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, 2012

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:

None.

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

Common Stock, par value $0.01 per share

Preferred Share Purchase Rights

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

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

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

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

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

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

Large accelerated filer	¨	Accelerated filer	þ
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 29, 2012: Common Stock, par value $0.01 per share, $111.6 million.

Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 15, 2013: Common Stock, par value $0.01 per share, 92,407,579 shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Part III of this Annual Report incorporates by reference certain information that the registrant intends to file in an amendment to this Form 10-K no later than 120 days after the close of the registrant’s fiscal year ended December 31, 2012. 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.	Business	8
Item 1A.	Risk Factors	32
Item 1B.	Unresolved Staff Comments	49
Item 2.	Properties	50
Item 3.	Legal Proceedings	54
Item 4.	Mine Safety Disclosure	60
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	61
Item 6.	Selected Consolidated Financial Data	61
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	64
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	86
Item 8.	Financial Statements and Supplementary Data	87
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	87
Item 9A.	Controls and Procedures	87
Item 9B.	Other Information	92
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	92
Item 11.	Executive Compensation	92
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	92
Item 13.	Certain Relationships and Related Transactions, and Director Independence	92
Item 14.	Principal Accounting Fees and Services	92
PART IV
Item 15.	Exhibits and Financial Statement Schedules	F-0

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CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

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

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

• our ability to continue as a going concern;

• our ability to successfully complete a reorganization under Chapter 11 and emerge from bankruptcy, which is dependent upon, among other things, our ability to implement changes to wage and benefit programs and postretirement benefit obligations pursuant to Sections 1113 and 1114 of the Bankruptcy Code, to minimize our liabilities upon emergence and to obtain post-bankruptcy financing;

• negotiation of labor contracts, labor availability and relations, including negotiations with the UMWA related to Section 1113 and 1114 of the Bankruptcy Code, which could result in labor disruptions, work stoppages or slowdowns;

• our ability to operate within the restrictions and liquidity limitations of the post-petition credit facilities authorized by the Bankruptcy Court in connection with the Bankruptcy Case (the DIP Facilities);

• potential adverse effects of the Bankruptcy Case on our liquidity and results of operations, including failure to comply with the financial covenants and other requirements of the DIP Facilities;

• our ability to obtain timely Bankruptcy Court approval with respect to motions filed in the Bankruptcy Case;

• disagreements between us and the Creditors’ Committee that could protract the Chapter 11 proceedings, negatively impact our ability to operate and delay our emergence from the Chapter 11 proceedings;

• objections to the Company’s plan of reorganization that could protract the Chapter 11 proceedings;

• employee attrition and our ability to retain senior management and key personnel due to the distractions and uncertainties, including our ability to provide adequate compensation and benefits during the Chapter 11 proceedings;

• U.S. and international financial, economic and political conditions, including coal, power and steel market conditions;

• coal price volatility and demand, particularly in higher margin products;

• availability and prices of competing energy resources for electricity generation;

• geologic, equipment and operational risks associated with mining;

• our ability to successfully implement solutions to treat the effluent selenium exceedances to meet the limits and timetables stipulated in the various court orders, consent decrees and permits;

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• actual costs of complying with selenium effluent limits being materially higher than the costs reflected in our selenium water treatment liability;

• reductions of purchases or deferral of shipments by major customers;

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

• changes in the interpretation, enforcement or application of existing and potential laws and regulations affecting the production of our coal;

• environmental laws and regulations, such as the Mercury and Air Toxic Standards, and changes in the interpretation or enforcement thereof, including those affecting our operations and those affecting our customers’ coal usage;

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

• weather patterns and conditions affecting energy demand or disrupting supply;

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

• 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;

• 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;

• customer performance and credit risks;

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

• downturns in consumer and commercial spending;

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

• availability and costs of transportation;

• our ability to replace proven and probable coal reserves;

• our ability to respond to changing customer preferences;

• the effects of mergers, acquisitions and divestitures, including our ability to successfully realize assets for amounts similar to those reflected in our consolidated financial statements;

• 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

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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.

GLOSSARY OF SELECTED MINING TERMS

ABMet. Advanced Biological Metals Removal System. A technology utilized for selenium water treatment, 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; depreciation, depletion and amortization; asset retirement obligation expense; sales contract accretion; impairment and restructuring charge; DIP financing fees; and reorganization items.

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 combustion 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.

CERCLA. Comprehensive Environmental Response, Compensation and Liability Act, commonly known as Superfund.

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 by-products.

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 utilized for selenium water treatment.

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

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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.

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.

IFSeR. Iron Facilitated Selenium Reduction. A technology utilized for selenium water treatment.

Illinois Basin. The bituminous coal producing states and regions of Illinois, Indiana and western Kentucky.

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.

OVEC. Ohio Valley Environmental Coalition, Inc.

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.

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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.

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.

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 utilized for selenium water treatment.

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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 5 through 7 for the definition of mining terms used throughout this document.

Item 1.Business.

Overview

We are a producer of coal in the eastern United States (U.S.), with operations and coal reserves in the Appalachia and the Illinois Basin coal regions. Our principal business is the mining, preparation and sale of thermal 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, 2012, our operations consisted of eleven 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 1.8 billion tons of proven and probable coal reserves. Our proven and probable coal reserves include metallurgical coal and medium and high-Btu thermal coal, with low, medium and high sulfur content.

We ship coal to electricity generators, industrial users, steel mills and independent coke producers, as well as brokers that ultimately sell the coal to these same types of customers. In 2012, we sold 24.9 million tons of coal, of which 75% was sold to domestic and global electricity generators and industrial customers and 25% was sold to domestic and global steel and coke producers. Export sales were 45% of our total volume in 2012. 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, publicly-traded company. 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.

Bankruptcy Proceedings

On July 9, 2012 (the Petition Date), Patriot Coal Corporation, as a stand-alone entity, and substantially all of its wholly-owned subsidiaries (the Filing Subsidiaries and, together with Patriot, the Debtors) filed voluntary petitions for reorganization (the Chapter 11 Petitions) under Chapter 11 of Title 11 of the U.S. Code (the Bankruptcy Code) in the U.S. Bankruptcy Court for the Southern District of New York. The Debtors’ Chapter 11 cases are being jointly administered under the caption In re: Patriot Coal Corporation, et al. (Case No. 12-51502) (the Bankruptcy Case). Our joint ventures and certain of our other subsidiaries (collectively, the Non-Debtor Subsidiaries) were not included in the Chapter 11 filing.

On July 18, 2012 and August 7, 2012, respectively, the United Mine Workers of America (UMWA) and several surety companies filed motions requesting that the venue for our Chapter 11 filing be transferred to the U.S. Bankruptcy Court for the Southern District of West Virginia. The U.S. Trustee also filed a motion arguing that the venue should be transferred from the Southern District of New York to another district. A hearing was held in September 2012, at which time the Company, the Creditors’ Committee and certain other creditors contested these motions. On November 27, 2012, the U.S. Bankruptcy Court for the Southern District of New York issued a ruling transferring the bankruptcy cases to the U.S. Bankruptcy Court for the Eastern District of Missouri. On December 19, 2012, the U.S. Bankruptcy Court for the Southern District of New York entered an order formally transferring the bankruptcy cases to the U.S. Bankruptcy Court for the Eastern District of Missouri (the U.S. Bankruptcy Court for the Eastern District of Missouri and/or the U.S. Bankruptcy Court for the Southern District of New York, as applicable, the Bankruptcy Court).

Effective July 10, 2012, the New York Stock Exchange (NYSE) suspended trading of our common stock and commenced proceedings to delist our common stock. On August 6, 2012, our common stock was delisted from the NYSE. Our stock is now traded under the ticker symbol “PCXCQ” on the OTCQB marketplace, operated by OTC Markets Group Inc. (the OTC Market).

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The filing of the Chapter 11 Petitions constituted an event of default under the Company’s pre-petition debt obligations, and those debt obligations became automatically and immediately due and payable, although any actions to enforce such payment obligations are stayed as a result of the filing of the Chapter 11 Petitions. Due to the filing of the Chapter 11 Petitions, the Company’s pre-petition unsecured long-term debt of $458.5 million is included in “Liabilities subject to compromise” in the consolidated balance sheet at December 31, 2012.

The Debtors are currently operating as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. In general, the Debtors are authorized to, and continue to, operate as an ongoing business, but may not engage in transactions outside of the ordinary course of business without the approval of the Bankruptcy Court.

Debtor-In-Possession (DIP) Financing

In connection with filing the Chapter 11 Petitions, the Debtors filed a motion seeking, among other things, Bankruptcy Court authorization to obtain post-petition financing, and for each Filing Subsidiary (other than EACC Camps, Inc.) and for Patriot Ventures LLC (collectively, the DIP Guarantors) to guaranty our obligations in connection with the DIP financing, up to an aggregate principal amount of $802.0 million, consisting of (a) a revolving credit loan in an amount not to exceed $125.0 million (First Out Revolving Credit Loan), (b) a term loan in the amount of $375.0 million (First Out Term Loan, and together with the First Out Revolving Credit Loan, the First Out Facility), and (c) a $302.0 million roll up (the L/C Roll Up) of obligations under the Amended and Restated Credit Agreement, dated May 5, 2010 (the Pre-Petition Credit Agreement) in respect to outstanding letters of credit, inclusive of any obligations as to reimbursement, renewal and extension of the same issued in the aggregate amount of $300.8 million as of the Petition Date (the Second Out Facility and, together with the First Out Facility, the DIP Facilities).

On July 11, 2012, the Bankruptcy Court entered an interim order (the Interim DIP Order) that, among other things, authorized us to borrow money and obtain letters of credit pursuant to the DIP Facilities and to guaranty such borrowings and our obligations with respect to such letters of credit, up to an aggregate principal or face amount of $677.0 million (plus interest, fees and other expenses and amounts), consisting of borrowings of up to an aggregate principal or face amount of $125.0 million under the First Out Revolving Credit Loan, $250.0 million under the First Out Term Loan, and up to $302.0 million under the Second Out Facility, in accordance with the terms of the Interim DIP Order. On August 3, 2012, the Bankruptcy Court entered a final order (the Final DIP Order) that, among other things, authorized us to borrow the full amount under the DIP Facilities in accordance with the terms of the Final DIP Order. The maturity date of the DIP Facilities is October 4, 2013, but may be extended to December 31, 2013 provided certain conditions are met.

Reorganization Process

The Bankruptcy Court authorized us to pay certain of our pre-petition obligations, including payments for employee wages, salaries and certain benefits and payments to certain shippers and critical vendors, subject to certain limitations. The Debtors are required to pay vendors and other providers in the ordinary course for goods and services received after the filing of the Chapter 11 Petitions and to pay certain other business-related payments necessary to maintain the operation of our business. We have retained legal and financial professionals to advise us on the bankruptcy proceedings. From time to time, we may seek the Bankruptcy Court’s approval for the retention of additional professionals.

Immediately after filing the Chapter 11 Petitions, we began notifying all known current or potential creditors of the Debtors of the bankruptcy filings. Subject to certain exceptions under the Bankruptcy Code, the filing of the Chapter 11 Petitions automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the filing of the Chapter 11 Petitions. Thus, for example, most creditor actions to obtain possession of property from us, or to create, perfect or enforce any lien against our property, or to collect on monies owed or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

As required by the Bankruptcy Code, the U.S. Trustee for the Southern District of New York appointed an official committee of unsecured creditors (the Creditors’ Committee). The Creditors’ Committee and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court.

Under Section 365 and other relevant sections of the Bankruptcy Code, we may assume, assume and assign, or reject certain executory contracts and unexpired leases, including leases of real property and equipment, subject to the approval of the Bankruptcy Court and certain other conditions. In this context, “assumption” means that the Company agrees to perform its obligations and cure all existing defaults under the contract or lease, and “rejection” means that it is relieved from its obligations to perform further under the contract or lease, but is subject to a pre-petition claim for damages for

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the breach thereof subject to certain limitations. Any damages resulting from rejection of executory contracts that are permitted to be recovered under the Bankruptcy Code will be treated as liabilities subject to compromise unless such claims were secured prior to the Petition Date.

Since the Petition Date, the Company received approval from the Bankruptcy Court to reject a number of equipment leases and other executory contracts of various types. On January 15, 2013, the Company filed a motion for authorization to assume or reject all of our unexpired leases of nonresidential real property, including our coal reserve leases. Substantially all of our assumptions and rejections were approved by the Bankruptcy Court on January 28, 2013. We are working to resolve differences in cure amounts and certain other discreet issues with counterparties that objected to our motion. The Company continues to review all of its executory contracts and unexpired leases to determine which additional contracts and leases it will reject.

The Company expects that additional liabilities subject to compromise will arise due to rejection of executory contracts, including leases, and from the determination of the Bankruptcy Court (or agreement by parties in interest) of allowed claims for contingencies and other disputed amounts. The Company also expects that the assumption of additional executory contracts and unexpired leases will convert certain of the liabilities shown on the consolidated balance sheet as liabilities subject to compromise to liabilities not subject to compromise. Due to the uncertain nature of many of the potential claims, the Company cannot project the magnitude of such claims with certainty.

On October 18, 2012, the Bankruptcy Court entered an order establishing December 14, 2012 (the General Bar Date) as the bar date for potential creditors, other than governmental units, to file claims. For governmental units to file claims, the bar date was established as January 21, 2013 (the Governmental Bar Date). The bar date is the date by which certain claims against the Company must be filed if the claimants wish to receive any distribution in the bankruptcy cases. Proof of claim forms received after the bar date are typically not eligible for consideration of recovery as part of the Company’s bankruptcy cases. All known potential creditors were notified of the bar date and the requirement to file a claim with the Bankruptcy Court. Patriot also published notices in various publications that are available to the public. Differences between liability amounts estimated by the Company and claims filed by creditors are being investigated and, if necessary, the Bankruptcy Court will make a final determination of the allowable claim. The determination of how liabilities will ultimately be treated cannot be made until the Bankruptcy Court approves a plan of reorganization. Accordingly, the ultimate amount or treatment of such liabilities is not determinable at this time.

In order to successfully exit Chapter 11, we will need to propose and obtain confirmation by the Bankruptcy Court of a plan of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization, among other things, would resolve our pre-petition obligations, set forth the revised capital structure of the newly reorganized entity and provide for corporate governance subsequent to emerging from bankruptcy.

We had the exclusive right for 120 days after the filing of the Chapter 11 Petitions to file a plan of reorganization. On November 15, 2012, the Bankruptcy Court entered an order extending this exclusivity period to May 5, 2013. We may file one or more motions to request extensions of this exclusivity period, which are routinely granted up to 18 months in bankruptcy cases of this size and complexity. If our exclusivity period lapses, any party-in-interest would be able to file a plan of reorganization. In addition to being voted on by requisite holders of impaired claims and equity interests, a plan of reorganization must satisfy certain requirements of the Bankruptcy Code and must be approved, or confirmed, by the Bankruptcy Court in order to become effective. Our timing for filing a plan of reorganization will depend on the timing and outcome of numerous other ongoing matters in the Chapter 11 proceedings.

Under the priority rankings established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full before stockholders are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation of a plan of reorganization. No assurance can be given as to what values, if any, will be ascribed to each of these constituencies or what types or amounts of distributions, if any, they would receive. A plan of reorganization could result in holders of certain liabilities and/or securities, including common stock, receiving no distribution on account of their interests and cancellation of their holdings. Because of such possibilities, there is significant uncertainty regarding the value of our liabilities and securities, including our common stock. At this time, there is no assurance we will be able to restructure as a going concern or successfully propose or implement a plan of reorganization.

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Going Concern Matters

Patriot’s consolidated financial statements and related notes have been prepared assuming we will continue as a going concern, although the Bankruptcy Case and weak industry conditions raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded assets or to the amounts and classification of liabilities or any other adjustments that might be necessary should we be unable to continue as a going concern. Our ability to continue as a going concern is dependent upon, among other things, market conditions and our ability to improve profitability, to meet the financial covenants of the DIP Facilities or obtain appropriate waivers, to obtain financing to replace the DIP Facilities upon emergence and to restructure our obligations in a manner that allows us to obtain confirmation of a plan of reorganization by the Bankruptcy Court. In order to improve profitability, we are taking actions to further reduce operating expenses and align our production to meet market demand. As a result of the Bankruptcy Case, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession pursuant to the Bankruptcy Code, we may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Facilities), for amounts other than those reflected in the consolidated financial statements. Further, any plan of reorganization could materially change the amounts and classifications of assets and liabilities reported in the historical consolidated financial statements.

Financial Reporting Considerations

For periods subsequent to filing the Chapter 11 Petitions, we have applied the Financial Accounting Standards Board Accounting Standards Codification 852, “Reorganizations” (ASC 852), in preparing the consolidated financial statements. ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings have been recorded in “Reorganization items, net” on the consolidated statements of operations. In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on the consolidated balance sheet at December 31, 2012 in “Liabilities subject to compromise.” These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

Reorganization Items and Other Bankruptcy Related Costs

ASC 852 requires separate disclosure of reorganization items. The Company’s reorganization items for the year ended December 31, 2012 consisted of the following:

	Year Ended
	December 31, 2012
	(Dollars in thousands)
Provision for rejected executory contracts and leases	$	82,213
Professional fees	35,506
Losses from adjusting debt from carrying value to amount of allowed claim	27,021
Accounts payable settlement gains	(8,876		)
Reorganization items, net	$	135,864

Professional fees are directly related to the reorganization and include fees associated with advisors to the Company, the Creditors’ Committee and certain secured creditors. Net cash paid for reorganization items for the year ended December 31, 2012 totaled $23.3 million, all of which related to professional fees.

Debt issuance costs of $42.5 million were incurred and paid in connection with the DIP Financing. These amounts were expensed and separately disclosed in the 2012 consolidated statement of operations.

Liabilities Subject to Compromise

Liabilities subject to compromise represent pre-petition unsecured obligations that will be settled under a plan of reorganization. Generally, actions to enforce or otherwise effect payment of pre-petition liabilities are stayed. Pre-petition liabilities subject to compromise are reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. These liabilities represent the amounts expected to be allowed on known or potential claims to be resolved through the Chapter 11 process, and remain subject to future adjustments arising from negotiated settlements, actions of

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the Bankruptcy Court, rejection of executory contracts and unexpired leases, the determination as to the value of collateral securing the claims, proofs of claim, or other events. Liabilities subject to compromise also include certain items that may be assumed under the plan of reorganization, and as such, may be subsequently reclassified to liabilities not subject to compromise.

The Bankruptcy Court approved payment of certain pre-petition obligations, including employee wages, salaries and benefits, and the payment of vendors and other providers in the ordinary course for goods and services received after the filing of the Chapter 11 Petitions and other business related payments necessary to maintain the operations of the Company’s business. Obligations associated with these matters are not classified as liabilities subject to compromise.

With the approval of the Bankruptcy Court, the Company has rejected certain pre-petition executory contracts and unexpired leases with respect to the Company’s operations and may reject additional contracts or unexpired leases in the future. Damages resulting from rejection of executory contracts and unexpired leases are generally treated as general unsecured claims and are classified as liabilities subject to compromise. Holders of pre-petition claims were required to file proofs of claims by the General Bar Date or the Governmental Bar Date, as applicable. Differences between liability amounts estimated by the Company and claims filed by creditors are being investigated and, if necessary, the Bankruptcy Court will make a final determination of the allowable claim. The determination of how liabilities will ultimately be treated cannot be made until the Bankruptcy Court approves a plan of reorganization. Accordingly, the ultimate amount or treatment of such liabilities is not determinable at this time.

Liabilities subject to compromise consisted of the following:

	December 31, 2012
	(Dollars in thousands)
Postretirement benefit obligations, excluding Coal Act	$	1,517,284
Unsecured debt	458,500
Interest payable	4,838
Rejected executory contracts and leases	151,449
Trade payables	78,086
Other accruals	52,150
Liabilities subject to compromise	$	2,262,307

Other accruals primarily include liabilities subject to compromise related to accrued royalty payments, litigation reserves, employee claims and other operating accruals.

Mining Operations

Our mining operations and coal reserves are as follows:

•Appalachia. As of December 31, 2012, we had eight active mining complexes located in Boone, Lincoln, Logan, Kanawha, and Raleigh counties in southern West Virginia. In northern West Virginia, we have one mining complex located in Monongalia County. During 2012, we closed one mining complex in southern West Virginia and converted certain contractor-operated mines to company-operated mines. Also during 2012, we reduced production at certain thermal and metallurgical coal mines in response to decreased market demand. In Appalachia, we sold 18.5 million tons of coal in the year ended December 31, 2012. As of December 31, 2012, we controlled approximately 1.2 billion tons of proven and probable coal reserves in Appalachia, of which 492 million tons were assigned to current operations.

•Illinois Basin. As of December 31, 2012, we had two active mining complexes located in Union and Henderson counties in western Kentucky. During 2012, we closed one Illinois Basin mining complex. In the Illinois Basin, we sold 6.4 million tons of coal in the year ended December 31, 2012. As of December 31, 2012, we controlled 658 million tons of proven and probable coal reserves in the Illinois Basin, of which 119 million tons were assigned to current operations.

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The following table provides the location and summary information of our operations for the year ended December 31, 2012.

Location	Complex	Mine(s)	Mining Method(1)	Met/Thermal	2012 Tons Sold(2)
Appalachia	Big Mountain(3)	Big Mountain No. 16, Contractor	CM	Thermal	106
	Corridor G	Job 21, Hill Fork(4)	DL, TS	Thermal	2,837
	Kanawha Eagle(5)	Peerless, Coalburg No. 1, Coalburg No. 2, Eagle	CM	Met/Thermal	697
	Logan County	Guyan	TS	Thermal	2,198
	Midland Trail	Blue Creek No. 1, Campbell’s Creek No. 7(6), Contractor	CM	Thermal	1,589
	Paint Creek	Samples, Winchester	TS, HW, CM	Met/Thermal	1,794
	Panther	Panther	LW, CM	Met	2,194
	Rocklick	Black Oak, Gateway Eagle, Farley Eagle	CM	Met	1,053
	Wells	Campbell’s Creek No. 10, Black Stallion, Workman Branch(7)	CM	Met	1,538
	Federal	Federal No. 2	LW, CM	Thermal	4,036
	Purchased coal	N/A	N/A	N/A	472
				Subtotal	18,514
Illinois Basin
	Bluegrass(8)	Patriot, Freedom	TS, CM	Thermal	1,539
	Dodge Hill	Dodge Hill No. 1	CM	Thermal	879
	Highland	Highland No. 9	CM	Thermal	3,967
				Subtotal	6,385
				Total	24,899

⁽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 2012, subject to stockpile variations.

⁽³⁾  The Big Mountain complex was closed in February 2012.

⁽⁴⁾  The Hill Fork mine was idled in April 2012.

⁽⁵⁾  The Coalburg No. 1, Coalburg No. 2 and Eagle mines were closed in the first half of 2012.

⁽⁶⁾  The Campbell’s Creek No. 7 mine was closed in February 2012.

⁽⁷⁾  The Workman Branch mine was idled in September 2012.

⁽⁸⁾  The Freedom mine was closed in June 2012 and the Patriot surface mine was closed in December 2012.

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Appalachian Mining Operations

As of December 31, 2012, our Appalachian Mining Operations included nine active mining complexes in West Virginia.

Appalachia

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. We idled the Hill Fork mine in the second quarter of 2012. 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.

Kanawha Eagle

The Kanawha Eagle mining complex is located in southern West Virginia and is currently sourced by one underground mine, Peerless, using continuous mining methods. The Peerless mine was opened in early 2012 and is a company-operated mine. In the first half of 2012, we closed three mines at our Kanawha Eagle mining complex. Processed coal can be sold either on the metallurgical or thermal markets and is transported via CSX rail directly to the customer or trucked to a loading facility on the Kanawha River where the coal can be loaded on barges or Norfolk Southern rail. Coal is produced from the Peerless seam. The employees at the Kanawha Eagle complex are not represented by a union.

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 Kittanning, Stockton and Coalburg seams. Certain employees at the Logan County complex are represented by the UMWA.

Midland Trail

The Midland Trail mining complex is located in southern West Virginia and consists of two underground mines, one company-operated, Blue Creek No. 1, and one contractor-operated. Coal at the Midland Trail mining complex is produced from the Stockton seam. The complex utilizes continuous mining methods. Coal produced at the Midland Trail complex is sold on the thermal market and is loaded onto trucks for transportation to a loading facility on the Kanawha River where the coal can be loaded on barges or Norfolk Southern rail. The employees at the company-operated mine are not represented

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by a union. In 2012, the Campbell’s Creek and Blue Creek mining operations were combined into the Midland Trail complex, and the Campbell’s Creek mines were closed in the first half of 2012.

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. Coal from Samples is sourced from the 5-Block, Stockton and Coalburg seams. The Winchester mine operates in the Hernshaw seam. 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 where the coal can be loaded on barges or Norfolk Southern rail. 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 a CSX loading facility or to a facility on the Kanawha River where the coal can be loaded on barges or Norfolk Southern rail. Coal produced at the Panther complex is sold into the metallurgical market; however, thermal coal can also be processed and sold at this operation. 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 three company-operated underground mines, Black Oak, Gateway Eagle, and Farley Eagle. In 2012, we reduced metallurgical coal production at our Rocklick mining complex in response to further weakened demand. 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. The Farley Eagle mine produces metallurgical coal from the Eagle seam. Thermal coal can also be processed and sold at this operation. Certain employees at the Rocklick mining complex are represented by the UMWA.

Wells

The Wells mining complex is located in southern West Virginia and is sourced by two company-operated underground mines, Black Stallion and Campbell’s Creek No. 10. In 2012, we reduced metallurgical coal production at our Wells mining complex in response to further weakened demand. Coal is produced utilizing continuous mining methods. Coal currently produced at the Wells mining complex is sold on the metallurgical market and is transported to customers via CSX rail. Thermal coal can also be processed and sold at this operation. Coal is sourced from the Eagle and No. 2 Gas seams. Certain employees at the company-operated facilities of the Wells mining complex are represented by the UMWA.

Federal

The Federal mining complex is located in northern West Virginia and is sourced by one company-operated underground mine, Federal No. 2, utilizing longwall and continuous mining methods. All coal produced at Federal is sold on the 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. Certain employees at the Federal mining complex are represented by the UMWA.

Big Mountain

In February 2012, we closed our Big Mountain mining complex located in southern West Virginia. This complex was sourced by one company-operated underground mine, Big Mountain No. 16, and one contractor-operated underground mine located in southern West Virginia.

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Illinois Basin Mining Operations

As of December 31, 2012, our Illinois Basin Mining Operations included two active mining complexes in western Kentucky.

Illinois Basin

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. Certain employees at the Highland complex are represented by the UMWA.

Bluegrass

During 2012, we closed our Bluegrass mining complex located in western Kentucky. This complex was sourced by two company-operated mines, Freedom, an underground mine, and Patriot, a surface mine. Coal was produced from the Kentucky No. 9 seam. Coal at Freedom was produced utilizing continuous mining methods, while coal at Patriot was produced utilizing the truck-and-shovel/loader mining method. All coal was sold on the thermal market and was transported via truck or via barge loaded on the Green River. The Freedom mine was idled in the second quarter of 2012 and the Patriot mine and preparation plant were closed in December 2012. The employees at the Bluegrass mining complex were not represented by a union.

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Customers and Backlog

In 2012, our coal was sold to 54 electricity generating, industrial, steel producing and coke producing plants in 9 countries, including the U.S., which is where we have our primary customer base. Additionally, 32% of our revenue in 2012 was derived from sales to third-party brokers and traders who ultimately sold the coal as exports to these same types of customers.

As of December 31, 2012, we had a sales backlog of 22.4 million tons of coal, including backlog subject to price reopener and/or extension provisions. Our coal supply agreements have remaining terms of up to 3 years and an average volume-weighted remaining term of approximately 1.4 years.

	Commitments as of December 31, 2012
	2013	2014	2015	2016 and Later	Total
Tons (in millions)	16.5	3.9	2.0	—	22.4

The 2013 commitments represent approximately 70-75% of our currently estimated production for 2013.

In 2012, approximately 65% of our coal sales were under long-term (greater than one year) agreements. We expect to continue selling a significant portion of our coal under long-term coal supply agreements. Our approach is to selectively renew or enter into new coal supply agreements when we can do so at prices we believe are favorable.

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 also 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. 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 price.

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, permitting or serious

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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 by 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, transloading fees at the port and any applicable vessel demurrage costs associated with delayed loadings.

Of our 24.9 million tons sold in 2012, approximately 58% was shipped by rail, 36% by barge, 4% by ocean-going vessel and 2% 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. We have many long, well-established relationships with our key suppliers. Although 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, there are a limited number of suppliers in the coal mining industry. Purchases of certain underground mining equipment and steel roof bolts are concentrated with one principal supplier. The supplier base providing mining materials has been relatively consistent in recent years.

We contract with third-party producers to mine certain of our owned or leased coal reserves on a rate per ton basis. Third-party contractors accounted for approximately 10% of our total sales volume for the year ended December 31, 2012.

Competition

The U.S. coal industry is highly competitive, both regionally and nationally. Coal production in Appalachia and the Illinois Basin totaled approximately 418.5 million tons in 2012, with the largest five producers (Alpha Natural Resources, Inc., CONSOL Energy Inc., Alliance Resource Partners, L.P., Peabody and Patriot) accounting for 48% 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. Coal consumption patterns are affected primarily by the demand for electricity and steel, environmental and other governmental regulations, and technological developments. 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 abroad 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. 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, 2012, we had approximately 4,100 employees. Approximately 40% of our employees were represented by an organized labor union, specifically the UMWA. Our represented employees work at various sites in Appalachia and at the Highland complex in the Illinois Basin. In relation to the bankruptcy process and pursuant to Sections 1113 and 1114 of the Bankruptcy Code, Patriot is seeking to renegotiate the terms of collective bargaining agreements between

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certain Patriot subsidiaries and the UMWA, as well as certain postretirement healthcare benefits. This process, and the resulting outcome, could negatively impact our labor relations.

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 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

Our asset retirement obligations include both reclamation and selenium water treatment 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 fair value of future anticipated costs for water treatment of selenium discharges, as required by current court orders, consent decrees and mining permits.

As of December 31, 2012, our asset retirement obligations of $731.6 million included $443.0 million of selenium water treatment obligations and $288.6 million of reclamation obligations ($130.4 million of which are related to locations that are closed or inactive). Asset retirement obligation expense (which includes liability accretion and asset amortization) for the years ended December 31, 2012, 2011 and 2010 was $354.6 million, $105.2 million and $112.7 million, respectively.

Our selenium water treatment obligation is primarily associated with mining properties acquired in connection with the Magnum acquisition in July 2008. 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 been 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.

The asset retirement obligation expense included adjustments to increase the selenium water treatment liability by $258.3 million, $35.0 million and $69.5 million for the years ended December 31, 2012, 2011 and 2010, respectively, due to modifications to our selenium water treatment plans in order to comply with our mining permits and the above mentioned court orders and consent decrees. See a full description of these lawsuits and outcomes related to our selenium water treatment obligations in Part I, Item 3. Legal Proceedings - Environmental Claims and Litigation.

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 the employee’s service to date. Additional amounts are accrued periodically so that the total estimated liability is accrued when the employee retires.

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Our postretirement benefit obligations were $1.6 billion and $1.5 billion as of December 31, 2012 and 2011, respectively. Expense for the years ended December 31, 2012, 2011 and 2010 was $134.6 million, $125.0 million and $117.2 million, respectively.

In relation to the bankruptcy process and pursuant to Sections 1113 and 1114 of the Bankruptcy Code, Patriot is seeking to renegotiate the terms of collective bargaining agreements between certain Patriot subsidiaries and the UMWA, as well as certain postretirement healthcare benefits. Patriot also intends to terminate certain non-union and salaried healthcare and postemployment plans. As such, we have classified the liabilities associated with these plans as “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2012. The liability related to healthcare coverage under the Coal Industry Retiree Health Benefits Act of 1992 (the Coal Act) is not subject to compromise and is classified as such.

In connection with the spin-off, a subsidiary of Peabody assumed certain of our pre-spin-off obligations associated with the Coal Act, the 2007 National Bituminous Coal Wage Agreement (2007 NBCWA) and certain postretirement healthcare benefits for salaried employees. At December 31, 2012, the present value of the liability as reported by Peabody was $637.6 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 postretirement 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, 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).

Many of the 2010 Healthcare Legislation’s standard changes have taken effect and estimates of the impact of these changes on our postretirement benefit obligation have been incorporated into the actuarial valuation. 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 obligations. 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 obligations. We will continue to evaluate the impact of the 2010 Healthcare Legislation in future periods as additional information and guidance become 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 retired former employees who last worked prior to 1976, as well as orphaned beneficiaries of bankrupt companies who were receiving benefits as orphans prior to the 1992 law. No new retirees will be added to this group. The liability is subject to increases or decreases in per capita healthcare costs, offset by the mortality curve in this aging population of beneficiaries. The Coal Act also created a second benefit fund, the 1992 Benefit Plan, for miners who retired between July 21, 1992, and September 30, 1994, and whose former employers are no longer in business. Beneficiaries may continue to be added to this fund as employers default in providing their former employees with retiree medical benefits, but the overall exposure for new beneficiaries into this fund is limited to retirees covered under their employer’s plan who retired prior to October 1, 1994. A third fund, the 1993 Benefit Plan, was established through collective bargaining and provides benefits to qualifying former employees, who retired after September 30, 1994, of certain signatory companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries may continue to be added to this fund as employers go out of business. The collective bargaining agreement with the UMWA, which specifies the payments to be made to the 1993 Benefit Plan, 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

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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 the United States Congress (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. Our subsidiaries that have agreed to the 2011 NBCWA will pay $1.10 per hour worked to the 1993 Benefit Plan in 2013. 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.

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 $39.3 million as of December 31, 2012, $5.0 million of which was a current liability. 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. Expenses for the years ended December 31, 2012, 2011 and 2010 were $2.1 million, $2.1 million and $3.2 million, respectively. Cash payments to these funds were $5.0 million, $5.4 million and $6.0 million for 2012, 2011 and 2010, 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 $4.0 million, $2.5 million and $10.0 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Certain of our subsidiaries participate in a defined benefit multi-employer pension fund (the 1974 Plan) that was 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. The assets of the 1974 Plan are managed by the UMWA. The plan provides pension and disability pension benefits to qualifying represented employees upon retirement. 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. Expense related to this plan was $20.8 million, $24.3 million and $21.0 million for the years ended December 31, 2012, 2011 and 2010, respectively.

In relation to the bankruptcy process and pursuant to Section 1113 of the Bankruptcy Code, Patriot is seeking to renegotiate the terms of collective bargaining agreements between certain Patriot subsidiaries and the UMWA, which may affect our future participation in the 1974 Plan.

The 1974 Plan is considered to be in “Seriously Endangered Status” for the plan year beginning in July 2011 (the 2011 Plan Year). That status is the result of the 1974 Plan funded percentages being less than 80% and because the 1974 Plan is projected to have an accumulated deficiency within six years after the 2011 Plan Year. As a result, a funding improvement plan was adopted by the 1974 Plan as of May 25, 2012, which would require increased contributions to the 1974 Plan after a new UMWA collective bargaining agreement is negotiated in 2016. Under the funding improvement plan, the hourly contribution rate would increase in stages from a minimum of $12.50 in 2017 to a maximum potential rate of $26.50 as early as 2022.

New inexperienced miners hired after January 1, 2012 will not participate in the 1974 Plan. Instead, for each hour worked, the Company contributes $1.00 into the UMWA Cash Deferral Plan on the employee’s behalf, increasing to $1.50 on January 1, 2014. Effective January 1, 2012, employers also pay $1.50 per hour to a new Retiree Bonus Account Trust (Trust) for the term of the 2011 NBCWA. This Trust will make a payment to pensioners in November of 2014, 2015 and

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2016 in the amount of $580 for most retirees and $455 for disabled retirees. 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 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 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.

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. 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. These liabilities were $279.1 million and $258.3 million as of December 31, 2012 and 2011, respectively, of which $24.4 million and $26.7 million were current liabilities, respectively. Expense for the years ended December 31, 2012, 2011 and 2010 was $35.1 million, $39.8 million and $38.2 million, respectively.

Regulatory Matters

Federal and state authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, the protection of the environment, plants and wildlife, the reclamation and restoration of mining properties after mining has been completed, surface subsidence from underground mining and the effects of mining on 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 coal production sold to U.S. customers. The excise tax is $1.10 per ton for underground mines and $0.55 per ton for surface mines, 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. Certain periodic incentive payments for eligible Patriot personnel are tied to our safety record.

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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 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 continues 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 April 13, 2012, the U.S. Department of Interior (DOI) ordered the consolidation of certain functions of the OSM into the Bureau of Land Management, and it is uncertain how this or any future actions 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

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geologic data and incorporating elements of the environmental data. Our mine and reclamation plans incorporate the provisions of SMCRA, the state programs and the complementary environmental programs that impact coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land, and documents required of the OSM’s Applicant Violator System, including the mining and compliance history of officers, directors and principal stockholders of the applicant.

Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Some SMCRA mine permit applications take over a year to prepare, depending on the size and complexity of the mine, and often take 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 U.S. Environmental Protection Agency (EPA) is the lead agency for states with no authorized programs under the Clean Water Act, RCRA and CERCLA. The U.S. Army Corps of Engineers (ACOE) regulates activities affecting navigable waters and the U.S. Bureau of Alcohol, Tobacco and Firearms regulates the use of explosive materials and equipment.

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. As of December 31, 2012, we had outstanding surety bonds and total letters of credit of $564.9 million, including: $354.5 million for post-mining reclamation; $132.6 million related to workers’ compensation obligations; $54.4 million for retiree health obligations; and $23.5 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 trust fund, which is part of SMCRA, imposes a fee on all coal produced in the U.S. 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, 2012 through September 30, 2021, the fee is $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 and certain new export transloading facilities due to the potential air emissions that would result both domestically and globally. 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 the 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

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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 were not directly impacted and a federal district court has since reinstated the rescinded permit, this could be an indication that 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 Item 3. Legal Proceedings – Environmental Claims and Litigation 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 has resulted in permitting delays and increased permitting and operating costs at surface mining operations. As such, Patriot has been evaluating its utilization of what is termed as large-scale surface mining operations on a long-term strategic basis. In late 2012, Patriot agreed in a litigation settlement and consent modification with various non-governmental environmental organizations to impose interim caps on surface mining coal production beginning in 2014 and leading to a permanent cap beginning in 2018; to retire its Paint Creek surface mine dragline in 2013 and its Hobet surface mine dragline in 2015; and to refrain from certain new large-scale surface mining operations. See Item 3. Legal Proceedings - Environmental Claims and Litigation - December 2012 Settlement and Consent Modification, for a discussion of this litigation settlement and consent modification.

As an example of the increased regulatory oversight, 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. NWP 21 was reinstated on March 19, 2012, but with significant modifications prohibiting the use of NWP 21 to authorize valley fills. Individual permits are required for surface coal mining projects that use valley fills. We have converted any pending permit applications that were submitted under NWP 21 to individual permit applications. 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.

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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 must consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.

National Pollutant Discharge Elimination System

The Clean Water Act requires effluent limitations and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (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 established 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 has stated that it may be difficult for most surface mining operations to meet these water quality standards. Additionally, the guidance made 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 would have been subject to more stringent permit requirements imposed through our NPDES and Section 404 permits.

On July 31, 2012, the U.S. District Court for the District of Columbia (the D.C. District Court) struck down the EPA water quality guidance issued on July 21, 2011. However, the EPA has filed a notice of intent to appeal the D.C. District Court ruling and we cannot predict the outcome of such action. Moreover, the West Virginia Environmental Quality Board has called on WVDEP to include similar standards to those in the EPA guidance in any pending coal mining permit.

There can be no guarantee that we are or will be able to meet the requirements 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, 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.

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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 and methane. 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 reduced 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 closing or curtailing operations or switching to other sources of fuel in an attempt to lower levels of regulated emissions.

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

Sulfur Dioxide and Nitrogen Oxide Emissions

The EPA promulgated the Clean Air Interstate Rule (CAIR) in March 2005. CAIR requires the reduction of sulfur dioxide and nitrogen oxide emissions from electricity generating plants in 27 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.

On August 21, 2012, the U.S. Court of Appeals for the District of Columbia (D.C. Circuit Court) vacated CSAPR, leaving CAIR in effect pending the issuance of a replacement rule. The EPA petitioned the D.C. Circuit Court for a rehearing in an effort to reinstate CSAPR. The D.C. Circuit Court rejected this petition on January 24, 2013. The EPA is expected to issue a replacement rule to regulate the interstate transport of sulfur dioxide and nitrogen oxide emissions. Any such replacement rule would likely impose significant emission reduction requirements on our customers and reduce the demand for thermal coal.

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 Clean Air Act initiatives could cause our customers to close or curtail operations, change their coal sources, or reduce their demand for coal.

Mercury and Other Air Pollutant Emissions

In December 2011, the EPA finalized the Mercury and Air Toxics Standards for power plants (MATS), which, by early 2015, will impose on power plants 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 December 2012, the EPA finalized revisions to the emission standards imposing work practice requirements and emission limits that may affect the demand for coal.

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 has estimated 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. In response, the EPA lowered the annual fine particulate matter standard to 12.0 micrograms per cubic meter on December 14, 2012. Existing and possible future restrictions 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.

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Ozone

Nitrogen oxides, which are a by-product of coal combustion, can lead to the creation of ground-level 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 in 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.

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, in particular, lead to the closure of aging, coal-fueled power plants. 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 a CAIR trading program 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. We and many of our customers are required to report annual greenhouse gas emissions from certain operations. In addition, 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 must determine what controls are required for facilities within their jurisdiction on a case-by-case basis.

On April 13, 2012, the EPA published proposed new source performance standards for emissions of carbon dioxide from certain new power plants. The proposal anticipates that affected new-build coal fueled plants would generally need to install carbon capture and storage technology, which currently is not economically feasible, or other expensive carbon dioxide emission control technology to meet the proposed standard. In addition to the proposed standards, the EPA may also seek to regulate modifications to existing coal-fueled plants or provide guidelines for states to address greenhouse gas emissions from existing power plants. Although it is not yet possible to predict the effect of these or any other

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greenhouse gas regulations, 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 have considered the passage of significant new laws to address climate change, including, among others, 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, 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 mid-Atlantic 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. 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 Congress has 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 close or curtail operations or 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 reduction 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

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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.

Additional Information

We file annual, quarterly and current reports, and any amendments to those reports, proxy statements and other information with the Securities and Exchange Commission (SEC). You may access and read our SEC filings free of charge through our website, at www.patriotcoal.com, or the SEC’s website, at www.sec.gov. You may read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

You may also request copies of our filings, free of charge, by telephone at (314) 275-3680 or by mail at: Patriot Coal Corporation, 12312 Olive Boulevard, St. Louis, Missouri 63141, attention: Investor Relations.

Executive Officers

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

Name	Age	Positions
Bennett K. Hatfield	56	President, Chief Executive Officer & Director
Michael D. Day	42	Executive Vice President - Operations
John E. Lushefski	57	Senior Vice President & Chief Financial Officer
Charles A. Ebetino, Jr.	60	Senior Vice President - Global Strategy & Corporate Development
Robert W. Bennett	50	Senior Vice President & Chief Marketing Officer
Joseph W. Bean	50	Senior Vice President - Law & Administration & General Counsel

Bennett K. Hatfield

President, Chief Executive Officer & Director

Bennett K. Hatfield, age 56, serves as President, Chief Executive Officer and as a Director. Mr. Hatfield was named President in May 2012 and Chief Executive Officer and Director in October 2012. He previously served as Patriot’s Chief Operating Officer since he joined the Company in September 2011. Mr. Hatfield has held a number of 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 and 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 the National Mining Association (NMA). Mr. Hatfield is a Licensed Professional Engineer with a Bachelor of Science degree in mining engineering from Virginia Polytechnic Institute and State University.

Michael D. Day

Executive Vice President - Operations

Michael D. Day, age 42, serves as Executive Vice President - Operations. He was appointed to this position effective February 1, 2013. Mr. Day most recently served as Patriot’s Senior Vice President – Engineering and W.V. Central Region & Kentucky Operations from August 2011 through January 2013. Mr. Day joined Patriot in August 2008 and held the positions of Vice President – Operations from August 2009 through August 2011 and Vice President – Surface Operations from August 2008 through August 2009. Prior to joining Patriot, Mr. Day served in a variety of management positions from 1992 through 2008 at Magnum Coal Company, Arch Coal, Inc. and James River Coal Company.

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Mr. Day is an executive board member of the Kentucky Coal Association and the University of Kentucky Mining Engineering Foundation. Mr. Day holds a Bachelor of Science degree in Mining Engineering from the University of Kentucky and is a Registered Professional Engineer.

John E. Lushefski

Senior Vice President & Chief Financial Officer

John E. Lushefski, age 57, serves as Senior Vice President and Chief Financial Officer. He previously served on Patriot’s Board of Directors from October 2007 until September 2012, at which time he resigned from the Board of Directors and was named to his current position. From 2005 until September 2012, Mr. Lushefski was a senior consultant providing strategic, business development and financial advice to public and private companies. He has substantial coal industry experience and a global background in treasury, tax, accounting, strategic planning, information technology, human resources, investor relations and business development. From 1996 until December 2004, he served as Chief Financial Officer of Millennium Chemicals Inc., a NYSE-listed international chemicals manufacturer that was spun off from Hanson PLC. He also served as Senior Vice President and Chief Financial Officer of Hanson Industries Inc. from 1995 to 1996, and as Vice President and Chief Financial Officer of Peabody Holding Company, Inc. from 1991 to 1995. Prior to joining Hanson in 1985, he was an Audit Manager with Price Waterhouse LLP.

Mr. Lushefski is a certified public accountant and holds a Bachelor of Science degree in Business Management and Accounting from Pennsylvania State University.

Charles A. Ebetino, Jr.

Senior Vice President - Global Strategy & Corporate Development

Charles A. Ebetino, Jr., age 60, serves as Senior Vice President - Global Strategy and Corporate Development. From August 2010 through September 2011, Mr. Ebetino served as Senior Vice President and 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 and Chief Operating Officer of AEP’s coal mining and coal-related subsidiaries from 1993 until 2002.

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 50, serves as Senior Vice President and Chief Marketing Officer. Mr. Bennett has over 24 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 U.S.

Prior to 1997, Mr. Bennett held various leadership positions with AGIP Coal Sales and Neweagle Corporation. Mr. Bennett holds a Bachelor of Arts degree in Finance from Marshall University.

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Joseph W. Bean

Senior Vice President - Law & Administration & General Counsel

Joseph W. Bean, age 50, serves as Senior Vice President - Law & Administration and General Counsel. From the spin-off to February 2009, Mr. Bean served as Senior Vice President, General Counsel and Corporate Secretary for Patriot. Prior to the spin-off, Mr. Bean served as Peabody’s Vice President and 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.

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 our Bankruptcy Proceedings

Patriot, as a stand-alone entity, and substantially all of our subsidiaries filed voluntary petitions for reorganization under the Bankruptcy Code. The U.S. Bankruptcy Court for the Eastern District of Missouri (collectively with the U.S. Bankruptcy Court of the Southern District of New York, the Bankruptcy Court) is hearing the cases, jointly administered under Case No. 12-51502 (the Bankruptcy Case), and we are subject to the risks and uncertainties associated with bankruptcy proceedings.

For the duration of the Bankruptcy Case, our operations and our ability to execute our business strategy will be subject to the risks and uncertainties associated with bankruptcy. These risks include:

• our ability to continue as a going concern;

• our ability to develop, confirm and consummate a plan of reorganization with respect to the Bankruptcy Case, which is dependent upon, among other things, our ability to implement changes to wage and benefit programs and postretirement benefit obligations pursuant to Sections 1113 and 1114 of the Bankruptcy Code to minimize our liabilities upon emergence and to obtain post-bankruptcy financing;

• our ability to operate within the restrictions and liquidity limitations of the post-petition credit facilities authorized by the Bankruptcy Court in connection with the Bankruptcy Case (the DIP Facilities);

• our ability to obtain timely Bankruptcy Court approval with respect to motions filed in the Bankruptcy Case;

• the ability of third parties to seek and obtain Bankruptcy Court approval to terminate or shorten the exclusivity period for us to propose and confirm a plan of reorganization, to appoint a Chapter 11 trustee or to convert the Bankruptcy Case to a case under Chapter 7 of the Bankruptcy Code;

• our ability to comply with and operate under any cash management orders entered by the Bankruptcy Court from time to time;

• our ability to maintain contracts that are critical to our operations;

• our ability to obtain and maintain normal payment and other terms with customers, vendors and service providers;

• our ability to attract, retain and motivate key employees;

• our ability to attract and retain customers;

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• our ability to maintain credit to retain and attract necessary suppliers and service providers; and

• our ability to fund and execute our business plan.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with the Bankruptcy Case could adversely affect our relationships with our vendors, employees and customers, which in turn could adversely affect our operations and financial condition. Also, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond timely to certain events or take advantage of opportunities. Because of the risks and uncertainties associated with the Bankruptcy Case, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 reorganization process may have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.

Trading in our securities during the pendency of the Bankruptcy Case is highly speculative and poses substantial risks. It is impossible to predict at this time whether our equity or other securities will be canceled or if holders of such equity or other securities will receive any distribution with respect to, or be able to recover any portion of, their investments.

It is unclear at this stage of the Bankruptcy Case if any proposed plan of reorganization would allow for distributions with respect to our equity or other securities. It is likely that our equity securities will be canceled and extinguished upon confirmation of a proposed plan of reorganization by the Bankruptcy Court and the holders thereof would not be entitled to receive, and would not receive or retain, any property or interest in property on account of such equity interests. In the event of cancellation of our equity or other securities, amounts invested by the holders of such securities would not be recoverable and such securities would have no value. Trading prices for our equity or other securities may bear little or no relationship to the actual recovery, if any, by the holders thereof during the pendency of the Bankruptcy Case. Accordingly, we urge extreme caution with respect to existing and future investments in our equity or other securities.

Our common stock is no longer listed on a national securities exchange and is traded only in the over-the-counter market, which could negatively affect our stock price and liquidity.

The shares of our common stock were historically listed on the New York Stock Exchange (the NYSE) under the symbol “PCX.” In connection with the commencement of the Bankruptcy Case, effective July 10, 2012, the NYSE suspended the trading of our shares and, effective August 6, 2012, the NYSE removed our shares from listing and registration on the NYSE. Our common stock is now trading over-the-counter and is quoted on the OTC Market under the ticker symbol “PCXCQ.” The extent of the public market for our common stock and the continued availability of quotations depends upon such factors as the aggregate market value of the common stock, the interest in maintaining a market in our common stock on the part of securities firms and other factors. The OTC Market is a significantly more limited market than the NYSE, and the quotation of our common stock on the OTC Market may result in a less liquid market available for existing and potential shareholders to trade shares of our common stock. This could further depress the trading price of our common stock and could also have a long-term adverse effect on our ability to raise capital. There can be no assurance that any public market for our common stock will exist in the future or that we will be able to relist our common stock on a national securities exchange. In connection with the delisting of our common stock, there may also be other negative implications, including the potential loss of confidence in Patriot by suppliers, customers and employees and the loss of institutional investor interest in our common stock.

The DIP Facilities include financial and other covenants that impose substantial restrictions on our financial and business operations. There can be no assurance that we will be able to remain in compliance with the requirements of the DIP Facilities or that the lending commitments under the DIP Facilities will not be restricted or terminated by the DIP lenders.

The DIP Facilities provide for events of default specific to the Bankruptcy Case, including dismissal of the Bankruptcy Case, conversion to a case under Chapter 7 of the Bankruptcy Code, the appointment of a trustee, or entry of certain orders. Orders that would be an event of default include: an order reversing, amending, supplementing, staying or vacating the DIP order entered by the Bankruptcy Court; an order denying or terminating our use of cash collateral; an order granting relief from the automatic stay to the holder or holders of any security interest permitting foreclosure on our assets above a threshold amount; or an order authorizing other actions that would have an adverse effect on us. The DIP Facilities contain other events of default customary for debtor-in-possession financings. An event of default under the DIP Facilities would give the DIP lenders the right to terminate their lending commitments, declare all loans, all

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interest thereon and all other obligations under the DIP Facilities due and payable and exercise other remedies available to them under the DIP Facilities.

The DIP Facilities provide for customary representations and warranties by us. The DIP Facilities further provide for affirmative and negative covenants applicable to us and our subsidiaries, including affirmative covenants requiring us to provide financial information, 13-week projections and other information to the DIP lenders, including, upon request, environmental or mining site assessments or audit reports, and negative covenants restricting our ability and the ability of our subsidiaries to incur additional indebtedness, grant liens, dispose of assets, pay dividends or take certain other actions.

The DIP Facilities include financial covenants applicable to Patriot and its subsidiaries, including compliance with requirements relating to minimum consolidated EBITDA, as defined by the DIP Facilities, maximum capital expenditures and minimum liquidity. At December 31, 2012, we were in compliance with these financial covenants. Based on continued declines in metallurgical coal demand and prices experienced in the second half of 2012 and the related effect on our current internal financial forecasts, we believe there is a substantial likelihood that we may not comply with the minimum consolidated EBITDA financial covenant beginning in the third quarter of 2013. Our financial forecasts are subject to significant variation due to the volatility in the coal markets, including demand and prices for our products, and uncertainties surrounding our restructuring initiatives, so our compliance with the minimum consolidated EBITDA financial covenant remains subject to market conditions and our ability to improve financial performance. Failure to comply with our financial covenants would be an event of default under the terms of our DIP Facilities. If an event of default occurs, we would need to negotiate an amendment or waiver from the lenders; however, there can be no assurances that we would be able to obtain such an amendment or waiver in the future.

If, as a result of our breach of the terms thereof, the DIP Facilities are terminated or our access to funding thereunder is restricted or terminated, we may not have sufficient cash availability to meet our operating needs or satisfy our obligations as they become due, in which instance we could be required to seek a sale of Patriot or certain of its material assets pursuant to Section 363 of the Bankruptcy Code, or to convert the Bankruptcy Case into a liquidation under Chapter 7 of the Bankruptcy Code.

Our liquidity position imposes significant risk to our operations.

There can be no assurance that the amounts of cash from operations, together with amounts available under the DIP Facilities, will be sufficient to fund operations. Given the current business environment, our liquidity needs could be significantly higher than we currently anticipate. Our ability to maintain adequate liquidity through 2013 and beyond could depend on our ability to successfully implement an appropriate plan of reorganization, successful operation of our business and appropriate management of operating expenses and capital spending, and our ability to borrow under the DIP Facilities. Our expected liquidity needs are highly sensitive to changes in each of these and other factors. Even if we successfully take any of the actions described above, we may be required to execute asset sales or other capital generating actions over and above our normal business activities and cut back or eliminate other programs that are important to the future success of our business.

The DIP Facilities provide for (a) the First Out Revolving Credit Loan in an amount not to exceed $125.0 million, (b) the First Out Term Loan in the amount of $375.0 million, and (c) the Second Out Facility, in respect of pre-petition letters of credit, inclusive of any obligations as to reimbursement, renewal and extension of the same, issued in the aggregate amount of approximately $302.0 million as of July 9, 2012. In the event that cash flows and borrowings under the DIP Facilities are not sufficient to meet our liquidity requirements, we may be required to seek additional financing. There can be no assurance that additional financing would be available, or, if available, would be available on acceptable terms. Failure to secure any necessary additional financing would have a material adverse effect on our operations and ability to continue as a going concern.

Our liquidity challenges are public information and despite the liquidity provided by our DIP Facilities, our ability to maintain normal credit terms with our suppliers may become impaired. We may be required to pay cash in advance to certain vendors and may experience restrictions on the availability of trade credit, which would further reduce our liquidity. If liquidity problems persist, our suppliers could refuse to provide key products and services in the future. In addition, due to the public perception of our financial condition and results of operations, in particular with regard to uncertainties surrounding our bankruptcy process and reorganization, some customers could be reluctant to enter into long-term agreements with us.

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The pursuit of the Bankruptcy Case and related litigation has occupied and will continue to occupy a substantial portion of the time and attention of our management and will impact how our business is conducted, which may have an adverse effect on our business and results of operations.

A long period of operating under Chapter 11 could adversely affect our business and results of operations. While the Bankruptcy Case continues, our employees will be required to spend a significant amount of time and effort focusing on the Bankruptcy Case. This diversion of attention from other matters may materially adversely affect the conduct of our business, and, as a result, on our financial condition and results of operations, particularly if the Bankruptcy Case is protracted.

The venue transfer from the U.S. Bankruptcy Court for the Southern District of New York to the U.S. Bankruptcy Court for the Eastern District of Missouri may prolong the bankruptcy process.

On July 18, 2012 and August 7, 2012, respectively, the UMWA and several surety companies filed motions requesting that the venue for our Chapter 11 filing be transferred to the U.S. Bankruptcy Court for the Southern District of West Virginia. The U.S. Trustee also filed a motion arguing that the venue should be transferred from the Southern District of New York to another district. On November 27, 2012, the U.S. Bankruptcy Court for the Southern District of New York issued a ruling transferring the bankruptcy cases to the U.S. Bankruptcy Court for the Eastern District of Missouri and, on December 19, 2012, the U.S. Bankruptcy Court for the Southern District of New York entered an order formally transferring the bankruptcy cases to the U.S. Bankruptcy Court for the Eastern District of Missouri. An effect of the venue transfer may be to increase the amount of time necessary for us to exit bankruptcy, prolonging our exposure to the risks and uncertainties of bankruptcy proceedings as well as increasing our professional fees related to the process of reorganizing.

We may experience increased levels of employee attrition.

During the pendency of the Bankruptcy Case, our employees will face considerable distraction and uncertainty and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a materially adverse effect on our ability to meet customer and supplier expectations, thereby adversely affecting our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incentivize key employees to remain with us through the pendency of the Bankruptcy Case is limited during the Bankruptcy Case by restrictions on implementation of retention programs and the uncertain value of our equity compensation. The failure to retain or attract members of our executive management team and other key personnel could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.

If we are not be able to obtain confirmation of our plan of reorganization or if sufficient debtor-in-possession financing is not available, we could be required to seek a sale of the Company or certain of its material assets pursuant to Section 363 of the Bankruptcy Code or liquidate under Chapter 7 of the Bankruptcy Code.

Our plan of reorganization has not yet been formulated or submitted to the Bankruptcy Court. In order to successfully emerge from Chapter 11 bankruptcy protection, we must develop and obtain court and creditor approval of our plan of reorganization. This process requires us to meet statutory requirements with respect to adequacy of disclosure with respect to a plan, soliciting and obtaining creditor acceptance of a plan, and fulfilling other statutory conditions for plan confirmation. We may not receive the requisite acceptances to confirm a plan. Even if the requisite acceptances of a plan are received, the Bankruptcy Court may not confirm it or there may not be sufficient exit financing available to finance the Company’s emergence from Chapter 11 under a plan. In addition, the DIP Facilities may not be sufficient to meet our liquidity requirements or may be restricted or terminated by the lenders under the DIP Facilities for our breach thereof. If any of these events were to occur we could be forced to sell the Company or certain of its material assets pursuant to Section 363 of the Bankruptcy Code or liquidate under Chapter 7 of the Bankruptcy Code.

We have not made any final determinations with respect to reorganizing our capital structure, and any changes to our capital structure may have a material adverse effect on existing debt and security holders.

Any reorganization of our capital structure that we may engage in may include exchanges of new debt or equity securities for our existing debt and equity securities, and such new debt or equity securities may be issued at different interest rates, payment schedules, and maturities than our existing debt and equity securities. We may also modify our existing debt or equity securities to the same effect. Such exchanges or modifications are inherently complex to implement. The success of a reorganization through any such exchanges or modifications will depend on approval by the Bankruptcy Court and the willingness of existing debt and security holders to agree to the exchange or modification, and there can

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be no guarantee of success. If such exchanges or modifications are successful, the existing holders of common stock may find that their holdings no longer have any value, are materially reduced in value or are severely diluted. Also, holders of our debt may find their holdings no longer have any value or are materially reduced in value, or they may be converted to equity and be diluted or receive debt with a principal amount that is less than the outstanding principal amount, longer maturities, and reduced interest rates. There can be no assurance that any new debt or equity securities will maintain their value at the time of issuance. Also, if the existing debt or equity security holders are adversely affected by a reorganization, it may adversely affect Patriot’s ability to issue new debt or equity in the future.

The volatility of the financial markets may prevent us from obtaining financing to complete the reorganization.

In order to reorganize, we will require access to the financial markets. Financial markets remain fragile and are heavily influenced by volatile government policies and interventions, which may ultimately limit the terms, availability and affordability of financing necessary for us to reorganize.

Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may be unsuccessful in its execution.

Any plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to substantially change our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees; and (v) the overall strength and stability of general economic conditions of the financial and coal industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, EBITDA, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

Operating under Chapter 11 may restrict our ability to pursue our strategic and operational initiatives.

Under Chapter 11, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities. Additionally, the terms of the DIP Facilities limit our ability to undertake certain business initiatives. These limitations include, among other things, our ability to:

• sell assets outside the normal course of business;

• consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;

• grant liens; and

• finance our operations, investments or other capital needs or to engage in other business activities that might be in our interest.

As a result of the Bankruptcy Case, realization of assets and liquidation of liabilities are subject to uncertainty.

While operating under the protection of the Bankruptcy Code, and subject to Bankruptcy Court approval or otherwise as permitted in the normal course of business, we may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in our consolidated financial statements. Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do

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not currently give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

As a result of the Bankruptcy Case, our historical financial information may not be indicative of our future financial performance.

Our capital structure will likely be significantly altered under any plan of reorganization ultimately confirmed by the Bankruptcy Court. Under fresh-start reporting rules that may apply to us upon the effective date of a plan of reorganization, our assets and liabilities would be adjusted to fair values and our accumulated deficit would be restated to zero. Accordingly, if fresh-start reporting rules apply, our financial condition and results of operations following our emergence from Chapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. In connection with the Bankruptcy Case and the development of a plan of reorganization, it is also possible that additional restructuring and related charges may be identified and recorded in future periods. Such charges could be material to our consolidated financial position and results of operations in any given period.

Risk Factors Relating to Demand for our Products

Any change in coal consumption patterns 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 25%, 24% and 22% of our coal sales volume during the years ended December 31, 2012, 2011 and 2010, respectively. Metallurgical coal is sold to 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 75%, 76% and 78% of our coal sales volume during the years ended December 31, 2012, 2011 and 2010, 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. The increasingly stringent requirements of the Clean Air Act and 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. Recent 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 2012, coal demand was negatively impacted by low natural gas prices, mild weather and weak international and domestic economies. The demand for metallurgical coal is dependent on the strength of the global economy and, in particular, on steel production in countries such as China and India as well as Europe, Brazil and the U.S. In response to the recent global economic downturn, the demand for steel declined, and as a result, the demand and price for metallurgical coal also declined.

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.

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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.

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 may be materially and adversely affected.

Prolonged global recessionary conditions could impact our customers’ ability to perform under our contracts with them and 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 demand 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 experienced in Greece and certain other European countries, demand for electricity and steel production may suffer.

The slowing global economic growth and distressed European financial markets experienced in late 2011 and early 2012 created economic uncertainty, and steel producers and electricity generators responded by decreasing coal purchases. 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. During the first half of 2012, we were approached by certain customers seeking to cancel or delay shipments of coal contracted for delivery under coal supply agreements. In addition, two of our customers defaulted on their contractual obligations to purchase coal from us. We have filed legal actions for damages resulting from these breached contracts. 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 Australia, Colombia, Venezuela and Indonesia.

Depending on the strength of the U.S. dollar relative to currencies of other coal-producing countries, coal from other countries 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.

We could experience decreased profitability if future coal production is consistently greater than coal demand. Lower demand for coal in recent years has resulted in the idling of coal production capacity, much of which, however, could be put back into production should demand increase. Any resulting overcapacity from existing or new competitors could reduce coal prices and, therefore, our revenue and profitability.

We also face competition from renewable energy providers, like biomass, wind and solar, and other alternative fuel sources, like natural gas and nuclear 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

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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 increase electricity generation from their natural gas-fueled plants instead of generation from 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 have considered the passage of significant new laws to address climate change, including, among others, 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, with the ultimate goal of reducing greenhouse gas emissions. The EPA and other regulators are using existing laws, including the federal Clean Air Act, to impose obligations, including emission limits and technology-based requirements, on carbon dioxide and other greenhouse gas emissions. For example, in April 2012 the EPA proposed new source performance standards for emissions of carbon dioxide from certain new power plants. The proposal anticipates that affected new-build, coal-fueled plants generally would need to install carbon capture and storage technologies, which currently is not economically feasible, or other expensive control technology to meet the proposed standard. Although it is not yet possible to predict the effect of the GHG Tailoring Rule, greenhouse gas reporting requirements or the proposed 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, 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 regulations under the Clean Air Act were recently finalized or are expected to be finalized in 2013 that regulate emissions of sulfur dioxide, nitrogen oxide, mercury and other air pollutants from power plants and industrial boilers. The regulations include CAIR, which establishes a cap and trade system for emissions of sulfur dioxide and nitrogen oxide from power plants in 27 eastern states, the Mercury and Air Toxics Standards, which regulates emissions of mercury and other heavy metals from power plants, and National Emission Standards for Hazardous Air Pollutants regulating emissions of mercury and other metals and organic air toxics from industrial, commercial and institutional boilers. The EPA is also expected to issue a new rule to replace CAIR in regulating the interstate transport of sulfur dioxide and nitrogen oxide emissions. Any such replacement rule could impose significant obligations on our customers, which could reduce the demand for coal.

A well-publicized failure in December 2008 of a coal ash slurry impoundment maintained by the Tennessee Valley Authority 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 adversely affect our and our customers’ reputations and reduce demand for coal.

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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.

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. Due to the public perception of our financial condition and results of operations, in particular with regard to uncertainties surrounding our bankruptcy process and reorganization, some customers could be reluctant to enter into long-term agreements with us. 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 to us.

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 that 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 that 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

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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.

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.

We could be negatively affected if we fail to maintain satisfactory labor relations, especially as we attempt to implement changes to wage and benefit programs and postretirement benefit obligations pursuant to Sections 1113 and 1114 of the Bankruptcy Code.

As of December 31, 2012, Patriot had approximately 4,100 employees. Approximately 40% 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 employees are represented by the UMWA. In 2011, certain of our subsidiaries signed new labor agreements with the UMWA that generally extend through December 31, 2016. Our represented employees work at various sites in Appalachia and at the Highland complex in the Illinois Basin.

In relation to the bankruptcy process and pursuant to Sections 1113 and 1114 of the Bankruptcy Code, Patriot is seeking to renegotiate the terms of collective bargaining agreements between certain Patriot subsidiaries and the UMWA, as well as certain postretirement healthcare benefits. The outcome of these negotiations is subject to many uncertainties and there is a risk that UMWA-represented employees may strike.

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 were to become organized, we could incur additional costs and an increased risk of work stoppages.

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 and that there are not sufficient numbers of younger workers with the requisite skills and knowledge to replace them. Further, due to uncertainties surrounding the Bankruptcy Case, it may be more difficult for us to hire new skilled laborers and managers. 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.

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 certain 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 becomes unavailable to meet our replacement demands, our profitability could be reduced.

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.

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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.

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, 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.

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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

Like many of our competitors, we have difficulty complying 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 implementing and maintaining a Fluidized Bed Reactor (FBR) water treatment facility for three Apogee outfalls, an Advanced Biological Metals Removal System (ABMet) selenium treatment technology at the Hobet Surface Mine No. 22 outfall, and Iron Facilitated Selenium Reduction (IFSeR) water treatment facilities at outfalls covered by various legal actions as described in Item 3. The outfalls to be remediated using IFSeR technology were separated into five categories based on the average gallons per minute water flow at each outfall. The estimated costs of IFSeR technology were based upon the installation and operating costs at the Category 1-5 outfalls.

The FBR water treatment facility for the three Apogee outfalls will be the first facility constructed for selenium removal on a commercial scale. Neither the FBR technology nor ABMet technology to be utilized at the Hobet Surface Mine No. 22 outfall 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.

To date, IFSeR technology has not been proven to achieve effluent selenium limitations for the water flows at outfalls other than those in Category 1. There is significant uncertainty as to which technology, if any, could be utilized to achieve compliance at the other four categories, particularly those with higher average water flows. However, IFSeR technology is currently the treatment technology that is best adapted for installation and operation under the various site-specific conditions at our outfalls.

If IFSeR systems are not ultimately successful in treating the effluent selenium exceedances at the outfalls covered by various legal actions as described in Item 3, we may be required to install alternative treatment solutions and may be subject to penalties or further litigation. Alternative technology solutions that we may ultimately select are still in the early phases of development and their related costs cannot be reasonably estimated at this time. The cost of other water treatment solutions could be materially different than the costs reflected in our liability. Furthermore, costs associated with potential modifications to IFSeR or the scale of our current IFSeR systems could also cause the costs to be materially different 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. Potential installations of selenium treatment alternatives are further complicated by the variable geological, topographical and water flow 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 for outfalls covered by legal actions against us. As a result, actual costs may

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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, modifications pursuant 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 to which we are subject.

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 for the Southern District of West Virginia (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 financial condition, results of operations and cash flows.

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

We may incur additional costs relating to the lawsuits discussed above, 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, permits may not be issued.

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. 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 may become increasingly restrictive, and there may be more rigorous enforcement of existing and future laws and regulations. For example, 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. 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

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suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. 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. Existing and future environmental, health and safety regulations, and the enforcement thereof, could have a material adverse effect on our financial condition, results of operations and cash flows.

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 establishing threshold conductivity levels to be used as a basis for evaluating compliance with narrative water quality standards. Though a federal district court set aside this guidance in July 2012, the EPA has appealed this decision. If the guidance is reinstated, we and other mining companies could be subject to more stringent permit requirements. There can be no guarantee that we would 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 were not directly impacted, and a federal district court has since reinstated the permit, this could be an indication that other surface mining water permits could be subject to more substantial review in the future. In addition, the federal Office of Surface Mining and Reclamation is considering rewriting the Stream Protection Rule. As rewritten, this rule could require us to comply with more stringent mining and reclamation obligations near water sources, or refrain from mining certain of our reserves.

A recent settlement and consent decree modification between Patriot and environmental non-governmental organizations also demonstrates regulatory authorities’ increased focus on the effects of surface coal mining and the regulatory impediments to large-scale surface mining operations. In December 2012, the Bankruptcy Court and the U.S. District Court approved an agreement between Patriot and such non-governmental organizations regarding claims under the Clean Water Act relating to surface mining activities in West Virginia. In exchange for extensions of technology selection and specified compliance dates related to selenium discharge limits, Patriot agreed to, among other things, impose interim caps on surface mining coal production beginning in 2014 and leading to a permanent annual cap beginning in 2018, retire its Paint Creek surface mine dragline in 2013 and its Hobet surface mine dragline in 2015, and refrain from certain new large-scale surface mining operations.

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 further, it could significantly increase our operational costs and make it more difficult to economically recover 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

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environmental, health and aesthetic impacts of surface coal mining could harm our reputation and reduce demand for coal.

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 the 1974 Plan, a multi-employer pension fund, that was 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. The plan provides pension and disability pension benefits to qualifying represented employees upon retirement. The funding is based on an hourly rate for active UMWA workers. The 2011 NBCWA requires funding at $5.50 per hour for certain UMWA workers. As of May 25, 2012, the 1974 Plan adopted a funding improvement plan under which the contribution rate is scheduled to increase in stages, beginning in 2017, from the current $5.50 per hour to a minimum of $12.50 per hour in 2017 up to a maximum potential rate of $26.50 per hour as early as 2022. Certain of our other subsidiaries have entered into other labor agreements with the UMWA that contain terms that differ from the terms of the 2011 NBCWA and that do not provide for participation in or contribution to the 1974 Plan.

Under the 2011 NBCWA, new inexperienced miners hired after January 1, 2012 do not participate in the 1974 Plan. Instead, for each hour worked, the Company contributes $1.00 into the UMWA Cash Deferral Plan on the employee’s behalf, increasing to $1.50 on January 1, 2014. Effective January 1, 2012, employers also pay $1.50 per hour to a new Retiree Bonus Account Trust (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. If Trust funding is not sufficient to make these annual bonus payments, employers will pay the difference directly to their retirees.

Under the 2011 NBCWA, effective January 1, 2012, employers 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 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 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 may be higher than the current rate as this deficit is addressed.

The Surface Mining Control and Reclamation Act Amendments of 2006 (2006 Act) authorized $490 million in general fund revenues to pay for certain benefits, including the healthcare costs under the UMWA 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.

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.

Certain of our current and historical coal mining operations have used hazardous materials and, to the extent that such materials are not recycled, they could become hazardous waste. We may be subject to claims under federal and state statutes and/or common law doctrines for toxic torts and other damages, as well as for natural resource damages and for the investigation and remediation of soil, surface water, groundwater, and other media under laws such as CERCLA, commonly known as Superfund. Such claims may arise, for example, out of current or former conditions at sites that we own or operate currently, as well as at sites that we and companies we acquired, owned or operated in the past, and at contaminated sites that have always been owned or operated by third parties with whom we do business. 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,

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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, and may become subject to other legal proceedings in the future, 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 and may become subject to other legal proceedings in the future. 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 current claims and litigation.

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 calculate the total estimated reclamation and mine-closing liabilities in accordance with accounting principles generally accepted in the U.S. 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, 2012, we had accrued reserves of $124.6 million for reclamation liabilities and an additional $164.0 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

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, 2012, we had outstanding surety bonds and letters of credit aggregating $564.9 million, of which $354.5 million was for post-mining reclamation, $132.6 million related to workers’ compensation obligations, $54.4 million was for retiree health obligations and $23.5 million was for other obligations (including collateral for surety companies and bank guarantees, road maintenance and performance guarantees). Some of these bonds are renewable on an annual basis and the letters of credit are available through the DIP Facilities.

As of December 31, 2012, Arch Coal, Inc. (Arch) posted surety bonds of $34.3 million related to properties acquired by Patriot in the Magnum acquisition, of which $33.1 million related to reclamation. Magnum posted a letter of credit in Arch’s favor, as required, for a portion of the outstanding reclamation bonds. As part of the bankruptcy proceedings, our prior surety agreement with Arch was terminated and replaced with a new surety agreement.

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 DIP Facilites and the exercise by third-party surety bond issuers of their right to refuse to renew the surety.

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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 non-regulated affiliates or third parties. These new customers may have credit ratings that are below investment grade. If the creditworthiness of our customers declines significantly and customers fail to make their payments, our business could be adversely affected.

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.

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 employees 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.

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 in accordance with accounting principles generally accepted in the U.S. We estimated the present value of the obligation to be $1.6 billion as of December 31, 2012. 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.

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 $637.6 million as of December 31, 2012. These obligations arise under the Coal Act, the 2007 NBCWA and predecessor and successor agreements and the 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 the 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.

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.

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Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the U.S. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. Any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

Item 1B.Unresolved Staff Comments.

None.

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Item 2.Properties.

Coal Reserves

We had an estimated 1.8 billion tons of proven and probable coal reserves as of December 31, 2012 located in Appalachia and the Illinois Basin. Of our proven and probable coal reserves 13%, or 234 million tons, are compliance coal and 1,610 million tons are non-compliance coal. We own approximately 37% of these reserves and lease property containing the remaining 63%. 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, 2012(1)
Geographic Region	Owned Tons	Leased Tons	Total Tons
	(In millions)
Appalachia	300	886	1,186
Illinois Basin	382	276	658
Total proven and probable coal reserves	682	1,162	1,844

⁽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 1,082 million tons of proven and 762 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 lie 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, 2012 were prepared by the Vice President–Engineering and his geology and engineering staff, by updating the December 31, 2011 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 1.8 billion tons of proven and probable reserves as of December 31, 2012.

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

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to determine the extent of our proven and probable coal reserves in a given area. The land management system contains reserve information, including the quantity and quality (where available) of coal reserves as well as production rates, surface ownership, lease payments and other information relating to our coal reserves and land holdings. We periodically update our reserve estimates to reflect production of coal from the reserves and new drilling or other data received. Accordingly, reserve estimates will change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings, modification of mining methods and other factors.

Our estimate of the economic recoverability of our proven and probable coal reserves is based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to existing market prices for the quality of coal expected to be mined and take into consideration typical contractual sales agreements for the region and product. Where possible, we also review production by competitors in similar mining areas. Only coal reserves expected to be mined economically are included in our reserve estimates. Finally, our coal reserve estimates include reductions for recoverability factors to estimate a saleable product.

With respect to the accuracy of our reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average. Our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to move reserves from the probable to the proven classification. The expected degree of variance from reserve estimate to tons produced is lower in the Illinois Basin due to the continuity of the coal seams as confirmed by the mining history. Appalachia has a higher degree of risk due to the mountainous nature of the topography which makes exploration drilling more difficult. Our proven and probable reserves in Appalachia are less predictable and may vary by an additional one to two percent above the threshold discussed above.

Private coal leases normally have terms of between 10 and 20 years and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments.

The terms of our private leases are normally extended by active production on or near the end of the lease term. Leases containing undeveloped reserves may expire or these leases may be renewed periodically. With a portfolio of approximately 1.8 billion tons, we believe that we have sufficient reserves to replace capacity from depleting mines for an extensive period of time and that our significant base of proven and probable coal reserves is one of our strengths. We believe 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.

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The following chart provides a summary, by geographic region and mining complex, of production for the years ended December 31, 2012, 2011 and 2010, 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, 2012
Geographic Region/ Mining Complex	Year Ended Dec 31, 2012	Year Ended Dec 31, 2011	Year Ended Dec 31, 2010	<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	0.1	1.8	2.0	5	6	—	Thermal	12,200	11	—	11	—	11
Corridor G	2.8	3.6	4.0	3	34	18	Thermal	12,300	55	1	54	55	—
Jupiter	—	—	—	1	4	—	Thermal	11,500	5	—	5	1	4
Kanawha Eagle	0.8	1.4	1.5	27	28	—	Met/Thermal	13,100	55	—	55	—	55
Logan County	2.3	2.6	2.7	12	16	38	Met/Thermal	12,500	66	14	52	44	22
Midland Trail	1.6	1.5	1.5	34	64	7	Thermal	12,800	105	24	81	11	94
Paint Creek	1.6	1.2	1.1	23	31	1	Met/Thermal	13,000	55	—	55	9	46
Panther	2.3	1.9	2.0	32	10	—	Met	13,200	42	1	41	—	42
Rocklick	0.8	1.1	0.4	—	14	—	Met	13,000	14	—	14	—	14
Wells	1.6	2.8	3.1	23	24	—	Met	13,200	47	—	47	—	47
Federal	4.0	3.7	3.7	—	—	37	Thermal	13,300	37	33	4	—	37
Total	17.9	21.6	22.0	160	231	101			492	73	419	120	372
Illinois Basin:
Bluegrass	1.5	2.4	2.3	—	—	15	Thermal	11,100	15	14	1	1	14
Dodge Hill	0.9	0.9	0.9	—	—	21	Thermal	12,700	21	1	20	—	21
Highland	4.0	3.9	3.5	—	—	83	Thermal	11,400	83	27	56	—	83
Total	6.4	7.2	6.7	—	—	119			119	42	77	1	118
Total	24.3	28.8	28.7	160	231	220			611	115	496	121	490

⁽¹⁾  Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2012. Unassigned reserves would require new mine development, mining equipment or plant facilities before operations could begin on the property.

⁽²⁾  Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal.

⁽³⁾  Type of coal is based on the type of coal produced and/or the type of coal in our reserves.

⁽⁴⁾  As-received Btu per pound includes the weight of moisture in the coal on an as-sold basis.

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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, 2012

						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	492	668	1,160	782	378	231	607	322	Met/Thermal	12,200	274	886	226	934
Total	492	694	1,186	801	385	231	607	348			300	886	226	960
Illinois   Basin:
Illinois	—	228	228	87	141	3	18	207	Thermal	11,100	226	2	—	228
Kentucky	119	311	430	194	236	—	3	427	Thermal	11,300	156	274	30	400
Total	119	539	658	281	377	3	21	634			382	276	30	628
Total  proven and   probable	611	1,233	1,844	1,082	762	234	628	982			682	1,162	256	1,588

⁽¹⁾  Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2012. Unassigned reserves would require new mine development, mining equipment or plant facilities before operations could begin on the property.

⁽²⁾  Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal.

⁽³⁾  Type of coal is based on the type of coal produced and/or the type of coal in our reserves.

⁽⁴⁾  As-received Btu per pound includes the weight of moisture in the coal on an as-sold basis.

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Item 3.Legal Proceedings.

From time to time, we are involved in legal proceedings, arbitration proceedings and administrative procedures arising in the ordinary course of business. It is currently unknown what the ultimate resolution of these proceedings will be, but the costs of resolving these proceedings could be material, and could result in an obligation to change our operations in a manner that could have an adverse effect on us. Our significant legal proceedings are discussed below.

The Bankruptcy Case

On July 9, 2012, the Debtors filed voluntary petitions for reorganization under the Bankruptcy Code in the Bankruptcy Court for the Southern District of New York. On November 27, 2012, the U.S. Bankruptcy Court for the Southern District of New York issued a ruling transferring the bankruptcy cases to the U.S. Bankruptcy Court for the Eastern District of Missouri. On December 19, 2012, the U.S. Bankruptcy Court for the Southern District of New York entered an order formally transferring the bankruptcy cases to the U.S. Bankruptcy Court for the Eastern District of Missouri (the U.S. Bankruptcy Court for the Eastern District of Missouri and/or the U.S. Bankruptcy Court for the Southern District of New York, as applicable, the Bankruptcy Court). The Debtors’ Chapter 11 cases are being jointly administered under the caption In re: Patriot Coal Corporation, et al. (Case No. 12-51502) (the Bankruptcy Case). The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As a result of the Chapter 11 Petitions, much of the pending litigation against the Debtors is stayed. Subject to certain exceptions and approval by the Bankruptcy Court, during the Chapter 11 process, no party can take further actions to recover pre-petition claims against the Debtors.

Environmental Claims and Litigation

We are subject to applicable federal, state and local environmental laws and regulations including Surface Mining Control and Reclamation Act (SMCRA), the federal Clean Water Act (CWA), the Clean Air Act, Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), Resource Conservation and Recovery Act (RCRA) and their state equivalents.

Clean Water Act Permit Issues

The 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 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. States are empowered to develop and enforce water quality standards, which are subject to change and must be approved by the U.S. Environmental Protection Agency (EPA). Water quality standards vary from state to state.

Patriot assumed obligations related to the discharge of selenium in excess of allowable limits at certain mining operations as part of the Magnum acquisition in July 2008. We had estimated the costs to treat the selenium discharges in excess of allowable limits at fair value at the acquisition date and continue to adjust these amounts as our treatment plans change. At the time of the acquisition, selenium discharge limits were first being added and becoming effective in our NPDES permits as the permits were being renewed. On an industry-wide basis, there was no proven technology to effectively treat selenium in coal mining discharges to the levels required. Existing technology continues to evolve and new technologies are being considered for the treatment of selenium discharges in excess of allowable limits. Additionally, 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 require us to, among other things, meet certain compliance deadlines. As of December 31, 2012, the liability related to selenium water treatment at outfalls with known exceedances was $443.0 million and reflects the estimated costs of the planned technology selections to be implemented and maintained at these operations. Further discussed below are the lawsuits in which we are involved, the various rulings and settlements related to these lawsuits, and the continued uncertainties related to the identification, implementation and cost of effective technologies.

At December 31, 2012, environmental claims and litigation in connection with our various NPDES permits and related CWA requirements included the following:

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Hobet West Virginia Department of Environmental Protection (WVDEP) Action

In 2007, Hobet Mining, LLC (Hobet), one of our subsidiaries, was sued for exceedances of effluent limits contained in four of its NPDES permits in state court in Boone County, West Virginia by the WVDEP. We refer to this case as the Hobet WVDEP Action. This action addressed all effluent limits, including selenium, established by the permits. We entered into a settlement and consent order with the WVDEP, as subsequently modified, to extend coverage to two additional permits, achieve full compliance with the WVDEP permits by July 2012 and to study potential treatment alternatives for selenium. One of the permits, for Hobet Surface Mine No. 22, was subsequently addressed as discussed below.

In May 2012, WVDEP and Hobet jointly requested an extension of the July 2012 compliance date while further refinements to the consent decree were discussed. The Boone County Circuit Court has extended the compliance date while those discussions are ongoing.

Federal Apogee Case and Federal Hobet Case

In 2007, Apogee Coal Company, LLC (Apogee), one of our subsidiaries, 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 water effluent limits for selenium set forth in one of its NPDES permits. The lawsuit sought compliance with the effluent limits of the NPDES permit, fines and penalties as well as injunctive relief prohibiting Apogee from further violating laws and its permit.

In 2008, OVEC and another environmental group filed a lawsuit against Hobet and WVDEP in the U.S. District Court (pursuant to the citizen suit provisions of the CWA). We refer to this case as the Federal Hobet Case and it is very similar to the Federal Apogee Case. Additionally, the Federal Hobet Case involved four NPDES permits that were the subject of the 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 the below discussion of the September 1, 2010 U.S. District Court Ruling for a description of 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 had in the past violated, and continued to violate, effluent limitations for selenium in a 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 U.S. District Court hearing that began on August 9, 2010. See the below discussion of the September 1, 2010 U.S. District Court Ruling for a description of 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 in West Virginia. 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

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and surface mining permits. WVDEP sought fines and penalties as well as injunctions prohibiting Catenary from discharging pollutants, including selenium, in violation of laws and NPDES permits. The Catenary WVDEP Action was consolidated with the Hobet WVDEP Action. The permits contained in the Catenary WVDEP Action are also included in the February 2011 Litigation discussed below.

On June 11, 2010, WVDEP filed a lawsuit against Apogee in the Logan County Circuit Court in West Virginia, 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 Apogee WVDEP Action are also included in the February 2011 Litigation discussed below. WVDEP is seeking fines and penalties as well as injunctions prohibiting Apogee from discharging pollutants, including selenium, in violation of laws and NPDES permits. No trial date is currently scheduled in the Apogee WVDEP Action and we remain engaged with the WVDEP regarding resolution of the Apogee WVDEP Action. The compliance deadline for outfalls covered by these lawsuits was addressed in the January 2012 comprehensive consent decree and subsequent modification, and we are taking steps to resolve these lawsuits on terms that are not inconsistent with the comprehensive consent decree, as amended by the December 2012 modification described below.

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, 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. See the below discussion of the January 2012 comprehensive consent decree for a description of the resolution to this matter.

Rulings and Settlements Related to Environmental Claims

Discussed below are the outcomes of certain of these proceedings as well as negotiations stemming from these lawsuits:

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 $69.5 million ($48.8 million related to installation costs and $20.7 million related to operating costs) for the fair value of the estimated costs related to these three outfalls. This charge was reflected in “Asset retirement obligation expense” in the consolidated statement of operations. We began construction on the Apogee FBR facility in the third quarter of 2011. As of December 31, 2012, the construction of the FBR facility is substantially complete and the testing phase of the installation is nearing completion. As of December 31, 2012, we have spent approximately $42.5 million on the Apogee FBR facility and the total expenditures are estimated to be approximately $48.0 million.

As part of this ruling, the U.S. District Court ordered Hobet to submit a proposed schedule to develop a treatment plan for the 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. As part of this process, 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 utilize an ABMet selenium treatment technology at this outfall. The U.S. District Court subsequently confirmed this technology. In 2011, we increased the selenium water treatment liability by $35.0 million ($21.3 million related to installation costs and $13.7 million related to operating costs) related to the fair value of the estimated costs of the ABMet water treatment facility at this outfall. This charge was reflected in “Asset retirement obligation expense” in the consolidated statement of operations. We began construction on the facility in the second quarter of 2012. As of December 31, 2012, we have spent approximately $5.6 million on the Hobet ABMet water treatment facility and total expenditures are estimated to be approximately $25.0 million.

January 2012 Comprehensive Consent Decree

On January 18, 2012, we finalized a comprehensive consent decree with OVEC and the other environmental groups to resolve the February 2011 Litigation. The comprehensive consent decree was approved by the U.S. District Court and

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became effective on March 15, 2012. The comprehensive consent decree set 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.

The comprehensive consent decree separated 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. Additionally, as subsequently amended in December 2012, 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 by March 15, 2015 and ending with the last category by March 15, 2018. We also agreed to waive our rights to mine certain coal reserves and to pay $7.5 million in civil penalties. These penalties 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.

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 the following framework under which we will interface with the plaintiffs with respect to the identified permits and outfalls:

Category/Gallons Per Minute	Technology Selection Date	Specified Compliance Date
I / 0-200	September 1, 2012	March 15, 2014
II / 201-400	December 31, 2012	March 15, 2015
III / 401-600	March 31, 2013	December 15, 2015
IV / 601-1000	September 1, 2013	May 15, 2016
V / 1000 +	September 1, 2014	March 15, 2017

The December 2012 Settlement and Consent Modification, as discussed more fully below, subsequently extended each of the technology selection and specified compliance deadlines by 12 months.

The comprehensive consent decree required that we select water treatment technology by category beginning with the first category in September 2012. We performed pilot testing on Iron Facilitated Selenium Reduction (IFSeR) technology in early 2012 and concluded the testing in May 2012. In May 2012, related to the January 2012 comprehensive consent decree, we submitted IFSeR technology to the Special Master for review and approval. The Special Master certified that IFSeR may be considered as a listed technology for Category 1 outfalls.

Prior to the second quarter of 2012, the liability to treat selenium discharges at outfalls not addressed in the September 1, 2010 U.S. District Court Ruling continued to be based on the use of the ZVI technology as there was no other definitive plan to install any technology other than ZVI. During the second quarter of 2012, we modified our selenium water treatment compliance plan from ZVI technology to IFSeR technology. IFSeR was developed in response to our need to resolve certain detailed design considerations for ZVI technology. While ZVI water treatment systems decreased selenium discharges, they had not performed consistently in reducing selenium concentrations to compliant levels. IFSeR incorporated various design enhancements including utilizing ZVI media in a different configuration than the original ZVI water treatment technology. We recorded an adjustment to increase our selenium water treatment liability by $307.4 million during the second quarter of 2012 to recognize the modification to our compliance plan from installing and operating ZVI technology to installing and operating IFSeR technology. This adjustment was based upon estimates for the installation and operating costs of IFSeR water treatment systems at the Category 1-5 outfalls.

In the fourth quarter of 2012, we recorded an adjustment to decrease our selenium water treatment liability by $49.1 million in total, $17.6 million of which related to optimizations made to the operational design of the IFSeR technology system. The remaining $31.5 million adjustment is discussed below as part of our December 2012 settlement. We continue to refine the IFSeR treatment systems to obtain the most effective selenium removal in the most cost-effective manner and will adjust the liability in the future as necessary.

December 2012 Settlement and Consent Modification

In December 2012, the Bankruptcy Court and the U.S. District Court approved an agreement between Patriot and OVEC and other environmental groups to extend the Hobet Surface Mine No. 22 outfall compliance date to August 1, 2014. In addition, a 12-month extension of each of the technology selection and specified compliance dates in the January

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2012 comprehensive consent decree was approved. Extension of the deadlines allows us to defer spending and maintain liquidity during the bankruptcy proceedings and provides additional time for alternative treatment technologies and solutions to develop. In the fourth quarter of 2012, we recorded a $31.5 million adjustment to decrease our selenium water treatment liability due to the impact of delaying the specified deadlines and the corresponding cash spending. The U.S. District Court separately entered an order extending the Hobet Surface Mine No. 22 outfall compliance date to August 1, 2014 in December 2012 and the modification to the comprehensive consent decree in January 2013.

As part of the settlement, we agreed to, among other things, impose interim caps on surface mining coal production beginning in 2014 leading to a permanent annual cap beginning in 2018; retire our Paint Creek surface mine dragline in 2013 and our Hobet surface mine dragline in 2015; and refrain from certain new large-scale surface mining operations. We performed a full assessment of our coal reserves to determine if the restrictions on certain types of mining would prevent us from mining any of our coal reserves. This assessment indicated that the existing coal reserves are likely accessible through mining techniques that are not impacted by the settlement and as such, no impairment charge was recorded.

Continued Uncertainties Related to Selenium Water Treatment Obligations

Prior to our pilot project performed in 2010, FBR technology required under the September 1, 2010 U.S. District Court Ruling had not been used to remove selenium or any other minerals discharged at coal mining operations, but had been successful in other industrial applications. The FBR water treatment facility will be the first facility constructed for selenium removal on a commercial scale. Neither the FBR technology nor ABMet technology to be utilized at the Hobet Surface Mine No. 22 outfall 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.

On September 1, 2012, we provisionally selected the IFSeR technology for all of our Category 1 outfalls. To date, IFSeR technology has not been proven to achieve effluent selenium limitations for the water flows at outfalls other than Category 1. There is significant uncertainty as to which technology, if any, could be utilized to achieve compliance at the other four categories, particularly those with higher average water flows. However, IFSeR technology is currently the treatment technology that is best adapted for installation and operation under the various site-specific conditions at our outfalls.

If IFSeR 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 may be required to install alternative treatment solutions. Alternative technology solutions that we may ultimately select are still in the early phases of development and their related costs cannot be reasonably estimated at this time. The cost of other water treatment solutions could be materially different than the costs reflected in our liability. Furthermore, costs associated with potential modifications to IFSeR or the scale of our current IFSeR systems could also cause the costs to be materially different 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. Potential installations of selenium treatment alternatives are further complicated by the variable geological, topographical and water flow 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 for outfalls covered by the Hobet WVDEP Action and the February 2011 Litigation. 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, modifications pursuant 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 to which we are subject.

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, or 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 financial condition, results of operations and cash flows.

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

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future technological progress could result in costs that differ from our current estimates, which could have a material adverse effect on our financial condition, results of operations and cash flows.

We may incur additional costs relating to the lawsuits discussed above, 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, permits may not be issued.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)

CERCLA and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to natural resources. Under CERCLA and many similar state statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault. These laws and related regulations could require us to do some or all of the following: (i) remove or mitigate the effects of the disposal or release of certain substances on the environment at various sites; (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 and 31, 2004 and June 4, 2004 in the Island Creek watershed of southern West Virginia. This litigation is pending before two different judges in the Circuit Court of Logan County, West Virginia. In one action, the plaintiffs assert 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 filed motions to dismiss, which were granted with respect to general factual allegations, generic claims, claims of strict liability and fraud and claims asserted by plaintiffs from certain localities. In the second action, in which plaintiffs allege that Hobet and Catenary engaged in extensive land altering activities that disturbed hydraulic balance, increased peak flow and surface runoff, and blocked natural drains, Hobet and Catenary filed motions to dismiss, asserting that the plaintiffs’ allegations are conclusory in nature and likely deficient as a matter of law. Most of the other defendants also filed motions to dismiss. The litigation of both actions are stayed due to the bankruptcy of one or more defendants. 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

Certain Patriot directors and officers have been named as defendants in various lawsuits filed in the U.S. District Court in the Eastern District of Missouri. In June 2012, a shareholder filed a derivative lawsuit for the benefit of Patriot against each of the then directors of Patriot and Patriot as a nominal defendant. This lawsuit was administratively closed due to the Bankruptcy Case. During the second half of 2012 and subsequent to the filing of the Chapter 11 Petitions, three class action complaints were filed against a former Chief Executive Officer, Richard M. Whiting, and former Chief Financial Officer, Mark N. Schroeder (the Class Action Complaints). The Class Action Complaints contain nearly identical allegations including that the defendants made or allowed false and misleading statements related to Patriot’s selenium water treatment liability and Patriot’s financial condition. The Class Action Complaints were consolidated and a lead plaintiff was appointed during January 2013. The Class Action Complaints can proceed during the pendency of the Bankruptcy Case as Patriot was not named as a defendant.

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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. 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, 2012, 51 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.

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.

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 January 2012, the terminated employee filed a civil lawsuit against us alleging retaliatory discharge and intentional infliction of emotional distress. Additionally, in January 2012, 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 are vigorously defending both civil lawsuits and the potential impact of these lawsuits cannot be estimated at this time. Both civil lawsuits are currently stayed due to the bankruptcy of one or more defendants.

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.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.

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PART II

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

Effective July 10, 2012, the New York Stock Exchange (NYSE) suspended trading of our common stock as a result of our filing of the Chapter 11 Petitions. On August 6, 2012, our common stock was delisted from the NYSE. Our stock is now traded under the ticker symbol “PCXCQ” on the OTCQB marketplace, operated by OTC Markets Group Inc. Prior to August 6, 2012, our common stock traded on the NYSE under the symbol “PCX”.

As of February 15, 2013, there were approximately 799 holders of record of our common stock.

The table below sets forth the range of quarterly high and low sales prices for our common stock during the calendar quarters indicated.

	High		Low
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
2012
First Quarter	$	9.24	$	6.22
Second Quarter	6.73		1.07
Third Quarter	2.26		0.10
Fourth Quarter	0.19		0.07

Dividend Policy

During the period covered by this report, we have not paid cash dividends on our common stock. As we are in Chapter 11 proceedings, we are prohibited from paying dividends.

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. 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, 2012 and the consolidated balance sheet data as of December 31, 2012 and 2011 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, 2010, 2009 and 2008 and the consolidated statements of operations for the years ended December 31, 2009 and 2008 were derived from audited consolidated financial statements that are not presented in this report.

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The financial information presented below may not reflect what our results of operations, financial position and cash flows will be in the future. In addition, the Risk Factors section of Part I, Item 1A of this report includes a discussion of risk factors that could impact our future results of operations.

	Year Ended December 31,
	2012			2011			2010			2009			2008
	(In thousands, except for share and per share data)
Results of Operations Data:
Revenues
Sales	$	1,879,013		$	2,378,260		$	2,017,464		$	1,995,667		$	1,630,873
Other revenues	43,659			24,246			17,647			49,616			23,749
Total revenues	1,922,672			2,402,506			2,035,111			2,045,283			1,654,622
Costs and expenses
Operating costs and expenses	1,779,921			2,213,124			1,900,704			1,893,419			1,607,746
Depreciation, depletion and   amortization	185,001			186,348			188,074			205,339			125,356
Asset retirement obligation expense	354,590			105,232			112,697			35,116			19,260
Sales contract accretion	(11,628		)	(55,020		)	(121,475		)	(298,572		)	(279,402		)
Impairment and restructuring charge	61,278			13,657			15,174			20,157			—
Selling and administrative expenses	49,040			52,907			50,248			48,732			38,607
Other operating (income) expense:
Net gain on disposal or exchange of   assets(1)	(3,121		)	(35,557		)	(48,226		)	(7,215		)	(7,004		)
Loss (income) from equity affiliates(2)	(85		)	(4,709		)	(9,476		)	(398		)	915
Operating profit (loss)	(492,324		)	(73,476		)	(52,609		)	148,705			149,144
Interest expense and other	60,069			65,533			57,419			38,108			23,648
DIP financing fees	42,540			—			—			—			—
Interest income	(189		)	(246		)	(12,831		)	(16,646		)	(17,232		)
Income (loss) before reorganization items   and income taxes	(594,744		)	(138,763		)	(97,197		)	127,243			142,728
Reorganization items, net	135,864			—			—			—			—
Income (loss) before income taxes	(730,608		)	(138,763		)	(97,197		)	127,243			142,728
Income tax provision (benefit)	(14		)	372			492			—			—
Net income (loss)	$	(730,594	)	$	(139,135	)	$	(97,689	)	$	127,243		$	142,728
Earnings (loss) per share, basic	$	(7.90	)	$	(1.52	)	$	(1.07	)	$	1.50		$	2.23
Earnings (loss) per share, diluted	$	(7.90	)	$	(1.52	)	$	(1.07	)	$	1.49		$	2.21
Weighted average shares outstanding -   basic	92,486,920			91,321,931			90,907,264			84,660,998			64,080,998
Weighted average shares outstanding -   diluted	92,486,920			91,321,931			90,907,264			85,424,502			64,625,911
Balance Sheet Data (at period end):
Total assets	$	3,838,807		$	3,844,763		$	3,808,978		$	3,618,163		$	3,622,320
Total liabilities	4,072,036			3,251,921			3,015,560			2,682,669			2,782,139
Total long-term debt, including current   maturities(3)	835,675			442,246			454,858			205,993			204,293
Total stockholders’ equity (deficit)	(233,229		)	592,842			793,418			935,494			840,181

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	Year Ended December 31,
	2012			2011			2010			2009			2008
	(In thousands, except for share and per share data)
Other Data:
Tons sold (in millions and unaudited)	24.9			31.1			30.9			32.8			28.5
Net cash provided by (used in):
Operating activities	$	(28,164	)	$	112,989		$	35,253		$	39,611		$	63,426
Investing activities	(162,463		)	(81,175		)	(108,875		)	(77,593		)	(138,665		)
Financing activities	330,394			(30,719		)	239,591			62,208			72,128
Adjusted EBITDA(4) (unaudited)	96,917			176,741			141,861			110,745			44,238
Past mining obligation payments(5) (unaudited)	131,580			126,614			128,712			129,060			101,746
Additions to property, plant,   equipment and mine development	139,139			162,965			121,931			78,263			121,388
Acquisitions, net	3,030			—			—			—			9,566

⁽¹⁾  Net gain on disposal or exchange of assets included gains of $35.6 million in 2011 from three coal reserve exchange transactions and $44.6 million in 2010 from five coal reserve exchange transactions.

⁽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. These investments scaled back production in recent years in response to market conditions.

⁽³⁾  The filing of the Chapter 11 Petitions constituted an event of default under our pre-petition debt obligations, and those debt obligations became automatically and immediately due and payable. As of December 31, 2012, secured debt of $375.4 million, consisting primarily of DIP Financing, is classified as a current liability in the accompanying consolidated balance sheet. At December 31, 2012, total debt includes unsecured debt of $458.5 million that is recorded in “Liabilities subject to compromise” in the accompanying consolidated balance sheet.

⁽⁴⁾  Adjusted EBITDA as calculated below is defined as net income (loss) before deducting interest income and expense; income taxes; depreciation, depletion and amortization; asset retirement obligation expense; sales contract accretion; impairment and restructuring charge; DIP financing fees; and reorganization items. Net sales contract accretion represents contract accretion excluding back-to-back coal purchase and sales contracts. The contract accretion on the back-to-back coal purchase and sales contracts reflects the accretion related to certain coal purchase and sales contracts existing prior to July 23, 2008, whereby Magnum purchased coal from third parties to fulfill tonnage commitments on sales contracts. Adjusted EBITDA is used by management as a measure of our segments’ operating performance. The term Adjusted EBITDA does not purport to be an alternative to operating income, net income or cash flows from operating activities as determined in accordance with generally accepted accounting principles as a measure of profitability or liquidity. We believe that in our industry such information is a relevant measurement of a company’s operating financial performance. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.

⁽⁵⁾  Past mining obligation payments represents cash payments relating to our postretirement benefit obligations, workers’ compensation obligations, and multi-employer retiree healthcare and pension plans.

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Adjusted EBITDA is calculated as follows (unaudited):

	Year Ended December 31,
	2012			2011			2010			2009			2008
	(In thousands)
Net income (loss)	$	(730,594	)	$	(139,135	)	$	(97,689	)	$	127,243		$	142,728
Depreciation, depletion and   amortization	185,001			186,348			188,074			205,339			125,356
Asset retirement obligation expense	354,590			105,232			112,697			35,116			19,260
Sales contract accretion, net(1)	(11,628		)	(55,020		)	(121,475		)	(298,572		)	(249,522		)
Impairment and restructuring charge	61,278			13,657			15,174			20,157			—
Interest expense and other	60,069			65,533			57,419			38,108			23,648
DIP financing fees(2)	42,540			—			—			—			—
Interest income	(189		)	(246		)	(12,831		)	(16,646		)	(17,232		)
Reorganization items, net(3)	135,864			—			—			—			—
Income tax provision (benefit)	(14		)	372			492			—			—
Adjusted EBITDA	$	96,917		$	176,741		$	141,861		$	110,745		$	44,238

⁽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 was accreted over the life of the contracts as the coal shipped.

⁽²⁾  DIP financing fees were incurred and paid during the second half of 2012 in connection with entering into the DIP Financing.

⁽³⁾  Reorganization items, net are expenses directly related to the process of reorganizing under Chapter 11. These items include losses from adjusting debt from carrying amount to amount of allowed claims, provision for rejected executory contracts and leases and professional fees, offset by gains on accounts payable settlements.

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

Overview

In recent years, the demand for coal has decreased, in large part because alternative sources of energy have become increasingly attractive to electricity generators due to declining natural gas prices and more burdensome environmental and other governmental regulations for the use of coal. At the same time, our liabilities have been increasing as we face sharply rising costs to comply with such regulations, the costs associated with our labor-related legacy liabilities, and the increasing burden of selenium water treatment.

Over the last several years, coal’s share of the U.S. energy market and prices for thermal coal have both markedly declined. Vast resources of natural gas have been unlocked through the new discovery of shale deposits and technological advancements in drilling, causing the price of natural gas in the U.S. to fall. Moreover, the mild winter in 2012 resulted in lower coal burn for electricity generation. These factors, in turn, caused coal inventories at U.S. electricity producers to expand. As a result, the coal industry as a whole has been forced to reduce production, idle mines and lay off workers.

Additionally, the demand for metallurgical coal is dependent on the strength of the global economy, and in particular on steel production in countries such as China and India, as well as Europe, Brazil and the U.S. In response to the recent global economic downturn, the demand for steel declined and, as a result, the demand and price for metallurgical coal also declined.

This declining demand has had a material impact on our business. Because we sell substantial quantities of coal products to domestic and international electricity generators and steel producers, our business and results of operations are linked closely to global demand for coal-fueled electricity and steel production. During the first half of this year, we were approached by certain customers seeking to cancel or delay shipments of coal contracted for delivery under their coal supply agreements. In addition, two of our customers, Bridgehouse Commodities Trading Limited (Bridgehouse) and Keystone Industries LLC (Keystone), defaulted on their contractual obligations to purchase coal from us. On April

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3, 2012 and June 1, 2012, we filed actions for damages against Bridgehouse and Keystone, respectively, resulting from these breached contracts.

In light of the decreased demand for both thermal and metallurgical coal, it has become uneconomical to operate certain of our mining complexes, and we have taken steps to reduce coal production to match expected sales volumes.

On July 9, 2012 (the Petition Date), Patriot Coal Corporation, as a stand-alone entity, and substantially all of its wholly-owned subsidiaries (the Filing Subsidiaries and, together with Patriot, the Debtors) filed voluntary petitions for reorganization (the Chapter 11 Petitions) under Chapter 11 of Title 11 of the U.S. Code (the Bankruptcy Code) in the U.S. Bankruptcy Court for the Southern District of New York. On November 27, 2012, the U.S. Bankruptcy Court for the Southern District of New York issued a ruling transferring the bankruptcy cases to the U.S. Bankruptcy Court for the Eastern District of Missouri. On December 19, 2012, the U.S. Bankruptcy Court for the Southern District of New York entered an order formally transferring the bankruptcy cases to the U.S. Bankruptcy Court for the Eastern District of Missouri (the U.S. Bankruptcy Court for the Eastern District of Missouri and/or the U.S. Bankruptcy Court for the Southern District of New York, as applicable, the Bankruptcy Court). The Debtors’ Chapter 11 cases are being jointly administered under the caption In re: Patriot Coal Corporation, et al. (Case No. 12-51502) (the Bankruptcy Case). Our joint ventures and certain of our other subsidiaries (collectively, the Non-Debtor Subsidiaries) were not included in the Chapter 11 filing. See Part I, Item 1. Business - Bankruptcy Proceedings.

We are a producer of coal in the eastern U.S., with operations and coal reserves in the Appalachia and the Illinois Basin coal regions. Our principal business is the mining, preparation and sale of thermal 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, 2012, our operations consisted of eleven active mining complexes, which include company-operated mines, contractor-operated mines and coal preparation facilities. The Appalachia and Illinois Basin segments consist of our operations in West Virginia and Kentucky, respectively.

We ship coal to electricity generators, industrial users, steel mills and independent coke producers, as well as brokers that ultimately sell the coal to these same types of customers. In 2012, we sold 24.9 million tons of coal, of which 75% was sold to domestic and global electricity generators and 25% was sold to domestic and global steel and coke producers. In 2011, we sold 31.1 million tons of coal, of which 76% was sold to domestic electricity generators and 24% was sold to domestic and global steel producers. Export sales were 45% and 29% of our total volume in 2012 and 2011, 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 greater than one year. Approximately 65% and 78% of our sales were under such contracts during 2012 and 2011, respectively.

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; depreciation, depletion and amortization; asset retirement obligation expense; sales contract accretion; impairment and restructuring charge; DIP financing fees; and reorganization items.

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.

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Year ended December 31, 2012 compared to year ended December 31, 2011

Summary

Our Segment Adjusted EBITDA for the year ended December 31, 2012 decreased compared to the prior year primarily due to a decrease in sales volumes resulting from lower demand driven by low natural gas prices, mild weather and weakened international and domestic economies.

In response to the lower demand, we decreased our production volume by 4.5 million tons from 2011 to 2012. These production decreases included closing our Big Mountain mining complex and reducing production of metallurgical coal at our Rocklick and Wells mining complexes in the first quarter of 2012. In the first half of 2012, we closed certain mines at our Kanawha Eagle mining complex due to reaching the end of the reserve life as well as decreased market demand. In addition, we also idled the Freedom mine at our Bluegrass mining complex and a mine at our Corridor G mining complex in the second quarter of 2012. In the second half of 2012, we reduced metallurgical coal production at our Rocklick, Wells and Kanawha Eagle mining complexes in response to further weakened demand. In the fourth quarter of 2012, the Patriot mine and preparation plant at the Bluegrass mining complex were closed.

In 2012, we recorded a net charge of $258.3 million to asset retirement obligation expense for our selenium water treatment obligations, primarily to reflect a modification in the technology used in our selenium water treatment compliance plan. Also in 2012, we recorded charges totaling $24.0 million to asset retirement obligation expense and $60.7 million to impairment and restructuring charge in relation to the early closure of certain mines and other changes to mining plans at certain locations.

Segment Results of Operations

	Year Ended December 31,					Increase (Decrease)
	2012		2011			Tons/$			%
	(Dollars and tons in thousands, except per ton amounts)
Tons Sold
Appalachia Mining Operations	18,514		23,861			(5,347		)	(22.4	)%
Illinois Basin Mining Operations	6,385		7,265			(880		)	(12.1	)%
Total Tons Sold	24,899		31,126			(6,227		)	(20.0	)%
Average Sales Price per Ton Sold
Appalachia Mining Operations	$	84.29	$	86.61		$	(2.32	)	(2.7	)%
Illinois Basin Mining Operations	49.88		42.89			6.99			16.3	%
Revenue
Appalachia Mining Operations	$	1,560,558	$	2,066,639		$	(506,081	)	(24.5	)%
Illinois Basin Mining Operations	318,455		311,621			6,834			2.2	%
Appalachia Other	43,659		24,246			19,413			80.1	%
Total Revenues	$	1,922,672	$	2,402,506		$	(479,834	)	(20.0	)%
Segment Operating Costs and Expenses(1)
Appalachia Mining Operations and Other	$	1,315,238	$	1,704,545		$	(389,307	)	(22.8	)%
Illinois Basin Mining Operations	277,671		323,761			(46,090		)	(14.2	)%
Total Segment Operating Costs and Expenses	$	1,592,909	$	2,028,306		$	(435,397	)	(21.5	)%
Segment Adjusted EBITDA
Appalachia Mining Operations and Other	$	288,979	$	386,340		$	(97,361	)	(25.2	)%
Illinois Basin Mining Operations	40,784		(12,140		)	52,924			435.9	%
Total Segment Adjusted EBITDA	$	329,763	$	374,200		$	(44,437	)	(11.9	)%

⁽¹⁾  Segment Operating Costs and Expenses represent consolidated operating costs and expenses of $1,779.9 million and $2,213.1 million less income from equity affiliates of $0.1 million and $4.7 million and past mining obligation expense of $186.9 million and $180.1 million for the years ended December 31, 2012 and 2011, respectively, as described below.

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Tons Sold and Revenues

Revenues in the Appalachia segment were lower for the year ended December 31, 2012 compared to the prior year primarily due to lower sales volumes resulting from reduced demand and to lower average sales prices. In response to the weaker markets, we closed our Big Mountain mining complex in February 2012, reduced production at certain metallurgical coal operations, and lowered brokerage coal volume. These sales volume decreases were partially offset by sales volume increases at our Panther and Paint Creek mining complexes due to additional production units and favorable mining conditions. Average sales prices decreased for the year ended December 31, 2012 primarily due to lower prices for our metallurgical products.

Revenues in the Illinois Basin segment were higher for the year ended December 31, 2012, as compared to 2011, due to higher average sales prices, partially offset by lower sales volumes. The higher average sales prices were the result of the expiration of a below market coal supply contract in December 2011. The lower sales volumes were due to weaker demand. In reaction to the weaker demand, Patriot idled the Freedom mine in June 2012 and closed the Patriot mine and preparation plant in December 2012, all of which were at our Bluegrass mining complex.

Appalachia Other revenue was higher for the year ended December 31, 2012 primarily due to customer contract settlements. During the first half of 2012, certain customers requested to cancel or delay shipment of coal contracted for 2012 deliveries. In certain situations, we agreed to release the customers from their commitments in exchange for cash settlements. For the year ended December 31, 2012, we recognized revenue of $24.6 million related to these cash settlements. Additionally, we received $8.3 million related to the settlement of a customer contract dispute concerning coal deliveries in prior years that was settled through mediation in the first quarter of 2012. For the year ended December 31, 2011, we recognized income of $8.9 million as underlying tons were shipped from a coal purchase option sold in a prior year.

Segment Operating Costs and Expenses

Segment operating costs and expenses for Appalachia decreased for the year ended December 31, 2012, as compared to 2011, primarily due to the lower sales volume in 2012. The decrease reflects the closure of our Big Mountain thermal coal mining complex in February 2012 ($123.9 million), reduced production at certain metallurgical mines during 2012 ($139.1 million), lower brokerage coal volumes ($73.4 million), and other mine closures or idlings ($41.8 million). Additionally, we experienced lower costs at our Kanawha Eagle mining complex due to the closure of certain mines that reached the end of their reserve lives as well as decreased sales volumes due to weaker market demand ($37.1 million). These decreases in costs were partially offset by increased costs at our Paint Creek mining complex ($23.1 million) due to additional production units and increased sales volume.

Segment operating costs and expenses for the Illinois Basin decreased for the year ended December 31, 2012, as compared to the prior year, primarily due to lower sales volumes and idling the Freedom mine at our Bluegrass mining complex in the first half of 2012, which was driven by lower demand and weaker market conditions ($40.1 million).

Segment Adjusted EBITDA

Our Segment Adjusted EBITDA for Appalachia was lower for the year ended December 31, 2012 compared to the prior year primarily due to decreased sales volumes resulting from reduced demand and also due to lower sales prices.

Segment Adjusted EBITDA for the Illinois Basin increased for the year ended December 31, 2012 from the prior year primarily due to higher revenues as a result of increased sales prices, as well as decreased operating costs due to idling the Freedom mine at our Bluegrass mining complex in June 2012.

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Net Loss

	Year Ended December 31,						Favorable/ (Unfavorable)
	2012			2011			$			%
	(Dollars in thousands)
Segment Adjusted EBITDA	$	329,763		$	374,200		$	(44,437	)	(11.9	)%
Corporate and Other:
Past mining obligation expense	(186,927		)	(180,109		)	(6,818		)	(3.8	)%
Net gain on disposal or exchange of assets	3,121			35,557			(32,436		)	(91.2	)%
Selling and administrative expenses	(49,040		)	(52,907		)	3,867			7.3	%
Total Corporate and Other	(232,846		)	(197,459		)	(35,387		)	(17.9	)%
Depreciation, depletion and amortization	(185,001		)	(186,348		)	1,347			0.7	%
Asset retirement obligation expense	(354,590		)	(105,232		)	(249,358		)	(237.0	)%
Sales contract accretion	11,628			55,020			(43,392		)	(78.9	)%
Impairment and restructuring charge	(61,278		)	(13,657		)	(47,621		)	(348.7	)%
Interest expense and other	(60,069		)	(65,533		)	5,464			8.3	%
DIP financing fees	(42,540		)	—			(42,540		)	n/a
Interest income	189			246			(57		)	(23.2	)%
Reorganization items, net	(135,864		)	—			(135,864		)	n/a
Income tax (provision) benefit	14			(372		)	386			103.8	%
Net loss	$	(730,594	)	$	(139,135	)	$	(591,459	)	(425.1	)%

Past Mining Obligation Expense

Past mining obligation expense was higher in 2012 compared to the prior year primarily due to changes in assumptions, primarily the discount rate, related to our actuarially-determined retiree healthcare obligations and higher funding rates for the UMWA pension fund, that were effective January 1, 2012. These increases were partially offset by lower UMWA funding related to mine closures and production curtailment as well as lower costs related to suspended mines and subsidence claims.

Net Gain on Disposal or Exchange of Assets

Net gain on disposal or exchange of assets was lower for the year ended December 31, 2012 compared to the prior year due to the timing and volume of transactions in a depressed market. In the first quarter of 2012, net gain on disposal or exchange of assets included the sale of certain non-strategic oil and gas rights. We recognized a gain of $1.5 million on this transaction. 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.

Selling and Administrative Expenses

Selling and administrative expenses decreased for the year ended December 31, 2012 as compared to the prior year due to significant forfeitures of stock-based compensation awards, offset by increased pre-petition legal fees for the reorganization and severance costs for executive management changes. In the second quarter of 2012, the employment of our former Chief Executive Officer, Richard M. Whiting, was terminated and resulted in a credit of $6.3 million for the net impact of the forfeiture and acceleration of his stock-based compensation awards, partially offset by additional compensation expense of $5.1 million for amounts due to him for severance.

Asset Retirement Obligation Expense

Asset retirement obligation expense increased for the year ended December 31, 2012 due to adjustments to our selenium water treatment obligations and related accretion as well as the early closure of several mines and mining complexes. In the second quarter of 2012, we recorded a $307.4 million charge to recognize a modification in the technology used in our selenium water treatment compliance plan at a majority of the outfalls. In the fourth quarter of

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2012, we reduced our selenium water treatment liability by $49.1 million primarily related to certain optimizations made to the operational design of the IFSeR technology as well as the impact of compliance deadline delays agreed to by Patriot and various environmental groups in a modified consent decree. For the year ended December 31, 2011, we recorded a charge totaling $48.2 million for the installation and operating costs of a selenium water treatment system for our Hobet Surface Mine No. 22 outfall as required by a U.S. District Court order as well as the write-off of certain coal reserves and penalties incurred in conjunction with the January 2012 comprehensive consent decree. See Liquidity and Capital Resources - Future Cash Flows - General Selenium Matters for a more detailed description of the adjustments made in relation to selenium water treatment. Additionally, asset retirement obligation expense increased by $24.0 million in 2012 due to earlier than expected mine closures and changes to mine plans, such as the Big Mountain and Bluegrass mining complex closures and both closures and plan changes at our Kanawha Eagle mining complex.

Sales Contract Accretion

Sales contract accretion decreased for the year ended December 31, 2012 as compared to the prior year due to the amendment of one of the below-market coal supply agreements in the first quarter of 2012 and the expiration of all remaining contracts assumed in the Magnum acquisition.

Impairment and Restructuring Charge

Impairment and restructuring charge for the year ended December 31, 2012 increased as compared to the prior year. In the third quarter of 2012, we recorded a charge of $18.4 million for the write-off of coal reserves related to our Bluegrass mining complex located in the Illinois Basin segment. This impairment resulted from the termination of leases providing rights to certain coal reserves through the contract rejection process and related negotiations. Additionally, in the second quarter of 2012, we recorded a charge of $8.2 million for the early closure of the Freedom mine at our Bluegrass mining complex and changes to mining plans for a mine at the Kanawha Eagle mining complex. In the first quarter of 2012, we recorded a $32.8 million charge due to the early closure of our Big Mountain mining complex. In 2011, we recorded an impairment charge of $13.6 million primarily related to mine closure decisions made in the fourth quarter of 2011, in response to weakening demand. These charges mainly consisted of the write-down of fixed assets related to infrastructure, mine development and certain equipment.

Interest Expense and Other

Interest expense and other decreased for the year ended December 31, 2012 primarily due to the $5.9 million loss on early repayment of notes receivable recorded in the first quarter of 2011. The outstanding notes receivable related to the 2006 and 2007 sales of coal reserves and surface land were repaid in full for $115.7 million in the first quarter of 2011 prior to the scheduled maturity date.

DIP Financing Fees

Debt issuance costs of $42.5 million were incurred and paid in connection with the DIP financing. These amounts were expensed and separately disclosed in the consolidated statements of operations for the year ended December 31, 2012.

Reorganization Items, net

ASC 852 requires separate disclosure of reorganization items directly related to the process of reorganizing the Company under Chapter 11. Our reorganization items for the year ended December 31, 2012 consist of the following:

	Year Ended
	December 31, 2012
	(Dollars in thousands)
Provision for rejected executory contracts and leases	$	82,213
Professional fees	35,506
Losses from adjusting debt from carrying value to amount of allowed claim	27,021
Accounts payable settlement gains	(8,876		)
Reorganization items, net	$	135,864

Since the Petition Date, we have received approval from the Bankruptcy Court to reject a number of leases and other executory contracts of various types. We are reviewing all of our executory contracts and unexpired leases to determine

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which additional contracts and leases we will reject. We expect that additional liabilities subject to compromise will arise due to rejection of executory contracts, including leases, and from the determination of the Bankruptcy Court (or agreement by parties in interest) of allowed claims for contingencies and other disputed amounts. We also expect that the assumption of additional executory contracts and unexpired leases will convert certain of the liabilities currently shown as liabilities subject to compromise to liabilities not subject to compromise. Due to the uncertain nature of many of the potential claims, we cannot project the magnitude of such claims with certainty.

Professional fees directly related to the reorganization include fees associated with advisors to us, the Creditors’ Committee and certain secured creditors.

Income Tax Benefit

For the year ended December 31, 2012, we recorded an immaterial income tax benefit, as compared to the year ended December 31, 2011, which had an income tax provision of $0.4 million related to certain state taxes. In 2012 and 2011, 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 2012 was the treatment of environmental related accruals recorded during 2012, with such amounts being deducted in the computation of book income but only deducted to the extent of the actual payments from the computation of taxable income. The primary difference between book and taxable income for 2011 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, 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 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 included a $38.3 million charge 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.

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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.

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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	(105,232		)	(112,697		)	7,465			6.6	%
Sales contract accretion, net	55,020			121,475			(66,455		)	(54.7	)%
Impairment and restructuring 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	$	(139,135	)	$	(97,689	)	$	(41,446	)	(42.4	)%

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.

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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 decreased for the year ended December 31, 2011. During the year ended December 31, 2011, asset retirement obligation expense included a $38.3 million charge to adjust 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 $69.5 million was recorded due to adjusting our estimated costs of 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.

Impairment and Restructuring Charge

Impairment and restructuring 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.

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.

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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.

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 U.S. 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.

Going Concern

The accompanying consolidated financial statements and related notes have been prepared assuming we will continue as a going concern, although the Bankruptcy Case and weak industry conditions raise substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded assets or to the amounts and classification of liabilities or any other adjustments that might be necessary should we be unable to continue as a going concern. Our ability to continue as a going concern is dependent upon, among other things, market conditions and our ability to improve profitability, to meet the financial covenants of the DIP Facilities or obtain appropriate waivers, to obtain financing to replace the DIP Facilities upon emergence and to restructure our obligations in a manner that allows us to obtain confirmation of a plan of reorganization by the Bankruptcy Court. In order to improve profitability, we are taking actions to further reduce operating expenses and align our production to meet market demand. As a result of the Bankruptcy Case, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession pursuant to the Bankruptcy Code, we may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Facilities), for amounts other than those reflected in the accompanying consolidated financial statements. Further, any plan of reorganization could materially change the amounts and classifications of assets and liabilities reported in the historical consolidated financial statements.

Bankruptcy Accounting

For periods subsequent to filing the Chapter 11 Petitions, we have applied the Financial Accounting Standards Board Accounting Standards Codification (ASC) 852, “Reorganizations” (ASC 852), in preparing the consolidated financial statements. ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings have been recorded in “Reorganization items, net” on the consolidated statements of operations. In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on the consolidated balance sheet at December 31, 2012 in “Liabilities subject to compromise.” These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. These liabilities represent the amounts expected to be allowed on known or potential claims to be resolved through the Chapter 11 process, and remain subject to future adjustments arising from negotiated settlements, actions of the Bankruptcy Court, rejection of executory contracts and unexpired leases, the determination as to the value of collateral securing the claims, proofs of claim, or other events. Liabilities subject to compromise also include certain items that may be assumed under the plan of reorganization, and as such, may be subsequently reclassified to liabilities not subject to compromise.

The Bankruptcy Court has approved payment of certain pre-petition obligations, including employee wages, salaries and benefits, and the payment of vendors and other providers in the ordinary course for goods and services received after

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the filing of the Chapter 11 Petitions and other business related payments necessary to maintain the operations of the Company’s business. Obligations associated with these matters are not classified as liabilities subject to compromise.

With the approval of the Bankruptcy Court, the Company has rejected certain pre-petition executory contracts and unexpired leases with respect to the Company’s operations and may reject additional ones in the future. Damages resulting from rejection of executory contracts and unexpired leases are generally treated as general unsecured claims and are classified as liabilities subject to compromise. Holders of pre-petition claims were required to file proofs of claims by the “bar date.” Differences between liability amounts estimated by the Company and claims filed by creditors are being investigated and, if necessary, the Bankruptcy Court will make a final determination of the allowable claim. The determination of how liabilities will ultimately be treated cannot be made until the Bankruptcy Court approves a plan of reorganization. Accordingly, the ultimate amount or treatment of such liabilities is not determinable at this time. See Note 2 to our consolidated financial statements.

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 17 and 18 to our consolidated financial statements. Expense for the year ended December 31, 2012 for these liabilities totaled $169.7 million, while payments were $101.8 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-related 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	$	10,636	$	(8,811	)
Effect on (gain)/loss amortization component	37,465		(31,184		)
Effect on total postretirement benefit obligation	215,770		(179,134		)

Discount rate:

	+0.5%			-0.5%
	(Dollars in thousands)
Effect on total service and interest cost components	$	1,794		$	(2,363	)
Effect on (gain)/loss amortization component	(10,467		)	10,667
Effect on total postretirement benefit obligation	(98,842		)	105,296

Asset Retirement Obligations

Our asset retirement obligations include both reclamation and selenium water treatment 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

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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 our mining permits. These obligations are recognized at fair value and accreted into earnings to the projected spending date. The net liability related to selenium water treatment reflects the estimated future costs to install and operate various treatment systems or facilities at affected outfalls. These estimated costs are based on our current treatment plans, but they are subject to uncertainty due to the fact there is no proven technology to decrease existing selenium discharges in excess of allowable limits to meet current standards. The technologies we have selected have proven effective in test cases, but if they cannot be utilized in all situations, if additional technology becomes available, or if standards change in the future, our actual cash costs could be materially different than currently estimated.

Asset retirement obligation expense for the year ended December 31, 2012 was $354.6 million, and payments totaled $90.4 million. See detailed information regarding our asset retirement obligations in Notes 16 and 22 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, 2012 and 2011, 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, 2012 and 2011, 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 12 to our consolidated financial statements.

Revenue Recognition

In general, we recognize revenues when they are realizable and earned. We generated substantially all of our revenues in 2012 from the sale of coal to our customers. Revenues from coal sales are realized and earned when title and 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 greater than one year. Approximately 65% and 78% of our sales were under such contracts during 2012 and 2011, respectively. 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.

Stock-Based Compensation

We have an equity incentive plan for certain eligible employees and eligible non-employee directors that allows for the issuance of stock-based compensation in the form of restricted stock, incentive stock options, nonqualified stock

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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 stock-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 stock-based awards expected to be forfeited prior to vesting. If actual forfeitures differ significantly from these estimates, stock-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.

Liquidity and Capital Resources

At December 31, 2012, we had cash and cash equivalents of $333.9 million compared to $194.2 million at December 31, 2011. The improvement in the liquidity primarily resulted from the borrowings under the DIP Facilities and the stay of payment of liabilities subject to compromise resulting from the bankruptcy filings. Historically, our primary sources of cash included 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.

On July 9, 2012, Patriot and substantially all of our wholly-owned subsidiaries filed Chapter 11 Petitions in the Bankruptcy Court. Following the filing of our Chapter 11 Petitions, our most significant sources of liquidity was funds generated by borrowings under the DIP Facilities and cash generated by operating activities.

Net cash used in operating activities was $28.2 million for the year ended December 31, 2012 compared to cash provided by operating activities of $113.0 million for the year ended December 31, 2011, or a decrease of $141.2 million. The increase in cash used in operating activities primarily relates to lower earnings from operations due to weakened demand, higher spending for asset retirement obligations, including selenium water treatment and mine closure obligations, of $54.5 million, and an increase of $35.0 million in cash collateralization deposits due to our DIP Facilities letter of credit requirements. This was partially offset by a change in working capital, exclusive of pre-petition claims, of $23.1 million; the weakened demand in late 2011 and 2012 resulted in a significant reduction in accounts receivable at December 31, 2012 as compared to December 31, 2011, partially offset by a favorable impact on accounts payable.

Net cash used in investing activities was $162.5 million for the year ended December 31, 2012, compared to $81.2 million used in the prior year. The $81.3 million increase in cash used in investing activities reflects the early repayment of $115.7 million of our outstanding notes receivable in February 2011 and a decrease in proceeds from disposal of assets of $3.2 million. Additionally, in 2012, we acquired several companies that employ the workforce or partial workforce at two Appalachia mining complexes for $3.0 million. This increase was partially offset by a decrease in capital expenditures of $23.8 million in 2012 compared to 2011 and a $14.8 million cash payment from a litigation settlement and asset acquisition during the year ended December 31, 2011.

Net cash provided by financing activities was $330.4 million for the year ended December 31, 2012 compared to cash used in financing activities of $30.7 million for the year ended December 31, 2011. The increase in cash flows provided by financing activities is primarily due to the First Out Term Loan Facility proceeds of $375.0 million. Also, our long term debt payments were lower by $29.6 million in 2012 as compared to 2011, offset by the DIP Facilities debt issuance costs of $42.5 million.

There can be no assurance that amounts available under the DIP Facilities plus cash generated from operations will be sufficient to meet our reorganization or ongoing cash needs or that we will remain in compliance with all the covenants under the DIP Facilities. If we cannot meet our liquidity needs using amounts available under the DIP Facilities plus cash generated from operations, or if our access to amounts available under the DIP Facilities is restricted or terminated for any of the reasons set forth therein, we may have to take other actions such as seeking additional financing to the extent available or by reducing or delaying capital expenditures. We could also be forced to consider other alternatives to maximize potential recovery for our various creditor constituencies, including a possible sale of the Company or certain

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of our material assets pursuant to Section 363 of the Bankruptcy Code, or liquidation under Chapter 7 of the Bankruptcy Code.

The DIP Facilities, as more fully described below, include financial covenants applicable to Patriot and its subsidiaries, including compliance with requirements relating to minimum consolidated EBITDA, as defined by the DIP Facilities, maximum capital expenditures and minimum liquidity. At December 31, 2012, we were in compliance with these financial covenants. Based on continued declines in metallurgical coal demand and prices experienced in the second half of 2012 and the related effect on our current internal financial forecasts, we believe there is a substantial likelihood that we may not comply with the minimum consolidated EBITDA financial covenant beginning in the third quarter of 2013. Our financial forecasts are subject to significant variation due to the volatility in the coal markets, including demand and prices for our products, and uncertainties surrounding our restructuring initiatives, so our compliance with the minimum consolidated EBITDA financial covenant remains subject to market conditions and our ability to improve financial performance. Failure to comply with our financial covenants would be an event of default under the terms of our DIP Facilities. If an event of default occurs, we would need to negotiate an amendment or waiver from the lenders; however, there can be no assurances that we would be able to obtain such an amendment or waiver in the future. If, as a result of such an event of default, the DIP Facilities are terminated or our access to funding thereunder is restricted or terminated, we may not have sufficient cash availability to meet our operating needs or satisfy our obligations as they become due, in which instance we could be required to seek a sale of Patriot or certain of its material assets pursuant to Section 363 of the Bankruptcy Code, or to convert the Bankruptcy Case into a liquidation under Chapter 7 of the Bankruptcy Code.

On May 23, 2012, Standard & Poor’s Ratings Services (Standard & Poor’s) lowered our long-term corporate rating and its rating on the Senior Notes to “CCC” from “B-”. The recovery rating of the Senior Notes by Standard & Poor’s was also lowered, indicating the expectation that creditors will receive negligible (0%-10%) recovery in a payment default scenario. Moody’s Investors Service (Moody’s) lowered our probability of default rating to “D” from “Caa1” and our corporate family rating to “Ca” from “Caa1” following our filing of the Bankruptcy Case. Moody’s also downgraded its rating on the Senior Notes to “C” from “Caa2”. As a result of the Bankruptcy Case, Standard & Poor’s and Moody’s have withdrawn all of their ratings on us. These debt and credit downgrades have an adverse effect on our ability to raise additional financing.

Our liquidity challenges, including these debt and credit downgrades, are public information and despite the liquidity provided by our DIP Facilities, our ability to maintain normal credit terms with our suppliers may become impaired. We may be required to pay cash in advance to certain vendors and may experience restrictions on the availability of trade credit, which would further reduce our liquidity. If liquidity problems persist, our suppliers could refuse to provide key products and services in the future. In addition, due to the public perception of our financial condition and results of operations, in particular with regard to uncertainties surrounding our bankruptcy process and reorganization, some customers could be reluctant to enter into long-term agreements with us.

DIP Financing

In connection with filing the Chapter 11 Petitions, the Debtors filed a motion seeking, among other things, Bankruptcy Court authorization for us to obtain the DIP Facilities, and for the DIP Guarantors to guaranty our obligations in connection with the DIP Facilities, up to an aggregate principal amount of $802.0 million, consisting of (a) First Out Revolving Credit Loan in an amount not to exceed $125.0 million, (b) a First Out Term Loan in the amount of $375.0 million, and (c) a $302.0 roll up of obligations under the Pre-Petition Credit Agreement, dated May 5, 2010, in respect to outstanding letters of credit, inclusive of any obligations as to reimbursement, renewal and extension of the same issued in the aggregate amount of $300.8 million as of the Petition Date (the Second Out Facility).

On July 11, 2012, the Bankruptcy Court entered the Interim DIP Order that, among other things, authorized us to borrow money and obtain letters of credit pursuant to the DIP Facilities and to guaranty such borrowings and our obligations with respect to such letters of credit, up to an aggregate principal or face amount of $677.0 million (plus interest, fees and other expenses and amounts), consisting of borrowings of up to an aggregate principal or face amount of $125.0 million under the First Out Revolving Credit Loan, $250.0 million under the First Out Term Loan, and up to $302.0 million under the Second Out Facility, in accordance with the terms of the Interim DIP Order and the DIP Facilities. On August 3, 2012, the Bankruptcy Court entered the Final DIP Order that, among other things, authorized us to borrow the full amount under the DIP Facilities in accordance with the terms of the Final DIP Order and the DIP Facilities. The Final DIP Order amended certain provisions of the DIP Facilities, including, among other things, the definition of “Applicable Rate” in the First Out DIP Credit Agreement.

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First Out Facility

On July 9, 2012, Patriot and the DIP Guarantors entered into a Superpriority Secured Debtor-in-Possession Revolving and Term Loan Credit Agreement (the First Out DIP Credit Agreement). Our obligations under the First Out DIP Credit Agreements are guaranteed by each DIP Guarantor. On July 11, 2012, the conditions precedent to closing and the initial borrowing were satisfied and the First Out DIP Credit Agreement became effective.

First Out Revolving Credit Loans bear interest at a rate per annum equal to the Eurocurrency Rate (as defined in the First Out DIP Credit Agreement) plus 3.25% or the Base Rate (as defined in the First Out DIP Credit Agreement) plus 2.25%. First Out Term Loans bear interest at a rate per annum equal to the Eurocurrency Rate plus 7.75% or the Base Rate plus 6.75%. As of December 31, 2012, the interest rate on the First Out Term Loans was 9.25%. Upon the occurrence and during the continuance of an event of default under the First Out DIP Credit Agreement, the interest rate increases by 2.00% per annum. In addition, letter of credit fees under the First Out Facility are paid at a rate equal to 3.25% per annum and a commitment fee of 0.75% per annum is required for unutilized commitments.

On July 11, 2012, we received proceeds of $250.0 million under the First Out Term Loan, and on August 6, 2012, we received the remaining proceeds of $125.0 million. We utilized the funds to repay borrowings under the Pre-Petition Credit Agreement of $25.0 million, which was originally borrowed in June 2012, pay DIP Facilities fees of $42.5 million and increase cash for general operating purposes. Letters of credit totaling $53.0 million were issued under the First Out Revolving Credit Loan to replace or backstop pre-petition letters of credit outstanding under the accounts receivable securitization program that were canceled. At December 31, 2012, letters of credit totaling $57.1 million were outstanding under the First Out Facility.

Borrowings under the First Out Facility are to be repaid on the earlier of (i) the Initial Maturity Date, which is October 4, 2013 provided that the Initial Maturity Date can be extended until December 31, 2013 subject to certain specified conditions, (ii) prepayment by Patriot of all outstanding principal and accrued but unpaid interest, (iii) the date of termination of the commitment of each lender and of the obligation of the L/C Issuers (as defined in the First Out DIP Credit Agreement) to make letter of credit extensions pursuant to the First Out DIP Credit Agreement, (iv) the date of the substantial consummation of a reorganization plan that is confirmed pursuant to an order of the Bankruptcy Court and (v) the date of dismissal of the Bankruptcy Case by the Bankruptcy Court. An extension fee of 0.25% of the Revolving Credit Commitments and Term Loans is due if we elect to extend the maturity date of the First Out Facility.

The First Out DIP Credit Agreement provides for representations and warranties by Patriot and the DIP Guarantors that are customary for facilities of this type. The First Out DIP Credit Agreement further provides for affirmative and negative covenants applicable to Patriot and its subsidiaries, including affirmative covenants requiring Patriot to provide financial information, 13-week projections and other information including, upon request, environmental or mining site assessments or audit reports to the administrative agent under the First Out DIP Credit Agreement (the First Out DIP Agent), and negative covenants restricting the ability of Patriot and its subsidiaries to incur additional indebtedness, grant liens, dispose of assets, pay dividends or take certain other actions. The First Out DIP Credit Agreement also provides financial covenants applicable to Patriot and its subsidiaries, including compliance with requirements relating to minimum consolidated EBITDA, as defined by the DIP Facilities, maximum capital expenditures and minimum liquidity.

The First Out DIP Credit Agreement provides for certain customary events of default, including events of default resulting from non-payment of principal, interest or other amounts when due, material breaches of Patriot’s and the DIP Guarantors’ representations and warranties, breaches by Patriot or the DIP Guarantors of their covenants in the First Out DIP Credit Agreement or ancillary loan documents, cross-defaults under other agreements or instruments, the entry of material judgments against Patriot or its subsidiaries, or revocation of the intercreditor and priority of payment provisions contained in the Pledge and Security and Intercreditor Agreement (as defined below). The First Out DIP Credit Agreement also includes customary events of default that may arise in connection with the Chapter 11 Petitions, including dismissal or conversion of the Debtors’ cases.

Second Out Facility and Second Out Guarantee

We entered into an Amended and Restated Superpriority Secured Debtor-in-Possession Credit Agreement dated as of July 11, 2012 (the Second Out DIP Credit Agreement). Our obligations under the Second Out DIP Credit Agreement are guaranteed by the DIP Guarantors pursuant to the Amended and Restated Guarantee (the Second Out Guarantee) dated as of July 11, 2012, made by Patriot and the DIP Guarantors in favor of the administrative agent under the Second Out DIP Credit Agreement (the Second Out DIP Agent). On July 13, 2012, the conditions precedent to closing were satisfied and the Second Out DIP Credit Agreement and the Second Out Guarantee became effective.

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Letter of credit fees under the Second Out Facility are paid at a rate equal to 4.50% per annum. The letter of credit borrowings under the Second Out Facility will bear interest at a rate per annum equal to the Eurocurrency Rate plus 8.00% or the Base Rate plus 7.00% per annum. Upon the occurrence and during the continuance of an event of default under the Second Out DIP Credit Agreement, the interest rate will increase by 2.00% per annum. On July 13, 2012, letters of credit totaling $300.8 million were continued under the Second Out Facility from the Pre-Petition Credit Agreement. At December 31, 2012 , letters of credit totaling $300.7 million were outstanding under the Second Out Facility.

All letter of credit borrowings under the Second Out Facility are to be repaid on the earlier of (i) the Initial Maturity Date provided that the Initial Maturity Date can be extended until December 31, 2013 subject to certain specified conditions, (ii) the date on which the obligation of the letter of credit issuers to permit the extension of the expiry date of any letter of credit is terminated upon direction from the Second Out DIP Agent in the case of an event of default, (iii) the date of the substantial consummation of a reorganization plan that is confirmed pursuant to an order of the Bankruptcy Court and (iv) the date of dismissal of the Bankruptcy Case by the Bankruptcy Court.

The Second Out DIP Credit Agreement provides for representations and warranties by Patriot and the DIP Guarantors, affirmative and negative covenants applicable to Patriot and its subsidiaries and events of default that are substantially similar to the representations, warranties, covenants and events of default under the First Out DIP Credit Agreement.

Pledge, Security and Intercreditor Agreement

On July 11, 2012, Patriot and the DIP Guarantors entered into a Debtor-in-Possession Pledge and Security and Intercreditor Agreement (the Pledge, Security and Intercreditor Agreement) with the First Out DIP Agent and Second Out DIP Agent.  The obligations of Patriot and the DIP Guarantors under the DIP Facilities are secured by a lien covering substantially all of the assets, rights and properties of Patriot and the DIP Guarantors, subject to certain exceptions set forth in the Pledge, Security and Intercreditor Agreement.  The Pledge, Security and Intercreditor Agreement also sets forth the seniority and priority of the respective liens on Patriot’s and the DIP Guarantors’ assets for the benefit of the lenders under the First Out Revolving Credit Loan, the First Out Term Loan and the Second Out Facility.

Default of Pre-Petition Financing

The filing of the Chapter 11 Petitions constituted an event of default under the following debt agreements, each of which provides that, as a result of the event of default, all principal, interest and other amounts due thereunder became immediately due and payable:

• the Pre-Petition Credit Agreement, with respect to outstanding letters of credit in an aggregate principal amount of approximately $300.8 million as of the Petition Date, plus accrued and unpaid interest thereon and borrowings in an aggregate principal amount of $25.0 million as of the Petition Date, plus accrued and unpaid interest thereon;

• the Indenture dated as of May 28, 2008 with respect to an aggregate principal amount of $200.0 million of 3.25% Convertible Senior Notes due 2013 plus accrued and unpaid interest thereon;

• the Indenture dated as of May 5, 2010 with respect to an aggregate principal amount of $250.0 million of 8.25% Senior Notes due 2018 plus accrued and unpaid interest thereon; and

• the $125.0 million accounts receivable securitization program with respect to outstanding letters of credit in an aggregate principal amount of approximately $51.8 million as of the Petition Date, plus accrued and unpaid interest thereon.

The ability of the creditors to seek remedies to enforce their rights under these pre-petition debt agreements is automatically stayed as a result of filing the Chapter 11 Petitions, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Due to the filing of the Chapter 11 Petitions, the Company’s unsecured long-term debt of $458.5 million is included in “Liabilities subject to compromise” at December 31, 2012. Since July 9, 2012, the Company has not recorded interest expense on unsecured debt that is subject to compromise. Contractual interest expense on unsecured debt from July 9, 2012 through December 31, 2012 was $22.6 million.

Pre-Petition Credit Facilities

Prior to filing of the Chapter 11 Petitions, the Company had a $427.5 million credit agreement with a maturity date of December 31, 2013. The credit facility provided for the issuance of letters of credit and direct borrowings. 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.

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Additionally, prior to filing of the Chapter 11 Petitions, the Company had a $125 million accounts receivable securitization program, which provided for the issuance of letters of credit and direct borrowings. Trade accounts receivable were sold, on a revolving basis, to a wholly-owned bankruptcy-remote entity (facilitating entity), which then sold an undivided interest in all of the trade accounts receivable to the creditors as collateral for any borrowings. 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 did not receive sale accounting treatment. As such, the trade accounts receivable balances remained on our financial statements until settled. Any direct borrowings under the program were recorded as secured debt. Available liquidity under the program fluctuated with the balance of our trade accounts receivable. The outstanding trade accounts receivable balance was $171.0 million as of December 31, 2011. This program was terminated on July 11, 2012.

Senior Notes (Unsecured)

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 was being amortized over the term of the notes, resulting in additional interest expense above the contractual coupon amount. For the years ended December 31, 2012 (prior to the Petition Date), 2011 and 2010, interest expense for the senior notes was $11.0 million, $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. We do not expect to make any principal or interest payments on the notes during the pendency of the Bankruptcy Case. 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. Because the notes are unsecured, we reclassified the notes, along with unpaid interest, to liabilities subject to compromise as of the Petition Date and ceased recording interest expense.

Pursuant to their terms, 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. Pursuant to their terms, 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, subject to the provisions of the Bankruptcy Code, to accelerate payments of outstanding debt in certain circumstances.

Private Convertible Senior Notes (Unsecured)

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. 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 was being 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 $8.6 million, $15.8 million and $15.1 million for the years ended December 31, 2012 (prior to the Petition Date), 2011 and 2010, respectively.

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Interest on the notes is payable semi-annually in arrears on May 31 and November 30 of each year. We do not expect to make any principal or interest payments on the notes during the pendency of the Bankruptcy Case. 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. Because the notes are unsecured, we reclassified the notes, along with unpaid interest, to liabilities subject to compromise as of the Petition Date and ceased recording interest expense.

The notes were 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. The conversion rate for the notes was 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 were subject to adjustment for certain dilutive events, such as a future stock split or a distribution of a stock dividend.

Pursuant to the terms of the notes, holders 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. The automatic stay in the Bankruptcy Case prevents such an exercise by the note holders.

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, 2012, the remaining payments totaling $8.5 million are recorded to “Liabilities subject to compromise” on our consolidated balance sheet.

Cash Management

Historically, we concentrated the majority of our cash balances in accounts held by Patriot Coal Corporation, and we deployed our cash throughout the enterprise through a variety of intercompany and transfer pricing arrangements. In addition, we were able to freely transfer funds to, from and among subsidiaries, as needed. Since filing the Chapter 11 Petitions, we have received Bankruptcy Court approval to generally maintain use of our cash management system, and, consequently, have minimized disruption to our operations while transitioning into the reorganization process.

The matters described herein, to the extent that they relate to future events or expectations, may be significantly affected by our Bankruptcy Case. Those proceedings will involve, or may result in, various restrictions on our activities, limitations on financing, the need to obtain Bankruptcy Court approval for various matters and uncertainty as to relationships with vendors, suppliers, customers and others whom we may conduct or seek to conduct business. In addition, there is no assurance that (i) we will be able to maintain our current cash management system, (ii) we will generate sufficient cash to fund our operations during this process, or (iii) that we will be able to access any alternative financing on acceptable terms or at all.

Future Cash Flows

Assumed Contracts

On January 15, 2013, the Company filed a motion for authorization to assume or reject all of our unexpired leases of nonresidential real property, including our coal reserve leases. Substantially all of our assumptions and rejections were approved by the Bankruptcy Court on January 28, 2013. We are working to resolve differences in cure amounts and certain other discreet issues with counterparties that objected to our motion.

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As assumed contracts are approved, we will cure all existing defaults under those leases, typically within a 30-day period. Total cure payments for assumed real property leases discussed above are estimated to be approximately $14 million and are anticipated to be paid within the first half of 2013.

September 1, 2010 U.S. District Court Ruling

On September 1, 2010, the U.S. District Court ordered Apogee Coal Company, LLC (Apogee), one of our subsidiaries, 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. As of December 31, 2012, the construction of the FBR facility is substantially complete and the testing phase of the installation is nearing completion. As of December 31, 2012, we have spent approximately $42.5 million on the Apogee FBR facility. Total expenditures to install the facility are estimated to be approximately $48.0 million.

Additionally, the U.S. District Court ordered Hobet Mining, LLC (Hobet), one of our subsidiaries, to submit a proposed schedule to develop a treatment plan for a Hobet Surface Mine No. 22 outfall and to come into compliance with applicable discharge limits under the permit by May 1, 2013. In 2011, Hobet requested, and it was subsequently approved, to utilize an ABMet selenium treatment technology at this outfall. As of December 31, 2012, we have spent approximately $5.6 million on the Hobet ABMet water treatment facility. Total expenditures to install the facility are estimated to be approximately $25.0 million.

These will be the first facilities 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. FBR technology has proven successful in other industrial applications.

General Selenium Matters

Prior to the second quarter of 2012, the liability to treat selenium discharges at outfalls not addressed in the September 1, 2010 ruling continued to be based on the use of the ZVI technology as there was no other definitive plan to install any technology other than ZVI. During the second quarter of 2012, we modified our selenium water treatment compliance plan from ZVI technology to installing and operating Iron Facilitated Selenium Reduction (IFSeR) technology. Installation and operating costs for the IFSeR technology are materially higher than ZVI technology due in part to the more technologically advanced processing system. IFSeR was developed in response to our need to resolve certain detailed design considerations for ZVI technology. While ZVI water treatment systems decreased selenium discharges, they had not performed consistently in reducing selenium concentrations to compliant levels. IFSeR incorporates various design enhancements including utilizing ZVI media in a different configuration than the original ZVI water treatment technology.

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 performed pilot testing on IFSeR technology in early 2012 and concluded the testing in May 2012. In May 2012, related to the comprehensive consent decree for the February 2011 Litigation, we submitted IFSeR technology to the Special Master for his review and approval. The Special Master certified that IFSeR may be considered as a listed technology for Category 1 outfalls, and, on September 1, 2012, we provisionally selected the IFSeR technology for all of our Category 1 outfalls. To date, IFSeR technology has not been proven to achieve effluent selenium limitations for the water flows at outfalls other than Category 1. There is significant uncertainty as to which technology, if any, could be utilized to achieve compliance at the other four categories, particularly those with higher average water flows. However, IFSeR technology is currently the treatment technology that is best adapted for installation and operation under the various site-specific conditions at our outfalls.

As a result, we recorded an adjustment to increase our selenium water treatment liability by $307.4 million during the second quarter of 2012 to recognize the modification to our compliance plan from installing and operating ZVI technology to installing and operating IFSeR technology. This adjustment is based upon estimates for the installation and operating costs of IFSeR water treatment systems at the Category 1-5 outfalls. In the fourth quarter of 2012, we recorded an adjustment to decrease our selenium water treatment liability by $49.1 million in total, $17.6 million of which related to changes made to the operational design of the IFSeR technology system. We continue to refine the IFSeR treatment systems to obtain the most effective selenium removal in the most cost-effective manner.

In October 2012, we, along with Apogee, Hobet and Catenary, requested extensions to the construction schedule and compliance deadline related to the Hobet Surface Mine No. 22 ABMet project as well as an extension of each of the deadlines related to the comprehensive consent decree for Category 1-5 outfalls. Extensions of these deadlines by 12 to

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18 months would assist in maintaining liquidity during the bankruptcy proceedings and provide additional time to continue current research and testing of effective treatment solutions. In December 2012, the Bankruptcy Court and the U.S. District Court approved an agreement between Patriot and OVEC and other environmental groups to extend the Hobet Surface Mine No. 22 outfall compliance date to August 1, 2014. In addition, a 12-month extension of each of the technology selection and specific compliance dates in the comprehensive consent decree was approved. As a result, in December 2012, Patriot recorded a $31.5 million adjustment to decrease its selenium water treatment liability due to the impact of delaying the specific deadlines and the corresponding cash spending.

If IFSeR 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 may be required to install alternative treatment solutions. Alternative technology solutions that we may ultimately select are still in the early phases of development and their related costs cannot be reasonably estimated at this time. The cost of other water treatment solutions could be materially different than the costs reflected in our liability. Furthermore, costs associated with potential modifications to IFSeR or the scale of our current IFSeR systems could also cause the costs to be materially different 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. Potential installations of selenium treatment alternatives are further complicated by the variable geological, topographical and water flow 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 for outfalls covered by the Hobet WVDEP Action and the February 2011 Litigation. 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, modifications pursuant 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 to which we are subject.

Multi-Employer Plan Funding Improvement Plan

The Company participates in a multi-employer pension plan, the UMWA 1974 Pension Plan (the 1974 Plan), that is considered to be in “Seriously Endangered Status” for the plan year beginning July 1, 2011 (the 2011 Plan Year). That status is the result of the 1974 Plan funded percentage being less than 80% and because the 1974 Plan is projected to have an accumulated deficiency within six plan years after the 2011 Plan Year. As a result, a funding improvement plan was adopted by the 1974 Plan as of May 25, 2012, which would require increased contributions to the 1974 Plan after a UMWA collective bargaining agreement is negotiated in 2016.

For the year ended December 31, 2012, the Company made contributions to the 1974 Plan and recognized expense of $20.8 million which were based upon an hourly contribution rate of $5.50. Under the funding improvement plan, the hourly contribution rate would increase in stages from a minimum of $12.50 in 2017 to a maximum potential rate of $26.50 as early as 2022.

In relation to the bankruptcy process and pursuant to Section 1113 of the Bankruptcy Code, Patriot is seeking to renegotiate the terms of collective bargaining agreements between certain Patriot subsidiaries and the UMWA, which may affect our future participation in the 1974 Plan.

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Contractual Obligations

In addition to our debt commitments at December 31, 2012, we had other commitments and contractual obligations that, notwithstanding the effect of the Chapter 11 Petitions, would require us to make specified payments in the future. The filing of the Chapter 11 Petitions constituted an event of default under our debt obligations, and those debt obligations became automatically and immediately due and payable, subject to an automatic stay of any action to collect, assert, or recover a claim against us and the application of applicable bankruptcy law. The following table summarizes the total amounts due as of December 31, 2012 under all debt agreements, commitments and other contractual obligations. We are in the process of evaluating our executory contracts in order to determine which contracts will be assumed in our bankruptcy proceedings.

	Payments Due by Year as of December 31, 2012
	Within 1 Year		2-3 Years		4-5 Years		After 5 Years
	(Dollars in thousands)
Long-term debt obligations (principal and cash interest) (1)	$	834,117	$	1,234	$	872	$	—
Operating lease obligations (2)	43,056		54,631		11,493		—
Coal reserve lease and royalty obligations	28,705		41,019		29,248		79,007
Other long-term liabilities (3)	160,408		368,046		413,639		1,681,325
Total contractual cash obligations	$	1,066,286	$	464,930	$	455,252	$	1,760,332

⁽¹⁾  Projected contractual interest payments are excluded. Based on interest rates in effect and long-term debt balances outstanding as of December 31, 2012, hypothetical projected contractual interest payments would be approximately $62.0 million in 2013 and for each future year. However, due to the bankruptcy proceedings, we do not expect to pay interest on our unsecured senior notes and unsecured private convertible senior notes. This disclosure does not attempt to predict future cash flows or changes in interest rates. Long-term debt obligations of $458.5 million have been classified as “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2012.

⁽²⁾  Amounts exclude those operating leases that have been rejected and approved by the Bankruptcy Court.

⁽³⁾  Represents long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses, mine reclamation, selenium water treatment and end-of-mine closure costs. Pursuant to actions taken as part of the bankruptcy proceedings, $1,517.3 million in liabilities associated with postretirement healthcare benefits have been classified as “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2012.

As of December 31, 2012, purchase commitments for equipment totaled $26.0 million primarily related to longwall equipment replacements and capital rebuilds at our Highland mining complex.

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, 2012:

	Asset Retirement Obligations		Workers’ Compensation Obligations		Retiree Health Obligations		Other(1)		Total
	(Dollars in thousands)
Surety bonds	$	192,188	$	—	$	—	$	9,134	$	201,322
Letters of credit	162,291		132,565		54,412		8,467		357,735
Third-party guarantees	—		—		—		5,873		5,873
	$	354,479	$	132,565	$	54,412	$	23,474	$	564,930

⁽¹⁾  Includes collateral for surety companies and bank guarantees, road maintenance, lease obligations and performance guarantees.

As of December 31, 2012, Arch posted surety bonds of $34.3 million related to properties acquired by Patriot in the Magnum acquisition, of which $33.1 million related to reclamation. Magnum posted a letter of credit in Arch’s favor, as required, for a portion of the outstanding reclamation bonds. As part of the bankruptcy proceedings, our prior surety agreement with Arch was terminated and replaced with a new surety agreement.

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In connection with the spin-off, Peabody assumed certain of Patriot’s retiree healthcare liabilities. The present value of these liabilities totaled $637.6 million as of December 31, 2012. 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.

During 2012, we posted collateral for letters of credit under the DIP Facilities, resulting in $50.0 million in interest-bearing deposits. During 2011, we posted a $15.0 million interest-bearing deposit with the U.S. Department of Labor (DOL) as collateral for occupational disease (black lung) workers’ compensation obligations related to certain of our subsidiaries.

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. The maximum term of the three loans is through January 2016 and our guaranteed portion of the loan balances at December 31, 2012 totaled $5.9 million.

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 $0.1 million as of December 31, 2012. Our obligation under the guarantee extends to September 2015.

Recent Accounting Pronouncements

Comprehensive Income

In June 2011, the Financial Accounting Standards Board (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. We adopted this guidance effective January 1, 2012. This guidance does not affect our results of operations or financial condition.

In February 2013, the FASB issued authoritative guidance that clarifies how to report the effect of significant reclassifications out of accumulated other comprehensive income. This guidance is effective prospectively for accounting periods beginning after December 15, 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.

Offsetting Assets and Liabilities

In December 2011, the FASB ratified authoritative guidance which mandates that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position, as well as instruments and transactions subject to an agreement similar to a master netting arrangement. This guidance is effective for fiscal years beginning on or after January 1, 2013. 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.

Indefinite-lived Intangible Assets

In July 2012, the FASB issued authoritative guidance which reduces the cost and complexity of performing an impairment test for indefinite-lived intangible assets by simplifying how an entity tests those assets for impairment and to improve consistency in impairment testing guidance. The new guidance allows an entity the option to make a qualitative assessment about the likelihood that an indefinite-lived intangible asset is impaired to determine whether it should then perform a quantitative impairment test. This guidance is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 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.

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

We are exposed to various types of market risk in the normal course of business, including fluctuations in commodity prices and interest rates.

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 65% of our sales volume under coal supply agreements with terms of more than one year during 2012. As of December 31, 2012 our total unpriced planned production for 2013 was approximately 6.8 million tons.

We have commodity risk related to our diesel fuel purchases. To manage this risk, we have entered into swap contracts with financial institutions. In connection with the Chapter 11 Petitions, we have been authorized by the Bankruptcy Court to continue performance under our pre-petition derivative contracts and to enter into and perform under post-petition derivative contracts consistent with the ordinary course of business and past practices. These derivative contracts have been designated as cash flow hedges of anticipated diesel fuel purchases. Our swap contracts related to heating oil purchases expired in 2012. As of December 31, 2012, the notional amounts outstanding for our ultra low sulfur diesel swap contracts was 3.0 million gallons, all of which expire in 2013. During the fourth quarter of 2012, our outstanding contracts ceased to be highly effective due to impacts on diesel fuel prices from Hurricane Sandy.

We expect to purchase approximately 21 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 $2.1 million.

Credit Risk

Our exposure to credit risk is primarily through our customer concentrations. Our coal sales are made directly to electricity generators, industrial companies, steelmakers, coke producers and coal brokers that ultimately sell the coal to these same types of customers.

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 we engage in a transaction with a counterparty that does not meet our credit standards, we will protect our accounts receivable by requiring the counterparty to provide adequate assurances. Additionally, when appropriate (as determined by our credit management function), we have requested adequate assurances 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. Adequate assurances may include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit. As the economy slowly recovers, 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.

87

Item 9A.Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined under Rules 13a-12(e) promulgated under the Securities Exchange Act of 1934, as amended) as of December 31, 2012. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have each concluded that our disclosure controls and procedures were designed, and were effective, to ensure that the information required to be disclosed in the reports filed or submitted by us under the Securities Exchange Act of 1934, as amended, (the Exchange Act) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

Remediation of A Material Weakness in Internal Control Over Financial Reporting

On May 8, 2012, we filed a Form 10-K/A for the restatement of our consolidated financial statements for the years ended December 31, 2011 and 2010. We had been recording the costs to install the Apogee FBR and Hobet ABMet water treatment facilities as capital expenditures when incurred. The total expenditures were estimated to be approximately $55 million for the Apogee FBR water treatment facility and $25 million for the Hobet ABMet water treatment facility. We restated our consolidated financial statements to accrue a liability and recognize a loss for the estimated costs of installing these two water treatment facilities, rather than record the cost of these two facilities as a capital expenditure.

In connection with the restatement of our consolidated financial statements for the years ended December 31, 2011 and 2010, management, including our then Chief Executive Officer and then Chief Financial Officer, re-evaluated the effectiveness of the design and operation of our disclosure controls and procedures and concluded that there was a material weakness in the internal control over financial reporting related to the accounting treatment for our selenium water treatment obligations as of December 31, 2011 and October 30, 2012.

In remediating the material weakness that resulted in the restatement described above, we added additional review procedures beginning in the quarter ended June 30, 2012 with the intent of widening the scope of the procedures to cover all selenium accruals and cost recognition. The remediation incorporated internal and external consultations with engineering and accounting experts in the areas that involve this level of complexity. As of the date hereof, management has implemented its remediation plan, the additional review procedures over the accounting treatment for selenium water treatment obligations have been operating effectively for an adequate period of time, and these review procedures and controls have been tested by our internal audit group when assessing the effectiveness of our internal controls over financial reporting. As a result, management has concluded that the material weakness in internal control over financial reporting related to the accounting treatment for our selenium water treatment obligations has been remediated as of December 31, 2012.

Changes in Internal Control over Financial Reporting

Other than the remediation procedures described above, there have not been any significant changes in our internal control over financial reporting during the fiscal quarter ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

88

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, 2012.

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/ BENNETT K. HATFIELD

Bennett K. Hatfield

President and Chief Executive Officer

February 22, 2013

89

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, 2012.

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/ JOHN E. LUSHEFSKI

John E. Lushefski

Senior Vice President and Chief Financial Officer

February 22, 2013

90

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, 2012, 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, 2012, 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, 2012 and 2011, and the related consolidated statements of operations, comprehensive loss, stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2012, and our report dated February 22, 2013, expressed an unqualified opinion thereon that included an explanatory paragraph related to the Company’s ability to continue as a going concern.

/s/ Ernst & Young LLP

St. Louis, Missouri

February 22, 2013

91

Item 9B. Other Information.

On January 30, 2013, the Company’s Board of Directors appointed Michael D. Day as Executive Vice President – Operations, effective February 1, 2013. Mr. Day, age 42, joined Patriot in August 2008. Mr. Day most recently served as Patriot’s Senior Vice President – Engineering and W.V. Central Region & Kentucky Operations (August 2011 through January 2013). During his time at Patriot, Mr. Day has also held the positions of Vice President – Operations (August 2009 through August 2011) and Vice President – Surface Operations (August 2008 through August 2009). Prior to joining Patriot, Mr. Day served in a variety of management positions from 1992 through 2008 at Magnum Coal Company, Arch Coal, Inc. and James River Coal Company.

PART III

Item 10.Directors, Executive Officers and Corporate Governance.

Except for the disclosures contained in Part I of this report under the caption “Executive Officers of the Company”, the information required under this item is incorporated herein by reference in an amendment to this Annual Report on Form 10-K, which will be filed within 120 days after the close of our Company’s 2012 fiscal year.

Item 11.Executive Compensation.

The information required under this item is incorporated herein by reference in an amendment to this Annual Report on Form 10-K, which will be filed within 120 days after the close of our Company’s 2012 fiscal year.

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

Except as provided below, the information required under this item is incorporated herein by reference in an amendment to this Annual Report on Form 10-K, which will be filed within 120 days after the close of our Company’s 2012 fiscal year.

The following table provides information regarding our equity compensation plans as of December 31, 2012:

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	1,408,513	$	12.91	6,533,932
Equity compensation plans not approved   by security holders	N/A	N/A		N/A
Total	1,408,513	$	12.91	6,533,932

Under the priority rankings established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition and post-petition liabilities must be satisfied in full before stockholders are entitled to receive any distribution or retain any property under a plan of reorganization. Therefore, there is significant uncertainty regarding the value of our equity securities, including our common stock and any related stock-based awards. Non-vested, non-qualified stock options will continue to vest; however, due to the significant reduction in our stock price and the bankruptcy proceedings, the non-qualified stock options are out-of-the-money and, if exercised by the award holder, Patriot will not honor the exercise.

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

The information required under this item is incorporated herein by reference in an amendment to this Annual Report on Form 10-K, which will be filed within 120 days after the close of our Company’s 2012 fiscal year.

Item 14.Principal Accountant Fees and Services.

The information required under this item is incorporated herein by reference in an amendment to this Annual Report on Form 10-K, which will be filed within 120 days after the close of our Company’s 2012 fiscal year.

92

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
Report of Independent Registered Public Accounting Firm	F-1
Consolidated Statements of Operations – Years Ended December 31, 2012, 2011 and 2010	F-2
Consolidated Statements of Comprehensive Loss – Years Ended December 31, 2012, 2011 and 2010	F-3
Consolidated Balance Sheets – December 31, 2012 and December 31, 2011	F-4
Consolidated Statements of Cash Flows – Years Ended December 31, 2012, 2011 and 2010	F-5
Consolidated Statements of Changes in Stockholders’ Equity (Deficit) – Years Ended December 31, 2012, 2011 and 2010	F-6
Notes to Consolidated Financial Statements	F-7

(2)Financial Statement Schedule.

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

	Page
Valuation and Qualifying Accounts	F-69

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.

93

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/ BENNETT K. HATFIELD

Bennett K. Hatfield

President, Chief Executive Officer and Director

Date: February 22, 2013

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/ BENNETT K. HATFIELD	President, Chief Executive Officer and Director (principal executive officer)	February 22, 2013
Bennett K. Hatfield
/s/ JOHN E. LUSHEFSKI	Senior Vice President & Chief Financial Officer (principal financial and accounting officer)	February 22, 2013
John E. Lushefski
/s/ J. JOE ADORJAN	Director	February 22, 2013
J. Joe Adorjan
/s/ B. R. BROWN	Director	February 22, 2013
B. R. Brown
/s/ MICHAEL P. JOHNSON	Director	February 22, 2013
Michael P. Johnson
/s/ JANIECE M. LONGORIA	Director	February 22, 2013
Janiece M. Longoria
/s/ MICHAEL M. SCHARF	Chairman of the Board, Director	February 22, 2013
Michael M. Scharf
/s/ ROBERT O. VIETS	Director	February 22, 2013
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 as Rights Agent. (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 Exhibit 4.1 of 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 Exhibit 10.3 of 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	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.)
10.22	Indemnification Agreement, dated October 23, 2012, between Patriot Coal Corporation and Bennett K. Hatfield. (Incorporated by reference to Exhibit 10.1of the Registrant's Current Report on Form 8-K, filed on February 5, 2013.)
10.23	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.)
10.24	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.)
10.25	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.)
10.26	Amendment to Employment Agreement between Patriot Coal Corporation and Charles A. Ebetino, Jr. (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed on February 6, 2009.)
10.27	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.)

Exhibit No.	Description of Exhibit
10.28	Amendment to Employment Agreement between Patriot Coal Corporation and Joseph W. Bean. (Incorporated by reference to Exhibit 10.1 the Registrant's Current Report on Form 8-K, filed on February 6, 2009.)
10.29	Employment Agreement, dated September 19, 2011, between Patriot Coal Corporation and Bennett K. Hatfield. (Incorporated by reference to Exhibit 10.5 of the Registrant's Quarterly Report on Form 10-Q, filed on November 2, 2011.)
10.30	First Amendment to Employment Agreement between Patriot Coal Corporation and Bennett K. Hatfield. (Incorporated by reference to Exhibit 10.60 of the Registrant's Annual Report on Form 10-K, filed on February 23, 2012.)
10.31	Second Amendment to Employment Agreement between Patriot Coal Corporation and Bennett K. Hatfield. (Incorporated by reference to Exhibit 10.3 of the Registrant's Quarterly Report on Form 10-Q, filed on August 9, 2012.)
10.32	Third Amendment to Employment Agreement between Patriot Coal Corporation and Bennett K. Hatfield. (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed on February 5, 2013.)
10.33	Employment Agreement, dated as of May 28, 2012 between Patriot Coal Corporation and Irl F. Engelhardt. (Incorporated by reference to Exhibit 10.2 of the Registrant's Quarterly Report on Form 10-Q, filed on August 9, 2012.)
10.34	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 Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on May 23, 2008.)
10.35	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.)
10.36	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.)
10.37	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.)
10.38	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.)
10.39	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.)
10.40	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.)
10.41	Form of Restricted Stock Award 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 January 4, 2010.)

Exhibit No.	Description of Exhibit
10.42	Form of Restricted Stock Award 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 January 9, 2012.)
10.43	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.)
10.44	Form of Performance-Based Restricted Stock Units Award 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 January 30, 2009.)
10.45	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 January 30, 2009.)
10.46	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.)
10.47	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.)
10.48	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.)
10.49	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.)
10.50	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.)
10.51	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.)
10.52	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.)
10.53	Amendment to the Patriot Coal Corporation 401(k) Retirement Plan, dated as of March 5, 2012. (Incorporated by reference to Exhibit 10.4 of the Registrant's Quarterly Report on Form 10-Q, filed on August 9, 2012.)
10.54	Amendment to the Patriot Coal Corporation 401(k) Retirement Plan, dated as of June 21, 2012. (Incorporated by reference to Exhibit 10.5 of the Registrant's Quarterly Report on Form 10-Q, filed on August 9, 2012.)
10.55	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.)
10.56	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.)

Exhibit No.	Description of Exhibit
10.57	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.)
10.58	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.)
10.59	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.)
10.60*	Fifth Amendment to the Patriot Coal Corporation Supplemental 401(k) Retirement Plan.
10.61	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.)
10.62	Modified 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 10.2 of the Registrant's Current Report on Form 8-K, filed on November 20, 2012.)
10.63	Global Settlement Agreement between Ohio Valley Environmental Coalition, Inc., West Virginia Highlands Conservancy, Inc. and Sierra Club and Patriot Coal Corporation. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on November 20, 2012.)
10.64	Superpriority Secured Debtor-in-Possession Revolving and Term Loan Credit Agreement dated July 9, 2012 among Patriot Coal Corporation, certain subsidiaries of Patriot Coal Corporation designated therein as guarantors, Citibank, N.A. as Administrative Agent, Citicorp North America, Inc., Barclays Bank PLC, New York Branch and Bank of America, N.A. as L/C Issuers and certain other lenders party thereto. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on July 13, 2012.)
10.65	Amendment No. 1 dated as of August 7, 2012 to the Superpriority Secured Debtor-in-Possession Credit Agreement dated July 9, 2012 among Patriot Coal Corporation, certain subsidiaries of Patriot Coal Corporation designated therein as guarantors, Citibank, N.A., as Administrative Agent, Citicorp North America, Inc., Barclays Bank PLC, New York Branch and Bank of America, N.A., as L/C Issuers, and certain other lenders party thereto. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on August 13, 2012.)
10.66	Amended and Restated Superpriority Secured Debtor-in-Possession Credit Agreement dated July 11, 2012 among Patriot Coal Corporation, Bank of America, N.A., as Administrative Agent and L/C Issuer and certain other lenders party thereto. (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed on July 13, 2012.)
10.67	Amended and Restated Guarantee dated July 11, 2012 made by Patriot Coal Corporation and certain subsidiaries of Patriot Coal Corporation designated therein as guarantors in favor of Bank of America, N.A. as Administrative Agent for the Lenders under the Amended and Restated Superpriority Secured Debtor-In-Possession Credit Agreement. (Incorporated by reference to Exhibit 10.3 of the Registrant's Current Report on Form 8-K, filed on July 13, 2012.)

Exhibit No.	Description of Exhibit
10.68	Debtor-In-Possession Pledge and Security and Intercreditor Agreement dated July 11, 2012 among Patriot Coal Corporation, certain subsidiaries of Patriot Coal Corporation, Citibank, N.A. and Bank of America, N.A. (Incorporated by reference to Exhibit 10.4 of the Registrant's Current Report on Form 8-K, filed on July 13, 2012.)
10.69	Engagement Letter by and between Patriot Coal Corporation and AP Services, LLC, dated July 9, 2012. (Incorporated by reference to Exhibit 10.6 of the Registrant's Quarterly Report on Form 10-Q, filed on October 30, 2012.)
10.70	First Amendment to Engagement Letter by and between Patriot Coal Corporation and AP Services, LLC, dated July 17, 2012. (Incorporated by reference to Exhibit 10.7 of the Registrant's Quarterly Report on Form 10-Q, filed on October 30, 2012.)
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, 2012, 2011 and 2010, (ii) the Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2012, 2011 and 2010, (iii) the Consolidated Balance Sheets as of December 31, 2012 and 2011, (iv) the Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010, (v) the Consolidated Statements of Changes in Stockholders' Equity (Deficit) for the Years Ended December 31, 2012, 2011 and 2010 and (vi) 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, 2012 and 2011, and the related consolidated statements of operations, comprehensive loss, stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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.

The accompanying consolidated financial statements have been prepared assuming Patriot Coal Corporation will continue as a going concern. As more fully described in Note 2 to the consolidated financial statements, the Company filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code on July 9, 2012, which raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to this matter are also described in Note 2. The consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of the liabilities that may result from the outcome of this uncertainty.

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, 2012, 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, 2013, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

St. Louis, Missouri

February 22, 2013

F-1

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2012			2011			2010
	(Dollars in thousands, except per share data)
Revenues
Sales	$	1,879,013		$	2,378,260		$	2,017,464
Other revenues	43,659			24,246			17,647
Total revenues	1,922,672			2,402,506			2,035,111
Costs and expenses
Operating costs and expenses	1,779,921			2,213,124			1,900,704
Depreciation, depletion and amortization	185,001			186,348			188,074
Asset retirement obligation expense	354,590			105,232			112,697
Sales contract accretion	(11,628		)	(55,020		)	(121,475		)
Impairment and restructuring charge	61,278			13,657			15,174
Selling and administrative expenses	49,040			52,907			50,248
Net gain on disposal or exchange of assets	(3,121		)	(35,557		)	(48,226		)
Income from equity affiliates	(85		)	(4,709		)	(9,476		)
Operating loss	(492,324		)	(73,476		)	(52,609		)
Interest expense and other	60,069			65,533			57,419
DIP financing fees	42,540			—			—
Interest income	(189		)	(246		)	(12,831		)
Loss before reorganization items and income taxes	(594,744		)	(138,763		)	(97,197		)
Reorganization items, net	135,864			—			—
Loss before income taxes	(730,608		)	(138,763		)	(97,197		)
Income tax provision (benefit)	(14		)	372			492
Net loss	$	(730,594	)	$	(139,135	)	$	(97,689	)
Weighted average shares outstanding, basic and diluted	92,486,920			91,321,931			90,907,264
Loss per share, basic and diluted	$	(7.90	)	$	(1.52	)	$	(1.07	)

See accompanying notes to the consolidated financial statements.

F-2

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

	Year Ended December 31,
	2012			2011			2010
	(Dollars in thousands)
Net loss	$	(730,594	)	$	(139,135	)	$	(97,689	)
Accumulated actuarial loss and prior service credit   realized in net loss	54,862			42,559			36,449
Accumulated actuarial unrealized losses	(151,692		)	(118,210		)	(95,801		)
Net change in fair value of diesel fuel hedge	2,213			3,060			1,855
Realized gains of diesel fuel hedge	(1,970		)	(4,744		)	(1,022		)
Other comprehensive loss	(96,587		)	(77,335		)	(58,519		)
Comprehensive loss	$	(827,181	)	$	(216,470	)	$	(156,208	)

See accompanying notes to the consolidated financial statements.

F-3

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

CONSOLIDATED BALANCE SHEETS

	December 31,
	2012			2011
	(Dollars in thousands, except per share data)
ASSETS
Current assets
Cash and cash equivalents	$	333,929		$	194,162
Accounts receivable and other, net of allowance for doubtful accounts of $18 and $138 as of December 31, 2012 and 2011, respectively	105,135			177,695
Inventories	99,219			98,366
Deferred income taxes	65,036			81,025
Prepaid expenses and other current assets	37,406			28,191
Total current assets	640,725			579,439
Property, plant, equipment and mine development
Land and coal interests	2,892,799			2,935,796
Buildings and improvements	571,985			504,275
Machinery and equipment	767,749			735,207
Less accumulated depreciation, depletion and amortization	(1,130,027		)	(973,157		)
Property, plant, equipment and mine development, net	3,102,506			3,202,121
Cash collateralization deposits	64,990			14,990
Investments and other assets	30,586			48,213
Total assets	$	3,838,807		$	3,844,763
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Liabilities not subject to compromise
Current liabilities
Accounts payable and accrued expenses	$	247,489		$	513,123
Below market sales contracts acquired	—			44,787
Current maturities of long-term debt	375,409			1,182
Total current liabilities	622,898			559,092
Long-term debt, less current maturities	1,766			441,064
Deferred income taxes	65,036			81,025
Asset retirement obligations	720,461			424,974
Workers’ compensation obligations	254,680			231,585
Postretirement benefit obligations	87,805			1,387,317
Obligation to industry fund	34,278			35,429
Below market sales contracts acquired, noncurrent	—			46,217
Other noncurrent liabilities	22,805			45,218
Total liabilities not subject to compromise	1,809,729			3,251,921
Liabilities subject to compromise	2,262,307			—
Total liabilities	4,072,036			3,251,921
Stockholders’ equity (deficit)
Common stock ($0.01 par value; 300,000,000 shares authorized; 92,531,916 and 91,885,338 shares issued and outstanding at December 31, 2012 and 2011, respectively)	925			919
Preferred stock ($0.01 par value; 10,000,000 shares authorized; no shares issued and outstanding at December 31, 2012 and 2011)	—			—
Series A Junior Participating Preferred Stock ($0.01 par value; 1,000,000 shares authorized; no shares issued and outstanding at December 31, 2012 and 2011)	—			—
Additional paid-in capital	978,273			977,169
Retained deficit	(730,810		)	(216		)
Accumulated other comprehensive loss	(481,617		)	(385,030		)
Total stockholders’ equity (deficit)	(233,229		)	592,842
Total liabilities and stockholders’ equity (deficit)	$	3,838,807		$	3,844,763

See accompanying notes to the consolidated financial statements.

F-4

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2012			2011			2010
	(Dollars in thousands)
Cash Flows From Operating Activities
Net loss	$	(730,594	)	$	(139,135	)	$	(97,689	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization	185,001			186,348			188,074
Debtor-in-possession debt issuance costs	42,540			—			—
Amortization of deferred financing costs	3,986			7,356			6,412
Amortization of debt discount	5,076			9,543			8,710
Sales contract accretion	(11,628		)	(55,020		)	(121,475		)
Impairment and restructuring charge	61,278			13,093			2,823
Loss on early repayment of note receivable	—			5,868			—
Net gain on disposal or exchange of assets	(3,121		)	(35,557		)	(48,226		)
Income from equity affiliates	(85		)	(4,709		)	(9,476		)
Distributions from equity affiliates	2,842			3,219			5,095
Stock-based compensation expense	180			13,779			11,657
Non-cash reorganization items, net	100,359			—			—
Changes in current assets and liabilities:
Accounts receivable	72,560			(22,336		)	(59		)
Inventories	(853		)	(393		)	(16,785		)
Other current assets	(9,320		)	(1,161		)	(15,172		)
Accounts payable and accrued expenses	(26,371		)	36,804			(13,936		)
Interest on notes receivable	—			—			(12,652		)
Asset retirement obligations	264,184			52,293			77,002
Workers’ compensation obligations	10,873			8,580			12,343
Postretirement benefit obligations	58,310			58,871			50,944
Obligation to industry fund	(2,437		)	(3,278		)	(2,769		)
Cash collateralization deposit	(50,000		)	(14,990		)	—
Other, net	(944		)	(6,186		)	10,432
Net cash (used in) provided by operating activities	(28,164		)	112,989			35,253
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	(139,139		)	(162,965		)	(121,931		)
Proceeds from notes receivable	—			115,679			33,100
Additions to advance mining royalties	(23,614		)	(26,030		)	(21,510		)
Acquisitions	(3,030		)	—			—
Net cash paid in litigation settlement and asset acquisition	—			(14,787		)	—
Proceeds from disposal or exchange of assets	3,690			6,928			1,766
Other	(370		)	—			(300		)
Net cash used in investing activities	(162,463		)	(81,175		)	(108,875		)
Cash Flows From Financing Activities
Proceeds from debtor-in-possession debt	375,000			—			—
Debtor-in-possession debt issuance costs	(42,540		)	—			—
Proceeds from debt offering, net of discount	—			—			248,198
Proceeds from coal reserve financing transaction	—			—			17,700
Long-term debt payments	(1,401		)	(31,002		)	(8,042		)
Deferred financing costs	(1,595		)	(1,832		)	(20,740		)
Proceeds from employee stock programs	930			2,115			2,475
Net cash provided by (used in) financing activities	330,394			(30,719		)	239,591
Net increase in cash and cash equivalents	139,767			1,095			165,969
Cash and cash equivalents at beginning of year	194,162			193,067			27,098
Cash and cash equivalents at end of year	$	333,929		$	194,162		$	193,067

See accompanying notes to the consolidated financial statements.

F-5

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)

	Common Stock		Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Loss			Total
	(Dollars in thousands)
Balance at December 31, 2009	$	903	$	947,159		$	236,608		$	(249,176	)	$	935,494
Net loss	—		—			(97,689		)	—			(97,689		)
Postretirement plans and workers’   compensation obligations (net of taxes   of $0)	—		—			—			(59,352		)	(59,352		)
Changes in diesel fuel hedge	—		—			—			833			833
Stock-based compensation	—		11,657			—			—			11,657
Employee stock purchases	3		2,472			—			—			2,475
Stock grants to employees	3		(3		)	—			—			—
Balance at December 31, 2010	909		961,285			138,919			(307,695		)	793,418
Net loss	—		—			(139,135		)	—			(139,135		)
Postretirement plans and workers’   compensation obligations (net of taxes   of $0)	—		—			—			(75,651		)	(75,651		)
Changes in diesel fuel hedge	—		—			—			(1,684		)	(1,684		)
Stock-based compensation	—		13,779			—			—			13,779
Employee stock purchases	2		2,113			—			—			2,115
Stock grants to employees	8		(8		)	—			—			—
Balance at December 31, 2011	919		977,169			(216		)	(385,030		)	592,842
Net loss	—		—			(730,594		)	—			(730,594		)
Postretirement plans and workers’   compensation obligations (net of taxes   of $0)	—		—			—			(96,830		)	(96,830		)
Changes in diesel fuel hedge	—		—			—			243			243
Stock-based compensation	—		180			—			—			180
Employee stock purchases	1		929			—			—			930
Stock grants to employees	5		(5		)	—			—			—
Balance at December 31, 2012	$	925	$	978,273		$	(730,810	)	$	(481,617	)	$	(233,229	)

See accompanying notes to the consolidated financial statements.

F-6

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

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, publicly-traded company. The spin-off from Peabody was accomplished through a dividend of all outstanding shares of Patriot.

Patriot is engaged in the mining, preparation and sale of thermal coal primarily to electricity generators, and metallurgical coal, for sale to steel 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 23 for our segment disclosures.

(2) Bankruptcy Proceedings

Chapter 11 Reorganization Filings

On July 9, 2012 (the Petition Date), Patriot Coal Corporation, as a stand-alone entity, and substantially all of its wholly-owned subsidiaries (the Filing Subsidiaries and, together with Patriot, the Debtors) filed voluntary petitions for reorganization (the Chapter 11 Petitions) under Chapter 11 of Title 11 of the U.S. Code (the Bankruptcy Code) in the U.S. Bankruptcy Court for the Southern District of New York. The Debtors’ Chapter 11 cases are being jointly administered under the caption In re: Patriot Coal Corporation, et al. (Case No. 12-51502) (the Bankruptcy Case). Our joint ventures and certain of our other subsidiaries (collectively, the Non-Debtor Subsidiaries) were not included in the Chapter 11 filing.

On July 18, 2012 and August 7, 2012, respectively, the United Mine Workers of America (UMWA) and several surety companies filed motions requesting that the venue for our Chapter 11 filing be transferred to the U.S. Bankruptcy Court for the Southern District of West Virginia. The U.S. Trustee also filed a motion arguing that the venue should be transferred from the Southern District of New York to another district. On November 27, 2012, the U.S. Bankruptcy Court for the Southern District of New York issued a ruling transferring the bankruptcy cases to the U.S. Bankruptcy Court for the Eastern District of Missouri. On December 19, 2012, the U.S. Bankruptcy Court for the Southern District of New York entered an order formally transferring the bankruptcy cases to the U.S. Bankruptcy Court for the Eastern District of Missouri (the U.S. Bankruptcy Court for the Eastern District of Missouri and/or the U.S. Bankruptcy Court for the Southern District of New York, as applicable, the Bankruptcy Court).

Effective July 10, 2012, the New York Stock Exchange (NYSE) suspended trading of our common stock and commenced proceedings to delist our common stock. On August 6, 2012, our common stock was delisted from the NYSE. Our stock is now traded under the ticker symbol “PCXCQ” on the OTCQB marketplace, operated by OTC Markets Group Inc.

The filing of the Chapter 11 Petitions constituted an event of default under the Company’s pre-petition debt obligations, and those debt obligations became automatically and immediately due and payable, although any actions to enforce such payment obligations are stayed as a result of the filing of the Chapter 11 Petitions. Due to the filing of the Chapter 11 Petitions, the Company’s pre-petition unsecured long-term debt of $458.5 million is included in “Liabilities subject to compromise” in the accompanying consolidated balance sheet at December 31, 2012.

The Debtors are currently operating as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. In general, the Debtors are authorized to, and continue to, operate as an ongoing business, but may not engage in transactions outside of the ordinary course of business without the approval of the Bankruptcy Court.

F-7

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Debtor-In-Possession (DIP) Financing

In connection with filing the Chapter 11 Petitions, the Debtors filed a motion seeking, among other things, Bankruptcy Court authorization to obtain post-petition financing, and for each Filing Subsidiary (other than EACC Camps, Inc.) and for Patriot Ventures LLC (collectively, the DIP Guarantors) to guaranty our obligations in connection with the DIP financing, up to an aggregate principal amount of $802.0 million, consisting of (a) a revolving credit loan in an amount not to exceed $125.0 million (First Out Revolving Credit Loan), (b) a term loan in the amount of $375.0 million (First Out Term Loan, and together with the First Out Revolving Credit Loan, the First Out Facility), and (c) a $302.0 million roll up (the L/C Roll Up) of obligations under the Amended and Restated Credit Agreement, dated May 5, 2010 (the Pre-Petition Credit Agreement) in respect to outstanding letters of credit, inclusive of any obligations as to reimbursement, renewal and extension of the same issued in the aggregate amount of $300.8 million as of the Petition Date (the Second Out Facility and, together with the First Out Facility, the DIP Facilities).

On July 11, 2012, the Bankruptcy Court entered an interim order (the Interim DIP Order) that, among other things, authorized us to borrow money and obtain letters of credit pursuant to the DIP Facilities and to guaranty such borrowings and our obligations with respect to such letters of credit, up to an aggregate principal or face amount of $677.0 million (plus interest, fees and other expenses and amounts), consisting of borrowings of up to an aggregate principal or face amount of $125.0 million under the First Out Revolving Credit Loan, $250.0 million under the First Out Term Loan, and up to $302.0 million under the Second Out Facility, in accordance with the terms of the Interim DIP Order. On August 3, 2012, the Bankruptcy Court entered a final order (the Final DIP Order) that, among other things, authorized us to borrow the full amount under the DIP Facilities in accordance with the terms of the Final DIP Order. The maturity date of the DIP Facilities is October 4, 2013, but may be extended to December 31, 2013 provided certain conditions are met.

For additional information on the DIP Facilities, see Note 13 - Debt and Credit Facilities.

Reorganization Process

The Bankruptcy Court has authorized us to pay certain of our pre-petition obligations, including payments for employee wages, salaries and certain benefits and payments to certain shippers and critical vendors, subject to certain limitations. The Debtors are required to pay vendors and other providers in the ordinary course for goods and services received after the filing of the Chapter 11 Petitions and to pay certain other business-related payments necessary to maintain the operation of our business. We have retained legal and financial professionals to advise us on the bankruptcy proceedings. From time to time, we may seek the Bankruptcy Court’s approval for the retention of additional professionals.

Immediately after filing the Chapter 11 Petitions, we began notifying all known current or potential creditors of the Debtors of the bankruptcy filings. Subject to certain exceptions under the Bankruptcy Code, the filing of the Chapter 11 Petitions automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the filing of the Chapter 11 Petitions. Thus, for example, most creditor actions to obtain possession of property from us, or to create, perfect or enforce any lien against our property, or to collect on monies owed or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

As required by the Bankruptcy Code, the U.S. Trustee for the Southern District of New York appointed an official committee of unsecured creditors (the Creditors’ Committee). The Creditors’ Committee and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court.

Under Section 365 and other relevant sections of the Bankruptcy Code, we may assume, assume and assign, or reject certain executory contracts and unexpired leases, including leases of real property and equipment, subject to the approval of the Bankruptcy Court and certain other conditions. In this context, “assumption” means that the Company agrees to perform its obligations and cure all existing defaults under the contract or lease, and “rejection” means that it is relieved from its obligations to perform further under the contract or lease, but is subject to a pre-petition claim for damages for the breach thereof subject to certain limitations. Any damages resulting from rejection of executory contracts that are permitted to be recovered under the Bankruptcy Code will be treated as liabilities subject to compromise unless such claims were secured prior to the Petition Date.

Since the Petition Date, the Company received approval from the Bankruptcy Court to reject a number of equipment leases and other executory contracts of various types. On January 15, 2013, the Company filed a motion for authorization to assume or reject all of our unexpired leases of nonresidential real property, including our coal reserve leases. Substantially all of our assumptions and rejections were approved by the Bankruptcy Court on January 28, 2013. We are working to resolve differences in cure amounts and certain other discreet issues with counterparties that objected to our motion. The

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PATRIOT COAL CORPORATION

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Company continues to review all of its executory contracts and unexpired leases to determine which additional contracts and leases it will reject.

The Company expects that additional liabilities subject to compromise will arise due to rejection of executory contracts, including leases, and from the determination of the Bankruptcy Court (or agreement by parties in interest) of allowed claims for contingencies and other disputed amounts. The Company also expects that the assumption of additional executory contracts and unexpired leases will convert certain of the liabilities shown on the accompanying consolidated balance sheet as liabilities subject to compromise to liabilities not subject to compromise. Due to the uncertain nature of many of the potential claims, the Company cannot project the magnitude of such claims with certainty.

On October 18, 2012, the Bankruptcy Court entered an order establishing December 14, 2012 (the General Bar Date) as the bar date for potential creditors, other than governmental units, to file claims. For governmental units to file claims, the bar date was established as January 21, 2013 (the Governmental Bar Date). The bar date is the date by which certain claims against the Company must be filed if the claimants wish to receive any distribution in the bankruptcy cases. Proof of claim forms received after the bar date are typically not eligible for consideration of recovery as part of the Company’s bankruptcy cases. All known potential creditors were notified of the bar date and the requirement to file a claim with the Bankruptcy Court. Patriot also published notices in various publications that are available to the public. Differences between liability amounts estimated by the Company and claims filed by creditors are being investigated and, if necessary, the Bankruptcy Court will make a final determination of the allowable claim. The determination of how liabilities will ultimately be treated cannot be made until the Bankruptcy Court approves a plan of reorganization. Accordingly, the ultimate amount or treatment of such liabilities is not determinable at this time.

In order to successfully exit Chapter 11, we will need to propose and obtain confirmation by the Bankruptcy Court of a plan of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization, among other things, would resolve our pre-petition obligations, set forth the revised capital structure of the newly reorganized entity and provide for corporate governance subsequent to emerging from bankruptcy.

We had the exclusive right for 120 days after the filing of the Chapter 11 Petitions to file a plan of reorganization. On November 15, 2012, the Bankruptcy Court entered an order extending this exclusivity period to May 5, 2013. We may file one or more motions to request extensions of this exclusivity period, which are routinely granted up to 18 months in bankruptcy cases of this size and complexity. If our exclusivity period lapses, any party-in-interest would be able to file a plan of reorganization. In addition to being voted on by requisite holders of impaired claims and equity interests, a plan of reorganization must satisfy certain requirements of the Bankruptcy Code and must be approved, or confirmed, by the Bankruptcy Court in order to become effective. Our timing for filing a plan of reorganization will depend on the timing and outcome of numerous other ongoing matters in the Chapter 11 proceedings.

Under the priority rankings established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full before stockholders are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation of a plan of reorganization. No assurance can be given as to what values, if any, will be ascribed to each of these constituencies or what types or amounts of distributions, if any, they would receive. A plan of reorganization could result in holders of certain liabilities and/or securities, including common stock, receiving no distribution on account of their interests and cancellation of their holdings. Because of such possibilities, there is significant uncertainty regarding the value of our liabilities and securities, including our common stock. At this time, there is no assurance we will be able to restructure as a going concern or successfully propose or implement a plan of reorganization.

Going Concern Matters

The accompanying consolidated financial statements and related notes have been prepared assuming we will continue as a going concern, although the Bankruptcy Case and weak industry conditions raise substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded assets or to the amounts and classification of liabilities or any other adjustments that might be necessary should we be unable to continue as a going concern. Our ability to continue as a going concern is dependent upon, among other things, market conditions and our ability to improve profitability, to meet the financial covenants of the DIP Facilities or obtain appropriate waivers, to obtain financing to replace the DIP Facilities upon emergence and to restructure our obligations in a manner that allows us to obtain confirmation of a plan of reorganization by the Bankruptcy Court. In order to improve profitability, we are taking actions to further reduce operating expenses and align our production to meet market demand. As a result of the Bankruptcy Case, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession pursuant to the Bankruptcy Code, we may

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Facilities), for amounts other than those reflected in the accompanying consolidated financial statements. Further, any plan of reorganization could materially change the amounts and classifications of assets and liabilities reported in the historical consolidated financial statements.

Financial Reporting Considerations

For periods subsequent to filing the Chapter 11 Petitions, we have applied the Financial Accounting Standards Board Accounting Standards Codification (ASC) 852, “Reorganizations” (ASC 852), in preparing the consolidated financial statements. ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings have been recorded in “Reorganization items, net” on the consolidated statements of operations. In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on the consolidated balance sheet at December 31, 2012 in “Liabilities subject to compromise.” These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

Reorganization Items and Other Bankruptcy Related Costs

ASC 852 requires separate disclosure of reorganization items such as realized gains and losses from the settlement of pre-petition liabilities, and provisions for losses resulting from the reorganization of the business, as well as professional fees directly related to the process of reorganizing under Chapter 11. The Company’s reorganization items for the year ended December 31, 2012 consist of the following:

	Year Ended
	December 31, 2012
	(Dollars in thousands)
Provision for rejected executory contracts and leases	$	82,213
Professional fees	35,506
Losses from adjusting debt from carrying value to amount of allowed claim	27,021
Accounts payable settlement gains	(8,876		)
Reorganization items, net	$	135,864

Professional fees are directly related to the reorganization and include fees associated with advisors to the Company, the Creditors’ Committee and certain secured creditors. Net cash paid for reorganization items for the year ended December 31, 2012 totaled $23.3 million, all of which related to professional fees.

Reorganization items exclude employee severance and other restructuring charges recorded during 2012. See Note 5 for further details on restructuring charges.

Debt issuance costs of $42.5 million were incurred and paid in connection with the DIP Financing. These amounts were expensed and separately presented in the 2012 consolidated statement of operations.

Liabilities Subject to Compromise

Liabilities subject to compromise represent unsecured obligations that will be accounted for under a plan of reorganization. Generally, actions to enforce or otherwise effect payment of pre-petition liabilities are stayed. ASC 852 requires pre-petition liabilities that are subject to compromise to be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. These liabilities represent the amounts expected to be allowed on known or potential claims to be resolved through the Chapter 11 process, and remain subject to future adjustments arising from negotiated settlements, actions of the Bankruptcy Court, rejection of executory contracts and unexpired leases, the determination as to the value of collateral securing the claims, proofs of claim, or other events. Liabilities subject to compromise also include certain items that may be assumed under the plan of reorganization, and as such, may be subsequently reclassified to liabilities not subject to compromise.

The Bankruptcy Court has authorized us to pay certain pre-petition obligations, including payment of employee wages, salaries and certain benefits and payments to certain shippers and critical vendors, subject to certain limitations. The Debtors are required to pay vendors and other providers in the ordinary course for goods and services received after the filing of the

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PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Chapter 11 Petitions and certain other business related payments necessary to maintain the operations of the Company’s business. Obligations associated with these matters are not classified as liabilities subject to compromise.

With the approval of the Bankruptcy Court, the Company has rejected certain pre-petition executory contracts and unexpired leases with respect to the Company’s operations and may reject additional ones in the future. Damages resulting from rejection of executory contracts and unexpired leases are generally treated as general unsecured claims and are classified as liabilities subject to compromise. Holders of pre-petition claims were required to file proofs of claims by the General Bar Date or the Governmental Bar Date, as applicable. Differences between liability amounts estimated by the Company and claims filed by creditors are being investigated and, if necessary, the Bankruptcy Court will make a final determination of the allowable claim. The determination of how liabilities will ultimately be treated cannot be made until the Bankruptcy Court approves a plan of reorganization. Accordingly, the ultimate amount or treatment of such liabilities is not determinable at this time.

Liabilities subject to compromise consist of the following:

	December 31, 2012
	(Dollars in thousands)
Postretirement benefit obligations, excluding Coal Act	$	1,517,284
Unsecured debt	458,500
Interest payable	4,838
Rejected executory contracts and leases	151,449
Trade payables	78,086
Other accruals	52,150
Liabilities subject to compromise	$	2,262,307

Other accruals primarily include liabilities subject to compromise related to accrued royalty payments, litigation reserves, employee claims and other operating accruals.

Debtor Financial Statements

The following condensed combined financial statements represent the financial statements for the Debtors only. The Company’s Non-Debtor Subsidiaries are accounted for as non-consolidated subsidiaries in these Debtor financial statements and, as such, their net income is included in “Loss from non-debtor entities” in the condensed combined statement of operations and their net assets are included as “Investments in and advances to non-debtor entities” in the condensed combined balance sheet. The Debtors’ condensed combined financial statements have been prepared in accordance with the guidance in ASC 852.

Intercompany transactions between the Debtors have been eliminated in the condensed combined financial statements. Intercompany transactions between the Debtors and Non-Debtor Subsidiaries have not been eliminated in the Debtors’ condensed combined financial statements.

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PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

PATRIOT COAL CORPORATION
CONDENSED COMBINED STATEMENT OF OPERATIONS - DEBTORS
	Year Ended
	December 31, 2012
	(Dollars in thousands)
Revenues
Sales	$	1,879,013
Other revenues	43,659
Total revenues	1,922,672
Costs and expenses
Operating costs and expenses	1,779,913
Depreciation, depletion and amortization	185,001
Asset retirement obligation expense	354,590
Sales contract accretion	(11,628		)
Impairment and restructuring charge	60,963
Selling and administrative expenses	49,040
Net gain on disposal or exchange of assets	(3,121		)
Income from equity affiliates	(191		)
Loss from non-debtor entities	364
Operating loss	(492,259		)
Interest expense and other	60,069
DIP financing fees	42,540
Interest income	(124		)
Loss before reorganization items and income taxes	(594,744		)
Reorganization items, net	135,864
Loss before income taxes	(730,608		)
Income tax benefit	(14		)
Net loss	$	(730,594	)

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(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

PATRIOT COAL CORPORATION
CONDENSED COMBINED STATEMENT OF COMPREHENSIVE LOSS - DEBTORS
	Year Ended
	December 31, 2012
	(Dollars in thousands)
Net loss	$	(730,594	)
Accumulated actuarial loss and prior service credit realized in net loss	54,862
Accumulated actuarial unrealized losses	(151,692		)
Net change in fair value of diesel fuel hedge	2,213
Realized gains of diesel fuel hedge	(1,970		)
Other comprehensive loss	(96,587		)
Comprehensive loss	$	(827,181	)

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PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

PATRIOT COAL CORPORATION
CONDENSED COMBINED BALANCE SHEET - DEBTORS
	December 31, 2012
	(Dollars in thousands)
ASSETS
Current assets
Cash and cash equivalents	$	333,175
Accounts receivable and other, net	105,135
Inventories	99,219
Deferred income taxes	65,036
Prepaid expenses and other current assets	36,734
Total current assets	639,299
Property, plant, equipment and mine development
Land and coal interests	2,892,799
Buildings and improvements	571,985
Machinery and equipment	767,749
Less accumulated depreciation, depletion and amortization	(1,130,027		)
Property, plant, equipment and mine development, net	3,102,506
Cash collateralization deposits	64,990
Investments and other assets	6,193
Investments in and advances to non-debtor entities	23,428
Total assets	$	3,836,416
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Liabilities not subject to compromise
Current liabilities
Accounts payable and accrued expenses	$	245,098
Current maturities of long-term debt	375,409
Total current liabilities	620,507
Long-term debt, less current maturities	1,766
Deferred income taxes	65,036
Asset retirement obligations	720,461
Workers’ compensation obligations	254,680
Postretirement benefit obligations	87,805
Obligation to industry fund	34,278
Other noncurrent liabilities	22,805
Total liabilities not subject to compromise	1,807,338
Liabilities subject to compromise	2,262,307
Total liabilities	4,069,645
Total stockholders’ deficit	(233,229		)
Total liabilities and stockholders’ deficit	$	3,836,416

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PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

PATRIOT COAL CORPORATION
CONDENSED COMBINED STATEMENT OF CASH FLOWS - DEBTORS
	Year Ended
	December 31, 2012
	(Dollars in thousands)
Cash Flows From Operating Activities
Net loss	$	(730,594	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization	185,001
Debtor-in-possession debt issuance costs	42,540
Amortization of deferred financing costs	3,986
Amortization of debt discount	5,076
Sales contract accretion	(11,628		)
Impairment and restructuring charge	60,963
Net gain on disposal or exchange of assets	(3,121		)
Income from equity affiliates	(191		)
Income from non-debtor entities	364
Stock-based compensation expense	180
Non-cash reorganization items, net	100,359
Changes in current assets and liabilities:
Accounts receivable	72,560
Inventories	(853		)
Other current assets	(8,647		)
Accounts payable and accrued expenses	(28,762		)
Advances to non-debtor entities	3,350
Asset retirement obligations	264,184
Workers’ compensation obligations	10,873
Postretirement benefit obligations	58,310
Obligation to industry fund	(2,437		)
Cash collateralization deposit	(50,000		)
Other, net	(801		)
Net cash used in operating activities	(29,288		)
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	(139,139		)
Additions to advance mining royalties	(23,614		)
Acquisitions	(3,030		)
Proceeds from disposal or exchange of assets	3,690
Net cash used in investing activities	(162,093		)
Cash Flows From Financing Activities
Proceeds from debtor-in-possession debt	375,000
Long-term debt payments	(1,401		)
Deferred financing costs	(1,595		)
Debtor-in-possession debt issuance costs	(42,540		)
Proceeds from employee stock programs	930
Net cash provided by financing activities	330,394
Net increase in cash and cash equivalents	139,013
Cash and cash equivalents at beginning of year	194,162
Cash and cash equivalents at end of year	$	333,175

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PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(3) Summary of Significant Accounting Policies

Sales

Revenues from coal sales are realized and earned when title and 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 (greater than one year). Under the typical terms of these coal supply agreements, title and risk of loss transfer to the customer at the mine, 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 resulting from the release of customers from receipt of committed tons, royalties related to coal lease agreements and farm income. Royalty income generally results from the lease or sublease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced. Certain agreements require minimum annual lease payments regardless of the extent to which minerals are produced from the leasehold, although revenue is only recognized on these payments as the mineral is mined. The terms of these agreements generally range from specified periods of 5 to 15 years, or can be for an unspecified period until all reserves are depleted.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.

Accounts Receivable

Accounts receivable are recorded at the invoiced amount and do not bear interest. Allowance for doubtful accounts was approximately $18,000 and $138,000 at December 31, 2012 and 2011, 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.

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 2012, 2011 and 2010 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, 2012 and 2011, the book value of coal reserves totaled $2.5 billion and $2.6 billion, including $1.9 billion and $1.8 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 $2.2 billion and $2.3 billion at

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PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2012 and 2011, 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 1 year up to 29 years. The charge against earnings for depreciation of property, plant, equipment and mine development, including depreciation of assets under capital lease, was $103.6 million, $101.0 million and $104.5 million for the years ended December 31, 2012, 2011 and 2010, 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 was accreted into earnings as the coal was shipped over a weighted average period of approximately three years.

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.

Obligations related to water treatment and compliance with selenium effluent limits are recognized at fair value and accreted into earnings to the projected spending date. The net liability related to selenium water treatment at December 31, 2012 and 2011 reflects the estimated future costs to install and operate various treatment systems or facilities at affected outfalls. The accretion of the estimated liability is included in “Asset retirement obligation expense” in the consolidated

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PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

statements of operations. Spending estimates are adjusted for inflation and then discounted at the credit-adjusted, risk-free rate.

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 sheets 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, 2012 and 2011 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 qualifies as multi-employer plans and expense is recognized as contributions are made.

We also participate in a multi-employer pension plan, the United Mine Workers of America (UMWA) 1974 Pension Plan (the 1974 Plan). The plan qualifies as a multi-employer plan and expense is recognized as contributions are made. The assets of the 1974 Plan are managed by the UMWA. See Note 19 for additional information.

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; 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, 2012 and 2011 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 uses 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, and in the case of selenium water treatment, relatively new and unproven technologies. 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.

F-18

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Stock-Based Compensation

We have an equity incentive plan for employees and eligible non-employee directors that allows for the issuance of stock-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, 2012 and 2011, 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.

Impairment of Long-Lived Assets

The Company reviews its long-lived assets held and used in accordance with ASC 360-10-35-15, “Impairment or Disposal of Long-Lived Assets,” which requires the Company to review for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may 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. We performed impairment reviews throughout 2012 as events occurred or market factors changed . See Note 5 for additional information.

Deferred Financing Costs

Prior to the bankruptcy filing, we capitalized costs incurred in connection with borrowings or establishment of credit facilities and issuance of debt securities. These costs were amortized and included in interest expense over the life of the borrowing or term of the credit facility using the interest method. During 2012, $15.1 million of unamortized deferred financing costs related to pre-petition debt was recorded to reorganization expense after filing the Chapter 11 Petitions. Costs incurred and paid in connection with the DIP Financing were expensed and separately presented in the 2012 consolidated statement of operations.

(4) Recent Accounting Pronouncements

Comprehensive Income

In June 2011, the Financial Accounting Standards Board (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. We adopted this guidance on January 1, 2012. This guidance does not affect our results of operations or financial condition.

In February 2013, the FASB issued authoritative guidance that clarifies how to report the effect of significant reclassifications out of accumulated other comprehensive income. This guidance is effective prospectively for accounting periods beginning after December 15, 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.

Offsetting Assets and Liabilities

In December 2011, the FASB ratified authoritative guidance which mandates that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position, as well as instruments and transactions subject to an agreement similar to a master netting arrangement. This guidance is effective for fiscal years beginning on or after January 1, 2013. 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.

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PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Indefinite-lived Intangible Assets

In July 2012, the FASB issued authoritative guidance which reduces the cost and complexity of performing an impairment test for indefinite-lived intangible assets by simplifying how an entity tests those assets for impairment and to improve consistency in impairment testing guidance. The new guidance allows an entity the option to make a qualitative assessment about the likelihood that an indefinite-lived intangible asset is impaired to determine whether it should then perform a quantitative impairment test. This guidance is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 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.

(5) Impairment and Restructuring Charge

In the third quarter of 2012, we recorded an impairment charge of $18.4 million for the write-off of coal reserves related to our Bluegrass mining complex located in the Illinois Basin segment. This impairment resulted from the termination of leases providing rights to certain coal reserves through the bankruptcy contract rejection process and related negotiations.

In the second quarter of 2012, as a result of weaker industry fundamentals and coal demand, and the significant decline in value of our equity securities and debt instruments, we performed an impairment review of all of our long-lived assets. This analysis was updated in the third and fourth quarters of 2012. Recoverability of long-lived assets was assessed based on the carrying value of these assets compared to the sum of the undiscounted cash flows expected to result from the use and eventual disposal of the assets, as well as specific appraisal in certain circumstances. As a result of the second quarter impairment review, we recorded a $1.4 million impairment charge during the second quarter of 2012 on certain coal reserves located in our Appalachia segment.

In June 2012, we idled our Freedom mine at the Bluegrass mining complex due to continued weakened demand for thermal coal. The Freedom mine produced approximately 1.2 million tons of thermal coal in 2011. We also closed one of our thermal mines at our Kanawha Eagle mining complex due to certain adjustments to our mining plans. The Kanawha Eagle mining complex is reported in our Appalachia segment. As a result, we recorded an $8.2 million impairment and restructuring charge related to these two mines during the second quarter of 2012, which primarily consisted of the write-off of infrastructure, mine development and certain equipment. We also recorded a $4.1 million charge to asset retirement obligation expense to adjust the liability for the accelerated closure and to write-off the related asset.

In February 2012, we closed the Big Mountain mining complex, which is reported in our Appalachia segment, due to the weakened demand for thermal coal experienced in late 2011 and early 2012. Prior to the closure, the complex had two active mines and one preparation plant. The complex produced 1.8 million tons of thermal coal in 2011. In the first quarter of 2012, we recorded a $32.8 million impairment and restructuring charge related to the closure, which mainly consisted of the write-off of infrastructure, mine development and certain equipment. We also recorded a $17.5 million charge to asset retirement obligation expense to adjust the asset retirement obligation liability for the accelerated closure and write-off the related asset.

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 sale 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 impairment and restructuring 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. At December 31, 2012, the restructuring liability totaled $6.0 million and is included in “Liabilities subject to compromise.” At December 31, 2011, the restructuring liability totaled $10.1 million, of which $4.5 million was the current portion and included in “Accounts payable and accrued expense.” The long-term portion of the restructuring reserves at December 31, 2011 was included in “Other noncurrent liabilities,” in the accompanying consolidated balance sheets. During the years ended December 31, 2012, 2011 and 2010, $0.3 million, $0.6 million and $0.4 million, respectively, of accretion related to the discounted future payment obligations was charged against the restructuring liability.

F-20

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The Company continues to review and evaluate various restructuring and other alternatives in response to changes in market demand. Such initiatives may include cost reductions, idling or closing mining operations, consolidating operations and functions, relocating or reducing production and voluntary and involuntary employee separation programs. In addition, such actions may subject the Company to additional asset impairment charges and short-term costs, which may include mine shutdown costs, lease commitment costs, employee severance costs and other closing costs.

(6) 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 March 2012, we sold certain non-strategic Appalachia gas and oil rights to a third party in exchange for cash resulting in a gain of $1.5 million.

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 $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 in Appalachia and recognized a gain of $4.9 million on this transaction. We also sold certain non-strategic Appalachia coal mineral rights to another coal producer resulting in a gain of $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 and recognized a gain of $7.3 million on this transaction. We also recognized a gain of $2.1 million related to an agreement allowing a right of way at our Kanawha Eagle mining complex in Appalachia to a third party. 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 in Appalachia. We recognized gains totaling $14.3 million on these transactions. 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 transaction as a result of transferring the reclamation liability.

In the first quarter of 2010, we received approximately 13 million tons of coal mineral rights contiguous to our Highland mining complex in exchange for non-strategic Illinois Basin coal reserves and recognized a gain of $24.0 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

In December 2005, Magnum Coal Company (Magnum), which was acquired by Patriot in 2008, entered into a coal sales and services agreement pursuant to which it agreed to sell the coal required to satisfy the buyer’s independent obligations under enumerated agreements with third parties. Effective March 27, 2012, we entered into an agreement with the buyer that provided us with a monthly option to make buyout payments in lieu of delivering the coal required for the buyer to satisfy its obligations under one of the enumerated agreements. In aggregate, over the next six years, the maximum potential buyout amount totaled $64.1 million if we made no deliveries during that period. In the fourth quarter of 2012, we received

F-21

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

approval from the Bankruptcy Court to reject these agreements. As such, at December 31, 2012, the liability is included in “Liabilities subject to compromise” in our consolidated balance sheet.

In 2012, we acquired several companies that employed the workforce or partial workforce at two Appalachia mining complexes for a total of $3.0 million. The purchase prices were recorded as intangible assets in accordance with asset acquisition authoritative guidance. The intangible assets are being amortized over the life of the mine where the workforce is located. In the third quarter of 2012, we reduced the Kanawha Eagle mining complex workforce by 60% as a result of a temporary curtailment of metallurgical coal production in response to further weakening of market demand. Accordingly, we recognized an impairment charge of $1.5 million representing a corresponding portion of the related intangible asset’s unamortized balance.

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.

Effective April 2010, we entered into an agreement to sell coal mineral rights at our Federal mining complex in Appalachia 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, 2012, 2011 and 2010, $2.5 million, $2.4 million and $1.8 million, respectively, was reflected in “Interest expense and other” on the consolidated statement of operations.

“Other revenues” includes payments from customer settlements, royalties related to coal lease agreements and farm income. During 2012, certain customers requested to cancel or delay shipment of coal contracted for 2012 and 2013 deliveries. In certain situations, we agreed to release the customers from their commitments in exchange for cash settlements. For the year ended December 31, 2012, we recognized revenue of $24.6 million related to these cash settlements. Additionally, we received $8.3 million related to the settlement of a customer contract dispute concerning coal deliveries in prior years that was settled through mediation in the first quarter of 2012.

For the year ended December 31, 2011, we recognized $8.9 million 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.

(7) Joint Ventures

We have interests in five joint ventures that are accounted for under the equity method. Only two joint ventures have active coal mining operations.

The book value of our equity method investments was $24.4 million and $27.1 million as of December 31, 2012 and 2011, respectively. The investments in these joint ventures are recorded in “Investments and other assets” in the consolidated balance sheets. Our maximum exposure to loss is our book value plus additional future capital contributions. Our future capital contributions exposure for all of our joint ventures is capped at $8.4 million as of December 31, 2012.

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. The maximum term of the three loans is through January 2016 and our guaranteed portion of the loan balances at December 31, 2012 totaled $5.9 million. At December 31, 2012 and 2011, 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. The financial performance of our joint ventures is subject to market risks similar to our coal mining operations.Our bankruptcy proceedings do not impact the limited guarantee we have provided to the joint venture, and the guarantee has remained in place.

F-22

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

We purchase metallurgical coal from one of our joint ventures. The cost of this coal, $55.2 million in 2012, $50.0 million in 2011 and $40.0 million in 2010, is included in “Operating costs and expenses” in our consolidated statements of operations. The coal is then sold to third-party customers. As of December 31, 2012 and 2011, “Accounts payable and accrued expenses” on our consolidated balance sheets included the outstanding payable to this joint venture for coal purchases of $1.8 million and $4.1 million, respectively.

At December 31, 2012, one of our joint ventures owed us approximately $2.3 million for royalties and utility usage.

(8) Earnings per Share

Basic earnings per share is computed by dividing net loss 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, 2012, 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, 1.9 million shares, 3.3 million shares, and 2.6 million shares related to stock-based compensation awards for the years ended December 31, 2012, 2011 and 2010, respectively, as described in Note 25, and 3.0 million common shares for all three years related to the convertible notes described in Note 13, were excluded from the diluted loss per share calculation.

(9) Inventories

Inventories consisted of the following:

	December 31,
	2012		2011
	(Dollars in thousands)
Materials and supplies	$	52,970	$	62,474
Saleable coal	27,197		23,806
Raw coal	19,052		12,086
Total	$	99,219	$	98,366

(10) 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 $63.0 million, $55.4 million and $43.0 million for the years ended December 31, 2012, 2011 and 2010, 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 $62.4 million, $88.5 million and $73.9 million for the years ended December 31, 2012, 2011 and 2010, respectively.

F-23

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Future minimum lease and royalty payments as of December 31, 2012, are as follows:

	Capital Leases			Operating Leases		Coal Reserves
	(Dollars in thousands)
2013	$	617		$	43,056	$	28,705
2014	617			34,957		22,995
2015	617			19,674		18,024
2016	617			9,555		15,913
2017	255			1,938		13,335
2018 - 2022	—			—		79,007
Total minimum lease & royalty payments	2,723			$	109,180	$	177,979
Less interest	(548		)
Present value of minimum capital lease payments	$	2,175

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 to PVR 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 in cash. 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 2010. 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.

(11) Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consisted of the following:

	December 31,
	2012		2011
	(Dollars in thousands)
Accounts payable	$	78,453	$	206,873
Accrued healthcare, including Coal Act postretirement obligations	16,790		85,506
Accrued taxes other than income	37,510		27,000
Accrued payroll and related benefits	24,848		43,097
Workers’ compensation obligations	24,414		26,707
Asset retirement obligations	11,175		63,067
Accrued interest payable	8,551		7,401
Other accrued benefits	9,972		8,936
Accrued royalties	5,245		9,394
Accrued lease payments	112		11,398
Other accrued expenses	30,419		23,744
Total accounts payable and accrued expenses	$	247,489	$	513,123

(12) Income Taxes

Loss before income taxes was $730.6 million, $138.8 million and $97.2 million for the years ended December 31, 2012, 2011 and 2010, respectively, and consisted entirely of domestic results.

For the year ended December 31, 2012, we had a nominal income tax benefit for state and local income taxes. For the years ended December 31, 2011 and 2010, we had an income tax provision for certain state and local income taxes of $0.4 million and $0.5 million, respectively. There was no provision for federal income taxes for any of the years presented.

F-24

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The income tax rate differed from the U.S. federal statutory rate as follows:

	Year Ended December 31,
	2012			2011			2010
	(Dollars in thousands)
Federal statutory rate	$	(255,713	)	$	(48,567	)	$	(34,019	)
Depletion	(28,296		)	(25,825		)	(23,893		)
State income taxes, net of U.S. federal tax benefit	(39,876		)	(9,936		)	(8,374		)
Change in valuation allowance	317,422			79,967			62,640
Change in tax reserves	1,598			1,476			1,382
Other, net	4,851			3,257			2,756
Total	$	(14	)	$	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,
	2012			2011
	(Dollars in thousands)
Deferred tax assets:
Postretirement benefit obligations	$	451,133		$	427,781
Tax credits and loss carryforwards	443,361			304,178
Workers’ compensation obligations	110,845			106,819
Asset retirement obligations	286,491			186,994
Obligation to industry fund	14,736			15,891
Sales contract liabilities	28,052			36,400
Other	87,240			49,414
Total gross deferred tax assets	1,421,858			1,127,477
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	837,735			865,264
Long-term debt	—			5,710
Other	4,032			774
Total gross deferred tax liabilities	841,767			871,748
Valuation allowance	580,091			255,729
Net deferred taxes	$	—		$	—
Deferred taxes consisted of the following:
Current deferred income taxes	$	65,036		$	81,025
Noncurrent deferred income taxes	(65,036		)	(81,025		)
Net deferred taxes	$	—		$	—

In previously issued financial statements, the 2011 deferred tax asset valuation allowance was improperly classified on the consolidated balance sheet. The misclassification had no impact on the results of operations or cash flows of the Company. The misclassification has been corrected in the 2011 consolidated balance sheet presented herein.

Our deferred tax assets include net operating loss (NOL) carryforwards, alternative minimum tax (AMT) credits, and general business credits of $443.4 million and $304.2 million as of December 31, 2012 and 2011, 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

F-25

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

On September 7, 2012, the Bankruptcy Court entered an order establishing procedures for trading in claims and equity securities that are designed to protect the Debtors’ potentially valuable tax attributes (such as NOL carryforwards); this order was effective to the Petition Date. The order establishes and implements restrictions and notification requirements regarding the beneficial ownership and certain transfers of Patriot Coal Corporation common stock, and sell down procedures with respect to covered claims.

Overall, our net deferred tax assets are offset by a valuation allowance of $580.1 million and $255.7 million as of December 31, 2012 and 2011, respectively. The valuation allowance increased by $324.4 million for the year ended December 31, 2012, primarily as a result of net future deductible temporary differences increasing by $185.2 million and an increase in NOL carryforwards of $139.2 million. We evaluated and assessed the expected near-term utilization of NOL 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, 2012 and 2011.

Patriot and its subsidiaries have examination exposure related to the federal and state income tax returns for the years ended December 31, 2009, 2010, 2011 and 2012.

For the year ended December 31, 2012, we paid less than $0.1 million in federal, state and local income taxes. During the years ended December 31, 2011 and 2010, we paid federal, state and local income taxes of $0.7 million, and $0.5 million, respectively. The portion paid for state income tax payments each year is for tax liabilities that are calculated based on gross receipts.

At December 31, 2012, 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,
	2012		2011			2010
	(Dollars in thousands)
Balance at beginning of year	$	12,969	$	9,279		$	5,866
Additions for current year tax positions	3,996		3,696			3,366
Additions (reductions) for prior year positions	46		(6		)	47
Balance at end of year	$	17,011	$	12,969		$	9,279

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.

F-26

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(13) Debt and Credit Facilities

Our total indebtedness consisted of the following:

	December 31,
	2012			2011
	(Dollars in thousands)
Secured Debt
DIP First Out Term Loan, due 2013	$	375,000		$	—
Capital leases	2,175			—
Total secured debt, not subject to compromise	377,175			—
Unsecured Debt
8.25% Senior Notes, due 2018	250,000			248,573
3.25% Convertible Senior Notes, due 2013	200,000			185,379
Promissory notes	8,500			8,294
Total unsecured debt, subject to compromise	458,500			442,246
Total long-term debt	835,675			442,246
Less liabilities subject to compromise	(458,500		)	—
Less current maturities of long-term debt	(375,409		)	(1,182		)
Long-term debt, less current maturities	$	1,766		$	441,064

DIP Financing

In connection with filing the Chapter 11 Petitions, the Debtors filed a motion seeking, among other things, Bankruptcy Court authorization for us to obtain the DIP Facilities, and for the DIP Guarantors to guaranty obligations in connection with the DIP Facilities, up to an aggregate principal amount of $802.0 million, consisting of (a) a First Out Revolving Credit Loan in an amount not to exceed $125.0 million, (b) a First Out Term Loan in the amount of $375.0 million, and (c) a $302.0 million roll up of obligations under the Pre-Petition Credit Agreement in respect to outstanding letters of credit, inclusive of any obligations as to reimbursement, renewal and extension of the same issued in the aggregate amount of $300.8 million as of the Petition Date (the Second Out Facility).

On July 11, 2012, the Bankruptcy Court entered the Interim DIP Order that, among other things, authorized us to borrow money and obtain letters of credit pursuant to the DIP Facilities and to guaranty such borrowings and our obligations with respect to such letters of credit, up to an aggregate principal or face amount of $677.0 million (plus interest, fees and other expenses and amounts), consisting of borrowings of up to an aggregate principal or face amount of $125.0 million under the First Out Revolving Credit Loan, $250.0 million under the First Out Term Loan, and up to $302.0 million under the Second Out Facility, in accordance with the terms of the Interim DIP Order and the DIP Facilities. On August 3, 2012, the Bankruptcy Court entered the Final DIP Order that, among other things, authorized us to borrow the full amount under the DIP Facilities in accordance with the terms of the Final DIP Order and the DIP Facilities. The Final DIP Order amended certain provisions of the DIP Facilities, including, among other things, the definition of “Applicable Rate” in the First Out DIP Credit Agreement.

The DIP Facilities, as more fully described below, include financial covenants applicable to Patriot and its subsidiaries, including compliance with requirements relating to minimum consolidated EBITDA, as defined by the DIP Facilities, maximum capital expenditures and minimum liquidity. At December 31, 2012, we were in compliance with these financial covenants. Based on continued declines in metallurgical coal demand and prices experienced in the second half of 2012 and the related effect on our current internal financial forecasts, we believe there is a substantial likelihood that we may not comply with the minimum consolidated EBITDA financial covenant beginning in the third quarter of 2013. Our financial forecasts are subject to significant variation due to the volatility in the coal markets, including demand and prices for our products, and uncertainties surrounding our restructuring initiatives, so our compliance with the minimum consolidated EBITDA financial covenant remains subject to market conditions and our ability to improve financial performance. Failure to comply with our financial covenants would be an event of default under the terms of our DIP Facilities. If an event of default occurs, we would need to negotiate an amendment or waiver from the lenders; however, there can be no assurances that we would be able to obtain such an amendment or waiver in the future.

F-27

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

First Out Facility

On July 9, 2012, Patriot and the DIP Guarantors entered into a Superpriority Secured Debtor-in-Possession Revolving and Term Loan Credit Agreement (the First Out DIP Credit Agreement). Our obligations under the First Out DIP Credit Agreement are guaranteed by each DIP Guarantor. On July 11, 2012, the conditions precedent to closing and the initial borrowing were satisfied and the First Out DIP Credit Agreement became effective.

First Out Revolving Credit Loans bear interest at a rate per annum equal to the Eurocurrency Rate (as defined in the First Out DIP Credit Agreement) plus 3.25% or the Base Rate (as defined in the First Out DIP Credit Agreement) plus 2.25%. First Out Term Loans bear interest at a rate per annum equal to the Eurocurrency Rate plus 7.75% or the Base Rate plus 6.75%. As of December 31, 2012, the interest rate on the First Out Term Loans was 9.25%. Upon the occurrence and during the continuance of an event of default under the First Out DIP Credit Agreement, the interest rate increases by 2.00% per annum. In addition, letter of credit fees under the First Out Facility are paid at a rate equal to 3.25% per annum and a commitment fee of 0.75% per annum is required for unutilized commitments.

On July 11, 2012, we received proceeds of $250.0 million under the First Out Term Loan, and on August 6, 2012, we received the remaining proceeds of $125.0 million. We utilized the funds to repay borrowings under the Pre-Petition Credit Agreement of $25.0 million, which was originally borrowed in June 2012, pay DIP Facilities fees of $42.5 million and increase cash for general operating purposes. Letters of credit totaling $53.0 million were issued under the First Out Revolving Credit Loan to replace or backstop pre-petition letters of credit outstanding under the accounts receivable securitization program that were canceled. At December 31, 2012, letters of credit totaling $57.1 million were outstanding under the First Out Facility.

Borrowings under the First Out Facility are to be repaid on the earlier of (i) the Initial Maturity Date, which is October 4, 2013 provided that the Initial Maturity Date can be extended until December 31, 2013 subject to certain specified conditions, (ii) prepayment by Patriot of all outstanding principal and accrued but unpaid interest, (iii) the date of termination of the commitment of each lender and of the obligation of the L/C Issuers (as defined in the First Out DIP Credit Agreement) to make letter of credit extensions pursuant to the First Out DIP Credit Agreement, (iv) the date of the substantial consummation of a reorganization plan that is confirmed pursuant to an order of the Bankruptcy Court and (v) the date of dismissal of the Bankruptcy Case by the Bankruptcy Court. An extension fee of 0.25% of the Revolving Credit Commitments and Term Loans is due if we elect to extend the maturity date of the First Out Facility.

The First Out DIP Credit Agreement provides for representations and warranties by Patriot and the DIP Guarantors that are customary for facilities of this type. The First Out DIP Credit Agreement further provides for affirmative and negative covenants applicable to Patriot and its subsidiaries, including affirmative covenants requiring Patriot to provide financial information, 13-week projections and other information including, upon request, environmental or mining site assessments or audit reports to the administrative agent under the First Out DIP Credit Agreement (the First Out DIP Agent), and negative covenants restricting the ability of Patriot and its subsidiaries to incur additional indebtedness, grant liens, dispose of assets, pay dividends or take certain other actions. The First Out DIP Credit Agreement also provides financial covenants applicable to Patriot and its subsidiaries, including compliance with requirements relating to minimum consolidated EBITDA, as defined by the DIP Facilities, maximum capital expenditures and minimum liquidity.

The First Out DIP Credit Agreement provides for certain customary events of default, including events of default resulting from non-payment of principal, interest or other amounts when due, material breaches of Patriot’s and the DIP Guarantors’ representations and warranties, breaches by Patriot or the DIP Guarantors of their covenants in the First Out DIP Credit Agreement or ancillary loan documents, cross-defaults under other agreements or instruments, the entry of material judgments against Patriot or its subsidiaries, or revocation of the intercreditor and priority of payment provisions contained in the Pledge and Security and Intercreditor Agreement (as defined below). The First Out DIP Credit Agreement also includes customary events of default that may arise in connection with the Chapter 11 Petitions, including dismissal or conversion of the Debtors’ cases.

Second Out Facility and Second Out Guarantee

We entered into an Amended and Restated Superpriority Secured Debtor-in-Possession Credit Agreement dated as of July 11, 2012 (the Second Out DIP Credit Agreement). Our obligations under the Second Out DIP Credit Agreement are guaranteed by the DIP Guarantors pursuant to the Amended and Restated Guarantee (the Second Out Guarantee) dated as of July 11, 2012, made by Patriot and the DIP Guarantors in favor of the administrative agent under the Second Out DIP Credit Agreement (the Second Out DIP Agent). On July 13, 2012, the conditions precedent to closing were satisfied and the Second Out DIP Credit Agreement and the Second Out Guarantee became effective.

F-28

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Letter of credit fees under the Second Out Facility are paid at a rate equal to 4.50% per annum. The letter of credit borrowings under the Second Out Facility will bear interest at a rate per annum equal to the Eurocurrency Rate plus 8.00% or the Base Rate plus 7.00% per annum. Upon the occurrence and during the continuance of an event of default under the Second Out DIP Credit Agreement, the interest rate will increase by 2.00% per annum. On July 13, 2012, letters of credit totaling $300.8 million were continued under the Second Out Facility from the Pre-Petition Credit Agreement. At December 31, 2012, letters of credit totaling $300.7 million were outstanding under the Second Out Facility.

All letter of credit borrowings under the Second Out Facility are to be repaid on the earlier of (i) the Initial Maturity Date, which is October 4, 2013, provided that the Initial Maturity Date can be extended until December 31, 2013 subject to certain specified conditions, (ii) the date on which the obligation of the letter of credit issuers to permit the extension of the expiry date of any letter of credit is terminated upon direction from the Second Out DIP Agent in the case of an event of default, (iii) the date of the substantial consummation of a reorganization plan that is confirmed pursuant to an order of the Bankruptcy Court and (iv) the date of dismissal of the Bankruptcy Case by the Bankruptcy Court.

The Second Out DIP Credit Agreement provides for representations and warranties by Patriot and the DIP Guarantors, affirmative and negative covenants applicable to Patriot and its subsidiaries and events of default that are substantially similar to the representations, warranties, covenants and events of default under the First Out DIP Credit Agreement.

Pledge and Security and Intercreditor Agreement

On July 11, 2012, Patriot and the DIP Guarantors entered into a Debtor-in-Possession Pledge and Security and Intercreditor Agreement (the Pledge and Security and Intercreditor Agreement) with the First Out DIP Agent and Second Out DIP Agent. The obligations of Patriot and the DIP Guarantors under the DIP Facilities are secured by a lien covering substantially all of the assets, rights and properties of Patriot and the DIP Guarantors, subject to certain exceptions set forth in the Pledge and Security and Intercreditor Agreement. The Pledge and Security and Intercreditor Agreement also sets forth the seniority and priority of the respective liens on Patriot’s and the DIP Guarantors’ assets for the benefit of the lenders under the First Out Revolving Credit Loan, the First Out Term Loan and the Second Out Facility.

DIP Financing Fees

Debt issuance costs of $42.5 million were incurred and paid in connection with the DIP financing. These amounts were expensed and separately disclosed in the consolidated statement of operations for the year ended December 31, 2012.

Default of Pre-Petition Financing

The filing of the Chapter 11 Petitions constituted an event of default under the following debt agreements, each of which provided that, as a result of the event of default, all principal, interest and other amounts due thereunder became immediately due and payable:

• the Pre-Petition Credit Agreement, with respect to outstanding letters of credit in an aggregate principal amount of $300.8 million as of the Petition Date, plus accrued and unpaid interest thereon and borrowings in an aggregate principal amount of $25.0 million as of the Petition Date, plus accrued and unpaid interest thereon;

• the Indenture dated as of May 28, 2008 with respect to an aggregate principal amount of $200.0 million of 3.25% Convertible Senior Notes due 2013 (the Convertible Notes) plus accrued and unpaid interest thereon;

• the Indenture dated as of May 5, 2010 with respect to an aggregate principal amount of $250.0 million of 8.25% Senior Notes due 2018 (the Senior Notes) plus accrued and unpaid interest thereon; and

• the $125.0 million accounts receivable securitization program with respect to outstanding letters of credit in an aggregate principal amount of $51.8 million as of the Petition Date, plus accrued and unpaid interest thereon.

The ability of the creditors to seek remedies to enforce their rights under these pre-petition debt agreements was automatically stayed as a result of filing the Chapter 11 Petitions, and the creditors’ rights of enforcement became subject to the applicable provisions of the Bankruptcy Code. Due to the filing of the Chapter 11 Petitions, the Company’s pre-petition unsecured long-term debt of $458.5 million is included in “Liabilities subject to compromise” at December 31, 2012. Since July 9, 2012, the Company has not recorded interest expense on unsecured debt that is subject to compromise. Contractual interest expense on unsecured debt from July 10, 2012 through December 31, 2012 was $22.6 million.

F-29

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Pre-Petition Credit Facilities

Prior to the filing of the Chapter 11 Petitions, the Company had a $427.5 million Pre-Petition Credit Agreement, as amended and restated, with a maturity date of December 31, 2013. The Pre-Petition Credit Agreement provided for the issuance of letters of credit and direct borrowings. We incurred total fees of $10.9 million in 2010 in relation to the amended and restated agreement. These fees as well as the fees related to the initial agreement were being amortized over the remaining term of the amended and restated agreement.

Additionally, prior to the filing of the Chapter 11 Petitions, the Company had a $125.0 million accounts receivable securitization program, which provided for the issuance of letters of credit and direct borrowings. Trade accounts receivable were sold, on a revolving basis, to a wholly-owned bankruptcy-remote entity (facilitating entity), which then sold an undivided interest in all of the trade accounts receivable to the creditors as collateral for any borrowings. 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 did not receive sale accounting treatment. As such, the trade accounts receivable balances remained on our financial statements until settled. Any direct borrowings under the program were recorded as secured debt. Available liquidity under the program fluctuated with the balance of our trade accounts receivable. The outstanding trade accounts receivable balance was $171.0 million as of December 31, 2011. This program was terminated on July 11, 2012.

Senior Notes (Unsecured)

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 was being amortized over the term of the notes, resulting in additional interest expense above the contractual coupon amount. For the years ended December 31, 2012 (prior to the Petition Date), 2011 and 2010, interest expense for the senior notes was $11.0 million, $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. We do not expect to make any principal or interest payments on the notes during the pendency of the Bankruptcy Case. 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. Because the notes are unsecured, we reclassified the notes, along with unpaid interest, to liabilities subject to compromise as of the Petition Date and ceased recording interest expense.

Pursuant to their terms, 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. Pursuant to their terms, 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, subject to the provisions of the Bankruptcy Code, to accelerate payments of outstanding debt in certain circumstances.

Private Convertible Senior Notes (Unsecured)

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. 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 was being amortized over the contractual life of the convertible notes, resulting in additional

F-30

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

interest expense above the contractual coupon amount. Interest expense for the convertible notes was $8.6 million, $15.8 million and $15.1 million for the years ended December 31, 2012 (prior to the Petition Date), 2011 and 2010, respectively.

Interest on the notes is payable semi-annually in arrears on May 31 and November 30 of each year. We do not expect to make any principal or interest payments on the notes during the pendency of the Bankruptcy Case. 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. Because the notes are unsecured, we reclassified the notes, along with unpaid interest, to liabilities subject to compromise as of the Petition Date and ceased recording interest expense.

The notes were 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. The conversion rate for the notes was 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 were subject to adjustment for certain dilutive events, such as a future stock split or a distribution of a stock dividend.

Pursuant to the terms of the notes, holders 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. The automatic stay in the Bankruptcy Case prevents such an exercise by the note holders.

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 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, 2012, the remaining payments totaling $8.5 million are recorded in “Liabilities subject to compromise” on our consolidated balance sheet.

Cash interest paid on long-term debt was $23.1 million, $29.3 million and $17.7 million for the years ended December 31, 2012, 2011 and 2010, respectively.

(14) Derivatives

In connection with the Chapter 11 Petitions, we have been authorized by the Bankruptcy Court to continue performance under our pre-petition derivative contracts and to enter into and perform under post-petition derivative contracts consistent with the ordinary course of business and past practices. We utilize derivative financial instruments to manage exposure to certain commodity prices. We recognize derivative financial instruments at fair value on the consolidated balance sheets. For derivative instruments that are eligible and designated as cash flow hedges, the periodic change in fair value is recorded in “Accumulated other comprehensive loss” until the hedged transaction occurs or the relationship ceases to qualify for hedge accounting. For derivatives that are not designated as hedges, the periodic change in fair value is recorded directly to earnings in “Operating costs and expenses” in the consolidated statements of operations. In addition, if a portion of the change in fair value of 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 have commodity price risk related to our diesel fuel purchases. To manage a portion of this risk, we enter 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 have historically been highly correlated, thus allowing the swap contracts to be designated as cash flow hedges of anticipated diesel fuel purchases. We expect to purchase approximately 21 million gallons of diesel fuel across all operations in 2013. Our swap contracts related to heating oil purchases expired in 2012. As of

F-31

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

December 31, 2012, the notional amounts outstanding for our ultra low sulfur diesel swap contracts was 3.0 million gallons, all of which expire in 2013. During the fourth quarter of 2012, our outstanding contracts ceased to be highly effective due to impacts on diesel fuel prices from Hurricane Sandy. As such, we will record the change in fair value directly to earnings on a prospective basis until the contract expires or effectiveness resumes. For the years ended December 31, 2012, 2011 and 2010, the portion of the fair value for the cash flow hedges deemed ineffective was immaterial.

For the years December 31, 2012, 2011 and 2010, we recognized a net gain of $2.0 million, $4.7 million and $1.0 million in earnings on settled contracts, respectively. 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 $2.1 million.

The following table presents amounts related to our fuel derivative instruments and hedging activities included in the consolidated balance sheets. See the Consolidated Statements of Comprehensive Loss for the impact of our fuel hedges on comprehensive loss.

	December 31,
	2012		2011
	(Dollars in thousands)
Fair value of current fuel contracts (Prepaid expenses and other current assets)	$	427	$	251
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

We utilized New York Mercantile Exchange (NYMEX) quoted market prices for the fair value measurement of these contracts, which reflect a Level 2 fair value input.

(15) Risk Management and Financial Instruments

We are exposed to various types of market 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 exposure to credit risk is primarily through our customer concentrations. Our coal sales are made directly to electricity generators, industrial companies, steelmakers, coke producers and coal brokers that ultimately sell the coal to these same types of customers. Allowance for doubtful accounts was approximately $18,000 and $138,000 at December 31, 2012 and 2011, 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 had sales agreements with a marketing affiliate of Peabody. Under these agreements, we sold 3.0 million tons of coal resulting in revenues of $162.7 million for the year ended December 31, 2012; 5.6 million tons of coal resulting in revenues of $247.6 million for the year ended December 31, 2011; and 7.3 million tons of coal resulting in revenues of $356.6 million for the year ended December 31, 2010. These revenues were recorded in both the Appalachia and Illinois Basin segments. As of December 31, 2012 and 2011, “Accounts receivable and other” on our consolidated balance sheets included outstanding trade receivables from Peabody related to coal sales of $13.7 million and $22.5 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 we engage in a transaction with a counterparty that does not meet our credit standards, we will protect our accounts receivable by requiring the counterparty to provide adequate assurances. Additionally, when appropriate (as determined by our credit management function), we have requested adequate assurances 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. Adequate assurances may include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit.

F-32

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Commodity Price Risk

We have commodity price 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. In connection with the Chapter 11 Petitions, we have been authorized by the Bankruptcy Court to continue performance under our pre-petition derivative contracts and to enter into and perform under post-petition derivative contracts consistent with the ordinary course of business and past practices. 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. During the fourth quarter of 2012, our outstanding contracts ceased to be highly effective due to impacts on diesel fuel prices from Hurricane Sandy.

Employees

As of December 31, 2012, we had approximately 4,100 employees. Approximately 40% 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. In relation to the bankruptcy process and pursuant to Sections 1113 and 1114 of the Bankruptcy Code, Patriot is seeking to renegotiate the terms of collective bargaining agreements between certain Patriot subsidiaries and the UMWA, as well as certain postretirement healthcare benefits.

Fair Value of Financial Instruments

Fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. Authoritative guidance establishes a three-level fair value hierarchy for fair value to be measured based on the observability of the inputs utilized in the valuation. The levels are: Level 1 - inputs from quoted prices in an active market, Level 2 - inputs other than quoted prices that are directly or indirectly observable through market corroborated inputs and Level 3 - inputs that are unobservable and require assumptions about pricing by market participants.

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, 2012 and 2011.

	December 31,
	2012		2011
	(Dollars in thousands)
Assets:
Fuel contracts, cash flow hedges	$	427	$	363
Liabilities:
Fuel contracts, cash flow hedges	—		179
First Out Term Loan	378,750		—
$200 million of 3.25% Convertible Senior notes due 2013	24,250		183,000
$250 million of 8.25% Senior notes due 2018	118,750		239,468

All of the instruments above were valued using Level 2 inputs. For additional disclosures regarding our fuel contracts, see Note 14. We utilized NYMEX quoted market prices for the fair value measurement of these contracts, which reflects a Level 2 input. The fair value of the First Out Term Loan, Convertible Notes and the Senior Notes was estimated using the last traded value on the last day of each period, as provided by a third party.

F-33

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(16) Asset Retirement Obligations

Reconciliations of our liability for asset retirement obligations were as follows:

	December 31, 2012
	Reclamation Obligations			Selenium Water Treatment Obligations			Total
	(Dollars in thousands)
Balance at beginning of year	$	292,050		$	195,991		$	488,041
Liabilities incurred	2,695			—			2,695
Liabilities settled or disposed	(46,843		)	(43,563		)	(90,406		)
Accretion expense	26,082			32,286			58,368
Revisions to estimate	14,632			258,306			272,938
Total asset retirement obligations	288,616			443,020			731,636
Less current portion (included in Accrued expenses)	—			(11,175		)	(11,175		)
Asset retirement obligations at end of year	$	288,616		$	431,845		$	720,461

	December 31, 2011
	Reclamation Obligations			Selenium Water Treatment Obligations			Total
	(Dollars in thousands)
Balance at beginning of year	$	254,140		$	163,942		$	418,082
Liabilities incurred	23,817			—			23,817
Liabilities settled or disposed	(13,786		)	(22,138		)	(35,924		)
Accretion expense	25,006			18,126			43,132
Revisions to estimate	2,873			36,061			38,934
Total asset retirement obligations	292,050			195,991			488,041
Less current portion (included in Accrued expenses)	—			(63,067		)	(63,067		)
Asset retirement obligations at end of year	$	292,050		$	132,924		$	424,974

As of December 31, 2012, reclamation obligations of $288.6 million included $130.4 million related to locations that are closed or inactive. As of December 31, 2011, reclamation obligations of $292.1 million included $99.4 million related to locations that are closed or inactive. The interest rates used to calculate our reclamation obligations at January 1, 2012 and 2011 were 8.63% and 8.37%, respectively.

At December 31, 2012, the Company’s liability related to selenium water treatment was $443.0 million, $1.5 billion on an undiscounted basis. The expected payments for these obligations are $10.9 million, $31.4 million, $15.4 million, $24.9 million, $46.3 million and $314.1 million in 2013, 2014, 2015, 2016, 2017 and thereafter, respectively. The interest rates used to calculate this obligation were 7.30% (installation costs) and 9.70% (operating costs). During the second quarter of 2012, we increased our selenium water treatment liability by $307.4 million to recognize the modification to our compliance plan from installing and operating Zero Valent Iron (ZVI) technology to installing and operating Iron Facilitated Selenium Reduction (IFSeR) technology at the Category 1-5 outfalls. In the fourth quarter of 2012, we recorded an adjustment to decrease our selenium water treatment liability by $49.1 million ($17.6 million related to optimizations made to the operational design of the IFSeR technology system and $31.5 million related to delaying the specified deadlines and the corresponding cash spending). During the year ended December 31, 2011, asset retirement obligation expense included a $38.3 million charge due to changes in our selenium water treatment technology selection for the Hobet Surface Mine No. 22 outfall and $9.9 million in relation to a comprehensive consent decree. See Note 22 for further background on our selenium water treatment obligations and related lawsuits.

As of December 31, 2012, we had $354.5 million in surety bonds and letters of credit outstanding to secure our asset retirement obligations.

F-34

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(17) 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,
	2012			2011			2010
	(Dollars in thousands)
Service cost	$	7,499		$	7,496		$	9,258
Interest cost	9,507			9,492			8,963
Net amortization of actuarial gains	(1,411		)	(2,070		)	(3,003		)
Total occupational disease	15,595			14,918			15,218
Traumatic injury claims	18,066			22,959			20,944
State assessment taxes	1,457			1,893			2,029
Total provision	$	35,118		$	39,770		$	38,191

The weighted-average assumptions used to determine the workers’ compensation expense were as follows:

	Year Ended December 31,
	2012		2011		2010
Discount rate:
Occupational disease	5.13	%	5.46	%	5.90	%
Traumatic injury	4.47	%	4.54	%	4.80	%
Inflation rate	3.00	%	3.00	%	3.00	%

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.

The workers’ compensation obligations consisted of the following:

	December 31,
	2012			2011
	(Dollars in thousands)
Occupational disease costs	$	204,631		$	185,639
Traumatic injury claims	74,463			72,653
Total obligations	279,094			258,292
Less current portion (included in Accrued expenses)	(24,414		)	(26,707		)
Noncurrent obligations (included in Workers’ compensation obligations)	$	254,680		$	231,585

The accrued workers’ compensation liability recorded on the consolidated balance sheets at December 31, 2012 and 2011 reflects the accumulated benefit obligation less any portion that is currently funded. The accumulated actuarial loss of $2.0 million that has not yet been reflected in the workers’ compensation provision is included in “Accumulated other comprehensive loss” within Stockholders’ equity (deficit) on the consolidated balance sheet at December 31, 2012.

As of December 31, 2012, we had $132.6 million in surety bonds and letters of credit outstanding to secure workers’ compensation obligations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The reconciliation of changes in the occupational disease obligation is as follows:

	December 31,
	2012			2011
	(Dollars in thousands)
Change in benefit obligation:
Beginning of year obligation	$	185,639		$	174,014
Service cost	7,499			7,496
Interest cost	9,507			9,492
Net change in actuarial gain	9,580			3,536
Benefit and administrative payments	(7,594		)	(8,899		)
Net obligation at end of year	204,631			185,639
Change in plan assets:
Fair value of plan assets at beginning of year	—			—
Employer contributions	7,594			8,899
Benefits paid	(7,594		)	(8,899		)
Fair value of plan assets at end of year	—			—
Obligation at end of year	$	204,631		$	185,639

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 4.4% and 5.1% at December 31, 2012 and 2011, respectively. Traumatic injury workers’ compensation obligations are estimated from both case reserves and actuarial determinations of historical trends, discounted at 3.7% and 4.5% as of December 31, 2012 and 2011, respectively.

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 and is funded by an excise tax on coal production sold to U.S. customers. The excise tax is $1.10 per ton for underground mines and $0.55 per ton for surface mines, neither amount to exceed 4.4% of the gross sales price.

(18) 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.

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, impacting our costs to provide healthcare benefits to our eligible active and certain retired employees.

Many of the plan standard changes have taken effect and estimates of the impact of these changes on our postretirement benefit obligation have been incorporated into the actuarial valuation. 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 obligations. 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 obligations. We will continue to evaluate the impact of the 2010 Healthcare Legislation in future periods as additional information and guidance become available.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Net periodic postretirement benefit costs included the following components:

	Year Ended December 31,
	2012			2011			2010
	(Dollars in thousands)
Service cost for benefits earned	$	5,530		$	5,609		$	5,695
Interest cost on accumulated postretirement benefit obligation	72,830			77,076			75,821
Amortization of actuarial losses	56,026			43,134			36,533
Amortization of prior service credit	(809		)	(809		)	(809		)
Curtailment loss recognized	1,014			—			—
Net periodic postretirement benefit costs	$	134,591		$	125,010		$	117,240

The following table sets forth the plan’s funded status reconciled with the amounts shown in the consolidated balance sheets:

	December 31,
	2012			2011
	(Dollars in thousands)
Change in benefit obligation:
Accumulated postretirement benefit obligation at beginning of period	$	1,468,763		$	1,334,759
Service cost	5,530			5,609
Interest cost	72,830			77,076
Participant contributions	968			1,218
Plan amendment	(7,955		)	—
Plan curtailments	1,808			—
Benefits paid	(77,246		)	(67,356		)
Change in actuarial loss	147,991			117,457
Accumulated postretirement benefit obligation at end of period	1,612,689			1,468,763
Change in plan assets:
Fair value of plan assets at beginning of period	—			—
Employer contributions	76,278			66,138
Participant contributions	968			1,218
Benefits paid and administrative fees (net of Medicare Part D reimbursements)	(77,246		)	(67,356		)
Fair value of plan assets at end of period	—			—
Postretirement benefit obligation	1,612,689			1,468,763
Less current portion (included in Accrued expenses)	(7,600		)	(81,446		)
Less liabilities subject to compromise portion	(1,517,284		)	—
Noncurrent obligation (included in Postretirement benefit obligations)	$	87,805		$	1,387,317

In relation to the bankruptcy process and pursuant to Sections 1113 and 1114 of the Bankruptcy Code, Patriot is seeking to renegotiate the terms of collective bargaining agreements between certain Patriot subsidiaries and the UMWA, as well as certain postretirement healthcare benefits. Patriot also intends to terminate certain non-union and salaried healthcare and postemployment plans. As such, we have classified the liabilities associated with these plans as “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2012. Until resolved through the bankruptcy process, Patriot continues to pay claims and recognize expense under the existing plan provisions. The liability related to healthcare coverage under the Coal Act is not subject to compromise and is classified as such.

The accrued postretirement benefit liability recorded on the consolidated balance sheets at December 31, 2012 and 2011 reflects the accumulated postretirement benefit obligation less any portion that is currently funded. The accumulated actuarial loss and prior service credit gain of $488.1 million and $10.4 million, respectively, that have not yet been reflected

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

in net periodic postretirement benefit costs are included in “Accumulated other comprehensive loss” within Stockholders’ equity (deficit) on the consolidated balance sheet at December 31, 2012.

The plan amendment relates to converting medical coverage for the Coal Act participants to an insured plan, effective January 1, 2013. The increases in the actuarial loss in 2012 and 2011 were primarily due to a lower discount rate.

We amortize actuarial gains and losses using a 0% corridor with an amortization period that covers the average remaining service period of active employees (7.07 years, 7.46 years and 7.55 years utilized for 2012, 2011 and 2010, respectively). For the year ending December 31, 2013, an estimated actuarial loss of $80.3 million and an estimated gain from prior service credit of $1.6 million will be amortized from accumulated comprehensive loss into net periodic postretirement costs.

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:

	Year Ended December 31,
	2012	2011
Discount rate	4.33%	5.10%
Rate of compensation increase	3.50%	3.50%
Measurement date	December 31, 2012	December 31, 2011

The weighted-average assumptions used to determine net periodic benefit cost were as follows:

	Year Ended December 31,
	2012	2011	2010
Discount rate	5.10%	5.92%	6.30%
Rate of compensation increase	3.50%	3.50%	3.50%
Measurement date	December 31, 2011	December 31, 2010	December 31, 2009

The following presents information about the assumed healthcare cost trend rate:

	Year Ended December 31,
	2012	2011
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	2019	2018

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	$	10,636	$	(8,811	)
Effect on year-end postretirement benefit obligation	215,770		(179,134		)

Plan Assets

Our postretirement benefit plans are unfunded.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Estimated Future Benefits Payments

The following benefit payments (net of retiree contributions), which reflect expected future service, as appropriate, are expected to be paid by Patriot:

	Postretirement Benefit Payments
	(Dollars in thousands)
2013	$	86,976
2014	91,761
2015	96,341
2016	98,824
2017	100,674
2018 - 2022	516,465

Assumption of Certain Patriot Liabilities

Peabody assumed certain of our retiree healthcare liabilities at the spin-off, which had a present value of $637.6 million as of December 31, 2012 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 $8.8 million in 2013 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, which are not subject to compromise under the Chapter 11 Petitions. The noncurrent portion related to these obligations was $34.3 million and $35.4 million as of December 31, 2012 and 2011, 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 $5.0 million and $5.4 million as of December 31, 2012 and 2011, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Expenses and payments related to the Combined Fund are as follows:

	Year Ended December 31,
	2012		2011			2010
	(Dollars in thousands)
Interest cost	$	1,716	$	2,208		$	2,592
Actuarial loss (gain)	366		(60		)	600
Total expense related to Combined Fund	$	2,082	$	2,148		$	3,192
Benefits paid	$	4,969	$	5,426		$	5,961

The obligation to industry fund recorded on the consolidated balance sheets at December 31, 2012 and 2011 reflects the obligation less any portion that is currently funded. The accumulated actuarial loss that has not yet been reflected in expense was $2.4 million as of December 31, 2012 and included in “Accumulated other comprehensive loss” within Stockholders’ equity (deficit) on the consolidated balance sheet.

A portion of these funds qualifies as multi-employer benefit plans, which allows us to recognize expense as contributions are made. The expense related to these funds was $4.0 million, $2.5 million and $10.0 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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.

(19) Multi-Employer Pension Plans

Certain subsidiaries participate in the 1974 Plan. The 1974 Plan is a multi-employer pension plan, which provides defined benefits to a majority of the hourly coal production workers represented by the UMWA. The assets of the 1974 Plan are managed by the UMWA. Benefits under the UMWA plan are computed based on service with our relevant subsidiaries or other signatory employers. The 1974 Plan qualifies as a multi-employer benefit plan, allowing us to recognize expense as contributions are made. The expense related to this plan was $20.8 million, $24.3 million and $21.0 million for the years ended December 31, 2012, 2011 and 2010, respectively. We expect to make contributions of approximately $19 million to the 1974 Plan in 2013.

The 1974 Plan’s Employer Identification Number is 52-1050282. 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 of the 1974 Plan at $5.50 per hour for certain UMWA workers. Our subsidiaries with UMWA-represented employees are required to contribute to the 1974 Plan.

In relation to the bankruptcy process and pursuant to Section 1113 of the Bankruptcy Code, Patriot is seeking to renegotiate the terms of collective bargaining agreements between certain Patriot subsidiaries and the UMWA, which may affect our future participation in the 1974 Plan.

The 1974 Plan is considered to be in “Seriously Endangered Status” for the plan year beginning in July 2011 (the 2011 Plan Year). That status is the result of the 1974 Plan funded percentages being less than 80% and because the 1974 Plan is projected to have an accumulated deficiency within six years after the 2011 Plan Year. As a result, a funding improvement plan was adopted by the 1974 Plan as of May 25, 2012, which would require increased contributions to the 1974 Plan after a new UMWA collective bargaining agreement is negotiated in 2016. Under the funding improvement plan, the hourly contribution rate would increase in stages from a minimum of $12.50 in 2017 to a maximum potential rate of $26.50 as early as 2022. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

New inexperienced miners hired after January 1, 2012 do not participate in the 1974 Plan. Instead, for each hour worked, the Company contributes $1.00 into the UMWA Cash Deferral Plan on the employee’s behalf, increasing to $1.50 on January 1, 2014. Effective January 1, 2012, employers also pay $1.50 per hour to a new Retiree Bonus Account Trust (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. 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 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 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.

(20) 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. We recognized 401(k) plan expense of $11.4 million, $10.8 million and $7.9 million for the years ended December 31, 2012, 2011 and 2010, respectively. In addition, a performance contribution feature under the 401(k) Plan allows for additional contributions based upon meeting specified performance targets. There were no such contributions for the year ended December 31, 2012; however, we recognized additional expense of $2.3 million and $7.2 million under this feature for the years ended December 31, 2011 and 2010, respectively.

(21) Guarantees

During 2012, we posted collateral for letters of credit under the DIP Facilities, resulting in $50.0 million in interest-bearing deposits. During 2011, Patriot posted a $15.0 million interest-bearing deposit with the U.S. Department of Labor (DOL) as collateral for occupational disease (black lung) workers’ compensation obligations related to certain of our subsidiaries. These deposits are recorded to “Cash collateralization deposits” on the accompanying consolidated balance sheets.

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, 2012:

	Asset Retirement Obligations		Workers’ Compensation Obligations		Retiree Health Obligations		Other(1)		Total
	(Dollars in thousands)
Surety bonds	$	192,188	$	—	$	—	$	9,134	$	201,322
Letters of credit	162,291		132,565		54,412		8,467		357,735
Third-party guarantees	—		—		—		5,873		5,873
	$	354,479	$	132,565	$	54,412	$	23,474	$	564,930

⁽¹⁾ Includes collateral for surety companies and bank guarantees, road maintenance, lease obligations and performance guarantees.

As of December 31, 2012, Arch Coal Company (Arch) posted surety bonds of $34.3 million related to properties acquired by Patriot in the Magnum acquisition, of which $33.1 million related to reclamation. Magnum posted a letter of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

credit in Arch’s favor, as required, for a portion of the outstanding reclamation bonds. As part of the bankruptcy proceedings, our prior surety agreement with Arch was terminated and replaced with a new surety agreement.

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 $0.1 million as of December 31, 2012. 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.

(22) Commitments and Contingencies

The Bankruptcy Case

On July 9, 2012, the Debtors filed voluntary petitions for reorganization under the Bankruptcy Code in the Bankruptcy Court. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As a result of the Chapter 11 Petitions, much of the pending litigation against the Debtors is stayed. Subject to certain exceptions and approval by the Bankruptcy Court, during the Chapter 11 process, no party can take further actions to recover pre-petition claims against the Debtors.

Commitments

As of December 31, 2012, purchase commitments for equipment totaled $26.0 million primarily related to longwall equipment replacements and capital rebuilds at our Highland mining complex.

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 U.S. 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. States are empowered to develop and enforce water quality standards, which are subject to change and must be approved by the U.S. Environmental Protection Agency (EPA). Water quality standards vary from state to state.

Patriot assumed obligations related to the discharge of selenium in excess of allowable limits at certain mining operations as part of the Magnum acquisition in July 2008. We had estimated the costs to treat the selenium discharges in excess of allowable limits at fair value at the acquisition date and continue to adjust these amounts as our treatment plans change. At the time of the acquisition, selenium discharge limits were first being added and becoming effective in our NPDES permits as the permits were being renewed. On an industry-wide basis, there was no proven technology to effectively treat selenium in coal mining discharges to the levels required. Existing technology continues to evolve and new technologies are being considered for the treatment of selenium discharges in excess of allowable limits. Additionally, 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 require us to, among other things, meet certain compliance deadlines. As of December 31, 2012, the liability related to selenium water treatment at outfalls with known exceedances was $443.0 million and reflects the estimated costs of the planned technology selections to be

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

implemented and maintained at these operations. Further discussed below are the lawsuits in which we are involved, the various rulings and settlements related to these lawsuits, and the continued uncertainties related to the identification, implementation and cost of effective technologies.

At December 31, 2012, environmental claims and litigation in connection with our various NPDES permits and related CWA requirements included the following:

Hobet West Virginia Department of Environmental Protection (WVDEP) Action

In 2007, Hobet Mining, LLC (Hobet), one of our subsidiaries, was sued for exceedances of effluent limits contained in four of its NPDES permits in state court in Boone County, West Virginia by the WVDEP. We refer to this case as the Hobet WVDEP Action. This action addressed all effluent limits, including selenium, established by the permits. We entered into a settlement and consent order with the WVDEP, as subsequently modified, to extend coverage to two additional permits, achieve full compliance with the WVDEP permits by July 2012 and to study potential treatment alternatives for selenium. One of the permits, for Hobet Surface Mine No. 22, was subsequently addressed as discussed below.

In May 2012, WVDEP and Hobet jointly requested an extension of the July 2012 compliance date while further refinements to the consent decree were discussed. The Boone County Circuit Court has extended the compliance date while those discussions are ongoing.

Federal Apogee Case and Federal Hobet Case

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

In 2008, OVEC and another environmental group filed a lawsuit against Hobet and WVDEP in the U.S. District Court (pursuant to the citizen suit provisions of the CWA). We refer to this case as the Federal Hobet Case and it is very similar to the Federal Apogee Case. Additionally, the Federal Hobet Case involved four NPDES permits that were the subject of the 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 the below discussion of the September 1, 2010 U.S. District Court Ruling for a description of 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 had in the past violated, and continued to violate, effluent limitations for selenium in a 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 U.S. District Court hearing that began on August 9, 2010. See the below discussion of the September 1, 2010 U.S. District Court Ruling for a description of the outcome of this hearing.

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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 in West Virginia. We refer to this case as the Catenary WVDEP Action. This lawsuit alleged that Catenary had discharged selenium from its surface mining operations in violation of certain of its NPDES and surface mining permits. WVDEP sought fines and penalties as well as injunctions prohibiting Catenary from discharging pollutants, including selenium, in violation of laws and NPDES permits. The Catenary WVDEP Action was consolidated with the Hobet WVDEP Action. The permits contained in the Catenary WVDEP Action are also included in the February 2011 Litigation discussed below.

On June 11, 2010, WVDEP filed a lawsuit against Apogee in the Logan County Circuit Court in West Virginia, 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 Apogee WVDEP Action are also included in the February 2011 Litigation discussed below. WVDEP is seeking fines and penalties as well as injunctions prohibiting Apogee from discharging pollutants, including selenium, in violation of laws and NPDES permits. No trial date is currently scheduled in the Apogee WVDEP Action and we remain engaged with the WVDEP regarding resolution of the Apogee WVDEP Action. The compliance deadline for outfalls covered by these lawsuits was addressed in the January 2012 comprehensive consent decree and subsequent modification, and we are taking steps to resolve these lawsuits on terms that are not inconsistent with the comprehensive consent decree, as amended by the December 2012 modification described below.

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, 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. See the below discussion of the January 2012 comprehensive consent decree for a description of the resolution to this matter.

Rulings and Settlements Related to Environmental Claims

Discussed below are the outcomes of certain of these proceedings as well as negotiations stemming from these lawsuits:

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 $69.5 million ($48.8 million related to installation costs and $20.7 million related to operating costs) for the fair value of the estimated costs related to these three outfalls. This charge was reflected in “Asset retirement obligation expense” in the consolidated statement of operations. We began construction on the Apogee FBR facility in the third quarter of 2011. As of December 31, 2012, the construction of the FBR facility is substantially complete and the testing phase of the installation is nearing completion. As of December 31, 2012, we have spent approximately $42.5 million on the Apogee FBR facility and the total expenditures are estimated to be approximately $48.0 million.

As part of this ruling, the U.S. District Court ordered Hobet to submit a proposed schedule to develop a treatment plan for the 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. As part of this process, 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 utilize an Advanced Biological Metals Removal System (ABMet) selenium treatment technology at this outfall. The U.S. District Court subsequently confirmed this technology. In 2011, we increased the selenium water treatment liability by $35.0 million ($21.3 million related to installation costs and $13.7 million related to operating costs) related to the fair value of the estimated costs of the ABMet water treatment facility at this outfall. This charge was reflected in “Asset retirement obligation expense” in the consolidated statement of operations. We began construction on the facility in the second quarter of 2012. As of December 31, 2012, we have spent approximately $5.6 million on the Hobet ABMet water treatment facility and total expenditures are estimated to be approximately $25.0 million.

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January 2012 Comprehensive Consent Decree

On January 18, 2012, we finalized a comprehensive consent decree with OVEC and the other environmental groups to resolve the February 2011 Litigation. The comprehensive consent decree was approved by the U.S. District Court and became effective on March 15, 2012. The comprehensive consent decree set 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.

The comprehensive consent decree separated 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. Additionally, as subsequently amended in December 2012, 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 by March 15, 2015 and ending with the last category by March 15, 2018. We also agreed to waive our rights to mine certain coal reserves and to pay $7.5 million in civil penalties. The comprehensive consent decree was determined to be a recognized subsequent event and the civil penalties paid per the agreement of approximately $7.5 million and the write-off of the forfeited coal reserves of approximately $2.3 million were reflected in “Asset retirement obligation expense” in our consolidated statement of operations at December 31, 2011.

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 the following framework under which we will interface with the plaintiffs with respect to the identified permits and outfalls:

Category/Gallons Per Minute	Technology Selection Date	Specified Compliance Date
I / 0-200	September 1, 2012	March 15, 2014
II / 201-400	December 31, 2012	March 15, 2015
III / 401-600	March 31, 2013	December 15, 2015
IV / 601-1000	September 1, 2013	May 15, 2016
V / 1000 +	September 1, 2014	March 15, 2017

The December 2012 Settlement and Consent Modification, as discussed more fully below, subsequently extended each of the technology selection and specified compliance deadlines by 12 months.

The comprehensive consent decree required that we select water treatment technology by category beginning with the first category in September 2012. We performed pilot testing on IFSeR technology in early 2012 and concluded the testing in May 2012. In May 2012, related to the January 2012 comprehensive consent decree, we submitted IFSeR technology to the Special Master for review and approval. The Special Master certified that IFSeR may be considered as a listed technology for Category 1 outfalls.

Prior to the second quarter of 2012, the liability to treat selenium discharges at outfalls not addressed in the September 1, 2010 U.S. District Court Ruling continued to be based on the use of the ZVI technology as there was no other definitive plan to install any technology other than ZVI. During the second quarter of 2012, we modified our selenium water treatment compliance plan from ZVI technology to IFSeR technology. IFSeR was developed in response to our need to resolve certain detailed design considerations for ZVI technology. While ZVI water treatment systems decreased selenium discharges, they had not performed consistently in reducing selenium concentrations to compliant levels. IFSeR incorporated various design enhancements including utilizing ZVI media in a different configuration than the original ZVI water treatment technology. We recorded an adjustment to increase our selenium water treatment liability by $307.4 million during the second quarter of 2012 to recognize the modification to our compliance plan from installing and operating ZVI technology to installing and operating IFSeR technology. This adjustment was based upon estimates for the installation and operating costs of IFSeR water treatment systems at the Category 1-5 outfalls.

In the fourth quarter of 2012, we recorded an adjustment to decrease our selenium water treatment liability by $49.1 million in total, $17.6 million of which related to optimizations made to the operational design of the IFSeR technology system. The remaining $31.5 million adjustment is discussed below as part of our December 2012 settlement. We continue to refine the IFSeR treatment systems to obtain the most effective selenium removal in the most cost-effective manner and will adjust the liability in the future as necessary.

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December 2012 Settlement and Consent Modification

In December 2012, the Bankruptcy Court and the U.S. District Court approved an agreement between Patriot and OVEC and other environmental groups to extend the Hobet Surface Mine No. 22 outfall compliance date to August 1, 2014. In addition, a 12-month extension of each of the technology selection and specified compliance dates in the January 2012 comprehensive consent decree was approved. Extension of the deadlines allows us to defer spending and maintain liquidity during the bankruptcy proceedings and provides additional time for alternative treatment technologies and solutions to develop. In the fourth quarter of 2012, we recorded a $31.5 million adjustment to decrease our selenium water treatment liability due to the impact of delaying the specified deadlines and the corresponding cash spending. The U.S. District Court separately entered an order extending the Hobet Surface Mine No. 22 outfall compliance date to August 1, 2014 in December 2012 and the modification to the comprehensive consent decree in January 2013.

As part of the settlement, we agreed to, among other things, impose interim caps on surface mining coal production beginning in 2014 leading to a permanent annual cap beginning in 2018; retire our Paint Creek surface mine dragline in 2013 and our Hobet surface mine dragline in 2015; and refrain from certain new large-scale surface mining operations. We performed a full assessment of our coal reserves to determine if the restrictions on certain types of mining would prevent us from mining any of our coal reserves. This assessment indicated that the existing coal reserves are likely accessible through mining techniques that are not impacted by the settlement and as such, no impairment charge was recorded.

Continued Uncertainties Related to Selenium Water Treatment Obligations

Prior to our pilot project performed in 2010, FBR technology required under the September 1, 2010 U.S. District Court Ruling had not been used to remove selenium or any other minerals discharged at coal mining operations, but had been successful in other industrial applications. The FBR water treatment facility will be the first facility constructed for selenium removal on a commercial scale. Neither the FBR technology nor ABMet technology to be utilized at the Hobet Surface Mine No. 22 outfall 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.

On September 1, 2012, we provisionally selected the IFSeR technology for all of our Category 1 outfalls. To date, IFSeR technology has not been proven to achieve effluent selenium limitations for the water flows at outfalls other than Category 1. There is significant uncertainty as to which technology, if any, could be utilized to achieve compliance at the other four categories, particularly those with higher average water flows. However, IFSeR technology is currently the treatment technology that is best adapted for installation and operation under the various site-specific conditions at our outfalls.

If IFSeR 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 may be required to install alternative treatment solutions. Alternative technology solutions that we may ultimately select are still in the early phases of development and their related costs cannot be reasonably estimated at this time. The cost of other water treatment solutions could be materially different than the costs reflected in our liability. Furthermore, costs associated with potential modifications to IFSeR or the scale of our current IFSeR systems could also cause the costs to be materially different 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. Potential installations of selenium treatment alternatives are further complicated by the variable geological, topographical and water flow 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 for outfalls covered by the Hobet WVDEP Action and the February 2011 Litigation. 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, modifications pursuant 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 to which we are subject.

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, or an inability to obtain new permits or to maintain existing permits, which could impact our ability to mine our

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coal reserves, and the imposition 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.

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 effect on our financial condition, results of operations and cash flows.

We may incur additional costs relating to the lawsuits discussed above, 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, permits may not be issued.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)

CERCLA and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to natural resources. Under CERCLA and many similar state statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault. These laws and related regulations could require us to do some or all of the following: (i) remove or mitigate the effects of the disposal or release of certain substances on the environment at various sites; (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 and 31, 2004 and June 4, 2004 in the Island Creek watershed of southern West Virginia. This litigation is pending before two different judges in the Circuit Court of Logan County, West Virginia. In one action, the plaintiffs assert 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 filed motions to dismiss, which were granted with respect to general factual allegations, generic claims, claims of strict liability and fraud and claims asserted by plaintiffs from certain localities. In the second action, in which plaintiffs allege that Hobet and Catenary engaged in extensive land altering activities that disturbed hydraulic balance, increased peak flow and surface runoff, and blocked natural drains, Hobet and Catenary filed motions to dismiss, asserting that the plaintiffs’ allegations are conclusory in nature and likely deficient as a matter of law. Most of the other defendants also filed motions to dismiss. The litigation of both actions are stayed due to the bankruptcy of one or more defendants. 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

Certain Patriot directors and officers have been named as defendants in various lawsuits filed in the U.S. District Court in the Eastern District of Missouri. In June 2012, a shareholder filed a derivative lawsuit for the benefit of Patriot against each of the then directors of Patriot and Patriot as a nominal defendant. This lawsuit was administratively closed due to the Bankruptcy Case. During the second half of 2012 and subsequent to the filing of the Chapter 11 Petitions, three class action complaints were filed against a former Chief Executive Officer, Richard M. Whiting, and former Chief Financial Officer, Mark N. Schroeder (the Class Action Complaints). The Class Action Complaints contain nearly identical allegations including that the defendants made or allowed false and misleading statements related to Patriot’s selenium water treatment

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liability and Patriot’s financial condition. The Class Action Complaints were consolidated and a lead plaintiff was appointed during January 2013. The Class Action Complaints can proceed during the pendency of the Bankruptcy Case as Patriot was not named as a defendant.

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. 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, 2012, 51 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.

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.

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 January 2012, the terminated employee filed a civil lawsuit against us alleging retaliatory discharge and intentional infliction of emotional distress. Additionally, in January 2012, 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 are vigorously defending both civil lawsuits and the potential impact of these lawsuits cannot be estimated at this time. Both civil lawsuits are currently stayed due to the bankruptcy of one or more defendants.

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.

(23) 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.

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	Year Ended December 31,
	2012			2011			2010
(% of total sales volume - tons)
Sales to electricity generators	75		%	76		%	78		%
Sales to steel & coke producers	25		%	24		%	22		%
Export sales	45		%	29		%	20		%
(Dollars in thousands)
Revenues attributable to foreign countries, based on where product was shipped	$	851,046		$	952,260		$	555,000

For the years ended December 31, 2012, 2011 and 2010, there were no material revenues attributed to any individual foreign country for which we can determine the final destination of the shipment. For certain sales made in 2012 through third-party arrangements, it is impracticable to determine sales by 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.

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; depreciation, depletion and amortization; asset retirement obligation expense; sales contract accretion; impairment and restructuring charge; DIP financing fees; and reorganization items. Segment Adjusted EBITDA is calculated the same as Adjusted EBITDA but excludes “Corporate and Other” as defined below. 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.

“Corporate and Other” in the tables below includes selling and administrative expenses, net gain on disposal or exchange of assets and costs associated with past mining obligations.

Operating segment results for the year ended December 31, 2012 were as follows:

	Appalachia		Illinois Basin		Corporate and Other			Total
	(Dollars in thousands)
Revenues	$	1,604,217	$	318,455	$	—		$	1,922,672
Adjusted EBITDA	288,979		40,784		(232,846		)	96,917
Additions to property, plant, equipment and mine development	119,060		20,074		5			139,139
Income from equity affiliates	85		—		—			85

Operating segment results for the year ended December 31, 2011 were as follows:

	Appalachia		Illinois Basin			Corporate and Other			Total
	(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	146,272		15,929			764			162,965
Income from equity affiliates	4,709		—			—			4,709

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Operating segment results for the year ended December 31, 2010 were as follows:

	Appalachia		Illinois Basin		Corporate and Other			Total
	(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	96,844		23,379		1,708			121,931
Income from equity affiliates	9,476		—		—			9,476

A reconciliation of Adjusted EBITDA to net loss follows:

	Year Ended December 31,
	2012			2011			2010
	(Dollars in thousands)
Adjusted EBITDA	$	96,917		$	176,741		$	141,861
Depreciation, depletion and amortization	(185,001		)	(186,348		)	(188,074		)
Asset retirement obligation expense	(354,590		)	(105,232		)	(112,697		)
Sales contract accretion	11,628			55,020			121,475
Impairment and restructuring charge	(61,278		)	(13,657		)	(15,174		)
Interest expense and other	(60,069		)	(65,533		)	(57,419		)
DIP financing fees	(42,540		)	—			—
Interest income	189			246			12,831
Reorganization items, net	(135,864		)	—			—
Income tax benefit (provision)	14			(372		)	(492		)
Net loss	$	(730,594	)	$	(139,135	)	$	(97,689	)

(24) 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.

As we are in Chapter 11 proceedings, we are prohibited from paying dividends. Prior to the Petition Date, we had not paid any cash dividends on our common stock. 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.

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The following table summarizes common stock activity from January 1, 2010 to December 31, 2012:

	2012	2011	2010
Shares outstanding at the beginning of the year	91,885,338	90,944,595	90,319,939
Stock options exercised	—	23,000	61,097
Stock grants to employees	517,418	758,096	259,458
Employee stock purchases	129,160	159,647	304,101
Shares outstanding at the end of the year	92,531,916	91,885,338	90,944,595

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, 2012 and 2011.

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.

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, 2012 and 2011.

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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, 2009	$	(255,902	)	$	5,691		$	1,035		$	(249,176	)
Unrealized gains (losses)	(95,801		)	—			1,855			(93,946		)
Reclassification from other comprehensive income (loss) 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 (loss) to earnings	43,368			(809		)	(4,744		)	37,815
December 31, 2011	(389,287		)	4,073			184			(385,030		)
Unrealized gains (losses)	(151,692		)	—			2,213			(149,479		)
Reclassification from other comprehensive income (loss) to earnings	48,512			6,350			(1,970		)	52,892
December 31, 2012	$	(492,467	)	$	10,423		$	427		$	(481,617	)

Comprehensive loss differs from net 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.

(25) Stock-Based Compensation

We have an equity incentive plan for employees and eligible non-employee directors that allowed for the issuance of stock-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 were eligible for deferred stock unit grants on the date of their initial election and annually.

Due to the bankruptcy proceedings, there is significant uncertainty regarding the value of our equity securities, including our common stock and any related stock-based awards. Under the priority rankings established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition and post-petition liabilities must be satisfied in full before stockholders are entitled to receive any distribution or retain any property under a plan of reorganization. Patriot has suspended its equity incentive plan and a majority of the awards granted thereunder. Patriot has not granted any additional equity awards since the Petition Date, and will not grant any equity awards while in bankruptcy.

The equity incentive plan has 11.7 million shares of our common stock available for grant, with 6.5 million shares remaining available for grant as of December 31, 2012. 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 1.5 million shares available for grant as of December 31, 2012. This plan has also been suspended.

Despite the significant uncertainty in relation to the value of stock-based awards, we continue to recognize the expense for nonvested awards based on applicable accounting guidance. Stock-based compensation expense of $0.2 million, $12.4 million and $10.7 million was recorded in “Selling and administrative expenses” in the consolidated statements of operations for the years ended December 31, 2012, 2011 and 2010, respectively, and less than $0.1 million, $1.4 million and $1.2 million was recorded in “Operating costs and expenses” for the years ended December 31, 2012, 2011 and 2010, respectively. During the years ended December 31, 2011 and 2010, stock-based compensation expense included $0.1 million and $0.5 million, respectively, related to awards from restricted stock and stock options granted by Peabody to Patriot employees

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PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

prior to the spin-off. As of December 31, 2012, the total unrecognized compensation cost related to nonvested awards was $7.6 million, net of taxes, which is expected to be recognized over a weighted-average period of 1.5 years.

Restricted Stock Awards

We have restricted stock award agreements in place for grants to employees, all of which were entered into prior to the Petition Date. 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 incentive plan. Restricted stock grants are treated as transfers of property rather than a contractual right to receive stock in the future and, therefore, will continue to vest and be distributed as scheduled.

A summary of restricted stock award activity is as follows:

	Year Ended December 31, 2012		Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2012	1,111,207		$	12.68
Granted	1,134,478		9.08
Forfeited	(377,667	)	11.37
Vested	(763,556	)	9.60
Nonvested at December 31, 2012	1,104,462		11.56

Restricted Stock Units

We have long-term incentive restricted stock unit agreements in place for grants to employees, all of which were entered into prior to the Petition Date. These agreements grant restricted stock units that vest over time as well as restricted stock units that vest based upon our financial performance. Restricted stock units that vest over time and were granted in 2012 will be one-third vested on each of the first, second and third anniversaries of the grant date. Time-based restricted stock units granted prior to 2012 will, in general, 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 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.

Due to the bankruptcy proceedings, any restricted stock unit award and deferred stock unit award that vested subsequent to the Petition Date were not delivered to the award holder and Patriot does not anticipate delivering these awards in the future.

F-53

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

A summary of restricted stock time-based units and deferred stock units award activity is as follows:

	Year Ended December 31, 2012		Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2012	394,614		$	19.81
Granted	455,727		3.67
Forfeited	(313,779	)	13.20
Vested	(36,851	)	21.02
Vested, not distributed	(96,329	)	19.75
Nonvested at December 31, 2012	403,382		6.62

As of December 31, 2012, there were 78,207 vested, unexercised deferred stock units that had a de minimus aggregate intrinsic value.

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.

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 2012 was determined using a Monte Carlo simulation model, allowing us to factor in the probability of various outcomes. The weighted-average fair value of $12.72 was determined using a risk-free rate of 0.40%, an expected option life of 3.0 years, an expected dividend yield of zero, and volatilities that ranged from 43.8% to 89.5%.

A summary of restricted stock performance units award activity is as follows:

	Year Ended December 31, 2012		Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2012	667,412		$	22.00
Granted	228,563		12.72
Forfeited	(498,247	)	18.48
Vested, not distributed	(91,192	)	22.69
Market conditions not met	(51,325	)	26.80
Nonvested at December 31, 2012	255,211		19.37

Long-Term Incentive Non-Qualified Stock Options

We have long-term incentive non-qualified stock option agreements in place for grants to employees. 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 or later 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. Non-vested, non-qualified stock options will continue to vest; however, due to the significant reduction in our stock price and the bankruptcy proceedings, the non-qualified stock options are out-of-the-money and, if exercised by the award holder, Patriot will not honor the exercise.

F-54

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

A summary of non-qualified stock options outstanding activity is as follows:

	Year Ended December 31, 2012		Weighted Average Exercise Price		Aggregate Intrinsic Value (in millions)		Weighted Average Remaining Contractual Life
Options outstanding at January 1, 2012	1,666,254		$	15.35
Granted	413,314		9.13
Forfeited	(671,055	)	16.65
Exercised	—		—		$	—
Options outstanding at December 31, 2012	1,408,513		$	12.91	$	—	6.75
Vested and Exercisable	935,303		$	11.91	$	—	6.34

We used the Black-Scholes option pricing model to determine the fair value of stock options. Determining the fair value of stock-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 50/50 blended approach to develop the expected volatility, combining a peer historical “look-back” calculation and an implied volatility calculation based on call-option trading history. 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,
	2012			2011			2010
Weighted-average fair value	$	6.58		$	8.98		$	9.63
Risk-free interest rate	1.08		%	0.74		%	1.49		%
Expected option life	5.69 years			2.95 years			2.95 years
Expected volatility	89.03		%	80.52		%	87.67		%
Dividend yield	0		%	0		%	0		%

Employee Stock Purchase Plan

Our employee stock purchase plan was suspended in June 2012, but effective January 1, 2012. Prior to that time, eligible full-time and part-time employees were 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 through December 31, 2011, employees were 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 began 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 was 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 129,160 shares of common stock during the year ended December 31, 2012. We did not recognize expense in 2012 due to the bankruptcy filing and suspension of the plan. For the year ended December 31, 2011, 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, 2010, we issued 304,101 shares of common stock and recognized $0.8 million of expense in “Selling and administrative expenses” and $0.1 million of expense in “Operating costs and expenses”.

F-55

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(26) Summary Quarterly Financial Information (Unaudited)

A summary of the unaudited quarterly results of operations and selected balance sheet data as of and for the years ended December 31, 2012 and 2011 is presented below.

	Year Ended December 31, 2012
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(Dollars in thousands, except per share and stock price data)
Revenues	$	502,578		$	534,065		$	448,196		$	437,833
Asset retirement obligation expense(1)	32,767			325,474			19,496			(23,147		)
Operating loss	(59,208		)	(338,065		)	(83,529		)	(11,522		)
Net loss	(75,297		)	(354,320		)	(215,933		)	(85,044		)
Basic and diluted loss per share	$	(0.82	)	$	(3.82	)	$	(2.33	)	$	(0.92	)
Weighted average shares outstanding	91,851,630			92,847,229			92,686,588			92,559,246
Stock price - high and low prices	$9.24 - $6.22			$6.73 - $1.07			$2.26 - $0.10			$0.19 - $0.07
Balance Sheet Data (at period end):
Property, plant, equipment and mine   development, net	$	3,157,075		$	3,174,821		$	3,139,807		$	3,102,506
Total assets	3,663,120			3,579,553			3,873,643			3,838,807
Current liabilities	499,709			895,065			284,039			622,898
Asset retirement obligations	426,361			737,644			743,095			720,461
Liabilities subject to compromise	—			—			2,090,743			2,262,307
Total liabilities	3,123,906			3,391,168			3,882,399			4,072,036
Total stockholders’ equity (deficit)	539,214			188,385			(8,756		)	(233,229		)

	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
Asset retirement obligation expense	15,067			72,356			13,299			4,510
Operating profit (loss)	7,300			(32,847		)	(34,302		)	(13,627		)
Net loss	(15,909		)	(49,596		)	(50,452		)	(23,178		)
Basic and diluted loss per share	$	(0.17	)	$	(0.54	)	$	(0.55	)	$	(0.25	)
Weighted average shares outstanding	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
Balance Sheet Data (at period end):
Property, plant, equipment and mine   development, net	$	3,146,141		$	3,175,020		$	3,179,536		$	3,202,121
Total assets	3,792,768			3,841,261			3,806,456			3,844,763
Current liabilities	487,883			532,725			570,623			559,092
Asset retirement obligations	388,753			439,111			430,181			424,974
Total liabilities	2,999,004			3,083,753			3,088,680			3,251,921
Total stockholders’ equity	793,764			757,508			717,776			592,842

⁽¹⁾  Asset retirement obligation expense includes a $307.4 million adjustment in the second quarter of 2012 to recognize the modification of our compliance plan to IFSeR technology and a $49.1 million adjustment in the fourth quarter of 2012 to decrease our liability due to delaying compliance deadlines and optimizations made to the design of the IFSeR technology.

F-56

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(27) Supplemental Guarantor/Non-Guarantor Financial Information

The following tables present condensed consolidating financial information for: (a) Patriot Coal Corporation (the Parent Company) on a stand-alone basis; (b) the subsidiary guarantors of the 8.25% Senior Notes (the Guarantor Subsidiaries) on a combined basis and; (c) the Non-Guarantor Subsidiary, Patriot Coal Receivables (SPV) Ltd. (the facilitating entity for the pre-petition accounts receivable securitization program), on a stand-alone basis. Each Guarantor Subsidiary is 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 will be 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 potential investors.

F-57

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

	Year Ended December 31, 2012
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(Dollars in thousands)
Revenues
Sales	$	—		$	1,879,013		$	—		$	—		$	1,879,013
Other revenues	—			43,659			—			—			43,659
Total revenues	—			1,922,672			—			—			1,922,672
Costs and expenses
Operating costs and expenses	—			1,779,921			—			—			1,779,921
Depreciation, depletion and amortization	—			185,001			—			—			185,001
Asset retirement obligation expense	—			354,590			—			—			354,590
Sales contract accretion	—			(11,628		)	—			—			(11,628		)
Impairment and restructuring charge	—			61,278			—			—			61,278
Selling and administrative expenses	13,083			35,957			—			—			49,040
Net gain on disposal or exchange of assets				(3,121		)	—			—			(3,121		)
Loss (income) from equity affiliates	606,429			(85		)	—			(606,429		)	(85		)
Operating loss	(619,512		)	(479,241		)	—			606,429			(492,324		)
Interest expense and other	42,784			17,285			952			(952		)	60,069
DIP financing fees	42,540			—			—			—			42,540
Interest income	(109		)	(80		)	(952		)	952			(189		)
Loss before reorganization items and   income taxes	(704,727		)	(496,446		)	—			606,429			(594,744		)
Reorganization items, net	25,867			109,997			—			—			135,864
Loss before income taxes	(730,594		)	(606,443		)	—			606,429			(730,608		)
Income tax benefit	—			(14		)	—			—			(14		)
Net loss	$	(730,594	)	$	(606,429	)	$	—		$	606,429		$	(730,594	)

F-58

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

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	—			105,232			—			—			105,232
Sales contract accretion	—			(55,020		)	—			—			(55,020		)
Impairment and restructuring 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		)
Loss (income) from equity affiliates	73,680			(4,709		)	—			(73,680		)	(4,709		)
Operating loss	(92,341		)	(54,815		)	—			73,680			(73,476		)
Interest expense and other	47,024			18,509			1,539			(1,539		)	65,533
DIP financing fees	—			—			—			—			—
Interest income	(230		)	(16		)	(1,539		)	1,539			(246		)
Loss before reorganization items and   income taxes	(139,135		)	(73,308		)	—			73,680			(138,763		)
Reorganization items, net	—			—			—			—			—
Loss before income taxes	(139,135		)	(73,308		)	—			73,680			(138,763		)
Income tax provision	—			372			—			—			372
Net loss	$	(139,135	)	$	(73,680	)	$	—		$	73,680		$	(139,135	)

F-59

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

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	—			112,697			—			—			112,697
Sales contract accretion	—			(121,475		)	—			—			(121,475		)
Impairment and restructuring 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	(4,219		)	(9,476		)	—			4,219			(9,476		)
Operating loss	(47,886		)	(504		)	—			(4,219		)	(52,609		)
Interest expense and other	49,885			7,534			1,041			(1,041		)	57,419
DIP financing fees	—			—			—			—			—
Interest income	(82		)	(12,749		)	(1,041		)	1,041			(12,831		)
Income (loss) before reorganization items   and income taxes	(97,689		)	4,711			—			(4,219		)	(97,197		)
Reorganization items, net	—			—			—			—			—
Income (loss) before income taxes	(97,689		)	4,711			—			(4,219		)	(97,197		)
Income tax provision	—			492			—			—			492
Net income (loss)	$	(97,689	)	$	4,219		$	—		$	(4,219	)	$	(97,689	)

F-60

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATING

STATEMENTS OF COMPREHENSIVE LOSS

	Year Ended December 31, 2012
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Eliminations		Consolidated
	(Dollars in thousands)
Net loss	$	(730,594	)	$	(606,429	)	$	—	$	606,429	$	(730,594	)
Accumulated actuarial loss and prior service   credit realized in net loss	—			54,862			—		—		54,862
Accumulated actuarial unrealized losses	—			(151,692		)	—		—		(151,692		)
Net change in fair value of diesel fuel hedge	2,213			—			—		—		2,213
Realized gains of diesel fuel hedge	(1,970		)	—			—		—		(1,970		)
Other comprehensive loss	243			(96,830		)	—		—		(96,587		)
Comprehensive loss	$	(730,351	)	$	(703,259	)	$	—	$	606,429	$	(827,181	)

F-61

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATING

STATEMENTS OF COMPREHENSIVE LOSS

	Year Ended December 31, 2011
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Eliminations		Consolidated
	(Dollars in thousands)
Net loss	$	(139,135	)	$	(73,680	)	$	—	$	73,680	$	(139,135	)
Accumulated actuarial loss and prior service   credit realized in net loss	—			42,559			—		—		42,559
Accumulated actuarial unrealized losses	—			(118,210		)	—		—		(118,210		)
Net change in fair value of diesel fuel hedge	3,060			—			—		—		3,060
Realized gains of diesel fuel hedge	(4,744		)	—			—		—		(4,744		)
Other comprehensive loss	(1,684		)	(75,651		)	—		—		(77,335		)
Comprehensive loss	$	(140,819	)	$	(149,331	)	$	—	$	73,680	$	(216,470	)

F-62

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATING

STATEMENTS OF COMPREHENSIVE LOSS

	Year Ended December 31, 2010
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Eliminations			Consolidated
	(Dollars in thousands)
Net income (loss)	$	(97,689	)	$	4,219		$	—	$	(4,219	)	$	(97,689	)
Accumulated actuarial loss and prior service   credit realized in net income (loss)	—			36,449			—		—			36,449
Accumulated actuarial unrealized losses	—			(95,801		)	—		—			(95,801		)
Net change in fair value of diesel fuel hedge	1,855			—			—		—			1,855
Realized gains of diesel fuel hedge	(1,022		)	—			—		—			(1,022		)
Other comprehensive income (loss)	833			(59,352		)	—		—			(58,519		)
Comprehensive loss	$	(96,856	)	$	(55,133	)	$	—	$	(4,219	)	$	(156,208	)

F-63

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS

	December 31, 2012
	Parent Company		Guarantor Subsidiaries			Non-Guarantor Subsidiary		Eliminations			Consolidated
	(Dollars in thousands)
ASSETS
Current assets
Cash and cash equivalents	$	333,041	$	888		$	—	$	—		$	333,929
Accounts receivable and other, net	125		105,010			—		—			105,135
Inventories	—		99,219			—		—			99,219
Deferred income taxes	65,036		—			—		—			65,036
Prepaid expenses and other current assets	2,253		35,153			—		—			37,406
Total current assets	400,455		240,270			—		—			640,725
Property, plant, equipment and mine   development
Land and coal interests	—		2,892,799			—		—			2,892,799
Buildings and improvements	—		571,985			—		—			571,985
Machinery and equipment	—		767,749			—		—			767,749
Less accumulated depreciation, depletion   and amortization	—		(1,130,027		)	—		—			(1,130,027		)
Property, plant, equipment and mine   development, net	—		3,102,506			—		—			3,102,506
Cash collateralization deposits	64,990		—			—		—			64,990
Investments, intercompany and other assets	692,771		(194,668		)	—		(467,517		)	30,586
Total assets	$	1,158,216	$	3,148,108		$	—	$	(467,517	)	$	3,838,807
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Liabilities not subject to compromise
Current liabilities
Accounts payable and accrued expenses	$	8,024	$	239,465		$	—	$	—		$	247,489
Current maturities of long-term debt	375,000		409			—		—			375,409
Total current liabilities	383,024		239,874			—		—			622,898
Long-term debt, less current maturities	—		1,766			—		—			1,766
Deferred income taxes	65,036		—			—		—			65,036
Asset retirement obligations	—		720,461			—		—			720,461
Workers’ compensation obligations	—		254,680			—		—			254,680
Postretirement benefit obligations	—		87,805			—		—			87,805
Obligation to industry fund	—		34,278			—		—			34,278
Other noncurrent liabilities	139		22,666			—		—			22,805
Total liabilities not subject to compromise	448,199		1,361,530			—		—			1,809,729
Liabilities subject to compromise	461,202		1,801,105			—		—			2,262,307
Total liabilities	909,401		3,162,635			—		—			4,072,036
Stockholders’ equity (deficit)	248,815		(14,527		)	—		(467,517		)	(233,229		)
Total liabilities and stockholders’ equity (deficit)	$	1,158,216	$	3,148,108		$	—	$	(467,517	)	$	3,838,807

F-64

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

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
Deferred income taxes	81,025		—			—		—			81,025
Prepaid expenses and other current assets	709		27,482			—		—			28,191
Total current assets	275,929		303,510			171,101		(171,101		)	579,439
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	—		735,207			—		—			735,207
Less accumulated depreciation, depletion   and amortization	—		(973,157		)	—		—			(973,157		)
Property, plant, equipment and mine   development, net	—		3,202,121			—		—			3,202,121
Cash collateralization deposits	14,990		—			—		—			14,990
Investments, intercompany and other assets	1,211,319		(89,162		)	—		(1,073,944		)	48,213
Total assets	$	1,502,238	$	3,416,469		$	171,101	$	(1,245,045	)	$	3,844,763
LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities not subject to compromise
Current liabilities
Accounts payable and accrued expenses	$	7,993	$	505,130		$	171,101	$	(171,101	)	$	513,123
Below market sales contracts acquired	—		44,787			—		—			44,787
Current maturities of long-term debt	—		1,182			—		—			1,182
Total current liabilities	7,993		551,099			171,101		(171,101		)	559,092
Long-term debt, less current maturities	433,951		7,113			—		—			441,064
Deferred income taxes	81,025		—			—		—			81,025
Asset retirement obligations	—		424,974			—		—			424,974
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 not subject to compromise	524,182		2,727,739			171,101		(171,101		)	3,251,921
Liabilities subject to compromise	—		—			—		—			—
Total liabilities	524,182		2,727,739			171,101		(171,101		)	3,251,921
Stockholders’ equity	978,056		688,730			—		(1,073,944		)	592,842
Total liabilities and stockholders’ equity	$	1,502,238	$	3,416,469		$	171,101	$	(1,245,045	)	$	3,844,763

F-65

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2012
	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	$	(87,107	)	$	58,943		$	—	$	—	$	(28,164	)
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine   development	—			(139,139		)	—		—		(139,139		)
Additions to advance mining royalties	—			(23,614		)	—		—		(23,614		)
Acquisitions	—			(3,030		)	—		—		(3,030		)
Proceeds from disposal or exchange of assets	—			3,690			—		—		3,690
Other	—			(370		)	—		—		(370		)
Net cash used in investing activities	—			(162,463		)	—		—		(162,463		)
Cash Flows From Financing Activities
Proceeds from debtor-in-possession debt	375,000			—			—		—		375,000
Long-term debt payments	—			(1,401		)	—		—		(1,401		)
Deferred financing costs	(1,595		)	—			—		—		(1,595		)
Debtor-in-possession debt issuance costs	(42,540		)	—			—		—		(42,540		)
Proceeds from employee stock programs	930			—			—		—		930
Intercompany transactions	(105,529		)	105,529			—		—		—
Net cash provided by financing activities	226,266			104,128			—		—		330,394
Net increase in cash and cash equivalents	139,159			608			—		—		139,767
Cash and cash equivalents at beginning of year	193,882			280			—		—		194,162
Cash and cash equivalents at end of year	$	333,041		$	888		$	—	$	—	$	333,929

F-66

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

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	)	$	164,126		$	—	$	—	$	112,989
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine   development	—			(162,965		)	—		—		(162,965		)
Proceeds from notes receivable	—			115,679			—		—		115,679
Additions to advance mining royalties	—			(26,030		)	—		—		(26,030		)
Net cash paid in litigation settlement and asset   acquisition	—			(14,787		)	—		—		(14,787		)
Proceeds from disposal or exchange of assets	—			6,928			—		—		6,928
Net cash used in investing activities	—			(81,175		)	—		—		(81,175		)
Cash Flows From Financing Activities
Long-term debt payments	—			(31,002		)	—		—		(31,002		)
Deferred financing costs	(1,832		)	—			—		—		(1,832		)
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 year	192,593			474			—		—		193,067
Cash and cash equivalents at end of year	$	193,882		$	280		$	—	$	—	$	194,162

F-67

PATRIOT COAL CORPORATION

(DEBTOR-IN-POSSESSION)

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	)	$	96,722		$	—	$	—	$	35,253
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine   development	(1,708		)	(120,223		)	—		—		(121,931		)
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		)	(107,167		)	—		—		(108,875		)
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
Long-term debt payments	—			(8,042		)	—		—		(8,042		)
Deferred financing costs	(20,740		)	—			—		—		(20,740		)
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 year	26,574			524			—		—		27,098
Cash and cash equivalents at end of year	$	192,593		$	474		$	—	$	—	$	193,067

F-68

PATRIOT COAL CORPORATION

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS

DECEMBER 31, 2012

Description	Balance at Beginning of Year		Additions Charged to Costs and Expenses			Deductions(1)			Other		Balance at End of Year
	(Dollars in thousands)
Year Ended December 31, 2010
Reserves deducted from asset accounts:
Valuation allowance for deferred tax assets	$	130,701	$	41,123		$	—		$	—	$	171,824
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:
Valuation allowance for deferred tax assets	$	171,824	$	83,905		$	—		$	—	$	255,729
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
Year Ended December 31, 2012
Reserves deducted from asset accounts:
Valuation allowance for deferred tax assets	$	255,729	$	324,362		$	—		$	—	$	580,091
Advance royalty recoupment reserve	49,158		7,688			(979		)	—		55,867
Reserve for materials and supplies	9,165		(1,222		)	—			—		7,943
Allowance for doubtful accounts	138		5			(125		)	—		18

⁽¹⁾  Reserves utilized, unless otherwise indicated.

F-69