. Byrd Mine Safety Bill, which was introduced in January 2011.

MSHA mandated additional requirements for two-way communication and electronic tracking for use in mine emergencies in January 2009. In September 2010, MSHA issued an emergency temporary standard requiring mine operators to increase the incombustible content of combined coal dust, rock dust, and other dust to at least 80 percent in underground areas of bituminous coal mines. This requirement is further increased for mines containing methane gas. Finally, MSHA has proposed several additional regulations, including a proposal to require the use of continuous personal dust monitors and expanded requirements for medical surveillance. Compliance with these regulations has and will continue to result in additional expense.

In the aftermath of the April 5, 2010 accident at a competitor’s underground mine in Central Appalachia, MSHA continues to make changes in seal design and ventilation system approvals. Through Emergency Temporary Standards, Program Policy Bulletins and discretionary approval criteria issued by the District Manager, the guidelines governing seals and ventilation evaluation points have reduced the action levels of the various gases while increasing the frequency of withdrawal from the mine. Once withdrawal levels are reached, the resumption of operation is solely at MSHA’s discretion and the criteria for plan approval is based on the District Manager’s requirements. New regulations and changes in the interpretation, enforcement or application of existing laws and regulations have resulted in higher scrutiny during inspections and lower production.

The states in which we operate also have programs for mine safety and health regulation and enforcement. As a result of industry-wide fatal accidents in recent years, primarily at underground mines, several states including West Virginia and Kentucky have adopted new safety and training regulations. In addition, MSHA has issued numerous new policies and regulations addressing, but not limited to, the following: emergency notification and response plans, increased fines for violations and additional training and mine rescue coverage requirements. 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. 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.

Mining Control and Reclamation Regulations

SMCRA is administered by the Office of Surface Mining Reclamation and Enforcement (OSM) and 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.

 

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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. Department of the Interior is actively considering establishing, in the context of new permit applications under SMCRA, new standards for restoring mountaintops affected by surface mining, removing the rights of states to revise or grant exemptions to federal restoration standards and developing a federal definition of “material damage” to be used in the context of existing watershed area protections. It is also considering requiring surface mining companies to collect more information on the environmental health of watersheds near their operations, to monitor conditions before and after mining, and to change or close operations if unpermitted damage to the watersheds occurs.

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 up 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 requires 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 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 (ACOE) regulates activities affecting navigable waters and the U.S. Bureau of Alcohol, Tobacco and Firearms regulates the use of explosive blasting.

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. As of December 31, 2010, we had outstanding surety bonds and total letters of credit of $513.4 million including: $282.6 million for post-mining reclamation; $151.5 million related to workers’ compensation obligations; $56.7 million for retiree health obligations; and $22.6 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 United States. The proceeds are used to rehabilitate land mined and left unreclaimed prior to August 3, 1977 and to pay healthcare benefit costs of orphan beneficiaries of the Combined Fund. Under current law, 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 and 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.

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 and 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 opposition could also reduce the demand for coal.

 

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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.

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. As a result of recent court decisions and regulatory actions, permitting requirements have increased and could continue to increase the cost and time we expend on compliance with water pollution regulations.

For example, in January 2011, the EPA took the unprecedented step of rescinding a federal Clean Water Act permit held by another coal mining company for a surface mine in Appalachia. In explaining its position, the EPA cited significant and irreversible damage to wildlife and fishery resources and severe degradation of water quality caused by mining pollution. This was the first time that the EPA has canceled a federal water permit after it was issued. While our operations are not directly impacted, this could be an indication that other surface mining water permits could be subject to more substantial review in the future.

These and other regulatory requirements, which have the potential to change due to legal challenges, legislative actions and other developments, increase the cost of, or could restrict or even prohibit, certain current or future mining operations. Our operations may not be able to remain in full compliance with all Clean 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. See Certain Liabilities – Reclamation and Remediation Obligations above for discussion of selenium-related matters.

Clean Water Act requirements that may affect our operations include the following:

Section 404

Section 404 of the Clean Water Act requires mining companies to obtain 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 surface mining operations, frequently require Section 404 permits. The issuance of Section 404 permits for surface mining operations has been the subject of many court cases and increased regulatory oversight which may result in permitting delays, increased permitting and operating costs and possible suspension of current operations or prevention of opening new mines.

For example, on June 17, 2010, the ACOE announced that it would suspend the use of the nationwide (or “general”) permit for the construction of valley fills and refuse impoundments under Section 404 of the Clean Water Act, commonly described as Nationwide Permit 21 (NWP 21), by surface coal operations in West Virginia and other Appalachian states. The regional suspension will remain in effect until the NWP 21 permit is modified or until the permit expires in 2012. In the absence of NWP 21, individual permits are required for surface coal mining projects. We have converted any pending permit applications that were submitted under NWP 21 to individual permit applications and believe that the suspension of the use of NWP 21 permits will have a minimal effect on our future production. However, individual permits require a public notice and review period, take longer to process and are more costly to obtain.

In September 2009, the EPA announced that proposed mining related to certain pending Section 404 permits in Appalachia would require additional review under the Clean Water Act due to the potential water quality impacts. At that time, seventy-nine permit applications were identified for further, detailed reviews, including six of our permit applications. In January 2010, the permit for our Hobet 45 mine was issued after it had been selected for detailed review. More than half of the permit applications selected for further review have been withdrawn, including two of our permit applications. The EPA and the ACOE continue to perform reviews of pending permit applications to ensure compliance with the Clean Water Act.

In November 2009, the U.S. Department of the Interior (DOI) issued an advance notice of proposed rule making regarding the use of valley fills within a set distance of a stream. The notice set forth a number of potential options the DOI is considering in order to meet the goals of a Memorandum of Understanding (MOU) among the DOI, the EPA and the ACOE. The DOI is currently developing an environmental impact statement for use in drafting the anticipated stream protection rule. If additional restrictions are ultimately imposed, certain mining activities could become prohibited.

 

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The DOI is also actively considering establishing, in the context of new permit applications under SMCRA, new standards for restoring mountaintops affected by surface mining, removing the rights of states to revise or grant exemptions to federal restoration standards and developing a federal definition of “material damage” to be used in the context of existing watershed area protections. It is also considering requiring surface mining companies to collect more information on the environmental health of watersheds near their operations, to monitor conditions before and after mining and to change or close operations if unpermitted damage to the watersheds occurs.

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.

National Pollutant Discharge Elimination System

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. Total Maximum Daily Load (TMDL) regulations establish a process by which states designate stream segments not meeting present water quality standards as impaired. Industrial dischargers, including coal mining operations, may be required to meet new TMDL effluent standards for these stream segments.

States must also develop anti-degradation policies to help protect high quality waters and existing quality of other waters. In general, the issuance and renewal of permits to discharge to non-impaired waters are subject to anti-degradation review and other limitations that could cause increases in the costs, time and difficulty associated with obtaining new and complying with existing NPDES permits and could adversely affect our coal production.

EPA Water Quality Standards

On April 1, 2010, the EPA issued comprehensive guidance to provide clarification as to the water quality standards that should apply when reviewing Clean Water Act permit applications for Appalachian surface coal mining operations, and of the EPA’s roles and expectations in coordinating with its federal and state partners, to assure more consistent, effective and timely compliance by Appalachian surface coal mining operations with the provisions of the Clean Water Act, the National Environmental Policy Act and the Environmental Justice Executive Order. Although this guidance does not apply retroactively to existing Clean Water Act permits, it applies to new Section 404 permits, new NPDES permits, modifications to existing NPDES permits and renewals of existing NPDES permits. This guidance establishes threshold conductivity levels to be used as a basis for evaluating compliance with narrative water quality standards. Conductivity is a measure that reflects levels of salt, sulfides and other chemical constituents present in water. In order to obtain federal Clean Water Act permits for surface coal mining in Appalachia, as defined in the guidance, applicants must perform an evaluation to determine if a reasonable potential exists that the proposed mining would cause a violation of water quality standards, including narrative standards. The EPA Administrator has stated that it may be difficult for most surface mining operations to meet these water quality standards. Additionally, the guidance contains requirements for avoiding and minimizing environmental impacts, mitigation of mining impacts, consideration of the full range of potential impacts on the environment, human health and communities, including low-income or minority populations, and provision of meaningful opportunities for public participation in the permit process. To obtain necessary permits, we and other mining companies are required to meet these requirements. We have begun to incorporate these new requirements into some of our current permit applications; however, there can be no guarantee that we will be able to meet these or any other new standards with respect to our permit applications.

In October 2010, the WVDEP filed a lawsuit against the EPA challenging the water quality standards put forth in the comprehensive guidance issued on April 1, 2010. The State of Kentucky and the Kentucky Coal Association have filed a similar lawsuit challenging the EPA’s authority to block state issued permits based on the water quality standards.

It is unknown what other future changes will be implemented to the permitting review and issuance process or to other aspects of mining operations, but the increased regulatory focus, recent attention in Congress, the announced regulatory changes and reviews and any additional future permitting changes could materially and adversely affect all coal mining companies operating in Appalachia, including us. In particular, we could be unable to obtain new permits or maintain existing permits, which could result in the suspension of current operations or prevent the opening of new mines, we could be required to change operations in a manner that could be costly and we could incur fines, penalties and other costs, any of which could materially adversely affect our business.

Clean Air Regulations

        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 our customers that operate coal-fueled electricity generating plants or other regulated combustion sources. Additionally, the EPA has begun regulating carbon dioxide and other greenhouse gas emissions under the Clean Air Act. In recent years Congress has also considered legislation that would require increased reductions in emissions of carbon dioxide and other greenhouse gases, sulfur dioxide, nitrogen oxide and mercury. Existing and

 

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new legislation may lead to some electricity generating customers switching to other sources of fuel, in an attempt to lower levels of regulated emissions.

Clean Air Act requirements that may directly affect our customers include the following:

Sulfur Dioxide and Nitrogen Oxide Emissions

The EPA promulgated the Clean Air Interstate Rule (CAIR) in March 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 (D.C.). CAIR has been subject to a complex series of legal challenges since its promulgation. In July 2010, the EPA proposed the Clean Air Transport Rule (CATR) to replace CAIR. The CATR would require the reduction of sulfur dioxide and/or nitrogen oxide emissions in 31 states and D.C. and would allow limited interstate trading of emission rights among power plants. Relative to CAIR, CATR would increase emission reductions and shorten the time frame for compliance. The EPA anticipates finalizing CATR in 2011. Congress is also considering additional legislation aimed at reducing sulfur dioxide and nitrogen oxide emissions from power plants. Any of the foregoing legislative or regulatory initiatives could cause our customers to change their regional coal sources or reduce their demand for coal.

Mercury Emissions

The EPA promulgated the Clean Air Mercury Rule (CAMR) in March 2005. CAMR permanently caps and reduces nationwide mercury emissions from new and existing coal-fueled power plants. The rule established a 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. In February 2011, the EPA issued emission standards for mercury and other hazardous air pollutants from certain boilers and process heaters. However, the EPA is expected to reconsider certain aspects of the standards. In addition, Congress is considering legislation mandating mercury emission reductions from coal-fueled power plants. These developments and future regulations and/or legislation could further limit mercury emissions from power plants, which could adversely affect the demand for coal.

Particulate Matter

In October 2006, the EPA updated the National Ambient Air Quality Standards (NAAQS) applicable to fine and coarse particulate matter. In February 2009, the U.S. Court of Appeals for the D.C. Circuit remanded to the EPA certain aspects of the fine particulate matter standards. Existing and possible future restrictions, including any that arise out of the EPA’s ongoing review, on the emission of fine or coarse particulate matter 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 2008, the EPA lowered the eight-hour ozone standards to 0.075 parts per million. In January 2010, the EPA proposed to further restrict these standards. The revised standards may require more stringent emissions controls on sources of nitrogen oxides, including coal-fueled electricity generating plants. Demand for coal from our mining operations may be adversely affected when the more stringent standards are implemented.

New Source Review Regulations

Pursuant to the EPA’s new source review (NSR) program, existing coal-fueled power plants could be required under certain circumstances to install the more stringent air emissions control equipment required of new plants. Our electricity generating customers may be subject to NSR enforcement actions and, if found not to be in compliance, could be required to install additional control equipment at the affected plants or they could decide to close some or all of those plants. The EPA has predicted that its enforcement of the NSR program will lead to the closure of aging, coal-fueled power plants, in particular. Changes to the NSR program and/or its enforcement may adversely impact demand for coal.

Regional Haze

On June 15, 2005, the EPA issued the Clean Air Visibility Rule to amend the 1999 regional haze rule, which established planning and emissions reduction timelines for states to use to improve visibility in national parks throughout the U.S. Under the amended rule, certain older power plants may be required to implement best available retrofit technology (BART), which could include the installation of additional controls for nitrogen oxide, sulfur dioxide and particulate matter. The EPA has determined that states that 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.

 

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Acid Rain

Title IV of the Clean Air Act regulates sulfur dioxide emissions by coal-fueled power plants with generating capacity 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.

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. Pursuant to the Clean Air Act, the EPA has begun regulating carbon dioxide and other greenhouse gas emissions. In April 2010, the EPA finalized regulations requiring a reduction in emissions of greenhouse gases from motor vehicles beginning in 2011. These regulations have subjected certain stationary sources of greenhouse gases, including coal-fueled power plants, to existing permitting and other requirements under the Clean Air Act. In May 2010, the EPA finalized its Greenhouse Gas Tailoring Rule (GHG Tailoring Rule), which sets forth criteria for determining which stationary sources are required to obtain permits to construct, modify or operate on account of, and to implement the best available control technology (BACT) for, their greenhouse gas emissions pursuant to the Clean Air Act Prevention of Significant Deterioration and Title V operating permit programs. Under the GHG Tailoring Rule, permitting requirements will be phased in through successive steps that expand the scope of covered sources over time. The EPA has issued guidance on what BACT entails for the control of greenhouse gases and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. More recently, the EPA has announced that it plans to set federal performance standards and state emission guidelines for greenhouse gas emissions from certain power plants by May 2012. These measures could require the installation of additional pollution controls or other emission reduction measures at certain new, modified and existing coal-fueled power plants. In addition, we are required to report annual greenhouse gas emissions from certain of our operations beginning with calendar year 2011. Although it is not yet possible to predict the effect of the GHG Tailoring Rule or any future greenhouse gas performance standards or emission guidelines, such regulations may cause a reduction in the amount of coal that our customers purchase from us, which could adversely affect our results of operations.

In addition, legislators, including Congress, have been considering the passage of significant new laws to address climate change. In 2009, the U.S. House of Representatives passed legislation that would, among other things, impose a nationwide cap on carbon dioxide and other greenhouse gas emissions and require large emitters, including coal-fueled power plants, to obtain “emission allowances” to meet that cap. Legislators are considering several other energy and air emission measures with the ultimate goal of reducing greenhouse gas emissions.

In the absence of federal legislation, many states, regions and local authorities have adopted greenhouse gas regulations and initiatives. For example, ten northeastern and midatlantic states participate in the Regional Greenhouse Gas Initiative, pursuant to which they have agreed to reduce carbon dioxide emissions from the power sector by 2018. Similarly, nine midwestern governors and two Canadian premiers have agreed to participate or observe in the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions. In addition, more than half of the states in the U.S. have implemented renewable portfolio standards, which mandate that a specified percentage of electricity sales in the state come from renewable energy, and in 2009 and 2010, Congress considered legislation that would impose a similar federal mandate.

These and other federal, state and regional climate change rules will likely require additional controls on coal-fueled sources 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 power, coal, oil and gas companies alleging that their operations are contributing to climate change. At least two U.S. federal appellate courts have permitted these lawsuits to proceed. One of these appellate court decisions was subsequently vacated, without being decided on the merits, when a request to rehear the case was granted but the court rehearing the case failed to establish a quorum. The U.S. Supreme Court has granted a petition to review the other appellate decision. The plaintiffs in these cases seek various remedies, including punitive and compensatory damages and injunctive relief. If successful, these or similar suits could lead to 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.

 

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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, the U.S. has participated in meetings to negotiate an agreement regarding greenhouse gas emissions reductions after 2012. Through these meetings, the U.S. has committed to non-binding emissions reductions targets. Any treaty or other arrangement ultimately adopted by the U.S. or other countries to implement this commitment or otherwise reduce greenhouse gas emissions 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.

Any of the foregoing current or future laws, regulations or other initiatives to address greenhouse gas emissions could affect coal-fueled power plants in particular and reduce the amount of coal that our customers purchase from us, thereby adversely affecting our results of operations.

Hazardous Waste

The RCRA established comprehensive requirements for the treatment, storage and disposal of hazardous wastes. These requirements primarily affect our customers as coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous waste materials under RCRA. In May 2010, the EPA released two competing proposals for the regulation of coal combustion by-products (CCB). One would regulate the by-products as hazardous or special waste, and the other would classify the by-products as non hazardous waste. If CCB were classified as special or hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations. These regulations, or any other regulations which increase the costs associated with the management or disposal of CCB, could adversely impact our customers’ operating costs and potentially reduce their purchase of coal.

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 and water treatment.

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 operate 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. In the past, 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.

 

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Additional Information

We file annual, quarterly and current reports, and any 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.

Executive Officers

Set forth below are the names, ages and current positions of our executive officers and Chairman of the Board of Directors. Executive officers are appointed by, and hold office at, the discretion of our Board of Directors.

 

Name

   Age     

Positions

Irl F. Engelhardt      64       Chairman of the Board of Directors
Richard M. Whiting      56       President, Chief Executive Officer & Director
Charles A. Ebetino, Jr.      58       Senior Vice President & Chief Operating Officer
Mark N. Schroeder      54       Senior Vice President & Chief Financial Officer
Joseph W. Bean      48       Senior Vice President - Law & Administration,
      General Counsel & Corporate Secretary
Robert W. Bennett      48       Senior Vice President & Chief Marketing Officer

Irl F. Engelhardt

Chairman of the Board of Directors

Irl F. Engelhardt, age 64, serves as Chairman of the Board of Directors and also served as Executive Advisor through December 31, 2010. Prior to the spin-off, Mr. Engelhardt served as Chairman and as a director of Peabody from 1998 until October 2007. He also served as Chief Executive Officer of Peabody or its predecessor companies from 1990 to 2005 and as Chairman of the predecessor companies from 1993 to 1998. After joining a predecessor of Peabody in 1979, Mr. Engelhardt 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. He also served as Co-Chief Executive Officer and executive director of The Energy Group from 1997 to 1998, Chairman of Cornerstone Construction & Materials, Inc. from 1994 to 1995 and Chairman of Suburban Propane Company from 1995 to 1996. He served as a director and Group Vice President of Hanson Industries from 1995 to 1996.

Mr. Engelhardt 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 currently serves on the Board of Directors of The Williams Companies, Inc. and served on the Board of Directors of Valero Energy Corporation from 2006 to 2010.

Richard M. Whiting

President, Chief Executive Officer & Director

Richard M. Whiting, age 56, serves as President, Chief Executive Officer and as a Director. Mr. Whiting joined Peabody’s predecessor company in 1976 and held a number of operations, sales and engineering positions both at the corporate offices and at field locations. Prior to the spin-off, he 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. Mr. Whiting 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.

Mr. Whiting currently serves as a member of the Executive Committee of the NMA, Chairman of the NMA’s Audit and Finance Committee, and COALPAC Chairman. He is the former Chairman of NMA’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 also currently a director of the Society of Mining Engineers Foundation. Mr. Whiting holds a Bachelor of Science degree in mining engineering from West Virginia University.

 

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Charles A. Ebetino, Jr.

Senior Vice President & Chief Operating Officer

Charles A. Ebetino, Jr., age 58, serves as Senior Vice President & Chief Operating Officer. From the spin-off through August 2010, Mr. Ebetino served as Senior Vice President – Corporate Development for Patriot. Prior to the spin-off, Mr. Ebetino was Senior Vice President — Business and Resource Development for Peabody since May 2006. Mr. Ebetino also served as Senior Vice President — Market Development for Peabody’s sales and marketing subsidiary from 2003 to 2006 and was directly responsible for COALTRADE, LLC. He 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.

Mr. 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 Vice Chairman of the Inland Waterway Users Board, and a past board member and President of the Western Coal Transportation Association. Mr. 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.

Mark N. Schroeder

Senior Vice President & Chief Financial Officer

Mark N. Schroeder, age 54, serves as Senior Vice President & Chief Financial Officer. Prior to the spin-off, Mr. Schroeder held several key management positions in his career at Peabody which began in 2000. These positions included President of Peabody China from 2006 to 2007, Vice President of Materials Management from 2004 to 2006, Vice President of Business Development from 2002 to 2004 and Vice President and Controller from 2000 to 2002. He has more than 30 years of business experience, including as Chief Financial Officer of Franklin Equity Leasing Company from 1998 to 2000, Chief Financial Officer of Behlmann Automotive Group from 1997 to 1998, and financial management positions with McDonnell Douglas Corporation and Ernst & Young, LLP.

Mr. Schroeder is a certified public accountant and holds a Bachelor of Science degree in business administration from Southern Illinois University — Edwardsville.

Joseph W. Bean

Senior Vice President — Law & Administration, General Counsel & Corporate Secretary

Joseph W. Bean, age 48, serves as Senior Vice President — Law & Administration, General Counsel & Corporate Secretary. From the spin-off to February 2009, Mr. Bean served as Senior Vice President, General Counsel & Corporate Secretary for Patriot. Prior to the spin-off, Mr. Bean served as Peabody’s Vice President & Associate General Counsel and Assistant Secretary from 2005 to 2007 and as Senior Counsel from 2001 to 2005. During his tenure at Peabody, he directed the company’s legal and compliance activities related to mergers and acquisitions, corporate governance, corporate finance and securities matters.

Mr. Bean has 24 years of corporate law experience, including 20 years as in-house legal counsel. He 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. He also served as a corporate law associate with the law firms of Mayer, Brown & Platt in Chicago and Thompson & Mitchell in St. Louis. Mr. Bean holds a Bachelor of Arts degree from the University of Illinois and a Juris Doctorate from Northwestern University School of Law.

Robert W. Bennett

Senior Vice President & Chief Marketing Officer

Robert W. Bennett, age 48, serves as Senior Vice President & Chief Marketing Officer. Mr. Bennett has over 23 years of experience in the coal sales, marketing and trading arena. From the time of the Magnum acquisition through March 2009, Mr. Bennett served as Patriot’s Senior Vice President of Sales and Trading and was responsible for Patriot’s thermal coal sales. Prior to the Magnum acquisition, Mr. Bennett served as Senior Vice President – Sales and Trading of Magnum Coal Company and President of Magnum Coal Sales, LLC, positions he held from 2006 to 2008. During 2005 and 2006, Mr. Bennett served as Vice President – Appalachia Sales for Peabody’s sales and marketing subsidiary, COALSALES, LLC. Mr. Bennett served as Vice President – Brokerage and Agency Sales for Peabody’s coal trading subsidiary, COALTRADE, LLC from 1997 to 2005 where he was responsible for all coal brokerage and agency relationships in the eastern United States. Prior to 1997, Mr. Bennett held various leadership positions with AGIP Coal Sales and Neweagle Corporation. Mr. Bennett holds a Bachelor of Arts in Finance from Marshall University.

 

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Item 1A. Risk Factors.

RISK FACTORS

You should carefully consider the risks described below, together with all of the other information included in this report, in evaluating our company and our common stock. If any of the risks described below actually occur, our business, financial results, financial condition and stock price could be materially adversely affected.

Risk Factors Relating to Demand for our Products

A decline in coal prices could reduce our revenues as well as adversely impact our earnings.

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 demand for our products which is impacted by numerous factors beyond our control, such as 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. Additional information about the risk factors that affect coal demand is included below. Any material decrease in demand would cause coal prices to decline and require us to decrease costs in order to maintain our margins.

Any change in coal consumption patterns, in particular by U.S. electric power generators or global 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 the value of our coal reserves as well as an adverse impact on our earnings.

Thermal coal accounted for approximately 78%, 83% and 79% of our coal sales volume during the years ended December 31, 2010, 2009 and 2008, respectively. The majority of our sales of thermal coal were to U.S. electric power generators with a small portion sold into the global export market. 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 fueled electrical generating sources in the future. Current developments in natural gas production processes have lowered the cost and increased the supply, resulting in greater demand for natural gas for electricity generation. 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 electricity demand. Accordingly, significant changes in weather patterns impact 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 22%, 17% and 21% of our coal sales volume during the years ended December 31, 2010, 2009 and 2008, respectively. Metallurgical coal was sold to the domestic steel industry and to steel producers in the global export markets. Industry-wide global export markets are primarily driven by steel production in growing countries such as China and India, as well as Europe, Brazil and the U.S. and are impacted by the availability of metallurgical coal from coal producing countries such as Australia. 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 steel industry also 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 be directly correlated to 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.

 

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Because we sell substantially all of our coal to electricity generators and steel producers, our business and results of operations are closely linked to 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. Prolonged decreases in global demand for electricity and steel production, could adversely affect our financial condition and results of operations.

The recent recession created economic uncertainty, and electricity generators and steel producers responded by decreasing production. As the demand for coal declined, certain of our thermal and metallurgical coal customers delayed shipments or requested deferrals pursuant to existing long-term coal supply agreements. Other customers may, in the future, seek to delay shipments or request deferrals under existing agreements. Customer deferrals, if agreed to, could affect the amount of revenue we recognize in a certain period and could adversely affect our results of operations and liquidity if we do not receive equivalent value from such customers and we are unable to sell committed coal at the contracted prices under our existing coal supply agreements.

Any decrease in coal prices, whether due to increased use of alternative energy sources, changes in weather patterns, decreases in overall demand or otherwise, would reduce our revenues and likely adversely impact our earnings and the value of our coal reserves. Additionally, if global recessions or general economic downturns result 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.

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 alternative fuel sources. 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 Alpha Natural Resources, Inc., Arch Coal, Inc., CONSOL Energy, 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 Illinois Basin, and the Western U.S., 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 Illinois Basin and the Powder River Basin. Coal with lower delivered costs shipped east from these regions 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 U.S. and abroad. Any resulting overcapacity from existing or new competitors could reduce coal prices and, therefore, our revenue and profitability.

We also face competition from renewable energy providers, like biomass, wind and solar, and other alternative fuel sources, like natural gas and nuclear. 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. Existing fuel sources also compete directly with coal. For example, weak natural gas prices have caused certain utilities to run more production through their natural gas-fueled plants instead of their coal-fueled plants.

New developments in the regulation of greenhouse gas emissions, coal ash and other environmental matters could materially adversely affect our customers’ demand for coal and our results of operations, cash flows and financial condition.

One by-product of burning coal is carbon dioxide, which has been linked in certain studies as a contributor to climate change. Legislators, including Congress, have considered the passage of significant new laws to address climate change, such as those that would impose a nationwide cap on carbon dioxide and other greenhouse gas emissions and require large sources, including coal-fueled power plants, to obtain “emission allowances” to meet that cap, and other measures are being imposed or proposed with the ultimate goal of reducing carbon dioxide and other greenhouse gas emissions. The EPA and other regulators are using existing laws, including the federal Clean Air Act, to impose obligations, including emission limits and technology-based requirements, on carbon dioxide and other greenhouse gas emissions. In addition, more than half of the states in the U.S. have implemented renewable portfolio standards, which generally mandate that a specified percentage of electricity sales in the state be attributable to renewable energy sources, and Congress has considered legislation that would impose a similar federal mandate. Further, governmental agencies have been providing

 

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grants and other financial incentives to entities developing or selling alternative energy sources with lower levels of greenhouse gas emissions, which may lead to more competition from those subsidized entities. See Item 1. Environmental Laws for additional discussion of greenhouse gas emission regulation.

There have also been several public nuisance lawsuits brought against power, coal, oil and gas companies alleging that their operations are contributing to climate change. At least two U.S. federal appellate courts have permitted these lawsuits to proceed. The plaintiffs are seeking various remedies, including punitive and compensatory damages and injunctive relief. Global treaties are also being considered that place restrictions on carbon dioxide and other greenhouse gas emissions.

A well publicized failure in December 2008 of a coal ash slurry impoundment maintained by the Tennessee Valley Authority has prompted the EPA to propose regulations governing coal combustion residuals. These regulations, if finalized, may impose significant obligations on us and our customers which could reduce demand for coal.

These current, potential and any future international, federal, state, regional or local laws, regulations or court orders addressing greenhouse gas emissions and/or coal ash, or emissions of sulfur dioxide, nitrogen oxides, mercury and/or particulate matter, will likely require additional controls on coal-fueled power plants and industrial boilers and may cause some users of coal to close existing facilities, reduce construction of new facilities or switch from coal to alternative fuels. These ongoing and future developments may have a material adverse impact on the global supply and demand for coal, and as a result could materially adversely affect our results of operations, cash flows and financial condition. Even in the absence of future regulatory developments, increased awareness of, and any adverse publicity regarding, greenhouse gas emissions and coal ash disposal associated with coal and coal-fueled power plants could affect our and our customers’ reputations and reduce demand for coal.

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 renew these agreements or to obtain new sales. If we cannot renew these coal supply agreements or find alternate customers willing to purchase our coal, 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 18% and 22% of our revenues for the years ended December 31, 2010 and 2009, respectively.

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. For the last several years, a global recession resulted in decreased demand worldwide for steel and electricity. Decreases in demand may cause our customers to delay negotiations for new contracts and/or request lower pricing. Furthermore, uncertainty caused by laws and regulations affecting electricity generators 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 is unfavorable.

In most of the contract price adjustment provisions, 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 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, chlorine content, grindability and ash fusion temperature. 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, and changes in the laws regulating the production, sale or use of coal. Moreover, a limited number 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.

In general, to the extent we or a customer do not fully perform under a contract, our results of operations and operating profit in the reporting period during which such non-performance occurs could be materially and adversely affected.

 

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Risk Factors Relating to our Operations

Our operations are subject to several operational risks, including events beyond our control, which could adversely affect our financial condition and results of operations.

Our ability to produce and sell coal is subject to operating conditions and events beyond our control. The operating conditions that have a significant impact on our operating results include geologic and equipment disruptions; the availability of skilled labor; our relationship with our represented employees; performance by the contract miners we rely on for certain production; access to and cost of key supplies, specialized mining equipment, steel, diesel fuel, and explosives; availability of transportation and continued successful relationships with our reserve leaseholders. Additional information about the risk factors that affect our operations is included below. Any significant changes to the items that affect our operations could disrupt our productions and have a significant impact on our operating results.

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 suspension of mining operations to prevent, or due to, a safety accident, including fires and explosions from methane and other sources. In 2010, enhanced safety inspections also resulted in significant disruption of production. For example, operations at our Federal No. 2 mine were temporarily suspended for 15 days in order to address potentially adverse atmospheric conditions in an abandoned area of the mine. Additionally, operations at our Panther mine were also temporarily suspended for 12 days in order to address potentially adverse atmospheric conditions in the active area of the mine.

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 thinning coal seam thickness, rock partings within a coal seam, weak roof or floor rock, sandstone channel intrusions, groundwater and increased stresses within the surrounding rock mass due to over mining, under mining and overburden changes, 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 our mining complexes and customers’ willingness to purchase our coal.

A prolonged 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 prolonged shortage of experienced labor could have an adverse impact on our productivity, our costs and our ability to expand production in the event there is an increase in the demand for our coal, all of which could adversely affect our profitability.

We could be negatively affected if we fail to maintain satisfactory labor relations.

As of December 31, 2010, Patriot had approximately 3,700 employees. Approximately 51% of our employees were represented by an organized labor union and they generated approximately 50% of the sales volume for the year ended December 31, 2010. 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 employees work at various sites in Appalachia and at the Highland complex in the Illinois Basin.

 

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The outcome of UMWA contract renewal negotiations is subject to many uncertainties and could cause a work stoppage if the labor negotiations are not completed on mutually acceptable terms. The contract negotiations could result in higher operating costs for our union operations due to increased salaries and benefits. Additionally, contributions to multi-employer pension funds could increase as a result of these negotiations. The multi-employer pension funds have become materially underfunded due to an increased retirement rate, a smaller employer base contributing to the fund, lower than expected returns on pension fund assets primarily caused by the difficult equity markets in recent years or other funding deficiencies. Our costs could increase significantly if this deficit is passed on to the current UMWA-employer base, including us. Any significant increases to wages or benefits as a result of the UMWA contract renewal negotiations could have a significant impact on our financial condition and results of operations.

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 additional costs and an increased risk of work stoppages.

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.

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. Steel is used for roof bolts that are required for 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.

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 19% of our total sales volume for the year ended December 31, 2010 was attributable to third-party contractor-operated mines. Certain of these operations 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.

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, trucks, overland conveyors, barges, river docks, 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 rail or 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 and/or Illinois Basin coal production less competitive than coal produced in other regions of the U.S. or abroad.

 

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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 U.S. inherently more expensive on a per ton-mile basis than shipments originating in the western U.S. 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 our 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.

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.

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 geologic 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 coal reserves and the 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 geologic 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, 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.

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.

 

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Risks Related to Environmental, Mine Safety and Health, and Other Regulation

Environmental, mine safety and health, and other regulations of federal and state authorities governing the coal mining industry could have a significant impact on our production and could adversely affect our financial condition and results of operations.

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 and enforcement of such 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. Additional information about the risks associated with environmental, mine safety and health, and other regulations that affect our operations and overall demand for coal is included below. Any significant changes to the requirements or enforcement of environmental and other regulations could have a significant impact on our financial condition and results of operations.

Increased focus by regulatory authorities on the effects of surface coal mining on the environment and recent regulatory developments related to surface coal mining operations could make it more difficult or increase our costs to receive new permits or to comply with our existing permits to mine coal in Appalachia or otherwise adversely affect us.

Regulatory agencies are increasingly focused on the effects of surface coal mining on the environment, particularly as it relates to water quality, which has resulted in more rigorous permitting requirements and enforcement efforts.

Section 404 of the Clean Water Act requires mining companies to obtain 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 certain of our surface mining operations, frequently require Section 404 permits. The issuance of permits to construct valley fills and refuse impoundments under Section 404 of the Clean Water Act has been the subject of many court cases and increased regulatory oversight, resulting in additional permitting requirements that are expected to delay or even prevent the opening of new mines. See Item 1. Environmental Laws for additional description of Section 404 of the Clean Water Act.

For example, in April 2010, the EPA issued comprehensive guidance to provide clarification as to the water quality standards that should apply when reviewing Clean Water Act permit applications for Appalachian surface coal mining operations. This guidance establishes threshold conductivity levels to be used as a basis for evaluating compliance with narrative water quality standards. To obtain necessary permits, we and other mining companies are required to meet these requirements. We have begun to incorporate these new requirements into our current permit applications; however, there can be no guarantee that we will be able to meet these or any other new standards with respect to our permit applications.

Additionally, in January 2011, the EPA rescinded a federal Clean Water Act permit held by another coal mining company for a surface mine in Appalachia citing associated environmental damage and degradation. While our operations are not directly impacted, this could be an indication that other surface mining water permits could be subject to more substantial review in the future.

It is unknown what future changes will be implemented to the permitting review and issuance process or to other aspects of surface mining operations, but the increased regulatory focus, future laws and judicial decisions and any other future changes could materially and adversely affect all coal mining companies operating in Appalachia, including us. In particular, we will incur additional permitting and operating costs, could be unable to obtain new permits or maintain existing permits and could incur fines, penalties and other costs, any of which could materially adversely affect our business. If surface coal 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 a material adverse effect on our financial condition and results of operations. In addition, increased public focus on the environmental, health and aesthetic impacts of surface coal mining could harm our reputation and reduce demand for coal.

 

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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, our payment of fines and penalties and the imposition of requirements that may in the future require us to incur material additional costs and may be difficult to resolve or satisfy on a timely basis given current technology.

Selenium is a naturally occurring element that is encountered in earthmoving operations. The extent of selenium occurrence varies depending upon site specific geologic conditions. Selenium is encountered globally in coal mining, phosphate mining and agricultural operations. In coal mining applications, selenium can be discharged to surface water when mine tailings are exposed to rain and other natural elements. Selenium effluent limits are included in permits issued to us and other coal mining companies.

We have established a liability for the treatment of outfalls with known selenium exceedances. The liability reflected the estimated total costs of the planned Zero Valent Iron (ZVI) water treatment systems we have been installing and maintaining. This estimate was prepared considering the dynamics of legislation, capabilities of available technology and our planned remediation strategy. We utilized the cost of the most successful treatment methodology at that time based on our testing results for our best estimate based on uncertainties regarding technology, compliance parameters and deadline extensions.

Despite our continued efforts, we have been unable to identify a treatment system that can remove selenium sustainably, consistently and uniformly under all variable conditions experienced at our mining operations. Accordingly, we cannot currently meet the effluent selenium limits in our mining permits. We are currently involved in various legal proceedings related to compliance with the effluent selenium limits in our mining permits. As a result of these legal proceedings, we are subject to various consent decrees and court orders that generally require us, among other things, to meet certain compliance deadlines related to selenium discharge levels and to research, develop and implement pilot projects of potential technologies for the treatment of selenium exceedances at permitted outfalls. In the past, we have paid fines and penalties with respect to violations of selenium effluent limitations. While we are actively continuing to explore treatment options, there can be no assurances as to when a definitive solution will be identified and implemented or whether we can meet the compliance deadlines. In 2010, one of our subsidiaries was found in contempt for failing to comply with a consent decree regarding selenium discharge limits. See Item 1 Certain Liabilities, Reclamation and Remediation Obligations for more information about selenium-related matters.

Pursuant to a September 1, 2010 order from the U.S. District Court, we are required to install a Fluidized Bed Reactor (FBR) water treatment facility for three mining outfalls and to comply with applicable selenium discharge limits at these outfalls by March 1, 2013. At this time, there is no plan to install FBR or any technology other than ZVI at the other outfalls as neither FBR nor other technologies have been proven effective on a full-scale basis. Because the levels of water flow and selenium discharges at each outfall differ, the solution for each outfall may be very different and a variety of solutions may ultimately be required. We are continuing to research various treatment alternatives in addition to ZVI for the other outfalls. If ZVI is not ultimately successful in treating the effluent selenium exceedances at these additional outfalls, we may be required to install alternative treatment technologies. The cost of other technologies could be materially higher than the costs reflected in our liability. Furthermore, costs associated with potential modifications to ZVI or the scale of the planned ZVI systems to be installed could also cause the costs to be materially higher than the costs reflected in our liability.

While we are actively continuing to explore options, there can be no assurance as to when a definitive solution will be identified and implemented or when other uncertainties will be finally resolved. As a result, we may incur additional costs beyond those that we have projected in our current estimates. Additionally, the existence of these federal and state consent decrees may not preclude further enforcement actions or other lawsuits. Any failure to meet the deadlines in our permits, consent decrees and court orders 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.

The environmental, health and safety regulations applicable to our mining operations impose significant costs on us, and future regulations or changes in the interpretation or application or enforcement of existing regulations could increase those costs and 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. Federal and state authorities inspect our operations, and in the aftermath of the April 5, 2010 accident at a competitor’s underground mine in Central Appalachia, we and other mining companies have experienced, and may in the future continue to experience, a significant increase in the frequency and scope of these inspections. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state and/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.

 

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In response to the April 5, 2010 accident mentioned above, federal and West Virginia authorities instituted enhanced inspections of coal mines for, among other safety concerns, the accumulation of coal dust and the proper ventilation of gases such as methane. We experienced some of these enhanced inspections throughout the remainder of 2010 and believe they will continue in the future. In September 2010, MSHA issued an emergency temporary standard requiring mine operators to increase the incombustible content of combined coal dust, rock dust, and other dust to at least 80% in underground areas of bituminous coal mines. This requirement is further increased for mines containing methane gas. MSHA has also proposed several additional regulations, including a proposal to require the use of continuous personal dust monitors and expanded requirements for medical surveillance.

In addition, Congress is currently considering legislation to enhance mine safety laws which could result in additional or enhanced mine safety equipment and procedure requirements, more frequent mine inspections, stricter enforcement practices, enhanced reporting and miner training requirements, higher penalties for certain violations of safety rules and increased authority for MSHA. West Virginia regulatory authorities are also considering enhanced mine safety laws, which could potentially result in more stringent equipment and procedure requirements.

In October 2010, MSHA proposed, among other things, lowering existing concentration limits for respirable coal mine dust, requiring the use of personal dust monitors and expanding medical surveillance for workers. This measure is part of MSHA’s efforts to reduce the incidence of lung disease among mine workers.

The costs, liabilities and requirements associated with addressing the outcome of inspections and complying with these environmental, health and safety requirements are often significant and time-consuming and may delay commencement or continuation of exploration or production. New or revised legislation or administrative regulations (or a change in judicial or administrative interpretation, application or enforcement 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 and/or users of coal, 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. Additionally, MSHA may order the temporary closure of mines in the event of certain violations of safety rules. 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. 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.

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 for 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 related 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 damage 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.

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.

 

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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 SMCRA and to other legal proceedings 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. See Item 3. Legal Proceedings for a full description of our claims and litigation.

If our benefit plan cost assumptions are incorrect, then expenditures for these benefits could be materially higher than we have assumed and could adversely affect our financial condition and results of operations.

We provide various health and welfare benefits to eligible active and certain retired employees. We make assumptions in order to calculate our obligations for future spending related to these employee benefit plans, including costs related to the 2010 healthcare legislation.

The 2010 healthcare legislation impacts our costs to provide healthcare benefits to our eligible active and certain retired employees and to provide workers’ compensation benefits related to occupational disease resulting from black lung disease. The 2010 healthcare legislation has both short-term and long-term implications on healthcare benefit plan standards. Implementation of the 2010 healthcare legislation will occur in phases, with plan standard changes taking effect beginning in 2010, but to a greater extent with the 2011 benefit plan year and extending through 2018. Plan standard changes that affect us in the short term include raising the maximum age for covered dependents to continue to receive benefits, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual, among other standard requirements. Plan standard changes that could affect us in the long term include a tax on “high cost” plans (excise tax) and the elimination of annual dollar limits per covered individual, among other standard requirements.

Beginning in 2018, the 2010 healthcare legislation will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of this excise tax. Until these regulations or interpretations are published, it is impractical to reasonably estimate the ultimate impact of the excise tax on our future healthcare costs or postretirement benefit obligation. We have incorporated changes to our actuarial assumptions to determine our postretirement benefit obligations utilizing preliminary estimates and basic assumptions around the pending interpretations of these regulations.

We provide postretirement 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 $1.3 billion as of December 31, 2010. We have estimated these unfunded obligations based on actuarial assumptions described in the notes to our consolidated financial statements.

Additional regulations or interpretations concerning the 2010 healthcare legislation could have a material adverse impact on our healthcare costs. Additionally, if our actual experience does not match our assumptions, it could have a material adverse impact on our results of operations, cash flows and financial condition and our cash expenditures and costs incurred for employee benefit plans 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 annually beginning in 2007, 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 rate. 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. Even with these increased rates, the difficult equity markets over recent years have resulted in materially underfunded multi-employer pension funds and any new rates assigned for 2012 and forward may be higher than the 2011 rate as this deficit is addressed.

 

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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.

We could be liable for certain retiree healthcare obligations 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 $680.9 million as of December 31, 2010. 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.

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.

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 in accordance with authoritative accounting guidance. 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, 2010, we had accrued reserves of $118.4 million for reclamation liabilities and an additional $135.7 million for mine closure costs, including medical benefits for employees and water treatment 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 or timing vary from assumptions, if the underlying facts change or if governmental requirements change significantly.

Risk Factors Relating to Financial and Other Aspects of our Business

If our business does not generate sufficient cash for operations, we may not be able to repay borrowings under our credit facility and outstanding notes, to refinance our accounts receivable securitization program 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 partially depend upon our operating performance. 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 any of our obligations 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 our operating performance, 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 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 our indebtedness 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 or more advantageous financing options; 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.

Our operations may depend on the availability of additional financing and access to funds under our credit facility and accounts receivable securitization program.

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 have been.

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 its 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.

 

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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 land 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 letter of credit. As of December 31, 2010, we had outstanding surety bonds and letters of credit aggregating $513.4 million, of which $282.6 million was for post-mining reclamation, $151.5 million related to workers’ compensation obligations, $56.7 million was for retiree health obligations and $22.6 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 and accounts receivable securitization program.

As of December 31, 2010, Arch Coal, Inc. (Arch) held surety bonds of $91.2 million related to properties acquired by Patriot in the Magnum acquisition, of which $89.5 million related to reclamation. We have posted letters of credit in Arch’s favor, as required.

Economic recession, 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 revolving credit facility and account receivable securitization program and the exercise by third-party surety bond issuers of their right to refuse to renew the surety.

We could be adversely affected by a decline in the creditworthiness or financial condition of our customers.

A significant portion of our revenue is generated through sales to a marketing affiliate of Peabody. We supply coal to Peabody on a contract basis so Peabody can meet its commitments under customer agreements in existence prior to the spin-off sourced from our operations. Our remaining sales are made directly to electricity generators, 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 struggle to maintain their business during economic recessions or downturns. If our customers are significantly and negatively impacted by the challenging economic conditions, or by other business factors, our results of operations and financial condition could be materially adversely affected.

The covenants in our credit facility and other debt indentures impose restrictions that could limit our operational and financial flexibility.

Our credit facility and our other debt indentures contain certain customary covenants, including certain limitations on, among other things, additional debt, liens, investments, acquisitions and capital expenditures, future dividends, and asset sales. Our credit facility also contains financial covenants related to net debt coverage and cash interest expense coverage. 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.

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, under certain circumstances, 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.

 

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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 Internal Revenue Service (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 U.S. 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.

Item 1B. Unresolved Staff Comments.

None.

 

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Item 2. Properties.

Coal Reserves

We had an estimated 1.9 billion tons of proven and probable coal reserves as of December 31, 2010 located in Appalachia and the Illinois Basin. Of our proven and probable coal reserves 13%, or just over 251 million tons, are compliance coal and 1,614 million tons are non-compliance coal. We own approximately 34% of these reserves and lease property containing the remaining 66%. 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.

 

     Proven and Probable
Reserves as of

December 31, 2010(1)
 

Geographic Region

   Owned
Tons
     Leased
Tons
     Total
Tons
 
     (In millions)  

Appalachia

     273         924         1,197   

Illinois Basin

     365         303         668   
                          

Total proven and probable coal reserves

     638         1,227         1,865   
                          

 

(1)

Reserves have been adjusted to take into account recoverability factors in producing a saleable product.

Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:

 

   

Proven (Measured) Reserves. Reserves for which (a) quantity is computed from dimensions defined by outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so close and the geologic character is so well defined that size, shape, depth and mineral content of coal reserves are well-established.

 

   

Probable (Indicated) Reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

Our estimates of 1,138 million tons of proven and 727 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, 2010 were prepared by our Vice President – Engineering and his geology and engineering staff, by updating the December 31, 2009 estimates and incorporating a reserve statement from an outside consultant for certain 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 1.9 billion tons of proven and probable reserves as of December 31, 2010.

 

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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 1.9 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 land 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.

 

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The following chart provides a summary, by geographic region and mining complex, of production for the years ended December 31, 2010, 2009 and 2008, tonnage of coal reserves assigned to our operating mines, property interest in those reserves and other characteristics of the facilities. Production for the Magnum operations is included from the date the acquisition was consummated, July 23, 2008.

PRODUCTION AND ASSIGNED RESERVES( 1)

 

    Production     Sulfur Content(2)                 As of December 31, 2010  

Geographic Region/

Mining Complex

  Year
Ended
Dec 31,
2010
    Year
Ended
Dec 31,
2009
    Year
Ended
Dec 31,
2008
    <1.2 lbs.
Sulfur
Dioxide
per
Million Btu
    >1.2 to 2.5
lbs. Sulfur
Dioxide
per
Million Btu
    >2.5 lbs.
Sulfur
Dioxide
per
Million Btu
    Type  of
Coal(3)
    As
Received
Btu per
Pound(4)
    Assigned
Proven and
Probable
Reserves
    Reserve
Control
    Mining
Method
 
                    Owned     Leased     Surface     Under-
ground
 
                                  (Tons in millions)                                      

Appalachia:

                         

Big Mountain

    2.0        2.0        1.9        4        19        —          Steam        12,200        23        —          23        —          23   

Blue Creek

    0.8        0.1        —          —          31        —          Steam        12,000        31        —          31        —          31   

Campbell’s Creek

    0.7        1.0        0.6        3        2        —          Steam        12,200        5        —          5        —          5   

Corridor G

    4.0        3.6        1.6        5        44        1        Steam        12,300        50        1        49        50        —     

Jupiter

    —          —          0.2        3        18        —          Steam        12,800        21        —          21        4        17   

Kanawha Eagle

    1.5        1.9        2.1        21        19        —          Met/Steam        13,100        40        —          40        —          40   

Logan County

    2.7        2.6        1.0        45        35        —          Met/Steam        12,400        80        10        70        68        12   

Paint Creek

    1.1        2.3        1.4        21        33        —          Met/Steam        13,000        54        —          54        5        49   

Panther

    2.0        2.1        0.6        34        2        —          Met/Steam        13,200        36        1        35        —          36   

Rocklick

    0.4        1.5        2.6        —          25        —          Met/Steam        12,800        25        —          25        —          25   

Wells

    3.1        3.4        3.4        24        18        —          Met/Steam        13,400        42        —          42        —          42   

Federal

    3.7        3.8        3.1        —          1        49        Steam        13,300        50        45        5        —          50   
                                                                                           

Total

    22.0        24.3        18.5        160        247        50            457        57        400        127        330   

Illinois Basin:

                         

Bluegrass

    2.3        2.5        2.8        —          —          70        Steam        10,900        70        16        54        4        66   

Dodge Hill

    0.9        0.9        1.0        —          —          19        Steam        12,700        19        2        17        —          19   

Highland

    3.5        3.7        3.9        —          —          89        Steam        11,300        89        28        61        —          89   
                                                                                           

Total

    6.7        7.1        7.7        —          —          178            178        46        132        4        174   
                                                                                           

Total

    28.7        31.4        26.2        160        247        228            635        103        532        131        504   
                                                                                           

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, 2010

 

                      Sulfur Content(2)                                      

Coal Seam

Location

  Total
Assigned(1)
    Tons Un-
assigned(1)
    Proven
and
Probable
Reserves
    Proven
(Measured)
    Probable
(Indicated)
    < 1.2  lbs.
Sulfur
Dioxide
per
Million
Btu
(Phase
II)
    >1.2 to 2.5
lbs.

Sulfur
Dioxide
per
Million
Btu
(Phase I)
    >2.5
lbs.
Sulfur
Dioxide

per
Million
Btu
(Non-
Com-
pliance)
    Type  of
Coal(3)
    As
Received
Btu per
Pound(4)
    Reserve
Control
    Mining
Method
 
                      Owned     Leased     Surface     Under-
ground
 
                                  (Tons in millions)                                            

Appalachia:

                           

Ohio

    —          26        26        19        7        —          —          26        Steam        11,300        26        —          —          26   

West Virginia    

    457        714        1,171        796        375        248        662        261       
 
Met/
Steam
 
  
    13,000        247        924        247        924   
                                                                                                   

Total

    457        740        1,197        815        382        248        662        287            273        924        247        950   

Illinois Basin:

                           

Illinois

    —          231        231        90        141        3        18        210        Steam        10,800        229        2        1        230   

Kentucky

    178        259        437        233        204        —          —          437        Steam        11,400        136        301        34        403   
                                                                                                   

Total

    178        490        668        323        345        3        18        647            365        303        35        633   
                                                                                                   

Total proven and probable

    635        1,230        1,865        1,138        727        251        680        934            638        1,227        282        1,583   
                                                                                                   

 

1)

Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2010. Unassigned reserves would require new mine development, mining equipment or plant facilities before operations could begin on the property.

2)

Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal.

3)

Type of coal is based on the type of coal produced and/or the type of coal in our reserves.

4)

As-received Btu per pound includes the weight of moisture in the coal on an as-sold basis.

 

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Item 3. Legal Proceedings.

From time to time, we are involved in legal proceedings, arbitration proceedings and administrative procedures arising in the ordinary course of business. 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. Our significant legal proceedings are discussed below.

Environmental Claims and Litigation

We are subject to applicable federal, state and local environmental laws and regulations including SMCRA, the Clean Water Act, the Clean Air Act, CERCLA (also known as Superfund), RCRA and their state equivalents.

Clean Water Act Permit Issues

The federal Clean Water Act (CWA) 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 CWA 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, 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 CWA issues, include the following:

EPA Consent Decree

In February 2009, we entered into a consent decree with the EPA and the WVDEP to resolve certain claims under the CWA and the West Virginia Water Pollution Control Act relating to our NPDES permits at several mining operations in West Virginia. The consent decree was entered by the federal district court on April 30, 2009. The consent decree, among other things, requires us to implement an enhanced company-wide environmental management system, which includes regular compliance audits, electronic tracking and reporting, and annual training for all employees and contractors with environmental responsibilities. We 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 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 to be material.

WVDEP Action

In 2007, Hobet was sued for exceedances of effluent limits contained in four of its NPDES permits in state court in Boone County by the WVDEP. We refer to this case as the WVDEP Action. 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 paid approximately $1.5 million in civil penalties, with the final payment made in July 2009. The settlement also required us to complete supplemental environmental projects, to gradually reduce selenium discharges from our Hobet Job 21 surface mine, to achieve full compliance with our NPDES permits by April 2010 and to study potential treatment alternatives for selenium.

On October 8, 2009, a motion to enter a modified settlement and consent order in the WVDEP Action was submitted to the Boone County Circuit Court. This motion to modify the settlement and consent order was jointly filed by Patriot and the WVDEP. On December 3, 2009, the Boone County Circuit Court approved and entered a modified settlement and consent order to, among other things, extend coverage of the September 5, 2008 settlement and consent order to two additional permits and extend the date to achieve full compliance with our NPDES permits from April 2010 to July 2012. One of the two additional permits subject to such extension, Hobet Surface Mine No. 22, was subsequently addressed in the September 1, 2010 U.S. District Court Ruling, as further discussed below.

We continue to install treatment systems at various permitted outfalls, but we have been unable to comply with selenium discharge limits due to the ongoing inability to identify a treatment system that can remove selenium sustainably, consistently and uniformly under all variable conditions experienced at our mining operations. While we are actively continuing to explore treatment options, there can be no assurances as to when a definitive solution will be identified and implemented or whether we can meet the July 2012 deadline.

 

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Selenium Matters

Federal Apogee Case and Federal Hobet Case

In 2007, Apogee was sued in the U.S. District Court for the Southern District of West Virginia (U.S. District Court) by the Ohio Valley Environmental Coalition, Inc. (OVEC) and another environmental group (pursuant to the citizen suit provisions of the CWA). We refer to this lawsuit as the Federal Apogee Case. This lawsuit alleged that Apogee had violated water discharge limits for selenium set forth in one of its NPDES permits. The lawsuit sought compliance with the limits of the NPDES permit, fines and penalties as well as injunctive relief prohibiting Apogee from further violating laws and its permit.

In 2008, OVEC and another environmental group filed a lawsuit against Hobet and WVDEP in the U.S. District Court (pursuant to the citizen suit provisions of the CWA). We refer to this case as the Federal Hobet Case and it is very similar to the Federal Apogee Case. Additionally, the Federal Hobet Case involved the same four NPDES permits that were the subject of the original WVDEP Action in state court. However, the Federal Hobet Case focused exclusively on selenium exceedances in permitted water discharges, while the WVDEP Action addressed all effluent limits, including selenium, established by the permits.

On March 19, 2009, the U.S. District Court approved two separate consent decrees, one between Apogee and the plaintiffs and the other between Hobet and the plaintiffs. The consent decrees extended the deadline to comply with water discharge limits for selenium with respect to the permits covered by the Federal Apogee Case and the Federal Hobet Case to April 5, 2010 and added interim reporting requirements up to that date. We agreed to, among other things, undertake pilot projects at Apogee and Hobet involving reverse osmosis technology along with interim reporting obligations and to comply with our NPDES permits’ water discharge limits for selenium by April 5, 2010. On February 26, 2010, we filed a motion requesting a hearing to discuss the modification of the March 19, 2009 consent decrees to, among other things, extend the compliance deadline to July 2012 in order to continue our efforts to identify viable treatment alternatives. On April 18, 2010, the plaintiffs in the Federal Apogee Case filed a motion asking the court to issue an order to show cause why Apogee should not be found in contempt for its failure to comply with the terms and conditions of the March 19, 2009 consent decree. The remedies sought by the plaintiffs included compliance with the terms of the consent decree, the imposition of fines and an obligation to pay plaintiffs’ attorneys fees. A hearing to discuss these motions was held beginning on August 9, 2010. See September 1, 2010 U.S. District Court Ruling below for the outcome of this hearing.

Federal Hobet Surface Mine No. 22 Case

In March 2010, the U.S. District Court permitted a lawsuit to proceed that was filed in October 2009 by OVEC and other environmental groups against Hobet, alleging that Hobet has in the past violated, and continued to violate, effluent limitations for selenium in an NPDES permit and the requirements of a SMCRA permit for Hobet Surface Mine No. 22 and seeking injunctive relief. We refer to this as the Federal Hobet Surface Mine No. 22 Case. In June 2010, the U.S. District Court denied Hobet’s motion to dismiss the case and ruled in favor of the plaintiffs, finding that Hobet had violated its NPDES and SMCRA permits at Hobet Surface Mine No. 22 and that the plaintiffs were entitled to injunctive relief. In addition to the Federal Apogee Case, the scope and terms of injunctive relief in the Federal Hobet Surface Mine No. 22 Case were discussed at the hearing that began on August 9, 2010. See September 1, 2010 U.S. District Court Ruling below for the outcome of this hearing.

Catenary WVDEP Action

On April 23, 2010, WVDEP filed a lawsuit against Catenary Coal Company, LLC (Catenary), one of our subsidiaries, in the Boone County Circuit Court. We refer to this case as the Catenary WVDEP Action. This lawsuit alleged that Catenary had discharged selenium from its surface mining operations in violation of certain of its NPDES and surface mining permits. WVDEP is seeking fines and penalties as well as injunctions prohibiting Catenary from discharging pollutants, including selenium, in violation of laws and its NPDES permits. We are unable to predict the likelihood of success of the plaintiffs’ claims. Although we intend to defend ourselves vigorously against these allegations, we may consider alternative resolutions to this matter if they would be in the best interest of the Company.

Federal Catenary/Hobet Case

On June 18, 2010, OVEC and three other environmental groups filed a lawsuit against Hobet and Catenary in the U.S. District Court under the citizen suit provisions of the CWA and SMCRA. We refer to this case as the Federal Catenary/Hobet Case. The plaintiffs allege that Hobet and Catenary have discharged, and continue to discharge selenium in violation of their NPDES and SMCRA permits. The Federal Catenary/Hobet Case involves the same two NPDES permits that are the subject of the Catenary WVDEP Action and the same four NPDES permits that are the subject of the WVDEP Action and the Federal Hobet Case. The plaintiffs seek, among other remedies, immediate compliance with the limits of the NPDES permits, the imposition of fines and penalties, as well as injunctions prohibiting Hobet and Catenary from further violating laws and their permits. On October 22, 2010, we entered into an agreement with OVEC and the other environmental groups, pursuant to which the plaintiffs agreed, among other things, to dismiss without prejudice the Federal Catenary/Hobet Case. In November 2010, this case was dismissed.

 

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February 2011 Litigation

In February 2011, OVEC and two other environmental groups filed a lawsuit against us, Apogee, Catenary and Hobet, alleging violations of ten NPDES permits and certain SMCRA permits. The ten NPDES permits include the six permits that were previously the subject of the Federal Catenary/Hobet Case. The plaintiffs are seeking fines, compliance with permit limits and other requirements, and injunctive relief.

September 1, 2010 U.S. District Court Ruling

On September 1, 2010, the U.S. District Court found Apogee in contempt for failing to comply with the March 19, 2009 consent decree entered in the Federal Apogee Case. Apogee was ordered to install an FBR water treatment facility for three outfalls and to come into compliance with applicable selenium discharge limits by March 1, 2013. Additionally, the court ordered Hobet to submit by October 1, 2010 a proposed schedule to develop a treatment plan for one outfall and to come into compliance with applicable discharge limits under the Hobet Surface Mine No. 22 permit by May 1, 2013. Apogee and Hobet were required to jointly establish an irrevocable $45 million letter of credit in support of the requirements of this ruling. The court also appointed a Special Master who is authorized to monitor, supervise and direct Apogee’s and Hobet’s compliance with, and hear disputes that arise under, the September 1, 2010 order as well as other orders of the U.S. District Court.

FBR technology had not been used to remove selenium or any other minerals discharged at surface coal mining operations prior to our pilot project that began in February 2010. The FBR water treatment facility, required by the ruling, will be the first of its kind constructed for selenium removal on a commercial scale. We anticipate that the design of the facility will be finalized in mid- to late- 2011 and then construction can begin.

Pursuant to the September 1, 2010 ruling, we will record the costs to install the FBR water treatment facility for the three Apogee outfalls as capital expenditures when incurred. The capital expenditure for the facility is estimated to be approximately $50 million. In addition, the estimated future on-going operating cash flows required to meet our legal obligation for remediation at the three Apogee outfalls have changed from our original estimates based on the September 1, 2010 ruling. As such, we increased the portion of the liability related to Apogee by updating the fair value of the on-going costs related to these three outfalls and recorded the $20.7 million difference between this updated value and our previously recorded liability directly to income, through “Reclamation and remediation obligation expense” in the third quarter of 2010.

As required under the order, we submitted a schedule to develop a treatment plan for the outfall at Hobet Surface Mine No. 22 to the U.S. District Court which includes conducting additional pilot projects related to certain technological alternatives. A final treatment technology to be utilized at Hobet Surface Mine No. 22 will be chosen in 2011 per the submitted schedule. We will record an adjustment to the selenium environmental treatment liability, if necessary, if we modify our planned treatment technology or if we choose a different treatment technology for this outfall.

Selenium Remediation Liability

We estimated the costs to treat our selenium discharges in excess of allowable limits at a fair value of $85.2 million at the Magnum acquisition date. This liability was recorded in the purchase accounting for the Magnum acquisition and included the estimated costs of installing Zero Valent Iron (ZVI) water treatment technology, which was the most successful methodology at the time based on our testing results. At the time we recorded this liability, it reflected the estimated total costs of the planned ZVI water treatment systems we have been installing and maintaining in consideration of the requirements of our mining permits, court orders, and consent decrees. This estimate was prepared considering the dynamics of legislation, capabilities of available technology and our planned remediation strategy at that time.

At the time of the Magnum acquisition, various outfalls across the acquired operations had been tested for selenium discharges. Of the outfalls tested, 88 were identified as potential sites of selenium discharge limit exceedances, of which 78 were identified as having known exceedances. The estimated liability recorded at fair value in the purchase allocation took into consideration the 78 outfalls with known exceedances at the acquisition date.

The fair value of our total liability to treat selenium discharges is $115.3 million as of December 31, 2010, including the $20.7 million adjustment related to the September 1, 2010 ruling. The current portion of the estimated liability of $19.7 million is included in “Trade accounts payable and accrued expenses” and the long-term portion is recorded in “Reclamation and remediation obligations” on our consolidated balance sheets.

Our liability to treat selenium discharges at the other outfalls not addressed in the September 1, 2010 ruling is based on the use of ZVI technology. We are currently continuing to install ZVI systems according to our original remediation strategy, while also performing a further review of other potential water treatment technology or other alternatives. Our remediation strategy reflects implementing scalable ZVI systems at each outfall due to its modular design that can be reconfigured as further knowledge and certainty is gained. Initial ZVI testing has identified potential system shortfalls, and to date ZVI has not been demonstrated to perform consistently and sustainably in achieving effluent selenium limitations or in treating the expected flows at these outfalls. However, based on the flexibility of the scalable system for configuration adjustments, we plan to continue to pursue the ZVI treatment systems and determine whether modifications to the system could result in its ability to treat selenium successfully.

 

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At this time, there is no plan to install FBR or any technology other than ZVI at the other outfalls as neither FBR nor other technologies have been proven effective on a full-scale basis. However, we are continuing to research various treatment alternatives in addition to ZVI for the other outfalls. If ZVI is not ultimately successful in treating the effluent selenium exceedances at these additional outfalls, we may be required to install alternative treatment technologies. The cost of other technologies could be materially higher than the costs reflected in our liability. Furthermore, costs associated with potential modifications to ZVI or the scale of the planned ZVI systems to be installed could also cause the costs to be materially higher than the costs reflected in our liability.

While we are actively continuing to explore treatment options, there can be no assurance as to when a definitive solution will be identified and implemented. As a result, actual costs may differ from our current estimates. Additionally, there are no assurances we will meet the time table stipulated in the various court orders, consent decrees and permits. We will make additional adjustments to our liability when, and if, we have become subject to other obligations and/or it becomes probable that we will utilize a different technology or modify the current technology, whether due to developments in our ongoing research or a legal obligation to do so.

General Selenium Matters

In general, we and other surface mining companies are currently operating pursuant to NPDES permits for which selenium limits were scheduled to go into effect on or around April 5, 2010. The WVDEP published a notice to extend the compliance deadlines, but the EPA subsequently objected to the extensions. We have filed administrative appeals and judicial actions which we believe effectively stayed any enforcement of the effective dates for the selenium limits. With respect to all outfalls with known exceedances, including the specific sites discussed above, any failure to meet the deadlines set forth in our consent decrees or established by the federal government, the U.S. District Court or the State of West Virginia 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, and the imposition 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.

In addition to the uncertainties related to technology discussed above, future changes to legislation, compliance with judicial rulings, consent decrees and regulatory requirements, findings from current research initiatives and the pace of future technological progress could result in costs that differ from our current estimates, which could have a material adverse affect on our results of operations, cash flows and financial condition.

We may incur costs relating to the lawsuits discussed above and possible additional costs, including potential fines and penalties relating to selenium matters. Additionally, as a result of these ongoing litigation matters and federal regulatory initiatives related to water quality standards that affect valley fills, impoundments and other mining practices, including the selenium discharge matters described above, 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.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)

CERCLA and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to natural resources. Under CERCLA and many similar state statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault. These regulations could require 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 its ultimate liability, if any, will not be material to our financial condition and results of operations.

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, in lawsuits 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 near, on, and/or contiguous to the sites of flooding; and (ii) Hobet participated in the development of plans to grade, blast, and alter the land near, on, 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.

 

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In the second action, 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 a similar case which was dismissed in April 2010.

The outcome of the flood 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 this matter is likely to be resolved without a material adverse effect on our financial condition, results of operations and cash flows.

Other Litigation and Investigations

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 of the 75 lawsuits are identical except for the named plaintiff. In December 2009, Apogee was served with 167 additional lawsuits with the same allegations as the original 75 lawsuits. In January 2011, Apogee was served with one additional similar lawsuit. Each lawsuit alleges 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 compensatory and punitive damages for personal injury. As of December 31, 2010, 45 of the lawsuits have been dismissed. 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.

We are a defendant in litigation involving Peabody Energy Corporation (Peabody), the parent of certain of our subsidiaries prior to our 2007 spin-off, in relation to their negotiation and June 2005 sale of two properties previously owned by two of our subsidiaries. Environmental Liability Transfer, Inc. (ELT) and its subsidiaries commenced litigation against these subsidiaries in the Circuit Court of the City of St. Louis in the State of Missouri alleging, among other claims, fraudulent misrepresentation, fraudulent omission, breach of duty and breach of contract. Pursuant to the terms of the Separation Agreement, Plan of Reorganization and Distribution from the spin-off, Patriot and Peabody are treating the case as a joint action with joint representation and equal sharing of costs. Peabody and Patriot filed counterclaims against the plaintiffs in connection with the sales of both properties. Motions for summary judgment on the complaint and counterclaim were filed by Peabody and Patriot and were denied. A trial date has been set for September 2011. Alleged damages are currently estimated to be as high as $100 million, in addition to punitive damages. We are unable to predict the likelihood of success of the plaintiffs’ claims. Although we intend to defend ourselves vigorously against all claims, we may consider alternative resolutions to this matter if they would be in the best interest of the Company.

A predecessor of one of our subsidiaries operated the Eagle No. 2 mine located near Shawneetown, Illinois from 1969 until closure of the mine in July 1993. In March 1999, the State of Illinois brought a proceeding before the Illinois Pollution Control Board against the subsidiary alleging that groundwater contamination due to leaching from a coal waste pile at the mine site violated state standards. The subsidiary has developed a remediation plan with the State of Illinois and is in litigation before the Illinois Pollution Control Board with the Illinois Attorney General’s office with respect to its claim for a civil penalty of $1.3 million.

One of our subsidiaries is a defendant in several related lawsuits filed in the Circuit Court of Boone County, West Virginia. As of December 31, 2010, there were approximately 140 related lawsuits. In addition to our subsidiary, the lawsuits name Peabody and other coal companies with mining operations in Boone County. The plaintiffs in each case allege contamination of their drinking water wells over a period in excess of 30 years from coal mining activities in Boone County, including underground coal slurry injection and coal slurry impoundments. The lawsuits seek property damages, personal injury damages and medical monitoring costs. The Boone County Public Service Commission is in the process of installing public water lines and most of the plaintiffs have access to public water. Pursuant to the terms of the Separation Agreement, Plan of Reorganization and Distribution from the spin-off, Patriot is indemnifying and defending Peabody in this litigation. In December 2009, we filed a third-party complaint against our current and former insurance carriers seeking coverage for this litigation under the applicable insurance policies. The lawsuits have been settled subject to court approval and are fully reserved.

In late January 2010, the U.S. Attorney’s office and the State of West Virginia began investigations relating to one or more of our employees making inaccurate entries in official mine records at our Federal No. 2 mine. We continue to investigate this matter internally. We terminated one employee and two other employees resigned after being placed on administrative leave. The terminated employee subsequently admitted to falsifying inspection records and has been cooperating with the U.S. Attorney’s office. In April 2010, we received a federal subpoena requesting methane detection systems equipment used at our Federal No. 2 mine since July 2008 and the results of tests performed on the equipment since that date. We have provided the equipment and information as required by the subpoena.

 

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The outcome of other litigation and the investigations is subject to numerous uncertainties. Based on our evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, we believe these matters are likely to be resolved without a material adverse effect on our financial condition, results of operations and cash flows.

Item 4. (Removed and Reserved).

Item 4B. Mine Safety Disclosure.

The information concerning mine safety violations or other regulatory matters required by Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 99.2 of this report.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

On October 31, 2007, Peabody effected the spin-off of Patriot and its subsidiaries. The spin-off was accomplished through a dividend of all outstanding shares of Patriot Coal Corporation. Our common stock is listed on the New York Stock Exchange, under the symbol PCX. As of February 18, 2011, there were 821 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.

 

     High      Low  

2009

     

First Quarter

   $ 9.00       $ 2.76   

Second Quarter

     10.90         3.51   

Third Quarter

     14.12         4.97   

Fourth Quarter

     17.24         10.21   

2010

     

First Quarter

   $ 22.37       $ 13.87   

Second Quarter

     24.25         11.68   

Third Quarter

     14.03         9.76   

Fourth Quarter

     19.94         11.52   

Dividend Policy

We have not paid 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.

 

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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 (representing the U.S. Coal Industry) comprised of Alpha Natural Resources, Inc., Arch Coal, Inc., CONSOL Energy, 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.

 

LOGO

 

     11/07      12/07      3/08      6/08      9/08      12/08      3/09      6/09      9/09      12/09      3/10      6/10      9/10      12/10  

Patriot Coal Corp

     100.00         111.31         125.25         408.77         154.93         33.33         19.79         34.03         62.72         82.45         109.12         62.67         60.85         103.31   

S&P Smallcap 600

     100.00         91.84         84.99         85.33         84.60         63.30         52.64         63.73         75.62         79.49         86.33         78.79         86.37         100.40   

Custom Composite

     100.00         127.81         120.67         220.88         100.33         50.58         48.19         63.21         83.08         97.81         99.87         77.04         93.16         128.28   

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 we specifically request that the information be treated as soliciting material or specifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.

 

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Item 6. Selected Consolidated Financial Data.

The following table presents selected financial and other data 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 and 2006. For periods prior to the spin-off, the historical consolidated statements of operations 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 of the acquisition, 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, 2010 and the consolidated balance sheet data as of December 31, 2010 and 2009 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, 2008, 2007 and 2006 and the consolidated statements of operations for the year ended December 31, 2007 and 2006 were derived from audited consolidated financial statements that are not presented in this report.

 

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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 and 2006 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.

 

     Year Ended December 31,  
     2010     2009     2008     2007     2006  
     (In thousands, except for share and per share data)  

Results of Operations Data:

          

Revenues

          

Sales

   $ 2,017,464      $ 1,995,667      $ 1,630,873      $ 1,069,316      $ 1,142,521   

Other revenues

     17,647        49,616        23,749        4,046        5,398   
                                        

Total revenues

     2,035,111        2,045,283        1,654,622        1,073,362        1,147,919   

Costs and expenses

          

Operating costs and expenses

     1,900,704        1,893,419        1,607,746        1,109,315        1,051,932   

Depreciation, depletion and amortization

     188,074        205,339        125,356        85,640        86,458   

Reclamation and remediation obligation expense

     63,034        35,116        19,260        20,144        24,282   

Sales contract accretion

     (121,475     (298,572     (279,402     —          —     

Restructuring and impairment charge

     15,174        20,157        —          —          —     

Selling and administrative expenses

     50,248        48,732        38,607        45,137        47,909   

Other operating (income) expense:

          

Net gain on disposal or exchange of assets(1)

     (48,226     (7,215     (7,004     (81,458     (78,631

Loss (income) from equity affiliates(2)

     (9,476     (398     915        (63     (60
                                        

Operating profit (loss)

     (2,946     148,705        149,144        (105,353     16,029   

Interest expense

     57,419        38,108        23,648        8,337        11,419   

Interest income

     (12,831     (16,646     (17,232     (11,543     (1,417
                                        

Income (loss) before income taxes

     (47,534     127,243        142,728        (102,147     6,027   

Income tax provision

     492        —          —          —          8,350   
                                        

Net income (loss)

     (48,026     127,243        142,728        (102,147     (2,323

Net income attributable to noncontrolling interest(2)

     —          —          —          4,721        11,169   
                                        

Net income (loss) attributable to Patriot

     (48,026     127,243        142,728        (106,868     (13,492

Effect of noncontrolling interest purchase arrangement

     —          —          —          (15,667     —     
                                        

Net income (loss) attributable to common stockholders

   $ (48,026   $ 127,243      $ 142,728      $ (122,535   $ (13,492
                                        

Earnings (loss) per share, basic

   $ (0.53   $ 1.50      $ 2.23      $ (2.29     N/A   

Earnings (loss) per share, diluted

   $ (0.53   $ 1.49      $ 2.21      $ (2.29     N/A   

Weighted average shares outstanding - basic

     90,907,264        84,660,998        64,080,998        53,511,478        N/A   

Weighted average shares outstanding - diluted

     90,907,264        85,424,502        64,625,911        53,546,116        N/A   

Balance Sheet Data (at period end):

          

Total assets

   $ 3,810,036      $ 3,618,163      $ 3,622,320      $ 1,199,837      $ 1,178,181   

Total liabilities(3)

     2,966,955        2,682,669        2,782,139        1,117,521        1,851,855   

Total long-term debt, less current maturities

     451,529        197,951        176,123        11,438        20,722   

Total stockholders’ equity (deficit)

     843,081        935,494        840,181        82,316        (673,674

 

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     Year Ended December 31,  
     2010     2009     2008     2007     2006  
     (In thousands, except for share and per share data)  

Other Data:

          

Tons sold (in millions and unaudited)

     30.9        32.8        28.5        22.1        24.3   

Net cash provided by (used in):

          

Operating activities

   $ 36,311      $ 39,611      $ 63,426      $ (79,699   $ (20,741

Investing activities

     (109,933     (77,593     (138,665     54,721        1,993   

Financing activities

     239,591        62,208        72,128        30,563        18,627   

Adjusted EBITDA(4) (unaudited)

     141,861        110,745        44,238        431        126,769   

Past mining obligation payments(5) (unaudited)

     128,712        129,060        101,746        144,811        150,672   

Additions to property, plant, equipment and mine development

     122,989        78,263        121,388        55,594        80,224   

Acquisitions, net

     —          —          9,566        47,733        44,538   

 

(1)

Net gain on disposal or exchange of assets included gains of $44.6 million in 2010 from five coal reserve exchange transactions, a $78.5 million gain in 2007 from the sales of coal reserves and surface land and gains of $66.6 million in 2006 from sales of coal reserves and surface land.

 

(2)

In 2008, we acquired 49% interests in two joint ventures designed to produce high quality metallurgical coal. These investments began to generate significant income in 2010, as the related mining properties increase production. In March 2006, we increased our 49% interest in KE Ventures, LLC to an effective 73.9% interest and began combining KE Ventures, LLC’s results with ours effective January 1, 2006. In 2007, we purchased the remaining interest. Prior to 2006, KE Ventures, LLC was accounted for on an equity basis and included in income from equity affiliates in our consolidated statements of operations.

 

(3)

On December 31, 2006, we increased noncurrent liabilities and decreased total invested capital (accumulated other comprehensive loss) by $322.1 million as a result of a then newly adopted authoritative accounting guidance related to employers accounting for postretirement benefit plans.

 

(4)

Adjusted EBITDA as calculated below is defined as net income (loss) before deducting interest income and expense; income taxes; reclamation and remediation obligation expense; depreciation, depletion and amortization; restructuring and impairment charge; and net sales contract accretion. Net sales contract accretion represents contract accretion excluding back-to-back coal purchase and sales contracts. The contract accretion on the back-to-back coal purchase and sales contracts reflects the accretion related to certain coal purchase and sales contracts existing prior to July 23, 2008, whereby Magnum purchased coal from third parties to fulfill tonnage commitments on sales contracts. Adjusted EBITDA is used by management as a measure of our segments’ operating performance. The term Adjusted EBITDA does not purport to be an alternative to operating income, net income or cash flows from operating activities as determined in accordance with generally accepted accounting principles as a measure of profitability or liquidity. We believe that in our industry such information is a relevant measurement of a company’s operating financial performance. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.

 

(5)

Past mining obligation payments represents cash payments relating to our postretirement benefit plans, work-related injuries and illnesses obligations and multi-employer retiree healthcare and pension plans.

 

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Adjusted EBITDA is calculated as follows (unaudited):

 

     Year Ended December 31,  
     2010     2009     2008     2007     2006  
     (In thousands)  

Net income (loss)

   $ (48,026   $ 127,243      $ 142,728      $ (102,147   $ (2,323

Depreciation, depletion and amortization

     188,074        205,339        125,356        85,640        86,458   

Sales contract accretion, net(1)

     (121,475     (298,572     (249,522     —          —     

Reclamation and remediation obligation expense

     63,034        35,116        19,260        20,144        24,282   

Restructuring and impairment charge

     15,174        20,157        —          —          —     

Interest expense

     57,419        38,108        23,648        8,337        11,419   

Interest income

     (12,831     (16,646     (17,232     (11,543     (1,417

Income tax provision

     492        —          —          —          8,350   
                                        

Adjusted EBITDA

   $ 141,861      $ 110,745      $ 44,238      $ 431      $ 126,769   
                                        

 

(1)

Net sales contract accretion resulted from the below market coal sales and purchase contracts acquired in the Magnum acquisition that were recorded at fair value in purchase accounting. The net liability generated from applying fair value to these contracts is being accreted over the life of the contracts as the coal is shipped.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

We are a leading producer of thermal coal in the eastern U.S., with operations and coal reserves in the Appalachia and the Illinois Basin coal regions. We are also a leading U.S. producer of metallurgical quality coal. Our principal business is the mining and preparation of thermal coal, for sale primarily to electricity generators, and metallurgical coal, for sale to steel mills and independent coke producers. Our operations consist of fourteen active mining complexes, which include company-operated mines, contractor-operated mines and coal preparation facilities. The Appalachia and Illinois Basin segments consist of our operations in West Virginia and Kentucky, respectively.

We ship coal to electricity generators, industrial users, steel mills and independent coke producers. In 2010, we sold 30.9 million tons of coal, of which 78% was sold to domestic electricity generators and 22% was sold to domestic and global steel producers. In 2009, we sold 32.8 million tons of coal, of which 83% was sold to domestic electricity generators and 17% was sold to domestic and global steel producers. Coal is shipped via various company-owned and third-party loading facilities, multiple rail and river transportation routes and ocean-going vessels.

We typically sell coal to utility and steel-making customers under contracts with terms of one year or more. Approximately 77% and 83% of our sales were under such contracts during 2010 and 2009, respectively.

Effective October 31, 2007, Patriot was spun off from Peabody. The spin-off was accomplished through a dividend of all outstanding shares of Patriot, resulting in Patriot becoming a separate, public company traded on the New York Stock Exchange (symbol PCX).

On July 23, 2008, Patriot completed the acquisition of Magnum. Magnum was one of the largest coal producers in Appalachia, operating eight mining complexes with production from surface and underground mines and controlling more than 600 million tons of proven and probable coal reserves. Magnum’s results are included as of the date of the acquisition.

 

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Results of Operations

Segment Adjusted EBITDA

The discussion of our results of operations below includes references to and analysis of our Appalachia and Illinois Basin Segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as net income (loss) before deducting interest income and expense; income taxes; reclamation and remediation obligation expense; depreciation, depletion and amortization; restructuring and impairment charge; and net sales contract accretion. Net sales contract accretion represents contract accretion excluding back-to-back coal purchase and sales contracts. The contract accretion on the back-to-back coal purchase and sales contracts reflects the accretion related to certain coal purchase and sales contracts existing prior to July 23, 2008, whereby Magnum purchased coal from third parties to fulfill tonnage commitments on sales contracts.

Adjusted EBITDA is used by management as a measure of our segments’ operating performance. We believe that in our industry such information is a relevant measurement of a company’s operating financial performance. Because Adjusted EBITDA and Segment Adjusted EBITDA are not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Segment Adjusted EBITDA is calculated the same as Adjusted EBITDA but also excludes selling, general and administrative expenses, past mining obligation expense and gain on disposal or exchange of assets and is reconciled to its most comparable measure below, under Net Income (Loss). Adjusted EBITDA is reconciled to its most comparable measure under generally accepted accounting principles in Item 6. Selected Consolidated Financial Data.

Geologic Conditions

Our results of operations are impacted by geologic conditions as they relate to coal mining. These conditions refer to the physical nature of the coal seam and surrounding strata and its effect on the mining process. Geologic conditions that can have an adverse effect on underground mining include thinning coal seam thickness, rock partings within a coal seam, weak roof or floor rock, sandstone channel intrusions, groundwater and increased stresses within the surrounding rock mass due to over mining, under mining and overburden changes. The term “adverse geologic conditions” is used in general to refer to these and similar situations where the geologic setting can negatively affect the normal mining process. Adverse geologic conditions would be markedly different from those that would be considered typical geologic conditions for a given mine. Since approximately 71% of our 2010 production was sourced from underground operations, geologic conditions can be a major factor in our results of operations.

Year ended December 31, 2010 compared to year ended December 31, 2009

Summary

Our Segment Adjusted EBITDA for the year ended December 31, 2010 increased compared to the prior year primarily due to higher average sales prices and cost savings resulting from the suspension of certain higher cost mining operations in 2009. In 2009, we implemented a strategic response to the then weakened coal markets. As a result, we suspended certain mining operations, which in certain circumstances remained suspended throughout 2010. The increase in Segment Adjusted EBITDA was partially offset by decreased sales volumes during 2010. Sales volume decreases in 2010 resulted from the closure of the Harris No. 1 mine in June 2010, and certain 2009 mine suspensions, lower production due to more employee time spent with regulators related to inspections at certain of our mines, as well as roof falls at the Harris and Highland mines. While increased employee time spent on inspections resulted in lower production, these inspections did not result in increased citations. Due to the nature of our business, we incur a significant amount of fixed costs and, therefore, lower sales volumes contributed to a higher cost per ton.

In June 2010, we announced the closure of the Harris No. 1 mine due to the roof fall on the primary conveyor belt, adverse geologic conditions in the travel entries of the mine and employee safety concerns. The Harris No. 1 mine was nearing the end of its projected mining life and was scheduled for closure in 2011. We recorded a restructuring and impairment charge related to the closure of the Harris No. 1 mine and further rationalization of our operations at the Rocklick mining complex.

Our Panther and Federal mining complexes both had major longwall moves and related downtime in 2010. Our Federal longwall was idled for almost two weeks in September as a result of MSHA enforcement actions that were subsequently vacated. Previously, our Federal mine had temporarily suspended active mining operations in late February 2010, upon discovering potentially adverse atmospheric conditions in an abandoned area of the mine.

In September 2010, we recorded an adjustment of $20.7 million to reclamation and remediation expense as a result of adjusting our estimated selenium remediation costs of three Apogee outfalls based on the new technologies required to be used for water treatment at certain locations due to the September 1, 2010 court ruling.

 

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Segment Results of Operations

 

     Year Ended December 31,      Increase (Decrease)  
     2010      2009      Tons/$     %  
     (Dollars and tons in thousands, except per ton amounts)  

Tons Sold

          

Appalachia Mining Operations

     24,276         25,850         (1,574     (6.1 )% 

Illinois Basin Mining Operations

     6,588         6,986         (398     (5.7 )% 
                            

Total Tons Sold

     30,864         32,836         (1,972     (6.0 )% 
                            

Average sales price per ton sold

          

Appalachia Mining Operations

   $ 71.73       $ 66.79       $ 4.94        7.4

Illinois Basin Mining Operations

     41.90         38.52         3.38        8.8

Revenue

          

Appalachia Mining Operations

   $ 1,741,430       $ 1,726,588       $ 14,842        0.9

Illinois Basin Mining Operations

     276,034         269,079         6,955        2.6

Appalachia Other

     17,647         49,616         (31,969     (64.4 )% 
                            

Total Revenues

   $ 2,035,111       $ 2,045,283       $ (10,172     (0.5 )% 
                            

Segment Operating Costs and Expenses(1)

          

Appalachia Mining Operations and Other

   $ 1,442,753       $ 1,481,831       $ (39,078     (2.6 )% 

Illinois Basin Mining Operations

     274,739         260,529         14,210        5.5
                            

Total Segment Operating Costs and Expenses

   $ 1,717,492       $ 1,742,360       $ (24,868     (1.4 )% 
                            

Segment Adjusted EBITDA

          

Appalachia Mining Operations and Other

   $ 316,324       $ 294,373       $ 21,951        7.5

Illinois Basin Mining Operations

     1,295         8,550         (7,255     (84.9 )% 
                            

Total Segment Adjusted EBITDA

   $ 317,619       $ 302,923       $ 14,696        4.9
                            

 

(1)

Segment Operating Costs and Expenses represent consolidated operating costs and expenses of $1,900.7 million and $1,893.4 million less income from equity affiliates of $9.5 million and $0.4 million and past mining obligation expense of $173.7 million and $150.7 million for the years ended December 31, 2010 and 2009, respectively, as described below.

Tons Sold and Revenues

Revenues in the Appalachia segment were higher for the year ended December 31, 2010 compared to the prior year primarily due to higher average sales prices for both thermal and metallurgical coal during 2010. The higher average sales prices were driven largely by increased metallurgical coal sales volume as a result of our Panther and Winchester mines product being sold on the metallurgical market rather than the thermal market during 2010. These increases were partially offset by lower sales volumes related to the 2009 suspension of various mines, which in certain circumstances remained suspended throughout 2010, such as the Samples mine.

Revenues in the Illinois Basin segment were higher for the year ended December 31, 2010 as compared to the same period in 2009 primarily due to higher average sales prices, partially offset by decreased sales volumes. Decreased sales volumes resulted from lower production caused by difficult geologic conditions including roof falls at our Highland mine during 2010 and shifting to new mine sections at our Bluegrass mining complex. In addition, more employee time has been spent with regulators related to inspections throughout 2010, particularly at Highland, which impacted production volumes.

Appalachia Other revenue was lower for the year ended December 31, 2010 primarily due to cash settlements received for reduced shipments in 2009 as a result of renegotiated customer agreements.

Segment Operating Costs and Expenses

Segment operating costs and expenses for Appalachia for the year ended December 31, 2010 decreased as compared to the prior year. In relation to the closing or idling of certain mines and the reduction in utilization of one of our preparation plants in the second half of 2009, we had decreased contract mining costs ($21.1 million), labor costs ($19.0 million) and fuel and explosives, taxes, lease and royalty expenses ($23.0 million) during 2010. These decreases were partially offset by increased purchased coal ($33.8 million). The increased purchased coal costs included purchases of thermal coal to cover certain thermal sales commitments at our Panther and Winchester mines, where production is now being sold as a metallurgical product. Operating costs and expenses also benefited in 2010 from an increase in income from equity affiliates ($9.4 million) as compared to the prior year. Patriot established two separate joint ventures in 2008 designed to produce high quality metallurgical coal. These investments are beginning to generate more income, as the related mining properties continue to increase production.

 

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Segment operating costs and expenses for the Illinois Basin increased for the year ended December 31, 2010 as compared to the prior year due to increased labor as a result of additional shifts and higher wages ($4.7 million), increased fuel and explosives expense primarily related to higher costs ($4.1 million) and additional repairs and maintenance activity ($3.5 million). Higher repair and maintenance costs related to additional belting repairs and roof bolting, as well as equipment maintenance. Costs were also negatively impacted by several roof falls at our Highland mine and heightened regulatory inspections throughout most of 2010.

Segment Adjusted EBITDA

Our Segment Adjusted EBITDA for Appalachia was higher for the year ended December 31, 2010 compared to the prior year primarily due to higher average sales prices and lower costs resulting from suspended or reduced production at certain mining operations, in particular some of our higher cost operations, in response to the economic recession experienced throughout 2009. These increases were partially offset by decreased sales volumes in 2010 and a decrease in non-recurring settlements from renegotiated customer agreements as compared to 2009.

Segment Adjusted EBITDA for the Illinois Basin decreased for the year ended December 31, 2010 from the prior year primarily due to higher operating costs.

Net Income (Loss)

 

     Year Ended December 31,     Favorable/
(Unfavorable)
 
     2010     2009     $     %  
     (Dollars in thousands)  

Segment Adjusted EBITDA

   $ 317,619      $ 302,923      $ 14,696        4.9

Corporate and Other:

        

Past mining obligation expense

     (173,736     (150,661     (23,075     (15.3 )% 

Net gain on disposal or exchange of assets

     48,226        7,215        41,011        568.4

Selling and administrative expenses

     (50,248     (48,732     (1,516     (3.1 )% 
                          

Total Corporate and Other

     (175,758     (192,178     16,420        8.5

Depreciation, depletion and amortization

     (188,074     (205,339     17,265        8.4

Reclamation and remediation obligation expense

     (63,034     (35,116     (27,918     (79.5 )% 

Sales contract accretion

     121,475        298,572        (177,097     (59.3 )% 

Restructuring and impairment charge

     (15,174     (20,157     4,983        24.7

Interest expense

     (57,419     (38,108     (19,311     (50.7 )% 

Interest income

     12,831        16,646        (3,815     (22.9 )% 

Income tax provision

     (492     —          (492     N/A   
                          

Net income

   $ (48,026   $ 127,243      $ (175,269     (137.7 )% 
                          

Past Mining Obligation Expense

Past mining obligation expenses were higher in 2010 than the prior year primarily due to changes in assumptions related to our actuarially-determined liabilities for retiree healthcare and workers’ compensation obligations ($28 million), with approximately one-half of the cost increase arising from the change to the discount rate. The increase was partially offset by lower costs related to suspended operations. The 2009 results included reduction-in-workforce costs related to suspended mines, primarily Samples.

Net Gain on Disposal or Exchange of Assets

Net gain on disposal or exchange of assets increased for the year ended December 31, 2010 as compared to the prior year. In 2010, net gain on disposal or exchange of assets included a gain of $2.9 million in the fourth quarter, a gain of $3.4 million in the third quarter, gains of $14.3 million on two transactions in the second quarter and a gain of $24.0 million in the first quarter. All of the gains were a result of exchange transactions for mineral interests. In 2009, net gain on disposal or exchange of assets included a $6.6 million gain on the exchange of surface land and coal mineral rights for certain mineral interests from two exchange transactions.

Selling and Administrative Expenses

Selling and administrative expenses increased for the year ended December 31, 2010 as compared to the prior year primarily due to higher incentive compensation expense partially offset by a net decrease in stock-based compensation expense due to a significant forfeiture in the third quarter.

 

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Depreciation, Depletion and Amortization

Depreciation, depletion and amortization decreased for the year ended December 31, 2010 compared to the prior year, primarily due to lower volumes associated with certain mines being closed or suspended in the second half of 2009 and due to the full depreciation of a significant number of assets associated with our 2008 Magnum acquisition. These decreases were partially offset by increased depreciation at our Blue Creek complex, which began operations in December 2009.

Reclamation and Remediation Obligation Expense

Reclamation and remediation obligation expense increased for the year ended December 31, 2010 primarily due to remediation expense related to the selenium liability assumed in the July 2008 Magnum acquisition, which was recorded at fair value upon finalization of purchase accounting in June 2009. Additional remediation expense of $20.7 million was recorded in the third quarter of 2010 as a result of adjusting our estimated future costs of selenium remediation at certain outfalls resulting from requirements of the September 1, 2010 court ruling. See Liquidity and Capital Resources – September 1, 2010 U.S. District Court Ruling for further description of the ruling and the adjustments.

Sales Contract Accretion

Sales contract accretion decreased for the year ended December 31, 2010 as compared to the prior year due to certain contracts assumed in the Magnum acquisition expiring in 2009.

Restructuring and Impairment Charge

In the second quarter of 2010, we recorded a $14.8 million restructuring and impairment charge related to the June 2010 closure of the Harris No. 1 mine, resulting from adverse geologic conditions, and further rationalization of our operations at the Rocklick mining complex based on this early closure. The charge included a $2.8 million impairment charge related to equipment and coal reserves that were abandoned due to the mine closure and a restructuring component of $12.0 million for payment of obligations that will be made with no future economic benefit for remaining operational contracts. For the year ended December 31, 2009, we incurred a $12.9 million impairment charge related to certain infrastructure and thermal coal reserves near our Rocklick complex that were deemed uneconomical to mine, as well as a $7.3 million restructuring charge related to the discontinued use of a beltline into the Rocklick preparation plant during the fourth quarter of 2009.

Interest Expense

Interest expense increased for the year ended December 31, 2010 primarily due to the $250 million of Senior Notes issued on May 5, 2010 as well as the increased amortization of deferred financing costs related to the new notes, accounts receivable securitization program entered into in March 2010, and the amended and restated credit agreement entered into in May 2010. In addition, we incurred additional interest expense in 2010 due to the Blue Creek preparation plant capital lease that began in May 2009.

Interest Income

Interest income decreased for the year ended December 31, 2010 compared to the prior year due to the collection of certain Black Lung excise tax refunds and related interest during 2009.

Income Tax Provision

For the year ended December 31, 2010, we recorded an income tax provision of $0.5 million related to certain state taxes. For the year ended December 31, 2009, no income tax provision was recorded. No federal income tax provision was recorded in 2010 or 2009 due to our tax net operating loss for each respective year and the full valuation allowance recorded against deferred tax assets. The primary difference between book and taxable income for 2010 and 2009 was the treatment of the net sales contract accretion on the below market purchase and sales contracts acquired in the July 2008 Magnum acquisition, with such amounts being included in the computation of book income but excluded from the computation of taxable income.

Year ended December 31, 2009 compared to year ended December 31, 2008

Summary

Revenues were $2,045.3 million, an increase of $390.7 million, and Segment Adjusted EBITDA was $302.9 million, an increase of $116.8 million, for the year ended December 31, 2009. The increase in revenue and Segment Adjusted EBITDA resulted from the addition of Magnum, the successful implementation of our Management Action Plan and improved performance at our longwall mines.

Beginning in the third quarter of 2008, the global recession resulted in decreased worldwide demand for steel and electricity, leading to weakened coal markets. Early in 2009, we implemented a Management Action Plan as a strategic response to the weakened coal markets. The Management Action Plan included output and cost reductions, workforce and capital redeployment and sales contract renegotiations. As a result of this plan, during 2009 we suspended certain company-operated and contract mines, including suspension of operations at our Samples surface mine, deferred production start up at one newly-developed mining complex and cancelled certain operating shifts at various other mining complexes. Additionally, we restructured certain below-market legacy coal supply agreements.

 

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Our 2009 results reflect the inclusion of a full year of the Magnum operations, which were acquired on July 23, 2008. The increased revenue from the acquired Magnum operations was partially offset by lower customer demand throughout the year and increased customer deferrals during 2009.

Both our Federal and Panther longwalls encountered some adverse geologic conditions in 2009, but significantly less than the difficulties encountered in 2008. The improved production in 2009 reflects the benefits of mine plan adjustments made in late 2008 to minimize the impact of difficult geology. In the third quarter of 2009, significant upgrades were made to certain components of the Panther longwall mining equipment. Both of the longwalls were performing well by the end of 2009. In the fourth quarter of 2009, Federal had its best production quarter in 2009 and Panther had its best quarter since the Magnum acquisition.

Segment Results of Operations

 

     Year Ended December 31,      Increase (Decrease)  
     2009      2008      Tons/$     %  
     (Dollars and tons in thousands, except per ton amounts)  

Tons Sold

          

Appalachia Mining Operations

     25,850         20,654         5,196        25.2

Illinois Basin Mining Operations

     6,986         7,866         (880     (11.2 )% 
                            

Total Tons Sold

     32,836         28,520         4,316        15.1
                            

Average sales price per ton sold

          

Appalachia Mining Operations

   $ 66.79       $ 65.23       $ 1.56        2.4

Illinois Basin Mining Operations

     38.52         36.06         2.46        6.8

Revenue

          

Appalachia Mining Operations

   $ 1,726,588       $ 1,347,230       $ 379,358        28.2

Illinois Basin Mining Operations

     269,079         283,643         (14,564     (5.1 )% 

Appalachia Other

     49,616         23,749         25,867        108.9
                            

Total Revenues

   $ 2,045,283       $ 1,654,622       $ 390,661        23.6
                            

Segment Operating Costs and Expenses(1)

          

Appalachia Mining Operations and Other

   $ 1,481,831       $ 1,197,985       $ 283,846        23.7

Illinois Basin Mining Operations

     260,529         270,488         (9,959     (3.7 )% 
                            

Total Segment Operating Costs and Expenses

   $ 1,742,360       $ 1,468,473       $ 273,887        18.7
                            

Segment Adjusted EBITDA

          

Appalachia Mining Operations and Other

   $ 294,373       $ 172,994       $ 121,379        70.2

Illinois Basin Mining Operations

     8,550         13,155         (4,605     (35.0 )% 
                            

Total Segment Adjusted EBITDA

   $ 302,923       $ 186,149       $ 116,774        62.7
                            

 

(1)

Segment Operating Costs and Expenses represent consolidated operating costs and expenses of $1,893.4 million and $1,607.7 million less income from equity affiliates of $0.4 million for the year ended December 31, 2009, plus loss from equity affiliates of $0.9 million for the year ended December 31, 2008, less past mining obligation expense of $150.7 million and $110.3 million for the years ended December 31, 2009 and 2008, respectively, as described below, and less back-to-back contract accretion of $29.9 million for the year ended December 31, 2008.

Tons Sold and Revenues

The increase in Appalachia revenue for the year ended December 31, 2009 compared to the prior year primarily related to the $318.8 million net increase in revenues from the acquired Magnum operations, due to an additional seven months of activity during 2009, as well as higher sales prices at certain complexes. These increases were partially offset by lower customer demand and increased customer deferrals.

Sales volumes in the Appalachia segment increased in 2009, primarily from the incremental 5.9 million tons sold from the acquired Magnum operations, partially offset by the overall decline in customer demand for both metallurgical and thermal coal including lower sales due to customer shipment deferrals and settlements. The overall decline in customer demand led to the suspension of certain operations and decreased operating shifts at other operations.

Illinois Basin revenue decreased slightly in 2009 compared to the prior year primarily due to lower sales volume caused by lower customer demand, unfavorable weather conditions early in the year and increased downtime due to regulatory inspections. Lower sales volumes were partially offset by higher average sales prices.

 

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Appalachia Other Revenue was higher in 2009 primarily due to cash settlements received for reduced shipments as a result of renegotiated customer agreements. In addition to royalty income, Appalachia Other Revenue in 2008 included a structured settlement on a property transaction, a settlement for past due coal royalties which had previously been fully reserved due to the uncertainty of collection, and gains on the sale of purchased coal in the first quarter.

Segment Operating Costs and Expenses

Segment operating costs and expenses represent consolidated operating costs and expenses less past mining obligations.

Segment operating costs and expenses for Appalachia increased in 2009 as compared to the prior year primarily due to the incremental $278.9 million of costs for the full year of the acquired Magnum operations. Excluding the impact of Magnum, operating costs were higher due to increased purchased coal ($12.8 million) and increased materials and supplies costs primarily related to equipment rebuilds at various locations ($8.7 million). We purchased coal to cover certain sales commitments at some of our suspended operations. The increased costs were partially offset by decreased labor costs primarily due to reduced shifts and mine suspensions as a result of lower customer demand ($10.6 million) and lower royalties resulting from decreased production at certain mines ($7.1 million).

Operating costs and expenses for Illinois Basin decreased in 2009 as compared to the prior year primarily due to decreased costs for purchased coal ($9.6 million) and lower diesel fuel and explosives costs ($6.5 million). In 2008, higher priced spot sale opportunities were available which resulted in more purchased coal to fulfill sales commitments. The decreased costs were partially offset by higher repair and maintenance and outside services costs primarily due to major non-recurring repairs including equipment rebuilds, belting and component upgrades ($7.8 million).

Segment Adjusted EBITDA

Segment Adjusted EBITDA for Appalachia increased in 2009 from the prior year primarily due to the contribution from the additional volume associated with the acquired Magnum operations. Additionally, during 2009, we received cash settlements for reduced shipments. These cash settlements approximated the financial impact associated with cancelled customer commitments.

Segment Adjusted EBITDA for the Illinois Basin decreased in 2009 primarily due to lower production volumes attributable to lower customer demand and severe winter storms. This decrease also reflected higher repair and maintenance and outside services costs that were primarily due to major non-recurring repairs including equipment rebuilds, belting and component upgrades. These decreases were partially offset by higher average sales prices and lower diesel fuel and explosives costs.

Net Income

 

     Year Ended December 31,     Favorable/(Unfavorable)  
     2009     2008     $     %  
     (Dollars in thousands)  

Segment Adjusted EBITDA

   $ 302,923      $ 186,149      $ 116,774        62.7

Corporate and Other:

        

Past mining obligation expense

     (150,661     (110,308     (40,353     (36.6 )% 

Net gain on disposal or exchange of assets

     7,215        7,004        211        3.0

Selling and administrative expenses

     (48,732     (38,607     (10,125     (26.2 )% 
                          

Total Corporate and Other

     (192,178     (141,911     (50,267     (35.4 )% 

Depreciation, depletion and amortization

     (205,339     (125,356     (79,983     (63.8 )% 

Reclamation and remediation obligation expense

     (35,116     (19,260     (15,856     (82.3 )% 

Sales contract accretion, net

     298,572        249,522        49,050        19.7

Restructuring and impairment charge

     (20,157     —          (20,157     N/A   

Interest expense

     (38,108     (23,648     (14,460     (61.1 )% 

Interest income

     16,646        17,232        (586     (3.4 )% 
                          

Net income

   $ 127,243      $ 142,728      $ (15,485     (10.8 )% 
                          

Past Mining Obligation Expense

Past mining obligation expenses were higher in 2009 than the prior year primarily due to a full year of retiree healthcare obligation expenses ($24.4 million) and multi-employer retiree healthcare and pension costs ($5.8 million) from the acquired Magnum operations in 2009 versus only five months in 2008; costs related to suspended mines ($9.9 million), primarily Samples; and higher subsidence expense. These increases were partially offset by lower spending at our closed locations ($2.6 million).

 

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Selling and Administrative Expenses

Selling and administrative expenses for the year ended December 31, 2009 increased compared to the prior year primarily due to increased headcount and expenses due to the addition and integration of Magnum operations, which were acquired July 23, 2008.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for 2009 increased compared to the prior year primarily due to the full year impact from the addition of the Magnum assets.

Reclamation and Remediation Obligation Expense

Reclamation and remediation obligation expense increased in 2009 as compared to the prior year primarily due to the full year impact from the acquisition of Magnum.

Sales Contract Accretion

Sales contract accretion resulted from the below market coal sale and purchase contracts acquired in the Magnum acquisition and recorded at fair value in purchase accounting. The net liability generated from applying fair value to these contracts is being accreted over the life of the contracts as the coal is shipped.

Restructuring and Impairment Charge

The restructuring and impairment charge in 2009 related to certain infrastructure and thermal coal reserves near our Rocklick complex that were deemed uneconomical to mine, as well as a restructuring charge related to the discontinued use of a beltline into the Rocklick preparation plant during the fourth quarter.

Interest Expense

Interest expense increased for 2009 compared to the prior year primarily due to interest and debt discount expense related to our convertible notes that were issued in May 2008 and higher letter of credit fees related to the Magnum acquisition. This increase was partially offset by the commitment fee expensed due to the termination of a bridge loan facility related to our assumption of Magnum’s debt during the second quarter of 2008. See Liquidity and Capital Resources for details concerning our outstanding debt and credit facility.

Income Tax Provision

For the years ended December 31, 2009 and 2008, no income tax provision was recorded due to net operating losses for the year and our full valuation allowance recorded against deferred tax assets. For 2009 and 2008, the primary difference between book and taxable income was the treatment of the net sales contract accretion on the below market purchase and sales contracts acquired in the Magnum acquisition, with such amounts being included in the computation of book income but excluded from the computation of taxable income.

Outlook

Market

Metallurgical coal markets are showing continued strength. We anticipate that the metallurgical coal market will remain strong throughout 2011, given the expectation for continued growth in economies around the world. Recent weather conditions, such as the extreme rain in Australia, have made the markets even tighter. We believe this constrained supply is setting the stage for higher pricing in 2011. We believe this structural shortage in metallurgical coal will continue for at least the next few years. This shortage is a result of limited supply in established coal basins, coupled with long lead-times to bring on significant production in new basins.

In thermal coal markets, key indicators are favorable. In the seaborne thermal market, the forward price for coal delivered during 2011 into northern Europe has increased approximately $15 per metric tonne from the end of October 2010 to February 2011. As a result, Appalachia and Illinois Basin thermal coal can now frequently be sold into the European market at more favorable margins than if sold domestically. We believe this is an indication of the continuing globalization of thermal markets, following the same pattern as metallurgical markets in recent years. In late 2010 and early 2011, we entered into contracts to export nearly one million tons of thermal coal to Europe in 2011 including shipments from all three of the basins where we operate.

The global increase in metallurgical and thermal coal demand is occurring while the Western economies have not yet fully rebounded. Moving forward, it is unclear how worldwide coal supply will keep pace with demand.

 

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Patriot Operations

As discussed more fully under Item 1A. Risk Factors, our results of operations in the near-term could be negatively impacted by price volatility and demand; unforeseen adverse geologic conditions or equipment problems at mining locations; changes in general economic conditions; changes in the interpretation, enforcement or application of existing and potential coal mining laws and regulations; availability and the costs of competing energy resources; the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs, or limit our customers’ ability to utilize coal as fuel for electricity generation; existing or new environmental laws and regulations, including selenium-related matters, and the interpretation or enforcement thereof; negotiation of labor contracts, labor availability and relations; the outcome of pending or future litigation; changes in the costs to provide healthcare to eligible active employees and certain retirees under postretirement benefit obligations and contribution requirements to multi-employer retiree healthcare and pension plans; reductions of purchases or deferral of deliveries by major customers; the availability and costs of credit, surety bonds and letters of credit; customer performance and credit risks; supplier and contract miner performance and the unavailability of transportation for coal shipments.

On a long-term basis, our results of operations could also be impacted by our ability to secure or acquire high-quality coal reserves; our ability to attract and retain skilled employees and contract miners; our ability to find replacement buyers for coal under contracts with comparable terms to existing contracts; and fluctuating prices of key supplies, mining equipment and commodities. Additionally, our cost to provide healthcare to eligible active employees and certain retirees could increase due to the 2010 healthcare legislation.

Potential legislation, regulation, treaties and accords at the local, state, federal and international level, and changes in the interpretation, enforcement or application of existing laws and regulations, have created uncertainty and could have a significant impact on demand for coal and our future operational and financial results. For example, increased scrutiny of mining could make it difficult to receive permits or could otherwise cause production delays in the future. The lack of proven technology to meet selenium discharge standards creates uncertainty as to the future costs of water treatment to comply with mining permits, which may be materially different from our current estimates. Additionally, future regulation of carbon dioxide and other greenhouse gas emissions and coal combustion by-products could have an adverse effect on the financial condition of our customers and significantly impact the demand for coal. See Item 1A. Risk Factors for expanded discussion of these factors.

If upward pressure on costs exceeds our ability to realize revenue increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. Management continues to focus on controlling costs, optimizing performance and responding quickly to market changes. Increased scrutiny by regulators has resulted in more comprehensive inspections which has caused decreased production and increased costs. We expect this heightened regulatory oversight to continue.

We have developed detailed organic growth plans based on our extensive coal reserve base. In response to what we believe will be sustained strength in the metallurgical coal market, we plan to increase our metallurgical coal production to 8 million tons in 2011, 9 million tons in 2012 and more than 11 million tons by 2013. We are planning to open a number of new metallurgical coal mines in the next two years. While output from some of these mines will replace existing production from mines nearing the end of their reserves, the majority of this expansion amounts to incremental metallurgical volume.

We expect to begin production in 2011 and 2012 from organic projects at the Rocklick, Wells, Kanawha Eagle and Logan County mining complexes. Annual production at each of these new mines is expected to be between 200,000 and 750,000 tons, resulting in a broad spectrum of coal qualities available from these expansions. These expansions should be accomplished with a very reasonable capital outlay because they will be adding volume to existing preparation plant and loadout facilities.

We anticipate 2011 sales volume in the range of 30 to 32 million tons. This includes metallurgical coal sales of 8.0 to 8.4 million tons, a significant increase over the 6.9 million tons sold in 2010. As of December 31, 2010, our total unpriced planned production was 5 to 7 million tons.

The guidance provided under the caption Outlook should be read in conjunction with the section entitled Cautionary Notice Regarding Forward Looking Statements on page 2 and Item 1A. Risk Factors. Actual events and results may vary significantly from those included in, or contemplated, or implied by the forward-looking statements under Outlook. For additional information regarding the risks and uncertainties that affect our business, see Item 1A. Risk Factors.

 

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Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

Employee-Related Liabilities

We have significant long-term liabilities for our employees’ postretirement benefit costs and workers’ compensation obligations. Detailed information related to these liabilities is included in Notes 20 and 22 to our consolidated financial statements. Expense for the year ended December 31, 2010 for these liabilities totaled $155.4 million, while payments were $91.7 million.

Postretirement benefits and certain components of our workers’ compensation obligations are actuarially determined, and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for these items. The discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service our liabilities. We make assumptions related to future trends for medical care costs in the estimates of retiree healthcare and work-related injuries and illness obligations. Our medical trend assumption is developed by annually examining the historical trend of our cost per claim data.

If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our obligation to satisfy these or additional obligations. Our most significant employee liability is postretirement healthcare. Assumed discount rates and healthcare cost trend rates have a significant effect on the expense and liability amounts reported for postretirement healthcare plans. Below we have provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.

Healthcare cost trend rate:

 

     +1.0%      -1.0%  
     (Dollars in thousands)  

Effect on total service and interest cost components

   $ 11,021       $ (9,390

Effect on (gain)/loss amortization component

     32,313         (27,693

Effect on total postretirement benefit obligation

     175,230         (145,930

Discount rate:

 

     +0.5%     -0.5%  
     (Dollars in thousands)  

Effect on total service and interest cost components

   $ 351      $ (773

Effect on (gain)/loss amortization component

     (9,722     9,960   

Effect on total postretirement benefit obligation

     (79,895     84,981   

Reclamation and Remediation Obligations

Our reclamation obligations primarily consist of spending estimates for surface land reclamation and support facilities at both underground and surface mines in accordance with federal and state reclamation laws as defined by each mining permit. Reclamation obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage, the timing of these cash flows, and a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of the reclamation activities), the obligation and asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities.

 

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Our remediation obligations primarily consist of the estimated liability for water treatment in order to comply with selenium effluent limits included in certain mining permits. This liability reflects the discounted estimated costs of the treatment systems to be installed and maintained with the goal of meeting the requirements of current court orders, consent decrees and mining permits. This estimate was prepared considering the dynamics of current legislation, capabilities of currently available technology and our planned remediation strategy. The exact amount of our assumed liability is uncertain due to the fact there is no proven technology to remediate our existing selenium discharges in excess of allowable limits to meet current permit standards. If technology becomes available that meets permit standards or if the standards change in the future, our actual cash expenditures and costs that we incur could be materially different than currently estimated.

Reclamation and remediation obligation expense for the year ended December 31, 2010, was $63.0 million, and payments totaled $24.3 million. See detailed information regarding our reclamation and remediation obligations in Notes 5, 6, 19 and 25 to our consolidated financial statements.

Income Taxes

Deferred tax assets and liabilities are recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. In addition, deferred tax assets are reduced by a valuation allowance if it is “more likely than not” that some portion or the entire deferred tax asset will not be realized. In our annual evaluation of the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in our annual evaluation of our valuation allowance, we may record a change in valuation allowance through income tax expense in the period this determination is made. As of December 31, 2010 and 2009, we maintained a full valuation allowance against our net deferred tax assets.

Uncertain tax positions taken on previously filed tax returns or expected to be taken on future tax returns are reflected in the measurement of current and deferred taxes. The initial recognition process is a two-step process with a recognition threshold step and a step to measure the benefit. A tax benefit is recognized when it is “more likely than not” of being sustained upon audit based on the merits of the position. The second step is to measure the appropriate amount of the benefit to be recognized based on a best estimate measurement of the maximum amount which is more likely than not to be realized. As of December 31, 2010 and 2009, the unrecognized tax benefits are immaterial, and if recognized would not currently affect our effective tax rate as any recognition would be offset with a valuation allowance. We do not expect any significant increases or decreases to unrecognized tax benefits within twelve months of this reporting date.

Additional detail regarding how we account for income taxes and the effect of income taxes on our consolidated financial statements is available in Note 15.

Revenue Recognition

In general, we recognize revenues when they are realizable and earned. We generated substantially all of our revenues in 2010 from the sale of coal to our customers. Revenues from coal sales are realized and earned when risk of loss passes to the customer. Coal sales are made to our customers under the terms of coal supply agreements, most of which have a term of one year or more. Under the typical terms of these coal supply agreements, risk of loss transfers to the customer at the mine or port, where coal is loaded to the rail, barge, ocean-going vessel, truck or other transportation source that delivers coal to its destination.

With respect to other revenues, other operating income, or gains on disposal or exchange of assets recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and apply the relevant accounting literature as appropriate. We do not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists; delivery has occurred or services have been rendered; the seller’s price to the buyer is fixed or determinable; and collectability is reasonably assured.

Derivatives

We utilize derivative financial instruments to manage exposure to certain commodity prices. We recognize derivative financial instruments at fair value in the consolidated balance sheets. For derivatives that are not designated as hedges, the periodic change in fair value is recorded directly to earnings. For derivative instruments that qualify and are designated by us as cash flow hedges, the periodic change in fair value is recorded to “Accumulated other comprehensive loss” until the contract settles or the relationship ceases to qualify for hedge accounting. In addition, if a portion of the change in fair value for a cash flow hedge is deemed ineffective during a reporting period, the ineffective portion of the change in fair value is recorded directly to earnings. We entered into heating oil swap contracts to manage our exposure to diesel fuel prices. The changes in diesel fuel and heating oil prices are highly correlated, thus allowing the swap contracts to be designated as cash flow hedges.

 

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Share-Based Compensation

We have an equity incentive plan for employees and eligible non-employee directors that allows for the issuance of share-based compensation in the form of restricted stock, incentive stock options, nonqualified stock options, stock appreciation rights, performance awards, restricted stock units and deferred stock units. We utilize the Black-Scholes option pricing model to determine the fair value of stock options and an applicable lattice pricing model to determine the fair value of certain market-based performance awards. Determining the fair value of share-based awards requires judgment, including estimating the expected term that stock options will be outstanding prior to exercise, the associated volatility, and a risk-free interest rate. Judgment is also required in estimating the amount of share-based awards expected to be forfeited prior to vesting. If actual forfeitures differ significantly from these estimates, share-based compensation expense could be materially impacted.

Impairment of Long-Lived Assets

Impairment losses on long-lived assets used in operations are recorded when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those assets under various assumptions are less than the carrying amounts of those assets. Impairment losses are measured by comparing the estimated fair value of the impaired asset to its carrying amount. An impairment charge was recorded in 2010 related to equipment and coal reserves that were abandoned due to the closure of our Harris No. 1 mine. An impairment charge was recorded in 2009 related to certain infrastructure and thermal coal reserves near our Rocklick complex that were deemed uneconomical to mine.

Business Combinations

We account for business acquisitions using the purchase method of accounting. Under this method of accounting, the purchase price is allocated to the fair value of the net assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including, but not limited to, assumptions with respect to future cash flows, discount rates and asset lives.

Liquidity and Capital Resources

Our primary sources of cash include sales of our coal production to customers, sales of non-core assets and financing transactions. Our primary uses of cash include our cash costs of coal production, capital expenditures, interest costs and costs related to past mining obligations as well as acquisitions. Our ability to service our debt (interest and principal) and acquire new productive assets or businesses is dependent upon our ability to continue to generate cash from the primary sources noted above in excess of the primary uses. We expect to fund our capital expenditure requirements with cash generated from operations or borrowed funds as necessary.

Net cash provided by operating activities was $36.3 million for the year ended December 31, 2010, a decrease of $3.3 million compared to the prior year. This decrease in net cash provided by operating activities resulted from an increase in the use of working capital of $8.2 million, offset by improved operating results.

Net cash used in investing activities was $109.9 million for the year ended December 31, 2010, an increase of $32.3 million compared to cash used in investing activities of $77.6 million in the prior year. The increase in cash used reflected higher capital expenditures of $44.7 million, additional advance mining royalties of $4.5 million and a decrease in proceeds from the disposal or exchange of assets of $3.7 million. These increases in cash used were partially offset by higher cash proceeds of $22.1 million from notes receivable related to the 2006 and 2007 sales of coal reserves and surface land.

Net cash provided by financing activities was $239.6 million for the year ended December 31, 2010, an increase of $177.4 million compared to the prior year. The increase in cash provided was primarily due to our debt offering, net of discount, of $248.2 million in 8.25% Senior Notes in May 2010, as well as $17.7 million from a coal reserve financing transaction in June 2010 and a decrease in short-term debt payments of $23.0 million. These increases were partially offset by the decrease in proceeds from the equity offering of $89.1 million, that occurred in June 2009, and additional deferred financing costs in 2010 of $20.7 million related to the May 2010 debt offering, the May 2010 credit facility restatement and amendment and the accounts receivable securitization program.

Effective April 2010, we entered into an agreement to sell coal mineral rights at our Federal mining complex to a third party lessor and added them to an existing lease. We recorded this transaction as a financing arrangement and accordingly recorded the $17.7 million cash consideration as a liability, with $1.2 million of the liability recorded in “Trade accounts payable and accrued expenses” and $16.5 million recorded in “Other noncurrent liabilities.” The liability is being accreted through interest expense over an expected lease term of approximately five years and will be relieved as we make future royalty payments.

Additionally, as of December 31, 2010, we had $121.5 million in notes receivable outstanding from a third party, arising out of the sale of coal reserves and surface land. On February 9, 2011, the third party repaid these notes in full for $115.7 million prior to their scheduled maturity date.

 

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September 1, 2010 U.S. District Court Ruling

On September 1, 2010, the U.S. District Court for the Southern District of West Virginia (the U.S. District Court) found Apogee in contempt for failing to comply with the March 19, 2009 consent decree. Apogee was ordered to install a Fluidized Bed Reactor (FBR) water treatment facility for three outfalls and to come into compliance with applicable selenium discharge limits by March 1, 2013. Additionally, the court ordered Hobet to come into compliance with applicable discharge limits under the Hobet Surface Mine No. 22 permit by May 1, 2013. Apogee and Hobet were required to jointly establish an irrevocable $45 million letter of credit in support of the requirements of this ruling. The court also appointed a Special Master who is authorized to monitor, supervise and direct Apogee’s and Hobet’s compliance with, and hear disputes that arise under, the September 1, 2010 order as well as other orders of the U.S. District Court.

Pursuant to the September 1, 2010 ruling, we will record the costs to install the FBR water treatment facility for the three Apogee outfalls as capital expenditures when incurred. The capital expenditure for the facility is estimated to be approximately $50 million. In addition, the estimated future on-going operating cash flows required to meet our legal obligation for remediation at the three Apogee outfalls have changed from our original estimates based on the September 1, 2010 ruling. As such, we increased the portion of the liability related to Apogee by updating the fair value of the on-going costs related to these three outfalls and recorded the $20.7 million difference between this updated value and our previously recorded liability directly to income, through reclamation and remediation obligation expense in the third quarter of 2010.

As required under the order, we submitted a schedule to develop a treatment plan for the outfall at Hobet Surface Mine No. 22 to the U.S. District Court which includes conducting additional pilot projects related to certain technological alternatives. A final treatment technology to be utilized at Hobet Surface Mine No. 22 will be chosen in 2011 per the submitted schedule. We will record an adjustment to the selenium environmental treatment liability, if necessary, if we modify our planned treatment technology or if we choose a different treatment technology for this outfall.

We are currently continuing to install Zero Valent Iron (ZVI) water treatment systems at other outfalls according to our original remediation strategy, while also performing a further review of other potential water treatment technology or other alternatives. Our remediation strategy reflects implementing scalable ZVI systems at each outfall due to its modular design that can be reconfigured as further knowledge and certainty is gained. Initial ZVI testing has identified potential system shortfalls, and to date ZVI has not been demonstrated to perform consistently and sustainably in achieving effluent selenium limitations or in treating the expected flows at these outfalls. However, based on the flexibility of the scalable system for configuration adjustments, we plan to continue to pursue the ZVI treatment systems and determine whether modifications to the system could result in its ability to treat selenium successfully.

At this time, there is no plan to install FBR or any technology other than ZVI at the other outfalls as neither FBR nor other technologies have been proven effective on a full-scale basis. However, we are continuing to research various treatment alternatives in addition to ZVI for the other outfalls. If ZVI is not ultimately successful in treating the effluent selenium exceedances at these additional outfalls, we may be required to install alternative treatment technologies. The cost of other technologies could be materially higher than the costs reflected in our liability. Furthermore, costs associated with potential modifications to ZVI or the scale of the planned ZVI systems to be installed could also cause the costs to be materially higher than the costs reflected in our liability.

While we are actively continuing to explore treatment options, there can be no assurance as to when a definitive solution will be identified and implemented. As a result, actual costs may differ from our current estimates. We will make additional adjustments to our liability when, and if, we have become subject to other obligations and/or it becomes probable that we will utilize a different technology or modify the current technology, whether due to developments in our ongoing research or a legal obligation to do so.

Credit Facility

Effective October 31, 2007, we entered into a $500 million, four-year revolving credit facility, which included a $50 million swingline sub-facility and a letter of credit sub-facility, subsequently amended for the Magnum acquisition and the issuance of the convertible notes. Effective May 5, 2010, we entered into an Amended and Restated Credit Agreement, which, among other things, extended the maturity date of the revolving credit facility and adjusted borrowing capacity. After the amendment and restatement, we have $427.5 million available under the revolving credit facility with a maturity date of December 31, 2013. We incurred total fees of $10.9 million in relation to the new agreement. These fees as well as the fees related to the initial agreement are being amortized over the remaining term of the amended and restated agreement. We wrote-off $0.6 million of the fees from the initial agreement due to changes to the syndication group.

This facility is available for our working capital requirements, capital expenditures and other corporate purposes. As of December 31, 2010 and 2009, the balance of outstanding letters of credit issued against the credit facility totaled $291.6 million and $352.1 million, respectively. There were no outstanding short-term borrowings against this facility as of December 31, 2010 and 2009. Availability under the credit facility was $135.9 million and $170.4 million as of December 31, 2010 and 2009, respectively.

 

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The obligations under our credit facility are secured by a first lien on substantially all of our assets, including but not limited to certain of our mines, coal reserves and related fixtures. The credit facility contains certain customary covenants, including financial covenants limiting our indebtedness related to net debt coverage and cash interest expense coverage, as well as certain limitations on, among other things, additional debt, liens, investments, acquisitions and capital expenditures, future dividends, and asset sales. The credit facility calls for quarterly reporting of compliance with financial covenants. On January 6, 2011, we entered into an amendment to the Credit Agreement which among other things modified certain limits and minimum requirements of our financial covenants. At December 31, 2010, we were in compliance with the covenants of our amended credit facility.

The terms of the credit facility also contain certain customary events of default, which give the lenders the right to accelerate payments of outstanding debt in certain circumstances. Customary events of default include breach of covenants, failure to maintain required ratios, failure to make principal payments or to make interest or fee payments within a grace period, and default, beyond any applicable grace period, on any of our other indebtedness exceeding a certain amount.

Accounts Receivables Securitization Program

In March 2010, we entered into a $125 million accounts receivable securitization program, which provides for the issuance of letters of credit and direct borrowings. Trade accounts receivable are sold, on a revolving basis, to a wholly-owned bankruptcy-remote entity (facilitating entity), which then sells an undivided interest in all of the trade receivables to creditors as collateral for any borrowings. Available liquidity under the program fluctuates with the balance of our trade accounts receivable.

Based on our continuing involvement with the trade accounts receivable balances, including continued risk of loss, the sale of the trade receivables to the creditors does not receive sale accounting treatment. As such, the trade accounts receivable balances remain on our financial statements until settled. Any direct borrowings under the program will be recorded as secured debt. The outstanding trade accounts receivable balance was $146.6 million as of December 31, 2010. As of December 31, 2010, the balance of outstanding letters of credit issued against the accounts receivable securitization program totaled $63.7 million and there were no direct borrowings under the program.

Senior Notes Issuance

On May 5, 2010, we completed a public offering of $250 million in aggregate principal amount of 8.25% Senior Notes due 2018. The net proceeds of the offering were approximately $240 million after deducting the initial $1.8 million discount, purchasers’ commissions and fees, and expenses of the offering. The net proceeds are being used for general corporate purposes, which may include capital expenditures for development of additional coal production capacity, working capital, acquisitions, refinancing of other debt or other capital transactions. The discount is being amortized over the term of the notes.

Interest on the notes is payable semi-annually in arrears on April 30 and October 30 of each year, beginning October 30, 2010. The notes mature on April 30, 2018, unless redeemed in accordance with their terms prior to such date. The notes are senior unsecured obligations and rank equally with all of our existing and future senior debt and are senior to any subordinated debt. The notes are guaranteed by the majority of our wholly-owned subsidiaries.

The indenture governing the notes contains customary covenants that, among other things, limit our ability to incur additional indebtedness and issue preferred equity; pay dividends or distributions; repurchase equity or repay subordinated indebtedness; make investments or certain other restricted payments; create liens; sell assets; enter into agreements that restrict dividends, distributions or other payments from subsidiaries; enter into transactions with affiliates; and consolidate, merge or transfer all or substantially all of our assets. The indenture also contains certain customary events of default, which give the lenders the right to accelerate payments of outstanding debt in certain circumstances. Customary events of default include breach of covenants, failure to make principal payments or to make interest payments within a grace period, and default, beyond any applicable grace period, on any of our other indebtedness exceeding a certain amount.

Private Convertible Notes Issuance

On May 28, 2008, we completed a private offering of $200 million in aggregate principal amount of 3.25% Convertible Senior Notes due 2013 (the notes), including $25 million related to the underwriters’ overallotment option. The net proceeds of the offering were $193.5 million after deducting the initial purchasers’ commissions and fees and expenses of the offering.

We adopted authoritative accounting guidance related to accounting for convertible debt effective January 1, 2009, with retrospective application to the issuance date of these convertible notes. We utilized an interest rate of 8.85% to reflect the nonconvertible market rate of our offering upon issuance, which resulted in a $44.7 million discount to the convertible note balance and an increase to “Additional paid-in capital” to reflect the value of the conversion feature. The nonconvertible market interest rate was based on an analysis of similar securities trading in the market at the pricing date of the issuance, taking into account company specific data such as credit spreads and implied volatility. In addition, we allocated the financing costs related to the issuance of the convertible instruments between the debt and equity components. The debt discount is amortized over the contractual life of the convertible notes, resulting in additional interest expense above the contractual coupon amount. Interest expense for the convertible notes was $15.1 million, $14.4 million and $8.2 million for the year ended December 31, 2010, 2009 and 2008, respectively.

 

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Interest on the notes is payable semi-annually in arrears on May 31 and November 30 of each year. The notes mature on May 31, 2013, unless converted, repurchased or redeemed in accordance with their terms prior to such date. The notes are senior unsecured obligations and rank equally with all of our existing and future senior debt and are senior to any subordinated debt. We used the proceeds of the offering to repay Magnum’s existing senior secured indebtedness and acquisition related fees and expenses. All remaining amounts were used for other general corporate purposes.

The notes are convertible into cash and, if applicable, shares of Patriot’s common stock during the period from issuance to February 15, 2013, subject to certain conditions of conversion as described below. The conversion rate for the notes is 14.7778 shares of Patriot’s common stock per $1,000 principal amount of notes, which is equivalent to a conversion price of approximately $67.67 per share of common stock. The conversion rate and the conversion price are subject to adjustment for certain dilutive events, such as a future stock split or a distribution of a stock dividend.

The notes require us to settle all conversions by paying cash for the lesser of the principal amount or the conversion value of the notes, and by settling any excess of the conversion value over the principal amount in cash or shares, at our option.

Holders of the notes may convert their notes prior to the close of business on the business day immediately preceding February 15, 2013, only under the following circumstances: (1) during the five trading day period after any ten consecutive trading day period (the measurement period) in which the trading price per note for each trading day of that measurement period was less than 97% of the product of the last reported sale price of Patriot’s common stock and the conversion rate on each such trading day; (2) during any calendar quarter, and only during such calendar quarter, if the last reported sale price of Patriot’s common stock for 20 or more trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the conversion price in effect on each such trading day; (3) if such holder’s notes have been called for redemption or (4) upon the occurrence of corporate events specified in the indenture. The notes will be convertible, regardless of the foregoing circumstances, at any time from, and including, February 15, 2013 until the close of business on the business day immediately preceding the maturity date.

The number of shares of Patriot’s common stock that we may deliver upon conversion will depend on the price of 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 Patriot’s business that are deemed “make-whole fundamental changes” in the indenture, the number of shares deliverable on conversion may increase, up to a maximum amount of 4,137,788 shares. These maximum amounts are subject to adjustment for certain dilutive events, such as a stock split or a distribution of a stock dividend.

Holders of the notes may require us to repurchase all or a portion of our notes upon a fundamental change in our business, as defined in the indenture. The holders would receive cash for 100% of the principal amount of the notes, plus any accrued and unpaid interest.

Patriot may redeem (i) some or all of the notes at any time on or after May 31, 2011, but only if the last reported sale price of our common stock for 20 or more trading days in a period of 30 consecutive trading days ending on the trading day prior to the date we provide the relevant notice of redemption exceeds 130% of the conversion price in effect on each such trading day, or (ii) all of the notes if at any time less than $20 million in aggregate principal amount of notes remain outstanding. In both cases, notes will be redeemed for cash at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus any accrued and unpaid interest up to, but excluding, the relevant redemption date.

The notes and any shares of common stock issuable upon conversion have not been registered under the Securities Act of 1933, as amended (the Securities Act), or any state securities laws. The notes were only offered to qualified institutional buyers pursuant to Rule 144A promulgated under the Securities Act.

Bridge Loan Facility

In connection with the Magnum acquisition agreement, we obtained a subordinated bridge loan financing commitment, allowing us to draw up to $150 million under the related bridge loan facility at the effective date of the acquisition to repay a portion of the outstanding debt of Magnum. We terminated the financing commitment on May 30, 2008, as a result of the issuance of the convertible notes. We recognized $1.5 million in commitment fees in connection with the financing commitment, which were included in “Interest expense” in the consolidated statements of operations.

Promissory Notes

In conjunction with an exchange transaction involving the acquisition of Illinois Basin coal reserves in 2005, we entered into promissory notes. Annual installments of $1.7 million on the promissory notes for principal and interest were payable beginning in January 2008 and run through January 2017. At December 31, 2010, the balance on the promissory notes was $9.4 million, $1.1 million of which was a current liability.

 

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Other

We do not anticipate that we will pay cash dividends on our common stock in the near term. The declaration and amount of future dividends, if any, will be determined by our Board of Directors and will be dependent upon covenant limitations in our credit facility and other debt agreements, our financial condition and future earnings, our capital, legal and regulatory requirements, and other factors our Board deems relevant.

Contractual Obligations

 

     Payments Due by Year as of December 31, 2010  
     Within 1
Year
     2-3 Years      4-5 Years      After 5
Years
 
     (Dollars in thousands)  

Long-term debt obligations (principal and cash interest)

   $ 32,984       $ 261,600       $ 51,850       $ 316,963   

Operating lease obligations

     39,343         57,220         14,575         410   

Coal reserve lease and royalty obligations

     33,296         68,105         55,060         126,492   

Other long-term liabilities (1)

     154,163         323,242         327,660         1,209,327   
                                   

Total contractual cash obligations

   $ 259,786       $ 710,167       $ 449,145       $ 1,653,192   
                                   

 

(1)

Represents long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses and mine reclamation and remediation and end-of-mine closure costs.

As of December 31, 2010, we had $27.0 million of purchase obligations for capital expenditures. Total capital expenditures for 2011 are expected to range from $150 million to $175 million.

Off-Balance Sheet Arrangements and Guarantees

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications, and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. Liabilities related to these arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effect on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

We have used a combination of surety bonds and letters of credit to secure our financial obligations for reclamation, workers’ compensation, postretirement benefits and lease obligations as follows as of December 31, 2010:

 

     Reclamation
and Remediation
Obligations
     Workers’
Compensation
Obligations
     Retiree
Health
Obligations
     Other(1)      Total  
     (Dollars in thousands)  

Surety bonds

   $ 138,646       $ 44       $ —         $ 11,011       $ 149,701   

Letters of credit

     143,938         151,476         56,678         3,207         355,299   

Third-party guarantees

     —           —           —           8,419         8,419   
                                            
   $ 282,584       $ 151,520       $ 56,678       $ 22,637       $ 513,419   
                                            

 

(1)

Includes collateral for surety companies and bank guarantees, road maintenance and performance guarantees.

As of December 31, 2010, Arch held surety bonds of $91.2 million related to properties acquired by Patriot in the Magnum acquisition, of which $89.5 million related to reclamation. As a result of the acquisition, Patriot has posted letters of credit in Arch’s favor, as required.

As part of the spin-off, Peabody had guaranteed certain of our workers’ compensation obligations with the U.S. Department of Labor (DOL). We posted our own surety directly with the DOL in early 2011.

In relation to an exchange transaction involving the acquisition of Illinois Basin coal reserves in 2005, we guaranteed bonding for a partnership in which we formerly held an interest. The aggregate amount that we guaranteed was $2.8 million and the fair value of the guarantee recognized as a liability was $0.2 million as of December 31, 2010. Our obligation under the guarantee extends to September 2015.

In connection with the spin-off, Peabody assumed certain of Patriot’s retiree healthcare liabilities. The present value of these liabilities totaled $680.9 million as of December 31, 2010. These liabilities included certain obligations under the Coal Act for which Peabody and Patriot are jointly and severally liable, obligations under the 2007 NBCWA for which we are secondarily liable, and obligations for certain active, vested employees of Patriot.

 

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Newly Adopted Accounting Pronouncements

Transfers of Financial Assets

In June 2009, the Financial Accounting Standards Board (FASB) issued authoritative guidance regarding the accounting for transfers of financial assets, which requires enhanced disclosures about the continuing risk exposure to a transferor resulting from its continuing involvement with transferred financial assets. We adopted this guidance effective January 1, 2010. See the description of our accounts receivables securitization program in Liquidity and Capital Resources above.

Consolidation

In June 2009, the FASB issued authoritative guidance, which requires a company to perform a qualitative analysis to determine whether it has a controlling financial interest in a variable interest entity, including an assessment of the company’s power to direct the activities of the variable interest entity that most significantly impact the entity’s economic performance. We adopted this guidance effective January 1, 2010. Upon adoption, we performed a qualitative assessment of our existing interests and determined that we held no interest in variable interest entities.

Fair Value Disclosures

In January 2010, the FASB issued authoritative guidance which requires additional disclosures and clarifies certain existing disclosure requirements regarding fair value measurements. This guidance is effective for interim and annual reporting periods beginning after December 15, 2009. We adopted this guidance effective January 1, 2010.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Commodity Price Risk

The potential for changes in the market value of our coal portfolio is referred to as “market risk.” Due to lack of quoted market prices and the long term, illiquid nature of the positions, we have not quantified market risk related to our portfolio of coal supply agreements. We manage our commodity price risk for our coal contracts through the use of long-term coal supply agreements, rather than through the use of derivative instruments. We sold 77% of our sales volume under coal supply agreements with terms of one year or more during 2010. As of December 31, 2010 our total unpriced planned production for 2011 was approximately 5 to 7 million tons.

In connection with the spin-off, we entered into long-term coal contracts with marketing affiliates of Peabody. The arrangements, except as described below under Credit Risk, have substantially similar terms and conditions as the pre-existing contractual obligations of Peabody’s marketing affiliate. These arrangements may be amended or terminated only with the mutual agreement of Peabody and Patriot.

We have commodity risk related to our diesel fuel purchases. To manage this risk, we have entered into swap contracts with financial institutions. These derivative contracts have been designated as cash flow hedges of anticipated diesel fuel purchases. As of December 31, 2010, the notional amounts outstanding for these swaps included 5.0 million gallons of heating oil expiring throughout 2011. As of February 18, 2011, the notional amounts outstanding for these swaps increased to 7.1 million gallons of heating oil expiring throughout 2011. We expect to purchase approximately 22 million gallons of diesel fuel annually. Excluding the impact of our hedging activities, a $0.10 per gallon change in the price of diesel fuel would impact our annual operating costs by approximately $2.2 million.

Credit Risk

Approximately 16% of our accounts receivable balance at December 31, 2010 was with a marketing affiliate of Peabody, and we will continue to supply coal to Peabody on a contract basis as described above, so Peabody can meet its commitments under pre-existing customer agreements sourced from our operations. The pre-existing customer arrangement between Patriot and Peabody with the longest term will expire on December 31, 2012. Our remaining sales are made directly to electricity generators, industrial companies and steelmakers. Therefore, our concentration of credit risk is with Peabody, as well as electricity generators and steelmakers.

Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor the credit extended. In the event that we engage in a transaction with a counterparty that does not meet our credit standards, we will protect our position by requiring the counterparty to provide appropriate credit enhancement. When appropriate (as determined by our credit management function), we have taken steps to mitigate our credit exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps may include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay. While the economic recession may affect our customers, we do not anticipate that it will significantly affect our overall credit risk profile due to our credit policies.

 

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Item 8. Financial Statements and Supplementary Data.

See Part IV, Item 15 of this report for information required by this Item.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, the CEO and the CFO have each concluded that our disclosure controls and procedures were designed, and were effective, to ensure that information required to be disclosed in our reports under the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

There have not been any significant changes in our internal control over financial reporting identified during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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Management’s Report on Internal Control Over Financial Reporting

Management is responsible for maintaining and establishing adequate internal control over financial reporting. Our internal control framework and processes were designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

Because of inherent limitations, any system of internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an assessment of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on this assessment, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.

Our Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited our internal control over financial reporting, as stated in their unqualified opinion report included herein.

 

/s/    RICHARD M. WHITING        
Richard M. Whiting
Chief Executive Officer

February 25, 2011

 

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Management’s Report on Internal Control Over Financial Reporting

Management is responsible for maintaining and establishing adequate internal control over financial reporting. Our internal control framework and processes were designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

Because of inherent limitations, any system of internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an assessment of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on this assessment, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.

Our Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited our internal control over financial reporting, as stated in their unqualified opinion report included herein.

 

/s/    MARK N. SCHROEDER        
Mark N. Schroeder
Chief Financial Officer

February 25, 2011

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Patriot Coal Corporation

We have audited Patriot Coal Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Patriot Coal Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Patriot Coal Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010 based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Patriot Coal Corporation as of December 31, 2010 and 2009 and the related consolidated statements of income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2010, and our report dated February 25, 2011 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

St. Louis, Missouri

February 25, 2011

 

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Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

The information required by Item 401 of Regulation S-K is included under the caption Election of Directors in our Proxy Statement and in Part I of this report under the caption Executive Officers of the Company. Such information is incorporated herein by reference. The information required by Items 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is included under the captions Section 16(a) Beneficial Ownership Reporting Compliance, Corporate Governance Matters and Executive Compensation, respectively, in our Proxy Statement and is incorporated herein by reference.

Item 11. Executive Compensation.

The information required by Items 402 and 407 (e)(4) and (e)(5) of Regulation S-K is included in our Proxy Statement under the caption Executive Compensation and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by Item 403 of Regulation S-K is included under the caption Ownership of Company Securities in our Proxy Statement and is incorporated herein by reference.

As required by Item 201(d) of Regulation S-K, the following table provides information regarding our equity compensation plans as of December 31, 2010:

Equity Compensation Plan Information

 

Plan Category

   (a)
Number of Securities
to be Issued

Upon Exercise of
Outstanding Options,
Warrants and Rights
     Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
     Number of Securities
Remaining Available
for Future Issuance
Under Equity Compensation
Plans (Excluding Securities
Reflected in Column (a))
 

Equity compensation plans approved by security holders

     1,509,348       $ 15.04         7,262,298   

Equity compensation plans not approved by security holders

     N/A         N/A         N/A   
                          

Total

     1,509,348       $ 15.04         7,262,298   
                          

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required by Item 404 of Regulation S-K is included under the captions Certain Relationships and Related Party Transactions, Director Independence and Policy for Approval of Related Person Transactions in our Proxy Statement and is incorporated herein by reference. The information required by Item 407(a) of Regulation S-K is included under the caption Executive Compensation in our Proxy Statement and is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services.

The information required by Item 9(e) of Schedule 14A is included under the caption Fees Paid to Independent Registered Public Accounting Firm in our Proxy Statement and is incorporated herein by reference.

 

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PART IV

Item 15. Exhibits and Financial Statement Schedules.

 

  (a) Documents Filed as Part of the Report

 

  (1) Financial Statements.

The following consolidated financial statements of Patriot Coal Corporation are included herein on the pages indicated:

 

     Page  

Reports of Independent Registered Public Accounting Firms

     F-1   

Consolidated Statements of Operations – Years Ended December 31, 2010, 2009 and 2008

     F-2   

Consolidated Balance Sheets – December 31, 2010 and December 31, 2009

     F-3   

Consolidated Statements of Cash Flows – Years Ended December 31, 2010, 2009 and 2008

     F-4   

Consolidated Statements of Changes in Stockholders’ Equity – Years Ended December  31, 2010, 2009 and 2008

     F-5   

Notes to Consolidated Financial Statements

     F-6   

 

  (2) Financial Statement Schedule.

The following financial statement schedule of Patriot Coal Corporation is at the page indicated:

 

     Page  

Valuation and Qualifying Accounts

     F-54   

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted.

 

  (3) Exhibits.

See Exhibit Index hereto.

 

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

PATRIOT COAL CORPORATION
/s/    RICHARD M. WHITING        
Richard M. Whiting
President, Chief Executive Officer and Director

Date: February 25, 2011

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons, on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature

  

Title

 

Date

/s/    RICHARD M. WHITING        

Richard M. Whiting

  

President, Chief Executive Officer and

Director (principal executive officer)

  February 25, 2011

/s/    MARK N. SCHROEDER        

Mark N. Schroeder

   Senior Vice President and Chief Financial Officer (principal financial and accounting officer)   February 25, 2011

/s/    IRL F. ENGELHARDT        

Irl F. Engelhardt

   Chairman of the Board and Director   February 25, 2011

/s/    J. JOE ADORJAN        

J. Joe Adorjan

   Director   February 25, 2011

/s/    B. R. BROWN        

B. R. Brown

   Director   February 25, 2011

/s/    MICHAEL P. JOHNSON        

Michael P. Johnson

   Director   February 25, 2011

/s/    JOHN E. LUSHEFSKI        

John E. Lushefski

   Director   February 25, 2011

/s/    MICHAEL M. SCHARF        

Michael M. Scharf

   Director   February 25, 2011

/s/    ROBERT O. VIETS        

Robert O. Viets

   Director   February 25, 2011

 

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Exhibit No.

 

Description of Exhibit

2.1   Separation Agreement, Plan of Reorganization and Distribution, dated October 22, 2007, between Peabody Energy Corporation and Patriot Coal Corporation (Incorporated by reference to Exhibit 2.1 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
2.2   Amendment No. 1 to the Separation Agreement, Plan of Reorganization and Distribution, dated November 1, 2007, between Peabody Energy Corporation and Patriot Coal Corporation. (Incorporated by reference to Exhibit 10.42 of the Registrant's Current Report on Form 10-K, filed on March 14, 2008.)
2.3   Agreement and Plan of Merger, dated as of April 2, 2008, by and among Magnum Coal Company, Patriot Coal Corporation, Colt Merger Corporation, and ArcLight Energy Partners Fund I, L.P. and ArcLight Energy Partners Fund II, L.P., acting jointly, as Stockholder Representative (Incorporated by reference to Exhibit 2.1 of the Registrant's Current Report on Form 8-K, filed on April 8, 2008.)
3.1   Amended and Restated Certificate of Incorporation (Incorporated by reference to Exhibit 3.1 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
3.2   Certificate of Amendment of the Amended and Restated Certificate of Incorporation (Incorporated by reference to Exhibit 3.1 of the Registrant's Current Report on Form 8-K, filed on May 17, 2010.)
3.3   Amended and Restated By-Laws (Incorporated by reference to Exhibit 3.2 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
4.1   Rights Agreement, dated October 22, 2007, between Patriot Coal Corporation and American Stock Transfer & Trust Company (Incorporated by reference to Exhibit 4.1 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
4.2   Certificate of Designations of Series A Junior Participating Preferred Stock (Incorporated by reference to Exhibit 4.1 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
4.3   First Amendment to Rights Agreement, dated as of April 2, 2008, to the Rights Agreement, dated as of October 22, 2007 between Patriot Coal Corporation and American Stock Transfer & Trust Company, as Rights Agent (Incorporated by reference to Exhibit 4.1 of the Registrant's Current Report on Form 8-K, filed on April 8, 2008.)
4.4   Indenture dated as of May 28, 2008, by and between Patriot Coal Corporation, as Issuer, and U.S. Bank National Association, as trustee (including form of 3.25% Convertible Senior Notes due 2013) (Incorporated by reference to the Registrant's Current Report on Form 8-K, dated May 29, 2008.)
4.5   Indenture dated as of May 5, 2010 between Patriot Coal Corporation and Wilmington Trust Company, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant's Current Report on Form 8-K, filed on May 5, 2010.)
4.6   First Supplemental Indenture dated May 5, 2010 among Patriot Coal Corporation, the guarantors party thereto and Wilmington Trust Company, trustee (Incorporated by reference to Exhibit 4.2 of the Registrant's Current Report on Form 8-K, filed on May 5, 2010.)
4.7   Second Supplemental Indenture dated May 5, 2010 among Patriot Coal Corporation, the guarantors party thereto and Wilmington Trust Company, trustee (Incorporated by reference to Exhibit 4.3 of the Registrant's Current Report on Form 8-K, filed on May 5, 2010.)
10.1   Tax Separation Agreement, dated October 22, 2007, between Peabody Energy Corporation and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
10.2   Employee Matters Agreement, dated October 22, 2007, between Peabody Energy Corporation and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.3 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
10.3   Coal Act Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC and Peabody Energy Corporation (Incorporated by reference to Exhibit 10.9 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
10.4   NBCWA Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC, Peabody Coal Company, LLC and Peabody Energy Corporation (Incorporated by reference to Exhibit 10.10 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)


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10.5   Salaried Employee Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC, Peabody Coal Company, LLC and Peabody Energy Corporation (Incorporated by reference to Exhibit 10.11 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
10.6   Administrative Services Agreement, dated October 22, 2007, between Patriot Coal Corporation, Peabody Holding Company, LLC and Peabody Energy Corporation (Incorporated by reference to Exhibit 10.12 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
10.7   Master Equipment Sublease Agreement, dated October 22, 2007, between Patriot Leasing Company LLC and PEC Equipment Company, LLC (Incorporated by reference to Exhibit 10.13 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
10.8   Software License Agreement, dated October 22, 2007, between Patriot Coal Corporation and Peabody Energy Corporation (Incorporated by reference to Exhibit 10.14 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
10.9   Throughput and Storage Agreement, dated October 22, 2007, among Peabody Terminals, LLC, James River Coal Terminal, LLC and Patriot Coal Sales LLC (Incorporated by reference to Exhibit 10.15 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
10.10   Conveyance and Assumption Agreement, dated October 22, 2007, among PEC Equipment Company, LLC, Central States Coal Reserves of Indiana, LLC, Central States Coal Reserves of Illinois, LLC, Cyprus Creek Land Company and Peabody Coal Company, LLC (Incorporated by reference to Exhibit 10.16 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
10.11   Coal Supply Agreement, dated October 22, 2007, between Patriot Coal Sales LLC and COALSALES II, LLC (Incorporated by reference to Exhibit 10.4 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
10.12   Amendment 1 to Coal Supply Agreement between Patriot Coal LLC and COALSALES II LLC, dated March 28, 2008. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 10-Q, filed on May 14, 2008.)
10.13   Coal Supply Agreement, dated October 22, 2007, between Patriot Coal Sales LLC and COALSALES LLC (Incorporated by reference to Exhibit 10.5 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
10.14