10-K 1 pcx1231201110k.htm FORM 10-K PCX 12.31.2011 10K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Year Ended December 31, 2011
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.  þ
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, 2011: Common Stock, par value $0.01 per share, $2.0 billion.
Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 17, 2012: Common Stock, par value $0.01 per share, 92,924,037 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 10, 2012 (the “Company’s 2011 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
 
PART I
Item 1.
 
 
 
Item 1A.
 
 
 
Item 1B.
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
Item 4B.
 
PART II
 
 
 
Item 5.
 
 
 
Item 6.
 
 
 
Item 7.
 
 
 
Item 7A.
 
 
 
Item 8.
 
 
 
Item 9.
 
 
 
Item 9A.
 
 
 
Item 9B.
 
PART III
 
 
 
Item 10.
 
 
 
Item 11.
 
 
 
Item 12.
 
 
 
Item 13.
 
 
 
Item 14.
 
PART IV
 
 
 
Item 15.

2

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:
•
U.S. and international financial, economic and political conditions;
•
coal price volatility and demand, particularly in higher margin products;
•
geologic, equipment and operational risks associated with mining;
•
reductions of purchases or deferral of shipments by major customers;
•
changes in general economic conditions, including coal, power and steel market conditions;
•
availability and prices of competing energy resources for electricity generation;
•
changes in the interpretation, enforcement or application of existing and potential laws and regulations affecting the production and use of our products;
•
availability and costs of credit, surety bonds and letters of credit;
•
weather patterns and conditions affecting energy demand or disrupting supply;
•
our ability to identify and implement cost effective solutions for selenium water treatment;
•
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;
•
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;
•
failure to comply with debt covenants;
•
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;
•
our ability to attract and retain qualified personnel;

3

•
negotiation of labor contracts, labor availability and relations;
•
customer performance and credit risks;
•
inflationary trends, including those impacting materials used in our business;
•
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;
•
the effects of mergers, acquisitions and divestitures, including our ability to successfully integrate mergers and acquisitions;
•
competition in our industry;
•
interest rate fluctuation;
•
wars and acts of terrorism or sabotage;
•
impact of pandemic illness; and
•
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.



4

GLOSSARY OF SELECTED MINING TERMS
ABMet. A technology that we are currently implementing for selenium water treatment at certain outfall(s), which was developed by General Electric.
ACOE. U.S. Army Corps of Engineers.
Adjusted EBITDA. Adjusted EBITDA is defined as net income (loss) before deducting interest income and expense; income taxes; asset retirement obligation expense; depreciation, depletion and amortization; restructuring and impairment charge; and net sales contract accretion.
Bituminous coal. The most common type of coal with moisture content less than 20% by weight and heating value of 10,500 to 14,000 Btu per pound.
British thermal unit, or “Btu.” A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).
Carbon dioxide (CO2). A gaseous chemical compound that is generated as a by-product of the combustions of fossil fuels or the burning of vegetable matter, among other processes.
Central Appalachia. The bituminous coal producing states and regions of eastern Kentucky, eastern Tennessee, western Virginia and southern West Virginia.
Coal ash. Impurities consisting of iron, aluminum and other incombustible matter that are contained in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the burning characteristics of coal.
Coal seam. Coal deposits occur in layers typically separated by layers of rock. Each layer is called a “seam.” A coal seam can vary in thickness from inches to a hundred feet or more.
Coke. A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel. Its production results in a number of useful byproducts.
Complex. An area with one or more company-operated mines and/or contractor-operated mines as well as a preparation plant.
Continuous miner. An underground mining machine that removes coal from the face.
Continuous miner mining. 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 thinner seams.
Dragline. A large machine used in the surface mining process to remove the overburden, or layers of earth and rock covering a coal seam. The dragline has a large bucket suspended from the end of a long boom. The bucket, which is suspended by cables, is able to scoop up substantial amounts of overburden as it is dragged across the excavation area.
Dragline mining. An efficient surface method that uses large capacity draglines to remove overburden to expose the coal seams. Once mined, the coal is loaded into haul trucks for transportation to a preparation plant or transportation to a loading facility.
EPA. U.S. Environmental Protection Agency.
Face. Commonly used to describe the exposed area of a coal seam from which coal is extracted.
FBR. Fluidized Bed Reactor. A technology we are currently implementing for selenium water treatment at certain outfalls.
Force majeure. An event not anticipated as of the date of the applicable contract, which is not within the reasonable control of the party affected by such event, that partially or entirely prevents such party's ability to perform its contractual obligations. During the duration of the force majeure, the obligations of the party affected by the event may be excused to the extent required.
Fossil fuel. Fuel such as coal, petroleum or natural gas formed from the fossil remains of organic material.

5

Geologic Conditions. The physical nature of the coal seam and surrounding strata and their effects 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.
Highwall mining. 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.
High vol metallurgical coal. Coal with volatile matter greater than approximately 30%. Volatile matter refers to the impurities that become gaseous when heated to certain temperatures.
Illinois Basin. The bituminous coal producing states and regions of Illinois, Indiana and western Kentucky.
IX. Ion Exchange. A technology we are currently testing for selenium water treatment at certain outfall(s).
Longwall mining. 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.
Low vol metallurgical coal. Coal with volatile matter between approximately 16% and 22%. Volatile matter refers to the impurities that become gaseous when heated to certain temperatures.
Metallurgical coal. The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as “met” coal and "coking" coal, it possesses four important qualities: volatility, which affects coke yield; the level of impurities, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Metallurgical coal generally has a particularly high Btu heat content, but low ash and sulfur content.
Mid vol metallurgical coal. Coal with volatile matter between approximately 24% and 28%. Volatile matter refers to the impurities that become gaseous when heated to certain temperatures.
MSHA. U.S. Mine Safety and Health Administration.
Northern Appalachia. The bituminous coal producing states and regions of Pennsylvania, Ohio and Maryland and the northern part of West Virginia.
NPDES. National Pollutant Discharge Elimination System.
OSM. Office of Surface Mining Reclamation and Enforcement. Administers the Surface Mining Control and Reclamation Act (SMCRA) and establishes mining, environmental protection and reclamation standards for all aspects of U.S. surface mining as well as many aspects of underground mining.
Outfall. A water discharge point authorized in a NPDES permit. In the case of coal mining, the discharge point is often a pipe or channel that discharges water from a sediment control structure. Also referred to as an "outlet."
Overburden. Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.
Pillar. An area of coal left to support the overlying strata in an underground mine, sometimes left permanently to support surface structures.
Preparation plant. A facility for crushing, sizing and washing coal to remove rock and other impurities to prepare it for use by a particular customer. Preparation plants are usually located on a mine site, although one plant may serve several mines. The washing process has the added benefit of removing some of the coal's sulfur content.
Reclamation. The process of restoring land and the environment to their original state following mining activities. The process commonly includes “recontouring” or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually underway before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law.

6

Roof. In an underground mine, the stratum of rock or other mineral above a coal seam; the overhead surface of a coal mine working area.
Roof bolting. A method of supporting the roof of underground mines by inserting long steel bolts into holes bored into the overlying strata forming a more stable roof by creating a composite beam.
Selenium. 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.
SMCRA. Surface Mining Control and Reclamation Act.
Stoker coal. 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.
Sulfur. One of the elements present in varying quantities in coal that reacts with air when coal is burned to form sulfur dioxide.
Sulfur dioxide (SO2). A gaseous by-product of coal combustion.
Surface mine. A mine in which the coal lies near the surface and can be extracted by removing the covering layer of earth and rock (see “Overburden”).
Thermal coal. Coal used by power plants and industrial steam boilers to produce electricity, steam or both. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal. Also known as "steam" coal.
Tons. A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is equal to 2,240 pounds; a “metric” ton (also called a "tonne") is approximately 2,205 pounds. The short ton is the unit of measure referred to in our filings.
Truck-and-Shovel/Loader Mining. A surface mining method that uses large electric- or diesel-powered shovels to remove overburden. 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.
UMWA. United Mine Workers of America.
Underground mine. Also known as a “deep” mine. Usually located several hundred feet below the earth's surface, an underground mine's coal is removed mechanically and transferred by shuttle car or conveyor to the surface.
WVDEP. West Virginia Department of Environmental Protection.
ZVI. Zero Valent Iron. A technology that we are currently utilizing for selenium water treatment at certain outfall(s).

7

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). Refer to the Glossary on pages 3 through 5 for the definition of terms used throughout this document.
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, and metallurgical coal. Thermal coal is primarily sold to electricity generators, and metallurgical coal is sold to steel mills and independent coke producers.
As of December 31, 2011, our operations consisted of fourteen active mining complexes. Our operations 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 2011, we sold 31.1 million tons of coal, of which 76% was sold to domestic and global electricity generators and industrial customers and 24% was sold to domestic and global steel and coke producers. Export sales were 29% of our total volume in 2011. 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. As of December 31, 2011, we had ten mining complexes located in Boone, Clay, Lincoln, Logan and Kanawha counties in southern West Virginia. In northern West Virginia, we have one complex located in Monongalia County. In Appalachia, we sold 23.9 million tons of coal in the year ended December 31, 2011. As of December 31, 2011, we controlled 1.2 billion tons of proven and probable coal reserves in Appalachia, of which 491 million tons were assigned to current operations. In January 2012, we announced the idling of and production curtailment at certain metallurgical coal mines in response to weaker demand. In February 2012, we announced the closure of the Big Mountain mining complex in response to weaker thermal coal demand.
•Illinois Basin. In the Illinois Basin, we have three complexes located in Union and Henderson counties in western Kentucky. In the Illinois Basin, we sold 7.3 million tons of coal in the year ended December 31, 2011. As of December 31, 2011, we controlled 722 million tons of proven and probable coal reserves in the Illinois Basin, of which 175 million tons were assigned to current operations.


8

The following table provides the location and summary information of our operations for the year ended December 31, 2011.
 
 
 
 
 
 
 
 
 
 
 
Location
 
Complex
 
Mine(s)
 
Mining
Method(1)
 
Met/Thermal
 
2011
Tons
Sold(2)
Appalachia
 
Big Mountain
 
Big Mountain No. 16, Contractor
 
CM
 
Thermal
 
1,879

 
 
Blue Creek
 
Blue Creek No. 1
 
CM
 
Thermal
 
848

 
 
Campbell’s Creek
 
Campbell’s Creek No. 7, Contractor
 
CM
 
Thermal
 
680

 
 
Corridor G
 
Job 21, Hill Fork
 
DL, TS
 
Thermal
 
3,656

 
 
Kanawha Eagle
 
Contractor
 
CM
 
Met/Thermal
 
1,445

 
 
Logan County
 
Guyan
 
TS
 
Thermal
 
2,693

 
 
Paint Creek
 
Samples, Winchester
 
TS, HW, CM
 
Met/Thermal
 
1,181

 
 
Panther
 
Panther
 
LW, CM
 
Met
 
1,845

 
 
Rocklick
 
Black Oak, Gateway Eagle, Contractor
 
CM
 
Met
 
1,294

 
 
Wells
 
Rivers Edge, Contractor
 
CM
 
Met
 
2,840

 
 
Federal
 
Federal No. 2
 
LW, CM
 
Thermal
 
3,973

 
 
Purchased coal
 
N/A
 
N/A
 
N/A
 
1,527

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Subtotal
 
23,861

 
 
 
 
 
 
 
 
 
 
 
Illinois Basin
 
 
 
 
 
 
 
 
 
 
 
 
Bluegrass
 
Patriot, Freedom
 
TS, CM
 
Thermal
 
2,456

 
 
Dodge Hill
 
Dodge Hill No. 1
 
CM
 
Thermal
 
831

 
 
Highland
 
Highland No. 9
 
CM
 
Thermal
 
3,978

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Subtotal
 
7,265

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
31,126

 
 
 
 
 
 
 
 
 
 
 
(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 2011, subject to stockpile variations.

9

Appalachian Mining Operations
As of December 31, 2011, our Appalachian Mining Operations included eleven active mining complexes in West Virginia.
                
Appalachia
Big Mountain
As of December 31, 2011, the Big Mountain mining complex is sourced by one company-operated underground mine, Big Mountain No. 16, and one contractor-operated underground mine located in southern West Virginia. Coal is produced utilizing continuous mining methods. The coal is sold on the thermal market and was 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). In February 2012, we closed our Big Mountain mining complex.
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. Coal at the Blue Creek mining complex is produced from the Stockton seam. The complex utilizes continuous mining methods. 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. Both 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. Coal produced at Campbell’s Creek mining complex is sold on the thermal and stoker coal markets. 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 dragline and truck-and-shovel/loader mining. Coal produced at Job 21 is transferred by belt to the on-site preparation plant and loadout facility. After processing, the coal is transported to customers by CSX rail. Hill Fork production is either trucked to a terminal on the Kanawha River and placed on barges or transported to a nearby preparation plant for processing. Coal produced at the Corridor G mining complex is sold on the thermal market. Certain employees at the Corridor G mining complex are represented by the UMWA.

10

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. In early 2012, we opened the Peerless underground mine.
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. The truck and shovel/loader method of mining the Samples surface mine has been idled since 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 is sold on both the metallurgical and thermal markets. The employees at the Paint Creek complex are not represented by a union.
Panther
The Panther mining complex consists of one company-operated 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 was sold into the metallurgical market during 2010 and 2011. 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, Black Oak and Gateway Eagle, and two contractor-operated underground mines. Coal at the Rocklick mining complex is produced utilizing continuous mining methods. 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. The Gateway Eagle mine opened in 2011 and produces metallurgical coal from the Eagle seam. Our contract mines produce metallurgical coal from the Eagle and No. 2 Gas seams. Thermal coal can also be processed and sold at this operation. Certain employees at the company-operated facilities of the Rocklick mining complex are represented by the UMWA. In January 2012, we announced plans to idle the Gateway Eagle mine and one contractor-operated mine, as well as to reduce production at the Black Oak mine.
Wells
The Wells mining complex is located in southern West Virginia and is sourced by multiple contractor-operated underground mines and was sourced by one company-operated underground mine. 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. 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. Rivers Edge produced coal from the Powellton seam until it reached the end of its life in April 2011. In January 2012, we announced plans to idle two contractor-operated mines in the Wells complex.

11

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 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.
Illinois Basin Mining Operations
As of December 31, 2011, our Illinois Basin Mining Operations included three mining complexes in western Kentucky.
                
Illinois Basin
Bluegrass
The Bluegrass mining complex is located in western Kentucky and is sourced by two company-operated mines, Freedom, 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 truck to a barge loading facility 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.


12

Customers and Backlog
In 2011, our coal was sold to over 80 electricity generating and industrial plants in 9 countries, including the U.S., which is where we have our primary customer base.
As of December 31, 2011, we had a sales backlog of 47.2 million tons of coal, including backlog subject to price reopener and/or extension provisions. Our coal supply agreements have remaining terms of up to 6 years and an average volume-weighted remaining term of approximately 1.9 years.
 
 
Commitments as of December 31, 2011
 
 
2012
 
2013
 
2014
 
2015 and
Later
 
Total
Tons (in millions)
 
25.9

 
10.6

 
4.6

 
6.1

 
47.2

The 2012 commitments represent approximately 90 - 95% of our currently estimated production for 2012.
In 2011, approximately 78% of our coal sales were under long-term (one year or greater) 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 a contract that existed at the date of spin-off with terms into 2012. As of December 31, 2011, approximately 12% of our current projected 2012 total production was committed under this pre-existing customer relationship with Peabody, which supplies thermal coal.
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 the 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. The inflation 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, 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 contract. 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.

13

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 buyer. 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 buyers 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 31.1 million tons sold in 2011, approximately 49% was shipped by rail, 40% by barge, 7% by ocean-going vessel and 4% 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 and steel roof bolts. Purchases of certain underground mining equipment and steel roof bolts are concentrated with one principal supplier; however, supplier competition continues to exist. 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 18% of our total sales volume for the year ended December 31, 2011.
Competition
The U.S. coal industry is highly competitive, both regionally and nationally. Coal production in Appalachia and the Illinois Basin totaled approximately 430 million tons in 2011, with the largest five producers (Alpha Natural Resources, Inc., CONSOL Energy Inc., Alliance Resource Partners, L.P., Patriot, and Peabody) accounting for 54% 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 around the world and 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, 2011, we had approximately 4,300 employees. Approximately 50% of our employees were represented by an organized labor union. Our represented employees work at various sites in Appalachia and at the Highland complex in the Illinois Basin.

14

In the third quarter of 2011, certain of our subsidiaries signed new agreements with the UMWA, which were effective July 1, 2011 and generally extend through December 2016. The new agreements are substantially the same as the National Bituminous Coal Wage Agreement negotiated in mid-2011 between the Bituminous Coal Operators Association and the UMWA. We refer to this as the 2011 National Bituminous Coal Wage Agreement (2011 NBCWA).
We operate two training centers in Appalachia. Our training centers educate our workforce, particularly our most recent hires, in our rigorous safety standards, the latest in mining techniques and equipment, and serve 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 near term, and to develop and retain a productive and safety-oriented workforce.
Certain Liabilities
We have significant long-term liabilities for asset retirement obligations (including reclamation and selenium water treatment), 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, future retirees and their dependents.
Asset Retirement 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). Selenium water treatment obligations primarily represent the present value of future anticipated costs for water treatment of selenium discharges, as required by current court orders, consent decrees and mining permits.
Asset retirement obligation expense (which includes liability accretion and asset amortization) for the years ended December 31, 2011, 2010 and 2009 was $81.6 million, $63.0 million, and $35.1 million, respectively. The 2011 and 2010 expense amounts included selenium water treatment obligation charges related to a court ruling as further described below. As of December 31, 2011, our asset retirement obligations of $427.5 million included $99.4 million of reclamation obligations related to locations that are closed or inactive.
Our selenium treatment obligation associated with the Magnum-acquired sites 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.
Our initial liability for the treatment of outfalls with known selenium exceedances was recorded at June 30, 2009 and reflected the estimated total costs of the planned Zero Valent Iron (ZVI) water treatment systems to be implemented and maintained 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 selenium water treatment strategy. We utilized the cost of the most successful treatment methodology at that time based on our testing results and considering the uncertainties regarding technology, compliance parameters and deadline extensions.
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 challenge.
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 at permitted outfalls. In the past, we have paid fines and penalties with respect to violations of selenium effluent limitations.

15

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 $55.0 million. In addition, the estimated future on-going operating cash flows required to meet our legal obligation for selenium water treatment 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 asset retirement obligation expense in the third quarter of 2010.
Additionally, the September 1, 2010 ruling required that we select a technology for one outfall at Hobet Surface Mine No. 22. In June 2011, we selected FBR technology for this outfall because we could utilize the knowledge gained building the Apogee FBR facility and additional research was needed to resolve certain detailed design considerations for ZVI and Ion Exchange (IX). In June 2011, we recorded an adjustment of $24.0 million to the selenium water treatment liability primarily related to the estimated future ongoing operating costs of an FBR water treatment facility at this outfall. In December 2011, the U.S. District Court agreed to a change to the selenium water treatment technology from FBR to ABMet technology at this outfall. In December 2011, we adjusted the portion of the selenium water treatment liability related to Hobet Surface Mine No. 22 by $10.3 million for the decrease in the fair value of the estimated future ongoing operating costs related to this outfall due to the change in the technology. We also wrote off approximately $3.0 million related to the final engineering specifications for the Hobet FBR facility. These charges are reflected in asset retirement obligation expense in the fourth quarter of 2011.
As with the Apogee FBR facility, we will record the costs to install the Hobet ABMet water treatment facility as capital expenditures when incurred. We continue to design and seek permits for the Hobet ABMet facility and anticipate beginning construction on the facility in the first half of 2012. The estimated total expenditures for completing the ABMet water treatment facility is approximately $25.0 million, which is significantly less than the estimated $40.0 million to build the Hobet FBR facility.
In February 2011, OVEC and two other environmental groups filed a lawsuit against us, Apogee, Catenary Coal Company, LLC (Catenary) and Hobet, in the U.S. District Court alleging violations of ten NPDES permits and certain SMCRA permits. In late 2011, we substantially agreed to the terms of a settlement agreement with the plaintiffs. On January 18, 2012, we finalized a comprehensive consent decree with OVEC and the other two environmental groups, which sets technology selection and compliance dates for the outfalls in the ten permits included in this litigation on a staggered basis, allowing us to continue testing certain technologies as well as to take advantage of technology that is still in the development stage. We also agreed to, among other things, waive our rights to mine certain coal reserves and to pay a civil penalty of $7.5 million. The plaintiffs agreed to, among other things, refrain from instituting new lawsuits with respect to the permits and outfalls identified in the comprehensive consent decree for certain periods, provided we meet the specified requirements. The comprehensive consent decree also established a framework under which we will

16

interface with the plaintiffs with respect to the identified permits and outfalls. The amounts paid per the comprehensive consent decree of $7.5 million and the write-off of the forfeited coal reserves of approximately $2.3 million are reflected in asset retirement obligation expense in the fourth quarter of 2011.
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 have installed ZVI systems according to our original water treatment strategy, while also performing a further review of other potential water treatment solutions. Our water treatment strategy reflects implementing scalable ZVI installations at each of the other outfalls due to its modular design that can be reconfigured as further knowledge and certainty is gained. Initial pilot testing of ZVI technology began in 2008 and has identified potential shortfalls requiring additional research to resolve certain detailed design considerations. To date, ZVI technology has not been demonstrated to perform consistently and sustainably in achieving effluent selenium limitations or in treating the expected water flows at all outfalls. However, based on the flexibility of the scalable system for configuration adjustments, improvements in the system design and demonstrated success in reducing selenium at certain flows, we plan to continue to pursue the ZVI-based water treatment installations and determine whether modifications to the technology could result in its ability to treat selenium successfully at outlets identified in the February 2011 litigation.
At this time, there is no definitive plan to install FBR, ABMet or any technology other than ZVI technology at the other outfalls not included in the September 1, 2010 ruling as none of the other technologies has been proven effective on a full-scale basis. Our comprehensive consent decree with the plaintiffs in the February 2011 litigation requires that we select water treatment technology by category beginning with the first category in September 2012 and ending with the last category in September 2014. We are continuing to research and evaluate various treatment solutions in addition to ZVI-based water treatment for the other outfalls. Results of pilot testing in the first half of 2011 indicated that ZVI, FBR and IX may be viable selenium treatment options. We are continuing to test modifications to these treatment options and we are pilot testing alternative solutions. Alternative technology solutions that we may ultimately select are still in the early phases of development and their related costs can not be estimated at this time.
Retiree Healthcare and Pension Obligations for Active and Retired Employees
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 $1.5 billion and $1.3 billion as of December 31, 2011 and 2010, respectively, of which $81.4 million and $65.6 million was a current liability, respectively. Expense for the years ended December 31, 2011, 2010 and 2009 was $125.0 million, $117.2 million and $92.5 million, respectively.
In connection with the spin-off, a subsidiary of Peabody assumed certain of our pre-spin-off obligations associated with the Coal Industry Retiree Health Benefits Act of 1992 (the Coal Act), the 2007 National Bituminous Coal Wage Agreement (2007 NBCWA) and certain salaried employee retiree healthcare benefits. At December 31, 2011, the present value of the liability assumed by Peabody at spin-off was $696.8 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.

17

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 related to pending interpretations. Based on preliminary estimates and basic assumptions regarding 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 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 to business. The collective bargaining agreement with the UMWA, which specifies the payments to be made to the 1993 Benefit Plan, was renegotiated in 2011 and generally extends through 2016.
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 in addition to any amounts that may be appropriated by Congress at its discretion. The legislation also revises the AML fees paid by coal producers based 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 the guarantee period from January 1, 2007 through December 31, 2010 were reviewed by the trustees with no additional liability to the employers. Our subsidiaries that have agreed to the 2011 NBCWA will pay $1.10 per hour worked to the 1993 Benefit Plan in 2012. New inexperienced miners hired after January 1, 2007 cannot receive benefits from the 1993 Benefit Plan unless they are disabled as the result of a mine accident. The 1993 Benefit Plan is now effectively closed to new miners.

18

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 $40.8 million as of December 31, 2011, $5.4 million of which was a current liability. 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. Expenses for the years ended December 31, 2011, 2010 and 2009 were $2.1 million, $3.2 million and $3.2 million, respectively. Cash payments to these funds were $5.4 million, $6.0 million and $6.3 million for 2011, 2010 and 2009, 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 $2.5 million, $10.0 million and $11.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.
Certain of our subsidiaries participate in two defined benefit multi-employer pension funds (the 1950 Plan and the 1974 Plan) that were established as a result of collective bargaining with the UMWA pursuant to the 2007 NBCWA as periodically negotiated and adjusted based on the 2011 NBCWA. 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 1950 Plan, or after December 31, 1975, in the case of the 1974 Plan. In December 2006, the 2007 NBCWA was signed, which required funding of the 1974 Plan through 2011 under a phased funding schedule. The funding is based on an hourly rate for active UMWA workers. Under the labor contract, the per hour funding rate increased annually, beginning in 2007, until reaching $5.50 in 2011. The 2011 NBCWA requires funding at $5.50 per hour for certain UMWA workers. Our subsidiaries with UMWA-represented employees are required to contribute to the 1974 Plan. The 1974 Plan funding rate could change during the term of the 2011 NBCWA if deemed necessary to guarantee benefit payments.
New inexperienced miners hired after January 1, 2012 will not participate in the 1974 Plan. These new hires will instead receive a payment of $1.00 per hour worked into the UMWA Cash Deferral Plan, increasing to $1.50 on January 1, 2014. Effective January 1, 2012, employers will also pay $1.50 per hour to a new Retiree Bonus Account Trust for the term of the 2011 NBCWA. This Trust will make a payment to pensioners in November of 2014, 2015 and 2016 in the amount of $580 for most retirees and $455 for disabled retirees. This payment was also made in November 2011. If Trust funding is not sufficient to make these annual bonus payments, employers will pay the difference directly to their retirees.
Effective January 1, 2012, employers will also make an additional supplemental pension contribution of $1.00 per hour worked into the UMWA Cash Deferred Savings Plan for each active miner with at least 20 years of credited service under the 1974 Plan, increasing to $1.50 per hour on January 1, 2014. Effective January 1, 2012, any participant in the 1974 Plan may make an irrevocable election to opt out of the 1974 Plan. Such employee will cease to accrue any further service or benefits under the 1974 Plan. Effective with the election, employers will contribute $1.00 per hour worked to the UMWA Cash Deferred Plan on the employee's behalf as a Supplemental Pension Contribution, increasing to $1.50 on January 1, 2014.
Contributions to these funds could increase in the future 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 $24.3 million, $21.0 million and $18.3 million for the years ended December 31, 2011, 2010 and 2009, 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 $258.3 million and $246.3 million as of December 31, 2011 and 2010, respectively, of which $26.7 million and $25.5 million was a current liability, respectively. Expense for the years ended December 31, 2011, 2010 and 2009 was $39.8 million, $38.2 million and $31.3 million, respectively.

19

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. In March 2010, we increased our liability by $11.5 million based on an estimate of the impact of these changes to our current population of beneficiaries and claimants. At that time we were not able to estimate the full impact of the legislation on our obligation 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 populations. We continue to evaluate the impact of this legislation on both our current and future population of claimants and to adjust our liability based on actual claim and award information.
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 surface and 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 focus on the 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 for at least one year 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 have been 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.
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 re-occurrence. We utilize best practices in emergency preparedness, which includes maintaining multiple mine rescue teams. A portion of the annual performance incentive for eligible 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 MINER Act's requirements, each miner must have at least two, one-hour Self Contained Self Rescue (SCSR) devices for use in the event of an emergency (each miner had at least one SCSR device prior to the MINER Act) and we must provide 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

20

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.
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 MSHA District Manager, the guidelines governing seals and ventilation evaluation points have reduced the action levels of the various gases while increasing the frequency of withdrawals 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 MSHA 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: 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. On October 26, 2011, the U.S. Department of Interior (DOI) proposed to consolidate certain functions of the OSM into the Bureau of Land Management, and it is uncertain how any future consolidation will affect the administration of SMCRA.
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 mining permit application process in the U.S. 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

21

often take two years or more 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, 2011, we had outstanding surety bonds and total letters of credit of $534.4 million, including: $325.0 million for post-mining reclamation; $132.2 million related to workers’ compensation obligations; $56.7 million for retiree health obligations; and $20.4 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.
Numerous federal, state and local 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 governmental 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 U.S. 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 several 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

22

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 obligations and permit requirements under the Clean Water Act or corresponding state or local laws, and as a result we have, at times, been subject to compliance orders and third-party litigation seeking fines or penalties or changes to our operations. See Certain Liabilities – Asset Retirement 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 March 18, 2012. On February 15, 2012, the ACOE announced revisions to NWP 21, which are scheduled to take effect on March 18, 2012, with significant modifications that would prohibit the use of NWP 21 to authorize valley fills. Individual permits are required for surface coal mining projects while NWP 21 is suspended, and will continue to be required to authorize valley fills. We have converted any pending permit applications that were submitted under NWP 21 to individual permit applications and believe that the revisions to the NWP 21 permit 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 enhanced 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 enhanced review. In October 2011, a federal district court set aside the enhanced review procedure. The EPA and ACOE have reportedly ceased using the enhanced review procedure but, consistent with the Clean Water Act and applicable regulations, continue to collaborate to review Section 404 permit applications.
In November 2009, the 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.
The DOI is also 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.

23

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 July 21, 2011, the EPA issued comprehensive guidance to clarify 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. 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. The EPA Administrator has stated that it may be difficult for most surface mining operations to meet these water quality standards. Additionally, the guidance makes recommendations with regard to assessing, avoiding and minimizing environmental impacts to water quality, including establishing protective water quality parameters and requiring best management practices and other permit requirements. As a result of the EPA's guidance, we and other mining companies are subject to more stringent permit requirements imposed through our NPDES and Section 404 permits. There can be no guarantee that we will be able to meet these permit requirements or any other standards imposed by our permits.
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, including with respect to particulate matter. In November 2011, advocates for further regulation of coal mining sued the EPA in an effort to force further restrictions on methane, volatile organic compounds, nitrogen oxide and other air emissions. The Clean Air Act and equivalent state laws also indirectly affect 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 new legislation and regulations may lead to some electricity generating customers switching to other sources of fuel in an attempt to lower levels of regulated emissions.

24

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. CAIR has been subject to a complex series of legal challenges since its promulgation. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to replace CAIR. CSAPR limits sulfur dioxide and nitrogen oxide emissions from power plants in 28 eastern states.
On December 30, 2011, the U.S. Court of Appeals for the District of Columbia (D.C. Circuit Court) effectively stayed CSAPR, leaving CAIR in effect pending judicial review. The court is expected to hear oral arguments in April 2012. Many of our customers would be affected by CSAPR, which would require emission reductions beginning in 2012 and significant additional reductions in 2014. CSAPR may affect coal quality price adjustments in certain of our contracts. In addition, Congress has, in the past, considered legislation to reduce sulfur dioxide and nitrogen oxide emissions from power plants. Any of the foregoing legislative or regulatory initiatives could cause our customers to change their coal sources or reduce their demand for coal.
Mercury and Other Air Pollutant Emissions
The EPA promulgated the Clean Air Mercury Rule (CAMR) in March 2005 to establish a market-based cap-and-trade program to reduce nationwide mercury emissions from new and existing coal-fueled power plants. CAMR was vacated on February 8, 2008 by the D.C. Circuit Court. In December 2011, the EPA finalized the Mercury and Air Toxics Standards for power plants (MATS), which will impose on power plants by early 2015 emission standards for heavy metals, including mercury, arsenic, chromium and nickel, and acid gases, including hydrogen chloride and hydrogen floride.
In February 2011, the EPA issued emission standards for mercury, other metals and organic air toxics from certain boilers and process heaters. In May 2011, the EPA stayed the effective date of such standards and, in December 2011, it proposed a revised version of such standards. In January 2012, the U.S. District Court for the District of Columbia vacated the May 2011 stay, effectively reinstating the February 2011 standards. However, the EPA has indicated that it expects to finalize the revised suite of emission standards issued in December 2011 for boilers and process heaters as early as April 2012.
Congress has in the past also considered legislation to reduce mercury emission from power plants. Existing and future regulations and legislation that reduce emissions of mercury and other hazardous air pollutants from power plants, and other combustion sources could adversely affect the demand for coal. For example, the EPA estimates that MATS could cause coal production in Appalachia for use by the electric power sector to decline by 6% in 2015 relative to projected production levels in the absence of MATS.
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 D.C. Circuit Court remanded to the EPA certain aspects of the fine particulate matter standards, which the EPA has indicated it will review by June 2013. Existing and possible future restrictions, including any that arise out of the EPA’s review, on the emission of fine or coarse particulate matter could result in additional and expensive control requirements for coal-fueled power plants, which could adversely affect the demand for coal. In addition, any such restrictions could adversely affect our ability to develop new mines or require us to modify our existing operations.
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. The EPA is expected to review these standards by 2013. Any revisions to these standards may require more stringent emissions controls on sources of nitrogen oxides, including coal-fueled electricity generating plants, which could adversely affect the demand for coal from our mining operations.

25

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 amended 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 indicated that states may implement the CAIR or CSAPR trading programs, as applicable, for sulfur dioxide and nitrogen oxide as an alternative to requiring source-specific BART for power plants.
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 and hazardous air pollutants. 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, as a result of which certain facilities, including coal-fueled power plants, are subject to permitting and other requirements under the Clean Air Act. The EPA's Greenhouse Gas Tailoring Rule (GHG Tailoring Rule) sets forth criteria for determining which facilities 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 are being 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 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 issue 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 coal-fueled power plants. In addition, we and many of our customers are required to report annual greenhouse gas emissions from certain operations. Although it is not yet possible to predict the effect of the GHG Tailoring Rule, greenhouse gas reporting requirements 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 considered 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 have considered 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, nine 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.

26

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 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. 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.
Demand for and use of coal also may be limited by any global treaties which place restrictions on greenhouse gas emissions. As part of the United Nations Framework Convention on Climate Change, the U.S. has participated in negotiations regarding greenhouse gas emissions reductions and 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 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. Coal mine wastes, such as overburden and coal cleaning wastes, generally are not considered hazardous waste materials under the RCRA. In May 2010, the EPA released two competing proposals for the regulation of coal combustion by-products (CCB). One approach 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 CCB 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 demand for 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 by us 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.

27

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.

28

Executive Officers
Set forth below are the names, ages and current positions of our officers. Executive officers are appointed by, and hold office at, the discretion of our Board of Directors.
Name
 
Age
 
                                        Positions
Richard M. Whiting
 
57
 
President, Chief Executive Officer & Director
Bennett K. Hatfield
 
55
 
Executive Vice President & Chief Operating Officer
Mark N. Schroeder
 
55
 
Senior Vice President & Chief Financial Officer
Charles A. Ebetino, Jr.
 
59
 
Senior Vice President - Global Strategy & Corporate Development
Robert W. Bennett
 
49
 
Senior Vice President & Chief Marketing Officer
Joseph W. Bean
 
49
 
Senior Vice President - Law & Administration & General Counsel
Christopher K. Knibb
 
42
 
Vice President - Controller & Chief Accounting Officer

Richard M. Whiting
President, Chief Executive Officer & Director
Richard M. Whiting, age 57, 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.
Bennett K. Hatfield
Executive Vice President & Chief Operating Officer
  Bennett K. Hatfield, age 55, serves as Executive Vice President & Chief Operating Officer. Mr. Hatfield has previously held a number of key executive operating and commercial positions during a 30-plus year career in the coal industry. Prior to joining Patriot, Mr. Hatfield served as President, Chief Executive Officer and Director of International Coal Group, Inc., from March 2005 until the company was sold in June 2011. Mr. Hatfield previously served as President, Eastern Operations of Arch Coal, Inc., from March 2003 until March 2005, and Executive Vice President & Chief Commercial Officer of Coastal Coal Company, from December 2001 through February 2003. Mr. Hatfield joined Massey Energy Company in 1979, where he served in a number of management roles, most recently as Executive Vice President and Chief Operating Officer, from June 1998 through December 2001.
Mr. Hatfield is a board member of the West Virginia Coal Association and a past board member of the NMA. Mr. Hatfield is a Licensed Professional Engineer with a Bachelor of Science degree in mining engineering from Virginia Polytechnic Institute and State University.

29

Mark N. Schroeder
Senior Vice President & Chief Financial Officer
Mark N. Schroeder, age 55, 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.
Charles A. Ebetino, Jr.
Senior Vice President - Global Strategy & Corporate Development
Charles A. Ebetino, Jr., age 59, serves as Senior Vice President - Global Strategy and Corporate Development. From August 2010 through September 2011, Mr. Ebetino also served as Senior Vice President & Chief Operating Officer. From our 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.
Robert W. Bennett
Senior Vice President & Chief Marketing Officer
Robert W. Bennett, age 49, 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.

30

Joseph W. Bean
Senior Vice President - Law & Administration & General Counsel
Joseph W. Bean, age 49, serves as Senior Vice President — Law & Administration & General Counsel. 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 more than 25 years of corporate law experience, including over 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.
Christopher K. Knibb
Vice President - Controller & Chief Accounting Officer
Christopher K. Knibb, age 42, serves as Vice President — Controller and Chief Accounting Officer. From the spin-off to September 2011, Mr. Knibb served as Vice President and Controller for Patriot. Mr. Knibb has more than 18 years of business experience including roles as Vice President, Finance of American Power Conversion during 2006 and 2007 and Vice President - Corporate Controller of SAVVIS, Inc. from 2003 to 2006. Prior to 2003, Mr. Knibb held various financial management positions with Artesyn Technologies, Inc, Seisint, Inc., PricewaterhouseCoopers and Deloitte.
Mr. Knibb is a veteran of the U.S. Army, a certified public accountant and holds a Bachelor of Arts degree in accounting from University of South Florida.

31

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
Any change in coal consumption patterns, in particular by global steel producers or global electric power generators, could result in a decrease in the use of our 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 results of operations.
Metallurgical coal accounted for approximately 24%, 22% and 17% of our coal sales volume during the years ended December 31, 2011, 2010 and 2009, respectively. Metallurgical coal was sold to the domestic steel producers 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.
Thermal coal accounted for approximately 76%, 78% and 83% of our coal sales volume during the years ended December 31, 2011, 2010 and 2009, respectively. The majority of our sales of thermal coal were to U.S. electric power generators with an increasing percentage 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 use of 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.
During 2011, headwinds created by low natural gas prices, mild weather and weaker international and domestic economies have impacted coal markets, and market weakness continues as we enter 2012. The demand for metallurgical coal, in particular, is dependent on the strength of global economies. Concerns over the pace of growth in China, the European financial crisis, and the strength of the U.S. recovery have caused pressure on steel demand. In early 2012, metallurgical coal demand trended downward, especially in export markets.
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.

32

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.
Prolonged global recessionary conditions could adversely affect our financial condition and results of operations.
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. If there is a worsening of global and U.S. economic and financial market conditions and additional tightening of global credit markets, as currently experienced in Greece and certain other European countries, demand for electricity and steel production may suffer.
The recent recession and distressed international financial markets have created economic uncertainty, and steel producers responded by decreasing production. As the demand for coal declines, certain of our customers may request delays in shipments or request deferrals pursuant to existing long-term coal supply 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. To the extent we or a customer do not fully perform under our contracts, our results of operations and operating profit in the reporting period during which such non-performance occurs would 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., James River Coal Company, Peabody Energy Corporation and Walter Energy, Inc. 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.

33

We also face competition from renewable energy providers, like biomass, wind and solar, and other alternative fuel sources, like natural gas and nuclear energy. 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 and other air emissions, coal ash and other environmental matters could materially adversely affect our customers’ demand for coal and our financial condition, results of operations and cash flows.
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 gases. 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 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. Global treaties are also being considered that place restrictions on carbon dioxide and other greenhouse gas emissions. See Item 1. Environmental Laws for additional discussion of greenhouse gas emission regulation.
In addition, several new regulations under the Clean Air Act have recently been finalized or are expected to be finalized in 2012 that would regulate emissions of sulfur dioxide, nitrogen oxide, mercury and other air pollutants from power plants and industrial boilers. The new regulations include the Cross-State Air Pollution Rule, which is expected to require reductions in emissions of sulfur dioxide and nitrogen oxide from power plants in 28 eastern U.S. states, the Mercury and Air Toxics Standards, which will regulate emissions of mercury and other heavy metals from power plants, and National Emission Standards for Hazardous Air Pollutants, which will regulate emissions of mercury and other metals and organic air toxics from industrial, commercial and institutional boilers.
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 and potential 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 other hazardous air pollutants 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 financial condition, results of operations and cash flows. Even in the absence of future regulatory developments, increased awareness of, and any adverse publicity regarding, greenhouse gas and other air 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. The pre-existing customer arrangement between Patriot and Peabody with the longest term will expire on December 31, 2012. Contracts with Peabody to purchase coal sourced from our operations accounted for approximately 10% and 18% of our revenues for the years ended December 31, 2011 and 2010, respectively.

34

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. In recent 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 addition to typical contract remedies for failure to perform, many of our long-term coal supply agreements also contain provisions which may result in price adjustments. In certain situations, these provisions may allow either party to terminate the agreement or suspend performance if certain conditions are met.
Many of our long-term thermal coal supply agreements contain price re-opener provisions, under which the parties negotiate contract pricing for future periods. If we are unable to reach agreement with our customers under these provisions, either party may have the right to terminate the contract or submit the dispute to arbitration.
Many of our long-term thermal coal supply agreements contain provisions that permit the parties to adjust the contract price for specific events, including inflation and changes in the laws regulating the production, sale or use of coal. Additionally, the majority of our long-term coal supply agreements contain provisions that allow a purchaser to terminate the 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.
Our coal supply agreements also typically contain force majeure provisions which allow the temporary suspension of performance by the affected party during the duration of specified events beyond the affected party's control.
In addition, most of our coal supply agreements contain provisions which require us to deliver coal within certain ranges for specific coal characteristics such as heat content (Btu), sulfur and ash content, moisture, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries, purchasing replacement coal in a higher priced open market or termination of the contract.
To the extent our customers exercise their rights under any of the foregoing provisions, our results of operations and operating profit could be adversely affected.
Risk Factors Relating to our Operations
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 results of operations.
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.
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 financial condition, results of operations and cash flows. We cannot assure you that these risks would be covered by our insurance policies.

35

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. We are subject to the risk that we will not be able to effectively replace the knowledge and expertise of an aging workforce as those workers retire. 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, 2011, Patriot had approximately 4,300 employees. Approximately 50% of our employees were represented by an organized labor union. Relations with our employees and, where applicable organized labor, are important to our success. Union labor is represented by the UMWA. In the third quarter of 2011, certain of our subsidiaries signed new labor agreements with the UMWA which generally extend through December 31, 2016. Our represented employees work at various sites in Appalachia and at the Highland complex in the Illinois Basin.
The outcome of future 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 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 future 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 and steel roof bolts 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.

36

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 18% of our total sales volume for the year ended December 31, 2011 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 financial condition, results of operations and cash flows.
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.
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, 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 many of 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.

37

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 and 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.
Industry Regulatory Risks
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.

38

Future legislation and regulations may 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 July 2011, the EPA issued final comprehensive guidance in part to assure more consistent, effective and timely compliance by Appalachian surface coal mining operations with the provisions of the Clean Water Act. This guidance establishes threshold conductivity levels to be used as a basis for evaluating compliance with narrative water quality standards. As a result of the EPA's guidance, we and other mining companies are subject to more stringent permit requirements. There can be no guarantee that we will be able to meet these permit requirements or any other standards imposed by our permits.
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 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.

39

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 reflects the estimated total costs of the planned Zero Valent Iron (ZVI) water treatment systems to be implemented and maintained. 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 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.
In 2010, one of our subsidiaries was found in contempt for failing to comply with a consent decree regarding selenium discharge limits. In January 2012, we entered into a comprehensive consent decree with certain environmental groups that will, when entered by the court, set technology selection and compliance dates for the outfalls in ten of our permits on a staggered basis, allowing us to continue testing certain technologies as well as to take advantage of technology that is still in the development stage. See Item 1. Certain Liabilities - Asset Retirement 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. Additionally, the September 1, 2010 ruling required that we select a technology for one outfall at Hobet Surface Mine No. 22. In June 2011, we selected FBR technology for this outfall because we could utilize the knowledge gained building the Apogee FBR facility and additional research was needed to resolve certain detailed design considerations for ZVI and IX. In December 2011, the U.S. District Court agreed to a change to the selenium water treatment technology from FBR to ABMet technology at this outfall.
At this time, there is no plan to install any technology other than ZVI at the other outfalls not addressed in the September 1, 2010 court ruling as no technology has 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 will 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 if or when a definitive solution will be identified and implemented, whether we can meet applicable compliance deadlines 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

40

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 financial condition, results of operations and cash flows.
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.
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 2011. 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. 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.
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.
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. These factors could have a material adverse effect on our financial condition, results of operations and cash flows.
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

41

contaminated sites that have always been owned or operated by third parties who we do business with. 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.
We are involved in legal proceedings that, if determined adversely to us, could significantly impact our financial condition, results of operations and cash flows.
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. 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 actual benefit plan costs vary from our estimates, then expenditures for these benefits could be materially higher than we have estimated 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 in 2010, but to a greater extent in 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 $1.5 billion as of December 31, 2011. 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 financial condition, results of operations and cash flows and our cash expenditures and costs incurred for employee benefit plans could be materially higher.

42

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, such as with the 2011 NBCWA. 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 Plan. The 2011 NBCWA requires funding at $5.50 per hour for certain UMWA workers. The 1974 Plan funding rate could change during the term of the 2011 NBCWA if deemed necessary to guarantee benefit payments.
New inexperienced miners hired after January 1, 2012 will not participate in the 1974 Plan. Such new hires will instead receive a payment of $1.00 per hour worked into the UMWA Cash Deferral Plan, increasing to $1.50 on January 1, 2014. Effective January 1, 2012, employers will also pay $1.50 per hour to a new Retiree Bonus Account Trust for the term of the 2011 NBCWA. This Trust will make a payment to pensioners in November of 2014, 2015 and 2016 in the amount of $580 for most retirees and $455 for disabled retirees. This payment was also made in November 2011. If the Trust funding is not sufficient to make these annual bonus payments, employers will pay the difference directly to their retirees.
Effective January 1, 2012, employers will also make an additional supplemental pension contribution of $1.00 per hour worked into the UMWA Cash Deferred Savings Plan for each active miner with at least 20 years of credited service under the 1974 Plan, increasing to $1.50 per hour on January 1, 2014. Effective January 1, 2012, any participant in the 1974 Plan may make an irrevocable election to opt out of the 1974 Plan. Such employee will cease to accrue any further service or benefits under the 1974 Plan. Effective with the election, employers will contribute $1.00 per hour worked to the UMWA Cash Deferred Plan on his behalf as a Supplemental Pension Contribution, increasing to $1.50 on January 1, 2014.
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.
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 former employees of defunct entities (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 $696.8 million as of December 31, 2011. These obligations arise under the Coal Act, the 2007 NBCWA and predecessor and successor 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 financial condition, results of operations and cash flows.

43

We have significant reclamation and mine closure obligations. If our actual costs vary from our estimates, 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, 2011, we had accrued reserves of $124.5 million for reclamation liabilities and an additional $167.5 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 financial condition, results of operations and cash flows.
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 continued uncertainty 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 financial condition, results of operations and cash flows.
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, 2011, we had outstanding surety bonds and letters of credit aggregating $534.4 million, of which $325.0 million was for post-mining reclamation, $132.2 million related to workers’ compensation obligations, $56.7 million was for retiree health obligations and $20.4 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.

44

As of December 31, 2011, Arch Coal, Inc. (Arch) held surety bonds of $39.4 million related to properties acquired by Patriot in the Magnum acquisition, of which $38.5 million related to reclamation. We posted a letter 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.
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.
For the year ended December 31, 2011, approximately 10% of our revenue was generated through sales to a marketing affiliate of Peabody. A portion of these sales relate to contracts to supply coal in order for Peabody to meet commitments under customer agreements in existence prior to the spin-off which were sourced from our operations. Our remaining sales are made to electricity generators, industrial companies and steelmakers.
In addition, during and subsequent to economic recessions, many companies struggle to maintain their businesses and are subject to an increased risk of bankruptcy. If our customers seek protection under the federal bankruptcy laws, they could terminate all or a portion of their business with us and/or originate new business with our competitors. If our customers are significantly and negatively impacted by the challenging economic conditions, or by other business factors, or if any of our significant customers seek bankruptcy protection, our financial condition and results of operations 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.
As described in other risk factors, issues such as global economic conditions, volatile financial markets, changing governmental regulation related to the production and use of our products, as well as competition from natural gas, create challenges for the coal industry and us. As a result, it has become more difficult to predict the future impact of these challenges including the results of Management's actions to deal with them.
Our credit facility contains financial covenants which require us to maintain specified ratios of Consolidated Interest Coverage and Consolidated Net Leverage (each as defined in the credit facility). In addition, the indenture governing our subordinated bonds includes a Fixed Charge Coverage Ratio Test related to the incurrence of additional debt. The credit facility calls for quarterly reporting of compliance with financial covenants. Our credit facility, the indenture governing our subordinated bonds and the agreements governing our other indebtedness also include additional covenants, that limit, among other things, additional debt, investments, acquisitions and capital expenditures, future dividends and asset sales. The aforementioned risks and challenges make it possible that we may not comply with our financial covenants in the future.

45

Upon the occurrence of an event of default under the credit facility, our lenders will be entitled to, among other things, accelerate payments of all outstanding loans, plus all accrued and unpaid interest thereon and any other amounts payable under the credit facility. Certain events of default under, and acceleration of, our credit facility could also result in the cross-acceleration of our subordinated bonds and subordinated convertible debentures. If an event of default occurs under the credit facility, we may be unable to negotiate a mutually acceptable amendment or waiver with our lenders and we may not have sufficient funds to pay the total amount of accelerated obligations. In addition, our lenders may exercise rights and remedies in respect of the collateral securing the credit facility (including, among other things, to take possession and dispose of such collateral). Any acceleration in the repayment of our debt, or the exercise of rights and remedies in respect of the collateral by our lenders in connection therewith, would adversely affect our business.
The negotiation of a mutually acceptable amendment or waiver with our lenders to maintain compliance with the covenants under our credit facility, if any, may be expensive. In January 2011 and 2012, we entered into amendments to our credit facility which, among other things, modified certain limits and minimum requirements of our financial covenants. However, there can be no assurance that we would be able to obtain additional amendments or waivers in the future.
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.
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.
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.
We have received no comments regarding our periodic or current reports from the staff of the SEC (the staff) that were issued 180 days or more preceding the end of our 2011 fiscal year and that remain unresolved. However, within the 180 days preceding the end of our 2011 fiscal year, we have received comments from the staff regarding our selenium water treatment requirements. There can be no assurance on the timing of resolution of such comments.


46

Item 2. Properties.
Coal Reserves
We had an estimated 1.9 billion tons of proven and probable coal reserves as of December 31, 2011 located in Appalachia and the Illinois Basin. Of our proven and probable coal reserves 14%, or 272 million tons, are compliance coal and 1,659 million tons are non-compliance coal. We own approximately 36% of these reserves and lease property containing the remaining 64%. Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu and complies with certain requirements of the Clean Air Act. Electricity generators are able to use non-compliance coal by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.
Below is a table summarizing the locations and reserves of our major operating regions. 
 
 
Proven and Probable
Reserves as of
December 31, 2011(1)
Geographic Region
 
Owned
Tons
 
Leased
Tons
 
Total
Tons
 
 
(In millions)
Appalachia
 
306

 
903

 
1,209

Illinois Basin
 
389

 
333

 
722

Total proven and probable coal reserves
 
695

 
1,236

 
1,931

 (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 1,139 million  tons of proven and 792 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, 2011 were prepared by our Vice President – Engineering and his geology and engineering staff, by updating the December 31, 2010 estimates. 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, 2011.

47

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 our reserves are adequate to sustain our desired production levels 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.

48

The following chart provides a summary, by geographic region and mining complex, of production for the years ended December 31, 2011, 2010 and 2009, tonnage of coal reserves assigned to our operating mines, property interest in those reserves and other characteristics of the facilities.
PRODUCTION AND ASSIGNED RESERVES(1) 
    
 
 
Production
 
Sulfur Content(2)
 
 
 
 
 
As of December 31, 2011
Geographic Region/
Mining Complex
 
Year
Ended
Dec 31,
2011
Year
Ended
Dec 31,
2010
Year
Ended
Dec 31,
2009
 
<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
 
1.8

2.0

2.0

 
5

11

—

 
Thermal
 
12,200

 
16

 
—

 
16

 
—

 
16

Blue Creek
 
0.8

0.8

0.1

 
21

52

—

 
Thermal
 
12,700

 
72

 
—

 
72

 
11

 
61

Campbell’s
  Creek
 
0.7

0.7

1.0

 
14

20

—

 
Thermal
 
13,100

 
34

 
24

 
10

 
—

 
34

Corridor G
 
3.6

4.0

3.6

 
5

45

1

 
Thermal
 
12,400

 
51

 
1

 
50

 
51

 
—

Jupiter
 
—

—

—

 
1

7

—

 
Thermal
 
11,500

 
8

 
—

 
8

 
1

 
7

Kanawha
  Eagle
 
1.4

1.5

1.9

 
36

1

—

 
Met/Thermal
 
12,600

 
38

 
—

 
38

 
—

 
38

Logan
  County
 
2.6

2.7

2.6

 
44

35

—

 
Thermal
 
12,500

 
79

 
10

 
69

 
66

 
13

Paint Creek
 
1.2

1.1

2.3

 
18

32

1

 
Met/Thermal
 
13,100

 
51

 
—

 
51

 
5

 
46

Panther
 
1.9

2.0

2.1

 
32

1

—

 
Met
 
13,200

 
33

 
1

 
32

 
—

 
33

Rocklick
 
1.1

0.4

1.5

 
—

23

—

 
Met
 
13,000

 
23

 
—

 
23

 
—

 
23

Wells
 
2.8

3.1

3.4

 
24

17

—

 
Met
 
13,400

 
41

 
—

 
41

 
—

 
41

Federal
 
3.7

3.7

3.8

 
—

—

45

 
Thermal
 
13,300

 
45

 
41

 
4

 
—

 
45

Total
 
21.6

22

24.3

 
200

244

47

 
 
 
 
 
491

 
77

 
414

 
134

 
357

Illinois Basin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bluegrass
 
2.4

2.3

2.5

 
—

—

64

 
Thermal
 
11,100

 
64

 
14

 
50

 
4

 
60

Dodge Hill
 
0.9

0.9

0.9

 
—

—

24

 
Thermal
 
12,700

 
24

 
3

 
21

 
—

 
24

Highland
 
3.9

3.5

3.7

 
—

—

87

 
Thermal
 
11,400

 
87

 
28

 
59

 
—

 
87

Total
 
7.2

6.7

7.1

 
—

—

175

 
 
 
 
 
175

 
45

 
130

 
4

 
171

Total
 
28.8

28.7

31.4

 
200

244

222

 
 
 
 
 
666

 
122

 
544

 
138

 
528


49

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, 2011
 
 
 
 
 
 
 
 
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

 
Thermal
 
11,700

 
26

 
—

 
—

 
26

West Virginia    
 
491

 
692

 
1,183

 
798

 
385

 
269

 
646

 
268

 
Met/Thermal
 
12,200

 
280

 
903

 
239

 
943

Total
 
491

 
718

 
1,209

 
817

 
392

 
269

 
646

 
294

 
 
 
 
 
306

 
903

 
239

 
969

Illinois
  Basin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Illinois
 
—

 
230

 
230

 
89

 
141

 
3

 
18

 
209

 
Thermal
 
11,100

 
228

 
2

 
—

 
230

Kentucky
 
175

 
317

 
492

 
233

 
259

 
—

 
3

 
489

 
Thermal
 
11,300

 
161

 
331

 
33

 
460

Total
 
175

 
547

 
722

 
322

 
400

 
3

 
21

 
698

 
 
 
 
 
389

 
333

 
33

 
690

Total
   proven and
    probable
 
666

 
1,265

 
1,931

 
1,139

 
792

 
272

 
667

 
992

 
 
 
 
 
695

 
1,236

 
272

 
1,659

1)
Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2011. 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.





50

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 U.S. 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 requirements, 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.
Hobet 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 Hobet WVDEP Action. The Hobet WVDEP Action was resolved by a settlement and consent order entered in the Boone County Circuit Court on September 5, 2008. The settlement required us, among other things, 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 Hobet 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.

51

Selenium Matters
Federal Apogee Case and Federal Hobet Case
In 2007, Apogee was sued in the 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 effluent limits for selenium set forth in one of its NPDES permits. The lawsuit sought compliance with the effluent limits, 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 Hobet WVDEP Action in state court. However, the Federal Hobet Case focused exclusively on selenium exceedances in permitted water discharges, while the Hobet 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 effluent 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' effluent 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 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.
Other WVDEP Actions
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. On June 11, 2010, WVDEP filed a lawsuit against Apogee in the Logan County Circuit Court, alleging discharge of pollutants, including selenium, in violation of certain of its NPDES and SMCRA permits. We refer to this case as the Apogee WVDEP Action. The permits contained in the Catenary WVDEP Action and the Apogee WVDEP Action are also involved in the February 2011 Action discussed below. WVDEP is seeking fines and penalties as well as injunctions prohibiting Catenary and Apogee from discharging pollutants, including selenium, in violation of laws and NPDES permits. A July 2012 trial date has been set for the Apogee WVDEP Action. The Catenary WVDEP Action has not been set for hearing. 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 these matters if they would be in the best interest of the Company.

52

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 a Fluidized Bed Reactor (FBR) water treatment facility for three outfalls and to come into compliance with applicable selenium discharge limits at these three outfalls by March 1, 2013. In September 2010, we increased the portion of the selenium water treatment liability related to Apogee by $20.7 million for the fair value of the estimated future ongoing operating costs related to these three outfalls. This charge is reflected in “Asset retirement obligation expense” in the consolidated statement of operations. We record the costs to install the Apogee FBR water treatment facility as capital expenditures when incurred. As of December 31, 2011, we have spent approximately $12.6 million on the Apogee FBR facility and the total expenditures are estimated to be approximately $55 million. We began construction on the Apogee FBR facility in the third quarter of 2011.
Additionally, the U.S. District Court ordered Hobet to submit a proposed schedule to develop a treatment plan for a Hobet Surface Mine No. 22 outfall by October 1, 2010 and to come into compliance with applicable discharge limits under the permit by May 1, 2013. We submitted the required schedule, which included conducting additional pilot projects related to certain technological alternatives. A treatment technology to be utilized at this Hobet Surface Mine No. 22 outfall was filed with the U.S. District Court in June 2011 in accordance with the submitted schedule. In June 2011, we recorded an adjustment of $24.0 million to the selenium water treatment liability primarily related to the estimated future ongoing operating costs of an FBR water treatment facility at this outfall. This charge is reflected in “Asset retirement obligation expense” in the consolidated statement of operations.
In December 2011, the Special Master appointed by the U.S. District Court to oversee the Hobet Surface Mine No. 22 project approved Hobet's request to substitute ABMet selenium treatment technology for the FBR technology at this outfall. The U.S. District Court subsequently confirmed this substitution. As with the Apogee FBR facility, we will record the costs to install the Hobet ABMet water treatment facility as capital expenditures when incurred. We continue to design and seek permits for the Hobet ABMet facility and anticipate beginning construction on the facility in the first half of 2012. The estimated total expenditures for completing the ABMet water treatment facility is approximately $25.0 million, which is significantly less than the estimated $40.0 million to build the Hobet FBR facility.
In December 2011, we adjusted the portion of the selenium water treatment liability related to Hobet Surface Mine No. 22 by $10.3 million for the decrease in the fair value of the estimated future ongoing operating costs related to this outfall due to the change in the technology. We also wrote off approximately $3.0 million related to the final engineering specification for the Hobet FBR facility. These charges are reflected in “Asset retirement obligation expense” in our consolidated statement of operations.
FBR technology had not been used to remove selenium or any other minerals discharged at coal mining operations prior to our pilot project performed in 2010. The FBR water treatment facility required by the September 1, 2010 ruling will be the first facility constructed for selenium removal on a commercial scale. Neither FBR nor ABMet technology has been proven effective on a full-scale commercial basis at coal mining operations and there can be no assurance that either of these technologies will be successful under all variable conditions experienced at our mining operations.
February 2011 Litigation
In February 2011, OVEC and two other environmental groups filed a lawsuit against us, Apogee, Catenary and Hobet, in the U.S. District Court alleging violations of ten NPDES permits and certain SMCRA permits. We refer to this case as the February 2011 Litigation. The February 2011 Litigation involves the same four NPDES permits that are the subject of the Catenary WVDEP Action, the same Apogee permit that is the subject of the Apogee WVDEP Action, the same four NPDES permits that are the subject of the Hobet WVDEP Action and one additional NPDES permit held by Hobet that is not the subject of any action by WVDEP. The plaintiffs were seeking fines, compliance with permit limits and other requirements, and injunctive relief.
In late 2011, we substantially agreed to the terms of a settlement agreement with OVEC and the other environmental groups. On January 18, 2012, we finalized a comprehensive consent decree that, when entered by the U.S. District Court, will resolve the February 2011 Litigation. The comprehensive consent decree also sets technology selection and compliance dates for the outfalls in the ten permits included in the February 2011 Litigation on a staggered basis, allowing us to continue testing certain technologies as well as to take advantage of technology that is still in the development stage. See our discussion below in relation to the uncertainties experienced in making technology selections. The comprehensive consent decree separates the outfalls included in these ten NPDES permits into categories based on the average gallons

53

per minute water flow at each outfall. The comprehensive consent decree requires that we select water treatment technology alternatives by category beginning with the first category in September 2012 and ending with the last category in September 2014.
Additionally, we agreed to, among other things, come into compliance with applicable selenium discharge limits at each outfall in the category beginning with the first category within 24 months of the effective date of the agreement and ending with the last category within 60 months of the effective date of the agreement. We also agreed to, among other things, waive our rights to mine certain coal reserves and to pay $7.5 million in civil penalties. The plaintiffs agreed to, among other things, refrain from instituting new lawsuits with respect to the permits and outfalls identified in the comprehensive consent decree for certain periods, provided we meet the specified requirements. The comprehensive consent decree also established a framework under which we will interface with the plaintiffs with respect to the identified permits and outfalls. See the table below for additional details. The comprehensive consent decree will become effective upon entry by the U.S. District Court after the conclusion of a public comment period.
The amounts paid per the comprehensive consent decree of approximately $7.5 million and the write-off of the forfeited coal reserves of approximately $2.3 million are reflected in “Asset retirement obligation expense” in our consolidated statement of operations.
Category/Gallons Per Minute
Technology Selection Date
Projected Compliance Date
I / 0-200
September 1, 2012
24 months from the effective date of the agreement
II / 201-400
December 31, 2012
36 months from the effective date of the agreement
III / 401-600
March 31, 2013
45 months from the effective date of the agreement
IV / 601-1000
September 1, 2013
50 months from the effective date of the agreement
V / 1000 +
September 1, 2014
60 months from the effective date of the agreement
Selenium Water Treatment 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 installations to be implemented and maintained 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 water treatment strategy.
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.
As of December 31, 2011, we have a $135.5 million liability recorded for the treatment of selenium discharges related to the 78 outfalls acquired in the Magnum acquisition. The current portion of the estimated liability is $9.6 million and is included in “Accounts payable and accrued expenses” and the long-term portion is recorded in “Asset retirement obligations” on our consolidated balance sheets. This total liability is inclusive of the adjustments that were recorded in connection with the September 1, 2010 U.S. District Court Ruling described above.
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 have installed ZVI systems according to our original water treatment strategy, while also performing a further review of other potential water treatment solutions. Our water treatment strategy reflects implementing scalable ZVI installations at each of the other outfalls due to its modular design that can be reconfigured as further knowledge and certainty is gained. Initial pilot testing of ZVI technology began in 2008 and has identified potential shortfalls requiring additional research to resolve certain detailed design considerations. To date, ZVI technology has not been demonstrated to perform consistently and sustainably in achieving effluent selenium limitations or in treating the expected water flows at all outfalls. However, based on the flexibility of the scalable system for configuration adjustments, improvements in the system design and demonstrated success in reducing selenium at certain flows, we plan to continue to pursue the ZVI-based water treatment installations and determine whether modifications to the technology could result in its ability to treat selenium successfully at outlets identified in the February 2011 Litigation.

54

At this time, there is no definitive plan to install any technology other than ZVI-based technology at the other outfalls not included in the September 1, 2010 ruling as none of the other technologies has been proven effective on a full-scale basis. Our comprehensive consent decree with the plaintiffs in the February 2011 Litigation requires that we select water treatment technology by category beginning with the first category in September 2012 and ending with the last category in September 2014. We are continuing to research and evaluate various treatment solutions in addition to ZVI-based systems for the other outfalls. Results of pilot testing in the first half of 2011 indicated that ZVI-based systems, FBR and an additional technology may be viable selenium treatment options. We are continuing to test modifications to these treatment options and we are pilot testing alternative solutions. Alternative technology solutions that we may ultimately select are still in the early phases of development and their related costs can not be estimated at this time.
We continue to implement treatment installations at various permitted outfalls, but we have been unable to comply with selenium discharge limits due to the ongoing inability to identify a water treatment solution that can remove selenium sustainably, consistently and uniformly under all variable conditions experienced at our mining operations. While we are actively continuing to explore new treatment options and modifying existing technologies, a definitive solution has not been identified and it is unknown when or if such a solution will be identified. Even if a definitive solution would have existed as of December 31, 2011, it likely would not have been possible to install such technology at all of the outfalls included in the Hobet WVDEP Action by the July 2012 compliance deadline, and we are taking the requisite steps to seek an extension approved by the court.
If ZVI-based systems are not ultimately successful in treating the effluent selenium exceedances at the outfalls covered by the Hobet WVDEP Action and the February 2011 Litigation, we will be required to install alternative treatment solutions. The cost of other water treatment solutions could be materially higher than the costs reflected in our liability. Furthermore, costs associated with potential modifications to ZVI or the scale of our current ZVI-based systems could also cause the costs to be materially higher than the costs reflected in our liability. We cannot provide an estimate of the possible additional range of costs associated with alternate treatment solutions at this time as no solution has been proven to be effective on a full-scale commercial basis and we have not made any changes to our treatment plans for these outfalls as of December 31, 2011. Potential installations of selenium treatment alternatives are further complicated by the variable geological and topographical considerations of each individual outfall.
While we are actively continuing to explore treatment options, there can be no assurance as to if or 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 it becomes probable that we will utilize a different technology or modify the current technology, whether due to developments in our ongoing research, technology changes or modifications according to the comprehensive consent decree or other legal obligations to do so. Additionally, there are no assurances we will meet the timetable stipulated in the various court orders, consent decrees and permits.
General Clean Water Act Matters
With respect to all outfalls with known exceedances for selenium or any other parameter, 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 our permits could result in further litigation against us, an inability to obtain new permits or to maintain existing permits, which could impact our ability to mine our coal reserves, 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. The specific sites discussed above were created prior to the Magnum acquisition under legacy permitting standards and resulted in violations of current selenium requirements, which were promulgated in West Virginia in 2007.
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.

55

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 laws and related 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.
In the second action, motions to dismiss have been filed, asserting that the allegations 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 (Monsanto), Pharmacia Corporation and Akzo Nobel Chemicals, Inc., by certain plaintiffs in state court in Putnam County, West Virginia. In total, 243 similar lawsuits have been served on Apogee, which are identical except for the named plaintiff. Of the 243 lawsuits, 75 were served in February 2008, 167 were served in December 2009, and one was served in January 2011. 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, 2011, 47 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 were a defendant in litigation involving Peabody 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. In May 2011, we entered into a litigation settlement agreement with ELT and its subsidiaries.

56

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 approximately 140 related lawsuits filed in the Circuit Court of Boone County, West Virginia. In addition to our subsidiary, the lawsuits name Peabody and other coal companies as defendants. 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 installed public water lines and most of the plaintiffs now have access to public water. Pursuant to the terms of the Separation Agreement, Plan of Reorganization and Distribution from our 2007 spin-off, Patriot is indemnifying and defending Peabody in this litigation. The lawsuits have been settled and all settlement fees were paid in full in 2011.
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 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. We have not received any additional requests for information in 2011. In January 2012, the terminated employee filed a civil lawsuit against us alleging retaliatory discharge and intentional infliction of emotional distress. In addition, five employees filed a purported class action lawsuit against us and the terminated employee seeking compensation for lost wages, emotional distress, and punitive damages for the alleged intentional violation of employee safety at the mine. We deny the validity of the allegations and intend to vigorously defend both civil lawsuits.
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 95.1 of this report.

57

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 17, 2012, there were approximately 1,386 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
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

2011
 
 
 
 
First Quarter
 
$
29.20

 
$
19.68

Second Quarter
 
27.56

 
18.61

Third Quarter
 
24.99

 
8.45

Fourth Quarter
 
13.43

 
6.92

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.

58

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., James River Coal Co., Peabody Energy Corp., Walters Energy 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 our common stock.            
 
 
11/07
 
12/07
 
6/08
 
12/08
 
6/09
 
12/09
 
6/10
 
12/10
 
6/11
 
12/11
Patriot Coal
    Corp
 
100.00

 
111.31

 
408.77

 
33.33

 
34.03

 
82.45

 
62.67

 
103.31

 
118.72

 
82.45

S&P Smallcap
    600
 
100.00

 
91.84

 
85.33

 
63.30

 
63.73

 
79.49

 
78.79

 
100.4

 
107.97

 
79.49

Custom
    Composite
 
100.00

 
128.98

 
220.35

 
51.52

 
66.25

 
102.71

 
82.45

 
138.19

 
123.71

 
102.71

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 (the Exchange Act), 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 Exchange Act.

59

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. For periods prior to the spin-off in October 2007, 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, 2011 and the consolidated balance sheet data as of December 31, 2011 and 2010 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, 2009, 2008 and 2007 and the consolidated statements of operations for the years ended December 31, 2008 and 2007 were derived from audited consolidated financial statements that are not presented in this report.
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 year ended December 31, 2007 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.

60

 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
2008
 
2007
 
 
(In thousands, except for share and per share data)
Results of Operations Data:
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
 
 
Sales
 
$
2,378,260

 
$
2,017,464

 
$
1,995,667

 
$
1,630,873

 
$
1,069,316

Other revenues
 
24,246

 
17,647

 
49,616

 
23,749

 
4,046

Total revenues
 
2,402,506

 
2,035,111

 
2,045,283

 
1,654,622

 
1,073,362

Costs and expenses
 
 
 
 
 
 
 
 
 
 
Operating costs and expenses
 
2,213,124

 
1,900,704

 
1,893,419

 
1,607,746

 
1,109,315

Depreciation, depletion and amortization
 
186,348

 
188,074

 
205,339

 
125,356

 
85,640

Asset retirement obligation expense
 
81,586

 
63,034

 
35,116

 
19,260

 
20,144

Sales contract accretion
 
(55,020
)
 
(121,475
)
 
(298,572
)
 
(279,402
)
 
—

Restructuring and impairment charge
 
13,657

 
15,174

 
20,157

 
—

 
—

Selling and administrative expenses
 
52,907

 
50,248

 
48,732

 
38,607

 
45,137

Other operating (income) expense:
 
 
 
 
 
 
 
 
 
 
Net gain on disposal or exchange of assets(1)
 
(35,557
)
 
(48,226
)
 
(7,215
)
 
(7,004
)
 
(81,458
)
Loss (income) from equity affiliates(2)
 
(4,709
)
 
(9,476
)
 
(398
)
 
915

 
(63
)
Operating profit (loss)
 
(49,830
)
 
(2,946
)
 
148,705

 
149,144

 
(105,353
)
Interest expense and other
 
65,533

 
57,419

 
38,108

 
23,648

 
8,337

Interest income
 
(246
)
 
(12,831
)
 
(16,646
)
 
(17,232
)
 
(11,543
)
Income (loss) before income taxes
 
(115,117
)
 
(47,534
)
 
127,243

 
142,728

 
(102,147
)
Income tax provision
 
372

 
492

 
—

 
—

 
—

Net income (loss)
 
(115,489
)
 
(48,026
)
 
127,243

 
142,728

 
(102,147
)
Net income attributable to noncontrolling interest(2)
 
—

 
—

 
—

 
—

 
4,721

Net income (loss) attributable to Patriot
 
(115,489
)
 
(48,026
)
 
127,243

 
142,728

 
(106,868
)
Effect of noncontrolling interest purchase
   arrangement
 
—

 
—

 
—

 
—

 
(15,667
)
Net income (loss) attributable to common
   stockholders
 
$
(115,489
)
 
$
(48,026
)
 
$
127,243

 
$
142,728

 
$
(122,535
)
 
 
 
 
 
 
 
 
 
 
 
Earnings (loss) per share, basic
 
$
(1.26
)
 
$
(0.53
)
 
$
1.50

 
$
2.23

 
$
(2.29
)
Earnings (loss) per share, diluted
 
$
(1.26
)
 
$
(0.53
)
 
$
1.49

 
$
2.21

 
$
(2.29
)
Weighted average shares outstanding - basic
 
91,321,931

 
90,907,264

 
84,660,998

 
64,080,998

 
53,511,478

Weighted average shares outstanding - diluted
 
91,321,931

 
90,907,264

 
85,424,502

 
64,625,911

 
53,546,116

 
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
3,776,544

 
$
3,810,036

 
$
3,618,163

 
$
3,622,320

 
$
1,199,837

Total liabilities
 
3,110,393

 
2,966,955

 
2,682,669

 
2,782,139

 
1,117,521

Total long-term debt, less current maturities
 
441,064

 
451,529

 
197,951

 
176,123

 
11,438

Total stockholders’ equity
 
666,151

 
843,081

 
935,494

 
840,181

 
82,316


61

 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
2008
 
2007
 
 
(In thousands, except for share and per share data)
Other Data:
 
 
 
 
 
 
 
 
 
 
Tons sold (in millions and unaudited)
 
31.1

 
30.9

 
32.8

 
28.5

 
22.1

Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
124,737

 
$
36,311

 
$
39,611

 
$
63,426

 
$
(79,699
)
Investing activities
 
(92,923
)
 
(109,933
)
 
(77,593
)
 
(138,665
)
 
54,721

Financing activities
 
(30,719
)
 
239,591

 
62,208

 
72,128

 
30,563

Adjusted EBITDA(3)(unaudited)
 
176,741

 
141,861

 
110,745

 
44,238

 
431

Past mining obligation payments(4)(unaudited)
 
126,614

 
128,712

 
129,060

 
101,746

 
144,811

Additions to property, plant,
   equipment and mine
   development
 
174,713

 
122,989

 
78,263

 
121,388

 
55,594

Acquisitions, net
 
—

 
—

 
—

 
9,566

 
47,733

 
(1)
Net gain on disposal or exchange of assets included gains of $35.6 million from three coal reserve exchange transactions in 2011, $44.6 million in 2010 from five coal reserve exchange transactions and a $78.5 million gain in 2007 from the sales of coal reserves.
(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 increased 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.
(3)
Adjusted EBITDA as calculated below is defined as net income (loss) before deducting interest income and expense; income taxes; asset retirement 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.
(4)
Past mining obligation payments represents cash payments relating to our postretirement benefit obligations, workers' compensation obligations, and multi-employer retiree healthcare and pension plans.

62

Adjusted EBITDA is calculated as follows (unaudited):
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
2008
 
2007
 
 
(In thousands)
Net income (loss)
 
$
(115,489
)
 
$
(48,026
)
 
$
127,243

 
$
142,728

 
$
(102,147
)
Depreciation, depletion and
  amortization
 
186,348

 
188,074

 
205,339

 
125,356

 
85,640

Sales contract accretion, net(1)
 
(55,020
)
 
(121,475
)
 
(298,572
)
 
(249,522
)
 
—

Asset retirement obligation
  expense
 
81,586

 
63,034

 
35,116

 
19,260

 
20,144

Restructuring and impairment
  charge
 
13,657

 
15,174

 
20,157

 
—

 
—

Interest expense and other
 
65,533

 
57,419

 
38,108

 
23,648

 
8,337

Interest income
 
(246
)
 
(12,831
)
 
(16,646
)
 
(17,232
)
 
(11,543
)
Income tax provision
 
372

 
492

 
—

 
—

 
—

Adjusted EBITDA
 
$
176,741

 
$
141,861

 
$
110,745

 
$
44,238

 
$
431

 
(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. As of December 31, 2011, our operations consisted of fourteen active mining complexes, which include company-operated mines, contractor-operated mines and coal preparation facilities. In January 2012, we announced the idling of and production curtailment at certain metallurgical coal mines in response to weaker demand. In February 2012, we announced the closure of the Big Mountain mining complex in response to weaker thermal coal demand. 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 2011, we sold 31.1 million tons of coal, of which 76% was sold to domestic and global electricity generators and 24% was sold to domestic and global steel and 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. Export sales were 29% and 20% of our total volume in 2011 and 2010, respectively. 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 78% and 77% of our sales were under such contracts during 2011 and 2010, 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.

63

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; asset retirement obligation expense; depreciation, depletion and amortization; restructuring and impairment charge; and sales contract accretion.
Adjusted EBITDA is used by management primarily 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 net gain on disposal or exchange of assets and is reconciled to its most comparable measure below, under Net Loss. Adjusted EBITDA is reconciled to its most comparable measure under generally accepted accounting principles in Item 6. Selected Consolidated Financial Data.
Year ended December 31, 2011 compared to year ended December 31, 2010
Summary
Our Segment Adjusted EBITDA for the year ended December 31, 2011 increased compared to the prior year primarily due to higher average sales prices resulting from an increased mix of metallurgical coal and from improved market prices. This increase was partially offset by higher operating costs resulting from increased metallurgical coal production and sales, which generally have a higher average cost per ton. In addition, higher operating costs were impacted by geologic and equipment issues at certain mines, along with higher commodity prices.
In the third quarter of 2011, certain of our subsidiaries reached new agreements with the United Mine Workers of America (UMWA), which were effective July 1, 2011 and generally extend through December 2016. The new agreements are substantially the same as the National Bituminous Coal Wage Agreement negotiated earlier in 2011 between the Bituminous Coal Operators Association and the UMWA.
During the year ended December 31, 2011, asset retirement obligation expense increased by $17.0 million due to changes in our selenium water treatment technology selection for one of our outfalls and $9.9 million in relation to a comprehensive consent decree.
Interest expense and other increased in 2011 compared to 2010 due to additional interest expense related to long-term debt issued in May 2010 and a loss related to the early repayment in full of outstanding notes receivable in February 2011, partially offset by the reimbursement of letter of credit fees in the fourth quarter of 2011.
Interest income decreased in 2011 compared to 2010 due to the full repayment of the outstanding notes receivable in February 2011. Additional fluctuations between the year ended December 31, 2011 and the year ended December 31, 2010 are discussed in Net Loss below.
    

64

Segment Results of Operations
 
 
Year Ended December 31,
 
Increase (Decrease)
 
 
2011
 
2010
 
Tons/$
 
%
 
 
(Dollars and tons in thousands, except per ton amounts)
Tons Sold
 
 
 
 
 
 
 
 
Appalachia Mining Operations
 
23,861

 
24,276

 
(415
)
 
(1.7
)%
Illinois Basin Mining Operations
 
7,265

 
6,588

 
677

 
10.3
 %
Total Tons Sold
 
31,126

 
30,864

 
262

 
0.8
 %
Average sales price per ton sold
 
 
 
 
 
 
 
 
Appalachia Mining Operations
 
$
86.61

 
$
71.73

 
$
14.88

 
20.7
 %
Illinois Basin Mining Operations
 
42.89

 
41.90

 
0.99

 
2.4
 %
Revenue
 
 
 
 
 
 
 
 
Appalachia Mining Operations
 
$
2,066,639

 
$
1,741,430

 
$
325,209

 
18.7
 %
Illinois Basin Mining Operations
 
311,621

 
276,034

 
35,587

 
12.9
 %
Appalachia Other
 
24,246

 
17,647

 
6,599

 
37.4
 %
Total Revenues
 
$
2,402,506

 
$
2,035,111

 
$
367,395

 
18.1
 %
Segment Operating Costs and Expenses(1)
 
 
 
 
 
 
 
 
Appalachia Mining Operations and Other
 
$
1,704,545

 
$
1,442,753

 
$
261,792

 
18.1
 %
Illinois Basin Mining Operations
 
323,761

 
274,739

 
49,022

 
17.8
 %
Total Segment Operating Costs and Expenses
 
$
2,028,306

 
$
1,717,492

 
$
310,814

 
18.1
 %
Segment Adjusted EBITDA
 
 
 
 
 
 
 
 
Appalachia Mining Operations and Other
 
$
386,340

 
$
316,324

 
$
70,016

 
22.1
 %
Illinois Basin Mining Operations
 
(12,140
)
 
1,295

 
(13,435
)
 
(1,037.5
)%
Total Segment Adjusted EBITDA
 
$
374,200

 
$
317,619

 
$
56,581

 
17.8
 %
(1)Segment Operating Costs and Expenses represent consolidated operating costs and expenses of $2,213.1 million and $1,900.7 million less income from equity affiliates of $4.7 million and $9.5 million and past mining obligation expense of $180.1 million and $173.7 million for the years ended December 31, 2011 and 2010, respectively, as described below.
Tons Sold and Revenues
Revenues in the Appalachia segment were higher for the year ended December 31, 2011 compared to the prior year primarily due to higher average sales prices. Average sales prices increased 21% due to the increased amount of metallurgical coal sold and increased sales prices compared to 2010.
Total sales volumes in Appalachia decreased for the year ended December 31, 2011 compared to 2010 primarily resulting from decreased dragline activity at our Corridor G (Hobet) mining complex due to development delays in 2011 stemming from the prolonged approval timeframe for the Hobet 45 permit, dating back to late 2008. In addition, we purchased and sold fewer tons of brokered coal in 2011 compared to the prior year purchases of thermal coal to cover certain sales commitments at our Panther mining complex. These decreases were partially offset by increase in metallurgical coal production due to opening new mines.
Revenues in the Illinois Basin segment were higher for the year ended December 31, 2011 as compared to 2010 primarily due to higher sales volumes, as well as slightly higher average sales prices. Total sales volumes for the year ended December 31, 2011 were higher compared to the prior year primarily due to roof falls at our Highland mine in the second and third quarters of 2010.
Appalachia Other Revenue was higher for the year ended December 31, 2011 primarily due to the recognition of income as underlying tons were shipped from a coal purchase option sold in a prior year. Additionally, we monetized future coal reserve royalty payments for $2.2 million in the second quarter of 2011.

65

Segment Operating Costs and Expenses
Segment operating costs and expenses for Appalachia for the year ended December 31, 2011 increased as compared to the prior year in large part due to higher costs related to expanded metallurgical coal production and sales with the addition of several new mines and additional sections at existing mines. The higher costs included increased sales-related costs driven by higher sales prices. Operating costs were also higher due to difficult geology and equipment issues at certain mines. During the year ended December 31, 2011, we incurred higher equipment and material costs, including rebuilds and general repairs and maintenance ($88.2 million); increased labor costs ($43.4 million); higher contract mining services ($21.3 million); and higher royalties, sales-related taxes and leases ($51.9 million). Additionally, the year ended December 31, 2011 also had higher fuel and explosives costs ($17.3 million) related to higher commodity prices.
Segment operating costs and expenses for the Illinois Basin increased for the year ended December 31, 2011 as compared to the prior year due to developing new areas and higher production, as well as increased labor costs and higher commodity prices. During the year ended December 31, 2011, we incurred higher equipment and material costs, including rebuilds and general repairs and maintenance ($22.2 million); increased labor costs ($8.3 million); and higher fuel and explosives costs ($4.0 million). Additionally, we also had higher royalties and sales-related taxes ($1.8 million) for the year ended December 31, 2011.
Segment Adjusted EBITDA
Our Segment Adjusted EBITDA for Appalachia was higher for the year ended December 31, 2011 compared to the prior year primarily due to higher average sales prices resulting from an increased mix and higher selling prices of metallurgical coal, which was partially offset by higher operating costs.
Segment Adjusted EBITDA for the Illinois Basin decreased for the year ended December 31, 2011 from the prior year primarily due to increased operating costs and expenses as discussed above, partially offset by higher revenues as a result of increased production and sales volumes.
Net Loss
 
 
Year Ended December 31,
 
Favorable/
(Unfavorable)
 
 
2011
 
2010
 
$
 
%
 
 
(Dollars in thousands)
Segment Adjusted EBITDA
 
$
374,200

 
$
317,619

 
$
56,581

 
17.8
 %
Corporate and Other:
 
 
 
 
 
 
 
 
Past mining obligation expense
 
(180,109
)
 
(173,736
)
 
(6,373
)
 
(3.7
)%
Net gain on disposal or exchange of assets
 
35,557

 
48,226

 
(12,669
)
 
(26.3
)%
Selling and administrative expenses
 
(52,907
)
 
(50,248
)
 
(2,659
)
 
(5.3
)%
Total Corporate and Other
 
(197,459
)
 
(175,758
)
 
(21,701
)
 
(12.3
)%
Depreciation, depletion and amortization
 
(186,348
)
 
(188,074
)
 
1,726

 
0.9
 %
Asset retirement obligation expense
 
(81,586
)
 
(63,034
)
 
(18,552
)
 
(29.4
)%
Sales contract accretion
 
55,020

 
121,475

 
(66,455
)
 
(54.7
)%
Restructuring and impairment charge
 
(13,657
)
 
(15,174
)
 
1,517

 
10.0
 %
Interest expense and other
 
(65,533
)
 
(57,419
)
 
(8,114
)
 
(14.1
)%
Interest income
 
246

 
12,831

 
(12,585
)
 
(98.1
)%
Income tax provision
 
(372
)
 
(492
)
 
120

 
24.4
 %
Net loss
 
$
(115,489
)
 
$
(48,026
)
 
$
(67,463
)
 
(140.5
)%

66

Past Mining Obligation Expense
Past mining obligation expense was higher in 2011 compared to the prior year primarily due to the change in the discount rate assumption for our actuarially-determined liability for retiree healthcare, partially offset by lower funding rates for the UMWA healthcare benefit plans. In the third and fourth quarters of 2011, we also incurred costs related to the suspension of operations at a contractor-operated mine in the Big Mountain mining complex after we experienced a significant roof fall and other structural damages, believed to be the result of the earthquake centered near Washington D.C. in August 2011.
Net Gain on Disposal or Exchange of Assets
Net gain on disposal or exchange of assets was lower for the year ended December 31, 2011 compared to the prior year. In 2011, net gain on disposal or exchange of assets included gains of $18.7 million on a mineral rights exchange transaction in the fourth quarter, gains of $6.2 million on exchange and sale transactions for mineral interests in the third quarter, a gain of $7.3 million on a mineral rights exchange transaction and a gain of $2.1 million on a right of way purchase transaction in the second quarter. In 2010, net gain on disposal or exchange of assets included a gain of $2.9 million on an exchange transaction in the fourth quarter, a gain of $3.4 million on exchange transactions for mineral interests in the third quarter, gains of $14.3 million on two mineral rights exchange transactions in the second quarter and a gain of $24.0 million on an exchange transaction for mineral rights in the first quarter.
Selling and Administrative Expenses
Selling and administrative expenses increased for the year ended December 31, 2011 as compared to the prior year primarily due to a net increase in stock-based compensation expense resulting from a significant third quarter 2010 forfeiture.
Asset Retirement Obligation Expense
Asset retirement obligation expense increased for the year ended December 31, 2011 primarily due to increases to selenium water treatment obligations as a result of adjusting our estimated future costs of ongoing water treatment per the September 1, 2010 court ruling, as well as the amounts associated with a comprehensive consent decree. During the year ended December 31, 2011, asset retirement obligation expense increased by $17.0 million in adjustments to our liability due to changes in our selenium water treatment technology selection for one of our outfalls and $9.9 million in relation to a comprehensive consent decree. In the third quarter of 2010, additional asset retirement obligation expense of $20.7 million was recorded due to adjusting our estimated future costs of ongoing water treatment at three outfalls resulting from the requirements of the September 1, 2010 court ruling. In addition, reclamation expense increased primarily in the first and fourth quarters of 2011, due to certain mines closing earlier than previously scheduled. See Liquidity and Capital Resources for a more detailed description of the adjustments made in relation to selenium water treatment.
Sales Contract Accretion
Sales contract accretion decreased for the year ended December 31, 2011 as compared to the prior year primarily due to the expiration of several contracts assumed in the Magnum acquisition in the second half of 2010. We expect sales contract accretion to continue to decrease as the acquired below market sales contracts reach the end of their contract lives.
Restructuring and Impairment Charge
Restructuring and impairment charge for the year ended December 31, 2011 was comparable to the corresponding charge in the prior year. In 2011, we recorded an impairment charge of $13.6 million primarily related to the infrastructure and coal reserves impacted by mine closure decisions made in the fourth quarter of 2011. As coal demand and sales prices weakened in late 2011, we made the strategic decision to close certain high cost mines. In 2010, the charge related to the early closure of the Harris No. 1 mine in June 2010, resulting from adverse geologic conditions. The 2010 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 remaining operational contracts to be made with no future economic benefit.

67

Interest Expense and Other
Interest expense and other increased for the year ended December 31, 2011 primarily due to interest expense related 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 senior notes and the amended and restated credit agreement entered into in May 2010. In addition, in February 2011, outstanding notes receivable related to the 2006 and 2007 sales of coal reserves and surface land were repaid in full for $115.7 million prior to the scheduled maturity date. The early repayment resulted in a loss of $5.9 million. Offsetting this increase in expense was the collection of $5.5 million in letter of credit fee reimbursements related to the administration of healthcare claims for a third party covering the past four years in the fourth quarter of 2011.
Interest Income
Interest income decreased significantly for the year ended December 31, 2011 compared to the prior year primarily related to the early repayment of outstanding notes receivable in February 2011.
Income Tax Provision
For the years ended December 31, 2011 and 2010, we recorded an income tax provision of $0.4 million and $0.5 million, respectively, related to certain state taxes. In 2011 and 2010, we had federal tax net operating losses for each respective year and a full valuation allowance recorded against deferred tax assets. The primary difference between book and taxable income for 2011 and 2010 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, 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.

68

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.

69

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.
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
 %
Asset retirement obligation expense
 
(63,034
)
 
(35,116
)
 
(27,918
)
 
(79.5
)%
Sales contract accretion, net
 
121,475

 
298,572

 
(177,097
)
 
(59.3
)%
Restructuring and impairment charge
 
(15,174
)
 
(20,157
)
 
4,983

 
24.7
 %
Interest expense and other
 
(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 (loss)
 
$
(48,026
)
 
$
127,243

 
$
(175,269
)
 
(137.7
)%

70

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.
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.
Asset Retirement Obligation Expense
Asset retirement obligation expense increased for the year ended December 31, 2010 primarily due to the selenium water treatment obligations assumed in the July 2008 Magnum acquisition, which was recorded at fair value upon finalization of purchase accounting in June 2009. Additional selenium water treatment 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 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.

71

Interest Expense and Other
Interest expense and other 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.
Outlook
Market
We believe long-term fundamentals in coal markets remain intact. Seaborne metallurgical coal demand is expected to grow more than 170 million metric tons to 428 million by 2020, which is nearly 70% higher than the 2011 level. At the same time, seaborne thermal coal demand is expected to grow by 200 million, or more than 25%, to over 950 million metric tons, by 2020.
In the near-term, uncertainty in the marketplace is impacting coal demand worldwide. The demand for metallurgical coal, in particular, is dependent on the strength of global economies. Concerns over the pace of growth in China, the European financial crisis, and the strength of the U.S. recovery have caused pressure on steel demand. Even with these short-term concerns, U.S. coke plants were running near capacity and global steel mill percentage utilization remained in the mid-70s in early 2012. Even with weakened global economies, current metallurgical coal pricing in early 2012 remains high by historical standards.
In the thermal market, uncertainty over the U.S. economy and environmental regulations, weak natural gas prices and mild weather have led to reduced coal-fueled electricity generation and coal pricing. While implementation of CSAPR has been delayed by the courts, the future outcome of this rule remains unknown, as does the time frame for compliance. We believe that the domestic thermal market is likely to remain depressed for an extended period.
We believe that the globalization of coal markets will create opportunities, with demand from developing countries continuing to grow for both thermal and metallurgical coal. We believe U.S. metallurgical and thermal coal could increasingly be shipped overseas to satisfy the growing global demand. We believe the U.S. metallurgical and eastern thermal coals are well-positioned to participate in these export opportunities.
Patriot Operations
We anticipate 2012 sales volume in the range of 27 to 29 million tons, including metallurgical coal sales of 7.0 to 7.8 million tons. Given short-term market softness, we plan to reduce our production to preserve our high-quality coal until markets improve. Due to the uncertainty in the coal markets, our volume estimates for 2012 continue to evolve.
Headwinds created by low natural gas prices, mild weather and weaker international and domestic economies impacted coal markets during the year, and market weakness continues as we enter 2012. In early 2012, metallurgical coal demand trended downward, especially in export markets. At a time of weakness in international steel markets, buyers are seeking lower raw material costs. With more emphasis on cost and less emphasis on maximum production volume, coke makers can employ longer coking times, which enables them to use less premium-quality coking coal in their blends. In this operating environment, our Panther-type coals are enjoying increased domestic and international acceptance, given their attractive combination of quality and pricing characteristics. We have sold our Panther-type coals as metallurgical

72

product in major quantities for more than ten years, and we have been successful in ramping up these metallurgical coal sales substantially over the last three years.
We took actions in early 2012 to match our metallurgical production with expected sales volume. We reduced production of high-quality metallurgical coal capacity at both our Rocklick and Wells complexes, with particular emphasis on higher cost operations.
Our modular mine portfolio allows us the versatility to increase or decrease production in a timely manner in response to market conditions. We began our Met Build-Out program in 2011, with a goal of significantly higher metallurgical coal production to meet anticipated market demand. We have temporarily placed portions of our Met Build-Out program on hold. We intend to bring back on line much of the idled production, as well as resume our metallurgical coal expansion, when market conditions warrant.
In thermal coal markets, we anticipate that international markets will present profitable export opportunities in the future for Eastern U.S. coals. We aggressively sold thermal coal for 2012 delivery to European markets, and expect thermal exports in 2012 of approximately 6 to 7 million tons, or nearly twice our thermal exports in 2011.
Given the depressed domestic thermal coal market, we have conducted a rigorous review of our Central Appalachia thermal coal mine portfolio. As a result, we made the decision to close the Big Mountain mining complex effective February 2, 2012.
As of December 31, 2011, approximately 50% of our employees were represented by the UMWA. In late September 2011, certain of our subsidiaries signed new agreements with the UMWA, which generally extend through December 2016. The contracts are substantially the same as the NBCWA negotiated earlier in 2011 between the Bituminous Coal Operators Association and the UMWA.
As discussed more fully under Part 1, Item 1A. Risk Factors, our results of operations in the near-term could be negatively impacted by factors such as U.S. and international financial, economic and political conditions; coal price volatility and demand; unforeseen adverse geologic conditions or equipment problems at mining locations; reductions of purchases or deferral of deliveries by major customers; changes in general global economic conditions; availability and prices of competing energy resources for electricity generation; changes in the interpretation, enforcement or application of existing and potential laws and regulations affecting the production and use of our products; the availability and costs of credit, surety bonds and letters of credit; weather patterns and conditions affecting energy demand or disrupting supply; our ability to identify and implement cost effective solutions for selenium water treatment; 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 those related to selenium, and changes in the interpretation, enforcement or application thereof; failure to comply with debt covenants; 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; customer performance and credit risks; fluctuating prices of key supplies, mining equipment and commodities; 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 qualified personnel; negotiation of labor contracts, labor availability and relations;and our ability to find replacement buyers for coal under contracts with comparable or favorable terms to existing contracts.
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 some 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, current and future regulation of greenhouse gas and other air 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 could be negatively impacted. Management continues to focus on controlling costs, optimizing performance and responding quickly to market changes. Increased scrutiny by

73

regulators has resulted in more comprehensive inspections and has caused decreased production and increased costs. We expect this heightened regulatory oversight to continue.
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.

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 18 and 19 to our consolidated financial statements. Expense for the year ended December 31, 2011 for these liabilities totaled $164.8 million, while payments were $94.4 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
 
$
11,315

 
$
(9,363
)
Effect on (gain)/loss amortization component
 
34,804

 
(28,925
)
Effect on total postretirement benefit obligation
 
189,683

 
(158,180
)
Discount rate:
    
 
 
+0.5%
 
-0.5%
 
 
(Dollars in thousands)
Effect on total service and interest cost components
 
$
894

 
$
(1,371
)
Effect on (gain)/loss amortization component
 
(9,816
)
 
10,021

Effect on total postretirement benefit obligation
 
(86,685
)
 
92,122



74

Asset Retirement 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.
Our selenium water treatment obligations primarily consist of the estimated liability for water treatment in order to comply with selenium effluent limits included in certain mining permits. The fair value of this liability as determined in purchase accounting 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 decrease 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.
Asset retirement obligation expense for the year ended December 31, 2011 was $81.6 million, and payments totaled $13.8 million. See detailed information regarding our asset retirement obligations in Notes 17 and 23 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, 2011 and 2010, 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, 2011 and 2010, the unrecognized tax benefits, 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 14.

75

Revenue Recognition
In general, we recognize revenues when they are realizable and earned. We generated substantially all of our revenues in 2011 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 and ultra low sulfur diesel fuel contracts to manage our exposure to diesel fuel prices. The changes in diesel fuel prices and the prices for these financial instruments are highly correlated, thus allowing the swap contracts to be designated as cash flow hedges.
Share-Based Compensation
We have an equity incentive plan for certain eligible 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.
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.

76

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 and reclamation 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 $124.7 million for the year ended December 31, 2011, an increase of $88.4 million compared to the prior year. The increase in cash provided by operating activities primarily related to higher cash flows from operations of $38.2 million, primarily driven by higher metallurgical coal sales prices, and changes in working capital of $54.5 million, partially offset by a one-time surety deposit of $15.0 million. The $15.0 million surety deposit was posted with the U.S. Department of Labor (DOL) in 2011 in relation to certain of our occupational disease (Federal black lung) workers' compensation obligations. As part of our 2007 spin-off, Peabody had previously guaranteed with the DOL certain obligations related to our subsidiaries until they were fully transferred in 2011.
Net cash used in investing activities was $92.9 million for the year ended December 31, 2011, a decrease of $17.0 million compared to cash used in investing activities of $109.9 million in the prior year. The decrease in cash used in investing activities in 2011 reflected the early repayment of $115.7 million of our outstanding notes receivable in February 2011 as compared to the collection of $33.1 million in scheduled payments on the same notes receivable in 2010. The decrease in cash used was partially offset by cash paid in a litigation settlement of $14.8 million and an increase in capital expenditures of $51.7 million in 2011 primarily related to the build out of our metallurgical coal production. As part of a litigation settlement, we made a payment of $14.8 million, and ownership of the assets and liabilities from a 2005 sale reverted back to us. The assets include coal reserves in West Virginia and surface land in Illinois at closed mine sites. The liabilities include the reclamation obligations related to these assets.
Net cash used in financing activities was $30.7 million for the year ended December 31, 2011 compared to cash provided by financing activities of $239.6 million for the year ended December 31, 2010. In 2011, we made long-term debt payments of $31.0 million, primarily due to the purchase of the Blue Creek preparation plant which was formerly leased. In May 2010, we received proceeds of $248.2 million, net of discount, from our debt offering of 8.25% Senior Notes, as well as $17.7 million from a coal reserve financing transaction in June 2010. In 2010, the cash provided by financing activities was partially offset by deferred financing costs 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.
Selenium Water Treatment Obligations
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. 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 at these three outfalls by March 1, 2013. In September 2010, we increased the portion of the selenium water treatment liability related to Apogee by $20.7 million for the fair value of the estimated future ongoing operating costs related to these three outfalls. We record the costs to install the Apogee FBR water treatment facility as capital expenditures when incurred. As of December 31, 2011, we have spent approximately $12.6 million on the Apogee FBR facility and the total expenditures are estimated to be approximately $55 million. We began construction on the Apogee FBR facility in the third quarter of 2011.
Additionally, the U.S. District Court ordered Hobet to submit a proposed schedule to develop a treatment plan for a Hobet Surface Mine No. 22 outfall by October 1, 2010 and to come into compliance with applicable discharge limits under the permit by May 1, 2013. We submitted the required schedule, which included conducting additional pilot projects related to certain technological alternatives. A treatment technology to be utilized at this Hobet Surface Mine No. 22 outfall was filed with the U.S. District Court in June 2011 in accordance with the submitted schedule. In June 2011, we recorded an adjustment of $24.0 million to the selenium water treatment liability primarily related to the estimated future ongoing operating costs of an FBR water treatment facility at this outfall. This charge is reflected in “Asset retirement obligation expense” in the consolidated statement of operations.

77

In December 2011, the Special Master appointed by the U.S. District Court to oversee the Hobet Surface Mine No. 22 project approved Hobet's request to substitute ABMet selenium treatment technology for the FBR technology at this outfall. The U.S. District Court subsequently confirmed this substitution. As with the Apogee FBR facility, we will record the costs to install the Hobet ABMet water treatment facility as capital expenditures when incurred. We continue to design and seek permits for the Hobet ABMet facility and anticipate beginning construction on the facility in the first half of 2012. The estimated total expenditures for completing the ABMet water treatment facility is approximately $25 million, which is significantly less than the estimated $40 million to build the Hobet FBR facility.
In December 2011, we adjusted the portion of the selenium water treatment liability related to Hobet Surface Mine No. 22 by $10.3 million for the decrease in the fair value of the estimated future ongoing operating costs related to this outfall due to the change in the technology. We also wrote off approximately $3.0 million related to final engineering specifications for the Hobet FBR facility. These charges are reflected in “Asset retirement obligation expense” in our consolidated statement of operations.
FBR technology had not been used to remove selenium or any other minerals discharged at coal mining operations prior to our pilot project performed in 2010. The FBR water treatment facility required by the September 1, 2010 ruling will be the first facility constructed for selenium removal on a commercial scale. Neither FBR nor ABMet technology has been proven effective on a full-scale commercial basis at coal mining operations and there can be no assurance that either of these technologies will be successful under all variable conditions experienced at our mining operations.
February 2011 Litigation
In February 2011, OVEC and two other environmental groups filed a lawsuit against us, Apogee, Catenary and Hobet, in the U.S. District Court alleging violations of ten NPDES permits and certain SMCRA permits. We refer to this case as the February 2011 Action. The February 2011 Action involves the same four NPDES permits that are the subject of the Catenary WVDEP Action, the same Apogee permit that is the subject of the Apogee WVDEP Action, the same four NPDES permits that are the subject of the Hobet WVDEP Action and one additional NPDES permit held by Hobet that is not the subject of any action by WVDEP. The plaintiffs were seeking fines, compliance with permit limits and other requirements, and injunctive relief.
In late 2011, we substantially agreed to the terms of a settlement agreement with OVEC and the other environmental groups. On January 18, 2012, we finalized a comprehensive consent decree that, when entered by the U.S. District Court, will resolve the February 2011 Action. The comprehensive consent decree also sets technology selection and compliance dates for the outfalls in the ten permits included in the February 2011 Action on a staggered basis, allowing us to continue testing certain technologies as well as to take advantage of technology that is still in the development stage. The comprehensive consent decree separates the outfalls included in these ten NPDES permits into categories based on the average gallons per minute water flow at each outfall. The comprehensive consent decree requires that we select water treatment technology alternatives by category beginning with the first category in September 2012 and ending with the last category in September 2014.
Additionally, we agreed to, among other things, come into compliance with applicable selenium discharge limits at each outfall in the category beginning with the first category within 24 months of the effective date of the agreement and ending with the last category within 60 months of the effective date of the agreement. We also agreed to, among other things, waive our rights to mine certain coal reserves and to pay $7.5 million in civil penalties. The plaintiffs agreed to, among other things, refrain from instituting new lawsuits with respect to the permits and outfalls identified in the comprehensive consent decree for certain periods, provided we meet the specified requirements. The comprehensive consent decree also established a framework under which we will interface with the plaintiffs with respect to the identified permits and outfalls. See the table below for additional details. The comprehensive consent decree will become effective upon entry by the U.S. District Court after the conclusion of a public comment period.
The amounts paid per the comprehensive consent decree of $7.5 million and the write-off of the forfeited coal reserves of approximately $2.3 million are reflected in “Asset retirement obligation expense” in our consolidated statement of operations.
    

78

Category/Gallons Per Minute
Technology Selection Date
Projected Compliance Date
I / 0-200
September 1, 2012
24 months from the effective date of the agreement
II / 201-400
December 31, 2012
36 months from the effective date of the agreement
III / 401-600
March 31, 2013
45 months from the effective date of the agreement
IV / 601-1000
September 1, 2013
50 months from the effective date of the agreement
V / 1000 +
September 1, 2014
60 months from the effective date of the agreement
While we are actively continuing to explore treatment options, there can be no assurance as to if or 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 it becomes probable that we will utilize a different technology or modify the current technology, whether due to developments in our ongoing research, technology changes or modifications according to the comprehensive consent decree or other legal obligations to do so. Additionally, there are no assurances we will meet the timetable stipulated in the various court orders, consent decrees and permits.
Credit Facilities
Effective May 5, 2010, we entered into a $427.5 million amended and restated credit agreement with a maturity date of December 31, 2013. The credit facility provides for the issuance of letters of credit and direct borrowings. We incurred total fees of $10.9 million in relation to the amended and restated credit 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.
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. In January 2011 and 2012, we entered into amendments to the credit agreement which, among other things, modified certain limits and minimum requirements of our financial covenants. At December 31, 2011, 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.
Our credit facility contains financial covenants which require us to maintain specified ratios of Consolidated Interest Coverage and Consolidated Net Leverage (each as defined in the credit facility). Given the current state of global economic conditions, volatile financial markets, changing governmental regulation related to the production and use of our products, as well as competition from natural gas, there is a possibility that we may not be able to comply with our financial covenants. Failure to comply with our financial covenants would be an event of default under the terms of our credit facility and could result in the acceleration of the loans outstanding thereunder, and possibly all of our debt obligations.
If we are unable to comply with the financial covenants under our credit facility, we will be required to seek one or more amendments or waivers from our lenders. We believe that we would be able to obtain any required amendments or waivers, but can give no assurance that we would be able to do so on favorable terms, if at all. If we are unable to obtain any required amendments or waivers, our lenders would have the right to exercise the remedies specified in the credit facility documents, including accelerating the repayment of our debt and taking collection action against us, including proceeding against the collateral securing the credit facility.
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 accounts receivable to creditors as collateral for any borrowings. Available liquidity under the program fluctuates with the balance of our trade accounts receivable. The outstanding trade accounts receivable balance was $171.0 million and $146.6 million as of December 31, 2011 and 2010, respectively.

79

Based on our continuing involvement with the trade accounts receivable balances, including continued risk of loss, the sale of the trade accounts receivable 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 are recorded as secured debt.
Both the credit agreement and the accounts receivable securitization program (the facilities) are available for our working capital requirements, capital expenditures and other corporate purposes. As of December 31, 2011 and 2010, the balance of outstanding letters of credit issued against the credit facilities totaled $331.8 million and $355.3 million, respectively. There were no outstanding short-term borrowings against these facilities as of December 31, 2011 and 2010. Availability under these facilities was $220.7 million and $197.2 million as of December 31, 2011 and 2010, respectively.
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 were 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. For the years ended December 31, 2011 and 2010, interest expense for the senior notes was $20.9 million and $13.2 million, respectively.
Interest on the notes is payable semi-annually in arrears on April 30 and October 30 of each year. The notes mature on April 30, 2018, unless redeemed in accordance with their terms prior to such date. The notes are senior unsecured obligations, 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 notes may be redeemed at any time prior to April 30, 2014, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest and a “make-whole” premium as defined in the indentures. The notes may be redeemed on or after April 30, 2014 at certain redemption prices as defined in the indentures. In addition, up to 35% of the aggregate principal amount of the notes may be redeemed prior to April 30, 2013 at a redemption price equal to 108.25% of the principal amount thereof from the net proceeds of certain equity offerings.
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 Senior 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, including $25 million related to the underwriters' overallotment option. The net proceeds of the offering were $194 million after deducting the commissions and fees and expenses of the offering. We used the majority of 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.
We utilized an interest rate of 8.85% to reflect the nonconvertible market rate of our offering upon issuance, which resulted in a $45 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 $15.8 million, $15.1 million and $14.4 million for the years ended December 31, 2011, 2010 and 2009, respectively.

80

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, rank equally with all of our existing and future senior debt and are senior to any subordinated debt.
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.
Promissory Notes
In conjunction with an exchange transaction involving the acquisition of Illinois Basin coal reserves in 2005, we entered into promissory notes. The promissory notes and related interest are payable in annual installments of $1.7 million beginning January 2008. The promissory notes mature in January 2017. At December 31, 2011, the short-term portion of the promissory notes was $1.2 million.

81

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, 2011
 
 
Within 1
Year
 
2-3 Years
 
4-5 Years
 
After 5
Years
 
 
(Dollars in thousands)
Long-term debt obligations (principal and cash interest)
 
$
28,825

 
$
247,900

 
$
44,650

 
$
282,638

Operating lease obligations
 
57,213

 
85,194

 
24,175

 
763

Coal reserve lease and royalty obligations
 
34,547

 
73,217

 
44,916

 
94,073

Other long-term liabilities(1)
 
170,516

 
355,679

 
361,848

 
1,304,791

Total contractual cash obligations
 
$
291,101

 
$
761,990

 
$
475,589

 
$
1,682,265

 (1) Represents long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses and mine reclamation, selenium water treatment and end-of-mine closure costs.
As of December 31, 2011, we had $172.8 million of purchase obligations for capital expenditures. Of this amount, we have equipment totaling $115.2 million scheduled for delivery in 2012, with the remainder in subsequent years. We typically finance a significant portion of equipment through leasing arrangements. Total capital expenditures for 2012 are expected to range from $160 million to $180 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, 2011:
 
 
Asset
Retirement
Obligations
 
Workers’
Compensation
Obligations
 
Retiree
Health
Obligations
 
Other(1)
 
Total
 
 
(Dollars in thousands)
Surety bonds
 
$
185,649

 
$
44

 
$
—

 
$
9,408

 
$
195,101

Letters of credit
 
139,392

 
132,181

 
56,730

 
3,498

 
331,801

Third-party guarantees
 
—

 
—

 
—

 
7,536

 
7,536

 
 
$
325,041

 
$
132,225

 
$
56,730

 
$
20,442

 
$
534,438

(1) Includes collateral for surety companies and bank guarantees, road maintenance, lease obligations and performance guarantees.
As of December 31, 2011, Arch held surety bonds of $39.4 million related to properties acquired by Patriot in the Magnum acquisition, of which $38.5 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, 2011. Our obligation under the guarantee extends to September 2015.

82

In connection with the spin-off, Peabody assumed certain of Patriot’s retiree healthcare liabilities. The present value of these liabilities totaled $696.8 million as of December 31, 2011. These liabilities included certain obligations under the Coal Act for which Peabody and Patriot are jointly and severally liable, obligations under the 2007 NBCWA for which we are secondarily liable, and obligations for certain active, vested employees of Patriot.

Newly Adopted Accounting Pronouncements
Multiemployer Benefit Plans
In September 2011, the Financial Accounting Standards Board (FASB) issued authoritative guidance which increases the quantitative and qualitative disclosures an employer is required to provide about its participation in multiemployer benefit plans. We adopted this guidance effective December 31, 2011, with no effect on our results of operations or financial condition.
Comprehensive Income
In June 2011, the FASB issued authoritative guidance which requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. This guidance is effective for fiscal years beginning after December 15, 2011, and we will adopt it on January 1, 2012. While we are currently evaluating the impact on our disclosures and presentation of our financial statements, we do not believe this guidance will affect our results of operations or financial condition.


Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Commodity Price Risk
The potential for changes in the market value of our coal portfolio is referred to as “market risk.” Due to lack of quoted market prices and the long term, illiquid nature of the positions, we have not quantified market risk related to our portfolio of coal supply agreements. We manage our commodity price risk for our coal contracts through the use of long-term coal supply agreements, rather than through the use of derivative instruments. We sold 78% of our sales volume under coal supply agreements with terms of one year or more during 2011. As of December 31, 2011 our total unpriced planned production for 2012 was approximately 2 to 4 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, 2011, the notional amounts outstanding for these swaps included 13.1 million gallons of heating oil expiring throughout 2012, as well as 4.0 million gallons of ultra low sulfur diesel expiring in 2013. We expect to purchase approximately 24 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 $2.4 million.
Credit Risk
Approximately 10% of our accounts receivable balance at December 31, 2011 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 electricity generators and steelmakers, as well as Peabody.

83

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.

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 Chief Executive Officer and the Chief Financial Officer 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 Securities and Exchange Commission's rules and forms and were also effective to ensure that the information required to be disclosed by us in this Annual Report was accumulated and communicated to our management, including our principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
There have not been any significant changes in our internal control over financial reporting during the fiscal quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


84

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, 2011.
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 22, 2012


85

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, 2011.
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 22, 2012


86

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, 2011, 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, 2011, 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, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011, and our report dated February 22, 2012, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
St. Louis, Missouri
February 22, 2012

87

Item 9B. Other Information.
Effective February 22, 2012, the Company and Bennett K. Hatfield entered into an agreement to amend the non-competition provision of Mr. Hatfield's employment agreement. Under the amended agreement, Mr. Hatfield has agreed that he will not directly or indirectly engage in competition with the business of the Company or its subsidiaries during the period ending on the later of December 31, 2012 or the termination of his employment with the Company. Previously, Mr. Hatfield had been subject to a non-competition period of one year following the termination of his employment provided that he received from the Company, in addition to his regular severance, a payment equal to one year of base salary.
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 2011 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, Board Oversight of Risk and Committees of the Board, respectively, in our 2011 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 2011 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 2011 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, 2011:
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
 
1,666,254

 
$
15.35

 
6,723,367

Equity compensation plans not approved
  by security holders
 
N/A

 
N/A

 
N/A

Total
 
1,666,254

 
$
15.35

 
6,723,367

Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by Items 404 and 407(a) of Regulation S-K is included under the captions Certain Relationships and Related Party Transactions, Director Independence and Policy for Approval of Related Party Transactions in our 2011 Proxy Statement and is incorporated herein by reference.
Item 14. Principal Accountant 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 2011 Proxy Statement and is incorporated herein by reference.

88

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, 2011, 2010 and 2009
F-2
 
 
Consolidated Balance Sheets – December 31, 2011 and December 31, 2010
F-3
 
 
Consolidated Statements of Cash Flows – Years Ended December 31, 2011, 2010 and 2009
F-4
 
 
Consolidated Statements of Changes in Stockholders’ Equity – Years Ended December 31, 2011, 2010 and 2009
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-53
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.

89

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 22, 2012
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

President, Chief Executive Officer and
Director (principal executive officer)
February 22, 2012
Richard M. Whiting
 
 
 
/s/    MARK N. SCHROEDER
Senior Vice President and Chief Financial Officer (principal financial officer)
February 22, 2012
Mark N. Schroeder
 
 
 
/s/    CHRISTOPHER K. KNIBB
Vice President - Controller and Chief Accounting Officer (principal accounting officer)
February 22, 2012
Christopher K. Knibb
 
 
 
/s/    IRL F. ENGELHARDT
Chairman of the Board and Director
February 22, 2012
Irl F. Engelhardt
 
 
 
/s/    J. JOE ADORJAN
Director
February 22, 2012
J. Joe Adorjan
 
 
 
/s/    B. R. BROWN
Director
February 22, 2012
B. R. Brown
 
 
 
/s/    MICHAEL P. JOHNSON
Director
February 22, 2012
Michael P. Johnson
 
 
 
/s/    JANIECE M. LONGORIA
Director
February 22, 2012
Janiece M. Longoria
 
 
 
/s/    JOHN E. LUSHEFSKI
Director
February 22, 2012
John E. Lushefski
 
 
 
/s/    MICHAEL M. SCHARF
Director
February 22, 2012
Michael M. Scharf
 
 
 
/s/    ROBERT O. VIETS
Director
February 22, 2012
Robert O. Viets


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 Annual 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.)
 
 
 


Exhibit No.
 
Description of Exhibit
 
 
 
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
 
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.)
 
 
 
10.5
 
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.)
 
 
 
10.6
 
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.)
 
 
 
10.7
 
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.)
 
 
 
10.8
 
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.)
 
 
 
10.9
 
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.)
 
 
 
10.10
 
Indemnification Agreement, dated November 1, 2007, between Patriot Coal Corporation and J. Joe Adorjan. (Incorporated by reference to Exhibit 10.3 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 
10.11
 
Indemnification Agreement, dated November 1, 2007, between Patriot Coal Corporation and B. R. Brown. (Incorporated by reference to Exhibit 10.4 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 
10.12
 
Indemnification Agreement, dated November 1, 2007, between Patriot Coal Corporation and John E. Lushefski. (Incorporated by reference to Exhibit 10.5 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 
10.13
 
Indemnification Agreement, dated November 1, 2007, between Patriot Coal Corporation and Michael M. Scharf. (Incorporated by reference to Exhibit 10.6 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 


Exhibit No.
 
Description of Exhibit
 
 
 
10.14
 
Indemnification Agreement, dated November 1, 2007, between Patriot Coal Corporation and Robert O. Viets. (Incorporated by reference to Exhibit 10.7 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 
10.15
 
Indemnification Agreement, dated July 24, 2008, between Patriot Coal Corporation and Robb E. Turner. (Incorporated by reference to the Registrant's Current Report on Form 8-K, filed on July 28, 2008.)
 
 
 
10.16
 
Indemnification Agreement, dated July 24, 2008, between Patriot Coal Corporation and John E. Erhard. (Incorporated by reference to the Registrant's Current Report on Form 8-K, filed on July 28, 2008.)
 
 
 
10.17
 
Indemnification Agreement, dated July 24, 2008, between Patriot Coal Corporation and Michael P. Johnson. (Incorporated by reference to the Registrant's Current Report on Form 8-K, filed on July 28, 2008.)
 
 
 
10.18
 
Indemnification Agreement, dated January 27, 2011, between Patriot Coal Corporation and Janiece M. Longoria. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on January 28, 2011.)
 
 
 
10.19
 
Indemnification Agreement, dated November 1, 2007, between Patriot Coal Corporation and Irl F. Engelhardt. (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 
10.20
 
Indemnification Agreement, dated November 1, 2007, between Patriot Coal Corporation and Richard M. Whiting. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 
10.21
 
Employment Agreement, dated October 31, 2007, between Patriot Coal Corporation and Richard M. Whiting. (Incorporated by reference to Exhibit 10.9 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 
10.22
 
Indemnification Agreement, dated November 1, 2007, between Patriot Coal Corporation and Mark N. Schroeder. (Incorporated by reference to Exhibit 10.8 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 
10.23
 
Employment Agreement, dated October 31, 2007, between Patriot Coal Corporation and Mark N. Schroeder. (Incorporated by reference to Exhibit 10.10 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 
10.24
 
Employment Agreement, dated October 31, 2007, between Patriot Coal Corporation and Charles A. Ebetino, Jr. (Incorporated by reference to Exhibit 10.12 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 
10.25
 
Amendment to Employment Agreement between Patriot Coal Corporation and Charles A. Ebetino, Jr. (Incorporated by reference to the Registrant's Current Report on Form 8-K, filed on February 6, 2009.)
 
 
 
10.26
 
Employment Agreement, dated October 31, 2007, between Patriot Coal Corporation and Joseph W. Bean. (Incorporated by reference to Exhibit 10.13 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 
10.27
 
Amendment to Employment Agreement between Patriot Coal Corporation and Joseph W. Bean. (Incorporated by reference to the Registrant's Current Report on Form 8-K, filed on February 6, 2009.)
 
 
 
10.28
 
Employment Agreement, dated September 19, 2011, between Patriot Coal Corporation and Bennett K. Hatfield. (Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q, filed on November 2, 2011.)


Exhibit No.
 
Description of Exhibit
 
 
 
10.29
 
Patriot Coal Corporation Pledge and Security Agreement, dated October 31, 2007, among Patriot Coal Corporation, certain subsidiaries of Patriot Coal Corporation and Bank of America, N.A. (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed on October 31, 2007.)
 
 
 
10.30
 
Amended and Restated Credit Agreement dated as of May 5, 2010 among Patriot Coal Corporation, Bank of America, N.A., as Administrative Agent, L/C Issuer and Swing Line Lender, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on May 5, 2010.)
 
 
 
10.31
 
Amendment No. 1, dated as of January 6, 2011, to the Amended and Restated Credit Agreement dated as of May 5, 2010, among Patriot Coal Corporation, Bank of America, N.A., as administrative agent, L/C Issuer and Swing Line Lender, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on January 6, 2011.)
 
 
 
10.32
 
Amendment No. 2, dated as of January 31, 2012, to the Amended and Restated Credit Agreement dated as of May 5, 2010, among Patriot Coal Corporation, Bank of America, N.A., as administrative agent, L/C Issuer and Swing Line Lender, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on February 2, 2012.)
 
 
 
10.33
 
Purchase and Sale Agreement, dated as of March 2, 2010, among the Originators referred to therein, as sellers, Patriot Coal Corporation and Patriot Coal Receivables (SPV) Ltd. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on March 4, 2010.)
 
 
 
10.34
 
Receivables Purchase Agreement, dated as of March 2, 2010, among Patriot Coal Receivables (SPV) Ltd., Patriot Coal Corporation, as Servicer, the LC Participants, Related Committed Purchasers, Uncommitted Purchasers and Purchaser Agents parties thereto from time to time and Fifth Third Bank, as Administrator and as issuer of letters of credit. (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed on March 4, 2010.)
 
 
 
10.35
 
Purchase Agreement, dated May 21, 2008 by and among Patriot Coal Corporation and Citigroup Global Markets Inc. and Lehman Brothers Inc. (Incorporated by reference to the Registrant's Current Report on Form 8-K, filed on May 23, 2008.)
 
 
 
10.36
 
Patriot Coal Corporation 2007 Long-Term Equity Incentive Plan. (Incorporated by reference to Exhibit 10.17 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
 
 
 
10.37
 
First Amendment to the Patriot Coal Corporation 2007 Long-Term Equity Incentive Plan. (Incorporated by reference to Exhibit 10.46 of the Registrant's Annual Report on Form 10-K, filed on February 25, 2011.)
 
 
 
10.38
 
Patriot Coal Corporation Management Annual Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.19 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
 
 
 
10.39
 
Form of Non-Qualified Stock Option Agreement under the Patriot Coal Corporation 2007 Long-Term Equity Incentive Plan. (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed on October 29, 2007.)
 
 
 
10.40
 
Form of Restricted Stock Unit Agreement under the Patriot Coal Corporation 2007 Long-Term Equity Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on October 29, 2007.)
 
 
 


Exhibit No.
 
Description of Exhibit
 
 
 
10.41
 
Form of Restricted Stock Award Agreement under the Patriot Coal Corporation 2007 Long-Term Equity Incentive Plan. (Incorporated by reference to Exhibit 10.3 of the Registrant's Current Report on Form 8-K, filed on October 29, 2007.)
 
 
 
10.42
 
Form of Restricted Stock Award Agreement for use in connection with awards under the Patriot Coal Corporation 2007 Long-Term Equity Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on January 4, 2010.)
 
 
 
10.43
 
Form of Restricted Stock Award Agreement for use in connection with awards under the Patriot Coal Corporation 2007 Long-Term Equity Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on January 9, 2012.)
 
 
 
10.44
 
Form of Deferred Stock Unit Award Agreement under the Patriot Coal Corporation 2007 Long-Term Equity Incentive Plan. (Incorporated by reference to Exhibit 10.4 of the Registrant's Current Report on Form 8-K, filed on October 29, 2007.)
 
 
 
10.45
 
Form of Performance-Based Restricted Stock Units Award Agreement for use in connection with awards under the Patriot Coal Corporation 2007 Long-Term Equity Incentive Plan. (Incorporated by reference to the Registrant's Current Report on Form 8-K, filed on January 30, 2009.)
 
 
 
10.46
 
Form of Non-Qualified Stock Option Agreement for use in connection with awards under the Patriot Coal Corporation 2007 Long-Term Equity Incentive Plan. (Incorporated by reference to the Registrant's Current Report on Form 8-K, filed on January 30, 2009.)
 
 
 
10.47
 
Patriot Coal Corporation Employee Stock Purchase Plan. (Incorporated by reference to Exhibit 10.18 of the Registrant's Current Report on Form 8-K, filed on October 25, 2007.)
 
 
 
10.48
 
First Amendment to the Patriot Coal Corporation Employee Stock Purchase Plan. (Incorporated by reference to Exhibit 10.63 of the Registrant's Annual Report on Form 10-K, filed on February 24, 2010.)
 
 
 
10.49
 
Second Amendment to the Patriot Coal Corporation Employee Stock Purchase Plan. (Incorporated by reference to Exhibit 10.64 of the Registrant's Annual Report on Form 10-K, filed on February 24, 2010.)
 
 
 
10.50
 
Third Amendment to the Patriot Coal Corporation Employee Stock Purchase Plan. (Incorporated by reference to Exhibit 10.65 of the Registrant's Annual Report on Form 10-K, filed on February 24, 2010.)
 
 
 
10.51
 
Fourth Amendment to the Patriot Coal Corporation Employee Stock Purchase Plan. (Incorporated by reference to Exhibit 10.59 of the Registrant's Annual Report on Form 10-K, filed on February 25, 2011.)
 
 
 
10.52
 
Fifth Amendment to the Patriot Coal Corporation Employee Stock Purchase Plan. (Incorporated by reference to Exhibit 10.60 of the Registrant's Annual Report on Form 10-K, filed on February 25, 2011.)
 
 
 
10.53
 
Patriot Coal Corporation 401(k) Retirement Plan, as Amended and Restated. (Incorporated by reference to Exhibit 10.61 of the Registrant's Annual Report on Form 10-K, filed on February 25, 2011.)
 
 
 
10.54
 
Patriot Coal Corporation Supplemental 401(k) Retirement Plan. (Incorporated by reference to Exhibit 10.16 of the Registrant's Current Report on Form 8-K, filed on November 6, 2007.)
 
 
 


Exhibit No.
 
Description of Exhibit
 
 
 
10.55
 
First Amendment to the Patriot Coal Corporation Supplemental 401(k) Retirement Plan. (Incorporated by reference to Exhibit 10.63 of the Registrant's Annual Report on Form 10-K, filed on February 25, 2011.)
 
 
 
10.56
 
Second Amendment to the Patriot Coal Corporation Supplemental 401(k) Retirement Plan. (Incorporated by reference to Exhibit 10.64 of the Registrant's Annual Report on Form 10-K, filed on February 25, 2011.)
 
 
 
10.57
 
Third Amendment to the Patriot Coal Corporation Supplemental 401(k) Retirement Plan. (Incorporated by reference to Exhibit 10.65 of the Registrant's Annual Report on Form 10-K, filed on February 25, 2011.)
 
 
 
10.58
 
Fourth Amendment to the Patriot Coal Corporation Supplemental 401(k) Retirement Plan. (Incorporated by reference to Exhibit 10.66 of the Registrant's Annual Report on Form 10-K, filed on February 25, 2011.)
 
 
 
10.59
 
Consent Decree between Ohio Valley Environmental Coalition, Inc., West Virginia Highlands Conservancy, Inc. and Sierra Club and Patriot Coal Corporation, Apogee Coal Company, LLC, Catenary Coal Company, LLC and Hobet Mining, LLC. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on January 23, 2012.)
 
 
 
10.60*
 
Amendment to Employment Agreement between Patriot Coal Corporation and Bennett K. Hatfield.
 
 
 
21.1*
 
List of Subsidiaries
 
 
 
23.1*
 
Consent of Independent Registered Accounting Firm
 
 
 
31.1*
 
Certification of periodic financial report by Patriot Coal Corporation's Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
31.2*
 
Certification of periodic financial report by Patriot Coal Corporation's Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
32.1*
 
Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Patriot Coal Corporation's Chief Executive Officer.
 
 
 
32.2*
 
Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Patriot Coal Corporation's Chief Financial Officer.
 
 
 
95.1*
 
Mine Safety Disclosure Exhibit
 
 
 
99.1
 
Patriot Coal Corporation Rights Adjustment Certificate dated July 28, 2008. (Incorporated by reference to Exhibit 99.4 of the Registrant's Current Report on Form 8-K, filed on July 28, 2008).
 
 
 
101**
 
Interactive Data Files pursuant to Rule 405 of Regulation S-T: (i) the Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009, (ii) the Consolidated Balance Sheets as of December 31, 2011 and 2010, (iii) the Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009, (iv) the Consolidated Statements of Changes in Stockholders' Equity for the Years Ended December 31, 2011, 2010 and 2009 and (v) the Notes to the Consolidated Financial Statements.


*
Filed herewith.
**
Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.





Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Patriot Coal Corporation
We have audited the accompanying consolidated balance sheets of Patriot Coal Corporation as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Patriot Coal Corporation at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Patriot Coal Corporation’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 22, 2012, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
St. Louis, Missouri
February 22, 2012

F-1


PATRIOT COAL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(Dollars in thousands, except share and per share data)
Revenues
 
 
 
 
 
 
Sales
 
$
2,378,260

 
$
2,017,464

 
$
1,995,667

Other revenues
 
24,246

 
17,647

 
49,616

Total revenues
 
2,402,506

 
2,035,111

 
2,045,283

Costs and expenses
 
 
 
 
 
 
Operating costs and expenses
 
2,213,124

 
1,900,704

 
1,893,419

Depreciation, depletion and amortization
 
186,348

 
188,074

 
205,339

Asset retirement obligation expense
 
81,586

 
63,034

 
35,116

Sales contract accretion
 
(55,020
)
 
(121,475
)
 
(298,572
)
Restructuring and impairment charge
 
13,657

 
15,174

 
20,157

Selling and administrative expenses
 
52,907

 
50,248

 
48,732

Net gain on disposal or exchange of assets
 
(35,557
)
 
(48,226
)
 
(7,215
)
Income from equity affiliates
 
(4,709
)
 
(9,476
)
 
(398
)
Operating profit (loss)
 
(49,830
)
 
(2,946
)
 
148,705

Interest expense and other
 
65,533

 
57,419

 
38,108

Interest income
 
(246
)
 
(12,831
)
 
(16,646
)
Income (loss) before income taxes
 
(115,117
)
 
(47,534
)
 
127,243

Income tax provision
 
372

 
492

 
—

Net income (loss)
 
$
(115,489
)
 
$
(48,026
)
 
$
127,243

 
 
 
 
 
 
 
Weighted average shares outstanding:
 
 
 
 
 
 
Basic
 
91,321,931

 
90,907,264

 
84,660,998

Effect of dilutive securities
 
—

 
—

 
763,504

Diluted
 
91,321,931

 
90,907,264

 
85,424,502

 
 
 
 
 
 
 
Earnings (loss) per share:
 
 
 
 
 
 
Basic
 
$
(1.26
)
 
$
(0.53
)
 
$
1.50

Diluted
 
$
(1.26
)
 
$
(0.53
)
 
$
1.49


F-2

PATRIOT COAL CORPORATION
CONSOLIDATED BALANCE SHEETS
 
 
 
December 31,
 
 
2011
 
2010
 
 
(Dollars in thousands, except
 share data)
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
194,162

 
$
193,067

Accounts receivable and other, net of allowance for doubtful accounts of $138 and
   $141 as of December 31, 2011 and 2010, respectively
 
177,695

 
207,365

Inventories
 
98,366

 
97,973

Prepaid expenses and other current assets
 
28,191

 
28,648

Total current assets
 
498,414

 
527,053

Property, plant, equipment and mine development
 
 
 
 
Land and coal interests
 
2,935,796

 
2,870,182

Buildings and improvements
 
504,275

 
439,326

Machinery and equipment
 
748,013

 
679,429

Less accumulated depreciation, depletion and amortization
 
(973,157
)
 
(828,402
)
Property, plant, equipment and mine development, net
 
3,214,927

 
3,160,535

Notes receivable
 
—

 
69,540

Investments and other assets
 
63,203

 
52,908

Total assets
 
$
3,776,544

 
$
3,810,036

 
 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable and accrued expenses
 
$
459,694

 
$
409,284

Below market sales contracts acquired
 
44,787

 
70,917

Current portion of debt
 
1,182

 
3,329

Total current liabilities
 
505,663

 
483,530

Long-term debt, less current maturities
 
441,064

 
451,529

Asset retirement obligations
 
417,900

 
349,791

Workers’ compensation obligations
 
231,585

 
220,757

Postretirement benefit obligations
 
1,387,317

 
1,269,168

Obligation to industry fund
 
35,429

 
38,978

Below market sales contracts acquired, noncurrent
 
46,217

 
92,253

Other noncurrent liabilities
 
45,218

 
60,949

Total liabilities
 
3,110,393

 
2,966,955

Stockholders’ equity
 
 
 
 
Common stock ($0.01 par value; 300,000,000 shares authorized; 91,885,338 and 90,944,595 shares issued and outstanding at December 31, 2011 and 2010, respectively)
 
919

 
909

Preferred stock ($0.01 par value; 10,000,000 shares authorized; no shares issued and outstanding at December 31, 2011 and 2010)
 
—

 
—

Series A Junior Participating Preferred Stock ($0.01 par value; 1,000,000 shares authorized; no shares issued and outstanding at December 31, 2011 and 2010)
 
—

 
—

Additional paid-in capital
 
977,169

 
961,285

Retained earnings
 
73,093

 
188,582

Accumulated other comprehensive loss
 
(385,030
)
 
(307,695
)
Total stockholders’ equity
 
666,151

 
843,081

Total liabilities and stockholders’ equity
 
$
3,776,544

 
$
3,810,036


F-3


PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PATRIOT COAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(Dollars in thousands)
Cash Flows From Operating Activities
 
 
 
 
 
 
Net income (loss)
 
$
(115,489
)
 
$
(48,026
)
 
$
127,243

Adjustments to reconcile net income (loss) to net cash provided
   by operating activities:
 
 
 
 
 
 
Depreciation, depletion and amortization
 
186,348

 
188,074

 
205,339

Amortization of deferred financing costs
 
7,356

 
6,412

 
3,700

Amortization of debt discount
 
9,543

 
8,710

 
7,864

Sales contract accretion
 
(55,020
)
 
(121,475
)
 
(298,572
)
Impairment charge
 
13,093

 
2,823

 
12,949

Selenium-related asset write-offs
 
5,369

 
—

 
—

Loss on early payment of note receivable
 
5,868

 
—

 
—

Net gain on disposal or exchange of assets
 
(35,557
)
 
(48,226
)
 
(7,215
)
Income from equity affiliates
 
(4,709
)
 
(9,476
)
 
(398
)
Distributions from equity affiliates
 
3,219

 
5,095

 
1,000

Stock-based compensation expense
 
13,779

 
11,657

 
13,852

Changes in current assets and liabilities:
 
 
 
 
 
 
Accounts receivable
 
(22,336
)
 
(59
)
 
(3,565
)
Inventories
 
(393
)
 
(16,785
)
 
(6,530
)
Other current assets
 
(1,161
)
 
(15,172
)
 
903

Accounts payable and accrued expenses
 
22,125

 
(24,258
)
 
(38,867
)
Interest on notes receivable
 
—

 
(12,652
)
 
(14,030
)
Asset retirement obligations
 
52,042

 
38,719

 
14,988

Workers’ compensation obligations
 
8,580

 
12,343

 
4,470

Accrued postretirement benefit costs
 
58,871

 
50,944

 
26,248

Obligation to industry fund
 
(3,278
)
 
(2,769
)
 
(3,019
)
Federal black lung collateralization
 
(14,990
)
 
—

 
—

Other, net
 
(8,523
)
 
10,432

 
(6,749
)
Net cash provided by operating activities
 
124,737

 
36,311

 
39,611

Cash Flows From Investing Activities
 
 
 
 
 
 
Additions to property, plant, equipment and mine development
 
(174,713
)
 
(122,989
)
 
(78,263
)
Proceeds from notes receivable
 
115,679

 
33,100

 
11,000

Additions to advance mining royalties
 
(26,030
)
 
(21,510
)
 
(16,997
)
Net cash paid in litigation settlement and asset acquisition
 
(14,787
)
 
—

 
—

Proceeds from disposal or exchange of assets
 
6,928

 
1,766

 
5,513

Other
 
—

 
(300
)
 
1,154

Net cash used in investing activities
 
(92,923
)
 
(109,933
)
 
(77,593
)
Cash Flows From Financing Activities
 
 
 
 
 
 
Proceeds from debt offering, net of discount
 
—

 
248,198

 
—

Proceeds from coal reserve financing transaction
 
—

 
17,700

 
—

Deferred financing costs
 
(1,832
)
 
(20,740
)
 
—

Long-term debt payments
 
(31,002
)
 
(8,042
)
 
(5,905
)
Proceeds from equity offering, net of costs
 
—

 
—

 
89,077

Short-term debt payments
 
—

 
—

 
(23,000
)
Proceeds from employee stock programs
 
2,115

 
2,475

 
2,036

Net cash provided by (used in) financing activities
 
(30,719
)
 
239,591

 
62,208

Net increase in cash and cash equivalents
 
1,095

 
165,969

 
24,226

Cash and cash equivalents at beginning of period
 
193,067

 
27,098

 
2,872

Cash and cash equivalents at end of period
 
$
194,162

 
$
193,067

 
$
27,098


F-4

PATRIOT COAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
 
 
 
Common
Stock
 
Additional
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Total
 
 
(Dollars in thousands)
December 31, 2008
 
$
774

 
$
842,323

 
$
109,365

 
$
(112,281
)
 
$
840,181

Net income
 
—

 
—

 
127,243

 
—

 
127,243

Postretirement plans and workers’
  compensation obligations (net of taxes
  of $0)
 
—

 
—

 
—

 
(147,625
)
 
(147,625
)
Changes in diesel fuel hedge
 
—

 
—

 
—

 
10,730

 
10,730

Total comprehensive loss
 
 
 
 
 
 
 
 
 
(9,652
)
Issuance of 12,000,000 shares of common
  stock from equity offering
 
120

 
88,957

 
—

 
—

 
89,077

Stock-based compensation
 
—

 
13,852

 
—

 
—

 
13,852

Employee stock purchases
 
3

 
2,033

 
—

 
—

 
2,036

Stock grants to employees
 
6

 
(6
)
 
—

 
—

 
—

December 31, 2009
 
903

 
947,159

 
236,608

 
(249,176
)
 
935,494

Net loss
 
—

 
—

 
(48,026
)
 
—

 
(48,026
)
Postretirement plans and workers’
  compensation obligations (net of taxes
  of $0)
 
—

 
—

 
—

 
(59,352
)
 
(59,352
)
Changes in diesel fuel hedge
 
—

 
—

 
—

 
833

 
833

Total comprehensive loss
 
 
 
 
 
 
 
 
 
(106,545
)
Stock-based compensation
 
—

 
11,657

 
—

 
—

 
11,657

Employee stock purchases
 
3

 
2,472

 
—

 
—

 
2,475

Stock grants to employees
 
3

 
(3
)
 
—

 
—

 
—

December 31, 2010
 
909

 
961,285

 
188,582

 
(307,695
)
 
843,081

Net loss
 
—

 
—

 
(115,489
)
 
—

 
(115,489
)
Postretirement plans and workers’
  compensation obligations (net of taxes
  of $0)
 
—

 
—

 
—

 
(75,651
)
 
(75,651
)
Changes in diesel fuel hedge
 
—

 
—

 
—

 
(1,684
)
 
(1,684
)
Total comprehensive loss
 
 
 
 
 
 
 
 
 
(192,824
)
Stock-based compensation
 
—

 
13,779

 
—

 
—

 
13,779

Employee stock purchases
 
2

 
2,113

 
—

 
—

 
2,115

Stock grants to employees
 
8

 
(8
)
 
—

 
—

 
—

December 31, 2011
 
$
919

 
$
977,169

 
$
73,093

 
$
(385,030
)
 
$
666,151


F-5
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)Basis of Presentation
Description of Business
Effective October 31, 2007, Patriot Coal Corporation (we, our, Patriot or the Company) was spun-off from Peabody Energy Corporation (Peabody) and became a separate, public company traded on the New York Stock Exchange (symbol PCX). The spin-off from Peabody was accomplished through a dividend of all outstanding shares of Patriot.
Patriot is engaged in 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 coke producers. Our mining complexes and coal reserves are located in the eastern and midwestern United States (U.S.), primarily in West Virginia and Kentucky.
We acquired Magnum Coal Company (Magnum) effective July 23, 2008. 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.
Basis of Presentation
The consolidated financial statements include the accounts of Patriot and its majority-owned subsidiaries. All significant transactions, profits and balances have been eliminated between Patriot and its subsidiaries. Patriot operates in two domestic coal segments; Appalachia and the Illinois Basin. See Note 24 for additional information.

(2)Summary of Significant Accounting Policies
Sales
Revenues from coal sales are realized and earned when risk of loss passes to the customer. Coal sales are made to customers under the terms of supply agreements. The majority of our coal sales are made pursuant to long-term agreements (one year or more). Under the typical terms of these coal supply agreements, title and risk of loss transfer to the customer at the mine, preparation plant or river terminal or port, where coal is loaded onto the rail, barge, truck, ocean-going vessel or other transportation source that delivers coal to its destination. Shipping and transportation costs are generally borne by the customer. In relation to export sales, we hold inventories at port facilities where title and risk of loss do not transfer until the coal is loaded into an ocean-going vessel. We incur certain “add-on” taxes and fees on coal sales. Coal sales are reported including taxes and fees charged by various federal and state governmental bodies.
Other Revenues
Other revenues include payments from customer settlements, royalties related to coal lease agreements and farm income. During 2009, certain metallurgical and thermal customers requested shipment deferrals on committed tons. In certain situations, we agreed to release the customers from receipt of the tons in exchange for a cash settlement. During 2009, these cash settlements represented a significant portion of other revenues. Royalty income generally results from the lease or sublease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced. Certain agreements require minimum annual lease payments regardless of the extent to which minerals are produced from the leasehold, although revenue is only recognized on these payments as the mineral is mined. The terms of these agreements generally range from specified periods of 5 to 15 years, or can be for an unspecified period until all reserves are depleted.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.
Accounts Receivable
Accounts receivable are recorded at the invoiced amount and do not bear interest. Allowance for doubtful accounts was approximately $138,000 and $141,000 at December 31, 2011 and 2010, respectively, and reflects specific amounts for which the risk of collection has been identified based on the current economic environment and circumstances of which we are aware. Account balances are written-off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

F-6
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Inventories
Materials and supplies and coal inventory are valued at the lower of average cost or market. Saleable coal represents coal stockpiles that will be sold in current condition. Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Coal inventory costs include labor, supplies, equipment, operating overhead and other related costs.
Property, Plant, Equipment and Mine Development
Property, plant, equipment and mine development are recorded at cost, or at fair value at the date of acquisition in the case of acquired businesses. Interest costs applicable to major asset additions are capitalized during the construction period. Capitalized interest in 2011, 2010 and 2009 was immaterial.
Expenditures which extend the useful lives of existing plant and equipment assets are capitalized. Maintenance and repairs are charged to operating costs as incurred. Costs incurred to develop coal mines or to expand the capacity of operating mines are capitalized. Costs incurred to maintain current production capacity at a mine and exploration expenditures are charged to operating costs as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves. Costs to acquire computer hardware and the development and/or purchase of software for internal use are capitalized and depreciated over the estimated useful lives.
Coal reserves are recorded at cost or at fair value at the date of acquisition in the case of acquired businesses. Coal reserves are included in “Land and coal interests” on the consolidated balance sheets. As of December 31, 2011 and 2010, the book value of coal reserves totaled $2.6 billion and $2.6 billion, including $1.8 billion and $1.6 billion, respectively, attributable to properties where we were not currently engaged in mining operations or leasing to third parties and, therefore, not currently depleting the related coal reserves. Included in the book value of coal reserves are mineral rights for leased coal interests, including advance royalties. The book value of these mineral rights was $2.3 billion and $2.3 billion at December 31, 2011 and 2010, respectively, with the remaining $0.3 billion of book value related to coal reserves held by fee ownership.
Depletion of coal reserves and amortization of advance royalties are computed using the units-of-production method utilizing only proven and probable reserves (as adjusted for recoverability factors) in the depletion base. Mine development costs are principally amortized ratably over the estimated lives of the mines.
Depreciation of plant and equipment (excluding life of mine assets) is computed ratably over the estimated useful lives as follows:  
 
  
Years
Buildings and improvements
  
10 to 20
Machinery and equipment
  
3 to 30
Leasehold improvements
  
Shorter of life of asset, mine or lease
In addition, certain plant and equipment assets associated with mining are depreciated ratably over the estimated life of the mine. Remaining lives vary from less than one year up to 26 years. The charge against earnings for depreciation of property, plant, equipment and mine development was $96.6 million, $100.8 million and $113.4 million for the years ended December 31, 2011, 2010 and 2009, respectively.
Joint Ventures
We apply the equity method to investments in joint ventures when we have the ability to exercise significant influence over the operating and financial policies of the joint venture. We review the documents governing each joint venture to assess if we have a controlling financial interest in the joint venture to determine if the equity method is appropriate or if the joint venture should be consolidated. We performed a qualitative assessment of our existing interests and determined that we held no interest in variable interest entities. Investments accounted for under the equity method are initially recorded at cost.
Sales Contract Liability
In connection with the Magnum acquisition, we recorded liabilities related to below market sales contracts. The below market supply contracts were recorded at their fair values when allocating the purchase price, resulting in a liability of $945.7 million, which is being accreted into earnings as the coal is shipped over a weighted average period of

F-7
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

approximately three years. The net liability at December 31, 2011 and 2010, relating to these below market sales contracts was $91.0 million and $163.2 million, respectively. The current portion of the liability is recorded in “Below market sales contracts acquired” and the long-term portion of the liability is recorded in “Below market sales contracts acquired, noncurrent” in the consolidated balance sheets.
Asset Retirement Obligations
Obligations associated with the retirement of tangible long-lived assets and the associated reclamation costs are recognized at fair value at the time the obligations are incurred. Our reclamation obligations primarily consist of spending estimates related to reclaiming surface land and support facilities at both surface and underground mines in accordance with federal and state reclamation laws as defined by each mining permit. Our liabilities for final reclamation and mine closure are estimated based upon detailed engineering calculations of the amount and timing of the future cash spending for a third-party to perform the required work. Spending estimates are escalated for inflation and then discounted at the credit-adjusted, risk-free interest rate.
We record an asset associated with the discounted liability for final reclamation and mine closure. The obligation and corresponding asset are recognized in the period in which the liability is incurred. The asset is amortized on the units-of-production method over its expected life and the liability is accreted to the projected spending date. The asset amortization and liability accretion are included in “Asset retirement obligation expense” in the consolidated statements of operations. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free interest rate. We also recognize obligations for contemporaneous reclamation liabilities incurred as a result of surface mining. Contemporaneous reclamation consists primarily of grading, topsoil replacement and revegetation of backfilled pit areas.
In connection with the Magnum acquisition, we assumed liabilities related to water treatment in order to comply with selenium effluent limits included in certain mining permits. The cost to treat the selenium discharges in excess of allowable limits was recorded at its fair value, which is accreted into earnings to the projected spending date. Accretion of the estimated selenium liability is included in “Asset retirement obligation expense” in the consolidated statements of operations. The net liability related to water treatment at December 31, 2011 reflected the estimated future 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.
Income Taxes
Income taxes are accounted for using a balance sheet approach. Deferred income taxes are accounted for by applying statutory tax rates in effect at the date of the balance sheet to differences between the book and tax basis of assets and liabilities. A valuation allowance is established if it is “more likely than not” that the related tax benefits will not be realized. In determining the appropriate valuation allowance, projected realization of tax benefits is considered based on expected levels of future taxable income, available tax planning strategies and the overall deferred tax position.
Postretirement Healthcare Benefits
Postretirement benefits other than pensions represent the accrual of the costs of benefits to be provided over the employees' period of active service. These costs are determined on an actuarial basis. Our consolidated balance sheets as of December 31, 2011 and 2010 fully reflect the funded status of postretirement benefits.
Multi-Employer Benefit Plans
We have an obligation to contribute to two plans established by the Coal Industry Retiree Health Benefits Act of 1992 (the Coal Act) - the Combined Fund and the 1992 Benefit Plan. A third fund, the 1993 Benefit Fund (the 1993 Benefit Plan), was established through collective bargaining, but is now a statutory plan under federal legislation passed in 2006. A portion of these obligations is determined on an actuarial basis. The remainder of these obligations qualify as multi-employer plans and expense is recognized as contributions are made.
We also participate in two multi-employer pension plans, the United Mine Workers of America (UMWA) 1950 Pension Plan (the 1950 Plan) and the UMWA 1974 Pension Plan (the 1974 Plan). These plans qualify as multi-employer plans and expense is recognized as contributions are made. The plan assets of the 1950 Plan and the 1974 Plan were combined and are managed by the UMWA. See Note 20 for additional information.

F-8
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Postemployment Benefits
Postemployment benefits are provided to qualifying employees, former employees and dependents, and we account for these items on the accrual basis. Postemployment benefits include workers' compensation occupational disease, which is accounted for on the actuarial basis over the employees' periods of active service; workers' compensation traumatic injury claims, which are accounted for based on estimated loss rates applied to payroll; and claim reserves determined by independent actuaries and claims administrators; disability income benefits, which are accrued when a claim occurs; and continuation of medical benefits, which is recognized when the obligation occurs. Our consolidated balance sheets as of December 31, 2011 and 2010 fully reflect the funded status of postemployment benefits.
Use of Estimates in the Preparation of the Consolidated Financial Statements
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
In particular, we have significant long-term liabilities relating to retiree healthcare and work-related injuries and illnesses. Each of these liabilities is actuarially determined and use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for these items. In addition, we have significant asset retirement and selenium water treatment obligations that involve estimations of costs to reclaim mining land, costs of water treatment and the timing of cash outlays for such costs. If these assumptions do not materialize as expected, actual cash expenditures and costs incurred could differ materially from current estimates. Moreover, regulatory changes could increase our liability to satisfy these or additional obligations.
Finally, in evaluating the valuation allowance related to deferred tax assets, various factors are taken into account, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in the evaluation of the valuation allowance, a change in valuation allowance may be recorded through income tax expense in the period the determination is made.
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, non-qualified stock options, stock appreciation rights, performance awards, restricted stock units and deferred stock units. We recognize compensation expense for awards with only service conditions that have a graded vesting schedule on a straight line basis over the requisite service period for each separately vesting portion of the award.
Derivatives
We have utilized derivative financial instruments to manage exposure to certain commodity prices. We recognize derivative financial instruments at fair value on our consolidated balance sheets. For derivatives that are not designated as hedges, the periodic change in fair value is recorded directly to earnings. As of December 31, 2011 and 2010, we had no such derivative instruments. For derivative instruments that are eligible and qualify as cash flow hedges, the periodic change in fair value is recorded to “Accumulated other comprehensive loss” until the hedged transaction occurs 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. The activity recorded to earnings is included in “Operating costs and expenses” in the consolidated statements of operations. We utilize heating oil and ultra low sulfur diesel fuel swap contracts to manage our exposure to diesel fuel prices. The changes in diesel fuel prices and the prices for these financial instruments are highly correlated thus allowing the swap contracts to be designated as cash flow hedges.
Impairment of Long-Lived Assets
Long-lived assets used in operations are evaluated for impairment when events and changes in circumstances indicate that the carrying value of the long-lived asset group might not be recoverable. Recoverability is measured based on the estimated undiscounted future cash flows attributable to the applicable asset group. If the undiscounted cash flows are less than the asset group's carrying value, we would record an impairment loss based on the amount that the carrying value of the long-lived asset group exceeds its fair value.

F-9
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Business Combinations
We accounted for the Magnum acquisition using the purchase method of accounting for business combinations in effect prior to January 1, 2009. Under this method of accounting, the purchase price was allocated to the fair value of the net assets acquired. Determining the fair value of assets acquired and liabilities assumed required management's judgment and involved the use of significant estimates and assumptions, including, but not limited to, assumptions with respect to future cash flows, discount rates and asset lives.
Deferred Financing Costs
We capitalize costs incurred in connection with borrowings or establishment of credit facilities and issuance of debt securities. These costs are amortized and included in interest expense over the life of the borrowing or term of the credit facility using the interest method.

(3)New Accounting Pronouncements
Multiemployer Benefit Plans
In September 2011, the Financial Accounting Standards Board (FASB) issued authoritative guidance which increases the quantitative and qualitative disclosures an employer is required to provide about its participation in multiemployer benefit plans. We adopted this guidance effective December 31, 2011, with no effect on our results of operations or financial condition.
Comprehensive Income
In June 2011, the FASB issued authoritative guidance which requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. This guidance is effective for fiscal years beginning after December 15, 2011, and we will adopt it on January 1, 2012. While we are currently evaluating the impact on our disclosures and presentation of our financial statements, we do not believe this guidance will affect our results of operations or financial condition.

(4)Selenium Water Treatment Obligation Adjustment
During the year ended December 31, 2011, asset retirement obligation expense increased by $17.0 million due to changes in our selenium water treatment technology selection for one of our outfalls and $9.9 million in relation to a comprehensive consent decree. The terms of the comprehensive consent decree were substantially agreed to in December 2011 and finalized in January 2012. In the third quarter of 2010, additional asset retirement obligation expense of $20.7 million was recorded due to adjusting our estimated future costs of ongoing water treatment at three outfalls resulting from the requirements of the September 1, 2010 court ruling. See Note 23 for the background on these proceedings and the additional impact of these orders on two of our subsidiaries.

(5)Restructuring and Impairment Charge
In the fourth quarter of 2011, we recorded an impairment charge of $13.1 million related to the infrastructure and coal reserves impacted by mine closure decisions in our Appalachia segment made in the fourth quarter of 2011. As coal sales prices weakened in late 2011, we made the strategic decision to close certain high cost mines in Appalachia.
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 Harris No. 1 mine was nearing the end of its projected mining life and was scheduled for closure in 2011. The charge included a $2.8 million non-cash, impairment component related to equipment and coal reserves that were abandoned due to the mine closure. Additionally, the charge included a restructuring component totaling $12.0 million for contractual obligation payments that are being made with no future economic benefit over the remaining term. These payments were for the use of a beltline and rights to coal reserves. Payments of these obligations will occur through the end of 2013. For the year ended December 31, 2011, the expense represents accretion related to the discounted future payment obligation. During the years ended December 31, 2011 and 2010, $0.6 million and $0.4 million, respectively, of accretion was charged against the restructuring liability

F-10
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

related to the discounted future payment obligations. At December 31, 2011, the current portion of the restructuring liability of $4.5 million was included in “Accounts payable and accrued expenses” and the long-term portion of $5.7 million was included in “Other noncurrent liabilities.”
In the fourth quarter of 2009, we recorded a $20.2 million restructuring and impairment charge. The charge included a $12.9 million impairment charge related to certain infrastructure and thermal coal reserves near our Rocklick complex that were deemed uneconomical to mine. Additionally, we recorded $7.3 million related to a restructuring charge for the discontinued use of a beltline into the Rocklick preparation plant. This restructuring charge represented the future lease payments and contract termination costs for the beltline that were made with no future economic benefit. The lease payments and contract termination fee were paid in early 2010.

(6)Risk Management and Financial Instruments
We are exposed to various types of risk in the normal course of business, including fluctuations in commodity prices and interest rates. These risks are actively monitored to ensure compliance with our risk management policies. We manage our commodity price risk related to the sale of coal through the use of long-term, fixed-price contracts, rather than financial instruments.
Credit Risk
Our concentration of credit risk substantially resides with large electricity generating customers, metallurgical customers and Peabody. In 2011, approximately 10% of our revenues were from a marketing affiliate of Peabody. Allowance for doubtful accounts was approximately $138,000 and $141,000 at December 31, 2011 and 2010, respectively, and reflects specific amounts for which risk of collection has been identified based on the current economic environment and circumstances of which we are aware.
As a result of the spin-off, we have sales agreements with a marketing affiliate of Peabody. Under these agreements, we sold 5.6 million tons of coal resulting in revenues of $247.6 million for the year ended December 31, 2011; 7.3 million tons of coal resulting in revenues of $356.6 million for the year ended December 31, 2010; and 8.8 million tons of coal resulting in revenues of $456.1 million for the year ended December 31, 2009. These revenues were recorded in both the Appalachia and Illinois Basin segments. As of December 31, 2011 and 2010, “Accounts receivable and other” on our consolidated balance sheets included outstanding trade receivables from Peabody related to coal sales of $22.5 million and $23.6 million, respectively.
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 a transaction occurs with a counterparty that does not meet our credit standards, we may protect our position by requiring the counterparty to provide appropriate credit enhancement. When appropriate, steps have been taken to reduce credit exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk, as determined by the credit management function, of failure to perform under their contractual obligations. These steps might include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of failure to pay.
Commodity Price Risk
We have commodity risk related to our diesel fuel purchases. To manage this risk, we have entered into heating oil and low sulfur diesel fuel swap contracts with financial institutions. These derivative contracts have been designated as cash flow hedges of anticipated diesel fuel purchases. The changes in fair value of these derivatives are recorded through accumulated other comprehensive loss until such time that the hedged transaction occurs.
Employees
As of December 31, 2011, we had approximately 4,300 employees. Approximately 50% of our employees were represented by an organized labor union. Union labor is represented by the UMWA under labor agreements which generally extend through December 31, 2016.

F-11
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Fair Value of Financial Instruments
Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses have carrying values which approximate fair value due to the short maturity or the financial nature of these instruments.
The following table summarizes the fair value of our financial instruments at December 31, 2011 and 2010.
 
 
 
December 31,
 
 
2011
 
2010
 
 
(Dollars in thousands)
Assets:
 
 
 
 
Fuel contracts, cash flow hedges
 
363

 
1,868

Liabilities:
 
 
 
 
Fuel contracts, cash flow hedges
 
179

 
—

$200 million of 3.25% Convertible Senior notes due 2013
 
183,000

 
190,211

$250 million of 8.25% Senior notes due 2018
 
239,468

 
253,750

All of the instruments above were valued using Level 2 inputs. For additional disclosures regarding our fuel contracts, see Note 16. We utilized New York Mercantile Exchange (NYMEX) quoted market prices for the fair value measurement of these contracts, which reflects a Level 2 input. The fair value of the Convertible Senior Notes and the 8.25% Senior Notes was estimated using the last traded value on the last day of each period, as provided by a third party.

(7)Net Gain on Disposal or Exchange of Assets and Other Transactions
In the normal course of business, we enter into certain asset sales and exchange agreements, which involve swapping non-strategic coal mineral rights or other assets for cash, other assets or coal mineral rights, that are strategic to our operations.
In December 2011, we entered into an agreement to exchange certain non-strategic Appalachia coal mineral rights for coal mineral rights located near our Highland and Dodge Hill mining complexes in the Illinois Basin. We recognized a gain of approximately $18.7 million on this transaction.
In September 2011, we entered into an agreement to exchange certain non-strategic Appalachia property for cash and coal mineral rights near our Big Mountain mining complex. We recognized a gain of $4.9 million on this transaction.
Also in September 2011, we sold certain non-strategic Appalachia coal mineral rights to another coal producer for $1.3 million.
In June 2011, we entered into an agreement to exchange certain non-strategic Appalachia coal mineral rights for coal mineral rights contiguous to our Highland mining complex in the Illinois Basin. We recognized a gain of $7.3 million on this transaction.
Also in June 2011, we entered into an agreement allowing a right of way at our Kanawha Eagle mining complex to a third party for compensation of $2.1 million. We have no future obligation related to this agreement.
In December 2010, we entered into an agreement with another coal producer to exchange certain of our non-strategic coal mineral rights for certain coal mineral rights located near our Highland mining complex. We recognized a gain of $2.9 million on this transaction.
In the third quarter of 2010, we entered into agreements with two other coal producers to exchange certain of our non-strategic coal mineral rights for certain coal mineral rights located near our Highland mining complex. We recognized a gain of $3.4 million on these transactions.
In the second quarter of 2010, we entered into two separate agreements with other coal producers to exchange certain of our non-strategic coal mineral rights for certain coal mineral rights located near our Wells and Corridor G mining complexes. We recognized gains totaling $14.3 million on these transactions.

F-12
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Effective April 2010, we entered into an agreement to surrender our rights to certain non-strategic leased coal reserves and the associated mining permits at our Rocklick mining complex in exchange for the release of the related reclamation obligations. We recognized a gain of $2.8 million on the April 2010 transaction as a result of transferring the reclamation liability.
In March 2010, we received approximately 13 million tons of coal mineral rights contiguous to our Highland mining complex in the Illinois Basin in exchange for non-strategic Illinois Basin coal reserves. We recognized a gain of $24.0 million on this transaction.
In December 2009, we entered into an agreement to swap certain coal mineral rights with another coal producer. We recognized a gain totaling $2.4 million on this transaction. In June 2009, we entered into an agreement with another coal producer to swap certain surface land for certain coal mineral rights and cash. We recognized a gain totaling $4.2 million on this transaction.
The exchange transactions above were recorded at fair value. The valuations primarily utilized Level 3 inputs, as defined by authoritative guidance, in a discounted cash flows model including assumptions for future coal sales prices and operating costs. Level 3 inputs were utilized due to the lack of an active, quoted market for coal reserves and due to the inability to use other transaction comparisons because of the unique nature and location of each coal seam.
Other Transactions
We were a defendant in litigation involving Peabody, in relation to their negotiation and June 2005 sale of two properties previously owned by two of our subsidiaries, which was filed prior to our 2007 spin-off from Peabody. In May 2011, this litigation was settled. As part of the settlement, we made a payment of $14.8 million and ownership of the related assets and liabilities reverted back to us. The assets included coal reserves in West Virginia and surface land in Illinois at closed mine sites. The liabilities included the reclamation obligations related to these assets. The assets were recorded at the value of the settlement consideration, which included $17.6 million of estimated reclamation liabilities assumed, resulting in no significant impact to our results of operations in the second quarter of 2011.
In February 2011, outstanding notes receivable related to the 2006 and 2007 sales of coal reserves and surface land were repaid for $115.7 million prior to the scheduled maturity date. The early repayment resulted in a loss of $5.9 million, which is reflected in “Interest expense and other” on the consolidated statement of operations. Prior to February 2011, the outstanding notes receivable were included in “Accounts receivable and other” and “Notes receivable” on the consolidated balance sheet.
In February 2010, we entered into an agreement to purchase certain coal mineral rights from another coal producer. The purchase price of $10.0 million is included in “Property, plant, equipment and mine development” on the consolidated balance sheet.
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. Therefore, we recorded the $17.7 million cash consideration as a liability. The liability is being accreted through interest expense over an expected lease term of approximately five years and is being relieved as we make future royalty payments. For the years ended December 31, 2011 and 2010, $1.2 million and $1.0 million, respectively, was reflected in “Interest expense and other” on the consolidated statement of operations.
In 2011, “Other revenues” includes the recognition of income as underlying tons were shipped from a coal purchase option sold in a prior year. Additionally, we monetized future coal reserve royalty payments for $2.2 million in the year ended December 31, 2011, with no associated future obligations. Other revenues also include payments from customer settlements, royalties related to coal lease agreements and farm income. During 2009, certain metallurgical and thermal customers requested shipment deferrals on committed tons. In certain situations, we agreed to release the customers from receipt of the tons in exchange for a cash settlement. For the year ended December 31, 2009, these cash settlements represented a significant portion of other revenues.
(8)Joint Ventures
We have interests in joint ventures that are accounted for under the equity method. In 2008, we acquired 49% interests in two joint ventures, both of which have coal mining operations in Appalachia. We also hold interests in two other joint ventures, both of which previously had coal mining operations. One has only closed operations remaining and the other primarily leases coal and oil reserves to third parties.

F-13
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The book value of our equity method investments was $27.1 million and $25.6 million as of December 31, 2011 and 2010, respectively. Our maximum exposure to loss is our book value plus additional future capital contributions, which in total for all of our joint ventures is capped at $8.8 million. The investments in these joint ventures are recorded in “Investments and other assets” in the consolidated balance sheets.
In 2010, we agreed to provide a limited guarantee of the payment and performance under three loans entered into by one of our joint ventures. The loans were obtained to purchase equipment, which is pledged as collateral for the loans. In the event of default on all three loans, we would be required to pay a maximum of $9.1 million. The maximum term of the three loans is through January 2016 and the loan balances at December 31, 2011 totaled $7.1 million. At December 31, 2011 and 2010, there was no carrying amount of the liability related to these guarantees on our consolidated balance sheets based on the amount of exposure and the likelihood of required performance.
We purchased metallurgical coal from one of our joint ventures which we account for under the equity method of accounting. The cost of this coal, $50.0 million in 2011 and $40.0 million in 2010, is included in operating costs. The coal is then sold to third-party customers. As of December 31, 2011 and 2010, "Accounts payable and accrued expenses" on our consolidated balance sheets included the outstanding payable to this joint venture for coal purchases of $4.1 million for both years.

(9)Earnings per Share
Basic earnings per share is computed by dividing net income by the number of weighted average common shares outstanding during the reporting period. Diluted earnings per share is calculated to give effect to all potentially dilutive common shares that were outstanding during the reporting period.
The effect of dilutive securities excludes certain stock options, restricted stock units and convertible debt-related shares because the inclusion of these securities was antidilutive to earnings per share. For the years ended December 31, 2011 and 2010, no common stock equivalents were included in the computation of the diluted loss per share because we reported a net loss.
Accordingly, 3.3 million shares, 2.6 million shares, and 1.3 million shares related to stock-based compensation awards for the years ended December 31, 2011, 2010 and 2009, respectively, as described in Note 26, and 3.0 million common shares for all three years related to the convertible notes described in Note 15, were excluded from the diluted earnings (loss) per share calculation.

(10)Inventories
Inventories consisted of the following:
         
 
 
December 31,
 
 
2011
 
2010
 
 
(Dollars in thousands)
Materials and supplies
 
$
62,474

 
$
42,056

Saleable coal
 
23,806

 
40,478

Raw coal
 
12,086

 
15,439

Total
 
$
98,366

 
$
97,973

Materials, supplies and coal inventory are valued at the lower of average cost or market. Saleable coal represents coal stockpiles that will be sold in current condition. Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Coal inventory costs include labor, supplies, equipment, operating overhead and other related costs. The decrease in saleable coal inventory from December 31, 2010 to December 31, 2011 primarily resulted from transportation delays due to poor weather conditions in the fourth quarter of 2010. The increase in materials and supplies from December 31, 2010 to December 31, 2011 was due to increased supply purchases at the end of 2011 in anticipation of price increases in 2012.


F-14
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(11)Accumulated Other Comprehensive Loss
The following table sets forth the components of accumulated other comprehensive loss:
 
 
Net
Actuarial Loss
Associated with
Postretirement
Plans and
Workers’
Compensation
Obligations
 
Prior Service
Credit
Associated
with
Postretirement
Plans
 
Diesel
Fuel
Hedge
 
Total
Accumulated
Other
Comprehensive
Loss
 
 
(Dollars in thousands)
December 31, 2008
 
$
(89,437
)
 
$
(13,149
)
 
$
(9,695
)
 
$
(112,281
)
Unrealized gains (losses)
 
(182,730
)
 
19,391

 
5,450

 
(157,889
)
Reclassification from other comprehensive income to earnings
 
16,265

 
(551
)
 
5,280

 
20,994

December 31, 2009
 
(255,902
)
 
5,691

 
1,035

 
(249,176
)
Unrealized gains (losses)
 
(95,801
)
 
—

 
1,855

 
(93,946
)
Reclassification from other comprehensive income to earnings
 
37,258

 
(809
)
 
(1,022
)
 
35,427

December 31, 2010
 
(314,445
)
 
4,882

 
1,868

 
(307,695
)
Unrealized gains (losses)
 
(118,210
)
 
—

 
3,060

 
(115,150
)
Reclassification from other comprehensive income to earnings
 
43,368

 
(809
)
 
(4,744
)
 
37,815

December 31, 2011
 
$
(389,287
)
 
$
4,073

 
$
184

 
$
(385,030
)
Comprehensive loss differs from net income (loss) by the amount of unrealized gain or loss resulting from valuation changes of our diesel fuel hedges and adjustments related to the change in funded status of various benefit plans during the periods.

(12)Leases
We lease equipment and facilities under various non-cancelable operating lease agreements. Certain lease agreements require the maintenance of specified ratios and contain restrictive covenants that limit indebtedness, subsidiary dividends, investments, asset sales and other actions. Rental expense under operating leases was $55.4 million, $43.0 million and $47.4 million for the years ended December 31, 2011, 2010 and 2009, respectively.
A substantial amount of the coal we mine is produced from mineral reserves leased from third-party land owners. We lease these coal reserves under agreements that require royalties to be paid as the coal is mined. Certain of these lease agreements also require minimum annual royalties to be paid regardless of the amount of coal mined during the year. Total royalty expense was $88.5 million, $73.9 million and $72.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

F-15
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


Future minimum lease and royalty payments as of December 31, 2011, are as follows:
    
 
 
Operating
Leases
 
Coal
Reserves
 
 
(Dollars in thousands)
2012
 
$
57,213

 
$
34,547

2013
 
50,508

 
39,390

2014
 
34,686

 
33,827

2015
 
17,277

 
28,987

2016
 
6,898

 
15,929

2017 and thereafter
 
763

 
94,073

Total minimum lease and royalty payments
 
$
167,345

 
$
246,753

During 2002, Peabody entered into a transaction with Penn Virginia Resource Partners, L.P. (PVR) whereby two Peabody subsidiaries sold 120 million tons of coal reserves in exchange for $72.5 million in cash and 2.76 million units, or 15%, of the PVR master limited partnership. We participated in the transaction, selling approximately 40 million tons of coal reserves with a net book value of $14.3 million in exchange for $40.0 million. We leased back the coal from PVR and pay royalties as the coal is mined. A $25.7 million gain was deferred at the inception of this transaction, and $3.2 million of the gain was recognized in each of the years 2010 and 2009. The deferred gain was intended to offset potential exposure to loss resulting from continuing involvement in the properties and was amortized to “Operating costs and expenses” in the consolidated statements of operations over the minimum remaining term of the lease, which ended December 31, 2010.

(13)Accounts Payable and Accrued Expenses
Accounts payable and accrued expenses consisted of the following: 
 
 
December 31,
 
 
2011
 
2010
 
 
(Dollars in thousands)
Accounts payable
 
$
206,873

 
$
159,860

Accrued healthcare, including postretirement
 
85,506

 
67,867

Accrued taxes other than income
 
27,000

 
32,805

Accrued payroll and related benefits
 
43,097

 
46,854

Workers’ compensation obligations
 
26,707

 
25,529

Asset retirement obligations
 
9,638

 
19,686

Accrued interest payable
 
7,401

 
10,157

Other accrued benefits
 
8,936

 
9,813

Accrued royalties
 
9,394

 
8,201

Accrued lease payments
 
11,398

 
5,434

Other accrued expenses
 
23,744

 
23,078

Total accounts payable and accrued expenses
 
$
459,694

 
$
409,284


(14)
Income Taxes
Net income (loss) before income taxes was a loss of $115.1 million, a loss of $47.5 million and income of $127.2 million for the years ended December 31, 2011, 2010 and 2009, respectively, and consisted entirely of domestic results.
For the years ended December 31, 2011 and 2010, we had an income tax provision for state and local income taxes of $0.4 million and $0.5 million, respectively, and no provision for federal income taxes. For the year ended December 31, 2009, there were no income tax provisions for federal, state or local income taxes.

F-16
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The income tax rate differed from the U.S. federal statutory rate as follows:
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(Dollars in thousands)
Federal statutory rate
 
$
(40,291
)
 
$
(16,637
)
 
$
44,535

Depletion
 
(25,825
)
 
(23,893
)
 
(22,588
)
State income taxes, net of U.S. federal tax benefit
 
(8,754
)
 
(5,643
)
 
3,520

Changes in valuation allowance
 
70,509

 
42,527

 
(27,225
)
Changes in tax reserves
 
1,476

 
1,382

 
1,307

Other, net
 
3,257

 
2,756

 
451

Total
 
$
372

 
$
492

 
$
—

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities consisted of the following:
 
 
December 31,
 
 
2011
 
2010
 
 
(Dollars in thousands)
Deferred tax assets:
 
 
 
 
Postretirement benefit obligations
 
$
427,781

 
$
393,197

Tax credits and loss carryforwards
 
299,056

 
296,925

Workers’ compensation obligations
 
106,819

 
103,180

Asset retirement obligations
 
162,794

 
135,610

Obligation to industry fund
 
15,891

 
15,235

Sales contract liabilities
 
36,400

 
66,084

Other
 
49,414

 
52,717

Total gross deferred tax assets
 
1,098,155

 
1,062,948

Deferred tax liabilities:
 
 
 
 
Property, plant, equipment and mine development, leased coal interests and advance royalties, principally due to differences in depreciation, depletion and asset writedowns
 
865,264

 
901,828

Long-term debt
 
5,710

 
9,409

Other
 
774

 
—

Total gross deferred tax liabilities
 
871,748

 
911,237

Valuation allowance
 
(226,407
)
 
(151,711
)
Net deferred tax liability
 
$
—

 
$
—

Deferred taxes consisted of the following:
 
 
 
 
Current deferred income taxes
 
$
—

 
$
—

Noncurrent deferred income taxes
 
—

 
—

Net deferred tax liability
 
$
—

 
$
—

Our deferred tax assets include net operating loss (NOL) carryforwards, alternative minimum tax (AMT) credits, and general business credits of $299.1 million and $296.9 million as of December 31, 2011 and 2010, respectively. The NOL carryforwards and AMT credits include amounts apportioned to us in accordance with the Internal Revenue Code and Treasury Regulations at the time of our spin-off from Peabody on October 31, 2007, Magnum NOL carryforwards from periods prior to the acquisition on July 23, 2008, and taxable losses from our operations since the spin-off from Peabody. The NOL carryforwards begin to expire in 2019, the general business credits begin to expire in 2027 and the AMT credits have no expiration date.
Overall, our net deferred tax assets are offset by a valuation allowance of $226.4 million and $151.7 million as of December 31, 2011 and 2010, respectively. The valuation allowance increased by $74.7 million for the year ended December 31, 2011, primarily as a result of net future deductible temporary differences increasing by $72.6 million and

F-17
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

an increase in NOL carryforwards of $2.1 million. We evaluated and assessed the expected near-term utilization of net operating loss carryforwards, book and taxable income trends, available tax strategies and the overall deferred tax position to determine the valuation allowance required as of December 31, 2011 and 2010.
The federal and state income tax returns for the Magnum companies for the tax year 2008 remain subject to examination by the relevant taxing authorities. Patriot and the remainder of its subsidiaries have examination exposure related to the federal and state income tax returns for the years ended December 31, 2008, 2009 and 2010.
During the years ended December 31, 2011, 2010 and 2009, we paid federal, state and local income taxes of $0.7 million, $0.5 million, and $0.1 million, respectively. The portion paid for state income tax payments each year are for tax liabilities that are calculated based on gross receipts, such as the State of Michigan.
At December 31, 2011, the unrecognized tax benefits in our consolidated financial statements, if recognized, would not currently affect our effective tax rate as any recognition would be offset by the associated change in the valuation allowance. We do not expect any significant increases or decreases to our unrecognized tax benefits within 12 months of this reporting date.
A reconciliation of the beginning and ending amounts of gross unrecognized tax benefits is as follows:
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(Dollars in thousands)
Balance at beginning of year
 
$
9,279

 
$
5,866

 
$
2,639

Additions for current year tax positions
 
3,696

 
3,366

 
3,527

Additions (reductions) for prior year positions
 
(6
)
 
47

 
(300
)
Balance at end of year
 
$
12,969

 
$
9,279

 
$
5,866

Due to the existence of NOL carryforwards, we have not currently accrued interest on any of our unrecognized tax benefits. We have considered the application of penalties on our unrecognized tax benefits and have determined, based on several factors, including the existence of NOL carryforwards, that no accrual of penalties related to our unrecognized tax benefits is required. If the accrual of interest or penalties becomes appropriate, we will record an accrual as part of our income tax provision.

(15)
Long-Term Debt and Credit Facilities
Our total indebtedness consisted of the following:
 
 
December 31,
 
 
2011
 
2010
 
 
(Dollars in thousands)
8.25% Senior Notes due 2018
 
$
248,573

 
$
248,348

3.25% Convertible Senior Notes due 2013
 
185,379

 
176,060

Capital leases
 
—

 
21,044

Promissory notes
 
8,294

 
9,406

Total long-term debt
 
442,246

 
454,858

Less current portion of debt
 
(1,182
)
 
(3,329
)
Long-term debt, less current maturities
 
$
441,064

 
$
451,529


F-18
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Credit Facilities
Effective May 5, 2010, we entered into a $427.5 million amended and restated credit agreement with a maturity date of December 31, 2013. The credit facility provides for the issuance of letters of credit and direct borrowings. We incurred total fees of $10.9 million in relation to the amended and restated 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.
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. In January 2011 and 2012, we entered into amendments to the credit agreement which, among other things, modified certain limits and minimum requirements of our financial covenants. At December 31, 2011, 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.
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 accounts receivable to creditors as collateral for any borrowings. Available liquidity under the program fluctuates with the balance of our trade accounts receivable. The outstanding trade accounts receivable balance was $171.0 million and $146.6 million as of December 31, 2011 and 2010, respectively.
Based on our continuing involvement with the trade accounts receivable balances, including continued risk of loss, the sale of the trade accounts receivable 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 are recorded as secured debt.
Both the credit agreement and the accounts receivable securitization program (the facilities) are available for our working capital requirements, capital expenditures and other corporate purposes. As of December 31, 2011 and 2010, the balance of outstanding letters of credit issued against the credit facilities totaled $331.8 million and $355.3 million, respectively. There were no outstanding short-term borrowings against these facilities as of December 31, 2011 and 2010. Availability under these facilities was $220.7 million and $197.2 million as of December 31, 2011 and 2010, respectively.
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 were used for general corporate purposes, which included capital expenditures for development of additional coal production capacity and working capital. The discount is being amortized over the term of the notes. For the years ended December 31, 2011 and 2010, interest expense for the senior notes was $20.9 million and $13.2 million, respectively.
Interest on the notes is payable semi-annually in arrears on April 30 and October 30 of each year. The notes mature on April 30, 2018, unless redeemed in accordance with their terms prior to such date. The notes are senior unsecured obligations, 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 notes may be redeemed at any time prior to April 30, 2014, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest and a “make-whole” premium as defined in the indentures. The notes may be redeemed on or after April 30, 2014 at certain redemption prices as defined in the indentures. In addition, up to 35% of the aggregate principal amount of the notes may be redeemed prior to April 30, 2013 at a redemption price equal to 108.25% of the principal amount thereof from the net proceeds of certain equity offerings.

F-19
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 Senior 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, including $25 million related to the underwriters' overallotment option. The net proceeds of the offering were $194 million after deducting the commissions and fees and expenses of the offering. 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.
We utilized an interest rate of 8.85% to reflect the nonconvertible market rate of our offering upon issuance, which resulted in a $45 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 $15.8 million, $15.1 million and $14.4 million for the years ended December 31, 2011, 2010 and 2009, respectively.
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, rank equally with all of our existing and future senior debt and are senior to any subordinated debt.
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.

F-20
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.
The aggregate amounts of long-term debt maturities subsequent to December 31, 2011 were as follows:
            
 
Debt
 
Maturities
 
(Dollars in thousands)
2012
$
1,182

2013
201,255

2014
1,334

2015
1,417

2016
1,506

2017 and thereafter
251,600

Total cash payments on debt
458,294

Debt discount on convertible notes
(16,048
)
Total long-term debt
$
442,246

Cash interest paid on long-term debt was $29.3 million, $17.7 million and $8.9 million for the years ended December 31, 2011, 2010 and 2009, respectively.
Promissory Notes and Other
In conjunction with an exchange transaction involving the acquisition of Illinois Basin coal reserves in 2005, we entered into promissory notes. The promissory notes and related interest are payable in annual installments of $1.7 million beginning January 2008. The promissory notes mature in January 2017. At December 31, 2011, the short-term portion of the promissory notes was $1.2 million.
On October 3, 2011, we purchased the preparation plant and the associated infrastructure at our Blue Creek mining complex for $28.1 million, which previously had been leased.

(16)Derivatives
We have commodity risk related to our diesel fuel purchases. To manage a portion of this risk, we entered into heating oil and ultra low sulfur diesel swap contracts with financial institutions. The changes in diesel fuel prices and the prices of these financial instruments are highly correlated, thus allowing the swap contracts to be designated as cash flow hedges of anticipated diesel fuel purchases. As of December 31, 2011, the notional amounts outstanding for these swaps included 13.1 million gallons of heating oil expiring throughout 2012, as well as 4.0 million gallons of ultra low sulfur diesel expiring in 2013. In 2012, we expect to purchase approximately 24 million gallons of diesel fuel across all operations. 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 $2.4 million. Based on our analysis, the portion of the fair value for the cash flow hedges deemed ineffective for the years ended December 31, 2011, 2010 and 2009, was immaterial.

F-21
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The following table presents the fair values of our derivatives and the amounts of unrealized gains and losses, net of tax, included in “Accumulated other comprehensive loss” related to fuel hedges in the consolidated balance sheets. See Note 11 for a rollforward of “Accumulated other comprehensive loss” for our fuel hedges.
 
 
December 31,
 
 
2011
 
2010
 
 
(Dollars in thousands)
Fair value of current fuel contracts
   (Prepaid expenses and other current assets)
 
$
251

 
$
1,868

Fair value of noncurrent fuel contracts
   (Investments and other assets)
 
112

 
—

Fair value of current fuel contracts
   (Accounts payable and accrued expenses)
 
168

 
—

Fair value of noncurrent fuel contracts
   (Other noncurrent liabilities)
 
11

 
—


(17)Asset Retirement Obligations
Reconciliations of our liability for asset retirement obligations were as follows:
     
 
 
December 31, 2011
 
 
Reclamation Obligations
 
Selenium Water Treatment Obligations
 
Total
 
 
(Dollars in thousands)
Balance at beginning of year
 
$
254,140

 
$
115,337

 
$
369,477

Liabilities incurred
 
23,817

 
—

 
23,817

Liabilities settled or disposed
 
(13,786
)
 
(10,390
)
 
(24,176
)
Accretion expense
 
25,006

 
15,800

 
40,806

Revisions to estimate
 
2,873

 
14,741

 
17,614

Balance at end of year
 
292,050

 
135,488

 
427,538

Less current portion (included in Accrued expenses)
 
—

 
(9,638
)
 
(9,638
)
Asset retirement obligations
 
$
292,050

 
$
125,850

 
$
417,900

    
 
 
December 31, 2010
 
 
Reclamation Obligations
 
Selenium Water Treatment Obligations
 
Total
 
 
(Dollars in thousands)
Balance at beginning of year
 
$
244,518

 
$
88,602

 
$
333,120

Liabilities incurred
 
3,624

 
—

 
3,624

Liabilities settled or disposed
 
(18,309
)
 
(5,997
)
 
(24,306
)
Accretion expense
 
24,522

 
12,036

 
36,558

Revisions to estimate
 
(215
)
 
20,696

 
20,481

Balance at end of year
 
254,140

 
115,337

 
369,477

Less current portion (included in Accrued expenses)
 
—

 
(19,686
)
 
(19,686
)
Asset retirement obligations
 
$
254,140

 
$
95,651

 
$
349,791


F-22
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

As of December 31, 2011, reclamation obligations of $292.1 million included $99.4 million related to locations that are closed or inactive. As of December 31, 2010, reclamation obligations of $254.1 million included $63.5 million related to locations that are closed or inactive. The credit-adjusted, risk-free interest rates used to calculate our reclamation obligation were 8.37% and 8.02% at January 1, 2011 and 2010, respectively. See Note 23 for further discussion regarding our selenium water treatment obligation.
As of December 31, 2011, we had $325.0 million in surety bonds and letters of credit outstanding to secure our asset retirement obligations.

(18)Workers’ Compensation Obligations
Certain of our operations are subject to the Federal Coal Mine Health and Safety Act of 1969, and the related workers’ compensation laws in the states in which we operate. These laws require our operations to pay benefits for occupational disease resulting from coal workers’ pneumoconiosis (occupational disease or black lung).
 We provide income replacement and medical treatment for work related traumatic injury claims as required by applicable state laws. Provisions for estimated claims incurred are recorded based on estimated loss rates applied to payroll and claim reserves. Certain of our operations are required to contribute to state workers’ compensation funds for costs incurred by the state using a payroll-based assessment by the applicable state. Provisions are recorded using the payroll-based assessment criteria.
The workers’ compensation provision consists of the following components: 
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(Dollars in thousands)
Service cost
 
$
7,496

 
$
9,258

 
$
5,462

Interest cost
 
9,492

 
8,963

 
9,042

Net amortization of actuarial gains
 
(2,070
)
 
(3,003
)
 
(4,504
)
Total occupational disease
 
14,918

 
15,218

 
10,000

Traumatic injury claims
 
22,959

 
20,944

 
18,798

State assessment taxes
 
1,893

 
2,029

 
2,503

Total provision
 
$
39,770

 
$
38,191

 
$
31,301

The increase in occupational disease costs from 2009 to 2010 reflected additional employees as new mines began operations as well as changes to actuarial assumptions such as a lower discount rate and the impact from the 2010 healthcare legislation as discussed below. The traumatic injury claims provision has increased consistently from 2009 through 2011 primarily due to a lower discount rate.
The weighted-average assumptions used to determine the workers’ compensation expense were as follows: 
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
Discount rate:
 
 
 
 
 
 
Occupational disease
 
5.46
%
 
5.90
%
 
6.00
%
Traumatic injury
 
4.54
%
 
4.80
%
 
6.06
%
Inflation rate
 
3.00
%
 
3.00
%
 
3.50
%
Workers’ compensation obligations consist of amounts accrued for loss sensitive insurance premiums, uninsured claims, and related taxes and assessments under black lung and traumatic injury workers’ compensation programs.

F-23
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The workers’ compensation obligations consisted of the following:
 
 
December 31,
 
 
2011
 
2010
 
 
(Dollars in thousands)
Occupational disease costs
 
$
185,639

 
$
174,014

Traumatic injury claims
 
72,653

 
72,272

Total obligations
 
258,292

 
246,286

Less current portion (included in Accrued expenses)
 
(26,707
)
 
(25,529
)
Noncurrent obligations (included in Workers’ compensation obligations)
 
$
231,585

 
$
220,757

The accrued workers’ compensation liability recorded on the consolidated balance sheets at December 31, 2011 and 2010 reflects the accumulated benefit obligation less any portion that is currently funded. The accumulated actuarial gain of $8.0 million that has not yet been reflected in the worker's compensation provision is included in “Accumulated other comprehensive loss.”
As of December 31, 2011, we had $132.2 million in surety bonds and letters of credit outstanding to secure workers’ compensation obligations.
The reconciliation of changes in the occupational disease obligation is as follows: 
 
 
December 31,
 
 
2011
 
2010
 
 
(Dollars in thousands)
Change in benefit obligation:
 
 
 
 
Beginning of year obligation
 
$
174,014

 
$
152,079

Service cost
 
7,496

 
9,258

Interest cost
 
9,492

 
8,963

Net change in actuarial gain
 
3,536

 
12,668

Benefit and administrative payments
 
(8,899
)
 
(8,954
)
Net obligation at end of year
 
185,639

 
174,014

Change in plan assets:
 
 
 
 
Fair value of plan assets at beginning of period
 
—

 
—

Employer contributions
 
8,899

 
8,954

Benefits paid
 
(8,899
)
 
(8,954
)
Fair value of plan assets at end of period
 
—

 
—

Obligation at end of period
 
$
185,639

 
$
174,014

The liability for occupational disease claims represents the actuarially-determined present value of known claims and an estimate of future claims that will be awarded to current and former employees. The liability for occupational disease claims was based on a discount rate of 5.1% and 5.5% at December 31, 2011 and 2010, respectively. Traumatic injury workers’ compensation obligations are estimated from both case reserves and actuarial determinations of historical trends, discounted at 4.5% as of December 31, 2011 and 2010.
2010 Healthcare Legislation
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.

F-24
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The 2010 healthcare legislation 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. In March 2010, we increased our liability by $11.5 million based on an estimate of the impact of these changes to our current population of beneficiaries and claimants. At that time, we were not able to estimate the full impact of the legislation on our obligation 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 populations. We continue to evaluate the impact of this legislation on both our current and future population of claimants and to adjust our liability based on actual claim and award information.
Federal Black Lung Excise Taxes
In addition to the obligations discussed above, certain subsidiaries of Patriot are required to pay black lung excise taxes to the Federal Black Lung Trust Fund (the Trust Fund). The Trust Fund pays occupational disease benefits to entitled former miners who worked prior to July 1, 1973. Excise taxes are based on the selling price of coal, up to a maximum of $1.10 per ton for underground mines and $0.55 per ton for surface mines.

(19)
Postretirement Healthcare Benefits
We currently provide healthcare and life insurance benefits to qualifying salaried and hourly retirees and their dependents from defined benefit plans. Plan coverage for health and life insurance benefits is provided to certain hourly retirees in accordance with the applicable labor agreement.
Enacted in March 2010, 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 that took effect beginning in 2010, but to a greater extent with the 2011 benefit plan year and extending through 2018. Plan standard changes currently applicable to us 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. However, we have incorporated changes to our actuarial assumptions to determine our postretirement benefit obligations utilizing basic assumptions related to pending interpretations. Based on preliminary estimates and these basic assumptions around the pending interpretations of these regulations, the present value of the estimated 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.
Net periodic postretirement benefit costs included the following components:
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(Dollars in thousands)
Service cost for benefits earned
 
$
5,609

 
$
5,695

 
$
3,715

Interest cost on accumulated postretirement benefit obligation
 
77,076

 
75,821

 
70,509

Amortization of actuarial losses
 
43,134

 
36,533

 
18,813

Amortization of prior service credit
 
(809
)
 
(809
)
 
(551
)
Net periodic postretirement benefit costs
 
$
125,010

 
$
117,240

 
$
92,486


F-25
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The following table sets forth the plan’s funded status reconciled with the amounts shown in the consolidated balance sheets:
 
 
December 31,
 
 
2011
 
2010
 
 
(Dollars in thousands)
Change in benefit obligation:
 
 
 
 
Accumulated postretirement benefit obligation at beginning of period
 
$
1,334,759

 
$
1,237,050

Service cost
 
5,609

 
5,695

Interest cost
 
77,076

 
75,821

Participant contributions
 
1,218

 
1,077

Benefits paid
 
(67,356
)
 
(67,374
)
Change in actuarial loss
 
117,457

 
82,490

Accumulated postretirement benefit obligation at end of period
 
1,468,763

 
1,334,759

Change in plan assets:
 
 
 
 
Fair value of plan assets at beginning of period
 
—

 
—

Employer contributions
 
66,138

 
66,297

Participant contributions
 
1,218

 
1,077

Benefits paid and administrative fees (net of Medicare Part D reimbursements)
 
(67,356
)
 
(67,374
)
Fair value of plan assets at end of period
 
—

 
—

Postretirement benefit obligation
 
1,468,763

 
1,334,759

Less current portion (included in Accrued expenses)
 
(81,446
)
 
(65,591
)
Noncurrent obligation (included in Postretirement benefit obligations)
 
$
1,387,317

 
$
1,269,168

The accrued postretirement benefit liability recorded on the consolidated balance sheets at December 31, 2011 and 2010 reflects the accumulated postretirement benefit obligation less any portion that is currently funded. The accumulated actuarial loss and prior service credit gain of $396.1 million and $4.1 million, respectively, that have not yet been reflected in net periodic postretirement benefit costs are included in “Accumulated other comprehensive loss.”
The increase in the actuarial loss in 2011 was mainly due to a lower discount rate. The change in the actuarial loss in 2010 mainly reflected a decrease in the discount rate and the incorporation of assumptions related to the excise tax promulgated in the 2010 healthcare legislation.
We amortize actuarial gains and losses using a 0% corridor with an amortization period that covers the average remaining service period of active employees (7.46 years, 7.55 years and 6.16 years utilized for 2011, 2010 and 2009, respectively). For the year ending December 31, 2012, an estimated actuarial loss of $56.0 million and an estimated gain from prior service credit of $0.8 million will be amortized from accumulated comprehensive loss into net periodic postretirement costs.
The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:
        
 
 
Year Ended December 31,
 
 
2011
 
2010
Discount rate
 
5.10%
 
5.92%
Rate of compensation increase
 
3.50%
 
3.50%
Measurement date
 
December 31, 2011
 
December 31, 2010

F-26
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The weighted-average assumptions used to determine net periodic benefit cost were as follows:
    
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
Discount rate
 
5.92%
 
6.30%
 
6.80%
Rate of compensation increase
 
3.50%
 
3.50%
 
3.50%
Measurement date
 
December 31, 2010
 
December 31, 2009
 
December 31, 2008
The following presents information about the assumed healthcare cost trend rate:
        
 
 
Year Ended December 31,
 
 
2011
 
2010
Healthcare cost trend rate assumed for next year
 
7.00%
 
7.00%
Rate to which the cost trend is assumed to decline
      (the ultimate trend rate)
 
5.00%
 
5.00%
Year that the rate reaches that ultimate trend rate
 
2018
 
2017
Assumed healthcare cost trend rates have a significant effect on the amounts reported for healthcare plans. A one percentage-point change in the assumed healthcare cost trend would have the following effects:
        
 
 
+1.0%
 
-1.0%
 
 
(Dollars in thousands)
Effect on total service and interest cost components
 
$
11,315

 
$
(9,363
)
Effect on year-end postretirement benefit obligation
 
189,683

 
(158,180
)
Plan Assets
Our postretirement benefit plans are unfunded.
Estimated Future Benefits Payments
The following benefit payments (net of retiree contributions), which reflect expected future service, as appropriate, are expected to be paid by Patriot:
 
 
Postretirement
Benefit Payments
 
 
(Dollars in thousands)
2012
 
$
81,446

2013
 
87,123

2014
 
91,628

2015
 
96,161

2016
 
98,998

2017 and thereafter
 
515,470

Plan Changes
In 2009, changes were made to certain defined benefit plans for retired and active, salaried individuals resulting in a reduction to projected healthcare costs of $8.5 million that will be amortized over 7.0 years and a reduction to projected healthcare costs of $10.9 million that will be amortized over 12.5 years.

F-27
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Assumption of Certain Patriot Liabilities
Peabody assumed certain of our retiree healthcare liabilities at the spin-off, which had a present value of $696.8 million as of December 31, 2011 and are not reflected above. These liabilities included certain obligations under the Coal Act for which Peabody and Patriot are jointly and severally liable, obligations under the 2007 National Bituminous Coal Wage Agreement (2007 NBCWA) for which Patriot is secondarily liable, and obligations for certain active, vested employees of Patriot.
Multi-Employer Benefit Plans
Retirees formerly employed by certain subsidiaries and their predecessors receive health and death benefits provided by the Combined Fund, a fund created by the Coal Act, if they meet the following criteria: they were members of the UMWA; last worked before January 1, 1976; and were receiving health benefits on July 20, 1992. The Coal Act requires former employers (including certain entities of the Company) and their affiliates to contribute to the Combined Fund according to a formula. No new retirees will be added to this group. The Coal Act also established the 1992 Benefit Plan, which provides medical benefits to persons who are not eligible for the Combined Fund, who retired prior to October 1, 1994. 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 prior national labor agreement established the 1993 Benefit Plan to provide health benefits for retired miners not covered by the Coal Act. The 1993 Benefit Plan provides benefits to qualifying retired former employees, who retired after September 30, 1994, of certain signatory companies which have gone out of business and defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business. We expect to pay $10.1 million in 2012 related to these funds.
The Surface Mining Control and Reclamation Act of 2006 (the 2006 Act), enacted in December 2006, amended the federal laws establishing the Combined Fund and 1992 Benefit Plan and addressed certain provisions of the 1993 Benefit Plan. Among other things, the 2006 Act guaranteed full funding of all beneficiaries in the Combined Fund, and provided funds on a phased-in basis for the 1992 Benefit Plan. The new and additional federal expenditures to the Combined Fund, 1992 Benefit Plan, 1993 Benefit Plan and certain Abandoned Mine Land payments to the states and Indian tribes are collectively limited by an aggregate annual cap of $490 million. To the extent that (i) the annual funding of the programs exceeds this amount (plus the amount of interest from the Abandoned Mine Land trust fund paid with respect to the Combined Fund), and (ii) Congress does not allocate additional funds to cover the shortfall, contributing employers and affiliates, including some of our entities, would be responsible for the additional costs.
We have recorded actuarially determined liabilities related to the Combined Fund. The noncurrent portion related to these obligations was $35.4 million and $39.0 million as of December 31, 2011 and 2010, respectively, and is reflected in “Obligation to industry fund” in the consolidated balance sheets. The current portion related to these obligations reflected in “Accounts payable and accrued expenses” in the consolidated balance sheets was $5.4 million and $5.9 million as of December 31, 2011 and 2010, respectively. Expense of $2.1 million was recognized related to these obligations for the year ended December 31, 2011, and consisted of interest of $2.2 million and amortization of actuarial gain of $0.1 million. Expense of $3.2 million was recognized related to these obligations for the year ended December 31, 2010, and consisted of interest of $2.6 million and amortization of actuarial loss of $0.6 million. Expense of $3.2 million was recognized related to these obligations for the year ended December 31, 2009, and consisted of interest of $3.4 million and amortization of actuarial gain of $0.2 million. We made payments of $5.4 million, $6.0 million and $6.3 million related to these obligations for the years ended December 31, 2011, 2010 and 2009, respectively.
The obligation to industry fund recorded on the consolidated balance sheets at December 31, 2011 and 2010 reflects the obligation less any portion that is currently funded. The accumulated actuarial loss that has not yet been reflected in expense as of December 31, 2011 and 2010 was $1.1 million, and is included in “Accumulated other comprehensive loss.”
A portion of these funds qualify as multi-employer benefit plans, which allows us to recognize expense as contributions are made. The expense related to these funds was $2.5 million, $10.0 million and $11.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

F-28
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Pursuant to the amended provisions of the 1992 Benefit Plan, we are required to provide security in an amount equal to one times the annual cost of providing healthcare benefits for all individuals receiving benefits from the 1992 Benefit Plan who are attributable to Patriot, plus all individuals receiving benefits from an individual employer plan maintained by Patriot who are entitled to receive such benefits.

(20)
Multi-Employer Pension Plans
Certain subsidiaries participate in multi-employer pension plans (the 1950 Plan and the 1974 Plan), which provide defined benefits to a majority of the hourly coal production workers represented by the UMWA. The plan assets of the 1950 Plan and the 1974 Plan were combined and are managed by the UMWA. Benefits under the UMWA plans are computed based on service with our relevant subsidiaries or other signatory employers. The 1950 Plan and the 1974 Plan qualify as multi-employer benefit plans, allowing us to recognize expense as contributions are made. The expense related to these funds was $24.3 million, $21.0 million and $18.3 million for the years ended December 31, 2011, 2010 and 2009, respectively.
In December 2006, the 2007 NBCWA was signed, which required funding of the 1974 Plan through 2011 under a phased funding schedule. The funding is based on an hourly rate for certain UMWA workers. Under the 2007 NBCWA, the per-hour funding rate increased annually, beginning in 2007, until reaching $5.50 in 2011. The collective bargaining agreement with the UMWA was renegotiated in 2011 and generally extends through 2016. We refer to this as the 2011 National Bituminous Coal Wage Agreement (2011 NBCWA). The 2011 NBCWA requires funding at $5.50 per hour for certain UMWA workers. Our subsidiaries with UMWA-represented employees are required to contribute to the 1974 Plan. The 1974 Plan funding rate could change during the term of the 2011 NBCWA if additional funding is deemed necessary to guarantee benefit payments.
The 1974 Plan's legal name is United Mine Workers of America 1974 Pension Plan and the Employer Identification Number is 52-1050282. The 1974 Plan is considered to be in Seriously Endangered Status for the plan year beginning July 1, 2011, because the plan actuary determined that the 1974 Plan's funded percentage is less than 80%, and the 1974 Plan is projected to have an accumulated funding deficiency within six plan years after the plan year beginning July 1, 2011. A funding improvement plan must be adopted by May 25, 2012 and may include increased contributions to the plan and/or modifications to certain future benefit accruals. The contributions to the 1974 Plan made by one of our wholly-owned subsidiaries, Eastern Associated Coal LLC, represent more than 5% of the total contributions to the 1974 Plan.
New inexperienced miners hired after January 1, 2012 will not participate in the 1974 Plan. Such new hires will instead receive a payment of $1.00 per hour worked into the UMWA Cash Deferral Plan, increasing to $1.50 on January 1, 2014. Effective January 1, 2012, employers will also pay $1.50 per hour to a new Retiree Bonus Account Trust for the term of the 2011 NBCWA. This Trust will make a payment to retirees in November of 2014, 2015 and 2016 in the amount of $580 for most retirees and $455 for disabled retirees. This payment was also made in November 2011. If Trust funding is not sufficient to make these annual bonus payments, employers will pay the difference directly to their retirees. Also effective January 1, 2012, employers will also make an additional supplemental pension contribution of $1.00 per hour worked into the UMWA Cash Deferred Savings Plan for each active miner with at least 20 years of credited service under the 1974 Plan, increasing to $1.50 per hour on January 1, 2014. Effective January 1, 2012, any participant in the 1974 Plan may make an irrevocable election to opt out of the 1974 Plan. Such employee will cease to accrue any further service or benefits under the 1974 Plan. Effective with the election, employers will contribute $1.00 per hour worked to the UMWA Cash Deferred Plan on the employee's behalf as a Supplemental Pension Contribution, increasing to $1.50 on January 1, 2014.
We expect to make contributions of approximately $23 million to the 1974 Plan in 2012. Even with these increased rates, the difficult equity markets over recent years have resulted in materially underfunded multi-employer pension funds and rates could increase as this deficit is addressed. Furthermore, 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.



F-29
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(21)Defined Contribution Plan
Patriot sponsors employee retirement accounts under a 401(k) plan for eligible salaried and non-union hourly employees of the Company (the 401(k) Plan). Generally, Patriot matches voluntary contributions to the 401(k) Plan up to specified levels. The match was temporarily suspended for the second half of 2009, and was reinstated January 1, 2010. A performance contribution feature under the 401(k) plan allows for additional contributions based upon meeting specified performance targets. We recognized 401(k) plan expense of $10.8 million, $7.9 million and $4.5 million for the years ended December 31, 2011, 2010 and 2009, respectively. We recognized additional expense of $2.3 million and $7.2 million under the performance contribution feature for the years ended December 31, 2011 and 2010, respectively.

(22)Guarantees
As part of our 2007 spin-off, Peabody had guaranteed occupational disease (black lung) workers' compensation obligations related to certain of our subsidiaries with the U.S. Department of Labor (DOL). In the first quarter of 2011, we posted our own surety, resulting in a $15.0 million interest-bearing deposit that was recorded to “Investments and other assets” on the consolidated balance sheet. Peabody no longer has any obligation to the DOL related to our subsidiaries included in the 2007 spin-off.
In the normal course of business, we are party to guarantees and financial instruments with off-balance-sheet risk, such as bank letters of credit, performance or surety bonds and other guarantees and indemnities, which are not reflected in the accompanying consolidated balance sheets. Such financial instruments are valued based on the amount of exposure under the instrument and the likelihood of required performance. We do not expect any material losses to result from these guarantees or off-balance-sheet instruments.
Letters of Credit and Bonding 
Letters of credit and surety bonds in support of our reclamation, lease, workers' compensation and other obligations were as follows as of December 31, 2011:
 
 
Asset Retirement Obligations
 
Workers’
Compensation
Obligations
 
Retiree
Health
Obligations
 
Other(1)
 
Total
 
 
(Dollars in thousands)
Surety bonds
 
$
185,649

 
$
44

 
$
—

 
$
9,408

 
$
195,101

Letters of credit
 
139,392

 
132,181

 
56,730

 
3,498

 
331,801

Third-party guarantees
 
—

 
—

 
—

 
7,536

 
7,536

 
 
$
325,041

 
$
132,225

 
$
56,730

 
$
20,442

 
$
534,438

(1) Includes collateral for surety companies and bank guarantees, road maintenance, lease obligations and performance guarantees.
As of December 31, 2011, Arch held surety bonds of $39.4 million related to properties acquired by Patriot in the Magnum acquisition, of which $38.5 million related to reclamation. We have posted letters of credit in Arch's favor, as required.
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, 2011. Our obligation under the guarantee extends to September 2015.
Other Guarantees 
We are the lessee or sublessee under numerous equipment and property leases. It is common in such commercial lease transactions for Patriot, as the lessee, to agree to indemnify the lessor for the value of the property or equipment leased, should the property be damaged or lost during the course of our operations. We expect that losses with respect to leased property would be covered by insurance (subject to deductibles). Patriot and certain of our subsidiaries have guaranteed other subsidiaries' performance under their various lease obligations. Aside from indemnification of the lessor for the value of the property leased, our maximum potential obligations under the leases are equal to the respective future minimum lease payments and/or, in certain leases, liquidated damages, assuming no amounts could be recovered from third parties.

F-30
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(23)Commitments and Contingencies
Commitments
As of December 31, 2011, purchase commitments for equipment totaled $172.8 million primarily related to our build out of metallurgical coal production. Of this amount, we have equipment totaling $115.2 million scheduled for delivery in 2012, with the remainder in subsequent years. We typically finance a significant portion of equipment through leasing arrangements.
Other
On occasion, we become a party to claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business. Our material legal proceedings are discussed below.
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 National Pollutant Discharge Elimination System (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. Our discharges must comply with effluent limitations that are established based on the implementation of certain treatment technologies determined by the Environmental Protection Agency (EPA) to be appropriate for the coal mining sector or to meet the applicable water quality standards in the streams receiving the discharge. States are empowered to develop and enforce water quality standards, which are subject to change and must be approved by the EPA. Water quality standards vary from state to state.
Environmental claims and litigation in connection with our various NPDES permits, and related CWA requirements that were assumed in the Magnum acquisition, include the following:
Hobet West Virginia Department of Environmental Protection (WVDEP) Action
In 2007, Hobet Mining, LLC (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 Hobet WVDEP Action. The Hobet WVDEP Action was resolved by a settlement and consent order entered in the Boone County Circuit Court on September 5, 2008. The settlement required us, among other things, 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 Hobet 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.
Selenium Matters
Federal Apogee Case and Federal Hobet Case
In 2007, Apogee Coal Company, LLC (Apogee) was sued in the 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 effluent limits for selenium set forth in one of its NPDES permits. The lawsuit sought compliance with the effluent limits, fines and penalties as well as injunctive relief prohibiting Apogee from further violating laws and its permit.

F-31
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 Hobet WVDEP Action in state court. However, the Federal Hobet Case focused exclusively on selenium exceedances in permitted water discharges, while the Hobet 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 effluent 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' effluent 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 Surface Mining Control and Reclamation Act (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 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.
Other WVDEP Actions
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. On June 11, 2010, WVDEP filed a lawsuit against Apogee in the Logan County Circuit Court, alleging discharge of pollutants, including selenium, in violation of certain of its NPDES and SMCRA permits. We refer to this case as the Apogee WVDEP Action. The permits contained in the Catenary WVDEP Action and the Apogee WVDEP Action are also involved in the February 2011 Action discussed below. WVDEP is seeking fines and penalties as well as injunctions prohibiting Catenary and Apogee from discharging pollutants, including selenium, in violation of laws and NPDES permits. A July 2012 trial date has been set for the Apogee WVDEP Action. The Catenary WVDEP Action has not been set for hearing. 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 these matters if they would be in the best interest of the Company.
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 a Fluidized Bed Reactor (FBR) water treatment facility for three outfalls and to come into compliance with applicable selenium discharge limits at these three outfalls by March 1, 2013. In September 2010, we increased the portion of the selenium water treatment liability related to Apogee by $20.7 million for the fair value of the estimated future ongoing operating costs related to these three outfalls. This charge is reflected in “Asset retirement obligation expense” in the consolidated statement of operations. We record the costs to install the Apogee FBR water treatment facility as capital expenditures when incurred. As of December 31, 2011, we have spent approximately $12.6 million on the Apogee FBR facility and the total expenditures are estimated to be approximately $55 million. We began construction on the Apogee FBR facility in the third quarter of 2011.

F-32
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Additionally, the U.S. District Court ordered Hobet to submit a proposed schedule to develop a treatment plan for a Hobet Surface Mine No. 22 outfall by October 1, 2010 and to come into compliance with applicable discharge limits under the permit by May 1, 2013. We submitted the required schedule, which included conducting additional pilot projects related to certain technological alternatives. A treatment technology to be utilized at this Hobet Surface Mine No. 22 outfall was filed with the U.S. District Court in June 2011 in accordance with the submitted schedule. In June 2011, we recorded an adjustment of $24.0 million to the selenium water treatment liability primarily related to fair value of the estimated future ongoing operating costs of an FBR water treatment facility at this outfall. This charge is reflected in “Asset retirement obligation expense” in the consolidated statement of operations.
In December 2011, the Special Master appointed by the U.S. District Court to oversee the Hobet Surface Mine No. 22 project approved Hobet's request to substitute ABMet selenium treatment technology for the FBR technology at this outfall. The U.S. District Court subsequently confirmed this substitution. As with the Apogee FBR facility, we will record the costs to install the Hobet ABMet water treatment facility as capital expenditures when incurred. We continue to design and seek permits for the Hobet ABMet facility and anticipate beginning construction on the facility in the first half of 2012. The estimated total expenditures for completing the ABMet water treatment facility is approximately $25 million, which is significantly less than the estimated $40 million to build the Hobet FBR facility.
In December 2011, we adjusted the portion of the selenium water treatment liability related to Hobet Surface Mine No. 22 by $10.3 million for the decrease in the fair value of the estimated future ongoing operating costs related to this outfall due to the change in the technology approved by the Special Master. We also wrote off approximately $3.0 million related to the final engineering specifications for the Hobet FBR facility. These charges are reflected in “Asset retirement obligation expense” in our consolidated statement of operations.
FBR technology had not been used to remove selenium or any other minerals discharged at coal mining operations prior to our pilot project performed in 2010. The FBR water treatment facility required by the September 1, 2010 ruling will be the first facility constructed for selenium removal on a commercial scale. Further, neither FBR nor ABMet technology has been proven effective on a full-scale commercial basis at coal mining operations and there can be no assurance that either of these technologies will be successful under all variable conditions experienced at our mining operations.
February 2011 Litigation
In February 2011, OVEC and two other environmental groups filed a lawsuit against us, Apogee, Catenary and Hobet, in the U.S. District Court alleging violations of ten NPDES permits and certain SMCRA permits relating to outfalls created prior to the Magnum acquisition. We refer to this case as the February 2011 Litigation. The February 2011 Litigation involves the same four NPDES permits that are the subject of the Catenary WVDEP Action, the same Apogee permit that is the subject of the Apogee WVDEP Action, the same four NPDES permits that are the subject of the Hobet WVDEP Action and one additional NPDES permit held by Hobet that is not the subject of any action by WVDEP. The plaintiffs were seeking fines, compliance with permit limits and other requirements, and injunctive relief.
In late 2011, we substantially agreed to the terms of a settlement agreement with OVEC and the other environmental groups. On January 18, 2012, we finalized a comprehensive consent decree that, when entered by the U.S. District Court, will resolve the February 2011 Litigation. The comprehensive consent decree sets technology selection and compliance dates for the outfalls in the ten permits included in the February 2011 Litigation on a staggered basis, allowing us to continue testing certain technologies as well as to take advantage of technology that is still in the development stage. See our discussion below in relation to the uncertainties experienced in making technology selections. The comprehensive consent decree separates the outfalls included in these ten NPDES permits into categories based on the average gallons per minute water flow at each outfall. The comprehensive consent decree requires that we select water treatment technology alternatives by category beginning with the first category in September 2012 and ending with the last category in September 2014.

F-33
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Additionally, we agreed to, among other things, come into compliance with applicable selenium discharge limits at each outfall in the category beginning with the first category within 24 months of the effective date of the agreement and ending with the last category within 60 months of the effective date of the agreement. We also agreed to, among other things, waive our rights to mine certain coal reserves and to pay $7.5 million in civil penalties. The plaintiffs agreed to, among other things, refrain from instituting new lawsuits with respect to the permits and outfalls identified in the comprehensive consent decree for certain periods, provided we meet the specified requirements. The comprehensive consent decree also established a framework under which we will interface with the plaintiffs with respect to the identified permits and outfalls. See the table below for additional details. The comprehensive consent decree will become effective upon entry by the U.S. District Court after the conclusion of a public comment period.
The comprehensive consent decree was determined to be a recognized subsequent event and the amounts paid per the agreement of approximately $7.5 million and the write-off of the forfeited coal reserves of approximately $2.3 million are reflected in “Asset retirement obligation expense” in our consolidated statement of operations at December 31, 2011.
Category/Gallons Per Minute
Technology Selection Date
Projected Compliance Date
I / 0-200
September 1, 2012
24 months from the effective date of the agreement
II / 201-400
December 31, 2012
36 months from the effective date of the agreement
III / 401-600
March 31, 2013
45 months from the effective date of the agreement
IV / 601-1000
September 1, 2013
50 months from the effective date of the agreement
V / 1000 +
September 1, 2014
60 months from the effective date of the agreement
Selenium Water Treatment 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 installations to be implemented and maintained 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 water treatment strategy. Based on this planned water treatment strategy, our expected annual operating costs are approximately $7.3 million each year over the next five years.
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 estimated aggregate undiscounted amount of the initial accrual was $390.7 million at the Magnum acquisition date.
As of December 31, 2011, we have a $135.5 million liability recorded for the treatment of selenium discharges related to the 78 outfalls acquired in the Magnum acquisition. The current portion of the estimated liability is $9.6 million and is included in “Accounts payable and accrued expenses” and the long-term portion is recorded in “Asset retirement obligations” on our consolidated balance sheets. This total liability is inclusive of the adjustments that were recorded in connection with the September 1, 2010 U.S. District Court Ruling described above.
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 have installed ZVI systems according to our original water treatment strategy, while also performing a further review of other potential water treatment solutions. Our water treatment strategy reflects implementing scalable ZVI installations at each of the other outfalls due to its modular design that can be reconfigured as further knowledge and certainty is gained. Initial pilot testing of ZVI technology began in 2008 and has identified potential shortfalls requiring additional research to resolve certain detailed design considerations. To date, ZVI technology has not been demonstrated to perform consistently and sustainably in achieving effluent selenium limitations or in treating the expected water flows at all outfalls. However, based on the flexibility of the scalable system for configuration adjustments, improvements in the system design and demonstrated success in reducing selenium at certain flows, we plan to continue to pursue the ZVI-based water treatment installations and determine whether modifications to the technology could result in its ability to treat selenium successfully at outlets identified in the February 2011 Litigation.

F-34
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

At this time, there is no definitive plan to install any technology other than ZVI-based technology at the other outfalls not included in the September 1, 2010 ruling as none of the other technologies has been proven effective on a full-scale basis. Our comprehensive consent decree with the plaintiffs in the February 2011 Litigation requires that we select water treatment technology by category beginning with the first category in September 2012 and ending with the last category in September 2014. We are continuing to research and evaluate various treatment solutions in addition to ZVI-based systems for the other outfalls. Results of pilot testing in the first half of 2011 indicated that ZVI-based systems, FBR and an additional technology may be viable selenium treatment options. We are continuing to test modifications to these treatment options and we are pilot testing alternative solutions. Alternative technology solutions that we may ultimately select are still in the early phases of development and their related costs can not be estimated at this time.
We continue to implement treatment installations at various permitted outfalls, but we have been unable to comply with selenium discharge limits due to the ongoing inability to identify a water treatment solution that can remove selenium sustainably, consistently and uniformly under all variable conditions experienced at our mining operations. While we are actively continuing to explore new treatment options and modifying existing technologies, a definitive solution has not been identified and it is unknown when or if such a solution will be identified. Even if a definitive solution would have existed as of December 31, 2011, it likely would not have been possible to install such technology at all of the outfalls included in the Hobet WVDEP Action by the July 2012 compliance deadline, and we are taking the requisite steps to seek an extension approved by the court.
If ZVI-based systems are not ultimately successful in treating the effluent selenium exceedances at the outfalls covered by the Hobet WVDEP Action and the February 2011 Action, we will be required to install alternative treatment solutions. The cost of other water treatment solutions could be materially higher than the costs reflected in our liability. Furthermore, costs associated with potential modifications to ZVI or the scale of our current ZVI-based systems could also cause the costs to be materially higher than the costs reflected in our liability. We cannot provide an estimate of the possible additional range of costs associated with alternate treatment solutions at this time as no solution has been proven to be effective on a full-scale commercial basis and we have not made any changes to our treatment plans for these outfalls as of December 31, 2011. Potential installations of selenium treatment alternatives are further complicated by the variable geological and topographical considerations of each individual outfall.
While we are actively continuing to explore treatment options, there can be no assurance as to if or 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 it becomes probable that we will utilize a different technology or modify the current technology, whether due to developments in our ongoing research, technology changes or modifications according to the comprehensive consent decree or other legal obligations to do so. Additionally, there are no assurances we will meet the timetable stipulated in the various court orders, consent decrees and permits.
General Clean Water Act Matters
With respect to all outfalls with known exceedances for selenium or any other parameter, 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 our permits could result in further litigation against us, an inability to obtain new permits or to maintain existing permits, which could impact our ability to mine our coal reserves, 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. The specific sites discussed above were created prior to the Magnum acquisition under legacy permitting standards and resulted in violations of current selenium requirements, which were promulgated in West Virginia in 2007.
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.

F-35
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 laws and related 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.
In the second action, motions to dismiss have been filed, asserting that the allegations 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 (Monsanto), Pharmacia Corporation and Akzo Nobel Chemicals, Inc., by certain plaintiffs in state court in Putnam County, West Virginia. In total, 243 similar lawsuits have been served on Apogee, which are identical except for the named plaintiff. Of the 243 lawsuits, 75 were served in February 2008, 167 were served in December 2009, and one was served in January 2011. 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, 2011, 47 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 were a defendant in litigation involving Peabody 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. In May 2011, we entered into a litigation settlement agreement with ELT and its subsidiaries. See Note 7 for a detailed description of the settlement.

F-36
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 approximately 140 related lawsuits filed in the Circuit Court of Boone County, West Virginia. In addition to our subsidiary, the lawsuits name Peabody and other coal companies as defendants. 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 installed public water lines and most of the plaintiffs now have access to public water. Pursuant to the terms of the Separation Agreement, Plan of Reorganization and Distribution from our 2007 spin-off, Patriot is indemnifying and defending Peabody in this litigation. The lawsuits have been settled and all settlement fees were paid in full in 2011.
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 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. We have not received any additional requests for information in 2011. In January 2012, the terminated employee filed a civil lawsuit against us alleging retaliatory discharge and intentional infliction of emotional distress. In addition, five employees filed a purported class action lawsuit against us and the terminated employee seeking compensation for lost wages, emotional distress, and punitive damages for the alleged intentional violation of employee safety at the mine. We deny the validity of the allegations and intend to vigorously defend both civil lawsuits.
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.

(24)Segment Information
We report our operations through two reportable operating segments, Appalachia and Illinois Basin. The Appalachia and Illinois Basin segments primarily consist of our mining operations in West Virginia and Kentucky, respectively. The principal business of the Appalachia segment is the mining and preparation of thermal coal, sold primarily to electricity generators and metallurgical coal, sold to steel and coke producers. The principal business of the Illinois Basin segment is the mining and preparation of thermal coal, sold primarily to electricity generators. For the years ended December 31, 2011, 2010 and 2009, our sales to electricity generators were 76%, 78% and 83% of our total volume, respectively. Our sales to steel and coke producers were 24%, 22% and 17% of our total volume for the years ended December 31, 2011, 2010 and 2009, respectively. For the years ended December 31, 2011, 2010, and 2009, our export sales were 29%, 20% and 11% of our total volume, respectively. Our revenues attributable to foreign countries, based on where the product was shipped, were $952.3 million, $555.0 million and $322.2 million for the years ended December 31, 2011, 2010 and 2009, respectively. There are no material revenues attributed to any individual foreign country.
We utilize underground and surface mining methods and produce coal with high and medium Btu content. Our operations have relatively short shipping distances from the mine to most of our domestic utility customers and certain metallurgical coal customers. “Corporate and Other” in the table below includes selling and administrative expenses, net gain on disposal or exchange of assets and costs associated with past mining obligations.
Our chief operating decision makers use Adjusted EBITDA as the primary measure of segment profit and loss. We believe that in our industry such information is a relevant measurement of a company’s operating financial performance. Adjusted EBITDA is defined as net income (loss) before deducting interest income and expense; income taxes; asset retirement obligation expense; depreciation, depletion and amortization; restructuring and impairment charge; and sales contract accretion. Segment Adjusted EBITDA is calculated the same as Adjusted EBITDA but excludes “Corporate and

F-37
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Other” as defined above. 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.
Operating segment results for the year ended December 31, 2011 were as follows:
 
 
Appalachia
 
Illinois
Basin
 
Corporate
and Other
 
Consolidated
 
 
(Dollars in thousands)
Revenues
 
$
2,090,885

 
$
311,621

 
$
—

 
$
2,402,506

Adjusted EBITDA
 
386,340

 
(12,140
)
 
(197,459
)
 
176,741

Additions to property, plant, equipment and mine development
 
158,020

 
15,929

 
764

 
174,713

Income from equity affiliates
 
4,709

 
—

 
—

 
4,709

Operating segment results for the year ended December 31, 2010 were as follows: 
 
 
Appalachia
 
Illinois
Basin
 
Corporate
and Other
 
Consolidated
 
 
(Dollars in thousands)
Revenues
 
$
1,759,077

 
$
276,034

 
$
—

 
$
2,035,111

Adjusted EBITDA
 
316,324

 
1,295

 
(175,758
)
 
141,861

Additions to property, plant, equipment and mine development
 
97,902

 
23,379

 
1,708

 
122,989

Income from equity affiliates
 
9,476

 
—

 
—

 
9,476

Operating segment results for the year ended December 31, 2009 were as follows: 
 
 
Appalachia
 
Illinois
Basin
 
Corporate
and Other
 
Consolidated
 
 
(Dollars in thousands)
Revenues
 
$
1,776,204

 
$
269,079

 
$
—

 
$
2,045,283

Adjusted EBITDA
 
294,373

 
8,550

 
(192,178
)
 
110,745

Additions to property, plant, equipment and mine development
 
69,931

 
7,437

 
895

 
78,263

Loss from equity affiliates
 
398

 
—

 
—

 
398

 A reconciliation of Adjusted EBITDA to net income (loss) follows:
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
 
(Dollars in thousands)
Adjusted EBITDA
 
$
176,741

 
$
141,861

 
$
110,745

Depreciation, depletion and amortization
 
(186,348
)
 
(188,074
)
 
(205,339
)
Asset retirement obligation expense
 
(81,586
)
 
(63,034
)
 
(35,116
)
Sales contract accretion
 
55,020

 
121,475

 
298,572

Restructuring and impairment charge
 
(13,657
)
 
(15,174
)
 
(20,157
)
Interest expense
 
(65,533
)
 
(57,419
)
 
(38,108
)
Interest income
 
246

 
12,831

 
16,646

Income tax provision
 
(372
)
 
(492
)
 
—

Net income (loss)
 
$
(115,489
)
 
$
(48,026
)
 
$
127,243



F-38
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(25)Stockholders’ Equity
Common Stock
Patriot has 300 million authorized shares of $0.01 par value common stock. Each share of common stock is entitled to one vote in the election of directors and all other matters submitted to stockholder vote. Except as otherwise required by law or provided in any resolution adopted by the Board of Directors with respect to any series of preferred stock, the holders of common stock will possess all voting power. The holders of common stock do not have cumulative voting rights. In general, all matters submitted to a meeting of stockholders, other than as described below, shall be decided by vote of a majority of the shares of Patriot’s common stock. Directors are elected by a plurality of the shares of Patriot’s common stock.
Subject to preferences that may be applicable to any series of preferred stock, the owners of Patriot’s common stock may receive dividends when declared by the Board of Directors. Common stockholders will share equally in the distribution of all assets remaining after payment to creditors and preferred stockholders upon liquidation, dissolution or winding up of the Company, whether voluntarily or not. The common stock will have no preemptive or similar rights.
Effective August 11, 2008, we implemented a 2-for-1 stock split on all shares of our common stock. All share and per share amounts in these consolidated financial statements and related notes reflect the stock split.
On June 16, 2009, we completed a public offering of 12 million shares of our common stock in a registered public offering under our shelf registration at $7.90 per share. The net proceeds from the sale of shares, after deducting fees and commissions, were $89.1 million. The proceeds were used to repay the outstanding balance on our revolving credit facility, with the remainder used for general corporate purposes.
The following table summarizes common stock activity from January 1, 2009 to December 31, 2011:
 
 
 
2011
 
2010
 
2009
Shares outstanding at the beginning of the year
 
90,944,595

 
90,319,939

 
77,383,199

Stock options exercised
 
23,000

 
61,097

 
12,729

Stock grants to employees
 
758,096

 
259,458

 
553,428

Employee stock purchases
 
159,647

 
304,101

 
370,583

Shares issued in equity offering
 
—

 
—

 
12,000,000

Shares outstanding at the end of the year
 
91,885,338

 
90,944,595

 
90,319,939

Preferred Stock
In addition to the common stock, the Board of Directors is authorized to issue up to 10 million shares of $0.01 par value preferred stock. The authorized preferred shares include 1,000,000 shares of Series A Junior Participating Preferred Stock. Our certificate of incorporation authorizes the Board of Directors, without the approval of the stockholders, to fix the designation, powers, preferences and rights of one or more series of preferred stock, which may be greater than those of the common stock. We believe that the ability of the Board to issue one or more series of preferred stock will provide us with flexibility in structuring possible future financings and acquisitions and in meeting other corporate needs that might arise. The issuance of shares of preferred stock, or the issuance of rights to purchase shares of preferred stock, could be used to discourage an unsolicited acquisition proposal. There were no outstanding shares of preferred stock as of December 31, 2011 and 2010.
Preferred Share Purchase Rights Plan and Series A Junior Participating Preferred Stock
The Board of Directors adopted a stockholders rights plan pursuant to the Rights Agreement with American Stock Transfer & Trust Company (the Rights Agreement). In connection with the Rights Agreement, on October 31, 2007, we filed the Certificate of Designations of Series A Junior Participating Preferred Stock (the Certificate of Designations) with the Secretary of State of the State of Delaware. Pursuant to the Certificate of Designations, we designated 1,000,000 shares of preferred stock as Series A Junior Participating Preferred Stock having the designations, rights, preferences and limitations set forth in the Rights Agreement. Each preferred share purchase right represents the right to purchase one-half of one-hundredth of a share of Series A Junior Participating Preferred Stock.

F-39
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The rights have certain anti-takeover effects. If the rights become exercisable, the rights will cause substantial dilution to a person or group that attempts to acquire Patriot on terms not approved by the Board of Directors, except pursuant to any offer conditioned on a substantial number of rights being acquired. The rights should not interfere with any merger or other business combination approved by the Board since the rights may be redeemed by Patriot at a nominal price prior to the time that a person or group has acquired beneficial ownership of 15% or more of common stock. Thus, the rights are intended to encourage persons who may seek to acquire control of Patriot to initiate such an acquisition through negotiations with the Board. However, the effect of the rights may be to discourage a third party from making a partial tender offer or otherwise attempting to obtain a substantial equity position in our equity securities or seeking to obtain control of Patriot. To the extent any potential acquirers are deterred by the rights, the rights may have the effect of preserving incumbent management in office. There were no outstanding shares of Series A Junior Participating Preferred Stock as of December 31, 2011 and 2010.
We have not paid cash dividends and 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 the Board deems relevant.

(26)Stock-Based Compensation
We have one equity incentive plan for employees and eligible non-employee directors that allows for the issuance of share-based compensation in the form of restricted stock, incentive stock options, nonqualified stock options, stock appreciation rights, performance awards, restricted stock units and deferred stock units. Members of our Board of Directors are eligible for deferred stock unit grants at the date of their election and annually. This plan has 11.7 million shares of our common stock available for grant, with 6.7 million shares remaining available for grant as of December 31, 2011. Additionally, we have established an employee stock purchase plan that provides for the purchase of up to 2.5 million shares of our common stock, with 1.6 million shares available for grant as of December 31, 2011.
Share-based compensation expense of $12.4 million, $10.7 million and $11.4 million was recorded in “Selling and administrative expenses” in the consolidated statements of operations for the years ended December 31, 2011, 2010 and 2009, respectively, and $1.4 million, $1.2 million and $1.3 million was recorded in “Operating costs and expenses” for the years ended December 31, 2011, 2010 and 2009, respectively. Share-based compensation expense included $0.1 million, $0.5 million and $0.9 million related to awards from restricted stock and stock options granted by Peabody to Patriot employees prior to spin-off for the years ended December 31, 2011, 2010 and 2009, respectively. As of December 31, 2011, the total unrecognized compensation cost related to nonvested awards granted after the spin-off was $13.6 million, net of taxes, which is expected to be recognized over a weighted-average period of 1.6 years. As of December 31, 2011, there was no unrecognized compensation cost related to nonvested awards granted by Peabody prior to the spin-off.
Restricted Stock
We have restricted stock agreements in place for grants to employees and service providers of Patriot and our subsidiaries. Certain of these agreements provide that restricted stock issued will fully vest on the third anniversary of the date the restricted stock was granted, while more recent grants provide a graded vesting schedule over three years. The restricted stock will fully vest sooner if a grantee terminates employment with or stops providing services to Patriot because of death or disability, or if a change in control occurs, as defined in the equity plan.

F-40
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

A summary of restricted stock award activity is as follows: 
    
 
 
Year Ended
December 31,
2011
 
Weighted
Average
Grant-Date
Fair Value
Nonvested at January 1, 2011
 
941,955

 
$
10.70

Granted
 
434,894

 
19.49

Forfeited
 
(127,166
)
 
10.38

Vested
 
(138,476
)
 
22.65

Nonvested at December 31, 2011
 
1,111,207

 
12.68

Restricted Stock Units
We have long-term incentive restricted stock unit agreements in place for grants to employees and service providers. These agreements grant restricted stock units that vest over time as well as restricted stock units that vest based upon our financial performance. In general, the restricted stock units that vest over time will be 50% vested on the fifth anniversary of the initial date of grant, 75% vested on the sixth such anniversary and 100% vested on the seventh such anniversary. The restricted stock units that vest over time will fully vest sooner if a grantee terminates employment with or stops providing services to Patriot because of death or disability, or if a change in control occurs, as defined in the equity plan.
In addition, we have deferred stock unit agreements in place for grants to non-employee directors of Patriot. These agreements provide that the deferred stock units will fully vest on the first anniversary of the date of grant, if the non-employee director served as a director for the entire one-year period between the date of grant and the first anniversary of the grant. The deferred stock units will fully vest sooner if a non-employee director ceases to be a Patriot director due to death or disability, or if a change in control occurs (as such term is defined in the Equity Plan). Any unvested deferred stock units will be forfeited if a non-employee director terminates service with Patriot for any reason other than death or disability prior to the first anniversary of the grant date. After vesting, the deferred stock units will be settled by issuing shares of Patriot common stock equal to the number of deferred stock units, and the settlement will occur upon the earlier of (i) the non-employee director’s termination of service as a director or (ii) the third anniversary of the grant date or a different date chosen by the non-employee director, provided the date was chosen by the non-employee director prior to January 1 of the year in which the director received the grant.
A summary of restricted stock time-based units and deferred stock units award activity is as follows:
        
 
 
Year Ended
December 31,
2011
 
Weighted
Average
Grant-Date
Fair Value
Nonvested at January 1, 2011
 
409,867

 
$
19.49

Granted
 
35,809

 
21.08

Forfeited
 
(28,520
)
 
18.75

Vested
 
(22,542
)
 
17.30

Nonvested at December 31, 2011
 
394,614

 
19.81

As of December 31, 2011, there were 52,326 deferred stock units vested that had an aggregate intrinsic value of $0.4 million.
Certain performance-based restricted stock units vest according to a formula, which is primarily based on our financial performance as measured by EBITDA, return on equity and leverage ratios. The achievement of the performance-based unit calculations is determined on December 31 following the fifth, sixth and seventh anniversaries of the initial grant date. We estimated the number of performance-based units that are expected to vest and utilized this amount in the calculation of the stock-based compensation expense related to these awards. Any changes to this estimate will impact stock-based compensation expense in the period during which the estimate is changed.

F-41
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

We have also granted performance-based stock units that vest based on market conditions. The number of shares issued is dependent upon the change in our shareholder value over a three-year vesting period versus the change of various peers for that time period. The fair value of the awards granted in 2011 was determined using a Monte Carlo simulation model, allowing us to factor in the probability of various outcomes. The weighted-average fair value of $30.40 was determined using a risk-free rate of 0.99%, an expected option life of 3.0 years, an expected dividend yield of zero, and volatilities that ranged from 74.0% to 106.6%. As of December 31, 2011, we had performance-based stock units that vested at a multiplier of 2, resulting in an issuance of 458,706 shares, with the remainder relinquished for taxes.
A summary of restricted stock performance units award activity is as follows: 
        
 
 
Year Ended
December 31,
2011
 
Weighted
Average
Grant-Date
Fair Value
Nonvested at January 1, 2011
 
876,144

 
$
17.12

Granted
 
75,382

 
30.40

Forfeited
 
(42,782
)
 
18.75

Vested
 
(241,332
)
 
7.48

Nonvested at December 31, 2011
 
667,412

 
22.00

Long-Term Incentive Non-Qualified Stock Option
We have long-term incentive non-qualified stock option agreements in place for grants to employees and service providers of Patriot. Generally, the agreements provide that any option awarded will become exercisable in three installments. Options granted in 2007 and 2008 will be 50% exercisable on the fifth anniversary of the November 2007 grant date, 75% exercisable on the sixth such anniversary and 100% exercisable on the seventh such anniversary. Options granted in 2009, 2010 and 2011 are exercisable on a graded vesting schedule of 33.33% on each anniversary over a three year period. The option will become fully exercisable sooner if a grantee terminates employment with or stops providing services to Patriot because of death or disability, or if a change in control occurs, as defined in the equity plan. No option can be exercised more than ten years after the date of grant, but the ability to exercise the option may terminate sooner upon the occurrence of certain events detailed in the Long-Term Incentive Non-Qualified Stock Option Agreement.
A summary of non-qualified stock options outstanding activity is as follows: 
    
 
 
Year Ended
December 31,
2011
 
Weighted
Average
Exercise
Price
 
Aggregate
Intrinsic
Value
(in millions)
 
Weighted
Average
Remaining
Contractual
Life
Options outstanding at January 1, 2011
 
1,509,348

 
$
15.04

 
 
 
 
Granted
 
246,918

 
17.25

 
 
 
 
Forfeited
 
(67,012
)
 
18.75

 
 
 
 
Exercised
 
(23,000
)
 
5.13

 
$
0.2

 
 
Options outstanding at December 31, 2011
 
1,666,254

 
$
15.35

 
$
1.5

 
6.35

Vested and Exercisable
 
346,433

 
$
6.80

 
$
1.0

 
5.84


F-42
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

We used the Black-Scholes option pricing model to determine the fair value of stock options. Determining the fair value of share-based awards requires judgment, including estimating the expected term that stock options will be outstanding prior to exercise and the associated volatility. We utilized U.S. Treasury yields as of the grant date for the risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option. We utilized a peer historical “look-back” to develop the expected volatility. Expected option life assumptions were developed by taking the weighted average time to vest plus the weighted average holding period after vesting.
    
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
Weighted-average fair value
 
$
8.98

 
$
9.63

 
$
2.49

Risk-free interest rate
 
0.74
%
 
1.49
%
 
1.31
%
Expected option life
 
2.95 years
 
2.95 years
 
2.87 years
Expected volatility
 
80.52
%
 
87.67
%
 
78.41
%
Dividend yield
 
0
%
 
0
%
 
0
%
Employee Stock Purchase Plan
Based on our employee stock purchase plan, eligible full-time and part-time employees are able to contribute up to 15% of their base compensation into this plan, subject to a fair market value limit of $25,000 per person per year as defined by the Internal Revenue Service (IRS). Effective January 1, 2008, employees are able to purchase Patriot common stock at a 15% discount to the lower of the fair market value of our common stock on the initial or final trading dates of each six-month offering period. Offering periods begin on January 1 and July 1 of each year. The fair value of the six-month “look-back” option in our employee stock purchase plan is estimated by adding the fair value of 0.15 of one share of stock to the fair value of 0.85 of an option on one share of stock. We issued 159,647 shares of common stock and recognized $0.9 million expense in “Selling and administrative expenses” and $0.1 million in “Operating costs and expenses” for the year ended December 31, 2011. We issued 304,101 shares of common stock and recognized $0.8 million expense in “Selling and administrative expenses” and $0.1 million in “Operating costs and expenses” for the year ended December 31, 2010. We issued 370,583 shares of common stock and recognized $1.1 million expense in “Selling and administrative expenses” and $0.1 million in “Operating costs and expenses” for the year ended December 31, 2009.


F-43
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(27)Summary Quarterly Financial Information (Unaudited)
A summary of the unaudited quarterly results of operations for the years ended December 31, 2011 and 2010 is presented below. Patriot common stock is listed on the New York Stock Exchange under the symbol PCX.
 
 
Year Ended December 31, 2011
 
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
 
(Dollars in thousands, except per share and stock price data)
Revenues
 
$577,024
 
$632,160
 
$589,395
 
$603,927
Operating profit (loss)
 
7,913
 
4,394
 
(33,367)
 
(28,770)
Net loss
 
(15,296)
 
(12,355)
 
(49,517)
 
(38,321)
Basic loss per share
 
$(0.17)
 
$(0.14)
 
$(0.54)
 
$(0.42)
Diluted loss per share
 
$(0.17)
 
$(0.14)
 
$(0.54)
 
$(0.42)
Weighted average shares used in calculating basic earnings per share
 
91,284,321
 
91,284,418
 
91,329,096
 
91,388,664
Stock price - high and low prices
 
$29.20-$19.68
 
$27.56-$18.61
 
$24.99-$8.45
 
$13.43-$6.92
 
 
Year Ended December 31, 2010
 
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
 
(Dollars in thousands, except per share and stock price data)
Revenues
 
$467,257
 
$538,992
 
$500,683
 
$528,179
Operating profit (loss)
 
10,086
 
(1,863)
 
(32,099)
 
20,930
Net income
 
4,261
 
(13,574)
 
(45,993)
 
7,280
Basic earnings per share
 
$0.05
 
$(0.15)
 
$(0.51)
 
$0.08
Diluted earnings per share
 
$0.05
 
$(0.15)
 
$(0.51)
 
$0.08
Weighted average shares used in calculating basic earnings per share
 
90,835,561
 
90,863,950
 
90,968,377
 
90,959,138
Stock price - high and low prices
 
$22.37-$13.87
 
$24.25-$11.68
 
$14.03-$9.76
 
$19.94-$11.52
(28)Subsequent Event
In January 2012, we announced the idling of and production curtailment at certain metallurgical coal mines in our Rocklick and Wells mining complexes in response to weaker demand. In February 2012, we also announced the closure of the Big Mountain mining complex in response to weaker thermal coal demand. The Big Mountain mining complex produced 1.8 million tons of thermal coal in 2011. We expect to record a charge of approximately $50 million to $60 million in the first quarter of 2012 in relation to this closure. This charge is expected to include an impairment component related to certain assets, including infrastructure, mine development, equipment and certain coal reserves. We also expect to record a charge to asset retirement obligation expense related to the acceleration of the reclamation activities.

(29)Supplemental Guarantor/Non-Guarantor Financial Information
The following tables present consolidating financial information for: (a) Patriot Coal Corporation (the “Parent”) on a stand-alone basis; (b) the subsidiary guarantors of our 8.25% Senior Notes due 2018 (“Guarantor Subsidiaries”) on a combined basis and (c) the Non-Guarantor Subsidiary, Patriot Coal Receivables (SPV) Ltd., on a stand-alone basis. Each Guarantor Subsidiary is 100% wholly-owned by Patriot Coal Corporation. The guarantees from each of the Guarantor Subsidiaries are full, unconditional, joint and several. Accordingly, separate financial statements of the wholly-owned Guarantor Subsidiaries are not presented because the Guarantor Subsidiaries are jointly, severally and unconditionally liable under the guarantees, and we believe that separate financial statements and other disclosures regarding the Guarantor Subsidiaries are not material to investors.

F-44
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)



SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
 
 
 
Year Ended December 31, 2011
 
 
Parent
Company
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiary
 
Eliminations
 
Consolidated
 
 
(Dollars in thousands)
Revenues
 
 
 
 
 
 
 
 
 
 
Sales
 
$
—

 
$
2,378,260

 
$
—

 
$
—

 
$
2,378,260

Other revenues
 
—

 
24,246

 
—

 
—

 
24,246

Total revenues
 
—

 
2,402,506

 
—

 
—

 
2,402,506

Costs and expenses
 
 
 
 
 
 
 
 
 

Operating costs and expenses
 
—

 
2,213,124

 
—

 
—

 
2,213,124

Depreciation, depletion and amortization
 
—

 
186,348

 
—

 
—

 
186,348

Asset retirement obligation expense
 
—

 
81,586

 
—

 
—

 
81,586

Sales contract accretion
 
—

 
(55,020
)
 
—

 
—

 
(55,020
)
Restructuring and impairment charge
 
—

 
13,657

 
—

 
—

 
13,657

Selling and administrative expenses
 
18,661

 
34,246

 
—

 
—

 
52,907

Net gain on disposal or exchange of assets
 
—

 
(35,557
)
 
—

 
—

 
(35,557
)
Income from equity affiliates
 
50,034

 
(4,709
)
 
—

 
(50,034
)
 
(4,709
)
Operating profit (loss)
 
(68,695
)
 
(31,169
)
 
—

 
50,034

 
(49,830
)
Interest expense and other
 
47,024

 
18,509

 
1,539

 
(1,539
)
 
65,533

Interest income
 
(230
)
 
(16
)
 
(1,539
)
 
1,539

 
(246
)
Income (loss) before income taxes
 
(115,489
)
 
(49,662
)
 
—

 
50,034

 
(115,117
)
Income tax provision
 
—

 
372

 
—

 
—

 
372

Net income (loss)
 
$
(115,489
)
 
$
(50,034
)
 
$
—

 
$
50,034

 
$
(115,489
)


F-45
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
 
 
 
Year Ended December 31, 2010
 
 
Parent
Company
 
Guarantor
Subsidiaries
 
Non-Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
 
(Dollars in thousands)
Revenues
 
 
 
 
 
 
 
 
 
 
Sales
 
$
—

 
$
2,017,464

 
$
—

 
$
—

 
$
2,017,464

Other revenues
 
—

 
17,647

 
—

 
—

 
17,647

Total revenues
 
—

 
2,035,111

 
—

 
—

 
2,035,111

Costs and expenses
 
 
 
 
 
 
 
 
 
 
Operating costs and expenses
 
122

 
1,900,582

 
—

 
—

 
1,900,704

Depreciation, depletion and amortization
 
1,761

 
186,313

 
—

 
—

 
188,074

Asset retirement obligation expense
 
—

 
63,034

 
—

 
—

 
63,034

Sales contract accretion
 
—

 
(121,475
)
 
—

 
—

 
(121,475
)
Restructuring and impairment charge
 
—

 
15,174

 
—

 
—

 
15,174

Selling and administrative expenses
 
50,222

 
26

 
—

 
—

 
50,248

Net gain on disposal or exchange of assets
 
—

 
(48,226
)
 
—

 
—

 
(48,226
)
Income from equity affiliates
 
(53,882
)
 
(9,476
)
 
—

 
53,882

 
(9,476
)
Operating profit (loss)
 
1,777

 
49,159

 
—

 
(53,882
)
 
(2,946
)
Interest expense and other
 
49,885

 
7,534

 
1,041

 
(1,041
)
 
57,419

Interest income
 
(82
)
 
(12,749
)
 
(1,041
)
 
1,041

 
(12,831
)
Income (loss) before income taxes
 
(48,026
)
 
54,374

 
—

 
(53,882
)
 
(47,534
)
Income tax provision
 
—

 
492

 
—

 
—

 
492

Net income (loss)
 
$
(48,026
)
 
$
53,882

 
$
—

 
$
(53,882
)
 
$
(48,026
)

F-46
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
 
 
 
Year Ended December 31, 2009
 
 
Parent
Company
 
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
 
 
(Dollars in thousands)
Revenues
 
 
 
 
 
 
 
 
Sales
 
$
—

 
$
1,995,667

 
$
—

 
$
1,995,667

Other revenues
 
—

 
49,616

 
—

 
49,616

Total revenues
 
—

 
2,045,283

 
—

 
2,045,283

Costs and expenses
 
 
 
 
 
 
 

Operating costs and expenses
 
254

 
1,893,165

 
—

 
1,893,419

Depreciation, depletion and amortization
 
2,316

 
203,023

 
—

 
205,339

Asset retirement obligation expense
 
—

 
35,116

 
—

 
35,116

Sales contract accretion
 
—

 
(298,572
)
 
—

 
(298,572
)
Restructuring and impairment charge
 
—

 
20,157

 
—

 
20,157

Selling and administrative expenses
 
47,334

 
1,398

 
—

 
48,732

Net gain on disposal or exchange of assets
 
—

 
(7,215
)
 
—

 
(7,215
)
Income from equity affiliates
 
(206,492
)
 
(398
)
 
206,492

 
(398
)
Operating profit (loss)
 
156,588

 
198,609

 
(206,492
)
 
148,705

Interest expense and other
 
29,415

 
8,693

 
—

 
38,108

Interest income
 
(70
)
 
(16,576
)
 
—

 
(16,646
)
Income (loss) before income taxes
 
127,243

 
206,492

 
(206,492
)
 
127,243

Income tax provision
 
—

 
—

 
—

 
—

Net income (loss)
 
$
127,243

 
$
206,492

 
$
(206,492
)
 
$
127,243

 
 
 
 
 
 
 
 
 



F-47
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)



SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS
 
 
 
December 31, 2011
 
 
Parent
Company
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiary
 
Eliminations
 
Consolidated
 
 
(Dollars in thousands)
ASSETS
 
 
 
 
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
193,882

 
$
280

 
$
—

 
$
—

 
$
194,162

Accounts receivable and other, net
 
313

 
177,382

 
171,101

 
(171,101
)
 
177,695

Inventories
 
—

 
98,366

 
—

 
—

 
98,366

Prepaid expenses and other current assets
 
709

 
27,482

 
—

 
—

 
28,191

Total current assets
 
194,904

 
303,510

 
171,101

 
(171,101
)
 
498,414

Property, plant, equipment and mine development
 
 
 
 
 

 
 
 
 
Land and coal interests
 
—

 
2,935,796

 
—

 
—

 
2,935,796

Buildings and improvements
 
—

 
504,275

 
—

 
—

 
504,275

Machinery and equipment
 
—

 
748,013

 
—

 
—

 
748,013

Less accumulated depreciation, depletion and
    amortization
 
—

 
(973,157
)
 
—

 
—

 
(973,157
)
Property, plant, equipment and mine
    development, net
 
—

 
3,214,927

 
—

 
—

 
3,214,927

Notes receivable
 
—

 
—

 
—

 
—

 
—

Investments, intercompany and other assets
 
1,299,618

 
(89,162
)
 
—

 
(1,147,253
)
 
63,203

Total assets
 
$
1,494,522

 
$
3,429,275

 
$
171,101

 
$
(1,318,354
)
 
$
3,776,544

LIABILITIES AND
 STOCKHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
 
 
 
Accounts payable and accrued expenses
 
$
7,993

 
$
451,701

 
$
171,101

 
$
(171,101
)
 
$
459,694

Below market sales contracts acquired
 
—

 
44,787

 
—

 
—

 
44,787

Current portion of debt
 
—

 
1,182

 
—

 
—

 
1,182

Total current liabilities
 
7,993

 
497,670

 
171,101

 
(171,101
)
 
505,663

Long-term debt, less current maturities
 
433,951

 
7,113

 
—

 
—

 
441,064

Asset retirement obligations
 
—

 
417,900

 
—

 
—

 
417,900

Workers’ compensation obligations
 
—

 
231,585

 
—

 
—

 
231,585

Postretirement benefit obligations
 
—

 
1,387,317

 
—

 
—

 
1,387,317

Obligation to industry fund
 
—

 
35,429

 
—

 
—

 
35,429

Below market sales contracts acquired, noncurrent
 
—

 
46,217

 
—

 
—

 
46,217

Other noncurrent liabilities
 
1,213

 
44,005

 
—

 
—

 
45,218

Total liabilities
 
443,157

 
2,667,236

 
171,101

 
(171,101
)
 
3,110,393

Stockholders’ equity
 
1,051,365

 
762,039

 
—

 
(1,147,253
)
 
666,151

Total liabilities and stockholders’ equity
 
$
1,494,522

 
$
3,429,275

 
$
171,101

 
$
(1,318,354
)
 
$
3,776,544


F-48
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS
 
 
 
December 31, 2010
 
 
Parent
Company
 
Guarantor
Subsidiaries
 
Non-Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
 
(Dollars in thousands)
ASSETS
 
 
 
 
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
192,593

 
$
474

 
$
—

 
$
—

 
$
193,067

Accounts receivable and other, net
 
522

 
206,843

 
146,652

 
(146,652
)
 
207,365

Inventories
 
—

 
97,973

 
—

 
—

 
97,973

Prepaid expenses and other current assets
 
2,603

 
26,045

 
—

 
—

 
28,648

Total current assets
 
195,718

 
331,335

 
146,652

 
(146,652
)
 
527,053

Property, plant, equipment and mine development
 
 
 
 
 
 
 
 
 
 
Land and coal interests
 
—

 
2,870,182

 
—

 
—

 
2,870,182

Buildings and improvements
 
2,554

 
436,772

 
—

 
—

 
439,326

Machinery and equipment
 
16,147

 
663,282

 
—

 
—

 
679,429

Less accumulated depreciation, depletion and
     amortization
 
(13,806
)
 
(814,596
)
 
—

 
—

 
(828,402
)
Property, plant, equipment and mine
    development, net
 
4,895

 
3,155,640

 
—

 
—

 
3,160,535

Notes receivable
 
—

 
69,540

 
—

 
—

 
69,540

Investments, intercompany and other assets
 
1,409,341

 
(159,146
)
 
—

 
(1,197,287
)
 
52,908

Total assets
 
$
1,609,954

 
$
3,397,369

 
$
146,652

 
$
(1,343,939
)
 
$
3,810,036

LIABILITIES AND
STOCKHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
 
 
 
Accounts payable and accrued expenses
 
$
26,752

 
$
382,532

 
$
146,652

 
$
(146,652
)
 
$
409,284

Below market sales contracts acquired
 
—

 
70,917

 
—

 
—

 
70,917

Current portion of debt
 
—

 
3,329

 
—

 
—

 
3,329

Total current liabilities
 
26,752

 
456,778

 
146,652

 
(146,652
)
 
483,530

Long-term debt, less current maturities
 
424,408

 
27,121

 
—

 
—

 
451,529

Asset retirement obligations
 
—

 
349,791

 
—

 
—

 
349,791

Workers’ compensation obligations
 
—

 
220,757

 
—

 
—

 
220,757

Postretirement benefit obligations
 
3,721

 
1,265,447

 
—

 
—

 
1,269,168

Obligation to industry fund
 
—

 
38,978

 
—

 
—

 
38,978

Below market sales contracts acquired, noncurrent
 
—

 
92,253

 
—

 
—

 
92,253

Other noncurrent liabilities
 
2,022

 
58,927

 
—

 
—

 
60,949

Total liabilities
 
456,903

 
2,510,052

 
146,652

 
(146,652
)
 
2,966,955

Stockholders’ equity
 
1,153,051

 
887,317

 
—

 
(1,197,287
)
 
843,081

Total liabilities and stockholders’ equity
 
$
1,609,954

 
$
3,397,369

 
$
146,652

 
$
(1,343,939
)
 
$
3,810,036



F-49
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

 

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
 
 
 
Year Ended December 31, 2011
 
 
Parent
Company
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiary
 
Eliminations
 
Consolidated
 
 
(Dollars in thousands)
Cash Flows From Operating Activities
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
(51,137
)
 
$
175,874

 
$
—

 
$
—

 
$
124,737

Cash Flows From Investing Activities
 
 
 
 
 
 
 
 
 
 
Additions to property, plant, equipment and mine
    development
 
—

 
(174,713
)
 
—

 
—

 
(174,713
)
Proceeds from notes receivable
 
—

 
115,679

 
—

 
—

 
115,679

Additions to advance mining royalties
 
—

 
(26,030
)
 
—

 
—

 
(26,030
)
Proceeds from disposal or exchange of assets
 
—

 
6,928

 
—

 
—

 
6,928

Net cash paid in litigation settlement and asset
    acquisition
 
—

 
(14,787
)
 
—

 
—

 
(14,787
)
Net cash used in investing activities
 
—

 
(92,923
)
 
—

 
—

 
(92,923
)
Cash Flows From Financing Activities
 
 
 
 
 
 
 
 
 
 
Deferred financing costs
 
(1,832
)
 
—

 
—

 
—

 
(1,832
)
Long-term debt payments
 
—

 
(31,002
)
 
—

 
—

 
(31,002
)
Proceeds from employee stock programs
 
2,115

 
—

 
—

 
—

 
2,115

Intercompany transactions
 
52,143

 
(52,143
)
 
—

 
—

 
—

Net cash provided by (used in) financing activities
 
52,426

 
(83,145
)
 
—

 
—

 
(30,719
)
Net increase (decrease) in cash and cash equivalents
 
1,289

 
(194
)
 
—

 
—

 
1,095

Cash and cash equivalents at beginning of period
 
192,593

 
474

 
—

 
—

 
193,067

Cash and cash equivalents at end of period
 
$
193,882

 
$
280

 
$
—

 
$
—

 
$
194,162


F-50
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
 
 
 
Year Ended December 31, 2010
 
 
Parent
Company
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiary
 
Eliminations
 
Consolidated
 
 
(Dollars in thousands)
Cash Flows From Operating Activities
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
(61,469
)
 
$
97,780

 
$
—

 
$
—

 
$
36,311

Cash Flows From Investing Activities
 
 
 
 
 
 
 
 
 
 
Additions to property, plant, equipment and mine
     development
 
(1,708
)
 
(121,281
)
 
—

 
—

 
(122,989
)
Proceeds from notes receivable
 
—

 
33,100

 
—

 
—

 
33,100

Additions to advance mining royalties
 
—

 
(21,510
)
 
—

 
—

 
(21,510
)
Proceeds from disposal or exchange of assets
 
—

 
1,766

 
—

 
—

 
1,766

Other
 
—

 
(300
)
 
—

 
—

 
(300
)
Net cash used in investing activities
 
(1,708
)
 
(108,225
)
 
—

 
—

 
(109,933
)
Cash Flows From Financing Activities
 
 
 
 
 
 
 
 
 
 
Proceeds from debt offering, net of discount
 
248,198

 
—

 
—

 
—

 
248,198

Proceeds from coal reserve financing transaction
 
—

 
17,700

 
—

 
—

 
17,700

Deferred financing costs
 
(20,740
)
 
—

 
—

 
—

 
(20,740
)
Long-term debt payments
 
—

 
(8,042
)
 
—

 
—

 
(8,042
)
Proceeds from employee stock programs
 
2,475

 
—

 
—

 
—

 
2,475

Intercompany transactions
 
(737
)
 
737

 
—

 
—

 
—

Net cash provided by financing activities
 
229,196

 
10,395

 
—

 
—

 
239,591

Net increase (decrease) in cash and cash equivalents
 
166,019

 
(50
)
 
—

 
—

 
165,969

Cash and cash equivalents at beginning of period
 
26,574

 
524

 
—

 
—

 
27,098

Cash and cash equivalents at end of period
 
$
192,593

 
$
474

 
$
—

 
$
—

 
$
193,067


F-51
PATRIOT COAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
 
 
 
Year Ended December 31, 2009
 
 
Parent
Company
 
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
 
 
(Dollars in thousands)
Cash Flows From Operating Activities
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
(45,370
)
 
$
84,981

 
$
—

 
$
39,611

Cash Flows From Investing Activities
 
 
 
 
 
 
 
 
Additions to property, plant, equipment and mine
      development
 
(896
)
 
(77,367
)
 
—

 
(78,263
)
Additions to advance mining royalties
 
—

 
(16,997
)
 
—

 
(16,997
)
Proceeds from notes receivable
 
—

 
11,000

 
—

 
11,000

Proceeds from disposal or exchange of assets
 
—

 
5,513

 
—

 
5,513

Other
 
—

 
1,154

 
—

 
1,154

Net cash used in investing activities
 
(896
)
 
(76,697
)
 
—

 
(77,593
)
Cash Flows From Financing Activities
 
 
 
 
 
 
 
 
Proceeds from equity offering, net of costs
 
89,077

 
—

 
—

 
89,077

Long-term debt payments
 
—

 
(5,905
)
 
—

 
(5,905
)
Short-term debt payments
 
(23,000
)
 
—

 
—

 
(23,000
)
Proceeds from employee stock programs
 
2,036

 
—

 
—

 
2,036

Intercompany transactions
 
2,770

 
(2,770
)
 
—

 
—

Net cash provided by financing activities
 
70,883

 
(8,675
)
 
—

 
62,208

Net increase (decrease) in cash and cash equivalents
 
24,617

 
(391
)
 
—

 
24,226

Cash and cash equivalents at beginning of period
 
1,957

 
915

 
—

 
2,872

Cash and cash equivalents at end of period
 
$
26,574

 
$
524

 
$
—

 
$
27,098




F-52


PATRIOT COAL CORPORATION

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
DECEMBER 31, 2011
 
Description
 
Balance at
Beginning
of Period
 
Charged to
Costs and
Expenses
 
Deductions(1)
 
Other
 
 
 
Balance at
End of
Period
 
 
(Dollars in thousands)
Year Ended December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
Reserves deducted from asset accounts:
 
 
 
 
 
 
 
 
 
 
 
 
Advance royalty recoupment reserve
 
$
43,564

 
$
252

 
$
—

 
$
927

 
(2)  
 
$
44,743

Reserve for materials and supplies
 
9,943

 
(11
)
 
(19
)
 
2,619

 
(2)  
 
12,532

Allowance for doubtful accounts
 
540

 
115

 
(514
)
 
—

 
  
 
141

Year Ended December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
Reserves deducted from asset accounts:
 
 
 
 
 
 
 
 
 
 
 
 
Advance royalty recoupment reserve
 
44,743

 
3,112

 
—

 
—

 

 
47,855

Reserve for materials and supplies
 
12,532

 
(3,399
)
 
—

 
—

 

 
9,133

Allowance for doubtful accounts
 
141

 
—

 
—

 
—

 
  
 
141

Year Ended December 31, 2011
 
 
 
 
 
 
 
 
 
 
 
 
Reserves deducted from asset accounts:
 
 
 
 
 
 
 
 
 
 
 
 
Advance royalty recoupment reserve
 
47,855

 
2,800

 
(1,497
)
 
—

 
  
 
49,158

Reserve for materials and supplies
 
9,133

 
32

 
—

 
—

 
  
 
9,165

Allowance for doubtful accounts
 
141

 
(3
)
 
—

 
—

 
  
 
138

 
(1) 
Reserves utilized, unless otherwise indicated.
(2) 
Activity reflects the final purchase accounting asset valuation entries for the Magnum acquisition, which were finalized in June 2009.


F-53