UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

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

For the Year Ended December 31, 2009

		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		(I.R.S. Employer
incorporation or organization)		Identification No.)

12312 Olive Boulevard, Suite 400
St. Louis, Missouri		63141
(Address of principal executive offices)		(Zip Code)

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)
Securities Registered Pursuant to Section 12(b) of the Act:

Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share		New York Stock Exchange
Preferred Share Purchase Rights		New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act		Yes þ      No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act		Yes o      No þ

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

Indicate by check mark 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 o      No o

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

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

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

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

Aggregate market value of the voting stock held by non-affiliates (shareholders who are not directors or executive officers) of the Registrant, calculated using the closing price on June 30, 2009: Common Stock, par value $0.01 per share, $571.0 million.

Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 19, 2010: Common Stock, par value $0.01 per share, 90,870,249 shares outstanding.

Portions of the Company’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company’s Annual Meeting of Stockholders to be held on May 13, 2010 (the “Company’s 2010 Proxy Statement”) are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

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

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

	•		price volatility and demand, particularly in higher margin products;
	•		geologic, equipment and operational risks associated with mining;
	•		changes in general economic conditions, including coal, power and steel market conditions;
	•		availability and costs of competing energy resources;
	•		regulatory and court decisions including, but not limited to, those impacting permits issued pursuant to the Clean Water Act;
	•		environmental laws and regulations including those affecting our operations and those affecting our customers’ coal usage;
	•		developments in greenhouse gas emission regulation and treatment, including any development of commercially successful carbon capture and storage techniques or market-based mechanisms, such as a cap-and-trade system, for regulating greenhouse gas emissions;
	•		coal mining laws and regulations;
	•		labor availability and relations;
	•		changes in postretirement benefit obligations;
	•		changes to contribution requirements to multi-employer retiree healthcare and pension plans;
	•		reductions of purchases or deferral of shipments by major customers;
	•		availability and costs of credit, surety bonds and letters of credit;
	•		customer performance and credit risks;
	•		inflationary trends, including those impacting materials used in our business;
	•		worldwide economic and political conditions;
	•		downturns in consumer and company spending;
	•		supplier and contract miner performance, and the availability and cost of key equipment and commodities;
	•		availability and costs of transportation;
	•		difficulty in implementing our business strategy;
	•		our ability to replace proven and probable coal reserves;
	•		the outcome of commercial negotiations involving sales contracts or other transactions;
	•		our ability to respond to changing customer preferences;
	•		our dependence on Peabody Energy for a significant portion of our revenues;
	•		failure to comply with debt covenants;
	•		the outcome of pending or future litigation;
	•		the effects of mergers, acquisitions and divestitures, including our ability to successfully integrate mergers and acquisitions;
	•		weather patterns affecting energy demand;
	•		competition in our industry;
	•		interest rate fluctuation;
	•		wars and acts of terrorism or sabotage;
	•		impact of pandemic illness; and
	•		other factors, including those discussed in Legal Proceedings, set forth in Item 3 of this report.

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

PART I

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

Item 1.		Business.

Overview

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

     Our operations consist of fourteen current mining complexes, which include company-operated mines, contractor-operated mines and coal preparation facilities. The Appalachia and Illinois Basin segments consist of our operations in West Virginia and Kentucky, respectively. We control approximately 1.8 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 electric utilities, industrial users, steel mills and independent coke producers. In 2009, we sold 32.8 million tons of coal, of which 83% was sold to domestic electric utilities and industrial customers and 17% was sold to domestic and global steel and coke producers. Coal is shipped via various company-owned and third-party loading facilities, multiple rail and river transportation routes and ocean-going vessels.

     Effective October 31, 2007, Patriot was spun off from Peabody Energy Corporation (Peabody) and became a separate, public company traded on the New York Stock Exchange (symbol PCX). This transaction is referred to in this Form 10-K as the “distribution” or the “spin-off.” The spin-off from Peabody was accomplished through a dividend of all outstanding shares of Patriot.

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

Mining Operations

     Our mining operations and coal reserves are as follows:

	•		Appalachia. In southern West Virginia, we have ten mining complexes located in Boone, Clay, Lincoln, Logan and Kanawha counties, and in northern West Virginia, we have one complex located in Monongalia County. As part of a comprehensive strategic review of operations upon the acquisition of Magnum, we idled operations at our Jupiter mining complex (December 2008) and our Remington mining complex (March 2009). Additionally, in response to the weakened coal markets, we announced the idling of our Black Oak mine (January 2009), the deferral of the opening of our Blue Creek mining complex, and the suspension of our Samples surface mine (August 2009). In Appalachia, we sold 25.8 million tons of coal in the year ended December 31, 2009. As of December 31, 2009, we controlled 1.2 billion tons of proven and probable coal reserves in Appalachia, of which 488 million tons were assigned to current operations.
	•		Illinois Basin. In the Illinois Basin, we have three complexes located in Union and Henderson counties in western Kentucky. In the Illinois Basin, we sold 7.0 million tons of coal in the year ended December 31, 2009. As of December 31, 2009, we controlled 646 million tons of proven and probable coal reserves in the Illinois Basin, of which 126 million tons were assigned to current operations.

     The following table provides the location and summary information of our operations as of December 31, 2009.

Mining

2009 Tons

Location

Complex

Mine(s)

Method(1)

Met/Steam

Sold(2)

Appalachia

Big Mountain

Big Mountain No. 16, Contractor

CM

Steam

2,072

Blue Creek

Blue Creek No. 1, Blue Creek No. 2

CM

Steam

134

Campbell’s Creek

Campbell’s Creek No. 6, Campbell’s Creek No. 7

CM

Steam

1,051

Corridor G

Job 21, Hill Fork

TS, DL

Steam

3,565

Kanawha Eagle

Eagle, Coalburg No. 1, Coalburg No. 2

CM

Met/Steam

1,881

Logan County

Guyan

TS

Steam

2,500

Paint Creek

Samples, Winchester

TS, HW, CM

Met/Steam

2,071

Panther

Panther

LW, CM

Met/Steam

2,023

Remington(3)

Stockburg No. 2, Deskins, Wildcat

CM, TS, HW

Steam

182

Rocklick

Harris No. 1, Black Oak, Contractor

TS, CM

Met/Steam

1,658

Wells

Rivers Edge, Contractor

CM

Met

3,315

Federal

Federal No. 2

LW, CM

Steam

3,522

Purchased coal

N/A

N/A

N/A

1,876

Subtotal

25,850

Illinois Basin

Bluegrass

Patriot, Freedom

TS, CM

Steam

2,433

Dodge Hill

Dodge Hill No. 1

CM

Steam

888

Highland

Highland No. 9

CM

Steam

3,665

Subtotal

6,986

Total

32,836

     Longwall mining. Longwall mining is an underground mining method that uses hydraulic shields, varying from five feet to twelve feet in height, to support the roof of the mine while a shearing machine traverses the coal face removing a two to three foot slab of coal with each pass. An armored face conveyer then moves the coal to a standard deep mine conveyer system for delivery to the surface. Longwall mining is highly productive, but it is effective only for large blocks of medium to thick coal seams.

     Continuous miner mining. Continuous miner mining is an underground method in which airways and transportation entries are developed by continuous mining machines, leaving “pillars” to support the roof. Continuous miner mining is also referred to as “room-and-pillar” mining. Pillars may subsequently be extracted to maximize the reserve recovery. This method is often used to mine smaller coal reserves or thin seams.

     Truck-and-shovel/loader mining. Truck-and-shovel/loader mining is a surface mining method that uses large electric- or diesel-powered shovels to remove overburden, which is used to backfill pits after coal removal. Loading equipment is used to load coal into haul trucks for transportation to the preparation plant or transportation loading facility. Productivity depends on equipment, geological composition and the ratio of overburden to coal.

     Dragline mining. Dragline mining is an efficient surface method that uses large capacity draglines to remove overburden to expose the coal seams. In Central Appalachia, the seams to be mined above the dragline are pre-stripped with support equipment in order to create a bench upon which the dragline can operate. The coal is loaded into haul trucks for transportation to a preparation plant or transportation to a loading facility.

     Highwall mining. Highwall mining is a surface mining method generally utilized in conjunction with truck-and-shovel/loader surface mining. As the highwall is exposed by the truck-and-shovel/loader operation, a modified continuous miner with an attached auger conveyor system cuts horizontal passages from the highwall into the coal seam. These passages can penetrate to a depth of up to 1,600 feet.

Appalachian Mining Operations

     Our Appalachian Mining Operations include eleven current mining complexes in West Virginia and the Remington complex, which was idled in March 2009.

Appalachia

     Big Mountain

     The Big Mountain mining complex is sourced by one company-operated underground mine, Big Mountain No. 16, and multiple contractor-operated underground mines located in southern West Virginia. Coal is produced utilizing continuous mining methods. The coal is sold on the thermal market and is transported from the preparation plant to customers via CSX rail or trucked to a river and placed on barges. Coal is produced from the Coalburg seam with average thickness of nine feet and the Dorothy seam with average thickness of six feet. Most of the employees at the company-operated mine are represented by the United Mine Workers of America (UMWA).

     Blue Creek

     The Blue Creek mining complex is located in southern West Virginia and consists of two company-operated underground mines, Blue Creek No. 1 and Blue Creek No. 2. One of the mines became operational in December 2009 and the other is expected to begin production in the first quarter of 2010. Both mines operate in the Stockton seam, with an average thickness of ten feet. The complex utilizes continuous mining methods and a third-party-owned on-site preparation facility. Coal produced at the Blue Creek complex is sold on the thermal market and is loaded onto trucks for transportation to a barge loading facility on the Kanawha River. The employees at the company-operated mines are not represented by a union.

     Campbell’s Creek

     The Campbell’s Creek mining complex consists of two underground mines located in southern West Virginia. The company-operated Campbell’s Creek No. 7 mine operates in the Winifrede seam, with an average mining thickness of seven and one half feet. The contractor-operated Campbell’s Creek No. 6 mine operates in the Stockton seam, and has an average mining thickness of seven feet. All mines in the Campbell’s Creek mining complex utilize the continuous mining method. After processing, the coal is transported by truck to the Kanawha River for loading onto barges that deliver the coal to customers. Coal produced at Campbell’s Creek mining complex is sold on the thermal market. The employees at the company-operated mine are not represented by a union.

     Corridor G

     The Corridor G mining complex consists of two company-operated surface mines, Job 21 and Hill Fork, located in southern West Virginia. Coal is sourced from the Kittanning, Stockton and Coalburg seams, with a 16-to-1 average overburden to coal ratio. Corridor G utilizes truck-and-shovel/loader and dragline mining. Coal produced at this complex is transferred by belt to the on-site preparation plant and loadout facility. After processing, the coal is transported to customers by CSX rail or trucked to a river and placed on barges. Coal produced at the Corridor G mining complex is sold on the thermal market. Most of the employees at the Corridor G mining complex are represented by the UMWA.

     Kanawha Eagle

     The Kanawha Eagle complex, which is contractor-operated, is located in southern West Virginia and is sourced by the Eagle, Coalburg No. 1 and Coalburg No. 2 underground mines. All three mines utilize continuous mining methods. Processed coal is sold on both metallurgical and thermal markets and is transported via CSX rail directly to the customer or by private line railroad to the Kanawha River and placed on barges. Coal is produced from the Coalburg seam, with average thickness of six feet, and the Eagle seam, with average thickness of four feet.

     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 is sourced from the Freeport, Kittanning, Stockton and Coalburg seams, with a 15-to-1 average overburden to coal ratio. Certain employees at the Logan County complex are represented by the UMWA.

     Paint Creek

     The Paint Creek mining complex consists of one surface mine and one underground mine located in southern West Virginia. Both mines are company-operated. The surface mine, Samples, utilizes truck-and-shovel/loader and highwall mining methods, while the underground mine, Winchester, utilizes the continuous mining method. The Winchester mine operates in the Hernshaw seam, with an average mining thickness of six feet. Coal from Samples is sourced from the Freeport, Kittanning, Stockton and Coalburg seams, with a 16.5-to-1 average overburden to coal ratio. We announced the idling of our Samples mine in August 2009. After processing, coal is transported from the on-site preparation plant and loadout facility to customers by CSX rail. Coal can also be trucked approximately 14 miles to the Kanawha River and transported by barge. Coal from this complex can be sold on either the metallurgical and thermal markets. The employees at the Paint Creek complex are not represented by a union.

     Panther

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

     Remington

     The Remington mining complex is located in southern West Virginia and consists of two underground mines and one surface mine. As part of a comprehensive strategic review of operations upon the acquisition of Magnum, the Remington complex was idled in March 2009.

     Rocklick

     The Rocklick mining complex is located in southern West Virginia and is sourced by two company-operated underground mines, Harris No. 1 and Black Oak, and contractor-operated underground and surface mines. Coal at the Rocklick mining complex is produced utilizing continuous mining methods at underground mines and the truck-and-shovel/loader mining method at surface mines. All Harris No. 1 and Black Oak coal is sold on the metallurgical market and contractor processed coal is sold on either the thermal or metallurgical markets. Rocklick has the capability to transport coal on both the CSX and the Norfolk Southern railroads. Metallurgical coal at Harris No. 1 is produced from the Eagle seam, with average thickness of four feet, if only the lower split is mined, or seven feet, if both seam splits are mined. Thermal coal is produced from the Kittanning, Stockton, Clarion and Coalburg seams, with an 18-to-1 average overburden to coal ratio. In January 2009, the Black Oak mine was suspended due to lower demand for metallurgical coal. Additionally, the contractor-operated surface mines were idled at the Rocklick complex during 2009. Most of the employees at the company-operated mines are represented by the UMWA.

     Wells

     The Wells mining complex is located in southern West Virginia and is sourced by one company-operated underground mine, Rivers Edge, and multiple contractor-operated underground mines. Coal is produced utilizing continuous mining methods. The majority of coal currently produced at Wells is sold on the metallurgical market and is transported to customers via CSX rail. Thermal coal can also be processed and sold at this operation. Rivers Edge mine produces coal from the Powellton seam, with average thickness of approximately eight feet. Coal is also produced from the Black Stallion contract mine in the Eagle seam, with average thickness of six feet. Contract mines produce coal from the No. 2 Gas, Winifrede, Powellton and Lower Chilton seams, each with an average thickness of five to eight feet. Most of the employees at the company-operated facilities of the Wells mining complex are represented by the UMWA.

     Federal

     The Federal mining complex is located in northern West Virginia and is sourced by one company-operated underground mine, Federal No. 2, utilizing longwall and continuous mining methods. All coal produced at Federal is sold on the high-Btu thermal market and is transported to customers via the CSX and Norfolk Southern railroads either directly or via barges on the Ohio River. Coal is produced from the Pittsburgh seam, with average thickness of seven feet. Most of the employees at the Federal mining complex are represented by the UMWA.

Illinois Basin Mining Operations

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

Illinois Basin

     Bluegrass

     The Bluegrass mining complex is located in western Kentucky and is sourced by two company-operated mines, Freedom, an underground mine, and Patriot, a surface mine. Coal at Freedom is produced utilizing continuous mining methods, while coal at Patriot is produced utilizing the truck-and-shovel/loader mining method. All coal is sold on the thermal market and is transported via truck or via barge loaded on the Green River. Coal is produced from the Kentucky No. 9 seam, with average thickness of four feet for the Freedom underground mine, and with a 15-to-1 average overburden to coal ratio for the Patriot surface mine. The employees at the Bluegrass mining complex are not represented by a union.

     Dodge Hill

     The Dodge Hill mining complex is located in western Kentucky and is sourced by one company-operated underground mine, utilizing continuous mining methods. All coal is sold on the thermal market and transported via barge on the Ohio River. Coal is produced from the Kentucky No. 6 seam, with average thickness of four feet. The employees at the Dodge Hill mining complex are not represented by a union.

     Highland

     The Highland mining complex is located in western Kentucky and is sourced by one company-operated underground mine, Highland No. 9, utilizing continuous mining methods. All coal is sold on the thermal market and is transported via barges loaded on the Ohio River. Coal is produced from the Kentucky No. 9 seam, with average thickness of five feet. Most of the employees at the Highland complex are represented by the UMWA.

Customers and Backlog

     As of December 31, 2009, we had a sales backlog of 72.6 million tons of coal, including backlog subject to price reopener and/or extension provisions. Our coal supply agreements have remaining terms up to 8 years and an average volume-weighted remaining term of approximately 2.5 years.

		Commitments as of December 31, 2009
														2013 and
		2010				2011				2012				Later				Total
Tons (in millions)			29.5				19.9				11.3				11.9				72.6

     The 2010 commitments represent more than 85% of our currently estimated production for 2010.

     In 2009, approximately 83% of our coal sales were under long-term (one year or greater) contracts. Also in 2009, our coal was sold to over 98 electricity generating and industrial plants in 8 countries, including the U.S., which is where we have our primary customer base.

     We expect to continue selling a significant portion of our coal under supply agreements with terms of one year or longer. Our approach is to selectively renew, or enter into, new coal supply contracts when we can do so at prices we believe are favorable. We continue to supply coal to Peabody under contracts that existed at the date of spin-off, and certain of these contracts have terms into 2012. As of December 31, 2009, approximately 25% and 19% of our current projected 2010 and 2011 total production, respectively, was committed under pre-existing customer relationships with various Peabody subsidiaries, all of which are thermal coal contracts.

     Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices, while we seek stable sources of revenue to support the investments required to open, expand and maintain or improve productivity at the mines needed to supply these contracts. 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, and termination and assignment provisions.

     Each contract sets a base price. Some contracts provide for a predetermined adjustment to base price at times specified in the agreement. Base prices may be adjusted quarterly, annually or at other periodic intervals for changes in production costs and/or changes due to inflation or deflation. Changes in production costs may be measured by defined formulas that may include actual cost experience at the mine as part of the formula. The inflation/deflation adjustments are measured by public indices, the most common of which is the implicit price deflator for the gross domestic product as published by the U.S. Department of Commerce. In most cases, the components of the base price represented by taxes, fees and royalties which are based on a percentage of the selling price are also adjusted for any changes in the base price and passed through to the customer.

     Most long-term contracts contain provisions to adjust the base price due to new laws or changes in the language, interpretation or application of existing laws that increase our cost of performance under such contracts. Buyers often negotiate similar clauses covering changes in environmental laws. We often negotiate the right to supply coal that complies with a new environmental requirement to avoid contract termination. Coal supply agreements typically contain termination clauses if either party fails to comply with the terms and conditions of the contract, although most termination provisions provide the opportunity to cure defaults.

     Price reopener provisions are present in some of our multi-year coal contracts. These provisions may allow either party to commence a renegotiation of the contract price at various intervals. In most of the agreements with price reopener provisions, if the parties do not agree on a new price, the purchaser or seller has an option to terminate the contract. Under some contracts, we have the right to match lower prices offered to our customers by other suppliers.

     Quality and volumes for the coal are stipulated in coal supply agreements, and in some limited instances buyers have the option to vary annual or monthly volumes, if necessary. Variations to the quality of coal may lead to adjustments in the contract price. Most coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content (Btu), sulfur and ash content, grindability and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Coal supply agreements typically stipulate procedures for sampling, analysis and weighing.

     In most of our contracts, we have a right of substitution, allowing us to provide coal from different mines, including third-party production, as long as the replacement coal meets the contracted quality specifications and is sold at the same delivered cost.

     Contract provisions in most cases set out mechanisms for temporary reductions or delays in coal volumes in the case of a force majeure event, including strikes, adverse mining conditions, labor shortages, permitting or serious transportation problems that affect the seller or unanticipated plant outages that may affect the buyer. Most contracts stipulate that this tonnage can be made up by either mutual agreement or at the option of the nonclaiming party.

Sales and Marketing

     We sell coal produced by our operations and third-party producers. We contract with third-party producers to mine our owned or leased coal reserves on a rate per ton or cost plus basis. Our sales and marketing group includes personnel dedicated to performing sales functions, transportation, distribution, market research, contract administration, and credit/risk management activities.

Transportation

     Coal consumed domestically is typically sold at the mine and transportation costs are borne by the purchaser. At certain locations, we utilize truck, conveyor belt and rail to transport coal from our mines to docks for transportation to customers via barges. Export coal is usually sold at the loading port, with purchasers paying ocean freight. Producers usually pay shipping costs from the mine to the port, trans-loading fees at the port and any applicable vessel demurrage costs associated with delayed loadings.

     Of our 32.8 million tons sold in 2009, we shipped approximately 50% by rail, 41% by barge, 7% by ocean-going vessel and 2% by truck. Our transportation staff manages the loading of coal via these transportation modes.

Suppliers

     The main types of goods we purchase are mining equipment and replacement parts, steel-related (including roof control) products, belting products, lubricants, fuel and tires. Although we have many, long, well-established relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers other than for purchases of certain underground mining equipment. The supplier base providing mining materials has been relatively consistent in recent years. Purchases of certain underground mining equipment are concentrated with one principle supplier; however, supplier competition continues to develop.

Competition

     The U.S. coal industry is highly competitive, both regionally and nationally. Coal production in Appalachia and the Illinois Basin totaled approximately 448 million tons in 2009, with the largest five producers (Alpha Natural Resources, Inc., CONSOL Energy, Inc., Massey Energy Company, Patriot and Peabody) accounting for 41% of production. In addition to competition within the eastern U.S. region, coal is transported into the region from the western U.S. and international producers for purchase by utility customers.

     A number of factors beyond our control affect the markets in which we sell our coal. Continued demand for our coal and the prices obtained by us depend primarily on the coal consumption patterns of the electricity and steel industries in the U.S. and elsewhere around the world; the availability, location, cost of transportation and price of competing coal; and other electricity generation and fuel supply sources such as natural gas, oil, nuclear, hydroelectric and renewable energy. Coal consumption patterns are affected primarily by the demand for electricity, environmental and other governmental regulations, and technological developments. The most important factors on which we compete are delivered price (i.e., including transportation costs, which are paid by our customers), coal quality characteristics and reliability of supply.

Employees & Labor Relations

     Relations with our employees and, where applicable, organized labor, are important to our success. As of December 31, 2009, we had approximately 3,500 employees. Approximately 52% of our employees at our company operations were represented by an organized labor union and these operations generated approximately 46% of our 2009 sales volume. Union labor is represented by the UMWA under labor agreements which expire December 31, 2011. Our represented employees work at various sites in Appalachia and at the Highland complex in the Illinois Basin.

     We operate a training center in Appalachia. Our training center educates our workforce, particularly our most recent hires, in our rigorous safety standards, the latest in mining techniques and equipment, and serves as a center for dissemination of mining best practices across all of our operations. Our training efforts are designed with the intent of attracting new miners, in large part to replace miners expected to retire in the next few years, and to develop and retain a productive and safety-oriented workforce.

Certain Liabilities

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

     Asset Retirement Obligations

     Asset retirement 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). Asset retirement obligation expense (which includes liability accretion and asset amortization) for the years ended December 31, 2009, 2008 and 2007 was $29.5 million, $19.3 million, and $20.1 million, respectively. As of December 31, 2009, our asset retirement obligations of $244.5 million included $183.1 million related to locations with active mining operations and $61.4 million related to locations that are closed or inactive.

     Remediation Obligations

     Remediation obligations primarily represent the present value of future anticipated costs for water treatment of selenium discharges in excess of allowable limits, as required by current court orders, consent decrees and mining permits. Our remediation obligation at the Magnum acquisition date was estimated and recorded at June 30, 2009, when the purchase accounting valuation of all assets acquired and liabilities assumed was finalized. Remediation obligation expense for the year ended December 31, 2009 was $5.6 million, representing six months of expense. We expect remediation obligation expense to be approximately $12 million in 2010. Our remediation obligation liability was $88.6 million as of December 31, 2009.

     Workers’ Compensation

     These liabilities represent the estimates for compensable, work-related injuries (traumatic claims) and occupational disease, principally black lung disease (pneumoconiosis) and are based primarily on actuarial valuations. The Federal Black Lung Benefits Act requires employers to pay black lung awards to former employees who filed successful claims after June 1973. These liabilities were $220.3 million as of December 31, 2009, of which $26.6 million was a current liability. Expense for the years ended December 31, 2009, 2008 and 2007 was $31.3 million, $25.1 million and $28.0 million, respectively.

     Retiree Healthcare and Pension

     Retiree healthcare obligations primarily represent the estimated cost of providing retiree healthcare benefits to current retirees and active employees who will retire in the future. Provisions for active employees represent the amount recognized to date, based on their service to date. Additional amounts are accrued periodically so that the total estimated liability is accrued when the employee retires.

     Our retiree healthcare liabilities were $1.2 billion as of December 31, 2009, of which $67.1 million was a current liability. Expense for the years ended December 31, 2009, 2008 and 2007 was $92.5 million, $66.0 million and $99.9 million, respectively. In 2009, our results included a full year of retiree healthcare expense related to the Magnum operations as compared to only five months in 2008. Our 2008 retiree healthcare expense decreased from 2007 primarily due to the retention by Peabody of a portion of the liability at the spin-off (as discussed below) and a higher discount rate in 2008, partially offset by the inclusion of five months of activity related to the Magnum operations in 2008.

     In connection with the spin-off, a subsidiary of Peabody assumed certain of our pre-spin-off obligations associated with the Coal Industry Retiree Health Benefits Act of 1992 (the Coal Act), the 2007 National Bituminous Coal Wage agreement (2007 NBCWA) and certain salaried employee retiree healthcare benefits. At December 31, 2009 the present value of the liability assumed by Peabody at spin-off was $665.0 million. We continue to administer these benefits. Certain Patriot subsidiaries will remain jointly and severally liable for the Coal Act obligations and remain secondarily liable for the 2007 NBCWA obligations and the salaried employee obligations.

     The Coal Act provides for the funding of health benefits for certain UMWA retirees. The Coal Act established the United Mine Workers of America Combined Fund (Combined Fund) into which “signatory operators” and “related persons” are obligated to pay annual premiums for beneficiaries. This multi-employer fund provides healthcare benefits to a closed group of our retired former employees who last worked prior to 1976, as well as orphaned beneficiaries of bankrupt companies who were receiving benefits as orphans prior to the 1992 law. No new retirees will be added to this group. The liability is subject to increases or decreases in per capita healthcare costs, offset by the mortality curve in this aging population of beneficiaries. The Coal Act also created a second benefit fund, the 1992 Benefit Plan, for miners who retired between July 21, 1992, and September 30, 1994, and whose former employers are no longer in business. Beneficiaries may continue to be added to this fund as employers default in providing their former employees with retiree medical benefits, but the overall exposure for new beneficiaries into this fund is limited to retirees covered under their employer’s plan who retired prior to October 1, 1994. A third fund, the 1993 Benefit Plan, was established through collective bargaining and provides benefits to qualifying former employees, who retired after September 30, 1994, of certain signatory companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries may continue to be added to this fund as employers go out of business. The collective bargaining agreement with the UMWA, which specifies the payments to be made to the 1993 Benefit Plan, expires on December 31, 2011.

     In December 2006, the Surface Mining Control and Reclamation Act Amendments of 2006 (2006 Act) was enacted. Under the 2006 Act, the orphan benefits paid to the Combined Fund and the 1992 Benefit Plan will be the responsibility of the federal government on a phased-in basis. The legislation authorizes $490 million per year in general fund revenues to pay for these and other benefits under the bill. In addition, future interest from the federal Abandoned Mine Land (AML) trust fund and previous unused interest from the AML trust fund will be available to offset orphan retiree healthcare costs. Under current projections for the health funds, these available resources are sufficient to cover all anticipated costs of orphan retirees. These amounts are also in addition to any amounts that may be appropriated by Congress at its discretion. The legislation also revises the AML fees paid by us on coal production, effective in October 2007, with the imposition of such fee currently scheduled to expire in its entirety on September 30, 2021.

     The 2006 Act specifically amended the federal laws establishing the Combined Fund, the 1992 Benefit Plan and the 1993 Benefit Plan. The 2006 Act provides new and additional funding to all three programs, subject to the limitations described below. The 2006 Act guarantees full funding of all beneficiaries in the Combined Fund by supplementing the annual transfers of interest earned on the AML trust fund. The 2006 Act further provides funding for the annual orphan health costs under the 1992 Benefit Plan on a phased-in basis: 25%, 50% and 75% in the years 2008, 2009 and 2010, respectively. Thereafter, federal funding will pay for 100% of the orphan health costs. The coal producers that signed the 1988 labor agreement, including some of our subsidiaries, remain responsible for the costs of the 1992 Benefit Plan. The 2006 Act also included the 1993 Benefit Plan as one of the statutory funds and authorizes the trustees of the 1993 Benefit Plan to determine the contribution rates through 2010 for pre-2007 beneficiaries. During calendar years 2008 through 2010, federal funding will pay a portion of the 1993 Benefit Plan’s annual health costs on a phased-in basis: 25%, 50% and 75% in the years 2008, 2009 and 2010, respectively. The 1993 Benefit Plan trustees have set a $1.42 per hour statutory contribution rate for 2010. 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. Those of our subsidiaries that have agreed to the 2007 NBCWA will pay $0.50 per hour worked to the 1993 Benefit Plan to provide benefits for post 2006 beneficiaries. To the extent the $0.50 per hour payment exceeds the amount needed for this purpose, the difference will be credited against the $1.42 per hour statutory payment.

     The actuarially-determined liability for these benefit plans was $48.5 million as of December 31, 2009, $6.3 million of which was a current liability. Expenses for the years ended December 31, 2009, 2008 and 2007 were $3.2 million, $2.6 million and $2.9 million, respectively. Cash payments to these funds were $6.3 million, $6.1 million and $5.5 million for 2009, 2008 and 2007, respectively. The benefit plans that qualify as multi-employer plans are expensed as payments are made and no liability was recorded other than amounts due and unpaid. Expense related to these funds was $11.2 million, $11.8 million and $15.9 million for the years ended December 31, 2009, 2008 and 2007, respectively.

     Certain of our subsidiaries participate in two defined benefit multi-employer pension funds that were established as a result of collective bargaining with the UMWA pursuant to the 2007 NBCWA as periodically negotiated. These plans provide pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked prior to January 1, 1976, in the case of the UMWA 1950 Pension Plan, or after December 31, 1975, in the case of the UMWA 1974 Pension Plan. In December 2006, the 2007 NBCWA was signed, which required funding of the 1974 Pension Plan through 2011 under a phased funding schedule. The funding is based on an hourly rate for active UMWA workers. Under the labor contract, the per hour funding rate increased to $4.25 in 2009 and increases each year until reaching $5.50 in 2011. Our subsidiaries with UMWA-represented employees are required to contribute to the 1974 Pension Plan at the new hourly rates. Contributions to these funds could increase as a result of future collective bargaining with the UMWA, a shrinking contribution base as a result of the insolvency of other coal companies who currently contribute to these funds, lower than expected returns on pension fund assets or other funding deficiencies. Expense related to these funds was $18.3 million, $13.5 million and $6.9 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Regulatory Matters

     Federal and state authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, the protection of the environment, plants and wildlife, the reclamation and restoration of mining properties after mining has been completed, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. We have in the past, and will in the future, be required to incur significant costs to comply with these laws and regulations.

     Future legislation and regulations are expected to become increasingly restrictive, and there may be more rigorous enforcement of existing and future laws and regulations. Depending on the development of future laws and regulations, we may experience substantial increases in equipment and operating costs and may experience delays, interruptions or termination of operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines or penalties, the acceleration of cleanup and site restoration costs, the issuance of injunctions to limit or cease operations and the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations.

     Mine Safety and Health

     Our goal is to achieve excellent mine safety and health performance. We measure our progress in this area primarily through the use of accident frequency rates. We believe that it is our responsibility to our employees to provide a superior safety and health environment. We seek to implement this goal by: training employees in safe work practices; openly communicating with employees; establishing, following and improving safety standards; involving employees in the establishment of safety standards; and recording, reporting and investigating all accidents, incidents and losses to avoid reoccurrence. We utilize best practices in emergency preparedness, which includes maintaining multiple mine rescue teams. A portion of the annual performance incentive for all Patriot personnel is tied to our safety record.

     Our approach to safety has resulted in a steady decline in incidence numbers and their severity rates. We received a number of significant safety awards in 2009, including four Mountaineer Guardian Safety Awards from the West Virginia Coal Association. Our training center educates our employees in safety best practices and reinforces our company-wide belief that productivity and profitability follow when safety is a cornerstone of all of our operations.

     Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 (the 1977 Act) significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. In 1978, the Mine Safety and Health Administration (MSHA) was created to carry out the mandates of the 1977 Act.

     Congress enacted the Mine Improvement and New Emergency Response Act of 2006 (MINER Act) as a result of an increase in fatal accidents. Among the new requirements, each miner must have at least two, one-hour Self Contained Self Rescue (SCSR) devices for their use in the event of an emergency (each miner had at least one SCSR device prior to the MINER Act) and additional caches of SCSR devices in the escape routes leading to the surface. Our evacuation training programs have been expanded to include more comprehensive training with the SCSR devices and frequent escape drills, as well as mine-wide simulated disaster training. The MINER Act also requires installation of two-way communication systems that allow communication between rescue workers and trapped miners following an accident as mine operators must have the ability to locate each miner’s last known position immediately before and after a disaster occurs. Compliance with this regulation has and will continue to result in additional expense.

     The states in which we operate also have programs for mine safety and health regulation and enforcement. As a result of industry-wide fatal accidents in recent years, primarily at underground mines, several states including West Virginia and Kentucky have adopted new safety and training regulations. In addition, MSHA has issued numerous new policies and regulations addressing, but not limited to, the following: emergency notification and response plans, increased fines for violations and additional training and mine rescue coverage requirements. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. While these changes have had a significant effect on our operating costs, our U.S. competitors with underground mines are subject to the same degree of regulation.

     Black Lung

     In the U.S., under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator must pay federal black lung benefits and medical expenses to claimants who are current and former employees and last worked for the operator after July 1, 1973. Coal mine operators must also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Historically, less than 7% of the miners currently seeking federal black lung benefits are awarded these benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for coal from underground mines and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

     Mining Control and Reclamation Regulations

     The 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.

     SMCRA permit provisions include requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and revegetation.

     The U.S. mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mining environmental condition of the permit area. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. Our mine and reclamation plans incorporate the provisions of SMCRA, the state programs and the complementary environmental programs that impact coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land, and documents required of the OSM’s Applicant Violator System, including the mining and compliance history of officers, directors and principal stockholders of the applicant.

     Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Some SMCRA mine permit applications take over a year to prepare, depending on the size and complexity of the mine, and often take six months to two years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including public hearings and through intervention in the courts.

     SMCRA requires compliance with many other major environmental programs. These programs include the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act (RCRA), the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and employee right-to-know provisions. Besides OSM, other federal regulatory agencies are involved in monitoring or permitting specific aspects of mining operations. The Environmental Protection Agency (EPA) is the lead agency for states with no authorized programs under the Clean Water Act, RCRA and CERCLA. The U.S. Army Corps of Engineers (ACOE) regulates activities affecting navigable waters and the U.S. Bureau of Alcohol, Tobacco and Firearms regulates the use of explosive blasting.

     Mine Closure Costs

     Various federal and state laws and regulations, including SMCRA, require us to obtain surety bonds or other forms of financial security to secure payment of certain long-term obligations, including mine closure or reclamation costs, federal and state workers’ compensation costs and other miscellaneous obligations. Many of these bonds are renewable on a yearly basis. Surety bond costs have increased in recent years. As of December 31, 2009, we had outstanding surety bonds and total letters of credit of $506.8 million including: $221.2 million for post-mining reclamation; $201.1 million related to workers’ compensation obligations; $50.5 million for retiree health obligations; $10.3 million for coal lease obligations; and $23.7 million for other obligations (including collateral for surety companies and bank guarantees, road maintenance and performance guarantees). Changes in these laws and regulations could require us to obtain additional surety bonds or other forms of financial assurance.

     The AML Fund, which is part of SMCRA, requires a fee on all coal produced in the United States. The proceeds are used to rehabilitate land mined and left unreclaimed prior to August 3, 1977 and to pay healthcare benefit costs of orphan beneficiaries of the Combined Fund. Under current law, from October 1, 2007 through September 30, 2012, the fee is $0.315 per ton for surface-mined coal and $0.135 per ton for underground-mined coal and from October 1, 2012 through September 30, 2021, the fee will be $0.28 per ton for surface-mined coal and $0.12 per ton for underground-mined coal.

Environmental Laws

     We are subject to various federal and state environmental laws and regulations that impose significant requirements on our operations. The cost of complying with current and future environmental laws and regulations and our liabilities arising from past or future releases of, or exposure to, hazardous substances, may adversely affect our business, results of operations or financial condition. In addition, environmental laws and regulations, particularly relating to air emissions, can reduce the demand for coal. Significant public opposition has been raised with respect to the proposed construction of certain new coal-fueled electricity generating plants due to the potential air emissions that would result. Such regulation and opposition could reduce the demand for coal.

     Numerous federal and state governmental permits and approvals are required for mining operations. When we apply for these permits or approvals, we may be required to prepare and present to federal or state authorities data pertaining to the effect or impact that a proposed exploration for, or production or processing of, coal may have on the environment. Compliance with these requirements can be costly and time-consuming and can delay exploration or production operations. A failure to obtain or comply with permits could result in significant fines and penalties and could adversely affect the issuance of other permits for which we may apply.

     Certain key environmental issues, laws and regulations facing us are described further below.

     Clean Water Act

     The federal Clean Water Act and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the United States. The Clean Water Act provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. As a result of recent court decisions and regulatory actions, permitting requirements have increased and could continue to increase the cost and time we expend on compliance with water pollution regulations.

     These and other regulatory requirements, which have the potential to change due to legal challenges, Congressional actions and other developments, increase the cost of, or could even prohibit, certain current or future mining operations. Our operations may not always be able to remain in full compliance with all Clean Water Act obligations and permit requirements, and as a result we have, at times, been subject to compliance orders and private party litigation seeking fines or penalties or changes to our operations.

     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. ACOE issues two types of permits pursuant to Section 404 of the Clean Water Act: nationwide (or “general”) and “individual” permits. Nationwide permits are issued to streamline the permitting process for dredging and filling activities that have minimal adverse environmental impacts. An individual permit typically requires a more comprehensive application process, including public notice and comment, but an individual permit can be issued for ten years (and may be extended thereafter upon application).

     The issuance of permits to construct valley fills and refuse impoundments under Section 404 of the Clean Water Act, whether general permits commonly described as the Nationwide Permit 21 (NWP 21), or individual permits, has been the subject of many recent court cases and increased regulatory oversight, the results of which may materially increase our permitting and operating costs, result in permitting delays, suspend current operations or prevent the opening of new mines.

     For instance, on June 11, 2009, the White House Council on Environmental Quality announced that the EPA, the Department of the Interior (DOI) and the ACOE had entered into a Memorandum of Understanding and Interagency Action Plan on Appalachian Surface Coal Mining (IAP) which is designed to coordinate actions between the agencies and to increase federal scrutiny and oversight of state permitting, enforcement and other activities affecting Appalachian surface mining, all with the stated goal of reducing the environmental impacts of surface coal mining in West Virginia and other Appalachian states. Among other things, the IAP set forth a proposal to prohibit use of the general NWP 21 for surface coal mining operations and a commitment by the DOI to issue guidance clarifying the rules on the use of valley fills within a set distance of a stream. The IAP also stated that there will be a general review of how surface mining is evaluated, authorized and regulated under the Clean Water Act, which may lead to further changes to relevant laws or enforcement thereof.

     On July 15, 2009, the ACOE announced it was soliciting public comments on proposals related to the use of NWP 21 pursuant to the IAP. The proposals modify NWP 21 to prohibit its use in the Appalachian region for surface coal mining operations and suspend the use of NWP 21 in West Virginia and other Appalachian states while the ACOE completes the process of modifying it. In the absence of NWP 21, individual permits are required for surface coal mining projects. We have converted any pending permit applications that were submitted under NWP 21 to individual permit applications and believe a prohibition on NWP 21 permits would have a minimal effect on our future production. However, individual permits take longer and are more costly to obtain.

     In July 2009, the EPA requested that the West Virginia Department of Environmental Protection (WVDEP) provide copies of draft National Pollution Discharge Elimination System (NPDES) permits for discharges associated with surface coal mining operations and announced its plans to conduct Permit Quality Reviews of mining permits in West Virginia. In September 2009, the EPA announced that proposed mining related to certain pending permits in Appalachia would require additional review under the Clean Water Act due to the potential water quality impacts. Seventy-nine permit applications were identified for further, detailed reviews, including our Hobet 45 mine permit application and five of our other permit applications. In January 2010, the evaluation process was finalized on our Hobet 45 permit and the permit was issued. It was the first of the seventy-nine permits to be issued. The EPA and the ACOE continue to perform reviews on the remaining permits pursuant to the IAP to ensure compliance with the Clean Water Act. As a result of the EPA’s increased scrutiny, the WVDEP announced in January 2010 that it is suspending review of permit applications for certain surface mining operations until the EPA establishes standards for such operations.

     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 DOI is considering in order to meet the goals in the Memorandum of Understanding (MOU). If more restrictive options are ultimately adopted, certain mining activities could become prohibited.

     In addition, Region 3 of the EPA, which covers West Virginia, has asked the EPA’s Office of Research & Development (ORD) to provide expert advice on a draft assessment of the ecological impacts associated with surface coal mining involving valley fills. ORD’s assessment will cover loss of headwater streams, downstream water quality, subsequent effects on in-stream biota, cumulative ecological impacts and an evaluation of restoration and recovery methods used by mining companies to address the foregoing.

     It is unknown what other future changes will be implemented to the permitting review and issuance process or to other aspects of surface mining operations, but the increased regulatory focus, recent attention in Congress, the announced changes and reviews and any additional future 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, 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.

     National Pollutant Discharge Elimination System

     The Clean Water Act requires effluent limitations and treatment standards for wastewater discharge through the NPDES program. NPDES permits govern the discharge of pollutants into water and require regular monitoring and reporting and performance standards. States are empowered to develop and enforce “in stream” water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. “In stream” standards vary from state to state. Additionally, through the Clean Water Act Section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.

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

     States must also conduct an anti-degradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality. A state’s anti-degradation regulations would prohibit the diminution of water quality in these streams. Several environmental groups and individuals recently challenged, in part successfully, West Virginia’s anti-degradation policy. As a result, in general, waters discharged from coal mines to high quality streams in West Virginia will be required to meet or exceed new “high quality” standards. This could cause increases in the costs, time and difficulty associated with obtaining new and complying with existing NPDES permits, and could adversely affect our coal production.

     Clean Air Regulations

     The Clean Air Act and the corresponding state laws that regulate the emissions of materials into the air affect U.S. coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter. The Clean Air Act indirectly affects the coal industry by extensively regulating the air emissions of sulfur dioxide, nitrogen oxide, mercury and other compounds emitted by our customers that operate coal-fueled electricity generating plants. Additionally, the EPA has proposed regulating carbon dioxide and other greenhouse gas emissions under the Clean Air Act. In recent years Congress has also considered legislation that would require increased reductions in emissions of carbon dioxide and other greenhouse gases, sulfur dioxide, nitrogen oxide and mercury. Existing and new legislation may lead to some electricity generating customers switching to other sources of fuel which would result in lower levels of regulated emissions.

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

     Sulfur Dioxide and Nitrogen Oxide Emissions

     The EPA promulgated the Clean Air Interstate Rule (CAIR) in March 2005. CAIR requires the reduction of sulfur dioxide and nitrogen oxide emissions from electricity generating plants in 28 eastern states and the District of Columbia (D.C.). CAIR has been subject to a complex series of legal challenges since its promulgation which have alleged, among other things, that it failed to meet the requirements of the federal Clean Air Act. However, as of December 2009, based on an order issued by the U.S. Court of Appeals for the D.C. Circuit, CAIR is currently in effect while the EPA develops a new clean air program for power plants that is consistent with the Clean Air Act. It is unknown what additional or different obligations the EPA will place on power plant air emissions as it revisits the obligations of the Clean Air Act. However, the existing CAIR obligations are expected to require many coal-fueled power sources to install additional pollution control equipment, such as wet scrubbers, or to incur costs to purchase the right to emit from other sources who do reduce their emissions, and it is possible that further changes in the rules, including those relating to emissions limitations and the right to purchase and trade allowances, will require coal-fueled power plants to incur even more costs. Congress is also considering additional legislation aimed at reducing sulfur dioxide and nitrogen oxide emissions from power plants. All of the foregoing could cause our customers to change their regional coal sources or reduce their demand for coal.

     Mercury Emissions

     The EPA promulgated the Clean Air Mercury Rule (CAMR) in March 2005. CAMR permanently caps and reduces nationwide mercury emissions from new and existing coal-fueled power plants. The rule established a market-based cap-and-trade program to reduce nationwide utility emissions of mercury in two distinct phases. CAMR was vacated on February 8, 2008 by the U.S. Court of Appeals for the D.C. Circuit and the EPA decided to develop mercury emissions standards for power plants under the Clean Air Act rather than pursue an appeal of the decision. It is anticipated that any new EPA rule will require power plants to implement maximum achievable control technology (MACT) to reduce their mercury emissions. In January 2009, the EPA issued a memorandum stating that any new electric steam generating units that began construction while CAMR was effective will be subject to a MACT determination on a case-by-case basis. In addition, Congress is also considering legislation mandating mercury emission reductions from coal-fueled power plants. These decisions and future regulations and/or legislation could further limit mercury emissions from power plants, which could adversely affect the demand for coal.

     Particulate Matter

     The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for pollutants considered harmful to public health and the environment. States must develop and maintain state implementation plans (SIPs) that explain how they will comply with established NAAQS. These SIPs are subject to public comment and must be approved by the EPA. Areas not in compliance with NAAQS must take steps to reduce emission levels, and as a result states that are affected must update their SIPs accordingly. Our mining operations are subject to NAAQS and the operations of some of our customers are also subject to NAAQS. In addition, the Clean Air Act allows states to assert claims against a source in an “upwind” state if the source, which could include coal-fueled power plants, is emitting pollutants in an amount and manner that the downwind state believes is preventing it from attaining its NAAQS.

     In October 2006, the EPA issued a final rule revising and updating NAAQS for various forms of particulate matter (the “PM Standards”). Specifically, the PM Standards were updated for fine and coarse particulate matter. Sources of fine particulate matter include power generation, residential fuel burning, and motor vehicles. Coarse particulate matter can be generated by, among other things, mining operations and construction and demolition activities. Three groups of petitioners filed for review of the PM Standards. On February 24, 2009, the U.S. Court of Appeals for the D.C. Circuit issued its opinion, and while it refused to review the petitioners’ challenges to the coarse PM Standards, it remanded certain aspects of the fine PM Standards for reconsideration by the EPA. As a result, the PM Standards related to fine particulate matter, which may affect many of our power plant customers and are currently in effect, will now be subject to further review by the EPA, and therefore these PM Standards could become more stringent. If that occurs, some states will likely need to change their existing SIPs to impose measures designed to ensure compliance with any new PM Standards.

     Existing and possible future restrictions, including any that arise out of the EPA’s reconsideration described above, on the emission of fine or coarse particulate matter could adversely affect our ability to develop new mines, could require us to modify our existing operations and could result in additional and expensive control requirements for coal-fueled power plants, which could adversely affect the demand for coal.

     Ozone

     Nitrogen oxides, which are a by-product of coal combustion, can lead to the creation of ozone. In March 2008, the EPA issued a rule in which it lowered the eight-hour ozone standard from the current 0.0884 parts per million to 0.075 parts per million. The rule became effective on May 27, 2008. Attainment dates for the new standard ranges between 2013 and 2030, depending on the severity of the non-attainment. In January 2010, the EPA proposed to further lower these standards to a range of 0.06 to 0.07 parts per million. The revised standard may require more stringent emissions controls on sources of nitrogen oxides, including coal-fueled electric generating plants. Demand for coal from our mining operations may be adversely affected when the more stringent standard is implemented.

     New Source Review Regulations

     A number of pending regulatory changes and court actions will affect the scope of the EPA’s new source review (NSR) program, which under certain circumstances requires existing coal-fueled power plants to install the more stringent air emissions control equipment required of new plants. For example, in April 2007, the U.S. Supreme Court ruled, in Environmental Defense et al. v. Duke Energy Corp. et al., against a generator in an NSR enforcement proceeding, reversing the decision of the appellate court. This decision could potentially expose numerous electricity generators to government or citizen actions based on a failure to obtain NSR permits for changes to emissions sources and could effectively increase the costs to them of continuing to use coal. Our customers are among the electricity generators subject to enforcement actions and, if found not to be in compliance, our customers could be required to install additional control equipment at the affected plants or they could decide to close some or all of those plants. Changes to the NSR program and/or its enforcement may adversely impact demand for coal.

     Regional Haze

     The EPA published the final regional haze rule on July 1, 1999. This rule established planning and emissions reduction timelines for states to use to improve visibility in national parks throughout the U.S. On June 22, 2001, the EPA signed a proposed rule to guide states in implementing the 1999 rule and in controlling power plant emissions that cause regional haze problems. The proposed rule set guidelines for states in setting Best Alternative Retrofit Technology (BART) at older power plants. On May 5, 2004, the EPA published a proposed rule with new BART provisions and re-proposed the BART guidelines. On June 15, 2005, the EPA finalized amendments to the July 1999 regional haze rule. The EPA directed states to develop plans for meeting its requirements and determined that states which adopt the CAIR cap-and-trade program for sulfur dioxide and nitrogen oxide will be allowed to apply CAIR controls as a substitute for those required by BART.

     Acid Rain

     Title IV of the Clean Air Act regulates sulfur dioxide emissions by all 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. We cannot predict the effect of these provisions of the Clean Air Act on us in future years.

     State Laws

     Several states have recently proposed or adopted legislation or regulations further limiting emissions of sulfur dioxide, nitrogen oxide, mercury and carbon dioxide. Limitations imposed by states on emissions of any of these substances could cause our customers to switch to other fuels to the extent it becomes economically preferable for them to do so.

     Global Climate Change

     One by-product of burning coal is carbon dioxide, which has been linked in certain studies as a contributor to climate change. Recently, legislators, including the U.S. Congress, have been considering the passage of significant new laws. The EPA has also proposed using the Clean Air Act to limit carbon dioxide and other greenhouse gas emissions, and other measures are being imposed or offered with the ultimate goal of reducing greenhouse gas emissions.

     Additionally, in 2009 the U.S. House of Representatives passed, and the U.S. Senate considered, legislation that would, among other things, impose a nationwide cap on carbon dioxide and other greenhouse gas emissions and require major sources, including coal-fueled power plants, to obtain “emission allowances” to meet that cap. It is possible that federal legislation related to greenhouse gas emissions will also be considered in Congress in 2010.

     The U.S. Supreme Court’s April 2007 ruling in Massachusetts v. EPA clarified that the EPA does have the authority to regulate carbon dioxide emissions as a “pollutant” under the Clean Air Act insofar as motor vehicles are concerned. In response to this decision, in December 2009, the EPA released a final finding that emissions of carbon dioxide and other greenhouse gases contribute to air pollution and endanger human health and welfare. This finding will subject certain stationary sources that emit carbon dioxide and other greenhouse gases, including coal-fueled power plants, to existing permitting and other requirements under the Clean Air Act. In October 2009, the EPA published a proposed rule referred to as the Greenhouse Gas Tailoring Rule (GHG Tailoring Rule), which sets forth how the Clean Air Act requirements would be imposed by the EPA on greenhouse gas emissions from stationary sources. The GHG Tailoring Rule, which is expected to be finalized in March 2010, could require the installation of best available control technologies in certain existing facilities and any new facilities that may be considered significant sources of greenhouse gas emissions. These actions by the EPA could be delayed or derailed by a number of factors, including expected legal challenges, lack of funding, and preemption by federal legislation. However, if the EPA’s regulation of greenhouse gases under the Clean Air Act proceeds, it may ultimately affect coal-fueled power plants in particular, and the amount of coal our customers purchase from us could decrease, which could adversely affect our results of operations.

     In the absence of federal legislation or regulation, many states, regions and local authorities have adopted greenhouse gas regulations and initiatives. Several northeastern states are part of the Regional Greenhouse Gas Initiative agreement, or RGGI. The RGGI program calls for signatory states to stabilize carbon dioxide emissions to current levels from 2009 to 2015, followed by a 2.5% reduction each year from 2015 to 2018. Auctions for carbon dioxide allowances under this program began in September 2008 and occur on a quarterly basis.

     In November 2007, the governors of Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Ohio, South Dakota and Wisconsin and the Premier of Manitoba signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions. In addition, more than half of the states in the U.S. have implemented renewable portfolio standards, which mandate that a specified percentage of electricity sales in the state come from renewable energy, and in 2009, Congress also considered legislation with a similar provision.

     These and other state and regional climate change rules will likely require additional controls on coal-fueled power plants and industrial boilers and may even cause some users of coal to switch from coal to a lower carbon fuel. In addition, some states, municipalities and individuals have initiated common law nuisance suits against power, coal, and oil and gas companies alleging that their operations are contributing to climate change. At least two U.S. federal appellate courts have permitted these lawsuits to proceed. The plaintiffs are seeking various remedies, including punitive and compensatory damages and injunctive relief. If successful, there could be reductions in or other limitations on the amount of coal our customers could utilize.

     The permitting of new coal-fueled power plants has also recently been contested by state regulators and environmental organizations based on concerns relating to greenhouse gas emissions. As a result, certain power generating companies may reconsider short-term or long-term plans to build coal-fueled plants or may elect to build capacity using alternative forms of electrical generation.

     Demand for and use of coal also may be limited by any global treaties which place restrictions on carbon dioxide emissions. As part of the United Nations Framework Convention on Climate Change, representatives from 187 nations met in Bali, Indonesia in December 2007 to discuss a program to limit greenhouse gas emissions after 2012. The U.S. participated in the conference. The convention adopted what is called the “Bali Action Plan.” The Bali Action Plan contains no binding commitments, but concludes that “deep cuts in global emissions will be required” and provides a timetable for two years of talks to shape the first formal addendum to the 1992 United Nations Framework Convention on Climate Change treaty since the Kyoto Protocol. In December 2009, an international meeting was held in Copenhagen, Denmark to further progress towards a new treaty or agreement regarding greenhouse gas emissions reductions after 2012. A number of countries, including the U.S., entered into an agreement called the “Copenhagen Accord,” which contains non-binding emissions reductions targets. One of the goals in the Accord is for all developed nations, including the U.S., to provide $100 billion (in the aggregate) annually, beginning in 2020, to developing countries to fund climate change adaptation and mitigation measures. Any treaty or other arrangement ultimately adopted by the U.S. or other countries, may have a material adverse impact on the global supply and demand for coal, which in turn could have an adverse impact on our business.

     Hazardous Waste

     The RCRA established comprehensive requirements for the treatment, storage and disposal of hazardous wastes. These requirements primarily affect our customers as coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous waste materials under RCRA. In 1993 and 2000, the EPA declined to impose hazardous waste regulatory controls under subtitle C of RCRA on the disposal of some coal combustion by-products (CCB), including the practice of using CCB as land fill. The EPA continues to evaluate the possibility of placing additional regulatory requirements on the disposal of such materials.

     The EPA published in the Federal Register in August 2007 a Notice of Data Availability (NODA) of analyses of the disposal of CCB that have become available since the EPA’s RCRA regulatory determination in 2000. The NODA is not a proposed rule and does not include a timeframe for issuing a proposed rule. The EPA has also indicated that it is proceeding with the development of regulations governing the management of CCB. Any regulations that increase the costs associated with handling or disposal of CCB could adversely impact our customers’ operating costs and potentially reduce their purchase of coal.

     Toxic Release Reporting

     Under the EPA’s Toxic Release Inventory process, companies are required to annually report the use, manufacture or processing of listed toxic materials that exceed defined thresholds, including chemicals used in equipment maintenance, reclamation and water treatment.

     Federal and State Superfund Statutes

     CERCLA and similar state laws impose liability for investigation and clean-up of contaminated properties and for damages to natural resources. Under CERCLA or similar state laws, strict, joint and several liability may be imposed on waste generators, site owners or operators and others regardless of fault. Thus, coal mines or other sites that we currently own or have previously owned or operated and sites to which we have sent waste material may be subject to liability under CERCLA and similar state laws. We have been identified as a potentially responsible party at some sites, but based on current information we do not believe any liability under CERCLA or similar state laws will be material.

Additional Information

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

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

New York Stock Exchange Certifications

     Our Chief Executive Officer (CEO) certified to the New York Stock Exchange (NYSE) in 2009 that we were in compliance with the NYSE listing standards. Our CEO and Chief Financial Officer (CFO) have executed the certification required by section 302 of the Sarbanes-Oxley Act of 2002, which is contained herein as exhibits to this Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

Item 1A.		Risk Factors.

RISK FACTORS

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

Risk Factors Relating to Our Business

     A decline in coal prices could reduce our revenues and the value of our coal reserves.

     Our results of operations are dependent upon the prices we charge for our coal as well as our ability to maximize productivity and control costs. Declines in the prices we receive for our coal could adversely affect our operating results and our ability to generate the cash flows we require to fund our existing operations and obligations, improve our productivity and reinvest in our business. The prices we receive for coal depend upon numerous factors beyond our control, including coal and power market conditions, weather patterns affecting energy demand, competition in our industry, availability and costs of competing energy resources, worldwide economic and political conditions, economic strength and political stability in the U.S. and countries in which we have customers, the outcome of commercial negotiations involving sales contracts or other transactions, customer performance and credit risk, availability and costs of transportation, our ability to respond to changing customer preferences, reductions of purchases by major customers, and legislative and regulatory developments, including new environmental regulations affecting the use of coal, such as mercury and carbon dioxide-related limitations. Any material decrease in demand would cause coal prices to decline and require us to decrease costs in order to maintain our margins.

     Any change in coal consumption patterns, in particular by U.S. electric power generators or global steel producers, could result in a decrease in the use of coal by those consumers, which could result in lower prices for our coal, a reduction in our revenues and an adverse impact on our earnings and the value of our coal reserves.

     Thermal coal accounted for approximately 83%, 79% and 77% of our coal sales volume during 2009, 2008 and 2007, respectively. The majority of our sales of thermal coal was to U.S. electric power generators. The amount of coal consumed for U.S. electric power generation is affected primarily by the overall demand for electricity; the location, availability, quality and price of competing fuels for power such as natural gas, nuclear, fuel oil and alternative energy sources such as wind and hydroelectric power; technological developments; limitations on financings for coal-fueled power plants and governmental regulations, including increasing difficulties in obtaining permits for coal-fueled power plants and more burdensome restrictions in the permits received for such facilities. In addition, the increasingly stringent requirements of the Clean Air Act or other laws and regulations, including tax credits that have been or may be provided for alternative energy sources and renewable energy mandates that have been or may be imposed on utilities, may result in more electric power generators shifting away from coal-fueled generation, the closure of existing coal-fueled plants and the building of more non-coal fueled electrical generating sources in the future. All of the foregoing could reduce demand for our coal, which could reduce our revenues, earnings and the value of our coal reserves.

     Weather patterns can greatly affect electricity generation. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increased generating requirements from all sources. Mild temperatures, on the other hand, result in lower electrical demand. Accordingly, significant changes in weather patterns impact the demand for our coal.

     Overall economic activity and the associated demands for power by industrial users can also have significant effects on overall electricity demand. Deterioration in U.S. electric power demand would reduce the demand for our thermal coal and could impact the collectability of our accounts receivable from electric utility customers.

     Metallurgical coal accounted for approximately 17%, 21% and 23% of our coal sales volume during 2009, 2008 and 2007, respectively. A significant portion of our sales of metallurgical coal was to the U.S. steel industry. The majority of our metallurgical coal production is priced annually, and as a result, a decrease in near term metallurgical coal prices could decrease our profitability. The current global recession resulted in decreased demand worldwide for steel and electricity. Deterioration in global steel production reduced the demand for our metallurgical coal, resulting in customer deferrals and cancellations of deliveries during 2009. In addition, the steel industry relies on electric arc furnaces or pulverized coal processes to make steel. These processes do not use furnace coke, an intermediate product produced from metallurgical coal. Therefore, growth in future steel production may not represent increased demand for metallurgical coal. If the demand or pricing for metallurgical coal decreases in the future, the amount of metallurgical coal we sell and prices that we receive for it could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

     Because we sell substantially all of our coal to electric utilities and steel producers, our business and results of operations are closely linked to the global demand for electricity and steel production. Historically, global demand for basic inputs, including for electricity and steel production, has decreased during periods of economic downturn. The current recession has created economic uncertainty, and electric utilities and steel producers have responded by decreasing production.

     Any downward pressure on coal prices, whether due to increased use of alternative energy sources, changes in weather patterns, decreases in overall demand or otherwise, would reduce our revenues and likely adversely impact our earnings and the value of our coal reserves. Additionally, if the current global recession results in sustained decreases in the global demand for electricity and steel production, our financial condition, results of operations and cash flows could be materially and adversely affected.

     Increased competition both within the coal industry, and outside of it, such as competition from alternative fuel providers, may adversely affect our ability to sell coal, and any excess production capacity in the industry could put downward pressure on coal prices.

     The coal industry is intensely competitive both within the industry and with respect to other fuel sources. The most important factors with which we compete are price, coal quality and characteristics, transportation costs from the mine to the customer and reliability of supply. Our principal competitors include Alpha Natural Resources, Inc., Arch Coal, Inc., CONSOL Energy, Inc., International Coal Group, Inc., James River Coal Company, Massey Energy Company and Peabody Energy Corporation. We also compete directly with all other Central Appalachian coal producers, as well as producers from other basins including Northern and Southern Appalachia, the western U.S. and the Interior U.S., and foreign countries, including Colombia, Venezuela, Australia and Indonesia.

     Depending on the strength of the U.S. dollar relative to currencies of other coal-producing countries, coal from such origins could enjoy cost advantages that we do not have. Several domestic coal-producing regions have lower-cost production than Central Appalachia, including the Powder River Basin in Wyoming. Coal with lower delivered costs shipped east from western coal mines and from offshore sources can result in increased competition for coal sales in regions historically sourced from Appalachian producers.

     During the mid-1970s and early 1980s, a growing coal market and increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in production capacity in excess of market demand throughout the industry. We could experience decreased profitability if future coal production is consistently greater than coal demand. Increases in coal prices could encourage the development of expanded coal producing capacity in the U.S. and abroad. Any resulting overcapacity from existing or new competitors could reduce coal prices and, therefore, our revenue and profitability.

     We also face competition from renewable energy providers, like biomass, wind and solar, and other alternative fuel sources, like natural gas and nuclear. Should renewable energy sources become more competitively priced, which may be more likely to occur given the federal tax incentives for alternative fuel sources that are already in place and that may be expanded in the future, or sought after as an energy substitute for fossil fuels, the demand for such fuels may adversely impact the demand for coal. Existing fuel sources also compete directly with coal. For example, weak natural gas prices in 2009 caused some utilities to dispatch their natural gas-fueled plants instead of their coal-fueled plants.

     Our operations are subject to geologic, equipment and operational risks, including events beyond our control, which could result in higher operating expenses and/or decreased production and sales and adversely affect our operating results.

     Our coal mining operations are conducted in underground and surface mines. The level of our production at these mines is subject to operating conditions and events beyond our control that could disrupt operations, affect production and the cost of mining at particular mines for varying lengths of time and have a significant impact on our operating results. Adverse operating conditions and events that coal producers have experienced in the past include changes or variations in geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit; mining and processing equipment failures and unexpected maintenance problems; adverse weather and natural disasters, such as snowstorms, ice storms, heavy rains and flooding; accidental mine water inflows; and unexpected suspension of mining operations to prevent, or due to, a safety accident, including fires and explosions from methane and other sources.

     If any of these conditions or events occur in the future at any of our mines or affect deliveries of our coal to customers, they may increase our cost of mining, delay or halt production at particular mines, or negatively impact sales to our customers either permanently or for varying lengths of time, which could adversely affect our results of operations, cash flows and financial condition. We cannot assure you that these risks would be fully covered by our insurance policies.

     Both our Federal and Panther longwalls encountered some adverse geologic conditions in 2009, but significantly less than the difficulties encountered in 2008. The improved production in 2009 reflects the benefits of mine plan adjustments made in late 2008 to minimize the impact of difficult geology.

     In February 2010, we announced that active mining operations at our Federal mine were temporarily suspended upon discovering potentially adverse atmospheric conditions in an abandoned area of the mine. We are currently conducting additional testing and working with the U.S. Department of Labor, Mine Safety & Health Administration to develop a plan to address this issue so that active mining operations can resume, the timing of which is currently uncertain.

     In addition, the geological characteristics of underground coal reserves in Appalachia and the Illinois Basin, such as rock intrusions, overmining, undermining and coal seam thickness, make these coal reserves complex and costly to mine. As mines become depleted, replacement reserves may not be mineable at costs comparable to those characteristic of the depleting mines. These factors could materially and adversely affect the mining operations and the cost structures of our mining complexes and customers’ willingness to purchase our coal.

     A prolonged shortage of skilled labor and qualified managers in our operating regions could pose a risk to labor productivity and competitive costs and could adversely affect our profitability.

     Efficient coal mining using modern techniques and equipment requires skilled laborers with mining experience and proficiency as well as qualified managers and supervisors. In recent years, a shortage of experienced coal miners and managers in Appalachia and the Illinois Basin has at times negatively impacted our production levels and increased our costs. A prolonged shortage of experienced labor could have an adverse impact on our productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our profitability.

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

     As of December 31, 2009, Patriot had approximately 3,500 employees. Approximately 52% of the employees at company operations were represented by an organized labor union and they generated approximately 46% of the 2009 sales volume. Relations with our employees and, where applicable organized labor, are important to our success. Union labor is represented by the UMWA under labor agreements which expire December 31, 2011. Our represented workers work at various sites in Appalachia and at the Highland complex in the Illinois Basin.

     Due to the increased risk of strikes and other work-related stoppages that may be associated with union operations in the coal industry, our competitors who operate without union labor may have a competitive advantage in areas where they compete with our unionized operations. If some or all of our current non-union operations or those of third party contract miners were to become organized, we could incur an increased risk of work stoppages.

     Our ability to operate our company effectively could be impaired if we lose key personnel or fail to attract qualified personnel.

     We manage our business with a number of key personnel, the loss of a number of whom could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. We cannot be certain that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. Failure to retain or attract key personnel could have a material adverse effect on us.

     If our business does not generate sufficient cash for operations, we may not be able to repay borrowings under our credit facility or fund other liquidity needs, and the amount of our indebtedness could affect our ability to grow and compete.

     Our ability to pay principal and interest on our debt and to refinance our debt, if necessary, will partially depend upon our operating performance. Our business may not generate sufficient cash flows from operations, and future borrowings may not be available to us under our credit facility or otherwise in an amount sufficient to enable us to repay any borrowings under any of our obligations or to fund our other liquidity needs. We also have significant lease and long-term royalty obligations. Our ability to meet our debt, lease and royalty obligations will depend upon our operating performance, which will be affected by economic conditions and a variety of other business factors, many of which are beyond our control.

     The amount of our indebtedness, as well as the current global recession, could have significant consequences, including, but not limited to: (i) limiting our ability to pay principal on our obligations; (ii) limiting our ability to refinance the revolver under our credit facility, which expires October 2011, or our convertible debt, which matures on May 31, 2013, on commercially reasonable terms, or terms acceptable to us or at all; (iii) limiting our ability to obtain additional financing to fund capital expenditures, future acquisitions, working capital or other general corporate requirements; (iv) placing us at a competitive disadvantage with competitors with lower amounts of debt or more advantageous financing options; and (v) limiting our flexibility in planning for, or reacting to, changes in the coal industry. Any inability by us to obtain financing in the future on favorable terms could have a negative effect on our results of operations, cash flows and financial condition.

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

     We expect to have sufficient liquidity to support the development of our business. In the future, however, we may require additional financing for liquidity, capital requirements and growth initiatives. We are dependent on our ability to generate cash flows from operations and to borrow funds and issue securities in the capital markets to maintain and expand our business. We may need to incur debt on terms and at interest rates that may not be as favorable as they have been.

     Our current credit facility is comprised of a group of lenders, each of which has severally agreed to make loans to us under the facility. Currently each of these lenders has met its individual obligation; however, based on the recent instability related to financial institutions we can make no assurances that all future obligations will be met. A failure by one or more of the participants to meet its obligation in the future could have a materially adverse impact on our liquidity, results of operations and financial condition.

     In late 2008 and early 2009, the credit markets experienced extreme volatility and disruption. Any inability by us to obtain financing in the future on favorable terms could have a negative effect on our results of operations, cash flows and financial condition.

     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 letters of credit. As of December 31, 2009, we had outstanding surety bonds and letters of credit aggregating $506.8 million, of which $221.2 million was for post-mining reclamation, $201.1 million related to workers’ compensation obligations, $50.5 million was for retiree health obligations, $10.3 million was for coal lease obligations and $23.7 million was for other obligations (including collateral for surety companies and bank guarantees, road maintenance and performance guarantees). These bonds are typically renewable on an annual basis and the letters of credit are available through our credit facility.

     The current economic recession and volatility and disruption in the credit markets could result in surety bond issuers deciding not to continue to renew the bonds or to demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds or to provide a suitable alternative would have a material adverse effect on us. That failure could result from a variety of factors including lack of availability, higher expense or unfavorable market terms of new surety bonds, restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our credit facility and the exercise by third-party surety bond issuers of their right to refuse to renew the surety.

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

     A significant portion of our revenues is generated through sales to a marketing affiliate of Peabody, and we supply coal to Peabody on a contract basis so Peabody can meet its commitments under customer agreements in existence prior to the spin-off sourced from our operations. Our remaining sales are made directly to electric utilities, industrial companies and steelmakers.

     Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base has changed with deregulation as some utilities have sold their power plants to their non-regulated affiliates or third parties. These new power plant owners or other customers may have credit ratings that are below investment grade. If the creditworthiness of our customers declines significantly and customers fail to stay current on their payments, our business could be adversely affected.

     As of December 31, 2009, we had $142.4 million in notes receivable outstanding from a single counterparty, arising out of the sale of coal reserves and surface land. Each of these notes contains a cross-collaterization provision secured primarily by the underlying coal reserves and surface land.

     In addition, many companies are struggling to maintain their business given the current economic conditions. If our customers are significantly and negatively impacted by the current economic conditions, or by other business factors, our results of operations and financial condition could be materially adversely affected.

     Prolonged global recessionary conditions could adversely affect our financial condition and results of operations.

     Because we sell substantially all of our coal to electric utilities and steel 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 electricity and steel production, has decreased during periods of economic downturn. Prolonged decreases in global demand for electricity and steel production, could adversely affect our financial condition and results of operations.

     The current downturn in the domestic and international financial markets has created economic uncertainty and raised the risk of prolonged global recessionary conditions. During this current downturn, as the demand for coal declined, certain of our thermal and metallurgical coal customers delayed shipments or requested deferrals pursuant to existing long-term coal supply agreements. Other customers may, in the future, seek to delay shipments or request deferrals under existing agreements. Customer deferrals, if agreed to, could affect the amount of revenue we recognize in a certain period and could adversely affect our results of operations and liquidity if we do not receive equivalent value from such customers and we are unable to sell committed coal at the contracted prices under our existing coal supply agreements.

     Additionally, certain of our contracts establish prices and terms that allow us to expect relatively higher levels of profitability than other contracts, assuming both we and our customer perform under the terms of these agreements. To the extent we or a customer do not fully perform under one of these relatively more profitable contracts, our results of operations and operating profit in the reporting period during which such non performance occurs would be materially and adversely affected.

     A decrease in the availability or increase in costs of key supplies, capital equipment or commodities used in our mining operations could decrease our profitability.

     Our purchases of some items of underground mining equipment are concentrated with one principal supplier. Further, our coal mining operations use significant amounts of steel, diesel fuel, explosives and tires. Steel is used in roof control for roof bolts that are required for the room-and-pillar method of mining. If the cost of any of these inputs increases significantly, or if a source for such mining equipment or supplies was unavailable to meet our replacement demands, our profitability could be reduced.

     Failures of contractor-operated sources to fulfill the delivery terms of their contracts with us could reduce our profitability.

     Within our normal mining operations, we utilize third party sources for some coal production, including contract miners, to fulfill deliveries under our coal supply agreements. Approximately 23% of our total sales volume for 2009 was attributable to third-party contractor-operated mines. Certain of their mines have experienced adverse geologic conditions, escalated operating costs and/or financial difficulties that have made their delivery of coal to us at the contracted price difficult or uncertain and, in many instances, these costs have been passed along to us. Our profitability or exposure to loss on transactions or relationships such as these is dependent upon a variety of factors, including the availability and reliability of the third-party supply; the price and financial viability of the third-party supply; our obligation to supply coal to our customers in the event that adverse geologic conditions restrict deliveries from our suppliers; our willingness to reimburse temporary cost increases experienced by third-party coal suppliers; our ability to pass on temporary cost increases to customers; our ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market; and other factors.

     Fluctuations in transportation costs, the availability or reliability of transportation facilities and our dependence on a single rail carrier for transport from certain of our mining complexes could affect the demand for our coal or temporarily impair our ability to supply coal to our customers.

     Coal producers depend upon rail, barge, truck, overland conveyor, ocean-going vessels and port facilities to deliver coal to customers. While our coal customers typically arrange and pay for transportation of coal from the mine or port to the point of use, disruption of these transportation services because of weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, transportation delays, lack of rail or port capacity or other events could temporarily impair our ability to supply coal to customers and thus could adversely affect our results of operations, cash flows and financial condition.

     Transportation costs represent a significant portion of the total cost of coal for our customers, and the cost of transportation is an important factor in a customer’s purchasing decision. Increases in transportation costs, including increases resulting from emission control requirements and fluctuations in the price of diesel fuel and demurrage, could make coal a less competitive source of energy when compared to alternative fuels such as natural gas, or could make Appalachian and/or Illinois Basin coal production less competitive than coal produced in other regions of the U.S. or abroad.

     Significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country and from abroad. Coordination of the many eastern loading facilities, the large number of small shipments, terrain and labor issues all combine to make shipments originating in the eastern U.S. inherently more expensive on a per ton-mile basis than shipments originating in the western U.S. Historically, high coal transportation rates from the western coal producing areas into Central Appalachian markets limited the use of western coal in those markets. However, a decrease in rail rates from the western coal producing areas to markets served by eastern U.S. producers could create major competitive challenges for eastern producers. Increased competition due to changing transportation costs could have an adverse effect on our business, financial condition and results of operations.

     Coal produced at certain of our mining complexes is transported to our customers by a single rail carrier. If there are significant disruptions in the rail services provided by that carrier or if the rail rates rise significantly, then costs of transportation for our coal could increase substantially. Additionally, if there are disruptions of the transportation services provided by the railroad and we are unable to find alternative transportation providers to ship our coal, our business and profitability could be adversely affected.

     Our future success depends upon our ability to develop our existing coal reserves and to acquire additional reserves that are economically recoverable.

     Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our proven and probable coal reserves that are economically recoverable. Furthermore, we may not be able to mine all of our proven and probable coal reserves as profitably as we do at our current operations. Our future success depends upon our conducting successful exploration and development activities and acquiring properties containing economically recoverable proven and probable coal reserves. Our current strategy includes using our existing properties and increasing our proven and probable coal reserves through acquisitions of leases and producing properties.

     Our planned mine development projects and acquisition activities may not result in significant additional proven and probable coal reserves and we may not have continuing success developing additional mines. A substantial portion of our proven and probable coal reserves is not located adjacent to current operations and will require significant capital expenditures to develop. In order to develop our proven and probable coal reserves, we must receive various governmental permits. We make no assurances that we will be able to obtain the governmental permits that we would need to continue developing our proven and probable coal reserves.

     Our mining operations are conducted on properties owned or leased by us. We may not be able to negotiate new leases from private parties or obtain mining contracts for properties containing additional proven and probable coal reserves or maintain our leasehold interest in properties on which mining operations are not commenced during the term of the lease.

     Inaccuracies in our estimates of economically recoverable coal reserves could result in lower than expected revenues, higher than expected costs or decreased profitability.

     We base our proven and probable coal reserve information on engineering, economic and geological data assembled and analyzed by our staff, which includes various engineers and geologists, and outside firms. The reserve estimates as to both quantity and quality are annually updated to reflect production of coal from the reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities and qualities of and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and assumptions relating to geological and mining conditions, relevant historical production statistics, the assumed effects of regulation and taxes, future coal prices, operating costs, mining technology improvements, development costs and reclamation costs.

     For these reasons, estimates of the economically recoverable quantities and qualities attributable to any particular group of properties, classifications of coal reserves based on risk of recovery and estimates of net cash flows expected from particular reserves prepared by different engineers or by the same engineers at different times may vary substantially. Actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our proven and probable coal reserves may vary materially from estimates. These estimates, thus, may not accurately reflect our actual coal reserves. Any inaccuracy in our estimates related to our proven and probable coal reserves could result in lower than expected revenues, higher than expected costs or decreased profitability.

     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 with our customers or find alternate customers willing to purchase our coal, our revenue and operating profits could suffer. We continue to supply coal to Peabody under contracts that existed at the date of spin-off. Contracts with Peabody to purchase coal sourced from our operations accounted for 22% of our revenues for 2009, compared with 35% of our revenues in 2008.

     Our customers may decide not to extend existing agreements or enter into new long-term contracts or, in the absence of long-term contracts, may decide to purchase fewer tons of coal than in the past or on different terms, including under different pricing terms. The global recession has resulted in decreased demand worldwide for steel and electricity. This decrease in demand may cause our customers to delay negotiations for new contracts and/or request lower pricing terms. Furthermore, uncertainty caused by laws and regulations affecting electric utilities could deter our customers from entering into long-term coal supply agreements. Some long-term contracts contain provisions for termination due to environmental changes if these changes prohibit utilities from burning the contracted coal. To the degree that we operate outside of long-term contracts, our revenues are subject to pricing in the spot market that can be significantly more volatile than the pricing structure negotiated through a long-term coal supply agreement. This volatility could adversely affect the profitability of our operations if spot market pricing for coal is unfavorable.

     In most of the contract price adjustment provisions, failure of the parties to agree on price adjustments may allow either party to terminate the contract. Coal supply agreements typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as heat value, sulfur content, ash content, chlorine content, hardness and ash fusion temperature in the case of thermal coal. Failure to meet these specifications could result in economic penalties, including price adjustments, purchasing replacement coal in a higher priced open market, the rejection of deliveries or termination of the contracts.

     Many agreements also contain provisions that permit the parties to adjust the contract price upward or downward for specific events, including inflation or deflation, and changes in the laws regulating the timing, production, sale or use of coal. Moreover, a limited number of these agreements permit the customer to terminate the contract if transportation costs, which are typically borne by the customer, increase substantially or in the event of changes in regulations affecting the coal industry, that increase the price of coal beyond specified amounts.

     Any defects in title of leasehold interests in our properties could limit our ability to mine these properties or could result in significant unanticipated costs.

     We conduct a significant part of our mining operations on properties that we lease. These leases were entered into over a period of many years by certain of our predecessors and title to our leased properties and mineral rights may not be thoroughly verified until a permit to mine the property is obtained. Our right to mine some of our proven and probable coal reserves may be materially adversely affected if there were defects in title or boundaries. In order to obtain leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs, which could adversely affect our profitability.

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

     The credit facility contains certain customary covenants, including financial covenants limiting our total indebtedness (maximum leverage ratio of 2.75) and requiring minimum EBITDA (as defined in the credit facility) coverage of interest expense (minimum interest coverage ratio of 4.0), as well as certain limitations on, among other things, additional debt, liens, investments, acquisitions and capital expenditures, future dividends, common stock repurchases and asset sales. Compliance with debt covenants may limit our ability to draw on our credit facility. In addition, the indenture for our convertible notes prohibits us from engaging in certain mergers or acquisitions unless, among other things, the surviving entity assumes our obligations under the notes. These and other provisions could prevent or deter a third party from acquiring us even where the acquisition could be beneficial to our stockholders.

     The ownership and voting interest of Patriot stockholders could be diluted as a result of the issuance of shares of our common stock to the holders of convertible notes upon conversion.

     The issuance of shares of our common stock upon conversion of the convertible notes could dilute the interests of Patriot’s existing stockholders. The convertible notes are convertible at the option of the holders during the period from issuance to February 15, 2013 into a combination of cash and shares of our common stock, unless we elect to deliver cash in lieu of the common stock portion. The number of shares of our common stock that we may deliver upon conversion will depend on the price of our common stock during an observation period as described in the indenture. Specifically, the number of shares deliverable upon conversion will increase as the common stock price increases above the conversion price of $67.67 per share during the observation period. The maximum number of shares that we may deliver is 2,955,560. However, if certain fundamental changes occur in our business that are deemed “make-whole fundamental changes” as defined by the indenture, the number of shares deliverable on conversion may increase, up to a maximum amount of 4,137,788 shares. These maximum amounts, the conversion rate and conversion price are subject to adjustment for certain dilutive events, such as a stock split or a distribution of a stock dividend.

     The net share settlement feature of our convertible notes may have adverse consequences on our liquidity.

     We will pay an amount in cash equal to the aggregate principal portion of our convertible notes calculated as described under the indenture for the convertible notes. Because we must settle at least a portion of the conversion obligation with regard to the convertible notes in cash, the conversion of our convertible notes may significantly reduce our liquidity.

     Peabody and its shareholders who received Patriot shares at the time of the spin-off could be subject to material amounts of taxes if the spin-off is determined to be a taxable transaction.

     On September 26, 2007, Peabody received a ruling from the Internal Revenue Service (IRS) to the effect that the spin-off qualified as a tax-free transaction under Section 355 of the Code. The IRS did not rule on whether the spin-off satisfied certain requirements necessary to obtain tax-free treatment under Section 355 of the Code. Therefore, in addition to obtaining the ruling from the IRS, Peabody received a favorable opinion from Ernst & Young LLP as to the satisfaction of these qualifying conditions required for the application of Section 355 to the spin-off. Ernst & Young LLP’s tax opinion is not binding on the IRS or the courts.

     The letter ruling and the Ernst & Young LLP opinion relied on certain representations, assumptions and undertakings, including those relating to the past and future conduct of our business, and neither the letter ruling nor the Ernst & Young LLP opinion would be valid if such representations, assumptions and undertakings were incorrect. Moreover, the letter ruling did not address all of the issues that are relevant to determining whether the distribution would qualify for tax-free treatment. Notwithstanding the letter ruling and the Ernst & Young LLP opinion, the IRS could determine that the distribution should be treated as a taxable transaction if it determines that any of the representations, assumptions or undertakings that were included in the request for the letter ruling are false or have been violated or if it disagrees with the conclusions in the Ernst & Young LLP opinion that are not covered by the letter ruling. If, notwithstanding the letter ruling and opinion, the spin-off is determined to be a taxable transaction, Peabody shareholders who received Patriot shares at the time of the spin-off and Peabody could be subject to material amounts of taxes.

     Patriot could be liable to Peabody for adverse tax consequences resulting from certain change in control transactions and therefore could be prevented from engaging in strategic or capital raising transactions.

     Peabody could recognize taxable gain if the spin-off is determined to be part of a plan or series of related transactions pursuant to which one or more persons acquire, directly or indirectly, stock representing a 50% or greater interest in either Peabody or Patriot. Under the Code, any acquisitions of Peabody or Patriot within the four-year period beginning two years before the date of the spin-off are presumed to be part of such a plan unless they are covered by at least one of several mitigating rules established by IRS regulations. Nonetheless, a merger, recapitalization or acquisition, or issuance or redemption of Patriot common stock after the spin-off could, in some circumstances, be counted toward the 50% change of ownership threshold. The tax separation agreement precludes Patriot from engaging in some of these transactions unless Patriot first obtains a tax opinion acceptable to Peabody or an IRS ruling to the effect that such transactions will not result in additional taxes. The tax separation agreement further requires Patriot to indemnify Peabody for any resulting taxes regardless of whether Patriot first obtains such opinion or ruling. As a result, Patriot may not be able to engage in strategic or capital raising transactions that stockholders might consider favorable, or to structure potential transactions in the manner most favorable to Patriot.

     Although not required pursuant to the terms of the tax separation agreement, in connection with the execution of the Magnum merger agreement, Patriot obtained an opinion dated April 2, 2008 from Ernst & Young LLP to the effect that the issuance of the Patriot common stock pursuant to the merger agreement would not result in an acquisition of a 50% or greater interest in Patriot within the meaning of Sections 355(d)(4) and (3)(4)(A) of the Code.

     Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations.

     Terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the U.S. or its allies, or military or trade disruptions affecting our customers or the economy as a whole may materially adversely affect our operations or those of our customers. As a result, there could be delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. Any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

Risks Related to Environmental and Other Regulation

     Recent increased focus by regulatory authorities on the effects of surface coal mining on the environment, the disposal of mining spoil material and surface coal mining permitting may materially adversely affect us.

     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. ACOE issues two types of permits pursuant to Section 404 of the Clean Water Act: “nationwide” (or general) and “individual” permits. Nationwide permits are issued to streamline the permitting process for dredging and filling activities that have minimal adverse environmental impacts. Regulators are considering prohibiting the use of nationwide permits for surface coal mining in Appalachia. 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 recent court cases and increased regulatory oversight resulting in permitting delays that are expected to cause a delay in or even prevent the opening of new mines. See Item 1. Regulatory Matters for additional description of Section 404 of the Clean Water Act.

     It is unknown what future changes will be implemented to the permitting review and issuance process or to other aspects of surface mining operations, but the increased regulatory focus, future laws and judicial decisions and any other future changes could materially and adversely affect all coal mining companies operating in Appalachia, including us. In particular, we will incur additional permitting and operating costs and we could be unable to obtain new permits or maintain existing permits and we could incur fines, penalties and other costs, any of which could materially adversely affect our business. If surface coal mining methods are limited or prohibited, it could significantly increase our operational costs and make it more difficult to economically recover a significant portion of our reserves. In the event that we cannot increase the price we charge for coal to cover the higher production costs without reducing customer demand for our coal, there could be a material adverse effect on our financial condition and results of operations. In addition, increased public focus on the environmental, health and aesthetic impacts of surface coal mining could harm our reputation and reduce demand for coal.

     Like many of our competitors, we cannot always completely comply with permit restrictions relating to the discharge of selenium into surface water, which has led to court challenges and related orders and settlements, has required us to pay fines and penalties, and may require us to incur other significant costs and may be difficult to resolve 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. Some of our permits have currently effective limits on the selenium that can be discharged, and other permits have limits that will be effective in the future. There is currently no reasonably available technology that has been proven to effectively address selenium exceedances in permitted water discharges, and accordingly we cannot currently meet the selenium discharge limits applicable to our operations.

     A federal court ordered Apogee Coal Company, LLC (Apogee), one of our subsidiaries, to develop and implement a treatment plan relating to the outfalls governed by its permits, or to show cause of its inability to do so. In addition, as a result of a lawsuit filed by the WVDEP in state court in West Virginia, Hobet Mining, LLC (Hobet), one of our subsidiaries, has entered into a settlement agreement with the WVDEP requiring Hobet to pay fines and penalties with respect to past violations of selenium limitations under four NPDES permits and to study potential treatments to address the selenium discharges.

     As a result of the above, we are actively engaged in studying potential solutions to controlling selenium discharges and we have been installing test treatment facilities at various permitted outfalls. Because the levels and frequency of selenium discharges at any given outfall will be different, the solution for each outfall may be very different and a variety of solutions will therefore ultimately be required. The potential solutions identified to date, some of which have been provided to the federal court in West Virginia, have not proven to be effective and otherwise may not be feasible due to a range of problems concerning technological issues, prohibitive implementation costs and other issues. While we are actively continuing to explore options, there can be no assurance as to when a definitive solution will be identified and implemented. While these selenium discharge issues generally relate to historical rather than ongoing mining operations, any failure to meet the deadlines in our consent decrees and court orders or to otherwise comply with selenium limits in our permits could result in further litigation against us, an inability to obtain new permits or to maintain existing permits, the incurrence of significant and material fines and penalties or other costs and could otherwise materially adversely affect our results of operations, cash flows and financial condition.

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

     One by-product of burning coal is carbon dioxide, which has been linked in certain studies as a contributor to climate change. Recently, legislators, including the U.S. Congress, have been considering the passage of significant new laws, such as those that would impose a nationwide cap on carbon dioxide and other greenhouse gas emissions and require major sources, including coal-fueled power plants, to obtain “emission allowances” to meet that cap, and other measures are being imposed or proposed with the ultimate goal of reducing carbon dioxide and other greenhouse gas emissions. In addition, the EPA and other regulators are using existing laws, including the federal Clean Air Act, to impose obligations, including emissions limits, on carbon dioxide and other greenhouse gas emissions. Further, governmental agencies have been providing grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of greenhouse gas emissions, which may lead to more competition from those subsidized entities. See Item 1. Regulatory Matters for additional discussion of greenhouse gas emission regulation.

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

     A well publicized failure in December 2008 of an ash slurry impoundment maintained by the Tennessee Valley Authority has led to new legislative and regulatory proposals that, if enacted, may impose significant obligations on us or our customers. The EPA has indicated that it plans to proceed in developing regulations to address the management of coal ash.

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

     Our mining operations are extensively regulated, which imposes significant costs on us, and future regulations or violations of regulations could increase those costs or limit our ability to produce coal.

     Federal and state authorities regulate the coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, the protection of the environment, plants and wildlife, reclamation and restoration of mining properties after mining is completed, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state 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. The costs, liabilities and requirements associated with these regulations are often costly and time-consuming and may delay commencement or continuation of exploration or production. New or revised legislation or administrative regulations (or judicial or administrative interpretations of existing laws and regulations), including proposals related to the protection of the environment or employee health and safety that would further regulate and tax the coal industry 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. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors could have a material adverse effect on our results of operations, cash flows and financial condition.

     In the event of certain violations of safety rules, MSHA may order the temporary closure of mines. Our customers may challenge our issuance of force majeure notices in connection with such closures. If these challenges are successful, we could be obligated to make up lost shipments, to reimburse customers for the additional costs to purchase replacement coal, or, in some cases, to terminate certain sales contracts.

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

     Certain of our current and historical coal mining operations have used hazardous materials and, to the extent that such materials are not recycled, they could become hazardous waste. We may be subject to claims under federal and state statutes and/or common law doctrines for toxic torts and other damages, as well as for natural resource damages and for the investigation and remediation of soil, surface water, groundwater, and other media under laws such as CERCLA, commonly known as Superfund. Such claims may arise, for example, out of current or former conditions at sites that we own or operate currently, as well as at sites that we and companies we acquired owned or operated in the past, and at contaminated sites that have always been owned or operated by third parties. Liability may be without regard to fault and may be strict, joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share.

     We maintain coal slurry impoundments at a number of our mines. Such impoundments are subject to extensive regulation. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as streams or bodies of water and wildlife, as well as related personal injuries and property damages which in turn can give rise to extensive liability. Some of our impoundments overlie areas where some mining has occurred, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties. In addition, the EPA administrator has publicly called for more inspections of coal slurry impoundments.

     These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could adversely affect us.

     We are involved in legal proceedings that if determined adversely to us, could significantly impact our profitability, financial position or liquidity.

     We are involved in various legal proceedings that arise in the ordinary course of business. Some of the lawsuits seek fines or penalties and damages in very large amounts, or seek to restrict our business activities. In particular, we are subject to legal proceedings relating to our receipt of and compliance with permits under the Clean Water Act and to other legal proceedings relating to environmental matters involving current and historical operations and ownership of land. It is currently unknown what the ultimate resolution of these proceedings will be, but the costs of resolving these proceedings could be material, and could result in an obligation to change our operations in a manner that could have an adverse effect on us. See Item 3. Legal Proceedings for a full description of our environmental claims and litigation.

     If our assumptions regarding our likely future expenses related to employee benefit plans are incorrect, then expenditures for these benefits could be materially higher than we have assumed.

     We provide post-retirement health and life insurance benefits to eligible union and non-union employees. We calculated the total accumulated postretirement benefit obligation according to the guidance provided by U.S. accounting standards. We estimated the present value of the obligation to be $1.2 billion as of December 31, 2009. We have estimated these unfunded obligations based on actuarial assumptions described in the notes to our consolidated financial statements. If our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially higher.

     Due to our participation in multi-employer pension plans and statutory retiree healthcare plans, we may have exposure that extends beyond what our obligations would be with respect to our employees.

     Certain of our subsidiaries participate in two defined benefit multi-employer pension funds that were established as a result of collective bargaining with the UMWA pursuant to the 2007 NBCWA as periodically negotiated. These plans provide pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked prior to January 1, 1976, in the case of the UMWA 1950 Pension Plan, or after December 31, 1975, in the case of the UMWA 1974 Pension Plan. In December 2006, the 2007 NBCWA was signed, which required funding of the 1974 Pension Plan through 2011 under a phased funding schedule. The funding is based on an hourly rate for active UMWA workers. Under the labor contract, the per hour funding rate increased to $4.25 in 2009 and will increase each year thereafter until reaching $5.50 in 2011. Our subsidiaries with UMWA-represented employees are required to contribute to the 1974 Pension Plan at the new hourly rates. Contributions to these funds could increase as a result of future collective bargaining with the UMWA, a shrinking contribution base as a result of the insolvency of other coal companies who currently contribute to these funds, lower than expected returns on pension fund assets or other funding deficiencies.

     The 2006 Act authorized $490 million in general fund revenues to pay for certain benefits, including the healthcare costs under the Combined Fund, 1992 Benefit Plan and 1993 Benefit Plan for “orphans” who are retirees and their dependents. Under the 2006 Act, these orphan benefits will be the responsibility of the federal government on a phased-in basis through 2012. If Congress were to amend or repeal the 2006 Act or if the $490 million authorization were insufficient to pay for these healthcare costs, certain of our subsidiaries, along with other contributing employers and their affiliates, would be responsible for the excess costs. Our aggregate cash payments to the Combined Fund, 1992 Benefit Plan and 1993 Benefit Plan were $17.5 million and $17.9 million during 2009 and 2008, respectively.

     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 $665.0 million as of December 31, 2009. These obligations arise under the Coal Act, the 2007 NBCWA and predecessor agreements and a subsidiary’s salaried retiree healthcare plan.

     Although the Peabody subsidiary is obligated to pay such obligations, certain Patriot subsidiaries also remain jointly and severally liable for the Coal Act obligations, and secondarily liable for the assumed 2007 NBCWA obligations and retiree healthcare obligations for certain participants under a subsidiary’s retiree healthcare plan. As a consequence, Patriot’s recorded retiree healthcare obligations and related cash costs could increase substantially if the Peabody subsidiary would fail to perform its obligations under the liability assumption agreements. These additional liabilities and costs, if incurred, could have a material adverse effect on our results of operations, cash flows and financial condition.

     We have significant reclamation and mine closure obligations. If the assumptions underlying our accruals are inaccurate, we could be required to expend greater amounts than anticipated.

     SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of deep mining. We calculated the total estimated reclamation and mine-closing liabilities in accordance with authoritative guidance. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. As of December 31, 2009, we had accrued reserves of $124.6 million for reclamation liabilities and an additional $119.9 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 cost or timing vary from assumptions, if the underlying facts change or if governmental requirements change significantly.

Item 1B.		Unresolved Staff Comments.

     None.

Item 2.		Properties.

Coal Reserves

     We had an estimated 1.8 billion tons of proven and probable coal reserves as of December 31, 2009 located in Appalachia and the Illinois Basin. Of our proven and probable coal reserves 13%, or just over 247 million tons, are compliance coal and 1,595 million tons are non-compliance coal. We own approximately 36% of these reserves and lease property containing the remaining 64%. Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu and complies with certain requirements of the Clean Air Act. Electricity generators are able to use non-compliance coal by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.

     Below is a table summarizing the locations and reserves of our major operating regions.

Proven and Probable

Reserves as of

December 31, 2009(1)

Owned

Leased

Total

Geographic Region

Tons

Tons

Tons

(In millions)

Appalachia

280

916

1,196

Illinois Basin

380

266

646

Total proven and probable coal reserves

660

1,182

1,842

(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 1,118 million tons of proven and 724 million tons of probable coal reserves are established within these guidelines. Patriot does not include sub-economic coal within these proven and probable reserve estimates. Proven reserves require the coal to lie within one-quarter mile of a valid point of measure or point of observation, such as exploratory drill holes or previously mined areas. Estimates of probable reserves may lay more than one-quarter mile, but less than three-quarters of a mile, from a point of thickness measurement. Estimates within the proven category have the highest degree of assurance, while estimates within the probable category have only a moderate degree of geologic assurance. Further exploration is necessary to place probable reserves into the proven reserve category. Our active properties generally have a much higher degree of reliability because of increased drilling density.

     Reserve estimates as of December 31, 2009 were prepared by our Director of Geology, a Certified Professional Geologist, by updating the December 31, 2008 estimates and incorporating reserve statements from outside consultants for certain operations. The reserve estimation process includes evaluating select reserve areas, updating estimates to reflect remodeling and additional available drilling information and coordinating third-party reviews when deemed necessary. This process confirmed that Patriot had approximately 1.8 billion tons of proven and probable reserves as of December 31, 2009.

     Our reserve estimates are predicated on information obtained from an ongoing drilling program, which totals more than 35,000 individual data points. We compile data from individual data points in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the quality of the coal are determined. The density of the data determines whether the reserves will be classified as proven or probable. The reserve estimates are then input into a computerized land management system, which overlays the geological data with data on ownership or control of the mineral and surface interests to determine the extent of our proven and probable coal reserves in a given area. The land management system contains reserve information, including the quantity and quality (where available) of coal reserves as well as production rates, surface ownership, lease payments and other information relating to our coal reserves and land holdings. We periodically update our reserve estimates to reflect production of coal from the reserves and new drilling or other data received. Accordingly, reserve estimates will change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings, modification of mining methods and other factors.

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

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

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

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

     Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to 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.

     The following chart provides a summary, by geographic region and mining complex, of production for the years ended December 31, 2009, 2008 and 2007, tonnage of coal reserves assigned to our operating mines, property interest in those reserves and other characteristics of the facilities. Production for the Magnum operations is included from the date the acquisition was consummated, July 23, 2008.

PRODUCTION AND ASSIGNED RESERVES⁽¹⁾

		Production																Sulfur Content(2)																As of December 31, 2009
																						>1.2 to 2.5
																		≤1.2 lbs.				lbs.				>2.5 lbs.
		Year				Year				Year								Sulfur				Sulfur				Sulfur				As				Assigned
		Ended				Ended				Ended								Dioxide				Dioxide				Dioxide				Received				Proven and
Geographic Region/		Dec 31,				Dec 31,				Dec 31,				Type of				per				per				per				Btu per				Probable																Under-
Mining Complex		2009				2008				2007				Coal				Million Btu				Million Btu				Million Btu				Pound(3)				Reserves				Owned				Leased				Surface				ground
(Tons in millions)
Appalachia:
Big Mountain			2.0				1.9				1.6			Steam					9				17				—				12,200				26				—				26				—				26
Blue Creek			0.1				—				—			Steam					—				15				—				12,000				15				—				15				—				15
Campbell’s Creek			1.0				0.6				—			Steam					1				2				—				12,200				3				—				3				—				3
Corridor G			3.6				1.6				—			Steam					5				71				1				12,500				77				3				74				53				24
Jupiter			—				0.2				—			Steam					2				17				—				12,500				19				—				19				4				15
Kanawha Eagle			1.9				2.1				2.1			Met/Steam					46				5				39				13,100				90				—				90				—				90
Logan County			2.6				1.0				—			Met/Steam					21				4				—				12,900				25				8				17				15				10
Paint Creek			2.1				1.1				—			Met/Steam					8				23				—				13,300				31				—				31				4				27
Panther			2.1				0.6				—			Met/Steam					44				24				—				13,500				68				1				67				—				68
Remington			0.2				0.3				—			Steam					3				3				—				12,200				6				—				6				1				5
Rocklick			1.5				2.6				3.1			Met/Steam					6				21				—				12,800				27				—				27				5				22
Wells			3.4				3.4				3.2			Met/Steam					24				23				—				13,400				47				—				47				—				47
Federal			3.8				3.1				4.0			Steam					—				12				42				13,300				54				48				6				—				54
Total			24.3				18.5				14.0								169				237				82								488				60				428				82				406
Illinois Basin:
Bluegrass			2.5				2.8				2.5			Steam					—				—				24				11,100				24				—				24				3				21
Dodge Hill			0.9				1.0				1.1			Steam					—				—				19				12,700				19				4				15				—				19
Highland			3.7				3.9				3.9			Steam					—				—				83				11,300				83				28				55				—				83
Total			7.1				7.7				7.5								—				—				126								126				32				94				3				123
Total			31.4				26.2				21.5								169				237				208								614				92				522				85				529

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, 2009

																										Sulfur Content(2)
																														>1.2 to 2.5				>2.5 lbs.
																										≤1.2 lbs.				lbs.				Sulfur
																										Sulfur				Sulfur				Dioxide
										Proven																Dioxide				Dioxide				per				As
										and																per				per				Million Btu				Received
		Total				Tons				Probable				Proven				Probable				Type of				Million Btu				Million Btu				(Non-				Btu per				Reserve Control								Mining Method
Coal Seam Location		Assigned(1)				Unassigned(1)				Reserves				(Measured)				(Indicated)				Coal				(Phase II)				(Phase I)				Compliance)				Pound(3)				Owned				Leased				Surface				Underground
(Tons in millions)
Appalachia:
Ohio			—				26				26				19				7			Steam					—				—				26				10,900				26				—				—				26
West Virginia			488				682				1,170				793				377			Met/Steam					243				671				256				13,000				254				916				189				981
Total			488				708				1,196				812				384								243				671				282								280				916				189				1,007
Illinois Basin:
Illinois			—				237				237				94				143			Steam					4				38				195				10,800				235				2				1				236
Kentucky			126				283				409				212				197			Steam					—				—				409				11,400				145				264				34				375
Total			126				520				646				306				340								4				38				604								380				266				35				611
Total proven and probable			614				1,228				1,842				1,118				724								247				709				886								660				1,182				224				1,618

Item 3.		Legal Proceedings.

     From time to time, Patriot and its subsidiaries are involved in legal proceedings, arbitration proceedings and administrative procedures arising in the ordinary course of business. Management believes that the ultimate resolution of such pending or threatened proceedings is not reasonably likely to have a material effect on our financial position, results of operations or cash flows. Our significant legal proceedings are discussed below.

     We are subject to applicable federal, state and local environmental laws and regulations where we conduct operations. Current and past mining operations are primarily covered by SMCRA, the Clean Water Act and the Clean Air Act, but are also covered by, among other laws, CERCLA (also known as Superfund) and RCRA.

     Clean Water Act Permit Issues

     The federal Clean Water Act and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the United States. In particular, the Clean Water Act requires effluent limitations and treatment standards for wastewater discharge through the NPDES program. NPDES permits, which we must obtain for both active and historical mining operations, govern the discharge of pollutants into water, require regular monitoring and reporting, and set forth performance standards. States are empowered to develop and enforce “in-stream” water quality standards, which are subject to change and must be approved by the EPA. In-stream standards vary from state to state.

     Environmental claims and litigation in connection with our various NPDES permits, and related Clean Water Act issues, include the following:

     EPA Consent Decree

     In February 2009, we entered into a consent decree with the EPA and the WVDEP to resolve certain claims under the Clean Water Act and the West Virginia Water Pollution Control Act relating to NPDES permits at several Magnum mining operations in West Virginia that existed prior to our acquisition of these operations. The consent decree was entered by the federal district court on April 30, 2009. Under the terms of the consent decree, we paid a civil penalty of $6.5 million in June 2009. We also could be subject to stipulated penalties in the future for failure to comply with certain permit requirements as well as certain other terms of the consent decree. Because our operations are complex and periodically exceed our permit limitations, it is possible that we will have to pay stipulated penalties in the future, but we do not expect the amounts of any such penalties to be material. The civil penalty of $6.5 million was accrued as part of the Magnum acquisition purchase accounting described in Note 6. The consent decree also requires us to implement an enhanced company-wide environmental management system, which includes regular compliance audits, electronic tracking and reporting, and annual training for all employees and contractors with environmental responsibilities. In addition, we will complete several stream restoration projects in consultation with the EPA and WVDEP. These latter requirements could result in incremental operating costs in addition to the $6.5 million civil penalty. We anticipate the incremental costs will be between $5 million and $10 million.

     In a separate administrative proceeding with the WVDEP, we paid a civil penalty of $315,000 in the second quarter of 2009 for past violations of other NPDES permits held by certain subsidiaries.

     Apogee Coal Company, LLC (Apogee)

     In 2007, 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 Clean Water Act). We refer to this lawsuit as the Federal Apogee Case. This lawsuit alleged that Apogee had violated water discharge limits for selenium set forth in one of its NPDES permits. The lawsuit sought fines and penalties as well as injunctions prohibiting Apogee from further violating laws and its permit.

     On March 19, 2009, the U.S. District Court approved a consent decree between Apogee, Hobet and the plaintiffs. The consent decree extended the compliance deadline to April 5, 2010 and added interim reporting requirements up to that date. Under the terms of the March 2009 consent decree, we paid a $50,000 penalty to the U.S. Treasury and $325,000 in attorneys’ fees in the second quarter of 2009. We also agreed to spend approximately $350,000 to implement a pilot project using certain reverse osmosis technology to determine whether the technology can effectively treat selenium discharges from mining outfalls, and to undertake interim reporting obligations. Finally, we agreed to comply with our NPDES permit’s water discharge limits for selenium by April 5, 2010. We have completed the pilot project and submitted our findings for review as required under the consent decree. We continue to install treatment systems at various permitted outfalls, but we will be unable to comply with selenium discharge limits by April 5, 2010 due to the ongoing inability to identify effective technology. We intend to seek a modification of the consent decree, to among other things, extend the compliance deadlines in order to continue our efforts to identify viable treatment alternatives.

     Currently, available technology has not been fully tested or proven effective at addressing selenium discharges in excess of allowable limits in mining outfalls similar to ours, and alternative technology is still in the research stage of development. The potential solutions identified to date, including the technology we are currently utilizing, have not been proven to be effective at all scales of operation, and otherwise may not be feasible, particularly at larger scale operations, due to a range of problems concerning technological issues, prohibitive implementation costs and other issues. While we are actively continuing to explore options, there can be no assurance as to when a definitive solution will be identified and implemented.

     Legislative developments in West Virginia have created the potential for industry-wide selenium compliance deadlines to be extended from 2010 to 2012. On May 13, 2009, the Governor of West Virginia signed a bill that authorized the WVDEP to extend selenium compliance deadlines to 2012 and appropriated state funds for selenium research. The bill cites “concerns within West Virginia regarding the applicability of the research underlying the federal selenium criteria to a state such as West Virginia which has high precipitation rates and free-flowing streams and that the alleged environmental impacts that were documented in the applicable federal research have not been observed in West Virginia.” As a result of this bill, the WVDEP is required to perform research that will assist in better defining and developing state laws and regulations addressing selenium discharges.

     We estimated the costs to treat our selenium discharges in excess of allowable limits at a net present value of $85.2 million as of the Magnum acquisition date. This liability reflects the estimated costs of the treatment systems necessary to be installed and maintained with the goal of meeting the requirements of current court orders, consent decrees and mining permits. This estimate was prepared considering the dynamics of current legislation, capabilities of currently available technology and our planned remediation strategy. Future changes to legislation, findings from current research initiatives and the pace of future technological progress could result in costs that differ from our current estimates, which could have a material adverse affect on our results of operations, cash flows and financial condition. Additionally, any failure to meet the deadlines set forth in the March 2009 consent decree or established by the federal government or the State of West Virginia or to otherwise comply with selenium limits in our permits could result in further litigation against us, an inability to obtain new permits or to maintain existing permits, and the imposition of significant and material fines and penalties or other costs and could otherwise materially adversely affect our results of operations, cash flows and financial condition.

     Hobet Mining, LLC (Hobet)

     In 2007, Hobet was sued for exceeding effluent limits contained in its NPDES permits in state court in Boone County by the WVDEP. We refer to this case as the WVDEP Action. In 2008, OVEC and another environmental group filed a lawsuit against Hobet and WVDEP in the U.S. District Court (pursuant to the citizen suit provisions of the Clean Water Act). We refer to this case as the Federal Hobet Case. The Federal Hobet Case involved the same four NPDES permits that were the subject of the WVDEP Action in state court. However, the Federal Hobet Case focused exclusively on selenium exceeding allowable limits in permitted water discharges, while the WVDEP Action addressed all effluent limits, including selenium, established by the permits. The Federal Hobet Case was included in the same March 19, 2009 consent decree that addressed the Federal Apogee Case discussed above, and the terms of that consent decree, including the April 5, 2010 deadline to comply with the selenium effluent limits established by our permits, also apply to Hobet.

     The WVDEP Action was resolved by a settlement and consent order entered in the Boone County circuit court on September 5, 2008. As part of the settlement, we paid approximately $1.5 million in civil penalties, with the final payment made in July 2009. The settlement also required us to complete five supplemental environmental projects estimated to cost approximately $2.6 million, many of which focus on identifying methods for treatment of selenium discharges and studying the effects of selenium on aquatic wildlife. Finally, we agreed to make gradual reductions in the selenium discharges from our Hobet Job 21 surface mine, to achieve full compliance with our NPDES permits by April 2010, and to study potential treatments for wastewater runoff.

     On October 8, 2009, a motion to enter a modified settlement and consent order was submitted to the Boone County circuit court. This motion to modify the settlement and consent order was jointly filed by Patriot and the WVDEP. The motion includes, among other term modifications, an extension of the date to achieve full compliance with our NPDES permits from April 2010 to July 2012. On December 3, 2009, the Boone County circuit court approved and entered the modified settlement and consent order.

     As a result of ongoing litigation and federal regulatory initiatives related to water quality standards that affect valley fills, impoundments and other mining practices, including the selenium discharge matters described above, the process of applying for new permits has become more time-consuming and complex, the review and approval process is taking longer, and in certain cases, new permits may not be issued.

     Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)

     CERCLA and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to natural resources. Under CERCLA and many similar state statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault. These regulations could require us to do some or all of the following: (i) remove or mitigate the effects on the environment at various sites from the disposal or release of certain substances; (ii) perform remediation work at such sites; and (iii) pay damages for loss of use and non-use values.

     Although waste substances generated by coal mining and processing are generally not regarded as hazardous substances for the purposes of CERCLA and similar legislation, and are generally covered by SMCRA, some products used by coal companies in operations, such as chemicals, and the disposal of these products are governed by CERCLA. Thus, coal mines currently or previously owned or operated by us, and sites to which we have sent waste materials, may be subject to liability under CERCLA and similar state laws. A predecessor of one of our subsidiaries has been named as a potentially responsible party at a third-party site, but given the large number of entities involved at the site and our anticipated share of expected cleanup costs, we believe that the ultimate liability, if any, will not be material to our financial condition and results of operations.

     Flood Litigation

     2001 Flood Litigation

     One of our subsidiaries, Catenary Coal Company, LLC (Catenary), has been named as a defendant, along with various other property owners, coal companies, timbering companies and oil and natural gas companies, in connection with alleged damages arising from flooding that occurred on July 8, 2001 in various watersheds, primarily located in southern West Virginia (referred to as the 2001 flood litigation). Pursuant to orders from the West Virginia Supreme Court of Appeals, the cases are being handled as mass litigation, and a panel of three judges was appointed to handle the matters that have been divided between the judges pursuant to the various watersheds.

     In December 2009, an agreement was reached to settle this litigation. These cases will be dismissed once the settlement is finalized and approved by the West Virginia Supreme Court of Appeals. Pursuant to the purchase and sale agreement related to Magnum, Arch Coal, Inc. (Arch) indemnifies us against claims arising from certain pending litigation proceedings, including the 2001 flood litigation, which will continue indefinitely. The failure of Arch to satisfy its indemnification obligations under the purchase agreement could have a material adverse effect on us.

     2004 Flood Litigation

     In 2006, Hobet and Catenary, two of our subsidiaries, were named as defendants along with various other property owners, coal companies, timbering companies and oil and natural gas companies, in lawsuits arising from flooding that occurred on May 30, 2004 in various watersheds, primarily located in southern West Virginia. This litigation is pending before two different judges in the Circuit Court of Logan County, West Virginia. In the first action, the plaintiffs have asserted that (i) Hobet failed to maintain an approved drainage control system for a pond on land near, on, and/or contiguous to the sites of flooding; and (ii) Hobet participated in the development of plans to grade, blast, and alter the land near, on, and/or contiguous to the sites of the flooding. Hobet has filed a motion to dismiss both claims based upon the assertion that insufficient facts have been stated to support the claims of the plaintiffs.

     In the second action, motions to dismiss have been filed, asserting that the allegations asserted by the plaintiffs are conclusory in nature and likely deficient as a matter of law. Most of the other defendants also filed motions to dismiss. Both actions were stayed during the pendency of the appeals to the West Virginia Supreme Court of Appeals in the 2001 flood litigation.

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

     Other Litigation and Investigations

     Apogee has been sued, along with eight other defendants, including Monsanto Company, Pharmacia Corporation and Akzo Nobel Chemicals, Inc., by certain plaintiffs in state court in Putnam County, West Virginia. The lawsuits were filed in October 2007, but not served on Apogee until February 2008, and each of the 77 lawsuits are identical except for the named plaintiff. They each allege personal injury occasioned by exposure to dioxin generated by a plant owned and operated by certain of the other defendants during production of a chemical, 2,4,5-T, from 1949-1969. Apogee is alleged to be liable as the successor to the liabilities of a company that owned and/or controlled a dump site known as the Manila Creek landfill, which allegedly received and incinerated dioxin-contaminated waste from the plant. The lawsuits seek compensatory and punitive damages for personal injury. As of December 31, 2009, 44 of the original 77 lawsuits have been dismissed. In December 2009, Apogee was served with 165 additional lawsuits with the same allegations as the original 77 lawsuits. Under the terms of the governing lease, Monsanto has assumed the defense of these lawsuits and has agreed to indemnify Apogee for any related damages. The failure of Monsanto to satisfy its indemnification obligations under the lease could have a material adverse effect on us.

     We are a defendant in litigation involving Peabody’s negotiation and June 2005 sale of two properties previously owned by two of our subsidiaries. Environmental Liability Transfer, Inc. (ELT) and its subsidiaries commenced litigation against these subsidiaries in the Circuit Court of the City of St. Louis in the State of Missouri alleging, among other claims, fraudulent misrepresentation, fraudulent omission, breach of duty and breach of contract. Pursuant to the terms of the Separation Agreement, Plan of Reorganization and Distribution from the spin-off, Patriot and Peabody are treating the case as a joint action with joint representation and equal sharing of costs. Peabody and Patriot filed counterclaims against the plaintiffs in connection with the sales of both properties. Motions for summary judgment on the complaint and counterclaim have been filed by Peabody and Patriot and are pending. A trial date has been preliminarily set for October 2010. The claim filed is for $40 million in damages. We are unable to predict the likelihood of success of the plaintiffs’ claims, though we intend to vigorously defend ourselves against all claims.

     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 of 1993. In 1999, the State of Illinois brought a proceeding before the Illinois Pollution Control Board against the subsidiary alleging that groundwater contamination due to leaching from a coal waste pile at the mine site violated state standards. The subsidiary has developed a remediation plan with the State of Illinois and is in litigation with the Illinois Attorney General’s office with respect to its claim for a civil penalty of $1.3 million.

     One of our subsidiaries is a defendant in several related lawsuits filed in the Circuit Court of Boone County, West Virginia. As of December 31, 2009, there were 109 related lawsuits filed by approximately 267 plaintiffs. In addition to our subsidiary, the lawsuits name Peabody and other coal companies with mining operations in Boone County. The plaintiffs in each case allege contamination of their drinking water wells over a period in excess of 30 years from coal mining activities in Boone County, including underground coal slurry injection and coal slurry impoundments. The lawsuits seek property damages, personal injury damages and medical monitoring costs. Public water lines are being installed by the Boone County Public Service Commission, and all plaintiffs will have access to public water by April 2010. Pursuant to the terms of the Separation Agreement, Plan of Reorganization and Distribution from the spin-off, Patriot is indemnifying and defending Peabody in this litigation. In December 2009, we filed a third party complaint against our current and former insurance carriers seeking coverage for this litigation under the applicable insurance policies. The court has scheduled an early mediation in this case for the last week in March 2010, directing all plaintiffs, defendants and third party defendants to appear. A trial date has been set for May 2011. We are unable to predict the likelihood of success of the plaintiffs’ claims, though we intend to vigorously defend ourselves against all claims.

     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 have undertaken an internal investigation into the matter and have terminated one employee and placed two other employees on administrative leave. We are cooperating with the relevant governmental authorities.

     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. Submission of Matters to a Vote of Security Holders.

     No matters were submitted to a vote of security holders during the quarter ended December 31, 2009.

Executive Officers

     Set forth below are the names, ages as of February 19, 2010 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
Richard M. Whiting			55			Chief Executive Officer & Director
Irl F. Engelhardt			63			Chairman of the Board of Directors, Executive Advisor and Director
Paul H. Vining			55			President & Chief Operating Officer
Mark N. Schroeder			53			Senior Vice President & Chief Financial Officer
Charles A. Ebetino, Jr.			57			Senior Vice President — Corporate Development
Joseph W. Bean			47			Senior Vice President — Law & Administration, General Counsel & Corporate Secretary
Robert W. Bennett			47			Senior Vice President & Chief Marketing Officer

Richard M. Whiting

Chief Executive Officer & Director

     Richard M. Whiting, age 55, serves as Chief Executive Officer and as a Director. Mr. Whiting joined Peabody’s predecessor company in 1976 and held a number of operations, sales and engineering positions both at the corporate offices and at field locations. Prior to the spin-off, he was Peabody’s Executive Vice President & Chief Marketing Officer from May 2006 to 2007, with responsibility for all marketing, sales and coal trading operations, as well as Peabody’s joint venture relationships. Mr. Whiting previously served as President & Chief Operating Officer and as a director of Peabody from 1998 to 2002. He also served as Executive Vice President — Sales, Marketing & Trading from 2002 to 2006, and as President of Peabody COALSALES Company from 1992 to 1998.

     Mr. Whiting is the former Chairman of National Mining Association’s Safety and Health Committee, the former Chairman of the Bituminous Coal Operators’ Association, and a past board member of the National Coal Council. He is currently a director of the National Mining Association (NMA) and a director of the Society of Mining Engineers Foundation Board of Trustees. Mr. Whiting holds a Bachelor of Science degree in mining engineering from West Virginia University.

Irl F. Engelhardt

Chairman of the Board of Directors, Executive Advisor & Director

     Irl F. Engelhardt, age 63, serves as Chairman of the Board of Directors and Executive Advisor. Prior to the spin-off, Mr. Engelhardt served as Chairman and as a director of Peabody from 1998 until October 2007. He also served as Chief Executive Officer of Peabody from 1998 to 2005 and as Chief Executive Officer of a predecessor of Peabody from 1990 to 1998. He also served as Chairman of a predecessor of Peabody from 1993 to 1998 and as President from 1990 to 1995. After joining a predecessor of Peabody in 1979, Mr. Engelhardt held various officer level positions in the executive, sales, business development and administrative areas, including Chairman of Peabody Resources Ltd. (Australia) and Chairman of Citizens Power LLC. He also served as Co-Chief Executive Officer and executive director of The Energy Group from February 1997 to May 1998, Chairman of Cornerstone Construction & Materials, Inc. from September 1994 to May 1995 and Chairman of Suburban Propane Company from May 1995 to February 1996. Mr. Engelhardt served as a director and Group Vice President of Hanson Industries from 1995 to 1996. He also previously served as Chairman of the Federal Reserve Bank of St. Louis, the NMA, the Coal Industry Advisory Board of the International Energy Agency, the Center for Energy and Economic Development and the Coal Utilization Research Council, as well as Co-Chairman of the Coal Based Generation Stakeholders Group. He serves on the Boards of Directors of Valero Energy Corporation and The Williams Companies, Inc.

Paul H. Vining

President & Chief Operating Officer

     Paul H. Vining, age 55, serves as President & Chief Operating Officer. Prior to the Magnum acquisition, Mr. Vining served as President and Chief Executive Officer of Magnum since 2006. Prior to joining Magnum, Mr. Vining was Senior Vice President of Marketing and Trading at Arch Coal. Prior to that, from 2003 to 2006, he was President of Ellett Valley CC Inc., a coal trading, marketing and consulting company based in Williamsburg, Virginia. From 1999 to 2002, Mr. Vining was Executive Vice President for Sales and Trading at Peabody. From 1996 to 1999, he was President of Peabody COALTRADE. From 1995 to 1996, Mr. Vining was Senior Vice President of Peabody COALSALES. Earlier in his career, he held leadership positions with Guasare Coal America, AGIP Coal USA, Island Creek Coal and A.T. Massey Energy.

     Mr. Vining currently serves as Treasurer and board member of the West Virginia Coal Association. Mr. Vining holds a Bachelor of Science degree in chemistry from the College of William and Mary, and a Bachelor of Science in mineral engineering and a Master of Science degree in extractive metallurgy from Columbia University’s Henry Krumb School of Mines in New York.

Mark N. Schroeder

Senior Vice President & Chief Financial Officer

     Mark N. Schroeder, age 53, serves as Senior Vice President & Chief Financial Officer. Prior to the spin-off, Mr. Schroeder held several key management positions in his career at Peabody which began in 2000. These positions included President of Peabody China from 2006 to 2007, Vice President of Materials Management from 2004 to 2006, Vice President of Business Development from 2002 to 2004 and Vice President and Controller from 2000 to 2002. He has more than 30 years of business experience, including as Chief Financial Officer of Franklin Equity Leasing Company from 1998 to 2000, Chief Financial Officer of Behlmann Automotive Group from 1997 to 1998, and financial management positions with McDonnell Douglas Corporation and Ernst & Young, LLP.

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

Charles A. Ebetino, Jr.

Senior Vice President — Corporate Development

     Charles A. Ebetino, Jr., age 57, serves as Senior Vice President — Corporate Development. Prior to the spin-off, Mr. Ebetino was Senior Vice President — Business and Resource Development for Peabody since May 2006. Mr. Ebetino also served as Senior Vice President — Market Development for Peabody’s sales and marketing subsidiary from 2003 to 2006 and was directly responsible for COALTRADE, LLC. He joined Peabody in 2003 after more than 25 years with American Electric Power Company, Inc. (AEP) where he served in a number of management roles in the fuel procurement and supply group, including Senior Vice President of Fuel Supply and President & Chief Operating Officer of AEP’s coal mining and coal-related subsidiaries from 1993 until 2002. In 2002, he formed Arlington Consulting Group, Ltd., an energy industry consulting firm.

     Mr. Ebetino is a past board member of NMA, former Chairman of the NMA Environmental Committee, a former Chairman and Vice Chairman of the Edison Electric Institute’s Power Generation Subject Area Committee, a former Vice Chairman of the Inland Waterway Users Board, and a past board member and President of the Western Coal Transportation Association. Mr. Ebetino has a Bachelor of Science degree in civil engineering from Rensselaer Polytechnic Institute. He also attended the New York University School of Business for graduate study in finance.

Joseph W. Bean

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

     Joseph W. Bean, age 47, serves as Senior Vice President — Law & Administration, General Counsel & Corporate Secretary. From the spin-off to February 2009, Mr. Bean served as Senior Vice President, General Counsel & Corporate Secretary for Patriot. Prior to the spin-off, Mr. Bean served as Peabody’s Vice President & Associate General Counsel and Assistant Secretary from 2005 to 2007 and as Senior Counsel from 2001 to 2005. During his tenure at Peabody, he directed the company’s legal and compliance activities related to mergers and acquisitions, corporate governance, corporate finance and securities matters.

     Mr. Bean has 23 years of corporate law experience, including 19 years as in-house legal counsel. He was counsel and assistant corporate secretary for The Quaker Oats Company prior to its acquisition by PepsiCo in 2001 and assistant general counsel for Pet Incorporated prior to its 1995 acquisition by Pillsbury. He also served as a corporate law associate with the law firms of Mayer, Brown & Platt in Chicago and Thompson & Mitchell in St. Louis. Mr. Bean holds a Bachelor of Arts degree from the University of Illinois and a Juris Doctorate from Northwestern University School of Law.

Robert W. Bennett

Senior Vice President & Chief Marketing Officer

     Robert W. Bennett, age 47, serves as Senior Vice President & Chief Marketing Officer. Mr. Bennett has over 22 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 COALSALES, LLC. Mr. Bennett served as Vice President – Brokerage and Agency Sales for COALTRADE, LLC from 1997 to 2005 where he was responsible for all brokerage and agency relationships in the eastern United States. Prior to 1997, Mr. Bennett held various leadership positions with AGIP Coal Sales and Neweagle Corporation. Mr. Bennett holds a Bachelor of Arts in Finance from Marshall University.

PART II

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

     On October 31, 2007, Peabody effected the spin-off of Patriot and its subsidiaries. The spin-off was accomplished through a dividend of all outstanding shares of Patriot Coal Corporation. Our common stock is listed on the New York Stock Exchange, under the symbol PCX. As of February 19, 2010, there were 858 holders of record of our common stock.

     Effective August 11, 2008, Patriot implemented a 2-for-1 stock split effected in the form of a 100% stock dividend. All share and per share amounts in this Annual Report on Form 10-K reflect this stock split.

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

		High				Low
2007
Fourth Quarter		$	21.50			$	13.54
2008
First Quarter		$	28.89			$	16.14
Second Quarter			82.23				23.13
Third Quarter			77.74				24.09
Fourth Quarter			28.45				5.24
2009
First Quarter		$	9.00			$	2.76
Second Quarter			10.90				3.51
Third Quarter			14.12				4.97
Fourth Quarter			17.24				10.21

Dividend Policy

     We have not paid and we do not anticipate that we will pay cash dividends on our common stock in the near term. The declaration and amount of future dividends, if any, will be determined by our Board of Directors and will depend on our financial condition, earnings, capital requirements, financial covenants, regulatory constraints, industry practice and other factors our Board deems relevant.

Stock Performance Graph

     The following performance graph compares the cumulative total return on our common stock with the cumulative total return of the following indices: (i) the S&P Smallcap 600 Index and (ii) the Custom Composite Index comprised of Alpha Natural Resources, Inc., Arch Coal, Inc., CONSOL Energy, Inc., International Coal Group, Inc., James River Coal Co., Massey Energy Company, Peabody Energy Corp. and Westmoreland Coal Company. These indices are included for comparative purposes only and do not necessarily reflect management’s opinion that such indices are an appropriate measure of the relative performance of the stock involved, and are not intended to forecast or be indicative of possible future performance of the common stock.

COMPARISON OF 26 MONTH CUMULATIVE TOTAL RETURN*
Among Patriot Coal Corporation, The S&P Smallcap 600 Index
And Custom Composite Index

*$100 invested on 11/1/07 in stock or 10/31/07 in index, including reinvestment of dividends.
Fiscal year ending December 31.

Copyright© 2010 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

				11/07					12/07					3/08					6/08					9/08					12/08					3/09					6/09					9/09					12/09
	Patriot Coal Corporation				100.00					111.31					125.25					408.77					154.93					33.33					19.79					34.03					62.72					82.45
	S&P Smallcap 600				100.00					91.84					84.99					85.33					84.60					63.30					52.64					63.73					75.62					79.49
	Custom Composite				100.00					127.81					120.67					220.88					100.33					50.58					48.19					63.21					83.08					97.81

     In accordance with SEC rules, the information contained in the Stock Performance Graph above, shall not be deemed to be “soliciting material,” or to be “filed” with the SEC or subject to the SEC’s Regulation 14A or 14C, other than as provided under Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended, except to the extent that we specifically request that the information be treated as soliciting material or specifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.

Item 6. Selected Consolidated Financial Data.

     The following table presents selected financial and other data for the most recent five fiscal years. The historical financial and other data have been prepared on a consolidated basis derived from Patriot’s consolidated financial statements using the historical results of operations and bases of the assets and liabilities of Patriot’s businesses and give effect to allocations of expenses from Peabody in 2007, 2006, and 2005. For periods prior to the spin-off, the historical consolidated statements of operations data set forth below do not reflect changes that occurred in the operations and funding of our company as a result of our spin-off from Peabody. Magnum results are consolidated as of the date the acquisition was consummated, July 23, 2008. The historical consolidated balance sheet data set forth below reflect the assets and liabilities that existed as of the dates and the periods presented.

     The selected consolidated financial data should be read in conjunction with, and are qualified by reference to, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the historical financial statements and the accompanying notes thereto of us and our consolidated subsidiaries included elsewhere in this report. The consolidated statements of operations and cash flow data for each of the three years in the period ended December 31, 2009 and the consolidated balance sheet data as of December 31, 2009 and 2008 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, 2007, 2006 and 2005 and the consolidated statements of operations for the years ended December 31, 2006 and 2005 were derived from audited consolidated financial statements that are not presented in this report.

     The financial information presented below may not reflect what our results of operations, cash flows and financial position would have been had we operated as a separate, stand-alone entity for the years ended December 31, 2007, 2006, and 2005 or what our results of operations, financial position and cash flows will be in the future. In addition, the Risk Factors section of Item 1A of this report includes a discussion of risk factors that could impact our future results of operations.

		Year Ended December 31,
		2009				2008				2007				2006				2005
		(In thousands, except for share and per share data)
Results of Operations Data:
Revenues
Sales		$	1,995,667			$	1,630,873			$	1,069,316			$	1,142,521			$	960,901
Other revenues			49,616				23,749				4,046				5,398				17,376
Total revenues			2,045,283				1,654,622				1,073,362				1,147,919				978,277
Costs and expenses
Operating costs and expenses			1,893,419				1,607,746				1,109,315				1,051,932				869,163
Depreciation, depletion and amortization			205,339				125,356				85,640				86,458				65,972
Reclamation and remediation obligation expense			35,116				19,260				20,144				24,282				15,572
Sales contract accretion			(298,572	)			(279,402	)			-				-				-
Restructuring and impairment charge			20,157				-				-				-				-
Selling and administrative expenses			48,732				38,607				45,137				47,909				57,123
Other operating (income) expense:
Net gain on disposal or exchange of assets(1)			(7,215	)			(7,004	)			(81,458	)			(78,631	)			(57,042	)
Loss (income) from equity affiliates(2)			(398	)			915				(63	)			(60	)			(15,578	)
Operating profit (loss)			148,705				149,144				(105,353	)			16,029				43,067
Interest expense			38,108				23,648				8,337				11,419				9,833
Interest income			(16,646	)			(17,232	)			(11,543	)			(1,417	)			(1,553	)
Income (loss) before income taxes			127,243				142,728				(102,147	)			6,027				34,787
Income tax provision			-				-				-				8,350				-
Net income (loss)			127,243				142,728				(102,147	)			(2,323	)			34,787
Net income attributable to noncontrolling interest(2)			-				-				4,721				11,169				-
Net income (loss) attributable to Patriot			127,243				142,728				(106,868	)			(13,492	)			34,787
Effect of noncontrolling interest purchase arrangement			-				-				(15,667	)			-				-
Net income (loss) attributable to common stockholders		$	127,243			$	142,728			$	(122,535	)		$	(13,492	)		$	34,787
Earnings (loss) per share, basic		$	1.50			$	2.23			$	(2.29	)			N/A				N/A
Earnings (loss) per share, diluted		$	1.49			$	2.21			$	(2.29	)			N/A				N/A
Weighted average shares outstanding - basic			84,660,998				64,080,998				53,511,478				N/A				N/A
Weighted average shares outstanding - diluted			85,424,502				64,625,911				53,546,116				N/A				N/A
Balance Sheet Data (at period end):
Total assets		$	3,618,163			$	3,622,320			$	1,199,837			$	1,178,181			$	1,113,058
Total liabilities(3)			2,682,669				2,782,139				1,117,521				1,851,855				1,511,810
Total long-term debt, less current maturities			197,951				176,123				11,438				20,722				11,459
Total stockholders’ equity (deficit)			935,494				840,181				82,316				(673,674	)			(398,752	)

		Year Ended December 31,
		2009				2008				2007				2006				2005
		(In thousands, except for share and per share data)
Other Data:
Tons sold (in millions and unaudited)			32.8				28.5				22.1				24.3				23.8
Net cash provided by (used in):
Operating activities		$	39,611			$	63,426			$	(79,699	)		$	(20,741	)		$	17,823
Investing activities			(77,593	)			(138,665	)			54,721				1,993				(29,529	)
Financing activities			62,208				72,128				30,563				18,627				11,459
Adjusted EBITDA(4) (unaudited)			110,745				44,238				431				126,769				124,611
Past mining obligation payments(5) (unaudited)			129,060				101,746				144,811				150,672				154,479
Additions to property, plant, equipment and mine development			78,263				121,388				55,594				80,224				75,151
Acquisitions, net			-				9,566				47,733				44,538				-

     Adjusted EBITDA is calculated as follows (unaudited):

		Year Ended December 31,
		2009				2008				2007				2006				2005
		(In thousands)
Net income (loss)		$	127,243			$	142,728			$	(102,147	)		$	(2,323	)		$	34,787
Depreciation, depletion and amortization			205,339				125,356				85,640				86,458				65,972
Sales contract accretion, net(1)			(298,572	)			(249,522	)			-				-				-
Asset retirement obligation expense			35,116				19,260				20,144				24,282				15,572
Restructuring and impairment			20,157				-				-				-				-
Interest expense			38,108				23,648				8,337				11,419				9,833
Interest income			(16,646	)			(17,232	)			(11,543	)			(1,417	)			(1,553	)
Income tax provision			-				-				-				8,350				-
Adjusted EBITDA		$	110,745			$	44,238			$	431			$	126,769			$	124,611

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

Overview

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

     We ship coal to electric utilities, industrial users, steel mills and independent coke producers. In 2009, we sold 32.8 million tons of coal, of which 83% was sold to domestic electric utilities and 17% was sold to domestic and global steel producers. In 2008, we sold 28.5 million tons of coal, of which 79% was sold to domestic electric utilities and 21% was sold to domestic and global steel producers. Coal is shipped via various company-owned and third-party loading facilities, multiple rail and river transportation routes and ocean-going vessels.

     We typically sell coal to utility and steel-making customers under contracts with terms of one year or more. Approximately 83% and 78% of our sales were under such contracts during 2009 and 2008, respectively.

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

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

Results of Operations

     Segment Adjusted EBITDA

     The discussion of our results of operations below includes references to and analysis of our Appalachia and Illinois Basin Segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as net income (loss) before deducting net interest income and expense; income taxes; reclamation and remediation obligation expense; depreciation, depletion and amortization; restructuring and impairment charge; and net sales contract accretion. Net sales contract accretion represents contract accretion excluding back-to-back coal purchase and sales contracts. The contract accretion on the back-to-back coal purchase and sales contracts reflects the accretion related to certain coal purchase and sales contracts existing on July 23, 2008, whereby Magnum purchased coal from third parties to fulfill tonnage commitments on sales contracts. Segment Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Because Segment Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is reconciled to its most comparable measure under generally accepted accounting principles in Item 6. Selected Consolidated Financial Data. Segment Adjusted EBITDA is calculated the same as Adjusted EBITDA but also excludes selling, general and administrative expenses, past mining obligation expense and gain on disposal or exchange of assets and is reconciled to its most comparable measure below, under Net Income.

     Geologic Conditions

     Our results of operations are impacted by geologic conditions as they relate to coal mining. These conditions refer to the physical nature of the coal seam and surrounding strata and its effect on the mining process. Geologic conditions that can have an adverse effect on underground mining include thinning coal seam thickness, rock partings within a coal seam, weak roof or floor rock, sandstone channel intrusions, groundwater and increased stresses within the surrounding rock mass due to over mining, under mining and overburden changes. The term “adverse geologic conditions” is used in general to refer to these and similar situations where the geologic setting can negatively affect the normal mining process. Adverse geologic conditions would be markedly different from those that would be considered typical geologic conditions for a given mine. Since approximately 70% of our 2009 production was sourced from underground operations, geologic conditions can be a major factor in our results of operations.

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

     Summary

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

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

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

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

     Segment Results of Operations

		Year Ended December 31,								Increase (Decrease)
		2009				2008				Tons/$				%
		(Dollars and tons in thousands, except per ton amounts)
Tons Sold
Appalachia			25,850				20,654				5,196				25.2	%
Illinois Basin			6,986				7,866				(880	)			(11.2	)%
Total Tons Sold			32,836				28,520				4,316				15.1	%
Average sales price per ton sold
Appalachia		$	66.79			$	65.23			$	1.56				2.4	%
Illinois Basin			38.52				36.06				2.46				6.8	%
Revenue
Appalachia Mining Operations		$	1,726,588			$	1,347,230			$	379,358				28.2	%
Illinois Basin Mining Operations			269,079				283,643				(14,564	)			(5.1	)%
Appalachia Other			49,616				23,749				25,867				108.9	%
Total Revenues		$	2,045,283			$	1,654,622			$	390,661				23.6	%
Segment Operating Costs and Expenses(1)
Appalachia Mining Operations and Other		$	1,481,831			$	1,197,985			$	283,846				23.7	%
Illinois Basin Mining Operations			260,529				270,488				(9,959	)			(3.7	)%
Total Segment Operating Costs and Expenses		$	1,742,360			$	1,468,473			$	273,887				18.7	%
Segment Adjusted EBITDA
Appalachia Mining Operations and Other		$	294,373			$	172,994			$	121,379				70.2	%
Illinois Basin Mining Operations			8,550				13,155				(4,605	)			(35.0	)%
Total Segment Adjusted EBITDA		$	302,923			$	186,149			$	116,774				62.7	%