Walter Energy 10-K 2011 FY Annual report

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

FORM 10-K

(Mark One)
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
For the year ended December 31, 2011
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-13711

WALTER ENERGY, INC.
(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	13-3429953 (IRS Employer Identification No.)
3000 Riverchase Galleria, Suite 1700 Birmingham, Alabama (Address of principal executive offices)	35244 (Zip Code)
(205) 745-2000 Registrant's telephone number, including area code:
Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Name of exchange on which registered
Common Stock, par value $0.01	New York Stock Exchange
	Toronto Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    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 ý

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 ý    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 ý    No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) 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. ý

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

Large accelerated filerý Accelerated filero Non-accelerated filero
(Do not check if a smaller
reporting company) Smaller reporting companyo

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

The aggregate market value of voting stock held by non-affiliates of the registrant, based on the closing price of the Common Stock on June 30, 2011, the registrant's most recently completed second fiscal quarter, as reported by the New York Stock Exchange, was approximately $7.2 billion.

Number of shares of common stock outstanding as of January 31, 2012: 62,444,905

Documents Incorporated by Reference

Applicable portions of the Proxy Statement for the Annual Meeting of Stockholders of the Company to be held April 19, 2012 are incorporated by reference in Part III of this Form 10-K.

CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

        This report includes 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. These statements, which involve risks and uncertainties, relate to analyses and other information that are based on forecasts of future results and estimates of amounts not yet determinable and may also relate to our future prospects, developments and business strategies. We have used the words "anticipate," "believe," "could," "estimate," "expect," "intend," "may," "plan," "predict," "project," "should" and similar terms and phrases, including references to assumptions, in this report to identify forward-looking statements. These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those matters expressed in or implied by these forward-looking statements. These risks and uncertainties include, but are not limited to:

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Deteriorating conditions in the financial markets;

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Global economic crisis;

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Market conditions beyond our control;

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Prolonged decline in the price of coal;

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Decline in global steel demand;

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Our customer's refusal to honor or renew contracts;

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Title defects preventing us from (or resulting in additional costs for) mining our mineral interests;

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Concentration of our coal and gas producing mineral interests in limited number of areas subjects us to risk;

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Weather patterns and conditions affecting production;

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Geological, equipment and operational risks associated with mining;

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Unavailability of cost-effective transportation for our coal;

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Significant increase in competitive pressures;

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Significant cost increases and delays in the delivery of purchased components;

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Availability of adequate skilled employees and other labor relations matters;

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Greater than anticipated costs incurred for compliance with environmental liabilities;

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Our ability to attract and retain key personnel;

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Future regulations that increase our costs or limit our ability to produce coal;

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New laws and regulations to reduce greenhouse gas emissions that impact the demand for our coal reserves;

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Adverse rulings in current or future litigation;

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Inability to access needed capital;

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Downgrade in our credit rating;

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Our ability to identify suitable acquisition candidates to promote growth;

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Our ability to successfully integrate acquisitions, including the recent acquisition of Western Coal Corp.;

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Volatility in the price of our common stock;

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Our ability to pay regular dividends to stockholders;

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Potential suitors could be discouraged by our stockholder rights agreement;

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Our exposure to indemnification obligations; and

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Other factors, including the other factors discussed in Item 1A, "Risk Factors," as updated by any subsequent Form 10-Qs or other documents that are on file with the Securities and Exchange Commission.

        You should keep in mind that any forward-looking statement made by us in this Annual Report on Form 10-K or elsewhere speaks only as of the date on which we make it. New risks and uncertainties come up from time to time, and it is impossible for us to predict these events or how they may affect us. We have no duty to, and do not intend to, update or revise the forward-looking statements in this Annual Report on Form 10-K after the date of this Annual Report on Form 10-K, except as may be required by law. In light of these risks and uncertainties, you should keep in mind that any forward-looking statement made in this Annual Report on Form 10-K or elsewhere might not occur.

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GLOSSARY OF SELECTED MINING TERMS

        Anthracite coal.    A hard natural coal containing little volatile hydrocarbons which burns slowly and gives intense heat almost without flame.

        Ash.    Impurities consisting of silica, iron, alumina and other incombustible matter that are contained in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the burning characteristics of coal.

        Assigned reserves.    Coal that is planned to be mined at an operation that is currently operating, currently idled, or for which permits have been submitted and plans are eventually to develop the operation.

        Bituminous coal.    A common type of coal with moisture content less than 20% by weight. It is dense and black and often has well-defined bands of bright and dull material.

        British thermal unit, or "Btu".    A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

        Coal seam.    Coal deposits occur in layers. Each layer is called a "seam."

        Coke.    A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel. Its production results in a number of useful by-products.

        Compliance coal.    Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus, as required by Phase II of the Clean Air Act.

        Continuous miner.    A machine used in underground mining to cut coal from the seam and load onto conveyers or shuttle cars in a continuous operation. In contrast, a conventional mining unit must stop extracting in order to begin loading.

        Continuous mining.    A form of underground mining that cuts the coal from the seam and loads continuously, thus eliminating the separate cycles of cutting, drilling, shooting and loading.

        Hard coking coal.    Hard coking coal is a type of metallurgical coal that is a necessary input in the production of strong coke. It is evaluated based on the strength, yield and size distribution of coke produced which is dependent on rank and plastic properties of the coal. Hard coking coals trade at a premium to other coals due to their importance in producing strong coke and as they are of limited resources.

        Industrial coal.    Coal generally used as a heat source in the production of lime, cement, or for other industrial uses and is not consideredthermal coal ormetallurgical coal.

        Longwall mining.    A form of underground mining that employs two rotating drums pulled mechanically back and forth across a long surface of the coal. A hydraulic system supports the roof of the mine while the drum is mining the coal. Chain conveyors move the loosened coal to an underground mine conveyor to transport to the surface. Longwall mining is the most efficient underground mining method in the United States.

        Metallurgical coal.    The various grades of coal suitable for carbonization to make coke for steel manufacture, including hard coking coal (see definition above), semi-soft coking coal (SSCC) and PCI coal (see definition below). Also known as "met" coal, its quality depends on four important criteria: (1) volatility, which affects coke yield; (2) the level of impurities including sulfur and ash, which affect coke quality; (3) composition, which affects coke strength; and (4) other basic characteristics that affect coke oven safety. Met coal typically has a particularly high Btu but low ash and sulfur content.

        Nitrogen oxide (NOx).    Produced as a gaseous by-product of coal combustion. It is a harmful pollutant that contributes to smog.

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        Overburden.    Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

        PCI Coal.    Coal used by steelmakers for pulverized coal injection (PCI) into blast furnaces rather than the coking coals used to produce coke.

        Preparation plant.    Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to remove impurities and prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal's sulfur content.

        Probable reserves.    Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven 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 reserves, is high enough to assume continuity between points of observation.

        Proven reserves.    Reserves for which: (a) quantity is computed from dimensions revealed in outcrops (part of a rock formation that appears at the surface of the ground), 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 closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

        Recoverable reserves.    Tons of mineable coal which can be extracted and marketed after deduction for coal to be left in pillars, etc. and adjusted for reasonable preparation and handling losses.

        Reclamation.    The process of restoring land and the environment to their original state following mining activities. The process commonly includes "recontouring" or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually underway before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law.

        Reserve.    That part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination.

        Roof.    The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place.

        Sulfur.    One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product of coal combustion.

        Surface mine.    A mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil (see "Overburden"). About 65% of total U.S. coal production comes from surface mines.

        Thermal coal.    Coal used by power plants and industrial steam boilers to produce electricity, steam or both. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

        Tons.    A "short" or net ton is equal to 2,000 pounds. A "metric" ton is approximately 2,205 pounds; a "long" or British ton is equal to 2,240 pounds. Unless otherwise indicated, the metric ton is the unit of measure referred to in this document. The international standard for quoting price per ton is based on the U.S. dollar per metric ton.

        Unassigned reserves.    Coal that is likely to be mined in the future, but which is not consideredAssigned reserves.

        Underground mine.    Also known as a "deep" mine. Usually located several hundred feet or more below the earth's surface, an underground mine's coal is removed mechanically and transferred by shuttle car and conveyor to the surface. Underground mines account for about 35% of annual U.S. coal production.

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PART I

Item 1.    Business

Introduction and History

        We are a leading producer and exporter of metallurgical coal for the global steel industry and also produce thermal coal and industrial coal, anthracite, metallurgical coke, coal bed methane gas ("natural gas") and other related products. We trace our roots back to 1946 when Jim Walter began a homebuilding business in Tampa, Florida. Although initially focused on Homebuilding, the company Mr. Walter founded later became Jim Walter Corporation and branched out into many different businesses, including the 1972 development of four underground coal mines in the Blue Creek coal seam near Brookwood, Alabama. In 1987 a group of investors that included Jim Walter formed a new company, subsequently named Walter Industries, Inc., and the following year completed a leveraged buyout of most of the businesses of Jim Walter Corporation. In 1997, Walter Industries, Inc. began trading on the New York Stock Exchange. In 2009 we closed our Homebuilding business and spun off our Financing business. Our Homebuilding business was an on-your-lot homebuilder and our Financing business serviced non-conforming installment notes and loans that were secured by mortgages and liens. With all of our remaining businesses concentrated in coal and natural gas, we changed our name to Walter Energy, Inc. in April 2009.

        On April 1, 2011 we completed the acquisition of all the outstanding common shares of Western Coal Corp. ("Western Coal"). The acquisition included high quality metallurgical coal mines in Northeast British Columbia (Canada), high quality metallurgical coal and compliant thermal coal from mines in West Virginia (United States), and high quality anthracite coal from mines located in South Wales (United Kingdom, "U.K."). The acquisition of Western Coal substantially increased our reserves available for future production, the majority of which is high-demand metallurgical coal, and created a diverse geographical footprint with strategic access to high-growth steel-producing countries in both the Atlantic and Pacific basins.

        On May 6, 2011, we acquired mineral rights for approximately 68 million metric tons of recoverable Blue Creek metallurgical coal reserves to the Northwest of our existing Alabama mines from a subsidiary of Chevron Corporation. The mineral leases are expected to form the core of what is a planned new underground metallurgical coal mine. In addition, we acquired Chevron Corporation's existing North River thermal coal mine in Fayette and Tuscaloosa Counties of Alabama.

Overview

        Our primary business, the mining and exporting of metallurgical coal for the steel industry, is conducted by two business segments, our U.S. Operations segment and Canadian and U.K. Operations segment. As a result of the Western Coal acquisition, beginning with the second quarter of 2011 the Company revised its reportable segments by arranging them geographically. We now report all of our operations located in the U.S. under the U.S. Operations segment, including the West Virginia mining operations acquired through the acquisition of Western Coal. We report our mining operations acquired through the Western Coal acquisition located in Northeast British Columbia and South Wales under the Canadian and U.K. Operations segment.

        The U.S. Operations segment includes the operations of our underground mines, surface mines, coke plant and natural gas operations located in Alabama, and our underground and surface mining operations located in West Virginia. Our Alabama mining operations mine metallurgical coal from both underground and surface mines. Our Alabama underground mining operation represents the country's southernmost Appalachian coal producer where we mine high quality metallurgical coal from Alabama's Blue Creek coal seam. Our Alabama underground mines are 1,500 to 2,200 feet underground, making them some of the deepest vertical shaft coal mines in North America.

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Metallurgical coal mined from the Blue Creek seam contains very low sulfur, has strong coking properties and high heat value making it ideally suited to the needs of steel makers as a coking coal. The Alabama operations also mine thermal coal for sale to industrial and electric utility customers at our surface mines and underground North River mine. Our Alabama mining operations have convenient access to the port of Mobile, Alabama through barge and by railroad allowing us to minimize our transportation costs. In 2011, the Alabama mining operations produced 5.5 million metric tons of metallurgical coal and 2.5 million metric tons of thermal coal.

        The U.S. Operations segment also extracts methane gas, principally from the Blue Creek coal seam. Our natural gas business represents one of the most extensive and comprehensive commercial programs for coal seams degasification in the country, producing approximately 52 million cubic feet of gas daily from over 1,760 wells.

        Through the acquisition of Western Coal we acquired two underground and two surface mines located in West Virginia, which produce both metallurgical coal and thermal coal. The West Virginia mining operations lie within the Appalachian coal-producing region and have a long history of mining development and production. Our West Virginia mining operations operate a rail-loading facility and utilize an extensive network of public roads to transport coal to markets along the Kanawha River or to independent river terminals for transfer to barges along the Kanawha River. The West Virginia mining operations have produced approximately 400 thousand metric tons of metallurgical coal and 900 thousand metric tons of thermal coal since the April 1, 2011 date of acquisition.

        The Canadian and U.K. Operations segment includes the operations of surface mines in Northeast British Columbia (Canada) and underground and surface mines in South Wales (U.K.) The Canadian operations currently operate three surface mines that produce primarily metallurgical and low-volatile PCI coals. The Canadian mines are located adjacent to or nearby existing infrastructure established for the Northeast coalfields, including established rail and road networks that are available all year round. Coal produced from the mines is shipped by rail to a coal terminal facility at the Port of Prince Rupert, British Columbia. The U.K. mining operations mine PCI, anthracite and thermal coal from its underground and surface mines. All coal mined is processed at the Company's nearby preparation plant where both road and rail coal transportation are available. The Canadian and U.K. mining operations have produced 1.1 million metric tons of hard coking coal, 1.7 million metric tons of low volatile PCI coal and 91 thousand metric tons of thermal coal since the April 1, 2011 date of acquisition.

        The financial results of our industry segments are included in Note 17 of "Notes to Consolidated Financial Statements" included in this Form 10-K.

The Coal Industry

        Coal is one of the most available and important energy sources in the world, providing approximately 30% of the world's primary energy needs according to the World Coal Association ("WCA"). Per the WCA, the most significant uses for coal are for electricity generation, steel production, cement manufacturing and as a liquid fuel. According to the WCA, approximately 41% of the world's electricity is generated from coal and this level is expected to increase to 44% by 2030. During 2011, coal was used to generate approximately 49% of the electricity in the United States according to the International Energy Agency ("IEA").

        Approximately 68% of global steel production relies directly on inputs of metallurgical coal according to the WCA. After metallurgical coal is converted to coke it is used in blast furnaces to smelt iron ore which is subsequently used to produce steel. The steel industry uses metallurgical coal which is distinguishable from other types of coal by its characteristics: lower volatility, lower sulfur and ash content and favorable coking characteristics (higher coke strength). Additionally, metallurgical coal has a higher Btu value. Approximately 29% of steel is also produced in electric arc furnaces, a process in which a large percentage of the electricity is generated from coal-fired power stations. The top five

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steel producing countries are China, Japan, the United States, India and Russia. In 2011, approximately 1.5 billion metric tons of steel was produced globally, a 7% increase over 2010.

        Coal reserves are available in almost every country worldwide, with recoverable reserves in around 70 countries. The largest reserves are in the U.S., Russia, China and India. Coal's appeal is that it is readily available from a wide variety of sources; its prices have been lower and more stable than oil and gas prices; and it is likely to remain the most affordable fuel for power generation in many developing and industrialized nations for several decades per the WCA. The top five coal producing countries in the world are China, the United States, India, Australia and South Africa. The largest exporters of coal in 2011 were Australia, Indonesia and Russia (the U.S. is 4^th) according to the WCA. The leading exporters of metallurgical coal for coking, per the WCA, are Australia, the United States and Canada. Because metallurgical coal is more expensive than thermal coal, exporters are able to afford the high freight rates involved in exporting metallurgical coal worldwide.

Coal Characteristics

        Coal is generally classified as either metallurgical coal or thermal coal (also known as steam and industrial coal). Sulfur, ash and moisture content as well as coking characteristics are key attributes in grading metallurgical coal while heat value, ash and sulfur content are important variables in rating thermal coal. We currently mine, process, market and ship coal with the characteristics described below.

        Heat Value:    The heating value of coal is supplied by its carbon content and volatile matter and commonly measured in British thermal units ("Btus"). A Btu is the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. Coal deposits are generally classified into four categories, ranging from lignite, subbituminous, bituminous and anthracite, reflecting their response to increasing heat and pressure. We primarily mine bituminous coal which is used to make coke for the steel industry or generate electricity with a heating value ranging between 10,500 and 15,500 Btus per pound. Anthracite coal has the highest carbon content and a heat value nearing 15,000 Btus per pound. Approximately 88.5% of our proven and probable reserves has a heat value above 13,500 Btus per pound, making it very desirable to our customers.

        Sulfur Content:    Although sulfur content can differ from seam to seam, approximately 95% of our estimated 375.1 million metric tons of proven and probable reserves are low sulfur coals, which are preferred by our customers. Low sulfur coals have a sulfur content of 1.5% or less. Coal produces undesirable sulfur dioxide when it burns, the amount of which depends on the concentration of sulfur in the coal as well as the chemical composition of the coal itself.

        Ash and Moisture Content:    Ash residue is what remains after the combustion of coal. Low ash is desirable because businesses must dispose of ash after the coal is used. High moisture content decreases the heat value of the coal which is undesirable and increases the coal's weight which is also negative because higher weight increases transportation charges. Our metallurgical coal, particularly the coal from the Blue Creek seam in Alabama, has a low ash rating and moisture content which is desirable to our customers.

        Coking Characteristics (metallurgical coal only):    Two important coking characteristics are coke strength and volatility. Measuring the expansion and contraction of coal when heated determines the strength of coke that could be produced from the coal. When coal is heated in the absence of air, the loss in mass less moisture is volatility. Volatility of metallurgical coal is used to determine the percentage of coal that becomes coke. This measure is known as coke yield. A low volatility results in a higher coke yield. Our metallurgical coal, particularly the coal from the Blue Creek seam in Alabama, has both a high rating for coke strength as well as a low measure of volatility.

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Types of Coal

        Metallurgical coal is classified into three major categories of hard coking coal ("HCC"), semi-soft coking coal, and pulverized coal injection coal ("PCI"). Coking coals are the basic ingredients for manufacture of metallurgical coke. PCI coal is not used in coke making, but is injected directly into the lower region of blast furnaces to supply both energy and carbon for iron reduction, thus replacing some of the metallurgical coke that may otherwise have been used.

        Thermal and industrial coal is the most abundant form of coal which is also referred to as steam coal. It has relatively high heat value and has long been used for steam generation in electric power and industrial boiler plants.

        Anthracite coal is commonly used as a reduction agent for various applications such as briquetting, charcoal and iron ore pellets. The primary current use of our anthracite coal is for a domestic fuel in either hand fired stoker or automatic stoker furnaces. However, the intent is to sell anthracite coal into the PCI coal market. Anthracite is a crossover coal and has been successfully used in the PCI coal market.

Coal Mining Methods

        We use two primary methods for mining coal of underground mining and surface mining. The mining methods that we employ are largely determined by the geological characteristics of our coal reserves.

        Underground Mining:    We employ underground mining methods when our coal reserves are located deep beneath the surface. Our underground mines typically use the two different mining techniques of longwall mining and room-and-pillar mining. In 2011, approximately 60% of the coal we produced was from underground mining operations.

        In longwall mining, mechanized shearers are used to cut and remove the coal from long rectangular blocks of medium to thick seams. Continuous miners are used to develop access to these coal blocks. After the coal is removed, it drops onto a chain conveyor, which moves it to a second conveyor that will ultimately take the coal to production shafts or slopes where it will be hoisted to the surface. In longwall mining mobile hydraulic powered roof supports hold up the roof throughout the extraction process. This method of mining has proven to be more efficient than other mining methods, with an extraction rate of nearly 100 percent, but the equipment is more expensive than that for other conventional mining methods and cannot be used in all geological circumstances. In longwall mining, only the gate entries are bolted. The longwall panel is allowed to collapse behind the shields which hold the roof as coal is extracted.

        Underground mining with longwall technology drives greater production efficiency, improved safety, higher coal recovery and lower production costs. We currently operate 4 longwall mining systems at our Alabama underground mining operations for primary production and four to six continuous miner sections in each mine for the development of mains and longwall panel entries. We expect to have four longwalls in operation through the second quarter of 2012 at which time one of our existing longwalls at our Mine No. 7 will be decommissioned. Our optimal operating plan is a longwall/continuous miner production ratio of approximately 80% / 20%.

        In room-and-pillar mining a network of rooms are cut into the coal seam by remote-controlled continuous miners, leaving a series of coal pillars to support the mine roof. Shuttle cars and battery coal haulers transport coal to conveyor belt systems for further transportation to the surface. Ultimate seam recovery is typically less than that achieved with longwall mining as the pillars generated as part of this mining method can constitute up to 40% of the total coal seam. We employ this method to mine smaller blocks of coal in thinner seams as compared to longwall mining.

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        Surface Mining:    We employ surface mining methods when our coal reserves are located close to the surface. In 2011, approximately 40% of the coal we produced came from surface mining operations.

        Surface mining involves removing the topsoil then drilling and blasting the earth and rock covering the coal (overburden) with explosives. The overburden is then removed with heavy earth-moving equipment such as draglines, power shovels, excavators and loaders exposing the coal seam. Once exposed, the coal seam is extracted and loaded into haul trucks for transportation to a preparation plant or load out facility. After the coal is removed, as part of our normal mining activities, we use the topsoil and overburden removed at the beginning of the process to backfill the excavated coal pits and reclaim disturbed areas. Once we replace the overburden and topsoil, we reestablish vegetation and plant life into the natural habitat and make other improvements that have local community and environmental benefits. Ultimate seam recovery typically exceeds 80% and is dependent on overburden, coal thickness, geological factors, and equipment.

Description of Our Business

        We operate our business through two principal business segments: U.S. Operations and Canadian and U.K. Operations. Our business segment financial information is included in Note 17 of "Notes to Consolidated Financial Statements" included herein. During 2011, we actively operated 14 mines. For a comprehensive summary of all of our coal properties and of our coal reserves and production levels, see the tables summarizing our coal reserves and production in "Item 2. Properties" in this Form 10-K.

U.S. Operations

        The U.S. Operations segment includes metallurgical coal and thermal coal mines in both Alabama and West Virginia and a coke plant in Alabama. In 2011 metallurgical coal production totaled 5.9 million metric tons and thermal coal production totaled 3.4 million metric tons.

        Alabama Operations:    Our mining operations in Alabama operate two underground metallurgical coal mines in Southern Appalachia's Blue Creek coal seam, the No. 7 Mine (which includes No. 7 East) and the No. 4 Mine, one underground thermal coal mine, the North River Mine, one surface metallurgical coal mine, the Reid School Mine, one surface metallurgical and thermal coal mine, the Swann's Crossing mine and one surface thermal coal mine, the Choctaw Mine.

        Our Alabama underground mining operations are headquartered in Brookwood, Alabama and currently have approximately 217.0 million metric tons of recoverable reserves from our mines and nearby reserves located in west central Alabama between the cities of Birmingham and Tuscaloosa. Operating at about 2,000 feet below the surface, the No. 4 and No. 7 mines are two of the deepest underground coal mines in North America. The coal is mined using longwall extraction technology with development support from continuous miners. We extract coal primarily from Alabama's Blue Creek and Mary Lee seams, which contain high-quality bituminous coal. Blue Creek coal offers high coking strength with low coking pressure, low sulfur and low-to-medium ash content with high Btu values that can be sold either as metallurgical coal (used to produce coke) or as compliance thermal coal (used by electric utilities because it meets current environmental compliance specifications).

        The coal from our No. 4 and 7 mines is currently sold as a high quality low and mid-vol metallurgical coal. At forecasted production levels, we estimate the current reserves at these mines to have a 25 to 30 year life. As described above, in May 2011 we acquired mineral rights for approximately 68 million metric tons of recoverable Blue Creek metallurgical coal reserves to the northwest of our No. 4 mine. The mineral leases are expected to form the core of a planned new underground metallurgical coal mine that could increase the life to 40 to 50 years. Mines No. 4 and No.7 are located near Brookwood, Alabama, and are serviced by CSX rail. Both mines have access to our barge load out facility on the Black Warrior River. Service via both rail and barge culminates in delivery to the Port of Mobile, where shipments are delivered to our international customers via ocean

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vessels. Approximately 86% of the metallurgical coal sales in our Alabama underground mining operations are sales to international customers.

        The coal producer is responsible for transporting the coal from the mine to the export coal-loading facility. Export coal is usually sold at the loading port, with the buyer responsible for further transportation to their location. Since potential customers may choose a metallurgical coal supplier largely based on transportation costs, this is a critical issue. We have the advantage of having our mines conveniently located near both river barge load out facilities and railroad transportation (CSX rail) with direct access to the Port of Mobile, minimizing our transportation costs.

        In May 2011 we acquired Chevron Corporation's existing North River thermal coal mine in Alabama. The North River Mine is near the end of its life and mining is currently expected to be completed in 2013.

        Our Alabama natural gas operations extract and sell natural gas from the coal seams owned or leased by the Company and others. Prior to May 2010, our natural gas operations solely consisted of Black Warrior Methane Corp., an equal ownership venture with El Paso Production Co., a subsidiary of El Paso Corporation. In May 2010, we acquired HighMount Exploration and Production Alabama, LLC's coal bed methane business. The acquisition of this business included approximately 1,300 conventional gas wells, pipeline infrastructure and related equipment located adjacent to our existing underground mining and coal bed methane business. As of December 31, 2011, there were 1,768 wells that produced approximately 19.5 billion cubic feet of natural gas in 2011. The degasification operations have improved mining operations and safety by reducing methane gas levels in the mines.

        We are currently operating three surface mines in Alabama. The Choctaw Mine is located near Parrish in Walker County, Alabama and primarily produces thermal coal. The mine has an onsite rail facility serviced by Norfolk Southern rail. Access to Highway 269 provides delivery access to local customers via truck. The Reid School Mine is located in Blount County, Alabama and primarily produces metallurgical coal. Access to Highway 79 provides delivery to local customers via truck. Metallurgical coal mined at the Reid School Mine is primarily sold to our Coke plant and underground mining operations for resale. The Swann's Crossing Mine is located in Tuscaloosa County near Brookwood, Alabama and produces both metallurgical and thermal coal. The mine has access to our barge load out facility on the Black Warrior River.

        We also own other surface mine coal reserves including the Flat Top surface mine that is a thermal mine and is ready for operation and will be placed in service when market conditions permit. This mine is located in Adamsville, Alabama near Highway 78 where coal will be delivered to local customers via truck.

        We operate a coke plant, Walter Coke, located in Birmingham, Alabama. The plant's major product line is metallurgical coke, which includes coke for furnace and foundry applications. Foundry coke is marketed to ductile iron pipe plants and foundries producing castings, such as for the automotive and agricultural equipment industries. Furnace coke is sold to the domestic and international steel industry for producing steel in blast furnaces. The plant utilizes 120 coke ovens with a capacity to produce 381,000 tons of metallurgical coke and is the second largest merchant foundry coke producer in the United States.

        West Virginia Operations:    As a result of the acquisition of Western Coal on April 1, 2011, we acquired four mines on two properties in West Virginia which produce both metallurgical and thermal coal: the Gauley Eagle underground mine and surface mine and the Maple underground mine and surface mine.

        The Maple Coal mines, located in Fayette and Kanawha counties and the Gauley Eagle mines located in Nicholas and Webster counties of West Virginia contain approximately 38.7 million metric

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tons of recoverable reserves within the Appalachian coal-producing region. The Maple underground mine operates in the Eagle coal seam and employs room-and-pillar mining with continuous miners to produce a premium high volatile coking coal, which is used in the steelmaking process. The Gauley Eagle underground mine also employs room-and-pillar mining to produce a high volatile semisoft coking coal, which can be used in the steelmaking process or as a premium low-sulfur thermal coal. The Gauley Eagle underground mine was temporarily idled in mid-2011, due to economic conditions and the reallocation of personnel and equipment to the Maple underground mine. Both the Maple and Gauley Eagle surface mines produce primarily thermal coal. At forecasted production levels, we estimate the current reserves to have a 20-25 year life.

        Coal from the Gauley Eagle and Maple mines is either transported by rail or by barge on the river systems to our customers. Coal shipped from our rail load out facility can access regional markets and ports on the eastern U.S. seaboard. Coal shipped by barge on the river systems is trucked to the Kanawha River and shipped locally or offshore via the Mississippi River or Tennessee-Tombigbee river system. The transportation infrastructure and strategic location of the mines close to customers, ensures continuous and reliable delivery of our products.

        The metallurgical coal produced by our West Virginia operations is sold to both domestic and international steel mills, while the thermal coal is sold domestically to regional electrical power plants on the eastern U.S. seaboard. Production comes from over 14 mineable seams which allow us to blend coal to virtually any quality specifications that our customers request.

Canadian and U.K. Operations

        The Canadian and U.K. Operations segment includes metallurgical coal and thermal coal mines located in Northeast British Columbia (Canada) and South Wales (U.K.). Since being acquired on April 1, 2011, the Canadian and U.K. Operations metallurgical coal production totaled 2.8 million metric tons and thermal coal production totaled 91 thousand metric tons in the aggregate.

        Canadian Operations:    The Canadian mining operations currently operate three surface metallurgical coal mines in Northeast British Columbia's coalfields, the Wolverine Mine, the Brule Mine, and the Willow Creek Mine. Within British Columbia, the Company holds the right to two large multi-deposit coal property groups: the Wolverine group, consisting of the Perry Creek (Wolverine Mine), EB and Hermann deposits; and the Brazion group, consisting of the Brule Mine and the Willow Creek Mine and less explored portions of these properties and adjacent properties. We also have a 50% interest in the Belcourt-Saxon multi-deposit coal property groups described below.

        Our Canadian surface mining operations are located in Northeast British Columbia near the towns of Tumbler Ridge and Chetwynd. Our Canadian operations currently have approximately 101.3 million metric tons of recoverable coal reserves including 47.5 million metric tons at future mine sites. The Wolverine surface mine is located near the town of Tumbler Ridge and produces a high grade hard coking coal. We expect mining at the Wolverine mine to continue until approximately 2019. Future projects at Wolverine include the EB and Hermann surface mines which are currently expected to each have lives of 10 years. The Brule surface mine is located near the town of Chetwynd and produces a premium grade low-volatile PCI coal. We expect mining at the Brule mine to continue until approximately 2022. The Willow Creek surface mine, also located near the town of Chetwynd, produces metallurgical coal with production plans of one third hard coking coal and two thirds low-volatile PCI coal over the mine's life which is currently expected to be through 2027.

        A key strategic advantage of the Canadian operations is the proximity to existing infrastructure. Our wholly-owned properties are located near rail and port infrastructure that is operational all year around. The rail line is approximately 590 miles from our mines to the port at Prince Rupert, British Columbia. From the port facility, shipments are delivered to our international customers via ocean

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vessels. This combined infrastructure provides cost effective and reliable delivery of our products to our customers.

        Our Falling Creek connector road project was substantially commissioned near the end of the 2011 third quarter and truck hauling volumes on the road have continued to increase into the 2012 first quarter. The road connects the Brule mine to the Willow Creek mine where Brule's coal is processed and loaded at the rail load out facility. The new road reduces the hauling distance as compared to the previous route from just over 62 miles down to 37 miles. It is anticipated that the road will eventually allow us to increase our payload capacity resulting in future lower transportation costs.

        The metallurgical coal produced by our Canadian operations is sold to international customers located in Asia to meet the demand for steel produced in the region. Our Wolverine mine's metallurgical coal is a hard coking coal and forms a key coke oven blend component with many of the leading steel mills in Asia. The Brule and Willow Creek mine's low-volatile PCI coal is ranked as a premium PCI coal and can replace up to 30% of the coke feed in a blast furnace. Willow Creek also has hard coking coal reserves that we will begin to produce in 2012. These high quality metallurgical coals in conjunction with the infrastructure present in Northeast British Columbia continue to provide us with an opportunity to grow and diversify our customer base.

        Additionally, we have a 50.0% interest in the Belcourt Saxon Coal Limited Partnership which includes two multi-deposit metallurgical coal properties comprised of approximately 28.5 million metric tons of recoverable reserves which are located approximately 40 to 80 miles south of our Wolverine mine. We believe that the area has the potential to support significant mining operations and we expect that the partnership will develop these properties in the future. We also own or hold an interest in a number of other property assets located in Southeast British Columbia that are in the early stages of development.

        Mine planning is progressing for the proposed EB mine and Hermann mine located near our existing Wolverine mine. These mines together have approximately 19 million metric tons of recoverable high quality metallurgical coal reserves. Exploration has been completed within the proposed mining areas and production is expected to commence in EB as early as 2013.

        U.K. Operations:    Our U.K. mining operations consist of underground and surface mines located in South Wales.

        Our U.K. underground operations currently have approximately 5.3 million metric tons of recoverable reserves. The U.K. operations' primary activity is the development and expansion of the Aberpergwm underground coal mine located at Glynneath in the Neath Valley. We also operate the smaller Forest Quarry surface mine which is expected to end production in 2012. These mines produce low-volatile PCI metallurgical coal, anthracite coal and thermal coal. Our current plan for the U.K. operations is for mining operations to continue until approximately 2025 across different reserve areas.

        The U.K. operations are ideally located to take advantage of the high demand from U.K. steel mills and the European export market. Coal is processed in the operation's new preparation plant and loaded at a nearby rail load out facility or shipped to customers by road. Our mines currently supply high quality metallurgical coal to nearby steel mills and thermal coal and anthracite coal to a nearby electrical power plant and for various other commercial purposes.

Coal Preparation and Blending

        All of our coal mines have coal preparation and blending facilities convenient to each mine, each of which receive, blend, process and ship coal that is produced from one or more mines. Using our facilities, we are able to ensure a consistent quality and efficiently blend our coal to meet our customers' specifications.

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Marketing, Sales and Customers

        Coal prices differ substantially by region and are impacted by many factors including the overall economy, the demand for steel, the demand for electricity, location, the market, quality and type of coal, mine operation costs and the cost of alternative fuels. The major factors influencing our business are the economy and the demand for steel. Our Alabama operations' high quality Blue Creek coal and our Canadian operations' high quality hard coking coal are rated among the highest quality coals in the world and are preferred as a base coal in our customers' blends. The low-volatile PCI coal produced by our Canadian operations has proven itself in the marketplace as a desired source for steel makers to complement their coking coal blends. Our marketing strategy is to focus on international markets mostly in Europe, South America and Asia where we have a significant transportation cost advantage and where our coal is in high demand.

        During 2011, approximately 48% of our metallurgical coal shipments were to customers in Europe, approximately 16% to South America and approximately 32% to Asia. We are the largest U.S. supplier of metallurgical coal into South America. Further, we focus on long-term customer relationships where we have a competitive advantage. We sell most of our metallurgical coal under fixed price supply contracts primarily with terms of three and six months. Some sales of metallurgical coal can, however, occur in the spot market as dictated by available supply and market demand.

        During 2011, our five largest customers represented approximately 29% of our sales. Even in this challenging economy we believe that the loss of these customers would not have a material adverse effect on our results of operations as the loss of volume from these customers would be replaced with sales to other existing or new customers due to the demand for our metallurgical coal. Our outlook on the long-term prospects for growth and related demand for our product is very strong.

        Our thermal coal is primarily marketed to customers in the United States, generally under long-term contracts.

Trade Names, Trademarks and Patents

        The names of each of our subsidiaries are well established in the respective markets they serve. Management believes that customer recognition of such trade names is of significant importance. Our subsidiaries have numerous trademarks. Management does not believe, however, that any one such trademark is material to our individual segments or to the business as a whole.

Competition

        A large percentage all of our metallurgical coal sales are exported. Our major competitors are businesses that sell into our core business areas of Europe, South America and Asia. In both Europe and South America, we primarily compete with producers of premium metallurgical coal from Australia, Canada and the United States. In Asia, we primarily compete with producers of metallurgical coal from the United States, Australia and Canada. The principal areas in which we compete are coal prices at the port of shipment, coal quality and characteristics, customer relationships and the reliability of supply. The demand for our metallurgical coal is significantly dependent on the general economy and the worldwide demand for steel. Although there are significant challenges in this current difficult economy, we believe that we have competitive strengths in our business areas that provide us with distinct advantages.

Competitive Strengths

        We have premium products.    Blue Creek coal from our Alabama mining operations is recognized to be among the highest quality coals in the world. Its characteristics are very low sulfur, low ash and low volatility. These strong coking properties and high heat value make it ideally suited for steel makers as a coking coal. Hard coking coal produced from the Canadian mining operations has been well accepted

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by steel makers, with 5 of the top 10 largest steel mills as customers. The low-volatile PCI coal from the Canadian operations has been widely accepted by customers.

        We have a significant transportation advantage in shipping to our customers.    Our principal mines in our Alabama operations are serviced by CSX rail. We also have access to our barge load out facility on the Black Warrior River. Service via rail or barge is a relatively short distance to the Port of Mobile. Since customers for our Alabama metallurgical coal are primarily in Europe and South America, we are able to ship our coal quickly and at a relatively favorable cost. Our Canadian operations are located on CN Rail's high capacity and uncongested rail lines. Also in Canada, Ridley Terminals located in the port utilized by our operations can handle 12 million metric tons per year of coal with the potential to expand to 24 million metric tons per year. Our West Virginia operations are situated near both rail lines and a river system that can readily ship our coal to customers on the eastern seaboard and off shore. The unconstrained infrastructure represents a competitive advantage for us.

        We maintain excellent relationships with our customers.    Customers want good products, delivered on a timely basis at a fair price. Having premium products and with our production and transportation efficiencies, we are able to reliably deliver premium products at a competitive price on a timely basis. As a result, we have maintained excellent relationships with our customers over many years.

        We are able to purchase and blend coal to the customer's specifications.    In order to meet the exact needs of our customers, we are able to blend the high quality coals we sell to meet our customer's requirements at competitive prices.

Environmental and Other Regulatory Matters

        Our businesses are subject to numerous federal, state, provincial and local laws and regulations with respect to matters such as permitting and licensing requirements, employee health and safety, reclamation and restoration of property and protection of the environment. In the United States, environmental laws and regulations include, but are not limited to, the federal Clean Air Act ("CAA") and its state counterparts with respect to air emissions; the Clean Water Act ("CWA") and its state counterparts with respect to water discharges; the Resource Conservation and Recovery Act ("RCRA") and its state counterparts with respect to solid and hazardous waste generation, treatment, storage and disposal, as well as the regulation of underground storage tanks; and the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and its state counterparts with respect to releases, threatened releases, and remediation of hazardous substances. In Canada, the Company's operations are primarily regulated by provincial legislation, with some regional and federal authorizations required. Applicable environmental laws and regulations include, but are not limited to, the federal Fisheries Act with respect to protection of fish and fish habitat; the Species at Risk Act ("SARA") with respect to protection of identified species of risk, particularly caribou; the British Columbia Environmental Assessment Act with respect to conditions of applicable environmental assessment certificates; the Canadian Environmental Assessment Act with respect to potential federal environmental assessment processes; the British Columbia Mines Act (including the Health, Safety and Reclamation Code); the British Columbia Environmental Management Act and associated regulations with respect to waste discharges, air emissions, hazardous waste disposal, contaminated sites and spills; and the British Columbia Greenhouse Gas Reduction (Cap and Trade) Act with respect to reporting greenhouse gas emissions. Other environmental laws and regulations require reporting, even though the impact of that reporting is unknown. Compliance with these laws and regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production at our operations. These laws are constantly evolving and becoming increasingly stringent. The ultimate impact of complying with existing laws and regulations is not always clearly known or determinable due in part to the fact that certain implementing regulations for these environmental laws have not yet been promulgated and in certain instances are undergoing revision. These laws and regulations, particularly new legislative or administrative proposals (or judicial interpretations of existing laws and regulations)

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related to the protection of the environment, could result in substantially increased capital, operating and compliance costs and have a material adverse effect on our operations and/or our customers' ability to use our products.

        We strive to conduct our mining, natural gas and coke operations in compliance with all applicable federal, provincial, state and local laws and regulations. However, due in part to the extensive and comprehensive regulatory requirements, along with changing interpretations of these requirements, violations occur from time to time in our industry and at our operations. In recent years, expenditures for regulatory or environmental obligations in the United States have been mainly for safety or process changes, although certainly some expenditures continue to be made at several facilities to comply with ongoing monitoring or investigation obligations. Expenditures relating to environmental compliance are a major cost consideration for our Canadian operations and environmental compliance is a significant factor in mine design, both to meet regulatory requirements and to minimize long-term environmental liabilities. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, operating results will be reduced. We believe that our major North American competitors are confronted by substantially similar conditions and thus do not believe that our relative position with regard to such competitors is materially affected by the impact of environmental laws and regulations. However, the costs and operating restrictions necessary for compliance with environmental laws and regulations may have an adverse effect on our competitive position with regard to foreign producers and operators who may not be required to undertake equivalent costs in their operations. In addition, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, applicable state legislation and its production methods.

Permitting and Approvals

        Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state, provincial or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal or gas may have upon the environment, the public and our employees. In addition, we must also submit a comprehensive plan for mining and restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. The requirements are costly and time-consuming and may delay commencement or continuation of exploration or production at our operations. Typically we submit our necessary mining permit applications several months, or even years, before we anticipate mining a new area.

        Our coking operation is subject to numerous regulatory permits and approvals, including air and water permits. These permits subject us to monitoring and reporting requirements. We typically submit our necessary permit renewal applications several months prior to expiration.

        Applications for permits and permit renewals at our mining and coking operations are subject to public comment and may be subject to litigation from third parties seeking to deny issuance of a permit or to overturn the agency's grant of the permit application, which may also delay commencement or continuation of our mining and coking operations. Further, regulations provide that applications for certain permits or permit modifications in the United States can be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position to control another entity that has outstanding permit violations. In the current regulatory environment, we anticipate approvals will take even longer than previously experienced, and some permits may not be issued at all. Significant delays in obtaining, or denial of, permits could have a material adverse effect on our business.

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U.S. Operations

Mine Safety and Health

        The Coal Mine Health and Safety Act of 1969, the Federal Mine Safety and Health Act of 1977 ("MSHA"), and the Mine Improvement and New Emergency Response Act of 2006 (the "MINER Act"), as well as regulations adopted under these federal laws, impose rigorous safety and health standards on mining operations. Such standards are comprehensive and affect numerous aspects of mining operations, including but not limited to: training of mine personnel, mining procedures, ventilation, blasting, use of mining equipment, dust and noise control, communications, and emergency response. MSHA monitors compliance with these laws and standards by regularly inspecting mining operations and taking enforcement actions where MSHA believes there to be non-compliance. Maximum civil penalties for violations of these laws and standards are $70,000 per violation, unless the violation is deemed to be flagrant which can result in a maximum civil penalty of $220,000. These federal mine safety and health laws and regulations have a significant effect on our operating costs.

        The MINER Act mandated increased regulations in some of the areas listed above, and some of those regulations are now effective. The MINER Act and other legislative and regulatory initiatives, such as the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank Act") passed by the U.S. Congress and signed into law on July 21, 2010 are still ongoing. While the Dodd-Frank Act is focused primarily on the regulation and oversight of financial institutions, it also provides for regulatory compliance related to mining safety and health matters. The Dodd-Frank Act requires the SEC to enact numerous rules and regulations, some of which could impact our business practices or place additional reporting burdens on us. It is not possible at this time to predict the full effect that the new or proposed regulations and policies will have on our operating costs, but it will likely increase our costs and those of our competitors.

Workers' Compensation and Black Lung

        We are self-insured for workers' compensation benefits for work-related injuries. Workers' compensation liabilities, including those related to claims incurred but not reported, are recorded principally using annual valuations based on discounted future expected payments using historical data of the division or combined insurance industry data when historical data is limited. In addition, certain of our subsidiaries are responsible for medical and disability benefits for black lung disease under the Federal Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act of 1977, as amended, and are self-insured against black lung related claims. We perform periodic evaluations of our black lung liability, using assumptions regarding rates of successful claims, discount factors, benefit increases and mortality rates, among others. See "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition" for further information on assumptions utilized.

Surface Mining Control and Reclamation Act

        The Surface Mining Control and Reclamation Act of 1977 ("SMCRA"), requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities. Permits for all mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement or, where state regulatory agencies have adopted federally approved state programs under the Act, the appropriate state regulatory authority. In Alabama, the Alabama Surface Mining Commission reviews and approves SMCRA permits.

        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, subsidence control for underground mines, surface drainage control, mine

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drainage and mine discharge control, treatment and revegetation. These requirements seek to limit the adverse impacts of coal mining and more restrictive requirements may be adopted from time to time.

        Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed or abandoned prior to 1977. On December 7, 2006, the Abandoned Mine Land Program was extended for 15 years.

        SMCRA stipulates compliance with many other major environmental statutes, including: the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act, and the Comprehensive Environmental Response, Compensation and Liability Act.

        On December 12, 2008, the Office of Surface Mining (OSM), finalized rulemaking regarding the interpretation of the stream buffer zone provisions of SMCRA which confirmed that excess spoil from mining and refuse from coal preparation could be placed in permitted areas of a mine site that constitute waters of the United States. The rule was challenged in U.S. District Court. A settlement agreement staying the litigation established a timeframe for revision of the regulations. The OSM anticipates publishing a proposed rule and draft impact statement during 2012.

        We accrue for the costs of final mine closure. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our experience. The amounts recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected. At December 31, 2011, we have accrued $75.1 million for our asset retirement obligations, most of which will be incurred at our underground mining operations at the end of the mines' lives.

Surety Bonds/Financial Assurance

        We use surety bonds, trusts and letters of credit to provide financial assurance for certain transactions and business activities. Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations, including mine closure or reclamation costs and other miscellaneous obligations. The bonds are renewable on a yearly basis.

        Surety bond costs have increased in recent years while the market terms of such bonds have generally become more unfavorable. In addition, the number of companies willing to issue surety bonds has decreased. Bonding companies also require posting of collateral, typically in the form of letters of credit, to secure the surety bonds. As of December 31, 2011, we had outstanding surety bonds and collateral with parties for post-mining reclamation at all of our mining operations totaling $68.5 million, plus $9.9 million for miscellaneous purposes. As of December 31, 2011, we maintained letters of credit totaling $34.2 million to secure surety bonds plus $24.9 million in other forms of collateral to satisfy reclamation obligations.

Climate Change

        Global climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity, especially the emission of greenhouse gases ("GHGs"), such as carbon dioxide and methane. Combustion of fossil fuels, such as the coal and methane gas we produce results in the creation of carbon dioxide that is currently emitted into the atmosphere by coal and gas end-users. Further, some of our operations such as coal mining and coke production directly emit GHGs. Laws and regulations governing emissions of GHGs have been adopted by foreign governments, including the European Union and member countries, individual states in the United States and regional governmental authorities. Further, numerous proposals have been made and are likely to continue to be made at the international, national, regional, and state levels of government

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that are intended to limit emissions of GHGs by enforceable requirements and voluntary measures. In addition, the United States and over 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which is intended to limit emissions of GHGs. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emission targets for developed nations. Although the specific emission targets vary from country to country, the United States would have been required to reduce emissions to 93% of 1990 levels from 2008 through 2012. During his campaign for office, President Obama pledged to implement an economy-wide cap-and-trade program to reduce GHG emissions 80 percent by 2050 and pledged that he would cause the United States to be a world leader on GHG reduction and re-engage with the United Nations Framework Convention on Climate Change to develop a global GHG program. However, following the mid-term elections, President Obama has placed a greater emphasis on clean energy technology as a means to reduce GHG emissions.

        In April 2009, in response to a 2007 U.S. Supreme Court decision, the Environmental Protection Agency ("EPA") proposed findings that emissions of GHGs from motor vehicles are contributing to air pollution which, in turn, is endangering the public health and welfare. These proposed findings (which were made final in December 2009) set in motion the process for EPA to regulate GHGs from mobile sources, which in turn may result in regulation of GHGs from stationary sources under the Clean Air Act. EPA's findings focus on six GHGs, including carbon dioxide and nitrous oxide (which are emitted from coal combustion) and methane (which is emitted from coal beds). Although EPA has stated a preference that GHG reduction be based on new federal legislation rather than through agency regulation pursuant to the existing Clean Air Act, EPA is nonetheless taking steps to regulate many sources of GHGs without further legislation (see Clean Air Act below). It is difficult to predict reliably how such regulation will develop and when or whether it will take effect, as EPA's recently finalized findings that underpin such regulation are the subject of a number of lawsuits. Also, bills have been introduced in Congress that would, if enacted, prevent EPA from regulating GHGs under the Clean Air Act.

        In June 2010, the U.S. House of Representatives passed a bill that would regulate GHG emissions through a "cap and trade" system and related programs, which generally would require emitters of GHGs to purchase or otherwise obtain allowances to emit GHGs. However, the bill failed to make it through the U.S. Senate. Thus, it is uncertain whether Congress will enact "cap and trade" or other legislation to address climate change and, if it does, when it will occur and what it will require.

        Coal bed methane must be expelled from our underground coal mines for mining safety reasons. Our gas operations extract coal bed methane from our underground coal mines prior to mining. With the exception of some coal bed methane which is vented into the atmosphere when the coal is mined, the methane is captured. If regulation of GHG emissions does not exempt the release of coal bed methane, we may have to curtail coal production, pay higher taxes, or incur costs to purchase credits that allow us to continue operations as they now exist at our underground coal mines. The amount of coal bed methane we capture is recorded, on a voluntary basis, with the U.S. Department of Energy. We have recorded the amounts we have captured since 1992. In 2009, JWR partnered with Biothermica Technologies to capture and mitigate the methane that is vented into the atmosphere as a result of the mining process. This project resulted in the listing of the project with the Climate Action Reserve on February 2, 2010, a national offsets program working to ensure integrity, transparency and financial value in the U.S. carbon market by establishing regulatory-quality standards for the development, quantification and verification of GHG emissions reduction projects in North America. If regulation of GHGs does not give us credit for capturing methane that would otherwise be released into the atmosphere at our coal mines, any value associated with our historical or future credits would be reduced or eliminated.

        The EPA released results of the 2010 GHG reports that were filed by about 6,700 entities with GHG emissions over 25,000 tons per year. The data is available to the public online in a form similar to Toxic Release Inventory data,i.e., searchable by state, industry sector, and source. Oral arguments in

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the litigation over EPA's GHG regulations are scheduled before the U.S. Court of Appeals for the DC Circuit on February 28, 2012.

        On December 1, 2011, EPA and the National Highway Traffic Safety Administration published a proposed rule for progressively tighter fuel economy and GHG emission standards for cars and light trucks beginning with the 2017 model year and culminating with limits of 56 mpg for passenger cars and 40.3 mpg for light trucks by 2025. The combined fleet average of 49.6 mpg compares to the current 25 mpg and the already promulgated average of 35.5 mpg to be achieved by model year 2016.

        At the 17th Conference of the Parties (COP-17) of the U.N. Framework Convention on Climate Change in Durban, South Africa, negotiations extended beyond the planned conclusion of the meeting and led to a somewhat vague and inexact agreement that would obligate major GHG emitting countries—including the U.S., China and India—to begin to reduce emissions beyond 2020. The agreement sets 2015 as a target date to complete a text for a legally binding agreement. A second commitment period for the Kyoto Protocol was also agreed to, although several major countries—Canada, Japan, and Russia—opted out, and a decision on the length of the second commitment period is being deferred to COP-18 in late 2012. Meanwhile, Canada has withdrawn from the original Kyoto Protocol, opting instead to commit to the Copenhagen Accord, which called for reducing GHG emissions to 2005 levels by 2020.

        Additional laws or regulations regarding GHG emissions or other actions to limit GHG emissions could result in fuel switching from coal, or to a lesser degree natural gas to other fuel sources. Alternative fuels (non-fossil fuels) could become more attractive than coal, or to a lesser degree natural gas, in order to reduce GHG emissions. This could result in a reduction in the demand for our coal, and to a lesser degree, our natural gas, and therefore, our revenues, as well as reduce the value of our reserves (although fuel switching could increase demand for our natural gas, which emits less GHG when burned than an equivalent quantity of coal). The anticipation of such requirements could also lead to reduced demand for some of our products. Additional GHG laws or regulations could also increase our costs, such as those to produce natural gas and manufacture coke. Although the potential impacts on us of additional climate change regulation are difficult to reliably quantify, they could be material.

Clean Air Act

        The federal Clean Air Act ("CAA") and comparable state laws that regulate air emissions affect coal mining and coking operations both directly and indirectly. Direct impacts on coal mining may occur through permitting requirements and/or emission control requirements relating to particulate matter, such as fugitive dust, or fine particulate matter measuring 2.5 micrometers in diameter or smaller. The Clean Air Act indirectly affects our mining operations and directly affects our coking operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired utilities, steel manufacturers and coke ovens. As described below, proposed regulations would also subject GHG emissions to regulation under the Clean Air Act.

        The CAA requires, among other things, the regulation of hazardous air pollutants through the development and promulgation of Maximum Achievable Control Technology ("MACT") Standards. The EPA has developed various industry-specific MACT standards pursuant to this requirement. The CAA requires EPA to promulgate regulations establishing emission standards for each category of Hazardous Air Pollutants. EPA must also conduct risk assessments on each source category that is already subject to MACT standards and determine if additional standards are needed to reduce residual risks.

        Our coking facility is subject to certain MACT standards and NESHAPS (National Emissions Standards for Hazardous Air Pollutants). Relative to MACT, these standards apply to pushing, quenching, and under-firing stacks and went into effect in April 2006. Concerning NESHAPS, the standards include Coke Oven NESHAPS (1993), Benzene NESHAPS and Benzene Waste NESHAPS, which were also enacted in the early 1990's. The portion of NESHAP which applies to coke ovens

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addresses emissions from charging, coke oven battery tops, and coke oven doors. With regard to this standard, Walter Coke chose the LAER (Lowest Achievable Emissions Rate) track, and therefore is not required to comply with residual risk until 2020.

        On January 9, 2012, the DC U.S. District Court overturned EPA's stay of the Boiler MACT and solid waste incinerator (CISWI) rules based on the Sierra Club's challenge of the stay, which was intended to provide time for EPA to reconsider and re-propose the rule. This means the 3-year period for existing sources to comply with the previously issued rule in March 2011 is effective, although the December 23, 2011 re-proposed rule, subject to comments by February 21, 2012 would re-set the compliance timetable when finalized. In a January 18, 2012 letter responding to a Congressional inquiry, EPA stated that no enforcement action would be taken relative to notification requirements in the original (no longer stayed) rule until a final rule is issued and EPA re-sets these dates. A request for an extension of the comment deadline has been made by a multi-industry group. Since the scope of future changes is relatively uncertain, the magnitude of the impact of any such anticipated changes cannot be estimated at this time.

        The CAA also requires EPA to develop and implement National Ambient Air Quality Standards or NAAQS for criteria pollutants, which include sulfur dioxide, particulate matter, nitrogen oxides, and ozone. Areas that are not in compliance with these standards, referred to as non-attainment areas, must take steps to reduce emission levels. Individual states must identify the sources of emissions and develop emission reduction plans. These plans may be state-specific or regional in scope. It is anticipated that EPA's fine particle programs will affect many power plants, especially coal-fueled power plants and all plants in non-attainment areas, and could result in significant costs; however, it is impossible to estimate the magnitude of these costs at this time as state and federal agencies are still developing regulations for the programs and implementation.

        EPA announced on January 6, 2010 a proposal to adopt a new, more stringent primary ambient air quality standard for ground-level ozone and to change the way in which the secondary standard is calculated. The EPA has entered into a consent decree with environmental groups that commits the agency to publish by May 31, 2012 designations for areas not attaining the 2008 ozone ambient air standard. Litigation over EPA's missed deadlines for implementing state implementation plans and air permitting requirements relative to the 2008 standard is not addressed in the consent decree and is continuing. The EPA has submitted for review a rule that would designate areas that are not attaining the 2008 ozone ambient air standards, which the agency agreed in a consent order to do by May 31, 2012. The agency is also working on guidance for states to implement those standards. Meanwhile, environmental groups continue to pursue their challenge to the 2008 standard as well as separate litigation challenging the Administration's September 2011 decision to withdraw its proposal to tighten the 2008 standard and instead roll consideration of a new standard into the ongoing review that would lead to a new proposal in 2014. Should these NAAQS withstand scrutiny, additional emission control expenditures will likely be required at coal-fueled power plants.

        On December 16, 2011, the EPA signed a rule to reduce emissions of toxic air pollutants from power plants. Specifically, these mercury and air toxics standards (MATS) for power plants will reduce emissions from new and existing coal and oil-fired eclectic utility steam generating units. The required reduction in emissions may require the installation of additional costly control technology or the implementation of other measures, including trading of emission allowances and switching to alternative fuels. These reductions in permissible emission levels will likely make it more costly to operate coal-fired power plants and may adversely affect the demand for coal.

        On January 22, 2010, EPA set a new one-hour Nitrogen Dioxide (NO2) standard and retained the annual average. The new standard must be taken into account when permitting new or modified major sources of NO2 emissions such as fossil-fueled power plants, boilers, and a variety of manufacturing operations. The EPA expects to designate non-attainment areas in early 2012 and based on additional

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monitoring, re-designate areas in 2016 or 2017. Additional emission control expenditure may be required at coal-fueled power plants and may adversely affect the demand for coal.

        On June 2, 2010, EPA revised the NAAQS for Sulfur Dioxide (SO2) by establishing a new one-hour standard and revoking the existing 24-hour and annual standards. EPA intends to complete non-attainment designation by June 2, 2012 and require state implementation plans by 2014 and standards to be met by August, 2017. Additional emission control expenditure may be required at coal-fueled power plants and may adversely affect the demand for coal.

        The EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. This program may result in additional emissions restrictions from new coal-fired power plants whose operation may impair visibility at and around federally protected areas. This program may also require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. EPA's finding concerning GHG endangerment of public health and welfare (see the discussion on Climate Change) may lead to regulation of GHG emissions from stationary sources under the Clean Air Act. In connection with that finding, EPA also finalized a tailoring rule which would set emission thresholds for GHG regulation under EPA's current Clean Air Act stationary source permitting requirements. Finalized on May 13, 2010 and effective January 2, 2011, this rule has drawn legal challenges. Accordingly, the impact of such regulation on us cannot be reliably estimated at this time, although it could be material.

Clean Water Act

        The federal Clean Water Act ("CWA") and corresponding state laws affect our operations by imposing restrictions on discharges of wastewater into creeks and streams. These restrictions, more often than not, require us to pre-treat the wastewater prior to discharging it. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. Our mining and coking operations maintain water discharge permits as required under the National Pollutant Discharge Elimination System program of the CWA, and conduct their operations to be in compliance with such permits. We believe we have obtained all permits required under the Clean Water Act and corresponding state laws and are in substantial compliance with such permits. However, new requirements under the Clean Water Act and corresponding state laws may cause us to incur significant additional costs that could adversely affect our operating results.

Resource Conservation and Recovery Act

        The Resource Conservation and Recovery Act ("RCRA") and corresponding state laws establish standards for the management of solid and hazardous wastes generated at our various facilities. Besides affecting current waste disposal practices, RCRA also addresses the environmental effects of certain past hazardous waste treatment, storage and disposal. In addition, RCRA also requires certain of our facilities to evaluate and respond to any past release, or threatened release, of a hazardous substance that may pose a risk to human health or the environment.

        RCRA may affect coal mining operations by establishing requirements for the proper management, handling, transportation and disposal of solid and hazardous wastes. Currently, certain coal mine wastes, such as earth and rock covering a mineral deposit (commonly referred to as overburden) and coal cleaning wastes, are exempted from hazardous waste management under RCRA. Any change or reclassification of this exemption could significantly increase our coal mining costs.

        Our coking operation is in the study phase of a RCRA corrective action program. Until the studies are complete, we are unable to determine the final cleanup or remediation that may be required and are unable to estimate the total cost of any such remediation activities. For additional information

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regarding significant enforcement actions, capital expenditures and costs of compliance, see "Item 3. Legal Proceedings" and Environmental Matters in Note 14 of "Notes to Consolidated Financial Statements" included in this form 10-K

Comprehensive Environmental Response, Compensation and Liability Act

        The Comprehensive Environmental Response, Compensation and Liability Act, CERCLA or Superfund, and similar state laws affect our coal mining and coking operations by, among other things, imposing investigation and cleanup requirements for threatened or actual releases of hazardous substances. Under CERCLA, joint and several liability may be imposed on operators, generators, site owners, lessees and others regardless of fault or the legality of the original activity that caused or resulted in the release of the hazardous substances. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, the universe of materials and wastes governed by CERCLA is broader than "hazardous waste" and as such even non-hazardous wastes can, in certain circumstances, contain hazardous substances which, if released into the environment, are governed by CERCLA. Alabama's version of CERCLA mirrors the federal version with the important difference that there is no joint and several liability. Liability is consistent with one's contribution to the contamination. In addition, the disposal, release or spilling of some products used by coal and coking companies in operations, such as chemicals, could trigger the liability provisions of CERCLA or similar state laws because, at that point they are deemed to be waste and the activity, even though inadvertent, is deemed to constitute disposal or a covered CERCLA release. Thus, we may be subject to liability under CERCLA and similar state laws for properties that (1) we currently own, lease or operate (2) we, our predecessors, or former subsidiaries have previously owned, leased or operated, (3) sites to which we, our predecessors or former subsidiaries sent waste materials, or (4) sites at which hazardous substances from our facilities' operations have otherwise come to be located.

Other Environmental Laws

        We are required to comply with numerous other federal, state and local environmental laws and regulations in addition to those previously discussed. These additional laws include, for example, the Endangered Species Act, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act.

Canadian and U.K. Operations

Endangered Species Legislation

        The Company has operations that may be affected by ongoing and proposed planning to protect certain species that are listed as threatened under the federal Species at Risk Act. The Species at Risk Act prohibits killing, harming, harassing, capturing or taking an individual of a wildlife species that is listed as threatened, and also makes it an offense to damage or destroy that species' residence, meaning a den, nest or other similar area of place that is occupied or habitually occupied by one for more individuals during all or part of their life cycles. The Act is federal legislation, which is generally applicable only on federal lands and to species under federal jurisdiction (fish and migratory birds), but under certain circumstances, the provisions of the Species at Risk Act may be extended by the federal government to apply on provincial lands.

        Species considered to be at risk by the province of British Columbia are identified by order of the provincial Minister of Environment under the authority of the Forest and Range Practices Act (British Columbia) and managed under the Identified Wildlife Management Strategy (IWMS), an initiative of the Ministry of Environment in partnership with the Ministry of Forests and Range. The IWMS provides direction, policy, procedures and guidelines for managing identified species, which may entail restoration of previously occupied habitats, particularly for those species most at risk, and the establishment of wildlife habitat areas and wildlife habitat area management objectives.

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        The species of the highest concern in respect of the Company's operations is the caribou, although we continue to consider the impacts of our operations on other threatened species in the area. While we take great care to cause little or no impact on caribou in the area of our operations, protection of caribou and their habitat has attracted significant attention in areas where we operate due to the drastic reduction in caribou herd numbers in those areas. The Company has experienced significant delays in obtaining new or amended permits and mining tenures in areas frequented by caribou, which could have a significant impact on the continued development of our Canadian operations. Further, infractions under the federal Act could attract penalties of up to CAD$1.0 million.

Environmental Management Act

        The Environmental Management Act affects our operations by requiring us to obtain authorizations to introduce "waste" into the environment, including air contaminants, effluent, and hazardous and solid waste. Permits requiring regular monitoring and compliance with waste discharge limitations and reporting requirements govern the discharge of various substances into the environment, including air and water. We have obtained all permits required under the Environmental Management Act and corresponding regulations and are in substantial compliance with such permits, subject to the considerations relating to selenium levels described below. However, any new requirements under the Environmental Management Act and corresponding regulations may cause us to incur significant additional costs that could adversely affect our operating results.

        The Company is currently not meeting revised provincial water quality guidelines relating to selenium levels at the Brule mine, and is cooperating and working with the British Columbia Ministry of Environment to reduce selenium levels in its effluent to meet these guidelines. As a result, the Company is considering various alternatives for selenium management and effluent treatment at the Brule mine, which will likely lead to significantly increased compliance costs at the operation and increased bonding requirements.

        The Environmental Management Act and the Contaminated Sites Regulation also affect our operations by, among other things, imposing investigation and cleanup requirements for contaminated sites. Part 5 of the Environmental Management Act makes specific provision for "Remediation of Mineral Exploration Sites and Mines" and gives general jurisdiction to the Chief Inspector of Mines, who is also responsible for the reclamation requirements imposed under the Mines Act and the Mine Code, with respect to "core areas" of a producing mine site. The Contaminated Sites Regulation continues to govern any contamination at "non-core areas", such as maintenance shops, storage facilities and crushing or processing mills, as well as the disposal, release or spilling of some chemical products used by coal and coking companies in operations. Under the Contaminated Sites Regulation, joint and several liability may be imposed on current operators or owners of a site, previous operators or owners of a site, producers or transporters of a substance that caused contamination and others regardless of fault or the legality of the original activity that caused or resulted in the release of the hazardous substances.

First Nations Considerations

        Canadian law recognizes the existence of Aboriginal and Treaty rights, including Aboriginal title to lands. The Canadian courts have confirmed that when the federal and provincial governments contemplate conduct that may adversely affect the Aboriginal or Treaty rights of a First Nation, they must consult with and accommodate the First Nation. In the regulatory context, the government's duty to consult may be triggered by a variety of decisions, including the decision to issue or amend a permit. In order to meet their duties to consult and accommodate in this context, the federal and provincial governments require a company seeking a new or amended permit or other authorization to engage and consult with the First Nation about the potential effects of granting the requested authorization. Based on this process, the company is then expected to assist the government in determining what

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accommodations of the First Nation's rights by the company may be necessary prior to granting the requested authorization.

        As the Company is governed by a significant number of permits in British Columbia and anticipates the need to both obtain new permits and amend existing permits in connection with its current and future operations, the government's duty to consult with First Nations may have a significant impact on the Company's ability to operate in the future. If a governmental authority determines that it has a duty to consult in a permitting matter, the consultation process could add significant delays in, and additional costs relating to the eventual issuance or amendment of the relevant permit. Further, where a governmental authority fails to meet its duty to consult in granting a government authorization, such a failure may expose the Company's permits and authorizations to judicial review, lengthy court processes and the risk of cancellation of the government authorization.

        The Company strives to build beneficial relationships with the First Nations in its areas of operation and participates in any consultation process that relates to its operations. Although ultimately the duty to consult is a duty of the government, the consultation process would not progress without the involvement of the Company and its strong interest in ensuring that the process is carried out effectively and comprehensively. The Company is committed to engaging with First Nations in a meaningful way and devotes significant time and resources to working proactively and cooperatively with local First Nations to acknowledge and address their concerns.

Fisheries Act

        The Fisheries Act (Canada) affects our Canadian operations by, amongst other things, prohibiting the harmful alteration, disruption or destruction of fish habitat without authorization as well as the deposit of deleterious substances into fish-bearing waters. We may be exposed to liability in the event that we cause harmful alteration, disruption or destruction of fish habitat or that we discharge, or are responsible for the discharge of, deleterious substances (as defined in the Act) into waters frequented by fish. Offenses under the Act resulting in the harmful alteration, disruption or destruction of fish habitat or the deposit of deleterious substances into fish habitat could attract fines of up to CAD$1.0 million for each day that an offence continues. Liability under the Act is for owners of the property or substance, as well as their directors and officers, agents, tenants, occupiers, partners or persons actually in charge of the property or substance.

        The Company is currently cooperating with regulatory authorities to address concerns relating to a release in April 2011 of sediment and debris into Willow Creek from the forest service road leading to the Willow Creek mine. Although the investigation into the matter is being led by the provincial Ministry of Environment, there is the potential that the discharge and deposit of sediment in the stream bed could be determined to be a harmful alteration, disruption or destruction of fish habitat contrary to the Fisheries Act.

Provincial and Federal Environmental Assessment Acts

        Our Canadian operations have been subject to an environmental assessment under the provincial Environmental Assessment Act. Each project was issued an environmental assessment certificate that sets out the criteria according to which the project must be designed and constructed, along with a schedule that sets out the commitments the Company has made to address concerns raised through the environmental assessment process. If, for any reason our operations are not conducted in accordance with the environmental assessment certificate, then our operations may be temporarily suspended until such time as our operations are brought back into compliance.

        Any significant changes to our current operations or further development of our properties in British Columbia may trigger a federal or provincial environmental assessment or both. In particular, the proposed project amendments at the EB mine have the potential to trigger an assessment under the Canadian Environmental Assessment Act. Although the Company considers that a federal

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environmental assessment would be unlikely, an additional environmental assessment, including the requirement for a substantive public review and First Nations consultation process, could result in significant delays for the operation.

Mines Act and the Health, Safety and Reclamation Code for Mines in British Columbia (the "Mine Code")

        Our Canadian operations require permits issued pursuant to the Mines Act outlining the details of the work at the mine and a program for the conservation of cultural heritage resources and for the protection and reclamation of the land, watercourses and cultural heritage resources affected by the mine. The Chief Inspector of Mines may issue a permit with conditions, including requiring that the owner, agent, manager or permittee give security in the amount and form specified by the Chief Inspector for mine reclamation and to provide for the protection of watercourses and cultural heritage resources affected by the mine. The reclamation security may be applied towards mine closure or reclamation costs and other miscellaneous obligations if permit conditions are not met. Detailed reclamation and closure requirements are contained in the Mine Code.

        Under the Mines Act and the Mine Code, we have filed mine plans and reclamation programs for each of our operations.

        As of December 31, 2011, we had posted surety bonds and letters of credit for post-mining reclamation, as required by our Mines Act permits, totaling CAD$22.4 million for all of our Canadian operations. We anticipate that the total amount of the required surety bonds and letters of credit will increase in 2012, primarily relating to selenium management, effluent discharge and permitting requirements (see above under "Environmental Management Act").

Climate Change

        While initially a signatory to the December 1997 Kyoto Protocol that established a set of greenhouse gas emission targets for developed countries, Canada withdrew from the Kyoto Protocol at the Conference of Parties 17 of the United Nations Framework Convention on Climate Change in December 2011. While the government of Canada has a previously stated goal of reducing Canada's total greenhouse gas emissions by 17 percent from 2005 levels by 2020, it has not indicated how it will achieve such a reduction. The Canadian government has also publicly stated that any legislative action to reduce greenhouse gas emissions at the federal level must be integrated with U.S. legislation. While there are currently no federal emissions targets affecting the Company's operations, the Company is currently required to report its emissions from the Perry Creek mine, and may in the future be required to report emissions for its other Canadian operations, pursuant to the federal Canadian Environmental Protection Act. This Act requires operators of facilities emitting greater than 50,000 metric tons per year of carbon dioxide equivalent to report emissions annually.

        In British Columbia, the provincial government has legislated a target of greenhouse gas emissions reductions of 33% below 2007 emissions levels by 2020 and 80% below 2007 emissions levels by 2050. British Columbia has also had a carbon tax on fuel since 2008. In 2008, the provincial government introduced legislation that was intended to establish a cap and trade system by January 1, 2012. The establishment of the cap and trade system in British Columbia has been delayed, however, and as of February 29, 2012, the provincial government has not released the regulatory details of the proposed cap and trade system, nor has it announced a start date. British Columbia remains a member of the Western Climate Initiative ("WCI"), which is a cooperative effort of the State of California and participating Canadian provinces to design a comprehensive regional model cap and trade program. It is expected that any cap and trade system to be implemented under the provincial legislation will be based on the model program developed by WCI. In preparation for the implementation of an emissions cap and trade system, in November 2009 the provincial government enacted a reporting regulation that requires facilities emitting greater than 10,000 metric tons of carbon dioxide equivalent per year to register and report emissions annually for periods beginning on January 1, 2010. Any facilities emitting greater than 25,000 metric tons per year are also subject to certain emissions reporting verification

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requirements. Each of the Company's Canadian operations is required to report emissions under the provincial legislation.

        Although the costs currently associated with emissions reporting under federal and provincial legislation are not material, the implementation of emissions targets or the proposed provincial cap and trade system may result in material financial impacts on our Canadian operations. As in the United States, it is unclear in the current political climate (both federally and provincially) whether or not a cap and trade system or other emissions reductions programs will be enacted and if so, when it would be enacted or what the program would require.

U.K. Environmental Laws

        The Company's operations in Wales are subject to certain environmental laws and regulations of the United Kingdom, including the Environmental Protection Act 1990, Environment Act 1995, Environmental Permitting Regulations 2010, and Town and Country Planning Act 1990. The costs of compliance with these environmental laws have not had a material impact on the Company's financial position in the most recently completed financial year, and the Company does not expect that compliance with these laws will have a material impact on the Company's financial position in the current or future financial years.

Other Environmental Laws

        We are required to comply with numerous other federal, state, provincial and local environmental laws and regulations in addition to those previously discussed. These additional laws include, for example, the Endangered Species Act, the Safe Drinking Water Act, the Toxic Substance Control Act, the Emergency Planning and Community Right-to-Know Act, the British Columbia Water Act and the British Columbia Forest Act.

Seasonality

        Our primary business is not materially impacted by seasonal fluctuations. Demand for coal is generally more heavily influenced by other factors such as the general economy, interest rates and commodity prices.

Employees

        As of December 31, 2011, we employed approximately 4,200 employees, of whom approximately 3,000 were hourly employees and 1,200 were salaried employees. As of December 31, 2011, unions represented approximately 2,100 employees under collective bargaining agreements, of which approximately 1,600 were covered by one contract with the United Mine Workers of America that expires on December 31, 2016.

Available Information

        We make our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K and amendments thereto available on our website atwww.walterenergy.com without charge as soon as reasonably practical after filing or furnishing these reports to the Securities and Exchange Commission ("SEC"). Additionally, we will also provide, without charge, a copy of our Form 10-K to any shareholder by mail. Requests should be sent to Walter Energy, Inc., Attention: Shareholder Relations, 3000 Riverchase Galleria, Suite 1700, Birmingham, Alabama 35244. You may read and copy any document the Company files at the SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. Our SEC filings are also available to the public from the SEC's website athttp://www.sec.gov.

Executive Officers of the Registrant

        Incorporated by reference into this Part I is the information set forth in Part III, "Item 10. Directors, Executive Officers and Corporate Governance."

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Item 1A.    Risk Factors

Risks Associated with our Current Continuing Operations

Unfavorable global economic, financial and business conditions may adversely affect our businesses.

        The global financial markets have been experiencing volatility and disruption over the last several years. These markets have experienced, among other things, volatility in security prices, commodities and currencies; diminished liquidity and credit availability, rating downgrades and declining valuations of certain investments. Weaknesses in global economic conditions could have a material adverse effect on the demand for our coal, coke and natural gas products and on our sales, pricing and profitability. We are not able to predict whether the global economic conditions will continue or worsen and the impact these events may have on our operations and the industry in general.

Our businesses may suffer as a result of a substantial or extended decline in pricing, demand and other factors beyond our control, which could negatively affect our operating results and cash flows.

        Our businesses are cyclical and have experienced significant difficulties in the past. Our financial performance depends, in large part, on varying conditions in the international and domestic markets we serve, which fluctuate in response to various factors beyond our control. The prices at which we sell our coal, coke and natural gas are largely dependent on prevailing market prices for those products. We have experienced significant price fluctuations in our coal, coke and natural gas businesses, and we expect that such fluctuations will continue. Demand for and, therefore, the price of, coal, coke and natural gas are driven by a variety of factors, including, but not limited to, the following:

•

the domestic and foreign supply and demand for coal;

•

the quantity and quality of coal available from competitors;

•

adverse weather, climatic or other natural conditions, including natural disasters;

•

domestic and foreign economic conditions, including economic slowdowns;

•

global or regional political events;

•

legislative, regulatory and judicial developments, environmental regulatory changes or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions or providing for increased funding and incentives for alternative energy sources;

•

the proximity to, capacity of and cost of transportation and port facilities; and

•

market price fluctuations for sulfur dioxide emission allowances.

        In addition, reductions in the demand for metallurgical coal caused by reduced steel production by our customers, increases in the use of substitutes for steel (such as aluminum, composites or plastics) and the use of steel-making technologies that use less or no metallurgical coal can significantly affect our financial results and impede growth. Demand for thermal coal is primarily driven by the price of thermal coal and natural gas and the consumption patterns of the domestic electric power generation industry, which, in turn, is influenced by demand for electricity and technological developments. We estimate that a 10% decrease in the price of metallurgical coal for the full year 2011 would have resulted in a reduction in pre-tax income of $205.4 million.

The failure of our customers to honor or renew contracts could adversely affect our business.

        A significant portion of the sales of our coal, coke and natural gas are to long-term customers. The success of our businesses depends on our ability to retain our current customers, renew our existing customer contracts and solicit new customers. Our ability to do so generally depends on a

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variety of factors, including the quality and price of our products, our ability to market these products effectively, our ability to deliver on a timely basis and the level of competition we face. If current customers do not honor current contract commitments, terminate agreements or exercise force majeure provisions allowing for the temporary suspension of performance, our revenues will be adversely affected. If we are unsuccessful in renewing contracts with our long-term customers and they discontinue purchasing coal, coke or natural gas from us, renew contracts on terms less favorable than in the past, or if we are unable to sell our coal, coke or natural gas to new customers on terms as favorable to us, our revenues could suffer significantly.

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

        Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer's coal sales contract. If this occurs, we may decide to sell the customer's coal on the spot market, which may be at prices lower than the contracted price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could materially and adversely affect our financial position. In addition, competition with other coal suppliers could cause us to extend credit to customers and on terms that could increase the risk of payment default.

Coal mining is subject to inherent risks and is dependent upon many factors and conditions beyond our control, which may cause our profitability and our financial position to decline.

        Coal mining is subject to inherent risks and is dependent upon a number of conditions beyond our control that can affect our costs and production schedules at particular mines. These risks and conditions include, but are not limited to:

•

variations in geological conditions, such as the thickness of the coal seam and amount of rock embedded in the coal deposit and variations in rock and other natural materials overlying the coal deposit;

•

mining, process and equipment or mechanical failures and unexpected maintenance problems;

•

adverse weather and natural disasters, such as heavy rains or snow, flooding and other natural events affecting the operations, transportation or customers;

•

environmental hazards, such as subsidence and excess water ingress;

•

delays and difficulties in acquiring, maintaining or renewing necessary permits or mining rights;

•

unexpected mine accidents, including rock-falls and explosions caused by the ignition of coal dust, natural gas or other explosive sources at our mine sites or fires caused by the spontaneous combustion of coal or similar mining accidents; and

•

competition and/or conflicts with other natural resource extraction activities and production within our operating areas, such as coalbed methane extraction or oil and gas development.

        These risks and conditions could result in damage to or the destruction of mineral properties or production facilities, personal injury or death, environmental damage, delays in mining, monetary losses and legal liability. For example, an explosion and fire occurred in our underground No. 5 mine in Alabama in September 2001. This accident resulted in the deaths of thirteen employees and caused extensive damage to the mine. Our insurance coverage may not be available or sufficient to fully cover claims which may arise from these risks and conditions.

        We have also experienced adverse geological conditions in our mines, such as variations in coal seam thickness, variations in the competency and make-up of the roof strata, fault-related

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discontinuities in the coal seam and the potential for ingress of excessive amounts of methane gas or water. We do not have meaningful excess capacity for current production needs, and we are not able to quickly increase production at one mine to offset an interruption in production at another mine. Such adverse conditions may increase our cost of sales and reduce our profitability, and may cause us to decide to close a mine. Any of these risks or conditions could have a negative impact on our profitability, the cash available from our operations and our financial position.

Defects in title of any real property or leasehold interests in our properties could limit our ability to mine or develop these properties or result in significant unanticipated costs.

        Our right to mine some of our reserves and extract natural gas may be materially adversely affected by defects in title or boundaries. We may not verify title to our leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. Any challenge to our title could delay the development of the property and could ultimately result in the loss of some or all of our interest in the property and could increase our costs. In addition, if we mine or conduct our natural gas operations on property that we do not own or lease, we could incur liability for such mining and gas operations. Some leases have minimum production requirements or require us to commence mining or gas operations in a specified term to retain the lease. Failure to meet those requirements could result in losses of prepaid royalties and, in some rare cases, could result in a loss of the lease itself.

Currently we have significant mining operations located predominately in central Alabama and northeast British Columbia, making us vulnerable to risks associated with having our production concentrated in two geographic areas.

        Our mining operations are geographically concentrated in central Alabama and Northeast British Columbia. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production caused by significant governmental regulation, transportation capacity constraints, curtailment of production, extreme weather conditions, natural disasters or interruption of transportation or other events which impact this area.

A significant reduction of, or loss of, purchases by our largest customers could adversely affect our profitability.

        For the year ended December 31, 2011, we derived approximately 29% of our total sales revenues from sales to our 5 largest customers. We expect to renew, extend or enter into new supply agreements with these and other customers. However, we may be unsuccessful in obtaining such agreements with these customers and these customers may discontinue purchasing coal from us. If any of our major customers were to significantly reduce the quantities of coal they purchase from us and we are unable to replace these customers with new customers, or if we are unable to sell coal to those customers or on terms favorable to us, our profitability could suffer significantly.

If transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal could suffer.

        Transportation costs can represent a significant portion of the total cost of coal to be delivered to the customer and, as a result, overall price increases in our transportation costs could make our coal less competitive with the same or alternative products from competitors with lower transportation costs. We typically depend upon overland conveyor, trucks, rail or barge to deliver our products. Disruption of any of these transportation services because of weather-related problems, which are variable and unpredictable; strikes, lock-outs; transportation delays or other events could temporarily impair our ability to supply our products to our customers, thereby resulting in lost sales and reduced profitability.

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All of our U.S. metallurgical mines are served by only one rail carrier, which increases our vulnerability to these risks, although our access to barge transportation partially mitigates that risk. In addition, the majority of the metallurgical coal produced by our Alabama underground mining operations is sold to coal customers who typically arrange and pay for transportation through the state-run docks at the Port of Mobile, Alabama to the point of use. As a result, disruption at the docks, port congestion and delayed coal shipments may result in demurrage fees to us. If this disruption were to persist over an extended period of time, demurrage costs could significantly impact profits. Substantially all of the Company's coal produced by its Canadian operations is exported to port facilities by one railway for which there are limited alternatives. Additionally, all of the Company's Canadian export sales are loaded through one port facility, for which there are limited cost-effective alternatives. The cost of securing additional facilities and services of this nature could significantly increase transportation and other costs. An interruption of rail or port services could significantly limit the Company's ability to operate and to the extent that alternate sources of transportation of port and rail services are available, it could increase transportation and port costs significantly. Further, the inconsistent nature of the shipping industry could affect the Company's revenues as a result of delays of ocean vessels and could significantly affect the Company's costs and relative competitiveness against the supply of coal from other markets.

Significant competition and foreign currency fluctuations could harm our sales, profitability and cash flows.

        The consolidation of the U.S. and global coal industry over the last several years has contributed to increased competition among coal producers. Some of our competitors have significantly greater financial resources than we do. This competition may affect domestic and foreign coal prices and impact our ability to retain or attract coal customers. In addition, our metallurgical coal business faces competition from foreign producers that sell their coal in the export market. The general economic conditions in foreign markets and changes in currency exchange rates are factors outside of our control that may affect international coal prices. If our competitors' currencies decline against our local currency or against our customers' currencies, those competitors may be able to offer lower prices to our customers. Furthermore, if the currencies of our overseas customers were to significantly decline in value in comparison to our local currency, those customers may seek decreased prices for the coal we sell to them. In addition, these factors may negatively impact our collection of trade receivables from our customers. These factors could reduce our profitability or result in lower coal sales.

        Expenses from our Canadian operations are typically incurred and paid in Canadian dollars and our United Kingdom operations revenues and expenses are incurred and paid in British pounds. We have elected not to adopt a formal foreign currency hedging strategy and as a result any significant fluctuation in foreign exchange rates could adversely affect our financial position and operating results.

Our businesses are subject to risk of cost increases and fluctuations and delay in the delivery of raw materials, mining equipment and purchased components.

        Our businesses require significant amounts of raw materials, mining equipment and labor and, therefore, shortages or increased costs of raw materials, mining equipment and labor could adversely affect our business or results of operations. Our coal mining operations rely on the availability of steel, petroleum products and other raw materials for use in various mining equipment. The availability and market prices of these materials are influenced by various factors that are beyond our control. Over the last year petroleum prices have fluctuated significantly and pricing for steel scrap has fluctuated markedly. Any inability to secure a reliable supply of these materials or shortages in raw materials used in the operation and manufacturing of mining equipment or replacement parts could negatively impact our operating results.

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Work stoppages, labor shortages and other labor relations matters may harm our business.

        The majority of our employees in our underground mining and coking operations in Alabama are unionized and we have a risk of work stoppages as the result of strike or lockout. The majority of employees of our underground mining operations in Alabama are members of United Mine Workers of America ("UMWA"). Normally, our negotiations with the UMWA follow the national contract negotiated with the UMWA by the Bituminous Coal Operators Association. The collective bargaining agreement expires December 31, 2016. At our coking operation, our contract with the United Steelworkers of America expires December 6, 2015. We experienced a strike at our coke facilities at the end of 2001 that lasted eight months. Future work stoppages, labor union issues or labor disruptions at our key customers or service providers could impede our ability to produce and deliver our products, to receive critical equipment and supplies or to collect payment. This may increase our costs or impede our ability to operate one or more of our operations.

We require a skilled workforce to run our business. If we cannot hire qualified people to meet replacement or expansion needs, we may not be able to achieve planned results.

        The demand for coal in recent years has caused a significant constriction of the labor supply resulting in higher labor costs. Efficient coal mining using modern techniques and equipment requires skilled laborers with mining experience and proficiency as well as qualified managers and supervisors. As coal producers compete for skilled miners, employee turnover rates have increased which negatively affects operating costs. If the shortage of skilled workers continues and we are unable to train and retain the necessary number of miners, it could adversely affect our productivity, costs and ability to expand production.

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

        The Surface Mining Control and Reclamation Act and counterpart state laws and regulations in the United States and theMines Act (British Columbia) and the Reclamation Code for Mines in British Columbia in Canada have established operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. We accrue for the costs of final mine closure. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our experience. The amounts recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected. At December 31, 2011, we have accrued $75.1 million for our asset retirement obligations.

Factors impacting our forecasts of future performance, reserve estimates and a decline in pricing could affect our revenues.

        Forecasts of our future performance are based on estimates of our recoverable coal reserves. Reserve estimates are based on a number of sources of information, including engineering, geological, mining and property control maps, our operational experience of historical production from similar areas with similar conditions and assumptions governing future pricing and operational costs. Reserve estimates will change periodically to reflect mining activities, the acquisition or divestiture of reserve holdings and modifications of mining plans. Certain factors beyond our control could affect the accuracy of these estimates, including unexpected mining conditions, future coal prices, operating and development costs and federal, state, provincial and local regulations affecting mining operations.

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

        Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. We base our estimates of reserves on engineering, economic and geological data assembled, analyzed and reviewed by internal and third-party engineers and consultants. We update our estimates of the quantity and quality of proven and probable coal reserves at least annually to reflect the production of coal from the reserves, updated geological models and mining recovery data, the tonnage contained in new lease areas acquired and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including the following:

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quality of the coal;

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geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;

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the percentage of coal ultimately recoverable;

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the assumed effects of regulation, including the issuance of required permits, taxes, including severage and excise taxes and royalties, and other payments to governmental agencies;

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assumptions concerning the timing of the development of the reserves; and

•

assumptions concerning the equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.

        As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary materially due to changes in the above factors and assumptions. Actual production recovered from identified reserve areas and properties, and revenues and expenditures associated with our mining operations, may vary materially from estimates. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues and/or higher than expected costs.

Canadian licenses, permits and other authorizations may be subject to challenges based on Aboriginal or Treaty rights

        Canadian judicial decisions have recognized the continued existence of Aboriginal and Treaty rights in Canada, including title to lands continuously used or occupied by Aboriginal groups. Our Northeast British Columbia operations are located within Treaty 8 territory, to which nine First Nations in British Columbia are signatories. Current operations are in or near the traditional territories of the West Moberly, Saulteau and Halfway River First Nations, and the McLeod Lake Indian Band. The Province of British Columbia has signed an Economic Benefits Agreement and related land and resource use agreements with several of the First Nations, including the West Moberly First Nation, over the last few years. The Treaty 8, as well as the Economic Benefits Agreement and related agreements, establish First Nations rights and define roles for their involvement in land and resource use. As a means of protecting Treaty and Aboriginal rights, as well as undetermined aboriginal rights, Canadian courts continue to confirm a duty to consult with Aboriginal groups when the Crown has knowledge of existing rights or the potential existence of an Aboriginal right, such as title or hunting rights, and contemplates conduct that might adversely impact First Nations. As issues relating to Aboriginal and Treaty rights and consultation continue to be heard, developed and resolved in Canadian courts, we will

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continue to cooperate, communicate and exchange information and views with Aboriginal groups and government, and participate with the Crown in its consultation processes with Aboriginal groups in order to foster good relationships and minimize risks to its mineral rights and operational plans. Due to their complexity, it is not expected that the issues regarding Aboriginal and Treaty rights or consultation will be finally resolved in the short term and, accordingly, the impact of these issues on mineral resources and on our mining operations is unknown at this time. We believe in building mutually beneficial and lasting relationships with local First Nations whose Treaty rights or potential Aboriginal rights overlap with our areas of operations. We are in the process of formalizing our relationships with local First Nations through agreements that generally seek to increase First Nations' participation in our planning and operational activities. Should a dispute arise between the First Nations and the Crown, it could significantly restrict the Company's ability to operate and transport coal within the region. Also, such action could have a detrimental impact on our financial condition and results of operations as well as our customers.

Failure to meet our project development and expansion targets could have a material adverse effect on our business

        There can be no assurance that we will be able to manage effectively the expansion of our operations or that our current personnel, systems, procedures and controls will be adequate to support our operations. Any failure of management to effectively manage our growth and development could have a material adverse effect on our business, financial condition and results of operations.

        Our operational targets are subject to the completion of planned operational goals on time and within budget, and are dependent on the effective support of our personnel, systems, procedures and controls. Any failure of these may result in delays in the achievement of operational targets with a consequent material adverse impact on our business, operations and financial performance.

Our operations in foreign jurisdictions are subject to risks and uncertainties which may have a negative impact on our profitability

        We operate in a number of foreign countries where there are added risks and uncertainties due to the different economic, cultural and political environments. We face risks in securing additional property licenses, as the process for obtaining these is likely to be different from that in the jurisdictions in which we have operated historically, which could result in failed attempts to obtain licenses which would have used up management time and financial resources. We also face risks from trade barriers, exchange controls and material changes in taxation which could negatively impact our ability to sell into foreign markets, as well as our profitability.

Extensive environmental, health and safety laws and regulations impose significant costs on our operations and future regulations could increase those costs, limit our ability to produce or adversely affect the demand for our products.

        Our businesses are subject to numerous federal, state, provincial and local laws and regulations with respect to matters such as:

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permitting and licensing requirements;

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employee health and safety, including:

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occupational safety and health;

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mine health and safety;

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workers' compensation;

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black lung;

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•

reclamation and restoration of property;

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environmental laws and regulations, including:

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greenhouse gases and climate change;

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air quality standards;

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water quality standards;

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management of materials generated by mining and coking operations;

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the storage, treatment and disposal of wastes;

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remediation of contaminated soil and groundwater; and

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protection of human health, plant-life and wildlife, including endangered species, and emergency planning and community right to know.

        Compliance with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production at our operations. These laws are constantly evolving and becoming increasingly stringent. The ultimate impact of complying with existing laws and regulations is not always clearly known or determinable due in part to the fact that certain implementing regulations for these laws have not yet been promulgated and in certain instances are undergoing revision. These laws and regulations, particularly new legislative or administrative proposals (or judicial interpretations of existing laws and regulations) could result in substantially increased capital, operating and compliance costs and could have a material adverse effect on our operations and/or our customers' ability to use our products. In addition, the industry in the United States is affected by significant legislation mandating certain benefits for current and retired coal miners.

        We strive to conduct our mining, natural gas and coke operations in compliance with all applicable federal, provincial, state and local laws and regulations. However, due in part to the extensive and comprehensive regulatory requirements, along with changing interpretations of these requirements, violations occur from time to time in our industry and at our operations. In recent years, expenditures at our U.S. operations for regulatory or environmental obligations have been mainly for safety or process changes. Although it is not possible at this time to predict the final outcome of these rule-making and standard-setting efforts, it is likely that the magnitude of these changes will require an unprecedented compliance effort on our part, could divert management's attention, and may require significant expenditures. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, operating results will be reduced. We believe that our major North American competitors are confronted by substantially similar conditions and thus do not believe that our relative position with regard to such competitors is materially affected by the impact of environmental laws and regulations. However, the costs and operating restrictions necessary for compliance with environmental laws and regulations, which is a major cost consideration for our Canadian operations in particular, may have an adverse effect on our competitive position with regard to foreign producers and operators who may not be required to undertake equivalent costs in their operations. In addition, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, applicable state or provincial legislation and its production methods.

Federal, state or provincial regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances, which could materially and adversely affect our ability to meet our customers' demands.

        Federal, state or provincial regulatory agencies have the authority under certain circumstances following significant health and safety incidents, such as fatalities, to order a mine to be temporarily or

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permanently closed. If this occurred, we may be required to incur capital expenditures to re-open the mine. In the event that these agencies order the closing of our mines, our coal sales contracts generally permit us to issueforce majeure notices which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances offorce majeure notices. If these challenges are successful, we may have to purchase coal from third-party sources, if it is available, to fulfill these obligations, incur capital expenditures to re-open the mines and/or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery or terminate customers' contracts. Any of these actions could have a material adverse effect on our business and results of operations.

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

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

        Section 404 of the Clean Water Act requires mining companies to obtain U.S. Army Corps of Engineers permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. As is the case with other coal mining companies operating in Appalachia, our construction and mining activities, including certain of our surface mining operations, frequently require Section 404 permits. The issuance of permits to construct valley fills and refuse impoundments under Section 404 of the Clean Water Act has been the subject of many court cases and increased regulatory oversight, resulting in additional permitting requirements that are expected to delay or even prevent the opening of new mines.

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

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

        It is unknown what future changes will be implemented to the permitting review and issuance process or to other aspects of surface mining operations, but the increased regulatory focus, future laws and judicial decisions and any other future changes could materially and adversely affect all coal mining companies operating in Appalachia, including us.

        Regulatory agencies in Canada are also increasingly focused on the effects of surface coal mining on the environment, particularly as it relates to water quality and to wildlife habitat. The British Columbia Ministry of Environment is updating its existing selenium guidelines which could affect water quality issues and effluent discharge standards. Expansion of existing coal mines and development of new coal mines in northeast British Columbia have also been the focus of consideration with respect to the impacts on caribou habitat, particularly in areas where caribou has been identified as a threatened species under the federalSpecies at Risk Act. It is unknown what future changes will be implemented to

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the permitting review and issuance process or to other aspects of surface mining operations in British Columbia, 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 British Columbia, including us.

        In particular, in each jurisdiction in which we operate, we will incur additional permitting and operating costs, could be unable to obtain new permits or maintain existing permits and could incur fines, penalties and other costs, any of which could materially adversely affect our business. If surface coal mining methods are limited or prohibited, it could significantly increase our operational costs and make it more difficult to economically recover a significant portion of our reserves. In the event that we cannot increase the price we charge for coal to cover the higher production costs without reducing customer demand for our coal, there could be a material adverse effect on our financial condition and results of operations. In addition, increased public focus on the environmental, health and aesthetic impacts of surface coal mining could harm our reputation and reduce demand for coal.

Climate change concerns could negatively affect our results of operations and cash flows.

        The combustion of fossil fuels, such as the coal, coke and natural gas we produce, results in the creation of carbon dioxide that is currently emitted into the atmosphere by coal, coke and gas end-users. Further, some of our operations emit GHGs directly, such as methane incident to coal mining and carbon dioxide during our coke production. Carbon dioxide is considered a greenhouse gas and is a major source of concern with respect to global warming, also known as climate change. Climate change continues to attract public and scientific attention, and increasing government attention is being paid to reducing GHG emissions.

        There are many legal and regulatory approaches currently in effect or being considered to address GHGs, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a "cap and trade" program, and regulation by the U.S. Environmental Protection Agency.

        Canadian legal and regulatory approaches include both federal and provincial regulations requiring the reporting of GHG emissions. At both the federal and provincial level, governments are considering the implementation of GHG regulatory structures such as a "cap and trade" program, and emissions trading. These programs could force reductions in total GHG emissions on an industry or on a facility basis. In British Columbia, the government charges a carbon emissions tax with scheduled increases.

        These existing laws and regulations or other current and future efforts to stabilize or reduce GHG emissions, could adversely impact the demand for, price of and the value of our products and reserves. Passage of additional state, provincial, federal or foreign laws or regulations regarding GHG emissions or other actions to limit GHG emissions could result in switching from coal to other fuel sources. The anticipation of such additional requirements could also lead to reduced demand for some of our products. Alternative fuels (including non-fossil fuels) could become more attractive than coal in order to reduce GHG emissions, which could result in a reduction in the demand for coal and, therefore, our revenues. As our operations also emit GHGs directly, current or future laws or regulations limiting GHG emissions could increase our own costs. Although the potential impacts on us of additional climate change regulation are difficult to reliably quantify, they could be material.

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.

        Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. We could become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own or

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operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be 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 extensive coal refuse areas and slurry impoundments at a number of our mining complexes. Such areas and impoundments are subject to extensive regulation. Slurry impoundments have been known to fail, releasing large volumes of coal slurry into the surrounding environment. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, 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.

        Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as "acid mine drainage," which we refer to as AMD. The treating of AMD can be costly. Although we do not currently face material costs associated with AMD, it is possible that we could incur significant costs in the future.

        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 materially and adversely affect us.

        See also "Environmental and Other Regulatory Matters" in Part I of this Annual Report.

Other Business Risks

Our substantial debt could adversely affect our financial condition, and our related debt service obligations may adversely affect our cash flow and ability to invest in and grow our businesses.

        We have approximately $2.2 billion of indebtedness outstanding under a new $2.7 billion credit agreement ("Credit Agreement"). Under the repayment schedule relating to the Credit Agreement we will be required to make principal payments totaling at least $19.8 million in 2012 and at least $82.5 million in 2013. In addition, we will be required to pay a percentage of excess cash flow, as defined in the Credit Agreement, to reduce the principal balance of the indebtedness. If we are unable to satisfy our indebtedness obligations, we will be unable to continue our operations, including our planned development and growth initiatives.

Access to capital, financing availability and our debt instruments may limit our ability to engage in certain transactions.

        Our business requires continued capital investment for, among other purposes, managing acquired assets, acquiring new equipment, maintaining the condition of our existing equipment and maintaining compliance with environmental and safety laws and regulations. To the extent that cash generated internally and cash available under our credit facilities are not sufficient to fund capital requirements, we will require additional debt and/or equity financing. However, this type of financing may not be available, or if available, may not be on satisfactory terms. Future debt financings, if available, may result in increased interest expense, increased financial leverage and decreased income available to fund further acquisitions and expansion. In addition, future debt financings may limit our ability to withstand competitive pressures and render us more vulnerable to economic downturns. If we fail to generate sufficient earnings or to obtain sufficient additional capital in the future or fail to manage our capital investments effectively, we could be forced to reduce or delay capital expenditures, sell assets or restructure or refinance our indebtedness.

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        In addition, our Credit Agreement contains customary affirmative and negative covenants for credit facilities of this type, including, but not limited to, limitations on the incurrence of indebtedness, asset dispositions, acquisitions, investments, dividends and other restricted payments, liens and transactions with affiliates. The Credit Agreement requires us to meet certain financial tests, including a maximum leverage ratio and a minimum fixed charge coverage ratio. Our ability to satisfy the financial ratios, tests or covenants related to our existing or future indebtedness can be affected by events beyond our control, and there is a risk that we will not meet those tests. A breach of any such covenants could result in a default under our credit facilities or under any other debt instrument that we may enter into in the future. If an event of default were not remedied after the delivery of notice of default and lapse of any relevant grace period, the holders of our debt could declare it immediately due and payable.

Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.

        Federal, state and provincial laws require us to obtain surety bonds or post other financial security to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers' compensation costs, coal leases and other obligations. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, or failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third party surety bond issuers of their right to refuse to renew the surety and restrictions on availability on collateral for current and future third party surety bond issuers under the terms of our financing arrangements.

Our expenditures for postretirement benefit and pension obligations are significant and could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.

        We provide a range of benefits to our employees and retirees, including pensions and postretirement healthcare. We record annual amounts relating to these plans based on calculations specified by generally accepted accounting principles, which include various actuarial assumptions. As of December 31, 2011, we estimate that our pension plans' aggregate accumulated benefit obligation had a present value of approximately $246.0 million, and our fair value of plan assets was approximately $202.5 million. As of December 31, 2011, we estimate that our postretirement health care and life insurance plans' aggregate accumulated benefit obligation would have had a present value of approximately $577.9 million, and such benefits are not required to be funded. In respect of the funding obligations for our pension plans, we must make minimum cash contributions on a quarterly basis. The weakening of the economic environment and uncertainty in the equity markets have caused investment income and the values of investment assets held in our pension trust to decline in the past and lose value. As a result, we may be required to increase the amount of cash contributions we make into the pension trust in the future in order to meet the funding level requirements of the Pension Protection Act of 2006 (Pension Act). Our estimated minimum funding obligation relating to these plans in 2012 is $55.3 million. We have estimated these obligations based on assumptions described under the heading "Critical Accounting Estimates—Employee Benefits" in "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition," and in the notes to our consolidated financial statements. Assumed health care cost trend rates, discount rates, expected return on plan assets and salary increases have a significant effect on the amounts reported for the pension and health care plans. If our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially higher. Moreover, regulatory changes could increase our obligations to provide these or additional benefits.

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

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

        In addition, certain of our subsidiaries participate in multiemployer pension and healthcare plan trusts established for union employees. 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.

        We have no current intention to withdraw from any multiemployer pension plan, but if we were to do so, under the Employee Retirement Income Security Act of 1974, as amended ("ERISA"), we would be liable for a proportionate share of the plan's unfunded vested benefit liabilities upon our withdrawal. Through June 30, 2012, our estimated withdrawal liability for the multiemployer pension plans amounts to $484.4 million.

Changes in our credit ratings could adversely affect our costs and expenses.

        Any downgrade in our credit ratings could adversely affect our ability to borrow and result in more restrictive borrowing terms, including increased borrowing costs and more restrictive covenants. This, in turn, could affect our internal cost of capital estimates and therefore impact operational and investment decisions.

We self-insure workers' compensation and certain medical and disability benefits, and greater than expected claims could reduce our profitability.

        We are self-insured for workers' compensation benefits for work-related injuries. Workers' compensation liabilities, including those related to claims incurred but not reported, are recorded principally using annual valuations based on discounted future expected payments using historical data of the division or combined insurance industry data when historical data is limited. In addition, certain of our subsidiaries are responsible for medical and disability benefits for black lung disease under the Federal Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act of 1977, as amended, and is self-insured against black lung related claims. We perform periodic evaluations of our black lung liability, using assumptions regarding rates of successful claims, discount factors, benefit increases and mortality rates, among others. See additional information under the

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heading "Critical Accounting Estimates—Employee Benefits" in "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition."

        If the number or severity of claims for which we are self insured increases, or we are required to accrue or pay additional amounts because the claims prove to be more severe than our original assessment, our operating results could be reduced.

We may be subject to litigation, the disposition of which could negatively affect our profitability and cash flow in a particular period.

        Our profitability or cash flow in a particular period could be affected by an adverse ruling in any litigation currently pending in the courts or by litigation that may be filed against us in the future. For information regarding our current significant legal proceedings, see "Item 3. Legal Proceedings", "Note 9-Income Taxes" and "Note 14- Commitments and Contingencies."

Our executive officers and other key personnel are important to our success and the loss of some of these individuals could harm our business.

        Our executive officers and other key personnel have significant experience in the businesses in which we operate and the loss of certain of these individuals could harm our business. Although we have been successful in attracting qualified individuals for key management and corporate positions in the past, as our business develops and expands, there can be no assurance that we will continue to be successful in attracting and retaining a sufficient number of qualified personnel in the future. The loss of the services of management personnel could harm our ability to successfully manage our business functions, prevent us from executing our business strategy and have an adverse effect on our results of operations and cash flows.

We may be unsuccessful in identifying or integrating suitable acquisitions, which could impair our growth.

        Our ability to grow depends upon our ability to identify, negotiate, complete and integrate suitable acquisitions. This strategy depends on the availability of acquisition candidates with businesses that can be successfully integrated into our existing business and that will provide us with complementary capabilities, products or services. There are many challenges to integrating acquired companies and businesses, including eliminating redundant operations, facilities and systems, coordinating management and personnel, retaining key employees, managing different corporate cultures and achieving cost reductions and cross-selling opportunities. It is possible that we will be unable to successfully complete potential acquisitions which could impair our growth.

The price of our common stock may be volatile and may be affected by market conditions beyond our control.

        Our share price is likely to fluctuate in the future because of the volatility of the stock market in general and a variety of factors, many of which are beyond our control, including:

•

general global economic conditions that impact infrastructure activity, including interest rate and currency movements;

•

quarterly variations in actual or anticipated results of our operations;

•

speculation in the press or investment community;

•

changes in financial estimates by securities analysts;

•

actions or announcements by our competitors;

•

actions by our principal stockholders;

•

trading volumes of our common stock;

40

•

regulatory actions;

•

litigation;

•

U.S. and international economic, legal and regulatory factors unrelated to our performance;

•

loss or gain of a major customer;

•

additions or departures of key personnel; and

•

future issuances of our common stock.

        Market fluctuations could result in extreme volatility in the price of shares of our common stock, which could cause a decline in the value of our stock. Price volatility may be greater if the public float and trading volume of shares of our common stock is low. In addition, if our operating results and net income fail to meet the expectations of stock analysts and investors, we may experience an immediate and significant decline in the trading price of our stock.

Our ability to pay regular dividends to our stockholders is subject to the discretion of our Board of Directors and may be limited by our holding company structure, the covenants in our debt instruments and applicable provisions of Delaware law.

        Our Board of Directors may, in its discretion, decrease the level of dividends or discontinue the payment of dividends entirely. In addition, as a holding company, we will be dependent upon the ability of our subsidiaries to generate earnings and cash flows and distribute them to us so that we may pay our obligations and expenses and pay dividends to our stockholders. Our ability to pay future dividends and the ability of our subsidiaries to make distributions to us will be subject to our and their respective operating results, cash requirements and financial condition, the applicable laws of the State of Delaware (which may limit the amount of funds available for distribution), compliance with covenants and financial ratios related to existing or future indebtedness and other agreements with third parties. If, as a consequence of these various limitations and restrictions, we are unable to generate sufficient distributions from our business, we may not be able to make, or may have to reduce or eliminate, the payment of dividends on our shares.

Our stockholder rights agreement, designed to increase benefit to our shareholders, could also discourage or prevent potential acquisition proposals and could deter a change of control.

        On February 27, 2009, our Board of Directors authorized and declared a dividend of one preferred stock purchase right (a "Right") for each share of common stock to stockholders of record as of the close of business on April 23, 2009. Our shareholders approved this action and we entered into a rights agreement on April 24, 2009. Initially the Right is not exercisable and will trade with our common stock. The Right may be exercisable under certain circumstances, including a person or group acquiring, or the commencement of a tender or exchange offer that would result in a person or group acquiring, beneficial ownership of more than 20% of the outstanding shares of common stock. Upon exercise of the Right, each Right holder, other than the person or group triggering the plan, will have the right to purchase from us 1/1000^th of a share of junior preferred stock (subject to adjustment) or, at our option, shares of common stock having a value equal to two times the exercise price of the Right. Each fractional share of the junior preferred stock has terms designed to make it substantially the economic equivalent of one share of common stock. This rights agreement expires on April 23, 2012. Our rights agreement is designed to, among other things, deter the use of coercive or abusive takeover tactics by one or more parties interested in acquiring the Company or a significant position in the Company's common stock without offering fair value to all stockholders, as well as to generally assist the Board in representing the interests of all stockholders in connection with any takeover proposals. The rights agreement would accomplish these objectives by encouraging a potential acquirer to negotiate with the Board to have the Rights redeemed or the rights agreement amended prior to such

41

party exceeding the ownership thresholds set forth in the rights agreement. If the Rights are not redeemed (or the rights agreement is not amended to permit the particular acquisition) and such party exceeds the ownership thresholds, the Rights become exercisable at a discounted price resulting in both a dilution of the party's holding in the Company and making an acquisition thereof significantly more expensive by significantly increasing the number of shares that would have to be acquired to effect a takeover. Our rights agreement, though designed to benefit current shareholders by allowing more time for thoughtful consideration of the offer and encouraging officers to suggest a higher price for the Company's shares, may also discourage third parties from attempting to purchase our Company or a significant position in our common stock, which may adversely affect the price of our common stock.

We may be required to satisfy certain indemnification obligations to Mueller Water or may not be able to collect on indemnification rights from Mueller Water.

        In connection with the spin-off of Mueller Water Products, Inc. ("Mueller Water") on December 14, 2006, we entered into certain agreements with Mueller Water, including an income tax allocation agreement and a joint litigation agreement. Under the terms of those agreements, we and Mueller Water agreed to indemnify each other with respect to the indebtedness, liabilities and obligations that will be retained by our respective companies, including certain tax and litigation liabilities. These indemnification obligations could be significant. For example, to the extent that we or Mueller Water take any action that would be inconsistent with the treatment of the spin-off of Mueller Water as a tax-free transaction under Section 355 of the Internal Revenue Code, then any tax resulting from such actions is attributable to the acting company. The ability to satisfy these indemnities if called upon to do so will depend upon the future financial strength of each of our companies. We cannot determine whether we will have to indemnify Mueller Water for any substantial obligations after the distribution. If Mueller Water has to indemnify us for any substantial obligations, Mueller Water may not have the ability to satisfy those obligations. If Mueller Water is unable to satisfy its obligations under its indemnity to us, we may have to satisfy those obligations.

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

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

Item 1B.    Unresolved Staff Comments

        None

42

Item 2.    Properties

        The administrative headquarters and production facilities of the Company and its subsidiaries as of December 31, 2011 are summarized as follows:

					Building Square Footage
			Land Acreage(4)
Reportable Segment	Business Unit /Location	Principal Operations			Leased		Owned
U.S. Operations	Alabama Operations:
	Blue Creek Coal Sales
	Mobile, AL	River terminal—Owned		49
	Jim Walter Resources
	Brookwood, AL	Administrative headquarters & mine support facilities						173,100
	Brookwood, AL	Coal mines, land holdings and coal bed methane fields—Owned		17,323				49,623
	Brookwood, AL	Coal mines, land holdings and coal bed methane fields—Leased		48,615
	Walter Black Warrior Basin
	Tuscaloosa County, AL	Coal bed methane fields—Leased, developed		366,568
	Walter Minerals
	Tuscaloosa County, AL	Mine support facilities—Barge load out		40		140
	Various Counties in AL	Real estate—Owned		31,080
	Various Counties in AL	Real estate—Owned, mineral interest only		165,293
	Tuscaloosa Resources
	Tuscaloosa County, AL	Administrative headquarters & mine support facilities				664		5,600
	Tuscaloosa County, AL	Coal mines and land holdings—Leased		1,132
	Tuscaloosa County, AL	Real estate—Owned		693
	Pickens County, AL	Real estate—Owned		81
	Taft
	Walker County, AL	Administrative headquarters & mine support facilities				3,680		11,075
	Walker County, AL	Coal mines and land holdings—Owned		1,490
	Walker County, AL	Coal mines and land holdings—Leased		1,820
	Blount County, AL	Mine support facilities				1,200
	Blount County, AL	Coal mines and land holdings—Leased		820
	Walter Coke
	Birmingham, AL	Administrative headquarters						12,000
	Birmingham, AL	Furnace & foundry coke battery—Owned		411				200,400
U.S. Operations	West Virginia Operations
	Atlantic Leaseco
	Nicholas County, WV	Administrative headquarters				6,038
	Nicholas County, WV	Coal mines and land holdings—Owned		2,296		50,083
	Nicholas County, WV	Coal mines and land holdings—Leased		19,207
	Maple Coal
	Fayette & Kanawha         Counties, WV	Coal mines and land holdings—Owned		5				43,500
	Fayette & Kanawha         Counties, WV	Coal mines and land holdings—Leased		21,960

43

					Building Square Footage
			Land Acreage(4)
Reportable Segment	Business Unit /Location	Principal Operations			Leased		Owned
Canadian and U.K. Operations	Canadian Operations
	Walter Energy Canada Holdings, Inc.
	Northeast, B.C.	Administrative headquarters				2,780
	Northeast, B.C.	Coal mines and land holdings—Leased		108,919
Canadian and U.K. Operations	U.K. Operations
	Energybuild
	South Wales, U.K	Administrative headquarters & mine support facilities				37,685		39,292
	South Wales, U.K	Coal mines and land holdings—Leased		5,953
	South Wales, U.K	Real estate—Leased		247
Other	Other
	Kodiak(1)
	Shelby County, AL	Administrative headquarters & mine support facilities						22,900
	Shelby County, AL	Coal mines and land holdings—Owned		70
	Birmingham, AL(2)	Executive headquarters				40,390
	Vancouver, B.C	Administrative headquarters				16,472
	Tampa, FL(2)	Administrative headquarters				31,574
	Tampa, FL(3)	Former Administrative headquarters for our Financing and Homebuilding businesses				46,500

(1)

Kodiak's mining operations ceased in December 2008. Facilities have been idled.

(2)

In January 2010, we signed a 10-year, non-cancellable lease agreement for 40,390 square feet of space at the Galleria Tower at Riverchase Galleria in Hoover, AL, a suburb of Birmingham, AL. The lease obligation related to the space at our executive offices in Tampa remains until April 2012.

(3)

In April 2009, we spun off our Financing business and, also in 2009, our Homebuilding business was closed. The lease obligation related to this space remains until April 2012.

(4)

Real estate and land holdings include mineral interests owned and leased.

44

        The following table provides the location of our recoverable reserves as of December 31, 2011:

ESTIMATED RECOVERABLE(1) COAL RESERVES
AS OF DECEMBER 31, 2011
(In Thousands of Metric Tons)

			Reserves						Classifications(3)				Our Interest
Location/Mine	Status of Operation	Coal Beds	Recoverable Reserves(1)		Assigned(2)		Unassigned(2)		Proven		Probable		Owned		Leased(4)		Reportable Acres
Alabama:
JWR's No. 4 Mine	Operational	Mary Lee and Blue Creek		69,854		69,854		—		67,425		2,429		1,013		68,841		17,802
JWR's No. 7 Mine	Operational	Mary Lee and Blue Creek		60,652		60,652		—		55,281		5,371		2,475		58,177		16,984
JWR's North River Mine	Operational	Pratt		4,634		4,634		—		4,240		394		719		3,915		816
Walter Energy's Blue Creek Energy No. 1	Pre-feasibility	Mary Lee and Blue Creek		81,908		—		81,908		78,574		3,334		—		81,908		20,406
TRI's Carter/Swann's Crossing Mine(5)	Operational	Guide 1 & 2, Lower Brookwood, Milldale, Carter		3,185		3,185		—		3,185		—		3,185		—		325
TRI's Panther 3 Mine	Idled	Carter, Johnson		262		262		—		262		—		262		—		161
Taft's Choctaw Mine(5)	Operational	Pratt, Nickle Plate, Top American, Bot. American & American No. 3		2,050		2,050		—		2,050		—		—		2,050		257
Taft's Reid School Mine(5)	Operational	Lick Creek Jefferson & Black Creek		478		478		—		478		—		—		478		127
Taft's Gayosa South Mine	Development	Pratt, Nickle Plate, Top American, Bot. American		353		353		—		353		—		—		353		70
Taft's Robbins Road Mine	Development	Pratt, Nickle Plate, Top American, Bot. American & American No. 3		1,434		1,434		—		1,434		—		—		1,434		217
Walter Minerals' Flat Top Mine	Ready for Operation	Pratt, Nickle Plate, Top American		2,073		2,073		—		2,073		—		2,073		—		356
Walter Minerals' Beltona East Mine	Development	Lick Creek Jefferson & Black Creek		1,013		1,013		—		1,013		—		1,013		—		184
Walter Minerals' Morris Mine	Development	Upper & Lower New Castle, Mary Lee, Blue Creek		1,801		1,801		—		525		1,276		1,801		—		249
Total Alabama				229,697		147,789		81,908		216,893		12,804		12,541		217,156		57,954
West Virginia:
Gauley Eagle Underground Mine	Idled	Allegheny, Kanawha, New River		7,107		7,107		—		6,272		835		—		7,107		2,393
Gauley Eagle Surface Mine(5)	Operational	Allegheny, Kanawha, New River		6,879		6,879		—		6,168		711		—		6,879		1,831
Maple Coal Eagle Underground Mine	Operational	Allegheny, Kanawha, New River		4,602		4,602		—		4,200		402		—		4,602		1,977
Maple Coal Peerless Underground Mine	Pre-feasibility	Allegheny, Kanawha, New River		6,406		—		6,406		4,769		1,637		—		6,406		2,168
Maple Surface Mine(5)	Operational	Allegheny, Kanawha, New River		13,796		9,116		4,680		12,803		993		—		13,796		3,413
Total West Virginia				38,790		27,704		11,086		34,212		4,578		—		38,790		11,782

45

			Reserves						Classifications(3)				Our Interest
Location/Mine	Status of Operation	Coal Beds	Recoverable Reserves(1)		Assigned(2)		Unassigned(2)		Proven		Probable		Owned		Leased(4)		Reportable Acres
Northeast B.C., Canada:
Wolverine's Perry Creek Mine(5)	Operational	Gates Formation		12,851		12,851		—		12,851		—		—		12,851		328
Wolverine's Mt. Spieker (EB) Area	Development	Gates Formation		9,856		—		9,856		9,856		—		—		9,856		216
Wolverine's Hermann Area	Pre-feasibility	Gates Formation		9,075		—		9,075		6,775		2,300		—		9,075		92
Brazion's Brule Mine(5)	Operational	Gething Formation		21,090		21,090		—		21,090		—		—		21,090		492
Brazion's Willow Creek Area(5)	Operational	Gething Formation		19,897		19,897		—		18,617		1,280		—		19,897		462
Belcourt Saxon Properties(6)	Pre-feasibility	Gates Formation		28,523		—		28,523		28,273		250		—		28,523		932
Total Canada				101,292		53,838		47,454		97,462		3,830		—		101,292		2,522
South Wales, U.K.:
Energybuild's Aberpergwm Mine	Development	Nine & Eighteen Feet		5,289		5,002		287		2,498		2,791		—		5,289		1,512
Total Walter Energy(7)				375,068		234,333		140,735		351,065		24,003		12,541		362,527		73,770

(1)

"Recoverable" reserves are defined as tons of mineable coal which can be extracted and marketed after deduction for coal to be left in pillars, etc. and adjusted for reasonable preparation and handling losses.

(2)

"Assigned" reserves represent coal which has been committed to mines, whether operating or in development. "Unassigned" reserves represent coal which is not committed to a mine. The division of reserves into these two categories is based upon current mining plans, projections and techniques.

(3)

The recoverable reserves (demonstrated reserves) are the sum of "Proven" and "Probable" reserves. Proven coal extends¹/4 mile from any point of observation or measurement. Probable coal is projected to extend from¹/4 mile to³/4 miles from any point of observation or measurement. See Glossary for definition of Proven and Probable reserves.

(4)

A majority of the leases are either renewable until the reserves are mined to exhaustion or are of sufficient duration to permit mining of all the reserves before the expiration of the term. Leases that expire before mining occurs have been removed from the reserve estimate.

(5)

These active mines are surface mines utilizing drills, excavators, dozers and rock trucks for coal removal. In addition, the Taft Choctaw Mine uses a 47 cubic yard dragline.

(6)

The Belcourt Saxon Properties are part of a joint venture partnership in which Walter Energy has a 50% ownership interest. The reserves reported represent 50% of the reserves held by the joint venture.

(7)

Additional properties that are currently not under lease are under review for possible leasing options.

Note: Also see Glossary for definitions of technical terms

46

        The following table provides the quality (average ash and sulfur content and Btus per pound) of our recoverable coal reserves as of December 31, 2011:

ESTIMATED RECOVERABLE COAL RESERVES (Continued)
AS OF DECEMBER 31, 2011
(In Thousands of Metric Tons)

						QUALITY
						(Wet Basis)
					Compliant(5)
	Status of Operation(2)(3)	Recoverable Reserves										Average Coal Seam (in Feet)
Location/Mine				Type	Y / N	% Ash		% Sulfur		BTU/lb.
Alabama(1):
JWR's No. 4 Mine	Operational		69,854	Thermal and/or Metallurgical	Yes		9.00		0.80		13,909		4.76
JWR's No. 7 Mine(4)	Operational		60,652	Thermal and/or Metallurgical	Yes		9.00		0.75		13,952		4.23
JWR's North River Mine	Operational		4,634	Thermal	No		13.00		2.07		13,711		3.87
Walter Energy's Blue Creek Energy No. 1	Pre-feasibility		81,908	Thermal and/or Metallurgical	Yes		9.00		0.69		13,791		4.70
TRI's Carter/Swann's Crossing Mine	Operational		3,185	Thermal and/or Metallurgical	No		12.02		1.26		12,497		9.41
TRI's Panther 3 Mine	Idled		262	Thermal	No		8.93		1.47		13,636		1.16
Taft's Choctaw Mine	Operational		2,050	Thermal and/or Metallurgical	No		12.36		1.87		12,927		6.16
Taft's Reid School Mine	Operational		478	Thermal and/or Metallurgical	Yes—Black Creek Only		2.92		0.89		15,041		3.15
Taft's Gayosa South Mine	Development		353	Thermal and/or Metallurgical	No		14.69		1.32		12,484		3.77
Taft's Robbins Road Mine	Development		1,434	Thermal and/or Metallurgical	No		11.09		1.87		12,927		5.24
Walter Minerals' Flat Top Mine	Ready for Operation		2,073	Thermal	No		10.89		2.13		13,590		5.37
Walter Minerals' Beltona East Mine	Development		1,013	Thermal and/or Metallurgical	Yes—Black Creek Only		7.79		2.58		14,162		4.32
Walter Minerals' Morris Mine	Development		1,801	Thermal	No		20.80		1.60		12,175		5.14
Total Alabama			229,697
West Virginia:
Gauley Eagle Underground Mine	Idled		7,107	Thermal and/or Metallurgical	Yes		7.45		1.04		12,944		3.80
Gauley Eagle Surface Mine	Operational		6,879	Thermal and/or Metallurgical	Yes		12.22		1.09		12,450		18.56
Maple Coal Eagle Underground Mine	Operational		4,602	Thermal and/or Metallurgical	Yes		6.21		0.87		13,643		4.14

47

						QUALITY
						(Wet Basis)
Location/Mine	Status of Operation(2)(3)	Recoverable Reserves		Type	Compliant(5)	% Ash		% Sulfur		BTU/lb.		Average Coal Seam (in Feet)
Maple Coal Peerless Underground Mine	Pre-feasibility		6,406	Thermal	No		5.24		2.31		N/A		3.59
Maple Coal Surface Mine	Operational		13,796	Thermal and/or Metallurgical	Yes		12.98		0.85		11,800		33.59
Total West Virginia			38,790
Northeast B.C., Canada:
Wolverine's Perry Creek Mine	Operational		12,851	Metallurgical	Yes		7.85		0.47		14,261		55.10
Wolverine's Mt. Spieker (EB) Area	Development		9,856	Metallurgical	Yes		8.72		0.49		14,116		43.30
Wolverine's Hermann Area	Pre-feasibility		9,075	Metallurgical	Yes		8.12		0.41		14,220		84.80
Brazion's Brule Mine	Operational		21,090	Metallurgical (PCI)	Yes		7.43		0.51		14,242		28.70
Brazion's Willow Creek Area	Operational		13,043	Metallurgical	Yes		8.00		0.60		14,775		32.50
Brazion's Willow Creek Area	Operational		6,854	Metallurgical (PCI)	Yes		7.00		0.57		14,303		52.50
Belcourt Saxon Properties	Pre-feasibility		28,523	Metallurgical	Yes		8.00		0.35		14,227		62.50
Total Canada			101,292
South Wales, U.K.:
Energybuild's Aberpergwm Mine	Development		5,289	Thermal and/or Metallurgical	Yes		5.80		0.80		14,428		9.29
Total Walter Energy			375,068

(1)

The majority of our reserves at our Alabama mines qualify as metallurgical coal and are within the Blue Creek, Mary Lee and Black Creek seams.

(2)

Mines labeled as "ready for operation" will begin production when market conditions permit. Tons at TRI's idled Panther 3 Mine will be mined when market conditions permit.

(3)

Mines that are labeled as development are undeveloped mines that are being developed or intended to be fully developed and mined as market conditions permit.

(4)

Mine No. 5 closed in December 2006, however, the related preparation plant remains operational and serves as the washing and shipping point for production associated with the Mine No. 7 East expansion project.

(5)

Compliant coal, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus as required by Phase II of the Clean Air Act.

Note: Also see Glossary for definitions of technical terms.

48

        Production and average coal selling price per metric ton for each of the three years in the period ended December 31, 2011 were as follows (production in thousands):

	Production(1)/Average Coal Selling Price per Ton
Location/Mine	2011				2010				2009
Alabama:
JWR's No. 4 Mine		1,926	$	272.61		2,537	$	204.11		2,467	$	138.44
JWR's No. 7 Mine		3,275	$	275.88		3,511	$	202.25		3,054	$	138.94
JWR's North River Mine(3)		1,539	$	43.56		—		—		—		—
TRI's East Brookwood Mine		97	$	112.59		421	$	104.86		489	$	96.62
TRI's Howton Mine		NA		NA		NA		NA		73	$	95.71
Taft's Choctaw Mine		549	$	90.74		601	$	70.45		568	$	64.11
TRI's Swann's Crossing(6)		183	$	105.73		NA		NA		NA		NA
Walter Minerals' Highway 59 Mine(4)		192	$	105.19		201	$	89.54		74	$	101.18
Taft's Reid School Mine(5)		221	$	163.45		147	$	150.98		NA		NA
Total Alabama		7,982				7,418				6,725
West Virginia(2):
Atlantic Development Capital's Gauley Eagle Underground Mine		8	$	114.17		—		—		—		—
Atlantic Development Capital's Gauley Eagle Surface Mine		519	$	64.79		—		—		—		—
Atlantic Development Capital's Maple Underground Mine		448	$	173.63		—		—		—		—
Atlantic Development Capital's Maple Surface Mine		391	$	71.36		—		—		—		—
Total West Virginia		1,366				—				—
Northeast B.C., Canada(2):
Wolverine's Perry Creek Mine		1,083	$	265.79		—		—		—		—
Brazion's Brule Mine		1,100	$	210.10		—		—		—		—
Brazion's Willow Creek Mine		568	$	215.22		—		—		—		—
Total Canada		2,751				—				—
South Wales, U.K.(2):
Energybuild's Aberpergwm Mine		100	$	121.67		—		—		—		—
Total Walter Energy		12,200				8,178				7,412

(1)

The production year ends December 31.

(2)

Acquired in the Western Coal acquisition on April 1, 2011. Production and average coal selling price per metric ton include activity since the date of acquisition.

(3)

The North River Mine was acquired on May 6, 2011. Production and average coal selling price per metric ton include activity since the date of acquisition. The contract price was lower than current market price at the time of acquisition and a liability for this impact was recorded as a part of the purchase price allocation process. This liability is amortized to revenue as tons are sold.

(4)

Operations of Walter Minerals' Highway 59 Mine commenced August 2009 and this mine was closed in 2011.

(5)

Operations of Taft's Reid School Mine commenced May 2010.

(6)

Operations of TRI's Swann's Crossing Mine commenced May 2011.

49

        Information concerning our properties has been prepared in accordance with applicable United States federal securities laws. All mineral reserve estimates have been prepared in accordance with SEC Industry Guide 7—Description of Property by Issuers Engaged or to be Engaged in Significant Mining Operations. We are also required to comply with the requirements of applicable Canadian securities law and, in particular, National Instrument 43-101—Standards of Disclosure for Mineral Projects ("NI 43-101") of the Canadian Securities Administrators which contains requirements and standards for mineral disclosure which differ from SEC Industry Guide 7. In this regard, we have filed technical reports in respect of certain of our properties to comply with the requirements of NI 43-101 and which have been filed with the Canadian securities regulatory authorities and are available at www.sedar.com. Investors resident in Canada should be aware that Canadian standards for mineral disclosure, including NI 43-101, differ significantly from the requirements of the SEC. Without limiting the generality of the foregoing, the requirements of NI 43-101 for identification of "mineral reserves" are not the same as those of the SEC, and reserves reported in compliance with NI 43-101 may not qualify as "reserves" under SEC Industry Guide 7. Accordingly, information contained in this annual report containing descriptions of mineral reserves may not be comparable to similar information made public by Canadian companies subject to the reporting and disclosure requirements under NI 43-101.

Item 3.    Legal Proceedings

        See the section entitled "Environmental" in Business and Notes 2 and 14 of "Notes to Consolidated Financial Statements" included herein.

Item 4.    Mine Safety Disclosures

        The information concerning mine safety violations and other regulatory matters is filed as Exhibit 95 to this form pursuant to the requirements of Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104).

50

PART II

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

        Our common stock (the "Common Stock") has been listed on the New York Stock Exchange under the trading symbol "WLT" since December 18, 1997 and the Toronto Stock Exchange under the trading symbol "WLT" since April 12, 2011. The table below sets forth the range of high and low closing sales prices of the Common Stock for the fiscal periods indicated.

	Year ended December 31, 2011
	High		Low
1st Fiscal quarter	$	138.58	$	114.12
2nd Fiscal quarter	$	141.17	$	105.59
3rd Fiscal quarter	$	131.71	$	60.01
4th Fiscal quarter	$	81.25	$	56.90

	Year ended December 31, 2010
	High		Low
1st Fiscal quarter	$	92.33	$	64.55
2nd Fiscal quarter	$	98.48	$	60.85
3rd Fiscal quarter	$	83.05	$	59.23
4th Fiscal quarter	$	129.84	$	79.41

        During the year ended December 31, 2011, we declared and paid a dividend of $0.125 per share to shareholders of record on each of February 18, May 6, August 12, and November 4. During the year ended December 31, 2010, we declared and paid a dividend of $0.10 per share to shareholders of record on February 19, and declared and paid a dividend of $0.125 per share to shareholders of record on each of May 7, August 6 and November 5. Covenants contained in certain of the debt instruments referred to in Note 10 of "Notes to Consolidated Financial Statements" may restrict the amount the Company can pay in cash dividends. Future dividends will be declared at the discretion of the Board of Directors and will depend on our future earnings, financial condition and other factors affecting dividend policy. As of February 22, 2012, there were 582 shareholders of record of the Common Stock.

51

        The following graph shows changes over the past five-year period in the value of $100 invested in (1) Walter Energy's common shares; (2) Russell 3000 Stock Index; and (3) Dow Jones U.S. Coal Index. The values of each investment are based on price change plus reinvestment of all dividends reported to shareholders. The information below is being furnished pursuant to Regulation S-K, Item 201 (e) (Performance Graph).

	2006		2007		2008		2009		2010		2011
Walter Energy, Inc.		100.0		132.8		64.7		278.4		472.6		223.9
Russell 3000 Stock Index		100.0		103.3		63.3		79.4		91.2		90.3
Dow Jones U.S. Coal Index		100.0		174.5		65.6		137.6		183.5		97.1

        The following table sets forth certain information relating to our equity compensation plans as of December 31, 2011:

	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance
Equity compensation plans approved by security holders:
2002 Long-term Incentive Award Plan		635,098	$	26.74		1,997,836
1995 Long-term Incentive Stock Plan		22,571	$	5.96		—
1996 Employee Stock Purchase Plan		—		—		1,172,153

Sales of Unregistered Securities

        None

Common Stock Issuance

        On April 1, 2011, we issued 8,951,558 shares of common stock to partially fund the acquisition of Western Coal.

52

Purchase of Equity Securities by the Company and Affiliated Purchasers

Period	Total Number of Shares Purchased(1)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions)(1)
January 1, 2011–January 31, 2011		—		—		—	$	0.2
February 1, 2011–February 28, 2011		35,541	$	120.49		—	$	0.2
March 1, 2011–March 31, 2011		6,097	$	131.83		—	$	0.2
April 1, 2011–April 30, 2011		—		—		—	$	0.2
May 1, 2011–May 31, 2011		368	$	120.17		—	$	0.2
June 1, 2011–June 30, 2011		289	$	116.06		—	$	0.2
July 1, 2011–July 31, 2011		419	$	123.05		—	$	0.2
August 1, 2011–August 31, 2011		—		—		—	$	0.2
September 1, 2011–September 30, 2011		25	$	85.62		—	$	0.2
October 1, 2011–October 31, 2011		—		—		—	$	0.2
November 1, 2011–November 30, 2011		37	$	74.80		—	$	0.2
December 1, 2011–December 31, 2011.		—		—		—	$	0.2
		42,776				—

(1)

These shares were acquired to satisfy certain employees' tax withholding obligations associated with the lapse of restrictions on certain stock awards granted under the Amended and Restated 2002 Long-Term Incentive Award Plan. Upon acquisition, these shares were retired.

Item 6.    Selected Financial Data

        The following data, insofar as it relates to each of the years ended December 31, 2011, 2010, 2009, 2008 and 2007 has been derived from annual consolidated financial statements, including the consolidated balance sheets and the related consolidated statements of operations, changes in stockholders' equity and comprehensive income and statements of cash flows and the notes thereto as they relate to our continuing operations. The information presented below should be read in conjunction with our consolidated financial statements and the notes thereto, including Note 2 related

53

to significant accounting policies, Note 3 for acquisitions and Note 4 related to discontinued operations, and the other information contained elsewhere in this report.

	Years ended December 31,
(in thousands, except per share data)	2011		2010		2009		2008		2007
Revenues	$	2,571,358	$	1,587,730	$	966,827	$	1,149,684	$	774,795
Income from continuing operations	$	349,176	$	389,425	$	141,850	$	231,192	$	98,227
Basic income per share from continuing operations	$	5.79	$	7.32	$	2.67	$	4.30	$	1.89
Number of shares used in calculation of basic income per share from continuing operations		60,257		53,179		53,076		53,791		52,016
Diluted income per share from continuing operations	$	5.76	$	7.25	$	2.64	$	4.24	$	1.87
Number of shares used in calculation of diluted income per share from continuing operations		60,611		53,700		53,819		54,585		52,490
Capital expenditures	$	414,566	$	157,476	$	96,298	$	141,627	$	147,556
Net property, plant and equipment	$	4,583,295	$	790,001	$	522,931	$	504,585	$	385,140
Total assets(1)	$	6,812,203	$	1,651,853	$	1,244,159	$	1,195,695	$	777,262
Debt:
2011 term loan A	$	894,837	$	—	$	—	$	—	$	—
2011 term loan B	$	1,333,163	$	—	$	—	$	—	$	—
2011 revolving credit facility	$	10,000	$	—	$	—	$	—	$	—
2005 Walter term loan	$	—	$	136,062	$	137,498	$	138,934	$	218,517
2005 Walter revolving credit facility	$	—	$	—	$	—	$	40,000	$	—
Convertible senior subordinated notes	$	—	$	—	$	—	$	—	$	785
Miscellaneous debt(2)	$	87,715	$	32,411	$	39,000	$	46,451	$	6,558
Quarterly cash dividend per common share	$	0.125	$	0.125	$	0.10	$	0.10	$	0.05

(1)

Excludes assets of discontinued operations.

(2)

This balance includes capital lease obligations and an equipment financing agreement.

54

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

ORGANIZATION

        Walter Energy, Inc. ("Walter") is a leading producer and exporter of metallurgical coal for the global steel industry from underground and surface mines located in the United States, Canada and the United Kingdom. Walter also produces thermal coal, anthracite coal, metallurgical coke and coal bed methane gas.

        As described in Note 3 of "Notes to Consolidated Financial Statements", on April 1, 2011 we completed the acquisition of Western Coal Corp. ("Western Coal"). The accompanying summary of operating results includes the results of operations of Western Coal since April 1, 2011. As a result of the Western Coal acquisition and the change in how our Chief Operating Decision Maker evaluates the business operations, beginning with the second quarter of 2011 we have revised our reportable segments by arranging them geographically. We now report all of our operations located in the U.S. in the U.S. Operations segment which includes our previous operating segments of Underground Mining, Surface Mining and Walter Coke. The U.S. Operations segment also includes the West Virginia mining operations acquired through the acquisition of Western Coal. We report our mining operations acquired through the Western Coal acquisition located in Northeast British Columbia (Canada) and South Wales (United Kingdom) in the Canadian and U.K. Operations segment. Previously reported segment amounts have been restated to conform to the current period presentation. Previously reported ton and per ton statistics have been restated to metric tons from short tons for all periods presented.

        In December 2008, we announced the closure of our Homebuilding segment and on April 17, 2009, we spun off our Financing segment, creating Walter Investment Management Corp., a publicly-traded real estate investment trust. As a result of the closure and spin-off, those segments are presented as discontinued operations for the years ended December 31, 2010 and 2009. See further discussion in Note 4 of "Notes to Consolidated Financial Statements." Unless otherwise noted, this "Management's Discussion and Analysis of Financial Condition and Results of Operations" addresses our continuing operations only.

EXECUTIVE DISCUSSION

        In 2011 we achieved record revenues, EBITDA and metallurgical coal sales largely due to the acquisition of Western Coal and strong pricing through much of the year for hard coking coal. Our key accomplishments in 2011 include:

•

On April 1, 2011 we completed the acquisition of Western Coal for a total purchase price of approximately $3.7 billion. Western Coal is a producer of high quality metallurgical coal from mines in Northeast British Columbia (Canada), high quality metallurgical coal and compliant thermal coal from mines located in West Virginia (United States), and high quality anthracite coal in South Wales (United Kingdom). The acquisition of Western Coal transformed the Company into the leading, publicly traded 'pure-play' metallurgical coal producer in the world with strategic access to high-growth steel-producing countries in Asia, South America and Europe. We have significant reserves available for future production, the majority of which is high-demand metallurgical coal, with a diverse geographical footprint.

•

On May 6, 2011 we acquired mineral rights for approximately 68 million metric tons of recoverable Blue Creek metallurgical coal reserves to the northwest of our existing Alabama mines from a subsidiary of Chevron Corporation. The transaction captured an integral portion of the last remaining block of Blue Creek metallurgical coal and paves the way for a strategic opportunity to assemble approximately 170 million metric tons of high quality hard coking coal and the development of a new underground mine. In addition, we acquired Chevron

55

Corporation's existing North River thermal coal mine in Fayette and Tuscaloosa Counties of Alabama.

•

Within our Canadian and U.K. Operations segment, our Falling Creek connector road project was substantially commissioned near the end of the 2011 third quarter and truck hauling volumes on the road have continued to increase into the 2012 first quarter. The Falling Creek connector road connects the Brule mine to the Willow Creek mine where Brule's coal is processed and loaded at the rail load out facility. The new connector road reduces the hauling distance as compared to the previous route from just over 62 miles down to 37 miles. It is anticipated that we will be able to increase our payload capacity resulting in lower transportation costs.

•

Our Canadian operations continued to implement expansion plans and initiatives designed to increase production, optimize equipment and move from contract to owner operated mines at two of the mines, one in 2012 and the other in 2013.

Industry Overview and Outlook

        Global steel production reached a record 1.5 billion metric tons in 2011, an increase of 6.8% from the previous record of 1.4 billion metric tons set in 2010, including in countries in our key markets of Asia, South America and Europe. All major steel producing countries showed growth in 2011. Annual 2011 steel production for Asia was 988 million metric tons, an increase of 7.9% compared to 2010. The share of global steel production by countries in Asia, South America and Europe increased slightly in 2011 to 64.7% from 64.0% in 2010. Steel production in South America experienced significant gains, up 10.2% for the year, while steel production in Europe showed a modest gain of 4.6% compared to 2010.

        Coking coal prices have softened somewhat as we have entered into 2012, with spot prices slightly below the first quarter benchmark price of $235 per metric ton. Prices have been recently constrained by contracting Chinese and emerging market growth, continued monetary issues in Europe, and slow growth in both the U.S. and European economies. However, the long-term demand for metallurgical coal within all our geographic markets is anticipated to remain strong as industry projections continue to suggest that global steelmaking will continue to require increasing amounts of high quality metallurgical coal. If necessary, we will leverage the opportunity to potentially increase coal inventory to working levels which could help both quality and profitability as it may provide better opportunities for blending as well as lower demurrage costs. We are focused on the long-term contractual market and anticipate continued strong demand for the high-quality metallurgical coals we produce.

        For 2012 we remain well positioned to achieve record metallurgical coal production and currently expect 2012 metallurgical coal production to be within the range of 11.5 million and 13.0 million metric tons of which approximately 75% will be hard coking coal and 25% will be low-volatile PCI coal. We expect more than one-third of the growth in production to come from our Alabama underground Mine No. 7 after having experienced slow cutting rates for the majority of 2011, just under one third of the growth in production is expected to come from our other U.S. mining operations in Alabama and West Virginia, and one-third of the growth is anticipated to come from increased production at our Canadian operations.

56

        The strong market environment influences Walter's investment considerations and is the primary driver for our growth prospects:

•

Our coking coal product is among the highest quality in the world. Our low-volatile PCI coals possess the chemical and physical characteristics, including high coke strength and good fluidity, which steel producers prefer.

•

We believe that demand for high quality, metallurgical coals, will continue to increase and that these raw materials will continue to grow in scarcity, particularly for the highest-grade coals, such as ours.

RESULTS OF CONTINUING OPERATIONS

2011 Summary Operating Results

	For the Year Ended December 31, 2011
(in thousands)	U.S. Operations		Canadian and U.K. Operations			Other			Total
Sales	$	1,850,015	$	711,322		$	988		$	2,562,325
Miscellaneous income (loss)		21,167		(13,268	)		1,134			9,033
Revenues		1,871,182		698,054			2,122			2,571,358
Cost of sales (exclusive of depreciation and depletion)		1,050,743		509,213			1,156			1,561,112
Depreciation and depletion		151,341		93,392			776			245,509
Selling, general and administrative		61,622		28,100			76,027			165,749
Postretirement benefits		41,745		—			(1,360	)		40,385
Operating income (loss)	$	565,731	$	67,349		$	(74,477	)		558,603
Interest expense, net										(96,214	)
Other income, net										17,606
Income tax expense										(130,819	)
Income from continuing operations									$	349,176

	For the Year Ended December 31, 2010
(in thousands)	U.S. Operations		Canadian and U.K. Operations		Other			Total
Sales	$	1,569,939	$	—	$	906		$	1,570,845
Miscellaneous income		14,795		—		2,090			16,885
Revenues		1,584,734		—		2,996			1,587,730
Cost of sales (exclusive of depreciation and depletion)		766,279		—		237			766,516
Depreciation and depletion		98,170		—		532			98,702
Selling, general and administrative		42,615		—		44,357			86,972
Postretirement benefits		43,228		—		(1,750	)		41,478
Operating income (loss)	$	634,442	$	—	$	(40,380	)		594,062
Interest expense, net									(16,466	)
Income tax expense									(188,171	)
Income from continuing operations								$	389,425

57

	Increase (Decrease) for the Year Ended December 31, 2011
(in thousands)	U.S. Operations			Canadian and U.K. Operations			Other			Total
Sales	$	280,076		$	711,322		$	82		$	991,480
Miscellaneous income (loss)		6,372			(13,268	)		(956	)		(7,852	)
Revenues		286,448			698,054			(874	)		983,628
Cost of sales (exclusive of depreciation and depletion)		284,464			509,213			919			794,596
Depreciation and depletion		53,171			93,392			244			146,807
Selling, general and administrative		19,007			28,100			31,670			78,777
Postretirement benefits		(1,483	)		—			390			(1,093	)
Operating income (loss)	$	(68,711	)	$	67,349		$	(34,097	)		(35,459	)
Interest expense, net											(79,748	)
Other income, net											17,606
Income tax expense											57,352
Income from continuing operations										$	(40,249	)

Year Ended December 31, 2011 as Compared to the Year Ended December 31, 2010

Overview of Consolidated Financial Results

        Our income from continuing operations for the year ended December 31, 2011 was $349.2 million or $5.76 per diluted share, which compares to $389.4 million, or $7.25 per diluted share for the year ended December 31, 2010.

        Principal factors impacting income from continuing operations in 2011 compared to 2010 include:

•

Revenues in 2011 increased $983.6 million, or 62.0% from 2010. The increase in revenues was primarily attributable to the addition of the Canadian and U.K. Operations segment and the West Virginia and North River mining operations within our U.S. Operations segment. These recently acquired operations contributed $942.6 million of the increase. The remainder of the increase was driven by higher hard coking coal pricing from our U.S. Operations, partially offset by lower hard coking coal sales volumes.

•

Cost of sales, exclusive of depreciation and depletion, increased $794.6 million to $1.6 billion in 2011 as compared to 2010, primarily as a result of the addition of the Canadian and U.K. Operations segment and the West Virginia and North River mining operations within our U.S. Operations segment, which accounted for 88.1% of the increase. The remainder of the increase was attributable to increased production costs at our Alabama underground mining operations, primarily due to difficult geological conditions, higher royalties and freight costs during 2011 as well as difficult weather conditions during the second quarter of 2011. Cost of sales, exclusive of depreciation and depletion, represented 60.7% of revenues in 2011 versus 48.3% of revenues for 2010.

•

Depreciation and depletion expense in 2011 increased $146.8 million as compared to 2010. The addition of the Canadian and U.K. Operations segment and the West Virginia and North River mining operations in our U.S. Operations segment represents $125.3 million of the increase. The remainder of the increase is primarily due to higher depreciation and depletion in our U.S. Operations resulting from the acquisition of the Walter Black Warrior Basin coal bed methane operations on May 28, 2010.

58

•

Selling, general & administrative expenses increased $78.8 million, or 90.6%, from 2010 primarily attributable to $48.4 million due to the addition of the Canadian and U.K. Operations segment and the West Virginia and North River mining operations in our U.S. Operations segment. The remainder of the increase was primarily attributable to $23.2 million of costs associated with the acquisition of Western Coal and increases in professional fees.

•

Other income for the year ended December 31, 2011 is primarily attributable to a gain of $20.5 million recognized on April 1, 2011 as a result of remeasuring to fair value the Western Coal shares acquired from Audley Capital in January 2011, partially offset by a net loss on the sale and remeasurement to fair value of other equity investments.

•

Interest expense, net of interest income was $96.2 million in 2011, an increase of $79.7 million compared to 2010. The increase reflects interest on borrowings of $2.35 billion on April 1, 2011 to fund a portion of the Western Coal acquisition.

•

Our effective tax rate for 2011 and 2010 was 27.3% and 32.6%, respectively. Our effective tax rate for 2011 declined primarily due to certain undistributed foreign earnings for which no U.S. taxes are provided because such earnings are intended to be indefinitely reinvested outside of the U.S. In addition, the tax expense for 2010 included a one-time tax charge of $20.7 million related to the elimination of the favorable tax treatment of Medicare Part D subsidies due to the passage of the Health Care Reform Act in March 2010, as well as a one-time tax benefit of $17.4 million related to unconventional fuel source credits for our Walter Coke operations for the years 2006 through 2009.

Overview of Our Operating Segments and Outlook

        In addition to the general overview discussions above, the following discussion provides specific operating and forward-looking information regarding each of our operating segments.

U.S. Operations

•

Hard coking coal sales totaled 5.7 million metric tons in 2011, a decrease as compared to 6.3 million metric tons during 2010 due to lower production volumes. The average selling price in 2011 was $237.05 per metric ton, a 18.4% increase as compared to an average selling price of $200.28 per metric ton in 2010. Hard coking coal production totaled 5.9 million metric tons in 2011, a decline of 405,000 metric tons as compared to 2010 as lower production in Alabama due to difficult geology more than offset the addition of hard coking coal production from the West Virginia operations.

•

In the fourth quarter of 2011, we sold 1.4 million metric tons of hard coking coal at an average selling price of $242.61 per metric ton as compared to 1.5 million metric tons at an average selling price of $217.64 per metric ton during the same period in 2010. Fourth quarter 2011 sales volumes were negatively impacted by production shortfalls at our Alabama operations as a result of equipment issues on the second longwall at Mine No. 7 and ventilation issues associated with the startup of the nearby third longwall. The third longwall is currently scheduled to replace the existing second longwall during the second quarter of 2012. Partially offsetting the decline were sales from inventory and purchased coal. Pricing for premium coking coal produced by our Alabama operations for the first quarter of 2012 is expected to average approximately $240 per metric ton FOB port, which includes a mix of carryover tons at $284 per metric ton as well as new contract tons for the first quarter averaging at the $235 per metric ton benchmark price.

•

Thermal coal sales totaled 3.7 million metric tons in 2011 as compared to 1.1 million metric tons during 2010. The increase was primarily due to sales of the recently acquired West Virginia and North River mining operations. The average selling price in 2011 was $72.42 per metric ton,

59

down 13.0% from the average selling price of $83.24 per metric ton in 2010. Lower average pricing was the result of lower prices for tons sold by the North River mine. Thermal coal production totaled 3.4 million metric tons in 2011, as compared to 1.1 million metric tons in 2010. The increase was due to the addition of the West Virginia and North River mining operations. In the fourth quarter of 2011, we sold 1.0 million metric tons of thermal coal, at an average selling price of $68.71 per metric ton.

Canadian and U.K. Operations

•

The Canadian and U.K. Operations segment was acquired during the second quarter of 2011 as part of the Western Coal acquisition and therefore there are no comparable results from the prior year and we have therefore limited our historic discussion to factors impacting the second, third and fourth quarters of 2011. We experienced production delays during the second and third quarters of 2011 which were caused by the effects of adverse weather conditions experienced during the second quarter of 2011. In addition, during 2011 we experienced delays in the commissioning of the Falling Creek connector road and delays in the issuance of mining permits. These delays adversely impacted sales and production volumes as well as transportation costs. While production volumes remained relatively flat during the fourth quarter as compared to the third quarter, we experienced sales volume increases as conditions improved and we anticipate further improvement in 2012.

•

Metallurgical coal sales from the Canadian and U.K. Operations since the April 1, 2011 date of acquisition totaled 1.3 million metric tons of hard coking coal at an average selling price of $262.67 per metric ton and 1.7 million metric tons of low-volatile PCI coal at an average selling price of $211.34 per metric ton. Metallurgical coal sales in the fourth quarter of 2011 totaled 488,000 metric tons of hard coking coal at an average selling price of $249.24 per metric ton and 523,000 metric tons of low-volatile PCI coal at an average selling price of $212.29 per metric ton. We have seen some weakness in the 2011 market and anticipate 2012 prices to be somewhat lower than those of 2011.

•

The Canadian and U.K. Operations segment produced a total of 1.1 million metric tons of hard coking coal and 1.7 million metric tons of low-volatile PCI coal since the April 1, 2011 date of acquisition. During the fourth quarter of 2011 the Canadian and U.K. Operations segment produced 391,000 metric tons of hard coking coal as compared to 371,000 metric tons of hard coking coal during the third quarter of 2011. Low-volatile PCI coal production during the fourth quarter of 2011 from the Canadian and U.K. Operations segment totaled 567,000 metric tons as compared to production of 587,000 metric tons during the third quarter of 2011.

•

In December 2011, operations of the Ridley terminal used by our Canadian mines was affected by the commissioning of an upgraded rail-car dumping system, which is the first stage towards a doubling of the annual capacity of the terminal to 24 million metric tons. The commissioning prevented the unloading of rail-cars. However, this did not delay any scheduled shipments of the fourth quarter. Project work at our Willow Creek mine coal handling and preparation plant upgrades were coordinated with the coal terminal upgrade, where possible, to minimize our downtime and advance the project completion date. The coal handling and preparation plant upgrades were executed in two phases with the last phase completed in the first quarter of 2012.

•

In 2012, our Canadian mines are continuing with expansion plans and initiatives designed to improve our long-term production, optimize equipment and decrease costs.

•

The current and prior year results also included the effect of the factors discussed in the following segment analysis.

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Segment Analysis

U.S. Operations

        Our U.S. Operations segment reported revenues of $1.9 billion in 2011, an increase of $286.4 million from 2010. The increase in revenues was primarily due to the addition of the West Virginia and North River mining operations acquired in the second quarter of 2011 which added $244.5 million in revenues to the segment, however at lower gross margins than those of the legacy operations. Increased revenues were also due to higher average selling prices for hard coking coal, partially offset by lower hard coking coal sales volumes. The lower hard coking coal sales volumes in 2011 as compared to 2010 reflects lower production at our Alabama underground mines due to geology issues during 2011 and weather related issues in the second quarter of 2011. Statistics for U.S. Operations are presented in the following table:

	For the year ended December 31,
	2011		2010
Average hard coking coal selling price(1) (per metric ton)	$	237.05	$	200.28
Tons of hard coking coal sold(1) (in thousands)		5,655		6,270
Average thermal coal selling price(1) (per metric ton)	$	72.42	$	83.24
Tons of thermal coal sold(1) (in thousands)		3,673		1,077

(1)

Includes sales of both coal produced and purchased coal.

        U.S. Operations reported operating income of $565.7 million in 2011, as compared to $634.4 million in 2010. The $68.7 million decrease in operating income was primarily due to the increase in cost of sales, a higher mix of lower margin thermal coal sales, and increased depreciation and depletion and selling, general and administrative expenses associated with the recently acquired North River and West Virginia operations. Cost of sales increased as a result of increased production costs at our Alabama underground operations primarily due to difficult geological conditions and higher thermal coal sales volumes as well as higher royalty and freight costs.

Canadian and U.K. Operations

        Results for 2011 represent the results of the segment since the April 1, 2011 date of acquisition. The segment reported revenues of $698.1 million and operating income of $67.3 million.

        Results for 2011 were adversely impacted by challenging weather conditions during the second quarter and their lingering effects during the third quarter, delays in the issuance of mining permits at the Willow Creek mine, delays in the commissioning of the Falling Creek connector road and higher mining ratios at our Northeast British Columbia mining operations. These conditions and delays impacted sales and production volumes during the year as well as production and transportation costs. Cost of sales during the fourth quarter for hard coking coal was negatively impacted by purchased coal related to the Ridley terminal upgrade. Fourth quarter cost of sales for PCI coal was also negatively impacted by our expediting the migration from a contractor base to owner base for our Willow Creek mine workers. Although this move will help lower overall future costs, it caused some short term

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increases as we prepared for the move. Statistics for Canadian and U.K. Operations are presented in the following table:

	For the year ended December 31,
	2011
Average hard coking coal selling price (per metric ton)(1)	$	262.67
Tons of hard coking coal sold (in thousands)(1)		1,321
Average low-volatile PCI coal selling price (per metric ton)	$	211.34
Tons of low-volatile PCI coal sold (in thousands)		1,732
Average thermal coal selling price (per metric ton)	$	119.03
Tons of thermal coal sold (in thousands)		94

(1)

Includes sales of both coal produced and purchased coal.

2010 Summary Operating Results

        As described above, we now report under the U.S. Operations segment our previous operating segments of Underground Mining, Surface Mining and Walter Coke. In the following discussion of our 2010 operating results, previously reported segment amounts have been restated to conform to the current period presentation.

	For the Year Ended December 31, 2010
(in thousands)	U.S. Operations		Other			Total
Sales	$	1,569,939	$	906		$	1,570,845
Miscellaneous income		14,795		2,090			16,885
Revenues		1,584,734		2,996			1,587,730
Cost of sales (exclusive of depreciation and depletion)		766,279		237			766,516
Depreciation and depletion		98,170		532			98,702
Selling, general and administrative		42,615		44,357			86,972
Postretirement benefits		43,228		(1,750	)		41,478
Operating income (loss)	$	634,442	$	(40,380	)		594,062
Interest expense, net							(16,466	)
Income tax expense							(188,171	)
Income from continuing operations						$	389,425

	For the Year Ended December 31, 2009
(in thousands)	U.S. Operations		Other			Total
Sales	$	954,924	$	584		$	955,508
Miscellaneous income		9,434		1,885			11,319
Revenues		964,358		2,469			966,827
Cost of sales (exclusive of depreciation and depletion)		587,186		(412	)		586,774
Depreciation and depletion		72,533		406			72,939
Selling, general and administrative		37,433		32,630			70,063
Postretirement benefits		31,902		(1,069	)		30,833
Amortization of intangibles		447		—			447
Restructuring & impairment charges		3,601		—			3,601
Operating income (loss)	$	231,256	$	(29,086	)		202,170
Interest expense, net							(18,176	)
Income tax expense							(42,144	)
Income from continuing operations						$	141,850

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	Increase (Decrease) For the Year Ended December 31, 2010
(in thousands)	U.S. Operations			Other			Total
Sales	$	615,015		$	322		$	615,337
Miscellaneous income		5,361			205			5,566
Revenues		620,376			527			620,903
Cost of sales (exclusive of depreciation and depletion)		179,093			649			179,742
Depreciation and depletion		25,637			126			25,763
Selling, general and administrative		5,182			11,727			16,909
Postretirement benefits		11,326			(681	)		10,645
Amortization of intangibles		(447	)		—			(447	)
Restructuring & impairment charges		(3,601	)		—			(3,601	)
Operating income (loss)	$	403,186		$	(11,294	)		391,892
Interest expense, net								1,710
Income tax expense								(146,027	)
Income from continuing operations							$	247,575

Year Ended December 31, 2010 as Compared to the Year Ended December 31, 2009

Overview of Consolidated Financial Results

        Our income from continuing operations for the year ended December 31, 2010 was $389.4 million or $7.25 per diluted share, which compares to $141.9 million, or $2.64 per diluted share for the year ended December 31, 2009.

        Principal factors impacting income from continuing operations in 2010 compared to 2009 included:

•

Revenues in 2010 increased $620.9 million, or 64.2% from 2009. The increase in revenues was primarily due to significantly higher average selling prices and higher volumes for hard coking coal, along with increased volumes and higher average selling prices for metallurgical coke and thermal coal.

•

Cost of sales, exclusive of depreciation and depletion, increased $179.7 million to $766.5 million in 2010 as compared to 2009, primarily as a result of increased volumes in all our operations along with higher freight and royalty costs at our underground mining operations, higher production costs at our surface mining operations, and higher raw material costs at our coke plant. Cost of sales represented 48.8% of sales in 2010 versus 61.4% of 2009. This reduction of cost of sales as a percentage of sales is primarily the result of increased selling prices.

•

Depreciation and depletion expense in 2010 increased $25.8 million as compared to 2009. The increase was primarily due to higher depreciation and depletion resulting from a change to the unit-of-production method of depletion on certain gas properties, as well as depreciation and depletion related to the acquisition of HighMount Exploration and Production Alabama, LLC ("HighMount") and from capital expenditures to develop our Mine No. 7 East longwall operation.

•

Selling, general & administrative expenses increased $16.9 million, or 24.1%, from 2009 primarily attributable to costs associated with the pending acquisition of Western Coal, acquisition and integration costs associated with the purchase of HighMount, costs associated with the relocation of our corporate headquarters and increases in employee compensation and benefit related expenses. Costs associated with completed and pending acquisitions totaled $9.5 million in 2010.

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•

Restructuring and impairment charges in 2009 of $3.6 million were for the closure of our fiber plant in December 2009.

���

Our effective tax rate for 2010 and 2009 was 32.6% and 22.9%, respectively. Income tax expense for 2010 included a one-time tax charge of $20.7 million related to the elimination of the favorable tax treatment of post 2012 Medicare Part D subsidies due to the passage of the Health Care Reform Act in March 2010, as well as a one-time tax benefit of $17.4 million related to unconventional fuel source credits for the years 2006 through 2009. These items are not expected to recur. Additionally, the impact of percentage depletion resulted in a significantly larger favorable impact on the full year effective tax rate in 2009 compared to the 2010 effective tax rate.

•

The 2010 and 2009 results also include the impact of the factors discussed in the following segment analysis.

Segment Analysis

U.S. Operations

        Our U.S. Operations segment reported revenues of approximately $1.6 billion for 2010, an increase of $620.4 million from the same period in 2009. The increase in revenues was primarily due to significantly higher average selling prices and higher volumes of hard coking coal and metallurgical coke sales during 2010 as compared to 2009 as shown in the table below:

	For the year ended December 31,
	2010		2009
Average hard coking coal selling price(1) (per metric ton)	$	200.28	$	137.39
Tons of hard coking coal sold(1) (in thousands)		6,270		5,519
Average thermal coal selling price (per metric ton)	$	83.24	$	71.60
Tons of thermal coal sold (in thousands)		1,077		1,119
Metallurgical coke average selling price (per metric ton)	$	410.85	$	362.49
Tons of metallurgical coke sold (in thousands)		394		181
Billion cubic feet of natural gas sold		10.6		6.1
Number of producing natural gas wells(2)		1,770		391

(1)

Includes sales of both hard coking coal produced and purchased coal.

(2)

Includes 1,370 wells associated with the acquisition of HighMount in 2010.

        The U.S. Operations segment reported operating income of $634.4 million in 2010 as compared to $231.3 million in 2009. The $403.1 million increase in operating income was almost entirely due to the increase in revenue as noted above, partially offset by higher cost of sales and depreciation and depletion. Cost of sales, exclusive of depreciation and depletion, increased as a result of higher sales volumes and higher freight and royalty costs. Depreciation and depletion increased as a result of implementing the unit-of-production method of accounting for depletion of certain gas properties during 2010, as well as depreciation and depletion related to the HighMount acquisition and the Mine No. 7 East mine expansion.

FINANCIAL CONDITION

        Cash and cash equivalents decreased by $165.0 million to $128.4 at December 31, 2011 from $293.4 million at December 31, 2010, primarily resulting from the use of cash during 2011 for capital expenditures of $436.7 million, $293.7 million used in January 2011 to acquire approximately 25.3 million common shares of Western Coal, $122.0 million of principal payments on our 2011 term

64

loans, and dividends paid of $30.0 million. Offsetting these uses of cash was $706.9 million in cash flows provided by operating activities during 2011. See additional discussion in the Statement of Cash Flows section that follows.

        Net receivables and inventories increased by $170.1 million and $145.0 million at December 31, 2011 as compared to December 31, 2010, respectively, primarily due to the acquisition of Western Coal and the North River Mine during the second quarter of 2011. See Note 3 of the "Notes to Consolidated Financial Statements" for further details around these acquisitions.

        Net mineral interests were $2.9 billion at December 31, 2011 as compared to $17.3 million at December 31, 2010. The increase was due to the acquisition of Western Coal. Net property, plant and equipment was $1.6 billion at December 31 2011, an increase of $864.5 million from December 31, 2010, primarily due to additions of $560.9 million as a result of the Western Coal acquisition and capital expenditures during 2011 of $414.6 million, partially offset by depreciation expense.

        Accrued expenses and accounts payable were $229.1 million and $112.7 million at December 31, 2011, an increase of $176.7 million and $42.0 million from December 31, 2010, respectively, primarily due to the acquisitions of Western Coal and the North River Mine. Deferred income tax liabilities were $1.0 billion at December 31, 2011 primarily due to the acquisition of Western Coal.

        The long-term portion of the accumulated postretirement benefits obligation was $550.7 million at December 31, 2011, up $99.4 million from $451.3 million at December 31, 2010. The increase was primarily attributed to a decrease in the discount rate, an increase in health care cost trend rates and revised mortality assumptions for the United Mine Workers of America portion of the postretirement benefit plan obligation causing an actuarially-determined increase to the liability at December 31, 2011. This adjustment is recognized as a corresponding decrease to stockholders' equity. Other long-term liabilities were $381.5 million at December 31, 2011, an increase of $118.6 from December 31, 2010 primarily due to the acquisition of Western Coal during the second quarter of 2011.

LIQUIDITY AND CAPITAL RESOURCES

Overview

        Our principal sources of short-term funding are our existing cash balances, operating cash flows and borrowings under our revolving credit facility. Our principal source of long-term funding is our bank term loans entered into on April 1, 2011 as discussed below.

        Based on current forecasts and anticipated market conditions, we believe that funding provided by operating cash flows and available sources of liquidity will be sufficient to meet substantially all operating needs, to make planned capital expenditures and to make all required interest and principal payments on indebtedness for the next twelve to eighteen months. However, our operating cash flows and liquidity are significantly influenced by numerous factors including prices of coal, coal production, costs of raw materials, interest rates and the general economy. Although we have experienced improvement in the market for our products, renewed deterioration of economic conditions or deteriorating mining conditions could adversely impact our operating cash flows. Additionally, although financial market conditions have improved there remains volatility and uncertainty, limited availability of credit, potential counterparty defaults, sovereign credit concerns and commercial and investment bank stress. While we have no indication that the uncertainty in the financial markets would impact our current credit facility or current credit providers, the possibility does exist.

2011 Credit Agreement

        On April 1, 2011, we entered into a $2.725 billion credit agreement (the "2011 Credit Agreement") to partially fund the acquisition of Western Coal and to pay off all outstanding loans under the 2005 Credit Agreement. The 2011 Credit Agreement consists of (1) a $950.0 million

65

principal amortizing term loan A facility maturing in April 2016, at which time the remaining outstanding principal is due, (2) a $1.4 billion principal amortizing term loan B facility maturing in April 2018, at which time the remaining outstanding principal is due and (3) a $375.0 million multi-currency revolving credit facility ("Revolver") maturing in April 2016, at which time any remaining balance is due. The Revolver provides for operational needs and letters of credit. Our obligations under the 2011 Credit Agreement are secured by our domestic and foreign real, personal and intellectual property. The 2011 Credit Agreement contains customary events of default and covenants, including among other things, covenants that do not prevent but restrict us and our subsidiaries ability to incur certain additional indebtedness, create or permit liens on assets, pay dividends and repurchase stock, engage in mergers or acquisitions, and make investments and loans. The 2011 Credit Agreement also includes certain financial covenants that must be maintained.

        The Revolver, term loan A and term loan B interest rates are tied to LIBOR or the Canadian Dealer Offered Rate ("CDOR"), plus a credit spread ranging from 225 to 300 basis points for the Revolver and term loan A, and 275 to 300 basis points on the term loan B, adjusted quarterly based on our total leverage ratio as defined by the 2011 Credit Agreement. The term loan B has a minimum LIBOR floor of 1.0%. The Revolver loans can be denominated in either U.S. dollars or Canadian dollars at our option. The commitment fee on the unused portion of the Revolver is 0.5% per year for all pricing levels.

        As of December 31, 2011, borrowings under the 2011 Credit Agreement consisted of a term loan A balance of $894.8 million with a weighted average interest rate of 3.44%, a term loan B balance of $1.333 billion with a weighted average interest rate of 4.00% and, under the Revolver, $10.0 million in borrowings with $71.2 million in outstanding stand-by letters of credit and $293.8 million of availability for future borrowings. During the 2011 fourth quarter, we prepaid $92.5 million of the outstanding principal balances of the term loans.

        On January 20, 2012, we entered into Amendment No. 1 to the 2011 Credit Agreement that provides for an increase in the amount available for the Canadian borrowers under the Credit Agreement and an increase in the amount that may be borrowed in Canadian Dollars, in each case from $150.0 million to $275.0 million.

2005 Credit Agreement, as Amended

        On April 1, 2011, in connection with the acquisition of Western Coal, we repaid all outstanding loans and accrued interest under the 2005 credit agreement, as amended ("2005 Credit Agreement") and it was simultaneously terminated. No penalties were due in connection with the repayments. As of March 31, 2011 the 2005 Credit Agreement included (1) an amortizing term loan facility ("2005 Term Loan") with an initial aggregate principal amount of $450.0 million and (2) a $300.0 million revolving credit facility ("2005 Revolver") which provided for loans and letters of credit. The 2005 Term Loan bore interest at LIBOR plus as much as 300 basis points and required quarterly principal payments of $0.4 million through October 3, 2012, at which time the remaining outstanding principal was to be due. The 2005 Revolver bore interest at LIBOR plus as much as 400 basis points and was due to mature on July 2, 2012. The commitment fee on the unused portion of the 2005 Revolver was 0.5% per year for all pricing levels. Our obligations under the 2005 Credit Agreement were secured by substantially all of the Company's real, personal and intellectual property.

Statements of Cash Flows

        Cash balances were $128.4 million and $293.4 million at December 31, 2011 and December 31, 2010, respectively. The decrease in cash during the year ended December 31, 2011 of $165.0 million primarily resulted from capital expenditures of $436.7 million, $293.7 million of cash used in the acquisition of Western Coal during January 2011 (see Note 3 of "Notes to Consolidated Financial Statements"), $122.0 million of principal payments on our 2011 term loans and dividends paid of $30.0 million, partially offset by cash provided by operating activities of $706.9 million.

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        The following table sets forth, for the periods indicated, selected consolidated cash flow information (in thousands):

	For the years ended December 31,
	2011			2010
Cash flows provided by operating activities	$	706,866		$	574,150
Cash flows used in investing activities		(2,840,660	)		(370,854	)
Cash flows provided by (used in) financing activities		1,971,947			(74,682	)
Effect of foreign exchange rates on cash		(3,668	)		—
Cash flows (used in) provided by continuing operations		(165,515	)		128,614
Cash flows provided by (used in) discontinued operations		535			(1,202	)
Net increase (decrease) in cash and cash equivalents	$	(164,980	)	$	127,412

        The $132.7 million increase in cash flows provided by operating activities is primarily attributable to an increase of $111.7 million in income from continuing operations, after adjusting for non-cash items such as depreciation and depletion and deferred taxes.

        Cash flows used in investing activities for the year ended December 31, 2011 were $2.8 billion as compared to $370.9 million for the same period in 2010. The increase in cash flows used in investing activities of $2.5 billion was primarily attributable to an increase in cash used in acquisitions of $2.2 billion as a result of the acquisition of Western Coal and an increase in capital expenditures of $279.2 million, primarily associated with expansion projects at the acquired Western Coal operations.

        Cash flows provided by financing activities for the year ended December 31, 2011 were $2.0 billion as compared to cash flows used in financing activities of $74.7 million in 2010. The increase in cash flows used in financing activities was primarily attributable to $2.4 billion of borrowings under the 2011 Credit Agreement to fund a portion of the Western Coal acquisition, offset by an increase in debt retirements of $263.7 million and $80.0 million of debt issuance costs.

Capital Expenditures

        Capital expenditures totaled $414.6 million in 2011 and included significant expansion projects at the operations acquired in the Western Coal acquisition on April 1, 2011. Capital expenditures for 2012 are expected to total approximately $450 million.

Contractual Obligations and Commercial Commitments

        We have certain contractual obligations and commercial commitments. Contractual obligations are those that will require cash payments in accordance with the terms of a contract, such as a borrowing or lease agreement. Commercial commitments represent potential obligations for performance in the event of demands by third parties or other contingent events, such as lines of credit or guarantees of debt.

        The following tables summarize our contractual obligations and commercial commitments as of December 31, 2011. This table does not include interest payable on these obligations. In 2011, we paid approximately $74.4 million of interest on the term loan, revolver and other debt financings.

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        Contractual obligations and commercial commitments(4) (in thousands):

			Payments Due by Period
	Total		2012		2013		2014		2015		2016		Thereafter
2011 credit agreement	$	2,238,000	$	19,837	$	82,500	$	112,500	$	517,500	$	182,663	$	1,323,000
Other debt(1)		87,715		36,858		27,215		17,530		6,058		54		—
Operating leases		67,348		22,435		16,310		13,471		7,327		4,869		2,936
Long-term purchase obligations(2)		332,463		49,760		45,782		33,846		33,846		33,846		135,383
Capital expenditure obligations		122,772		115,194		7,578		—		—		—		—
Total contractual cash obligations	$	2,848,298		244,084		179,385		177,347		564,731		221,432	$	1,461,319
Other long-term liabilities(3)				27,246		29,116		30,718		32,124		33,528
Total cash obligations			$	271,330	$	208,501	$	208,065	$	596,855	$	254,960

(1)

Primarily includes capital lease obligations and an equipment financing agreements. See Note 14 of "Notes to Consolidated Financial Statements" for further discussion of our capital lease obligations.

(2)

Represents minimum throughput obligations and minimum maintenance payments due for assets under capital lease.

(3)

Other long-term liabilities include pension and other post-retirement benefit liabilities. While the estimated total liability is actuarially determined, there are no definitive payments by period, as pension contributions depend on government-mandated minimum funding requirements and other post-retirement benefits are paid as incurred. Accordingly, amounts by period included in this schedule are estimates and primarily include estimated post-retirement benefits.

(4)

The timing of cash outflows related to liabilities for uncertain tax positions, and the interest thereon, as established pursuant to ASC Topic 740, "Income Taxes," cannot be estimated and, therefore, has not been included in the table. See Note 9 of "Notes to Consolidated Financial Statements."

Environmental, Miscellaneous Litigation and Other Commitments and Contingencies

        See Note 14 of "Notes to Consolidated Financial Statements" for discussion of these matters not included in the tables above due to their contingent nature.

EBITDA

        EBITDA is defined as earnings from continuing operations before interest, income taxes, depreciation, depletion and amortization expense. EBITDA is a financial measure which is not calculated in conformity with accounting principles generally accepted in the United States of America ("U.S. GAAP") and should be considered supplemental to, and not as a substitute or superior to financial measures calculated in conformity with U.S. GAAP. We believe that EBITDA is a useful measure as some investors and analysts use EBITDA to compare us against other companies and to help analyze our ability to satisfy principal and interest obligations and capital expenditure needs. EBITDA may not be comparable to similarly titled measures used by other entities.

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        Reconciliation of Net Income to EBITDA (in thousands):

	For the years ended December 31,
	2011			2010
Net income	$	349,176		$	385,797
Add: Interest expense		96,820			17,250
Less: Interest income		(606	)		(784	)
Add: Income tax expense		130,819			188,171
Add: Depreciation and depletion expense		245,509			98,702
Add: Loss from discontinued operations		—			3,628
Earnings from continuing operations before interest, income taxes, and depreciation and depletion (EBITDA)	$	821,718		$	692,764

CRITICAL ACCOUNTING ESTIMATES

        Management's discussion and analysis is based on, and should be read in conjunction with, the consolidated financial statements and notes thereto, particularly Note 17 of "Notes to Consolidated Financial Statements" which presents revenues and operating income by reportable segment. The preparation of financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in these financial statements or disclosed in the related notes thereto. Management evaluates these estimates and assumptions on an ongoing basis, using historical experience, consultation with experts and other methods considered reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from management's estimates.

        We believe the following discussion addresses our most critical accounting estimates, which are those that are most important to the portrayal of our financial condition and results of operations and require management's most difficult, subjective and complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain. These estimates are based upon management's historical experience and on various other assumptions that we believe reasonable under the circumstances. Changes in estimates used in these and other items could have a material impact on our financial statements.

Coal Reserves

        There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, many of which are beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled by our internal engineers and geologists or third party consultants. A number of sources of information are used to determine accurate recoverable reserves estimates including:

•

geological conditions;

•

historical production from the area compared with production from other producing areas;

•

the assumed effects of regulations and taxes by governmental agencies;

•

previously completed geological and reserve studies;

•

assumptions governing future prices; and

•

future operating costs.

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        Reserve estimates will change from time to time to reflect, among other factors:

•

mining activities;

•

new engineering and geological data;

•

acquisition or divestiture of reserve holdings; and

•

modification of mining plans or mining methods.

        Each of these factors may vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and these variances may be material. Variances could affect our projected future revenues and expenditures, as well as the valuation of coal reserves and depletion rates. At December 31, 2011, our current operations had 375.1 million metric tons of proven and probable coal reserves.

Business Combinations

        At acquisition, we allocate the cost of a business acquisition to the specific tangible and intangible assets acquired and liabilities assumed based upon their relative fair values. Significant judgments and estimates are often made to determine these allocated values, and may include the use of appraisals, consideration of market quotes for similar transactions, employment of discounted cash flow techniques or consideration of other information we believe relevant. The finalization of the purchase price allocation will typically take a number of months to complete, and if final values are materially different from initially recorded amounts, adjustments are recorded.

        Subsequent to the finalization of the purchase price allocation, any adjustments to the recorded values of acquired assets and liabilities would be reflected in the consolidated statement of operations. Once final, it is not permitted to revise the allocation of the original purchase price, even if subsequent events or circumstances prove the original judgments and estimates to be incorrect. In addition, long-lived assets like mineral interests, property, plant and equipment and goodwill may be deemed to be impaired in the future resulting in the recognition of an impairment loss. The assumptions and judgments made when recording business combinations will have an impact on reported results of operations for many years into the future.

Asset Retirement Obligations

        Our asset retirement obligations primarily consist of spending estimates to reclaim surface lands and supporting infrastructure at both surface and underground mines in accordance with applicable reclamation laws in the U.S., Canada and U.K. as defined by each mining permit. Significant reclamation activities include reclaiming refuse piles and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at underground mines. Asset retirement obligations are determined for each mine using various estimates and assumptions, including estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, discounted using a credit-adjusted, risk-free rate. On at least an annual basis, we review our entire asset retirement obligation liability and make necessary adjustment for permit changes, the timing of mine closures, and revisions to cost estimates and productivity assumptions, to reflect current experience. As changes in estimates occur, the carrying amount of the obligation and asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate. If our assumptions differ from actual experience, or if changes in the regulatory environment occur, our actual cash expenditures and costs that we incur could be materially different

70

than currently estimated. At December 31, 2011, we had recorded asset retirement obligation liabilities of $75.1 million, including amounts reported as current.

Employee Benefits

        We provide a range of benefits to our employees and retirees, including pensions and postretirement healthcare. We record annual amounts relating to these plans based on calculations specified by U.S. GAAP, which include various actuarial assumptions used in developing the required estimates including the following key factors:

•

Discount rate

•

Salary growth

•

Retirement rates

•

Mortality rates

•

Healthcare cost trends

•

Expected return on plan assets

	Pension Benefits						Other Benefits
	December 31, 2011			December 31, 2010			December 31, 2011			December 31, 2010
Weighted average assumptions used to determine benefit obligations:
Discount rate		5.02	%		5.30	%		5.14	%		5.35	%
Rate of compensation increase		3.70	%		3.70	%		—			—
Weighted average assumptions used to determine net periodic cost:
Discount rate		5.30	%		5.90	%		5.35	%		5.90	%
Expected return on plan assets		7.75	%		8.25	%		—			—
Rate of compensation increase		3.70	%		3.70	%		—			—

	December 31,
	2011						2010
	Pre-65			Post-65			Pre-65			Post-65
Assumed health care cost trend rates:
Health care cost trend rate assumed for next year		8.00	%		8.00	%		7.50	%		7.50	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		5.00	%		5.00	%		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate		2018			2018			2016			2016

        We review our actuarial assumptions on an annual basis and make modifications to the assumptions based on current rates and trends when appropriate. As required by U.S. GAAP, the effects of modifications are amortized over future periods. Assumed healthcare cost trend rates, discount rates, expected return on plan assets and salary increases have a significant effect on the amounts reported for the pension and healthcare plans. A one-percentage-point change in the rate for

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each of these assumptions would have had the following effects as of and for the year ended December 31, 2011 (in thousands):

	Increase (Decrease)
	1-Percentage Point Increase			1-Percentage Point Decrease
Healthcare cost trend:
Effect on total of service and interest cost components	$	4,580		$	(3,693	)
Effect on postretirement benefit obligation	$	79,862		$	(65,409	)
Discount rate:
Effect on postretirement service and interest cost components	$	13,897		$	(85	)
Effect on postretirement benefit obligation	$	(68,165	)	$	84,930
Effect on current year postretirement expense	$	(3,820	)	$	4,621
Effect on pension service and interest cost components	$	127		$	(237	)
Effect on pension benefit obligation	$	(26,555	)	$	32,101
Effect on current year pension expense	$	(2,554	)	$	2,995
Expected return on plan assets:
Effect on current year pension expense	$	(1,905	)	$	1,905
Rate of compensation increase:
Effect on pension service and interest cost components	$	444		$	(396	)
Effect on pension benefit obligation	$	3,452		$	(3,185	)
Effect on current year pension expense	$	836		$	(757	)

        We also have significant liabilities for uninsured or partially insured employee-related liabilities, including workers' compensation liabilities, miners' Black Lung benefit liabilities, and liabilities for various life and health benefits. The recorded amounts of these liabilities are based on estimates of loss from individual claims and on estimates determined on an actuarial basis from historical experience using assumptions regarding rates of successful claims, discount factors, benefit increases and mortality rates.

        Workers' compensation and Black Lung benefit liabilities are also affected by discount rates used. Changes in the frequency or severity of losses from historical experience and changes in discount rates or actual losses on individual claims that differ materially from estimated amounts could affect the recorded amount of these liabilities. At December 31, 2011, a one-percentage-point increase in the discount rate on the discounted Black Lung liability would decrease the liability by $1.8 million, while a one-percentage-point decrease in the discount rate would increase the liability by $2.3 million.

        For the workers' compensation liability, we apply a discount rate at a risk-free interest rate, generally a U.S. Treasury bill rate, for each policy year. The rate used is one with a duration that corresponds to the weighted average expected payout period for each policy year. Once a discount rate is applied to a policy year, it remains the discount rate for the year until all claims are paid. The use of this method decreases the volatility of the liability as impacted by changes in the discount rate. At December 31, 2011, a one-percentage-point increase in the discount rate on the discounted workers' compensation liability would decrease the liability by $0.1 million, while a one-percentage-point decrease in the discount rate would increase the liability by $0.1 million.

72

Income Taxes

        Accounting principles generally accepted in the U.S. require that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. Deferred tax assets are required to be reduced by a valuation allowance if it is "more likely than not" that some portion or the entire deferred tax asset will not be realized. As of December 31, 2011 we had valuation allowances totaling $1.7 million primarily for capital loss carry forwards not expected to provide future tax benefits. In our evaluation of the need for a valuation allowance, we considered various factors including the reversal of taxable temporary differences, expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in this evaluation, we may need to record a charge to earnings to reflect the change in our expected valuation of the deferred tax assets.

        As discussed in Note 9 of "Notes to Consolidated Financial Statements," we are in dispute with the Internal Revenue Service (the "IRS") on a number of federal income tax issues, primarily related to the discontinued Homebuilding and Financing businesses. We believe that our tax filing positions have substantial merit and we intend to vigorously defend these positions. We have established accruals that we believe are sufficient to address claims related to our uncertain tax positions, including related interest and penalties. Since the issues involved are highly complex, are subject to the uncertainties of extensive litigation and/or administrative processes and may require an extended period of time to reach ultimate resolution, it is possible that management's estimate of this liability could change.

Accounting for the Impairment of Long-Lived Assets

        Mineral interests, property, plant and equipment and other long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the book value of the asset may not be recoverable. We periodically evaluate whether events and circumstances have occurred that indicate possible impairment and, if so, assessing whether the asset net book values are recoverable from estimated future undiscounted cash flows. The actual amount of an impairment loss to be recorded, if any, is equal to the amount by which the asset's net book value exceeds its fair market value. Fair market value is generally based on the present values of estimated future cash flows in the absence of quoted market prices. Inherent in our development of cash flow projections are assumptions and estimates derived from a review of our operating results, operating budgets, expected growth rates, and cost of capital. We also make certain assumptions about future economic conditions, interest rates and other market data. Many of the factors used in assessing fair value are outside of management's control and these assumptions and estimates can change in future periods.

Accounting for Natural Gas Exploration Activities

        We apply the successful efforts method of accounting for our natural gas exploration activities. The costs of drilling exploratory wells are initially capitalized, pending determination of a commercially sufficient quantity of proved reserves attributable to the area as a result of drilling. If a commercially sufficient quantity of proved reserves is not discovered, any associated previously capitalized exploration costs associated with the drilling area are expensed. In some circumstances, it may be uncertain whether sufficient proved reserves have been found when drilling of an individual exploratory well has been completed. Such exploratory drilling costs, as well as additional exploratory well costs for the area, may continue to be capitalized if the reserve quantity is sufficient to justify the area's completion as a producing well, or field of production and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. At December 31, 2011 and 2010, capitalized exploratory drilling costs were $43.9 million and $37.3 million, respectively. Costs to develop proved reserves, including the cost of all development wells and related equipment used in the production of natural gas, are capitalized.

73

Goodwill

        As of December 31, 2011 we had goodwill of $1.1 billion. Goodwill represents the excess of the purchase price over the fair value assigned to the net tangible and identifiable intangible assets acquired in a business combination. Goodwill is not amortized, but tested for impairment annually or when circumstances indicate a possible impairment may exist. We perform our annual goodwill testing as of the beginning of the fourth quarter at the reporting unit level. The fair value of each reporting unit is determined using valuation models and expected future cash flows projections, which are then discounted using a risk-adjusted discount rate. A number of significant assumptions and estimates are involved in forecasting future cash flows including markets, sales volumes and prices, costs to produce, capital spending, working capital changes and the discount rate. Our assumptions regarding future prices and sales volumes require significant judgment as actual prices and volumes have fluctuated in the past and will likely continue to do so. Changes in market conditions could result in impairment charges in the future. Management considers historical experience and all available information at the time the fair values of its reporting units are estimated.

NEW ACCOUNTING PRONOUNCEMENTS

        In June 2011, the Financial Accounting Standards Board ("FASB") issued an accounting standard update that requires companies to present the components of net income and other comprehensive income either in a single continuous statement or as two separate but consecutive statements. The accounting standard update eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders' equity, and is effective for interim and annual periods beginning after December 15, 2011. The adoption of this accounting standard update will not have an impact on the Company's operating results or financial position as it only requires a change in the format of our current presentation of comprehensive income.

        In September 2011, the FASB issued an accounting standard update that requires employers that participate in multiemployer pension plans to provide additional quantitative and qualitative disclosures. The amended disclosures provide users with more detailed information about an employer's involvement and related commitments associated with multiemployer pension plans and became effective for the year ended December 31, 2011. See Note 11 of "Notes to Consolidated Financial Statements" for discussion of the multiemployer pension plan in which the Company participates.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

        We are exposed to certain market risks inherent in our operations. These risks generally arise from transactions entered into in the normal course of business. The primary market risk exposures relate to commodity price risk, interest rate risk and foreign currency risks. We do not enter into derivatives or other financial instruments for trading or speculative purposes.

Interest Rate Risk

        We have exposure to changes in interest rates under the 2011 Credit Agreement through our term loan A, term loan B and Revolver loans. The interest rates for the term loan A, term loan B and revolver loans are tied to LIBOR or the Canadian Dealer Offered Rate ("CDOR"), plus a credit spread ranging from 225 to 300 basis points for the revolver and term loan A and 275 to 300 basis points on the term loan B adjusted quarterly based on our total leverage ratio as defined by the 2011 Credit Agreement. As of December 31, 2011, our borrowings due under the 2011 Credit Agreement totaled $2.239 billion. As of December 31, 2011 a 100 basis point increase in interest rates would increase our yearly expense by approximately $11.5 million while a 100 basis point decrease in interest rates would decrease our yearly interest expense by approximately $2.2 million due to the LIBOR floor.

74

        Our objective in managing exposure to interest rate changes is to protect against the variability in expected future cash flows attributable to changes in the benchmark interest rate related to interest payments required under the 2011 Credit Agreement. To achieve this objective, we manage a portion of our interest rate exposure through the use of interest rate swaps and an interest rate cap. To reduce our exposure to rising interest rates and the risk that changing interest rates could have on our operations, during June 2011 we entered into an interest rate swap agreement and an interest rate cap agreement as described in Note 15 of "Notes to Consolidated Financial Statements." The interest rate swap agreement has a notional value of $450.0 million and is based on a 1.17% fixed rate. The interest rate cap agreement has a notional value of $255.0 million and has a strike price of 2.00%.

Commodity Risks

        We are exposed to commodity price risk on sales of natural gas. Our natural gas business sold 12.4 billion cubic feet of gas during the year ended December 31, 2011.

        We occasionally utilize derivative commodity instruments to manage the exposure to changing natural gas prices. Such derivative instruments are structured as cash flow hedges and not for trading. These swap contracts effectively converted a portion of forecasted sales at floating-rate natural gas prices to a fixed-rate basis. As described in Note 15 of "Notes to Consolidated Financial Statements," in order to reduce the risk associated with natural gas price volatility, on June 7, 2011 we entered into a one year swap contract to hedge 4.2 million MMBTUs of natural gas sales at a price of $5.00 per MMBTU beginning in July 2011 and ending June 2012. The swap agreement will hedge approximately 35% of anticipated natural gas sales from July 2011 until June 2012. During 2010, we hedged approximately 15% of our natural gas sales with swap contracts. At December 31, 2010, no swap contracts were outstanding.

Item 8.    Financial Statements and Supplementary Data

        Financial Statements and Supplementary Data consist of the financial statements as indexed on page F-1 and unaudited financial information presented in Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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

None

Item 9A.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

        An evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Interim Principal Financial Officer, of the effectiveness of our disclosure controls and procedures as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as amended ("Exchange Act") as of the end of the period covered by this annual report on Form 10-K. Based on that evaluation, our management, including our Chief Executive Officer and Interim Principal Financial Officer, concluded that our disclosure controls and procedures were effective as of December 31, 2011 to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and (2) accumulated and communicated to our management, including our Chief Executive Officer and Interim Principal Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

75

Management's Annual Report on Internal Control over Financial Reporting

        Management, under the supervision of our Chief Executive Officer and Interim Principal Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

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

        Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") inInternal Control-Integrated Framework. Based on this assessment, management has concluded that, as of December 31, 2011, our internal control over financial reporting was effective.

        Management's assessment of and conclusion on the effectiveness of our internal control over financial reporting as of December 31, 2011 excludes the internal control over financial reporting of Western Coal acquired on April 1, 2011 (as defined and described in Note 3 of "Notes to Consolidated Financial Statements"). Registrants are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year if, among other circumstances and factors, there is not adequate time between the consummation date of the acquisition and the assessment date for assessing internal controls.

        Our independent registered public accounting firm, Ernst & Young, has audited the effectiveness of our internal control over financial reporting, as stated in their attestation report included in this Annual Report on Form 10-K.

Evaluation of Changes in Internal Control over Financial Reporting

        There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the year ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

Item 9B.    Other Information

None

76

Part III

Item 10.    Directors, Executive Officers and Corporate Governance

Executive Officers of the Registrant

        Set forth below is a list showing the names, ages and positions of the executive officers of the Company.

Name	Age		Position
Walter J. Scheller, III		51	Chief Executive Officer
Robert P. Kerley		50	Chief Accounting Officer, Vice President and Corporate Controller (Interim Principal Financial Officer)
Michael T. Madden		60	Senior Vice President, Marketing
James M. Griffin		58	Senior Vice President, Business Development
Earl H. Doppelt		58	Senior Vice President, General Counsel and Secretary
Richard A. Donnelly		57	President, Jim Walter Resources, Inc.
Daniel P. Cartwright		59	President, Canadian Operations
Charles C. Stewart		56	President and Chief Operating Officer, Walter Coke, Inc. and Walter Minerals, Inc.

        Our executive officers as of February 29, 2012, are listed below.

Walter J. Scheller, III was appointed Chief Executive Officer of Walter Energy in September 2011 after serving as President and Chief Operating Officer of the Company's primary subsidiary, Jim Walter Resources, beginning in June 2010. Prior to joining Walter Energy, Mr. Scheller served from June 2006 until June 2010 at Peabody Energy Corporation as Group Executive, Colorado Operations and before that Senior Vice President, Strategic Operations. Prior to his career at Peabody, Mr. Scheller worked for CNX Gas Corporation as Vice President, Northern Appalachia Gas Operations as well as Consol Energy where he held a number of executive and operational roles, the last of which was Vice President, Operations. Mr. Scheller holds an MBA from University of Pittsburgh—Joseph M. Katz Graduate School of Business, a Juris Doctor degree from Duquesne University and a bachelor's degree in mining engineering from West Virginia University.

Robert P. Kerley was named Walter Energy's Chief Accounting Officer, Vice President, Corporate Controller and Interim Principal Financial Officer in July 2011 and was previously Vice President and Corporate Controller since joining the Company in September 2010. Prior to his career with Walter Energy, Mr. Kerley held various senior finance positions across the globe for more than 20 years, including most recently (from September 2006 to September 2010) as Vice President and Corporate Controller—Worldwide at Avocent Corporation, a developer and manufacturer of server and desktop management solutions. Prior to Avocent, he held the position of Senior Director and Divisional Chief Financial Officer for the Mobile Computing Division at Symbol Technologies, a manufacturer and worldwide supplier of mobile data capture delivery equipment. Before Symbol Technologies, Mr. Kerley worked in Asia for more than eight years in multiple senior management positions. Mr. Kerley began his accounting career in June 1985 with Arthur Andersen & Co. He is a Certified Public Accountant and holds a Bachelor of Science degree in accounting from Oklahoma Christian University (formerly Oklahoma Christian College).

Michael T. Madden was appointed Senior Vice President, Marketing for Walter Energy in April 2011 after serving as Senior Vice President, Sales and Marketing since February 2010 and Vice President, Marketing, Transportation, and Quality Control since 1997 for the Company's primary subsidiary, Jim Walter Resources. Prior to beginning his career with the Company in 1997, Mr. Madden held various management positions in the coal industry for both the domestic and export markets from 1974 through 1996. He is a member of the National Mining Association, the Alabama Coal

77

Association, and the Coal Trade Association of New York, and he previously served as a director of the Coal Exporters Association. Mr. Madden holds a bachelor's degree in marketing from St. Bonaventure University.

James M. Griffin was named Senior Vice President, Business Development of Walter Energy in April 2011 after serving as Global Head, Commercial and Business Development since joining the Company's subsidiary, Western Coal, in September 2010. Prior to joining Walter Energy, Mr. Griffin previously held a Managing Director role at Rothschild Inc.'s investment bank from April 1998 to September 2010 where he had primary responsibility for initiating its North American coal practice. Prior to that, Mr. Griffin managed the global mining and metals group at Chase Manhattan Bank where he was an employee from May 1981 to April 1998. His previous experience also includes progressively challenging senior mining engineering positions at Consol Energy, Union Pacific Corporation, and Energy Fuels Corporation. Mr. Griffin holds a degree in mining engineering from McGill University in Montreal, Canada.

Earl H. Doppelt was named Senior Vice President, General Counsel and Secretary of Walter Energy in January 2012. With more than 30 years of legal experience, he joined the Company from Information Services Group, Inc. where he served as Executive Vice President, General Counsel and Secretary from December 2006 to May 2010. Mr. Doppelt has also served as the senior legal officer of other major global companies, including The Nielsen Corporation (formerly VNU), ACNielsen Corporation, The Dun & Bradstreet Corporation and Paramount Communications Inc. He is a summa cum laude graduate of Cornell Law School and University of Rochester.

Richard A. Donnelly was named President, Jim Walter Resources (JWR) in January 2012 after most recently serving as Vice President, Engineering at JWR since March 2003. Beginning his career with the Company in 1977, Mr. Donnelly has extensive experience in all aspects of the mining business. He has held numerous positions within the engineering and operations areas of various Walter Energy properties, including Deputy Mine Manager and Mine Manager positions as well as Vice President, Operations. Mr. Donnelly holds a Bachelor of Science degree in mining engineering from the University of Missouri—Rolla.

Daniel P. Cartwright was appointed President, Canadian Operations in January 2012. Mr. Cartwright joined Walter Energy in July 2011 as Vice President, Underground Mining Operations. With more than 37 years of mining experience, he previously worked for Peabody Energy from January 2011 to December 2011 as Vice President, Operations Support—Powder River Basin and Southwest where he supported six large mines across Wyoming, New Mexico and Arizona. Prior to that, from May 2004 to December 2010 Mr. Cartwright was Operations Director—North Antelope Rochelle Operations Unit, Peabody's flagship operation. He also served Shell Mining Company for more than 15 years in various positions, the last of which was President, Shell/Marrowbone Development Company. Mr. Cartwright graduated summa cum laude from University of Missouri—Rolla with a Bachelor of Science degree in mining engineering.

Charles C. Stewart has served as President and Chief Operating Officer of Walter Coke, Inc. since May 2003, as well as President and Chief Operating Officer of Walter Minerals, Inc. since November 2010 after previously serving Walter Minerals as President since July 2007. In 2011, he also assumed responsibility for Walter Energy's operations in West Virginia and Wales. Beginning his career with the Company in 1978, Mr. Stewart has held a number of progressively responsible leadership roles in various mining and engineering capacities across the Company, culminating in his appointment as Vice President, Engineering. Mr. Stewart holds an MBA from Samford University and a Bachelor of Science degree in mineral engineering from the University of Alabama.

78

Code of Conduct

        The Board has adopted a Business Ethics and Code of Conduct ("Code of Conduct") which is applicable to all employees, directors and officers of the Company. The Code of Conduct is posted on our website atwww.walterenergy.com and is available in print to stockholders who request a copy. We have made available an Ethics Hotline, where employees can anonymously report a violation of the Code of Conduct.

Additional Information

        Additional information, as required in Item 10, "Directors and Executive Officers of the Registrant" are incorporated by reference to the Proxy Statement (the "2012 Proxy Statement") included in the Schedule 14A to be filed by the Company with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended.

Item 11.    Executive Compensation

        Incorporated by reference to the 2012 Proxy Statement.

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

        The equity compensation plan information as required by Item 201(d) of Regulation S-K is illustrated in Part II, Item 5 of this document. All other information as required by Item 12 is incorporated by reference to the 2012 Proxy Statement.

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

        Incorporated by reference to the 2012 Proxy Statement.

Item 14.    Principal Accounting Fees and Services

        Incorporated by reference to the 2012 Proxy Statement.

PART IV

Item 15.    Exhibits, Financial Statement Schedules

(a)

For Financial Statements—See Index to Financial Statements on page F-1. For Exhibits—See Item 15(b).



(b)

For Exhibits—See Index to Exhibits on pages E-1-E-5.

79

SIGNATURES

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

	WALTER ENERGY, INC.
February 29, 2012	/s/ WALTER J. SCHELLER, III Walter J. Scheller, III, Chief Executive Officer (Principal Executive Officer)

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

February 29, 2012	/s/ ROBERT P. KERLEY Robert P. Kerley, Chief Accounting Officer, Vice President and Corporate Controller (Interim Principal Financial Officer)
February 29, 2012	/s/ DAVID R. BEATTY David R. Beatty, O.B.E., Director*
February 29, 2012	/s/ HOWARD L. CLARK JR. Howard L. Clark, Jr., Director*
February 29, 2012	/s/ JERRY W. KOLB Jerry W. Kolb, Director*
February 29, 2012	/s/ PATRICK A. KRIEGSHAUSER Patrick A. Kriegshauser, Director*
February 29, 2012	/s/ JOSEPH B. LEONARD Joseph B. Leonard, Director*
February 29, 2012	/s/ GRAHAM MASCALL Graham Mascall, Director*
February 29, 2012	/s/ BERNARD G. RETHORE Bernard G. Rethore, Director*
February 29, 2012	/s/ MICHAEL T. TOKARZ Michael T. Tokarz, Chairman*
February 29, 2012	/s/ A.J. WAGNER A.J. Wagner, Director*

*By: /s/ EARL H. DOPPELT
Earl H. Doppelt
Attorney-in-Fact

80

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Walter Energy, Inc. and Subsidiaries
Reports of Independent Registered Certified Public Accounting Firm	F-2
Consolidated Balance Sheets—December 31, 2011 and 2010	F-4
Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2011	F-5
Consolidated Statements of Changes in Stockholders' Equity and Comprehensive Income for Each of the Three Years in the Period Ended December 31, 2011	F-6
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2011	F-7
Notes to Consolidated Financial Statements	F-9

F-1

Report of Independent Registered Public Accounting Firm

        The Board of Directors and Stockholders of Walter Energy, Inc.

        We have audited the accompanying consolidated balance sheets of Walter Energy, Inc and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in shareholders' equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Walter Energy, Inc. and subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Walter Energy, Inc.'s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 29, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young, LLP

Birmingham, Alabama
February 29, 2012

F-2

Report of Independent Registered Public Accounting Firm

        The Board of Directors and Shareholders of Walter Energy, Inc.

        We have audited Walter Energy, Inc. and subsidiaries' internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Walter Energy, Inc. and subsidiaries' management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

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

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

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

        As indicated in the accompanying Management's Annual Report on Internal Control over Financial Reporting, management's assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Western Coal Corp., which is included in the 2011 consolidated financial statements of Walter Energy, Inc. and constituted $5.1 billion and $3.8 billion of total and net assets, respectively, as of December 31, 2011 and $846.7 million and $60.5 million of revenues and net income, respectively, for the year then ended. Our audit of internal control over financial reporting of Walter Energy, Inc. also did not include an evaluation of the internal control over financial reporting Western Coal Corp.

        In our opinion, Walter Energy, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

        We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Walter Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in stockholders' equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011 and our report dated February 29, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young, LLP

Birmingham, Alabama
February 29, 2012

F-3

WALTER ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share amounts)

	December 31,
	2011			2010
ASSETS
Cash and cash equivalents	$	128,430		$	293,410
Receivables, net		313,343			143,238
Inventories		242,607			97,631
Deferred income taxes		61,079			62,371
Prepaid expenses		49,974			28,179
Other current assets		45,627			4,798
Current assets of discontinued operations		—			5,912
Total current assets		841,060			635,539
Mineral interests, net		2,946,113			17,305
Property, plant and equipment, net		1,637,182			772,696
Deferred income taxes		109,300			149,520
Goodwill		1,124,597			—
Other long-term assets		153,951			82,705
	$	6,812,203		$	1,657,765
LIABILITIES AND STOCKHOLDERS' EQUITY
Current debt	$	56,695		$	13,903
Accounts payable		112,661			70,692
Accrued expenses		229,067			52,399
Accumulated postretirement benefits obligation		27,247			24,753
Other current liabilities		59,827			24,362
Current liabilities of discontinued operations		—			7,738
Total current liabilities		485,497			193,847
Long-term debt		2,269,020			154,570
Deferred income taxes		1,003,383			—
Accumulated postretirement benefits obligation		550,671			451,348
Other long-term liabilities		381,537			262,934
Total liabilities		4,690,108			1,062,699
Commitments and Contingencies (Note 14)
Stockholders' equity:
Common stock, $0.01 par value per share:
Authorized—200,000,000 shares; issued—62,444,905 and 53,136,977 shares, respectively		624			531
Preferred stock, $0.01 par value per share:
Authorized—20,000,000 shares; issued—0 shares		—			—
Capital in excess of par value		1,620,430			355,540
Retained earnings		730,517			411,383
Accumulated other comprehensive income (loss):
Pension and other post-retirement benefit plans, net of tax		(225,541	)		(172,317	)
Foreign currency translation adjustment		(3,276	)		—
Unrealized loss on hedges, net of tax		(787	)		(71	)
Unrealized investment gain, net of tax		128			—
Total stockholders' equity		2,122,095			595,066
	$	6,812,203		$	1,657,765

The accompanying notes are an integral part of the consolidated financial statements.

F-4

WALTER ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)

	For the years ended December 31,
	2011			2010			2009
Revenues:
Sales	$	2,562,325		$	1,570,845		$	955,508
Miscellaneous income		9,033			16,885			11,319
		2,571,358			1,587,730			966,827
Cost and expenses:
Cost of sales (exclusive of depreciation and depletion)		1,561,112			766,516			586,774
Depreciation and depletion		245,509			98,702			72,939
Selling, general and administrative		165,749			86,972			70,510
Postretirement benefits		40,385			41,478			30,833
Restructuring and impairment charges		—			—			3,601
		2,012,755			993,668			764,657
Operating income		558,603			594,062			202,170
Interest expense		(96,820	)		(17,250	)		(18,975	)
Interest income		606			784			799
Other income, net		17,606			—			—
Income from continuing operations before income tax expense		479,995			577,596			183,994
Income tax expense		130,819			188,171			42,144
Income from continuing operations		349,176			389,425			141,850
Loss from discontinued operations		—			(3,628	)		(4,692	)
Net income	$	349,176		$	385,797		$	137,158
Basic income per share:
Income from continuing operations	$	5.79		$	7.32		$	2.67
Loss from discontinued operations		—			(0.07	)		(0.09	)
Net income	$	5.79		$	7.25		$	2.58
Diluted income per share:
Income from continuing operations	$	5.76		$	7.25		$	2.64
Loss from discontinued operations		—			(0.07	)		(0.09	)
Net income	$	5.76		$	7.18		$	2.55

The accompanying notes are an integral part of the consolidated financial statements.

F-5

WALTER ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
AND COMPREHENSIVE INCOME
FOR THE THREE YEARS ENDED DECEMBER 31, 2011
(in thousands, except per share amounts)

	Total			Common Stock			Capital in Excess of Par Value			Comprehensive Income			Retained Earnings (Deficit)			Treasury Stock		Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2008	$	630,269		$	541		$	714,174					$	50,990			—	$	(135,436	)
Comprehensive income:
Net income		137,158								$	137,158			137,158
Other comprehensive income, net of tax:
Change in pension and postretirement benefit plans, net of $44.2 million tax benefit		(28,513	)								(28,513	)							(28,513	)
Change in unrealized loss on hedges, net of $0.4 million tax		(877	)								(877	)							(877	)
Comprehensive income										$	107,768
Purchases of stock under stock repurchase program		(34,254	)		(14	)		(34,240	)
Stock issued upon exercise of stock options		9,888			6			9,882
Stock dividend for spin-off of Financing		(439,093	)					(321,301	)					(116,106	)				(1,686	)
Dividends paid, $0.40 per share		(21,190	)											(21,190	)
Stock based compensation		6,703						6,703
Other		(696	)					(696	)
Balance at December 31, 2009		259,395			533			374,522						50,852			—		(166,512	)
Comprehensive income:
Net income		385,797								$	385,797			385,797
Other comprehensive income, net of tax:
Change in pension and postretirement benefit plans, net of $2.2 million tax benefit		(5,280	)								(5,280	)							(5,280	)
Change in unrealized loss on hedges, net of $0.2 million tax		(596	)								(596	)							(596	)
Comprehensive income										$	379,921
Purchases of stock under stock repurchase program		(65,438	)		(9	)		(65,429	)
Stock issued upon exercise of stock options		17,134			8			17,126
Dividends paid, $0.475 per share		(25,266	)											(25,266	)
Stock based compensation		3,460						3,460
Excess tax benefits from stock-based compensation arrangements		28,875						28,875
Other		(3,015	)		(1	)		(3,014	)
Balance at December 31, 2010		595,066			531			355,540						411,383			—		(172,388	)
Comprehensive income:
Net income		349,176								$	349,176			349,176
Other comprehensive income:
Change in pension and postretirement benefit plans, net of $33.2 million tax benefit		(53,224	)								(53,224	)							(53,224	)
Change in unrealized loss on hedges, net of $0.3 million tax benefit		(716	)								(716	)							(716	)
Change in foreign currency translation adjustment		(3,276	)								(3,276	)							(3,276	)
Change in unrealized gain on investments, net of $0.09 million tax provision		128									128								128
Comprehensive income										$	292,088
Stock issued upon the exercise of stock options		8,920			3			8,917
Dividends paid, $0.50 per share		(30,042	)											(30,042	)
Stock based compensation		9,384						9,384
Excess tax benefits from stock-based compensation arrangements		8,929						8,929
Issuance of common stock in connection with the Western Coal Corp. acquisition		1,224,126			90			1,224,036
Fair value of replacement stock options and warrants issued in connection with the Western Coal Corp. acquisition		18,844						18,844
Other		(5,220	)					(5,220	)
Balance at December 31, 2011	$	2,122,095		$	624		$	1,620,430					$	730,517		$	—	$	(229,476	)

The accompanying notes are an integral part of the consolidated financial statements.

F-6

WALTER ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

	For the years ended December 31,
	2011			2010			2009
OPERATING ACTIVITIES
Net income	$	349,176		$	385,797		$	137,158
Loss from discontinued operations		—			3,628			4,692
Income from continuing operations		349,176			389,425			141,850
Adjustments to reconcile income from continuing operations to net cash flows provided by (used in) operating activities:
Depreciation and depletion		245,509			98,702			72,939
Deferred income tax provision		66,397			83,174			29,038
Amortization of debt issuance costs		21,154			2,975			2,559
Excess tax benefits from stock-based compensation arrangements		(8,929	)		(28,875	)		—
Gain on initial investment in Western Coal Corp		(20,553	)		—			—
Non-cash restructuring and impairment charges		—			—			3,601
Other		18,764			14,433			15,778
Decrease (increase) in current assets, net of effect of business acquisitions:
Receivables		(1,605	)		(65,935	)		69,772
Inventories		(1,885	)		1,966			(25,076	)
Prepaid expenses and other current assets		18,929			13,155			17,624
Increase (decrease) in current liabilities, net of effect of business acquisitions:
Accounts payable		13,676			23,717			(16,286	)
Accrued expenses and other current liabilities		6,233			41,413			(27,831	)
Cash flows provided by operating activities		706,866			574,150			283,968
INVESTING ACTIVITIES
Additions to property, plant and equipment		(436,705	)		(157,476	)		(96,298	)
Acquisition of Western Coal Corp., net of cash acquired		(2,432,693	)		—			—
Acquisition of HighMount Exploration & Production Alabama, LLC		—			(209,964	)		—
Proceeds from sales of investments		27,325			—			—
Other		1,413			(3,414	)		3,270
Cash flows used in investing activities		(2,840,660	)		(370,854	)		(93,028	)
FINANCING ACTIVITIES
Proceeds from issuance of debt		2,350,000			—			—
Borrowings under revolving credit agreement		71,259			—			—
Repayments on revolving credit agreement		(61,259	)		—			—
Retirements of debt		(290,630	)		(26,972	)		(61,597	)
Dividends paid		(30,042	)		(25,266	)		(21,190	)
Cash spun off to Financing		—			—			(33,821	)
Purchases of stock under stock repurchase program		—			(65,438	)		(34,254	)
Excess tax benefits from stock-based compensation arrangements		8,929			28,875			—
Proceeds from stock options exercised		8,920			17,134			9,888
Debt issuance costs		(80,027	)		—			—
Other		(5,203	)		(3,015	)		(6,169	)
Cash flows provided by (used in) financing activities		1,971,947			(74,682	)		(147,143	)
Cash flows provided by (used in) continuing operations		(161,847	)		128,614			43,797
CASH FLOWS FROM DISCONTINUED OPERATIONS
Cash flows provided by (used in) operating activities		—			(6,268	)		19,070
Cash flows provided by investing activities		—			5,066			27,379
Cash flows used in financing activities		—			—			(41,385	)
Cash flows provided by (used in) discontinued operations		—			(1,202	)		5,064
Effect of foreign exchange rates on cash		(3,668	)		—			—
Net increase (decrease) in cash and cash equivalents	$	(165,515	)	$	127,412		$	48,861

F-7

	For the years ended December 31,
	2011			2010			2009
Cash and cash equivalents at beginning of year	$	293,410		$	165,279		$	116,074
Add: Cash and cash equivalents of discontinued operations at beginning of year		535			1,254			1,598
Net increase (decrease) in cash and cash equivalents		(165,515	)		127,412			48,861
Less: Cash and cash equivalents of discontinued operations at end of year		—			535			1,254
Cash and cash equivalents at end of year	$	128,430		$	293,410		$	165,279
SUPPLEMENTAL DISCLOSURES:
Interest paid, net of capitalized interest	$	63,828		$	9,848		$	9,991
Income taxes paid	$	69,101		$	77,247		$	15,326
Non-Cash Investing Activities:
Acquisition of Western Coal in 2011 and HighMount in 2010:
Fair value of assets acquired	$	5,135,365		$	217,607			—
Less: fair value of liabilities assumed		(1,389,163	)		(7,643	)		—
fair value of shares of common stock issued		(1,224,126	)		—			—
fair value of stock options issued and warrants		(34,765	)		—			—
gain on initial investment		(20,553	)		—			—
cash acquired		(34,065	)		—			—
Net cash paid	$	2,432,693		$	209,964		$	—
Non-Cash Financing Activities:
One-year property insurance policy financing agreement	$	—		$	18,947		$	12,710
Dividend to spin off Financing	$	—		$	—		$	437,407

The accompanying notes are an integral part of the consolidated financial statements.

F-8

WALTER ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2011

NOTE 1—Organization

        Walter Energy, Inc. ("Walter"), together with its consolidated subsidiaries ("the Company"), is a leading producer and exporter of metallurgical coal for the global steel industry from underground and surface mines located in the United States, Canada and the United Kingdom. The Company also produces thermal coal, anthracite coal, metallurgical coke and coal bed methane gas.

        As described in Note 3, on April 1, 2011, the Company completed the acquisition of all the outstanding common shares of Western Coal Corp. ("Western Coal"). The accompanying financial statements include the results of operations of Western Coal since April 1, 2011. As a result of the Western Coal acquisition and the change in how our Chief Operating Decision Maker evaluates the business operations, beginning with the second quarter of 2011, the Company has revised its reportable segments by arranging them geographically. The Company now reports all of its operations located in the U.S. in the U.S. Operations segment which includes the Company's previous operating segments of Underground Mining, Surface Mining and Walter Coke. The U.S. Operations segment also includes the West Virginia mining operations acquired through the acquisition of Western Coal. The Company reports its mining operations acquired through the Western Coal acquisition located in Northeast British Columbia (Canada) and South Wales (United Kingdom) in the Canadian and U.K. Operations segment. The Other segment primarily consists of Corporate activities and expenditures. See Note 17 for segment information. Previously reported segment amounts have been restated to conform to the current period presentation.

        In December 2008, the Company announced the closure of its Homebuilding segment and Kodiak Mining Co. and on April 17, 2009 the Company spun off its Financing segment. As a result of the closure and spin-off, those segments are presented as discontinued operations for the years ended December 31, 2010 and 2009. See Note 4.

NOTE 2—Summary of Significant Accounting Policies

Basis of Presentation

        The consolidated financial statements include the accounts of all wholly and majority owned subsidiaries. Preparation of financial statements in accordance with accounting principles generally accepted in the U.S. requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements. Actual results could differ from those estimates. All significant intercompany balances and transactions have been eliminated. The notes to consolidated financial statements, except where otherwise indicated, relate to continuing operations only.

Concentrations of Credit Risk and Major Customers

        The Company's principal line of business is the mining and marketing of its metallurgical coal to foreign steel and coke producers. In 2011, approximately 76% of the Company's revenues were derived from coal shipments to these customers, located primarily in Europe, South America, and Asia. At December 31, 2011 and 2010, approximately 63% and 69%, respectively, of the Company's net receivables related to these customers. Furthermore, sales to a single customer represented 6.8%, 13.0% and 13.7% of consolidated revenues in 2011, 2010 and 2009, respectively, while sales to another single customer represented 6.2%, 10.3% and 12.6% of consolidated revenues in 2011, 2010 and 2009, respectively. Credit is extended based on an evaluation of the customer's financial condition. In some

F-9

instances, the Company requires letters of credit, cash collateral or prepayment for shipment from its customers to mitigate the risk of loss. These efforts have consistently led to minimal credit losses.

Revenue Recognition

        Revenue is recognized when the following criteria have been met: persuasive evidence of an arrangement exists; the price to the buyer is fixed or determinable; delivery has occurred; and collectability is reasonably assured. Delivery is considered to have occurred at the time title and risk of loss transfers to the customer. For coal shipments via rail, delivery generally occurs when the railcar is loaded. For coal shipments via ocean vessel, delivery generally occurs when the vessel is loaded. For coke shipments via rail or truck, revenue is recognized when title and risk of loss transfer to the customer, generally at the point of shipment. For the Company's natural gas operations, delivery occurs when the gas has been transferred to the customer's pipeline.

Shipping and Handling

        Costs to ship products to customers are included in cost of sales and amounts billed to customers, if any, to cover shipping and handling are included in sales.

Cash and Cash Equivalents

        Cash and cash equivalents include short-term deposits and highly liquid investments that have original maturities of three months or less when purchased and are stated at cost.

Allowances for Losses

        Allowances for losses on trade and other accounts receivables are based, in large part, upon judgments and estimates of expected losses and specific identification of problem trade accounts and other receivables. Significantly weaker than anticipated industry or economic conditions could impact customers' ability to pay such that actual losses may be greater than the amounts provided for in these allowances.

Inventories

        Inventories are valued at the lower of cost or market. The Company's coal inventory costs include labor, supplies, equipment costs, operating overhead, freight, royalties and other related costs. As of December 31, 2011, all of the Company's coal inventories are determined using the first-in, first-out ("FIFO") inventory valuation method. The Company's supplies inventories are determined using the average cost method of accounting. The valuation of coal inventories are subject to estimates due to possible gains and losses resulting from inventory movements from the mine site to storage facilities, inherent inaccuracies in belt scales and aerial surveys used to measure quantities and fluctuations in moisture content. Periodic adjustments to coal tonnages on hand are made for an estimate of coal shortages due to these inherent gains and losses, primarily based on historical findings, the results of aerial surveys and periodic coal pile clean-ups. Additionally, the Company evaluates its inventory in terms of excess and obsolete exposures. This evaluation includes such factors as anticipated usage, inventory turnover, inventory levels and ultimate market value.

Owned and Leased Mineral Interests

        Costs to obtain coal reserves and lease mineral rights are capitalized based on the fair value at acquisition and depleted using the unit-of-production method over the life of proven and probable reserves. Lease agreements are generally long-term in nature (original terms range from 10 to 50 years), and substantially all of the leases contain provisions that allow for automatic extension of the lease term providing certain requirements are met.

F-10

Property, Plant and Equipment

        Property, plant and equipment are recorded at cost. Depreciation is recorded principally on the straight-line method over the estimated useful lives of the assets. Leasehold improvements are amortized on the straight-line method over the lesser of the useful life of the improvement or the remaining lease term. Estimated useful lives used in computing depreciation expense range from 3 to 10 years for machinery and equipment, and from 15 to 30 years for land improvements and buildings, well life for gas properties and related development, and mine life for mine development costs. Gains and losses upon disposition are reflected in the statement of operations in the period of disposition. Maintenance and repair expenditures are charged to expense as incurred.

        Costs of developing new underground mines and certain underground expansion projects are capitalized. Underground development costs, which are costs incurred to make the coal physically accessible, may include construction permits and licenses, mine design, construction of access roads, main entries, airshafts, roof protection and other facilities. Costs of developing the first pit within a permitted area of a surface mine are capitalized up to the point of coal production attaining a level that would be more than de minimis. A surface mine is defined as the permitted mining area which includes various adjacent pits that share common infrastructure, processing equipment and a common coal reserve. Surface mine development costs include construction costs for entry roads, drilling, blasting and removal of overburden to access the first coal seam. Mine development costs are amortized primarily on a unit-of-production basis over the estimated reserve tons directly benefiting from the capital expenditures. Costs incurred during the production phase of a mine are capitalized into inventory and expensed to cost of sales as the coal is sold.

        Direct internal and external costs to implement computer systems and software are capitalized and are amortized over the estimated useful life of the system or software, generally 3 to 5 years, beginning when site installations or module development is complete and ready for its intended use.

        For the years ended December 31, 2011, 2010 and 2009, the Company capitalized interest costs in the amounts of $5.4 million, $1.4 million and $1.2 million, respectively.

        The Company has certain asset retirement obligations, primarily related to reclamation efforts for its mining operations. These obligations are recognized at fair value in the period in which they are incurred and the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its future value. The corresponding asset cost capitalized at inception is amortized over the useful life of the asset. The present values of the Company's asset retirement obligations were $75.1 million and $25.3 million as of December 31, 2011 and 2010, respectively. The increase is primarily attributable to $30.5 million of asset retirement obligations assumed in connection with the acquisition of Western Coal on April 1, 2011 as described in Note 3.

        The Company accounts for its natural gas exploration activities under the successful efforts method of accounting. Costs of exploratory wells are capitalized pending determination of whether the wells found commercially sufficient quantities of proved reserves. If a commercially sufficient quantity of proved reserves is not discovered, any associated previously capitalized exploratory costs associated with the drilling area are expensed. Costs of producing properties and natural gas mineral interests are amortized using the unit-of-production method. Costs incurred to develop proved reserves, including the cost of all development wells and related equipment used in the production of natural gas, are capitalized and amortized using the unit-of-production method. Unit-of-production amortization rates are revised when events and circumstances indicate an adjustment is necessary, but at least once a year, and such revisions are accounted for prospectively as changes in accounting estimates.

F-11

Impairment of Long-Lived Assets

        Property, plant and equipment and other long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the book value of the asset may not be recoverable. The Company periodically evaluates whether events and circumstances have occurred that indicate possible impairment. When impairment indicators exist, the Company uses an estimate of the future undiscounted net cash flows of the related asset or asset group over the remaining life in measuring whether or not the asset values are recoverable. Fair value is generally determined using market quotes, if available, or a discounted cash flow approach. There were no significant impairments of long-lived assets during the years ended December 31, 2011, 2010 or 2009.

Goodwill

        Goodwill represents the excess of the purchase price over the fair value assigned to the net tangible and identifiable intangible assets acquired in a business combination. Goodwill is to be tested for impairment at a minimum annually unless circumstances indicate a possible impairment may exist. The Company performs its annual goodwill testing as of the beginning of the fourth quarter at the reporting unit level. An impairment loss generally would be recognized when the carrying amount of the reporting unit exceeds the fair value of the reporting unit. The fair value of each reporting unit is determined using valuation models and expected future cash flows projections, which are then discounted using a risk-adjusted discount rate. A number of significant assumptions and estimates are involved in forecasting future cash flows including markets, sales volumes and prices, costs to produce, capital spending, working capital changes and the discount rate. Management considers historical experience and all available information at the time the fair values of its reporting units are estimated.

Workers' Compensation and Pneumoconiosis ("Black Lung")

        The Company is self-insured for workers' compensation benefits for work related injuries. Liabilities, including those related to claims incurred but not reported, are recorded principally using annual valuations based on discounted future expected payments and using historical data of the division or combined insurance industry data when historical data is limited. Workers' compensation liabilities were as follows (in thousands):

	December 31,
	2011		2010
Undiscounted aggregated estimated claims to be paid	$	43,501	$	45,497
Workers' compensation liability recorded on a discounted basis	$	36,987	$	37,761

        The Company applies a discount rate at a risk-free interest rate, generally a U.S. Treasury bill rate, for each policy year. The rate used is one with a duration that corresponds to the weighted average expected payout period for each policy year. Once a discount rate is applied to a policy year, it remains the discount rate for that year until all claims are paid. The weighted average rate used for discounting the 2011 policy year liability at December 31, 2011 was 0.81%. A one-percentage-point increase in the discount rate on the discounted claims liability would decrease the liability by $0.1 million, while a one-percentage-point decrease in the discount rate would increase the liability by $0.1 million.

        The Company is responsible for medical and disability benefits for black lung disease under the Federal Coal Mine Health and Safety Act of 1969, as amended, and is self-insured against black lung related claims. The Company performs an annual evaluation of the overall black lung liabilities at the December 31^st balance sheet date. The calculation is performed using assumptions regarding rates of successful claims, discount factors, benefit increases and mortality rates, among others. The present value of the obligation recorded by the Company using a discount factor of 5.14% for 2011 and 5.35% for 2010 was $12.0 million and $9.2 million as of December 31, 2011 and 2010, respectively. A

F-12

one-percentage-point increase in the discount rate on the discounted claims liability would decrease the liability by $1.8 million, while a one-percentage-point decrease in the discount rate would increase the liability by $2.3 million.

Derivative Instruments and Hedging Activities

        The Company enters into interest rate hedge agreements in accordance with the Company's internal debt and interest rate risk management policy, which is designed to mitigate risks related to floating rate financing agreements that are subject to changes in the market rate of interest. Changes in the fair value of interest rate hedge agreements that are designated and effective as hedges are recorded in accumulated other comprehensive income (loss) ("OCI"). Deferred gains or losses are reclassified from OCI to the statement of operations in the same period as the underlying transactions are recorded and are recognized in the caption, interest expense. Changes in the fair value of interest rate hedge agreements that are not effective as hedges would be recorded immediately in the statement of operations as interest expense.

        To protect against the reduction in the value of forecasted cash flows resulting from sales of natural gas, the Company periodically engages in a natural gas hedging program. The Company periodically hedges portions of its forecasted revenues from sales of natural gas with natural gas derivative contracts, generally either "swaps" or "collars". The Company enters into natural gas derivatives that effectively convert a portion of its forecasted sales at floating-rate natural gas prices to a fixed-rate basis, thus reducing the impact of natural gas price changes on revenues. When natural gas prices fall, the decline in value of future natural gas sales is offset by gains in the value of swap contracts designated as hedges. Conversely, when natural gas prices rise, the increase in the value of future cash flows from natural gas sales is offset by losses in the value of the swap contracts. Changes in the fair value of natural gas derivative agreements that are designated and effective as hedges are recorded in OCI. Deferred gains or losses are reclassified from OCI and recognized as miscellaneous income in the statement of operations in the same period as the underlying transactions are recognized. Changes in the fair value of natural gas hedge agreements that are not effective as hedges or are not designated as hedges would be recorded immediately in the statement of operations as miscellaneous income.

        During the three years ended December 31, 2011, the Company did not hold any non-derivative instruments designated as hedges or any derivatives designated as fair value hedges. In addition, the Company does not enter into derivative financial instruments for speculative or trading purposes. Derivative contracts are entered into only with counterparties that management considers creditworthy. Cash flows from hedging activities are reported in the statement of cash flows in the same classification as the hedged item, generally as a component of cash flows from operations.

Foreign Currency Translation

        The functional currency of the Company's Canadian operations is the U.S. dollar, while the U.K. operations functional currency is the British Pound. As such, monetary assets and liabilities are remeasured at period end exchange rates while non-monetary items are remeasured at historical rates. Income and expense accounts are remeasured at the average rates in effect during the year, except for those expenses related to balance sheet amounts that are remeasured at historical exchange rates. For the Company's Canadian operations, gains and losses from foreign currency remeasurement related to tax balances are included as a component of income tax expense while all other remeasurement gains and losses are included in miscellaneous income. For the Company's U.K. operations, foreign currency translation adjustments are reported in OCI. The foreign currency remeasurement gain recognized in miscellaneous income for the year ended December 31, 2011 was $3.8 million. The Company had no foreign operations prior to the acquisition of Western Coal on April 1, 2011 as described in Note 3.

F-13

Stock-Based Compensation

        The Company periodically grants stock-based awards to employees and its Board of Directors and records the related compensation expense during the period of vesting. This compensation expense is charged to the statement of operations with a corresponding credit to capital in excess of par value and is generally recognized utilizing the graded vesting method for stock options and the straight-line method for restricted stock units. The Company uses the Black-Scholes option pricing model to value its stock option grants and estimates forfeitures in calculating the expense related to stock-based compensation. See Note 5 for additional information on stock-based compensation.

Environmental Expenditures

        The Company capitalizes environmental expenditures that increase the life or efficiency of property or that reduce or prevent environmental contamination. The Company accrues for environmental expenses resulting from existing conditions that relate to past operations when the costs are probable and reasonably estimable. See Note 14 for additional discussion of environmental matters.

Income (Loss) per Share

        The Company calculates basic income (loss) per share based on the weighted average common shares outstanding during each period and diluted income (loss) per share based on weighted average common shares and dilutive common equivalent shares outstanding during each period. Dilutive common equivalent shares include the dilutive effect of stock awards, see Note 13.

NOTE 3—Acquisitions

        Western Coal Corp.    On November 18, 2010, the Company announced its intent to acquire all of the outstanding common shares of Western Coal. Western Coal is a producer of high quality metallurgical coal from mines in Northeast British Columbia (Canada), high quality metallurgical coal and compliant thermal coal from mines located in West Virginia (United States), and high quality anthracite coal from mines located in South Wales (United Kingdom). The acquisition of Western Coal substantially increased the Company's reserves available for future production, the majority of which is high-quality metallurgical coal, and created a diverse geographical footprint with strategic access to high-growth steel-producing countries in both the Atlantic and Pacific basins.

        On November 17, 2010, the Company entered into a share purchase agreement with various funds advised by Audley Capital to purchase approximately 54.5 million common shares, or 19.8%, of the outstanding common shares of Western Coal for CAD$11.50 per share in two separate transactions. On December 2, 2010 the Company entered into an arrangement agreement with Western Coal to acquire all the remaining outstanding common shares of Western Coal for CAD$11.50 per share in cash or 0.114 of a Walter Energy share, or for a combination thereof at the holder's election, subject to proration.

        In January 2011, the Company completed the first transaction to acquire 25,274,745 common shares of Western Coal, or 9.15% of the outstanding shares, from funds advised by Audley Capital. The shares were purchased for $293.7 million in cash and had a fair value of $314.2 million on April 1, 2011. The Company recognized a gain on April 1, 2011 of $20.5 million as a result of remeasuring to fair value the Western Coal shares acquired from Audley Capital which is included in other income in the Consolidated Statements of Operations for the year ended December 31, 2011. On April 1, 2011, the Company acquired the remaining outstanding common shares of Western Coal (including the second Audley Capital transaction) for a combination of $2.2 billion in cash and the issuance of 8,951,558 common shares of Walter Energy valued at $1.2 billion. The fair value of Walter Energy's common stock on April 1, 2011 was $136.75 per share based on the closing value on the New York Stock Exchange. The cash portion was funded with part of the proceeds from the new $2.725 billion

F-14

credit facility discussed in Note 10. All of the outstanding options to purchase Western Coal common shares that were not exercised prior to the acquisition were exchanged for fully-vested and immediately exercisable options to purchase shares of Walter Energy common stock. The Company issued 193,498 stock options in exchange for the Western Coal stock options outstanding as of April 1, 2011. The stock options issued had a fair value of $15.5 million, which was estimated using the Black-Scholes option pricing model. The outstanding warrants of Western Coal were not directly affected by the acquisition. Instead, upon exercise each warrant entitled the holder to receive cash and shares of Walter Energy common stock that would have been issued if the warrants had been exercised immediately before closing the acquisition.

        The purchase consideration has been preliminarily allocated to the assets acquired and liabilities assumed based upon their estimated fair values at the date of acquisition. A full and detailed valuation of the assets and liabilities is being completed with the assistance of an independent third party and certain information and analysis remains pending at this time. Accordingly, the allocation is preliminary and may change as additional information becomes available and is assessed by the Company. The final allocation of the consideration transferred may include adjustment to the fair value estimates of identifiable assets and liabilities, including but not limited to depreciable tangible assets, proven and probable reserves, reserves related to current development projects, value beyond proven and probable reserves, intangible assets and contract-related liabilities after a full review has been completed. The impact of such changes may be material. Fair values were determined using the income, cost and market price valuation methods as deemed appropriate.

        Management further refined information regarding acquired mineral interests during the fourth quarter of 2011 including refined estimates for future costs and production volumes and timing which resulted in a $1.4 billion reduction in fair value initially allocated to mineral interests. This also resulted in an increase in goodwill of $845.5 million and the deferred tax liability was reduced by $555.7 million reflecting a reduction in future depletion expense not deductible for tax. Changes made to the preliminary allocation of the purchase consideration and the alignment of accounting policies in the 2011 fourth quarter impacted the Company's previously reported quarterly results by an increase in net income of $7.8 million and a $0.13 increase in diluted net income per share for the three months ended June 30, 2011 and an increase in net income of $4.1 million and a $0.07 increase in diluted net income per share for the three months ended September 30, 2011. These amounts are included in the Company's results of operations for the year ended December 31, 2011. The Company did not consider the effect of these changes to be material to its second quarter 2011 and third quarter 2011 operating results or financial condition.

        The following tables summarizes the purchase consideration, the December 31, 2011 preliminary purchase price allocation, the preliminary purchase price allocation reported in the Company's quarterly report on Form 10-Q for the period ended September 30, 2011 and the adjustments made in the three months ended December 31, 2011 (in thousands):

Purchase consideration:
Cash	$	2,173,080
Fair value of shares of common stock issued		1,224,126
Fair value of stock options issued and warrants		34,765
Fair value of consideration transferred		3,431,971
Fair value of equity interest in Western Coal held before the acquisition		314,231
Total consideration	$	3,746,202

F-15

	Preliminary September 30, 2011		Adjustments			Preliminary December 31, 2011
Fair value of assets acquired and liabilities assumed:
Cash and cash equivalents	$	34,065	$	—		$	34,065
Receivables		163,668		—			163,668
Inventories		122,012		(783	)		121,229
Other current assets		65,606		20,869			86,475
Mineral interests		4,399,000		(1,407,000	)		2,992,000
Property, plant and equipment		565,228		(4,334	)		560,894
Goodwill		277,404		845,480			1,122,884
Other long-term assets		54,150		—			54,150
Total assets		5,681,133		(545,768	)		5,135,365
Accounts payable and accrued liabilities		180,157		4,826			184,983
Other current liabilities		75,824		6,351			82,175
Deferred tax liability		1,576,896		(555,735	)		1,021,161
Other long-term liabilities		102,054		(1,210	)		100,844
Total liabilities		1,934,931		(545,768	)		1,389,163
Net assets acquired	$	3,746,202	$	—		$	3,746,202

        Goodwill is calculated as the excess of the purchase consideration transferred over the fair value of the identifiable assets acquired and liabilities assumed. The factors that contribute to the recognition of goodwill include Western Coal's (i) historical cash flows and income levels, (ii) reputation in its markets, (iii) strength of its management team, (iv) efficiency of its operations, and (v) future cash flows and income growth projections. Goodwill has been assigned to the Canadian and U.K. Operations segment and the U.S. Operations segment in the amounts of $1.054 billion and $68.7 million, respectively. None of the goodwill is expected to be tax deductible. The Company incurred acquisition costs related to the purchase of approximately $23.2 million during the year ended December 31, 2011, which is included in selling, general and administrative expenses in the Company's Consolidated Statements of Operations.

        The amounts of revenues and earnings of Western Coal included in the Company's consolidated statement of operations from the acquisition date are as follows (in thousands):

	For the year ended December 31, 2011
Revenues	$	846,682
Net income	$	60,538

        The unaudited supplemental pro forma information presented below includes the effects of the Western Coal acquisition as if it had been completed as of January 1, 2010. The pro forma results include (i) the impact of certain estimated fair value adjustments, including additional estimated depreciation and depletion expense associated with the acquired mineral interests and property, plant and equipment and (ii) interest expense associated with debt used to fund the acquisition. The pro forma results for the year ended December 31, 2010 include adjustments for the financial impact of certain acquisition related items incurred during the year ended December 31, 2011. Accordingly, the following unaudited pro forma financial information should not be considered indicative of either

F-16

future results or results that might have occurred had the acquisition been consummated as of January 1, 2010 (in thousands):

	For the years ended December 31,
	2011		2010
Revenues	$	2,795,566	$	2,358,040
Net income	$	403,945	$	325,196

        North River Mine    On May 6, 2011, the Company acquired the North River thermal coal mine in Fayette and Tuscaloosa Counties of Alabama from a subsidiary of Chevron Corporation for $1.1 million in cash and the assumption of certain liabilities totaling approximately $90.9 million, including a $70.0 million below-market coal sales contract liability. The below-market contract has a remaining term of 26 months as of December 31, 2011 and such contracts acquired in a business combination are recorded at their fair value with this fair value being amortized into revenues over the tons of coal sold during the contract term. The Company has recognized goodwill of $1.7 million. None of the goodwill is expected to be tax deductible. The purchase consideration has been allocated to the assets acquired and liabilities assumed based upon their estimated fair values at the date of acquisition. The inclusion of this business for the current period did not have a material impact on either the Company's revenues or operating income, and the Company does not expect the results of this business to have a material effect on future operating results.

        HighMount Exploration & Production Alabama, LLC    On May 28, 2010, the Company acquired 100% of the issued and outstanding membership interests of HighMount Exploration & Production Alabama, LLC's ("HighMount") coal bed methane business for a cash payment of $210.0 million and renamed the business Walter Black Warrior Basin, LLC ("WBWB"). The fair value of the assets acquired and liabilities assumed totaled $217.6 million and $7.6 million, respectively. The Company incurred acquisition costs related to the purchase of approximately $2.7 million during the year ended December 31, 2010, which is included in selling, general and administrative expenses in the Company's Consolidated Statement of Operations. The acquisition of the coal bed methane operations included approximately 1,300 existing conventional gas wells, pipeline infrastructure and related equipment located adjacent to the Company's existing underground mining and coal bed methane business in Alabama. Current proven reserves are approximately 79 bcf (billion cubic feet), with annual coal bed methane production of approximately 8.0 bcf expected. The acquisition of this natural gas business, included in the U.S. Operations segment, helps ensure that future coal production areas will be properly degasified, thereby improving safety and operating efficiency of the Company's existing underground metallurgical coal production.

        WBWB's financial results have been included in the Company's financial statements since the date of acquisition. The inclusion of this business for 2010 and 2011 did not have a material impact on either the Company's revenues or operating income and the Company does not expect the results of this business to have a material impact in the foreseeable future. Assets acquired and liabilities assumed were recorded at estimated fair value as of the acquisition date. Fair values were determined using the income, cost and market price valuation methods as deemed appropriate. The following table

F-17

summarizes the fair value of the assets acquired and liabilities assumed at the acquisition date (in thousands):

Fair value of assets acquired and liabilities assumed:
Receivables	$	5,439
Other current assets		340
Property, plant and equipment		210,323
Identifiable intangible asset		1,505
Total assets		217,607
Accounts payable & accrued liabilities		(4,282	)
Asset retirement obligations		(3,361	)
Total liabilities		(7,643	)
Net assets acquired	$	209,964

NOTE 4—Discontinued Operations

        Spin-off of Financing    In 2009, the Company completed the spin-off of its Financing business and the merger of that business with Hanover Capital Mortgage Holdings, Inc. to create Walter Investment Management Corp. ("Walter Investment"), which operates as a publicly traded real estate investment trust. The subsidiaries and assets that Walter Investment owned at the time of the spin-off included all assets of Financing except for those associated with the workers' compensation program and various other run-off insurance programs within Cardem Insurance Co., Ltd. As a result of the spin-off, the Company no longer has any ownership interest in Walter Investment. Amounts previously reported in the Financing segment are presented as discontinued operations for the years ended December 31, 2010 and 2009.

        Closure of Homebuilding    In 2008, the Company made the decision to close the Homebuilding business. This decision was reached despite the efforts of management and employees, including a major restructuring during 2008 that closed nearly half of the sales centers. After the decision was made, the Company immediately took steps to liquidate the remaining assets and wind down the business. This wind down was substantially complete in 2009 and as a result, the Company has reported the results of operations, assets, liabilities and cash flows of the Homebuilding segment as discontinued operations for the years ended December 31, 2010 and 2009.

        Closure of Kodiak Mining Co.    In 2008, the Company announced the permanent closure of the underground coal mine operations of Kodiak Mining Company, LLC ("Kodiak"), which is wholly-owned by Walter Minerals, due to high operational costs, difficult operating conditions and a challenging pricing environment for Kodiak's product. As such, the Company has reported the results of operations, assets, liabilities and cash flows of Kodiak as discontinued operations for the years ended December 31, 2010 and 2009.

F-18

        The table below presents the significant components of operating results included in loss from discontinued operations (primarily Financing, Homebuilding and Kodiak) for the years ended December 31, 2010 and 2009 (in thousands):

	For the years ended December 31,
	2010			2009
Sales and revenues	$	4,293		$	83,673
Loss from discontinued operations before income tax expense (benefit)	$	(5,856	)	$	(3,725	)
Income tax expense (benefit)		(2,228	)		967
Loss from discontinued operations	$	(3,628	)	$	(4,692	)

        Prior to the Company discontinuing these operations, the Company allocated certain corporate expenses, limited to specifically identified costs and other corporate shared services which supported segment operations, to discontinued operations. These costs represented expenses that had historically been allocated to and recorded by the Company's operating segments as selling, general and administrative expenses. The Company did not elect to allocate corporate interest expense to discontinued operations.

        The remaining assets and liabilities of Homebuilding and Kodiak included as discontinued operations in the consolidated balance sheet as of December 31, 2010 are shown below (in thousands):

	December 31, 2010
Cash and cash equivalents	$	535
Receivables, net		563
Inventories		613
Property, plant and equipment, net		3,691
Other assets		510
Total assets(a)	$	5,912
Accounts payable	$	943
Accrued expenses		6,045
Other liabilities		750
Total liabilities(a)	$	7,738

(a)

Total assets and liabilities of discontinued operations are shown as "current" in the consolidated balance sheet at December 31, 2010.

NOTE 5—Equity Award Plans

        The stockholders of the Company approved the 2002 Long-Term Incentive Award Plan (the "2002 Plan"), under which an aggregate of 4.3 million shares of the Company's common stock, as restated to reflect the modification for the Financing spin-off, have been reserved for grant and issuance of incentive and non-qualified stock options, stock appreciation rights and stock awards.

        Under the 2002 Plan, an option becomes exercisable at such times and in such installments as set by the Compensation Committee of the Board of Directors (generally, vesting occurs over three years in equal annual increments), but no option will be exercisable after the tenth anniversary of the date on which it is granted. The Company may also issue restricted stock units. The Company has issued

F-19

restricted stock units which generally fully vest after three years of continuous employment or over three years in equal annual increments.

        Upon completion of the Western Coal acquisition, all of the outstanding options to purchase Western Coal common shares that were not exercised prior to the acquisition were exchanged for fully-vested and immediately exercisable Walter energy stock options. The Company issued 193,498 stock options in exchange for the Western Coal stock options outstanding as of April 1, 2011.

        For the years ended December 31, 2011, 2010 and 2009, the Company recorded stock-based compensation expense for its continuing operations related to equity awards totaling approximately $9.2 million, $3.3 million, and $6.7 million, respectively. These amounts are included in selling, general and administrative expenses and have been allocated to the reportable segments. The total income tax benefits in the Company's continuing operations recognized in the statements of operations for share-based compensation arrangements were $3.2 million, $1.2 million, and $2.4 million during 2011, 2010 and 2009, respectively.

        A summary of activity related to stock options during the year ended December 31, 2011, including awards applicable to discontinued operations, is presented below:

	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value ($000)
Outstanding at December 31, 2010		514,708		$	28.54
Granted		80,432		$	116.78
Granted in exchange for Western Coal stock options		193,498		$	50.16
Exercised		(265,833	)	$	33.70
Cancelled		(27,481	)	$	126.04
Outstanding at December 31, 2011		495,324		$	43.13		5.5	$	12,259
Exercisable at December 31, 2011		381,507		$	34.02		4.6	$	10,623

        Weighted average assumptions used to determine the grant-date fair value of options granted were:

	For the year ended December 31,
	2011(1)			2010			2009
Risk free interest rate		0.88	%		2.22	%		2.12	%
Dividend yield		0.52	%		0.75	%		0.75	%
Expected life (years)		2.46			5.10			5.24
Volatility		57.51	%		69.64	%		64.37	%

(1)

Includes fully vested replacement stock options issued on April 1, 2011 in connection with the acquisition of Western Coal described in Note 3, which significantly reduced the expected life as compared to prior periods.

        The risk-free interest rate is based on the U.S. Treasury yield in effect at the time of grant with a term equal to the expected life. The expected dividend yield is based on the Company's estimated annual dividend payout at grant date. The expected term of the options represents the period of time the options are expected to be outstanding. Expected volatility is based on historical volatility of the Company's share price for the expected term of the options.

F-20

        A summary of activity related to restricted stock units during the year ended December 31, 2011, including awards applicable to discontinued operations, is as follows:

	Shares			Aggregate Intrinsic Value ($000)		Weighted Average Remaining Contractual Term in Years
Outstanding at December 31, 2010		201,838
Granted		144,517
Vested		(127,598	)
Cancelled		(55,510	)
Outstanding at December 31, 2011		163,247		$	9,886		1.47

        The weighted-average grant-date fair values of stock options granted during the years ended December 31, 2011, 2010 and 2009 were $81.82, $46.43 and $10.67, respectively. The weighted-average grant-date fair values of restricted stock units granted during the years ended December 31, 2011, 2010 and 2009 were $133.15, $82.30 and $20.70, respectively. The total amount of cash received from exercise of stock options was $8.9 million, $17.1 million and $9.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. The total intrinsic value of stock awards exercised or converted during 2011 was $24.2 million and $7.7 million, respectively, and the total intrinsic value of stock awards exercised or converted during 2010 was $43.1 million and $11.0 million, respectively. The total intrinsic value of stock awards exercised or converted during 2009 was $20.0 million and $3.0 million, respectively. The total fair value of shares vested during the years 2011, 2010 and 2009 was $4.9 million, $5.8 million and $9.0 million respectively.

        Unrecognized compensation costs related to non-vested share-based compensation arrangements granted were approximately $12.6 million, $2.3 million and $5.4 million as of December 31, 2011, 2010 and 2009, respectively. These costs are to be recognized over a weighted average period of 2.3 years.

Employee Stock Purchase Plan

        All full-time employees of the Company who have attained the age of majority in the country in which they reside are eligible to participate in the employee stock purchase plan, which was adopted in January 1996 and amended in April 2004. The Company contributes a sum equal to 15% (20% after five years of continuous participation) of each participant's actual payroll deduction as authorized, and remits such funds to a designated brokerage firm that purchases, in the open market, shares of the Company's common stock for the accounts of the participants. The total number of shares that may be purchased under the plan is 3.5 million. Total shares purchased under the plan during the years ended December 31, 2011, 2010 and 2009 were approximately 29,500, 20,000 and 47,000, respectively, and the Company's contributions recognized as expense were approximately $0.4 million, $0.2 million and $0.3 million, respectively, during such years.

NOTE 6—Receivables

        Receivables are summarized as follows (in thousands):

	December 31,
	2011			2010
Trade receivables	$	233,568		$	130,904
Other receivables		86,493			14,856
Less: Allowance for losses		(6,718	)		(2,522	)
Receivables, net	$	313,343		$	143,238

F-21

NOTE 7—Inventories

        Inventories are summarized as follows (in thousands):

	December 31,
	2011		2010
Coal	$	182,707	$	69,110
Raw materials and supplies		59,900		28,521
Total inventories	$	242,607	$	97,631

NOTE 8—Mineral Interests and Property, Plant and Equipment

        The book value of mineral interests totaled $3,047.3 million and $34.9 million as of December 31, 2011 and 2010, respectively. Accumulated amortization totaled $101.2 million and $17.6 million as of December 31, 2011 and 2010, respectively.

        Property, plant and equipment are summarized as follows (in thousands):

	December 31,
	2011			2010
Land	$	85,439		$	68,695
Land improvements		14,484			12,356
Buildings and leasehold improvements		564,088			25,091
Mine development costs		36,861			84,930
Machinery and equipment		995,753			614,262
Gas properties and related development		222,711			305,697
Construction in progress		332,474			94,798
Total		2,251,810			1,205,829
Less: Accumulated depreciation and depletion		(614,628	)		(433,133	)
Net	$	1,637,182		$	772,696

NOTE 9—Income Taxes

        Income tax expense (benefit) applicable to continuing operations consists of the following (in thousands):

	For the years ended December 31,
	2011							2010						2009
	Current		Deferred			Total		Current		Deferred		Total		Current		Deferred			Total
Federal	$	37,307	$	82,228		$	119,535	$	77,400	$	75,579	$	152,979	$	3,423	$	35,515		$	38,938
State		6,226		3,129			9,355		27,597		7,595		35,192		9,683		(6,477	)		3,206
Foreign		20,889		(18,960	)		1,929		—		—		—		—		—			—
Total	$	64,422	$	66,397		$	130,819	$	104,997	$	83,174	$	188,171	$	13,106	$	29,038		$	42,144

        The foreign provision for income taxes is based on foreign pretax earnings of $64.8 million in 2011. The Company did not have foreign operations in 2010 and 2009. The Company records a provision for income taxes on amounts that may be repatriated but not on undistributed foreign earnings of the Company's foreign subsidiaries that are intended to be indefinitely reinvested in operations outside of the United States. As of December 31, 2011, United States income taxes have not been provided on the cumulative earnings of foreign subsidiaries considered to be indefinitely reinvested in operations outside of the United States.

F-22

        Deferred tax assets and liabilities reflect the effects of tax losses, credits, and the future income tax effects of temporary differences between the consolidated financial statements carrying amounts of existing assets and liabilities and their respective tax bases and are measured using enacted tax rates that apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.

        As of December 31, 2011 and December 31, 2010, the significant components of the Company's deferred income tax assets and liabilities were (in thousands):

	December 31,
	2011			2010
Deferred income tax assets:
Net operating loss and credit carryforwards	$	56,970		$	31,578
Accrued expenses		18,773			17,367
Contingent interest		36,441			33,515
Postretirement benefits other than pensions		219,399			183,711
Pension obligations		20,229			22,071
Other		31,623			29,476
Total deferred tax assets		383,435			317,718
Less: valuation allowance for deferred tax assets		(1,729	)		(1,549	)
Net deferred income tax asset		381,706			316,169
Deferred income tax liabilities:
Prepaid expenses		(12,069	)		(10,181	)
B.C. minerals tax		(262,413	)		—
Property, plant and equipment		(940,228	)		(94,097	)
Total deferred income tax liabilities		(1,214,710	)		(104,278	)
Net deferred income tax (liability) asset	$	(833,004	)	$	211,891
Deferred income taxes are classified as follows:
Current deferred income tax asset	$	61,079		$	62,371
Noncurrent deferred income tax asset		109,300			149,520
Noncurrent deferred income tax liability, net		(1,003,383	)		—
Net deferred tax (liability) asset	$	(833,004	)	$	211,891

        At December 31, 2011, approximately $41.0 million of federal net operating losses ("NOLs") and $71.6 million of state tax NOLs were available. The NOLs primarily expire between 2025 and 2031. We believe the U.S. operations will have sufficient taxable income to utilize the domestic NOLs prior to expiration.

        At December 31, 2011, approximately $161.9 million of non-U.S. NOLs were available. Canadian NOLs of $121.5 million will expire between 2025 and 2031. U.K. NOLs of $40.4 million have an indefinite carryforward period. As of December 31, 2011 we had valuation allowances totaling $1.7 million primarily for non-U.S. capital loss carry forwards not expected to provide future tax benefits.

F-23

        The income tax expense (benefit) at the Company's effective tax rate differed from the U.S. statutory rate of 35% as follows (in thousands):

	For the years ended December 31,
	2011			2010			2009
Income from continuing operations before income tax expense	$	479,995		$	577,596		$	183,994
Tax expense at statutory tax rate of 35%	$	167,998		$	202,159		$	64,398
Effect of:
Excess depletion benefit		(32,370	)		(31,572	)		(18,693	)
Impact of foreign taxes		(29,774	)		—			—
B.C. minerals tax		9,947			—			—
State and local income tax, net of federal effect		7,416			26,134			2,158
U.S. domestic production activities benefit		(5,583	)		(3,871	)		—
Acquisition costs		8,078			—			—
Other		5,107			(4,679	)		(5,719	)
Tax expense recognized	$	130,819		$	188,171		$	42,144

        Our effective tax rate for 2011 declined from 2010 due primarily to certain undistributed foreign earnings for which U.S. taxes are not provided because such earnings are intended to be indefinitely reinvested outside of the U.S. The effective tax rate was also impacted by certain foreign taxes, including the British Columbia, Canada minerals tax, which were not applicable to the Company in 2010.

        The Company's income taxes payable have been reduced by the tax benefits from employee stock plan awards. For stock options, the Company receives an income tax benefit calculated as the difference between the fair market value of the stock issued at the time of the exercise and the option price, tax effected. For restricted stock units, the Company receives an income tax benefit upon the award's vesting equal to the tax effect of the underlying stock's fair market value. The Company had net excess tax benefits from equity awards of $23.6 million, $16.8 million, and $6.8 million in 2011, 2010, and 2009, respectively.

        The Company files income tax returns in the U.S., Canada, UK, Australia and in various state, provincial and local jurisdictions which are routinely examined by tax authorities in these jurisdictions. The statute of limitations related to the U.S. consolidated federal income tax return is closed for the years prior to August 31, 1983 and for the years ended May 31, 1997, 1998 and 1999. The impact of any U.S. federal changes for these years on state income taxes remains subject to examination for a period up to five years after formal notification to the states. The Company generally remains subject to income tax in various states for prior periods ranging from three to eleven years depending on jurisdiction. In our major non-U.S. jurisdictions, tax years are typically subject to examination for three to six years.

        On December 27, 1989, the Company and most of its U.S. subsidiaries each filed a voluntary petition for reorganization under Chapter 11 of Title 11 of the United States Code (the "Bankruptcy Proceedings") in the United States Bankruptcy Court for the Middle District of Florida, Tampa Division (the "Bankruptcy Court"). The Company emerged from bankruptcy on March 17, 1995 (the "Effective Date") pursuant to the Amended Joint Plan of Reorganization dated as of December 9, 1994, as modified on March 1, 1995 (as so modified the "Consensual Plan"). Despite the confirmation and effectiveness of the Consensual Plan, the Bankruptcy Court continues to have jurisdiction over, among other things, the resolution of disputed prepetition claims against the Company and other matters that may arise in connection with or related to the Consensual Plan, including claims related to federal income taxes.

F-24

        In connection with the U.S. Bankruptcy Proceedings, the Internal Revenue Service ("IRS") filed a proof of claim in the Bankruptcy Court (the "Proof of Claim") for a substantial amount of taxes, interest and penalties with respect to fiscal years ended August 31, 1983 through May 31, 1994. The Company filed an adversary proceeding in the Bankruptcy Court disputing the Proof of Claim (the "Adversary Proceeding") and the various issues have been litigated in the Bankruptcy Court. An opinion was issued by the Bankruptcy Court in June 2010 as to the remaining disputed issues. The Bankruptcy Court instructed both parties to submit a proposed final order addressing all issues that have been litigated for the tax years 1983 through 1995 in the Adversary Proceeding by late August 2010. At the request of both parties, the Bankruptcy Court granted an extension of time of 90 days from the initial submission date to submit the proposed final order. Additional extensions of time to submit the proposed final order were granted in November 2010, February 2011, May 2011 and September 2011. At the request of both parties, in January 2012 the Bankruptcy Court granted an additional extension of time until May 10, 2012 to submit the proposed final order.

        The amounts initially asserted by the Proof of Claim do not reflect the subsequent resolution of various issues through settlements or concessions by the parties. The Company believes that any financial exposure with respect to those issues that have not been resolved or settled in the Proof of Claim is limited to interest and possible penalties and the amount of tax assessed has been offset by tax reductions in future years. All of the issues in the Proof of Claim, which have not been settled or conceded, have been litigated before the Bankruptcy Court and are subject to appeal but only at the conclusion of the entire Adversary Proceeding.

        The Company believes that those portions of the Proof of Claim, which remain in dispute or are subject to appeal, substantially overstate the amount of taxes allegedly owed. However, because of the complexity of the issues presented and the uncertainties associated with litigation, the Company is unable to predict the ultimate outcome of the Adversary Proceeding.

        The IRS completed its audit of the Company's federal income tax returns for the years ended May 31, 2000 through December 31, 2005. The IRS issued 30-Day Letters to the Company in June 2010, proposing changes to tax for these tax years. The Company filed a formal protest with the IRS within the prescribed 30-day time limit for those issues which have not been previously settled or conceded. The IRS filed a rebuttal to the Company's formal protest and the case was assigned to the Appeals Division of the IRS. The Appeals Division convened a hearing on March 8, 2011 and heard arguments from both parties as to issues not settled or conceded for the 2000 through 2005 audit period. At this time, no final resolution has been reached with the Appeals Division pertaining to these matters. The disputed issues in this audit period are similar to the issues remaining in the Proof of Claim and consequently, should the IRS prevail on its positions, the Company believes its financial exposure is limited to interest and possible penalties.

        The IRS is conducting an audit of the Company's income tax returns filed for 2006 through 2008. Since the IRS examination is ongoing, any resulting tax deficiency or overpayment cannot be estimated at this time. The Company expects the current IRS exam to conclude during 2012. During the next year, the statute of limitations for assessing additional income tax deficiencies will expire for certain tax years in several state tax jurisdictions. The expiration of the statute of limitations for these years is expected to have an immaterial impact on the total uncertain income tax positions and net income.

        The Company believes that all of its current and prior tax filing positions have substantial merit and intends to defend vigorously any tax claims asserted. The Company believes that it has sufficient accruals to address any claims, including interest and penalties, and as a result, believes that any potential difference between actual losses and costs incurred and the amounts accrued would be immaterial.

F-25

        A reconciliation of the beginning and ending balances of the total amounts of gross unrecognized tax benefits is as follows (in thousands):

	December 31,
	2011			2010
Gross unrecognized tax benefits at beginning of year	$	39,191		$	34,300
Increases for tax positions taken in prior years		31,704			5,216
Increases in tax positions for the current year		23,169			—
Decreases for changes in temporary differences		(1,306	)		(325	)
Gross unrecognized tax benefits at end of year	$	92,758		$	39,191

        The total amount of net unrecognized tax benefits that, if recognized, would affect the effective tax rate totaled $92.1 million and $37.3 million at December 31, 2011 and 2010, respectively. The Company recognizes interest expense and penalties related to unrecognized tax benefits in interest expense and selling, general and administrative expenses, respectively.

        For the years ended December 31, 2011, 2010 and 2009, interest expense includes $7.2 million, $5.6 million and $7.4 million, respectively, for interest accrued on the liability for unrecognized tax benefits and for issues identified in the Proof of Claim. As of December 31, 2011, the Company had accrued interest and penalties related to unrecognized tax benefits and the Adversary Proceeding of $105.3 million. Due to the uncertainties associated with litigation and the Adversary Proceeding, the Company is unable to predict the amount, if any, of the change in the gross unrecognized tax benefits balance in the next twelve months.

NOTE 10—Debt

        Debt consisted of the following (in thousands):

	December 31, 2011			December 31, 2010			Weighted Average Stated Interest Rate At December 31, 2011		Estimated Final Maturity
2011 term loan A	$	894,837		$	—			3.44%		2016
2011 term loan B		1,333,163			—			4.00%		2018
2005 term loan		—			136,062
Revolving credit facility		10,000			—			3.28%		2016
Other(1)		87,715			32,411			Various		Various
Total debt		2,325,715			168,473
Less current debt		(56,695	)		(13,903	)
Total long-term debt	$	2,269,020		$	154,570

(1)

This balance includes capital lease obligations (see Note 14) and an equipment financing agreement.

        The Company's minimum debt repayment schedule, excluding interest, as of December 31, 2011 is as follows (in thousands):

	Payments Due
	2012		2013		2014		2015		2016		Thereafter
2011 term loan A	$	19,837	$	82,500	$	112,500	$	517,500	$	162,500	$	—
2011 term loan B		—		—		—		—		10,163		1,323,000
Revolving credit facility		—		—		—		—		10,000		—
Other debt		36,858		27,215		17,530		6,058		54		—
	$	56,695	$	109,715	$	130,030	$	523,558	$	182,717	$	1,323,000

F-26

        2011 Credit Agreement    On April 1, 2011, the Company entered into a $2.725 billion credit agreement (the "2011 Credit Agreement") to partially fund the acquisition of Western Coal and to pay off all outstanding loans under the 2005 Credit Agreement described below. The 2011 Credit Agreement consists of (1) a $950.0 million principal amortizing term loan A facility maturing in April 2016, at which time the remaining outstanding principal is due, (2) a $1.4 billion principal amortizing term loan B facility maturing in April 2018, at which time the remaining outstanding principal is due and (3) a $375.0 million multi-currency revolving credit facility ("Revolver") maturing in April 2016, at which time any remaining balance is due. The Revolver provides for operational needs and letters of credit. The Company's obligations under the 2011 Credit Agreement are secured by substantially all of the Company's domestic and foreign real, personal and intellectual property. The 2011 Credit Agreement contains customary events of default and covenants, including among other things, covenants that restrict but do not prevent the ability of the Company and its subsidiaries to incur certain additional indebtedness, create or permit liens on assets, pay dividends and repurchase stock, engage in mergers or acquisitions and make investments and loans. The 2011 Credit Agreement also includes certain financial covenants that must be maintained.

        The Revolver, term loan A and term loan B interest rates are tied to LIBOR or the Canadian Dealer Offered Rate ("CDOR"), plus a credit spread ranging from 225 to 300 basis points for the Revolver and term loan A, and 275 to 300 basis points on the term loan B adjusted quarterly based on the Company's total leverage ratio as defined by the 2011 Credit Agreement. The term loan B has a minimum LIBOR floor of 1.0%. The Revolver loans can be denominated in either U.S. dollars or Canadian dollars at the Company's option. The commitment fee on the unused portion of the Revolver is 0.5% per year for all pricing levels. As of December 31, 2011, the Revolver had $10.0 million in borrowings, with $71.2 million outstanding stand-by letters of credit and $293.8 million of availability for future borrowings.

        2005 Credit Agreement, as Amended    On April 1, 2011, in connection with the acquisition of Western Coal, the Company repaid all outstanding loans and accrued interest under the 2005 credit agreement, as amended ("2005 Credit Agreement") and it was simultaneously terminated. No penalties were due in connection with the repayments. As of March 31, 2011 the 2005 Credit Agreement included (1) an amortizing term loan facility ("2005 Term Loan") with an initial aggregate principal amount of $450.0 million and (2) a $300.0 million revolving credit facility ("2005 Revolver") which provided for loans and letters of credit. The 2005 Term Loan bore interest at LIBOR plus as much as 300 basis points and required quarterly principal payments of $0.4 million through October 3, 2012, at which time the remaining outstanding principal was to be due. The 2005 Revolver bore interest at LIBOR plus as much as 400 basis points and was due to mature on July 2, 2012. The commitment fee on the unused portion of the 2005 Revolver was 0.5% per year for all pricing levels. The Company's obligations under the 2005 Credit Agreement were secured by substantially all of the Company's real, personal and intellectual property.

NOTE 11—Pension and Other Employee Benefits

        The Company has various defined benefit pension plans covering certain U.S. salaried employees and eligible hourly employees. In addition to its own pension plans, the Company contributes to a multi-employer defined benefit pension plan covering eligible employees who are represented by the United Mine Workers of America ("UMWA"). The Company funds its retirement and employee benefit plans in accordance with the requirements of the plans and, where applicable, in amounts sufficient to satisfy the "Minimum Funding Standards" of the Employee Retirement Income Security Act of 1974 ("ERISA"). The plans provide benefits based on years of service and compensation or at stated amounts for each year of service.

        The Company also provides certain postretirement benefits other than pensions, primarily healthcare, to eligible retirees. The Company's postretirement benefit plans are not funded. New

F-27

salaried employees have been ineligible to participate in postretirement healthcare benefits since May 2000. Effective January 1, 2003 the Company placed a monthly cap on Company contributions for postretirement healthcare coverage.

        The Company is required to measure plan assets and liabilities as of the fiscal year-end reporting date. As of December 31, 2011 and 2010, respectively, all of our pension plans have obligations that exceed plan assets. The amounts recognized for all of the Company's pension and postretirement benefit plans are as follows (in thousands):

	Pension Benefits						Other Benefits
	December 31, 2011			December 31, 2010			December 31, 2011			December 31, 2010
Accumulated benefit obligation	$	246,021		$	235,727		$	577,918		$	476,101
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	250,005		$	226,580		$	476,101		$	452,659
Service cost		5,163			4,419			6,160			3,014
Interest cost		12,576			12,906			25,140			26,040
Actuarial loss		5,895			16,338			84,796			16,594
Benefits paid		(11,027	)		(10,238	)		(21,813	)		(22,732	)
Plan amendments		375			—			104			—
Plan settlements		(4,207	)		—			—			—
Business combinations		—			—			7,430			—
Other		—			—			—			526
Benefit obligation at end of year	$	258,780		$	250,005		$	577,918		$	476,101
Change in plan assets:
Fair value of plan assets at beginning of year	$	191,736		$	160,944		$	—		$	—
Actual gain on plan assets		1,163			21,270			—			—
Employer contributions		24,871			19,760			21,813			22,732
Benefits paid		(11,026	)		(10,238	)		(21,813	)		(22,732	)
Plan settlements		(4,207	)		—			—			—
Fair value of plan assets at end of year	$	202,537		$	191,736			—			—
Unfunded status of the plan	$	(56,243	)	$	(58,269	)	$	(577,918	)	$	(476,101	)
Amounts recognized in the balance sheet:
Other current liabilities	$	(5,083	)	$	(8,892	)	$	—		$	—
Accumulated postretirement benefits obligation
Current							$	(27,247	)	$	(24,753	)
Long-term								(550,671	)		(451,348	)
Other long-term liabilities		(51,160	)		(49,377	)		—			—
Net amount recognized	$	(56,243	)	$	(58,269	)	$	(577,918	)	$	(476,101	)
Amounts recognized in accumulated other comprehensive income, pre-tax
Prior service cost	$	1,290		$	1,187		$	9,916		$	8,852
Net actuarial loss		106,479			96,090			275,049			200,299
Net amount recognized	$	107,769		$	97,277		$	284,965		$	209,151

F-28

        The components of net periodic benefit cost are as follows (in thousands):

	Pension Benefits									Other Benefits
	For the years ended December 31,									For the years ended December 31,
	2011			2010			2009			2011			2010			2009
Components of net periodic benefit cost:
Service cost	$	5,163		$	4,419		$	4,154		$	6,160		$	3,014		$	3,049
Interest cost		12,576			12,906			12,458			25,140			26,040			23,294
Expected return on plan assets		(15,717	)		(13,076	)		(11,304	)		—			—			—
Amortization of prior service cost (credit)		272			304			304			(961	)		(2,098	)		(1,950	)
Amortization of net actuarial loss		8,252			8,922			9,356			10,046			14,522			6,440
Settlement loss		1,807			—			—			—			—			—
Net periodic benefit cost for continuing operations	$	12,353		$	13,475		$	14,968		$	40,385		$	41,478		$	30,833

        The estimated portion of net prior service cost and net actuarial loss remaining in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost in 2012 are as follows (in thousands):

	Pension Benefits		Other Benefits
Prior service cost	$	256	$	1,045
Net actuarial loss		9,252		14,725
Net amount to be recognized	$	9,508	$	15,770

        Changes in plan assets and benefit obligations recognized in other comprehensive income as (income) loss in 2011 are as follows (in thousands):

	Pension Benefits			Other Benefits			Total
Current year net actuarial loss	$	20,544		$	84,796		$	105,340
Current year prior service cost		374			104			478
Amortization of actuarial loss		(10,059	)		(10,046	)		(20,105	)
Amortization of prior service cost (credit)		(272	)		961			689
Total		10,587			75,815			86,402
Deferred income taxes		(4,037	)		(29,141	)		(33,178	)
Total recognized in other comprehensive (income) loss, net of taxes	$	6,550		$	46,674		$	53,224

F-29

        A summary of key assumptions used is as follows:

	Pension Benefits									Other Benefits
	December 31,									December 31,
	2011			2010			2009			2011			2010			2009
Weighted average assumptions used to determine benefit obligations:
Discount rate		5.02	%		5.30	%		5.90	%		5.14	%		5.35	%		5.90	%
Rate of compensation increase		3.70	%		3.70	%		3.70	%		—			—			—
Weighted average assumptions used to determine net periodic cost:
Discount rate		5.30	%		5.90	%		6.50	%		5.35	%		5.90	%		6.50	%
Expected return on plan assets		7.75	%		8.25	%		8.90	%		—			—			—
Rate of compensation increase		3.70	%		3.70	%		3.70	%		—			—			—

	December 31,
	2011						2010						2009
	Pre-65			Post-65			Pre-65			Post-65			Pre-65			Post-65
Assumed health care cost trend rates at December 31:
Health care cost trend rate assumed for next year		8.00	%		8.00	%		7.50	%		7.50	%		8.00	%		8.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate		2018			2018			2016			2016			2016			2016

        The discount rate is based on a yield-curve approach which matches the expected cash flows to high quality corporate bonds available at the measurement date. The model constructs a hypothetical bond portfolio whose cash flows match the year-by-year, projected benefit cash flow from the benefit plan. The yield on this hypothetical portfolio is the maximum discount rate used. The yield curve is based on a universe of bonds available from the Barclays Capital bond database at the measurement date, with a quality rating of AA or better by Moody's or S&P. To minimize any potential distortion only bonds with significant issues of at least 100,000 outstanding are used. Bonds whose yields exceed two standard deviations from the yield curve derived from similar quality bonds are excluded. In addition, other tests are performed to eliminate bonds that do not appear to be priced properly by the market.

        The plan assets of the pension plans are held and invested by the Walter Energy, Inc. Subsidiaries Master Pension Trust ("Pension Trust"). The Pension Trust employs a total return investment approach whereby a mix of equity and fixed income investments are used to meet the long-term funding and near-term cash flow requirements of the pension plan. The asset mix strives to generate rates of return sufficient to fund plan liabilities and exceed the long-term rate of inflation, while maintaining an appropriate level of portfolio risk. Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio is diversified across domestic and foreign equity holdings, and by investment styles and market capitalizations. Domestic equity holdings primarily consist of investments in large-cap and mid-cap companies located in the United States, and of investments in collective trusts managed to replicate the investment performance of industry standard investment indexes. Foreign equity holdings primarily consist of investments in domestically managed mutual funds located in the United States. Fixed income holdings are diversified by issuer, security type and principal and interest payment characteristics. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investments. Fixed income and derivatives holdings primarily consist of investments in domestically managed mutual funds located in the United States. Investment risk is measured and monitored on an ongoing basis through quarterly

F-30

investment portfolio reviews, annual benefits liability measurements, and periodic asset/liability studies. Management believes the only significant concentration of investment risk lies in exposure to the U.S. domestic markets as compared to total global investment opportunities.

        Effective January 1, 2011, the Company lowered its expected return on plan assets from 8.25% to 7.75% given the decline in asset performance due to the ongoing global recession and disruption in the financial markets, as well as management's reevaluation of the ongoing impact of active management of assets by outside investment advisors. During 2009, the strategic allocation in the fixed income component was raised from 30% to 40% with a corresponding reduction in equity allocation from 70% to 60%. As a result of this change, the expected return on asset assumption decreased from 8.90% in 2009 to 8.25% in 2010. As of December 31, 2011, the Pension Trust's strategic asset allocation targets are as follows:

							Actual Allocation
	Strategic Allocation			Tactical Range
							2011			2010
Equity investments:
Large capitalization stocks		38.5	%		29-48	%		37.2	%		39.1	%
Mid capitalization stocks		8.5	%		6-11	%		9.5	%		11.2	%
Small capitalization stocks		0.0	%		0	%		0.0	%		0.0	%
International stocks		13.0	%		9-17	%		12.5	%		11.6	%
Total equity investments		60.0	%		50-70	%		59.2	%		61.9	%
Fixed income investments		40.0	%		30-50	%		39.0	%		37.5	%
Cash		0.0	%		0-5	%		1.8	%		0.6	%
Total		100.0	%					100.0	%		100.0	%

        These ranges are targets and deviations may occur from time-to-time due to market fluctuations. Portfolio assets are typically rebalanced to the allocation targets at least annually.

        As of December 31, 2011, the fair values of the Pension Trust's assets were as follows ($ in thousands):

Asset category			Level 1(L1)	Level 2(L2)	Level 3(L3)
Cash	$	3,568	X
Equity investments
Large cap value—Index(a)		16,586	X
Large cap value(b)		16,658	X
Large cap growth—Index(c)		21,195	X
Large cap growth(d)		20,894	X
Mid-cap growth(e)		19,350	X
International(f)		25,332	X
Fixed income investments:
Intermediate-term bond(g)		73,928	X
Long-term bond(h)		5,026	X
Total	$	202,537

(a)

This category comprises an investment in a low-cost, non-actively managed, U.S.-regulated equity index mutual fund that tracks the Russell 1000 Value Index.

(b)

This category comprises an investment in an actively managed, U.S.-regulated mutual fund with a goal of achieving a return above the Russell 1000 Value Index.

F-31

(c)

This category comprises an investment in a low-cost, non-actively managed, U.S.-regulated equity index mutual fund that tracks the Russell 1000 Growth Index.

(d)

This category primarily consists of U.S. common stocks selected using a large-capitalization, growth-oriented investment strategy with a goal of achieving a return above the Russell 1000 Growth Index.

(e)

This category primarily consists of U.S. common stocks selected using a mid-capitalization, growth-oriented investment strategy with a goal of achieving a return above the Russell Mid Cap Index.

(f)

This category comprises an investment in an actively managed, U.S.-regulated mutual fund with a goal of achieving a return above the MSCI EAFE Index.

(g)

This category comprises an investment in an actively managed, U.S.-regulated mutual fund with a goal of achieving a return above the Barclays Capital U.S. Aggregate Bond Index.

(h)

This category comprises an investment in a low-cost, non-actively managed, U.S.-regulated mutual fund that tracks the Barclays Capital U.S. Long Government/Credit Float Adjusted Index.

(L1)

These assets are equity securities or exchange traded funds whose fair value is determined from quoted prices on nationally recognized securities exchanges.

(L2)

The Pension Trust does not invest in any Level 2 assets with unobservable inputs.

(L3)

The Pension Trust does not invest in any Level 3 assets with significant unobservable inputs.

        The Pension Trust employs a building block approach in determining the long-term rate of return for plan assets. Historical market returns are studied and long-term risk/return relationships between equity and fixed income asset classes are analyzed. This analysis supports the widely accepted fundamental investment principle that assets with greater risk generate higher returns over long periods of time. The historical impact of returns in one asset class on returns of another asset class is reviewed to evaluate portfolio diversification benefits. Current market factors including inflation rates and interest rate levels are considered before assumptions are developed. The long-term portfolio return is established via the building block approach by adding interest rate risk and equity risk premiums to the anticipated long-term rate of inflation. Proper consideration is given to the importance of portfolio diversification and periodic rebalancing. Peer data and historical return assumptions are reviewed to check for reasonableness.

F-32

        Assumed healthcare cost trend rates, discount rates, expected return on plan assets and salary increases have a significant effect on the amounts reported for the pension and healthcare plans. A one-percentage-point change in the trend rate for these assumptions would have the following effects (in thousands):

	Increase (Decrease)
	1-Percentage Point Increase			1-Percentage Point Decrease
Health care cost trend:
Effect on total of service and interest cost components	$	4,580		$	(3,693	)
Effect on postretirement benefit obligation	$	79,862		$	(65,409	)
Discount rate:
Effect on postretirement service and interest cost components	$	13,897		$	(85	)
Effect on postretirement benefit obligation	$	(68,165	)	$	84,930
Effect on current year postretirement benefits expense	$	(3,820	)	$	4,621
Effect on pension service and interest cost components	$	127		$	(237	)
Effect on pension benefit obligation	$	(26,555	)	$	32,101
Effect on current year pension expense	$	(2,554	)	$	2,995
Expected return on plan assets:
Effect on current year pension expense	$	(1,905	)	$	1,905
Rate of compensation increase:
Effect on pension service and interest cost components	$	444		$	(396	)
Effect on pension benefit obligation	$	3,452		$	(3,185	)
Effect on current year pension expense	$	836		$	(757	)

        The Company's minimum pension plan funding requirement for 2012 is $28.1 million, which the Company expects to fully fund. The Company also expects to pay $27.2 million in 2012 for benefits related to its other postretirement healthcare plan. The following estimated benefit payments from the plans, which reflect expected future service, as appropriate, are expected to be paid as follows (in thousands):

	Pension Benefits		Other Postretirement Benefits Before Medicare Subsidy		Medicare Part D Subsidy
2012	$	18,479	$	29,006	$	1,760
2013	$	14,304	$	31,102	$	1,986
2014	$	15,173	$	32,952	$	2,234
2015	$	16,566	$	34,626	$	2,502
2016	$	16,736	$	36,268	$	2,740
Years 2017-2021	$	92,313	$	197,460	$	17,761

        The Company and certain of its subsidiaries maintain profit sharing and 401(k) plans. The total cost of these plans in 2011, 2010 and 2009 was $0.4 million, $0.4 million and $0.5 million, respectively.

UMWA Pension and Benefit Trusts

        The Company is required under its agreement with the UMWA to contribute to multi-employer plans providing pension, healthcare and other postretirement benefits. The risks of participating in these multi-employer plans are different from single-employer plans in the following aspects:

•

Assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers.

F-33

•

If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers.

•

The Employee Retirement Income Security Act of 1974 ("ERISA"), as amended in 1980, imposes certain liabilities on contributors to multi-employer pension plans in the event of a contributor's withdrawal from the plan.

        At December 31, 2011, approximately 38% of Walter Energy's workforce was represented by the UMWA and covered under our collective bargaining agreement which began July 11, 2012 and will expire December 31, 2016. During 2011 the number of UMWA represented employees increased by approximately 300 as a result of the acquisition of the North River mine described in Note 3.

UMWA 1974 Pension Plan

        The Company is required under the agreement with the UMWA to pay amounts to the 1974 UMWA Pension Plan ("the 1974 Pension Plan") based principally on hours worked by UMWA represented employees. The required contribution called for by our current collective bargaining agreement is $5.50 per hour worked. This cost is recognized as an expense in the year the payments are assessed. The benefits provided by the 1974 Pension Plan to the participating employees are determined based on age and years of service at retirement. The Company was listed in the 1974 Pension Plan's Form 5500, filed April 15, 2011, as providing more than 5 percent of the total contributions for the 2009 plan year.

        As of June 30, 2011, the most recent date for which information is available, the 1974 Pension Plan was underfunded. This determination was made in accordance with ERISA calculations. In October 2011, the Company received notice from the trustees of the 1974 Pension Plan stating that the plan is considered to be "seriously endangered" for the plan year beginning July 1, 2011. The Pension Protection Act ("Pensions Act") requires a funded percentage of 80% be maintained for this multi-employer pension plan, and if the plan is determined to have a funded percentage of less than 80% it will be deemed to be "endangered" or "seriously endangered", if the number of years to reach a projected funding deficiency equals 7 or less in addition to having a funded percentage of less than 80%, and if less than 65%, it will be deemed to be in "critical" status. The funded percentage certified by the actuary for the 1974 Pension Plan was determined to be 76.50% under the Pension Act.

        The Company faces risks and uncertainties by participating in the 1974 Pension Plan. All assets contributed to the plan are pooled and available to provide benefits for all participants and beneficiaries. As a result, contributions made by the Company benefit the employees of other employers. If the 1974 Pension Plan fails to meet ERISA's minimum funding requirements or fails to develop and adopt a rehabilitation plan, a nondeductible excise tax of five percent of the accumulated funding deficiency may be imposed on an employer's contribution to this multi-employer pension plan. As a result of the 1974 Pension Plan's "seriously endangered" status, steps must be taken under the Pension Act to improve the funded status of the plan. As a result, the Pension Act requires the 1974 Pension Plan to adopt a funding improvement plan no later than May 25, 2012, to improve the funded status of the plan, which may include increased contributions to the 1974 Pension Plan from employers in the future. Because our current collective bargaining agreement established our contribution obligations through December 31, 2016, our contributions to the 1974 Pension Plan should not increase during the term of the current collective bargaining agreement as a consequence of any funding improvement plan adopted by the 1974 Pension Plan to address the plan's seriously endangered status.

        Under current law governing multi-employer defined benefit plans, if the Company voluntarily withdrew from the 1974 Pension Plan, the currently underfunded multi-employer defined benefit plan would require the Company to make payments to the plan which would approximate the proportionate share of the multiemployer plan's unfunded vested benefit liabilities at the time of the withdrawal. The 1974 Pension Plan uses a modified "rolling five" method for calculating an employer's share of the

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unfunded vested benefits, or the withdrawal liability, for a plan year. An employer would be obligated to pay its pro-rata share of the unfunded vested benefits based on the ratio of hours worked by the employer's employees during the previous five plan years for which contributions were due compared to the number of hours worked by all the employees of the employers from which contributions were due. The 1974 Pension Plan's unfunded vested benefits at June 30, 2011, the end of the latest plan year, were $4.3 billion. The Company's percentage of hours worked compared during the previous five plan years to the total hours worked by all plan participants during the same period was estimated to be approximately 9%. The Company does not have any intention to withdraw from the plan; however, through June 30, 2012, the calculation of the Company's combined withdrawal liability amounts to $484.4 million.

        The following table provides additional information regarding the multiemployer plan in which the Company participates as of December 31, 2011 (in thousands):

			Pension Protection Act Zone Status
						Contributions of Walter Energy
	EIN/Pension Plan Number				FIP/RP Status Pending/Implemented							Surcharge Imposed	Expiration Date of Collective-Bargaining Agreement
Pension Fund			2011	2010		2011		2010		2009
United Mine Workers of America 1974 Pension Plan(1)		52-1050282/002	Yellow	Green	Yes	$	19,520	$	13,425	$	10,732	No		12/31/2016

(1)

The enrolled actuary for the UMWA 1974 Pension Plan ("the Plan") certified to the U.S. Department of the Treasury and the plan sponsor that the Plan is in "Seriously Endangered Status" for the plan year beginning July 1, 2011 and ending June 30, 2012. A funding improvement plan is currently pending. Federal law requires the Plan to adopt a funding improvement plan by May 25, 2012.

UMWA Benefit Trusts

        The Coal Industry Retiree Health Benefit Act of 1992 ("Coal Act") created two multiemployer benefit plans: (1) the United Mine Workers of America Combined Benefit Fund ("Combined Fund") into which the former UMWA Benefit Trusts were merged, and (2) the 1992 Benefit Fund. The Combined Fund provides medical and death benefits for all beneficiaries of the former UMWA Benefit Trusts who were actually receiving benefits as of July 20, 1992. The 1992 Benefit Fund provides medical and death benefits to orphan UMWA-represented members eligible for retirement on February 1, 1993, and who actually retired between July 20, 1992 and September 30, 1994. The Coal Act provides for the assignment of beneficiaries to former employers and the allocation of unassigned beneficiaries (referred to as orphans) to companies using a formula set forth in the Coal Act. The Coal Act requires that responsibility for funding the benefits to be paid to beneficiaries, be assigned to their former signatory employers or related companies. This cost is recognized as an expense in the year the payments are assessed. The Company made no contributions to these funds for the years ended December 31, 2011 and 2010 and made contributions of $0.3 million during the year ended December 31, 2009.

        The UMWA 1993 Benefit Plan is a defined contribution plan that was created as the result of negotiations for the National Bituminous Coal Wage Agreement (NBCWA) of 1993. This plan provides healthcare benefits to orphan UMWA retirees who are not eligible to participate in the Combined Fund, or the 1992 Benefit Fund or whose last employer signed the 1993, or a later, NBCWA and who subsequently goes out of business. Contributions to the trust under the 2011 labor agreement are $0.50 per hour worked by UMWA represented employees for the year ended December 31, 2011. Contributions to the trust under the 2007 agreement were $1.42 per hour worked by UMWA represented employees for the year ended December 31, 2010, comprised of a $0.50 per hour worked under the labor agreement and $0.92 per hour worked by UMWA represented employees under the Tax Relief and Health Care Act of 2006 (the 2006 Act). Contributions to the trust under the 2007 agreement were $1.44 per hour worked by UMWA represented employees for the year ended December 31, 2009, comprised of a $0.50 per hour worked under the labor agreement and $0.94 per

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hour worked by UMWA represented employees under the 2006 Act. Total contributions to the UMWA 1993 Benefit Plan in 2011, 2010 and 2009 were $1.8 million, $3.8 million and $3.6 million, respectively.

NOTE 12—Stockholders' Equity

        In September 2008 the Board of Directors approved a $50.0 million share repurchase program and in December 2008 the Board of Directors authorized a $50.0 million expansion of the Company's share repurchase program. The new program began on January 1, 2009 and purchases were based on liquidity and market conditions. Through December 31, 2009, the Company purchased a total of 2,747,659 shares for $79.4 million. The Company purchased an additional 270,159 shares for $20.5 million andcompleted the program during the second quarter of 2010. On May 14, 2010, the Board of Directors authorized a $45.0 million share repurchase program, which was substantially completed during the third quarter of 2010. Through December 31, 2010, a total of 3,658,408 shares were repurchased under the programs for a total cost of approximately $144.8 million. No shares were repurchased in 2011.

        On February 27, 2009, the Company's Board of Directors authorized and declared a dividend of one preferred stock purchase right (a "Right") for each share of common stock to stockholders of record as of the close of business on April 23, 2009. The shareholders approved this action and the Company entered into a rights agreement on April 24, 2009. Initially the Right is not exercisable and will trade with our common stock. The Right may be exercisable under certain circumstances, including a person or group acquiring, or the commencement of a tender or exchange offer that would result in a person or group acquiring, beneficial ownership of more than 20% of the outstanding shares of common stock. Upon exercise of the Right, each Right holder, other than the person or group triggering the plan, will have the right to purchase from us 1/1000^th of a share of junior preferred stock (subject to adjustment) or, at the Company's option, shares of common stock having a value equal to two times the exercise price of the Right. Each fractional share of the junior preferred stock has terms designed to make it substantially the economic equivalent of one share of common stock. This rights agreement expires on April 23, 2012.

        On April 23, 2009, shareholders voted to grant the Company the authority to issue 20,000,000 shares of preferred stock, at a par value of $0.01 per share. The Board believes the ability to issue preferred stock is necessary in order to provide the Company with greater flexibility in structuring future capital raising transactions, acquisitions and/or joint ventures, including taking advantage of financing techniques that receive favorable treatment from credit rating agencies. No preferred shares have been issued.

        On April 1, 2011, the Company issued 8,951,558 common shares valued at $1.2 billion in connection with the acquisition of Western Coal as described in Note 3.

        In connection with the acquisition of Western Coal, the Company assumed all the outstanding warrants of Western Coal (see Note 3). Upon exercise the outstanding Western Coal warrants will entitle the holder to receive cash and shares of Walter Energy common stock that would have been issued if the warrants had been exercised immediately before closing of the acquisition. Warrants to purchase an aggregate of 19,119 shares of Walter Energy common stock are exercisable and outstanding as of December 31, 2011. The warrants have an exercise price of CAD$3.25 and expire on June 28, 2012.

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NOTE 13—Net Income Per Share

        A reconciliation of the basic and diluted net income per share computations for the years ended December 31, 2011, 2010 and 2009 is as follows (in thousands, except per share data):

	For the years ended December 31,
	2011				2010						2009
	Basic		Diluted		Basic			Diluted			Basic			Diluted
Numerator:
Income from continuing operations	$	349,176	$	349,176	$	389,425		$	389,425		$	141,850		$	141,850
Loss from discontinued operations	$	—	$	—	$	(3,628	)	$	(3,628	)	$	(4,692	)	$	(4,692	)
Denominator:
Average number of common shares outstanding		60,257		60,257		53,179			53,179			53,076			53,076
Effect of dilutive securities
Stock awards and warrants(a)		—		354		—			521			—			743
		60,257		60,611		53,179			53,700			53,076			53,819
Income from continuing operations	$	5.79	$	5.76	$	7.32		$	7.25		$	2.67		$	2.64
Loss from discontinued operations		—		—		(0.07	)		(0.07	)		(0.09	)		(0.09	)
Net income per share	$	5.79	$	5.76	$	7.25		$	7.18		$	2.58		$	2.55

(a)

Stock awards represent the weighted average number of shares of common stock issuable on the exercise of dilutive employee stock options and restricted stock units, less the number of shares of common stock which could have been purchased with the proceeds from the exercise of such stock awards. These purchases were assumed to have been made at the average market price of the common stock for the period. The weighted average number of stock options outstanding of 31,511, 25,177, and 150,907 for the years ended December 31, 2011, 2010 and 2009, respectively, were excluded because their effect would have been anti-dilutive. Outstanding warrants entitle the holder to receive cash and shares of common stock upon exercise.

NOTE 14—Commitments and Contingencies

Income Tax Litigation

        The Company is currently engaged in litigation with the IRS with regard to certain federal income tax issues; see Note 9 for a more complete explanation.

Environmental Matters

        The Company is subject to a wide variety of laws and regulations concerning the protection of the environment, both with respect to the construction and operation of its plants, mines and other facilities and with respect to remediating environmental conditions that may exist at its own and other properties.

        The Company believes that it is in substantial compliance with federal, state and local environmental laws and regulations. The Company accrues for environmental expenses resulting from existing conditions that relate to past operations when the costs are probable and can be reasonably estimated.

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Walter Coke, Inc.

        Walter Coke entered into a decree order in 1989 relative to a Resource Conservation Recovery Act ("RCRA") compliance program mandated by the Environmental Protection Agency ("EPA"). A RCRA Facility Investigation ("RFI") Work Plan was prepared which proposed investigative tasks to assess the presence of contamination at the Walter Coke facility. A work plan was approved in 1994 and the Phase I investigations were conducted and completed between 1995 and 1999. Phase II investigations for the Chemical Plant/Coke Plant and Biological Treatment Facility and Sewers/Land Disposal Areas at the Walter Coke facility were performed in 2000 and 2001 and are complete. At the end of 2004, the EPA re-directed Walter Coke's RFI efforts toward completion of the Environmental Indicator ("EI") determinations for the Current Human Exposures. This EI effort was completed to assist the EPA in meeting goals set by the Government Performance Results Act ("GPRA") for RCRA by 2005. Walter Coke implemented the approved EI sampling plan in April 2005. The EPA approved and finalized the EI determinations for Walter Coke's Birmingham facility in September 2005. In an effort to refocus the RFI, the EPA approved technical comments on the Phase II RFI report and the report submitted as part of the EI effort. A Phase III work plan was submitted to the EPA during the first quarter of 2007. The EPA commented on the Phase III plan and Walter Coke responded. Subsequently, a meeting was held with the EPA during the third quarter of 2007 with the objective of finalization of the Phase III plan. Phase III sampling reports were submitted in March 2009 and June 2009. Beyond the scope of the Phase III activity performed in 2007 through 2009, additional requests by EPA expanded the scope of the project which required additional sampling and testing. In January 2008, as a follow-up to the EI determination, the EPA requested that Walter Coke perform additional soil sampling and testing in the neighborhoods surrounding its facility. Subsequent to EPA's initial request and presentation of a residential sampling plan to EPA by Walter Coke, the plan was finalized and community involvement initiated, with sampling and testing commencing in July 2009. The results of this sampling and testing were submitted to the EPA for review in December 2009. In conjunction with the plan, Walter Coke agreed to remediate portions of 23 properties based on the 2009 sampling and that process was started in July, 2011. As of December 31, 2011, Walter Coke had completed soil removal action at portions of 16 residential properties for which access agreements were obtained. In December 2011, the EPA notified Walter Coke in the form of a General Notice Letter that it proposed that the offsite remediation project be classified and managed as a Superfund site under CERCLA, allowing other Potentially Responsible Parties (PRP's) to be brought in.

        The Company has incurred costs to investigate the presence of contamination at the Walter Coke facility and to define remediation actions to address this environmental liability in accordance with the agreements reached with the EPA under the RFI and the residential soil sampling conducted by Walter Coke in the neighborhoods surrounding its facility. At December 31, 2011, the Company has an amount accrued that is probable and can be reasonably estimated for the costs to be incurred to identify and define remediation actions, as well as to perform certain remedial tasks which can be quantified, in accordance with the agreements reached and proposals that continue to be coordinated with the EPA to date. The amount of this accrual is not material to the financial statements. While it is probable that the Company will incur additional future costs to remediate environmental liabilities at the Walter Coke facility, the amount of these costs cannot be reasonably estimated at this time. Because the RCRA and CERCLA compliance programs are in the study phase with negotiation of final orders ongoing, until these processes are complete the Company is unable to fully estimate the cost of remediation activities that will be required. Although no assurances can be given that the Company will not be required in the future to make material expenditures relating to the Walter Coke site or other sites, management does not believe at this time that the cleanup costs, if any, associated with these sites will have a material adverse effect on the financial condition of the Company, but such cleanup costs could be material to results of operations in a future reporting period.

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        The Company and Walter Coke were named in a suit filed by Louise Moore on April 26, 2011 (Louise Moore v. Walter Energy, Inc. and Walter Coke, Inc., Case No. 2:11-CV-01391) in the federal District Court for the Northern District of Alabama. This is a putative civil class action alleging state law tort claims arising from the alleged presence on properties of substances, including arsenic, BaP, and other hazardous substances, allegedly as a result of current and/or historic operations in the area conducted by the companies and/or their predecessors. This action is still in the earliest stages of litigation. On June 6, 2011, the plaintiff filed an amended complaint eliminating Walter Energy as a defendant and amending the claims alleged against Walter Coke to relate to Walter Coke's alleged conduct for the period commencing after March 2, 1995. Based on initial evaluation, management believes that both procedural and substantive defenses are available to the Company and Walter Coke expects to vigorously defend this matter. No specific dollar value has been claimed in the suit's demand for monetary damages. On June 20, 2011, Walter Coke filed a Motion to Dismiss which, was heard on October 28, 2011. As of the date of filing this annual report on Form 10-K, a ruling has not been received.

Maple Coal Company

        Maple Coal Company ("Maple") was the subject of a compliance order issued against its water discharge permit in April, 2007 by the West Virginia Department of Environmental Protection ("WVDEP"). This order provided that Maple would have until April 5, 2010 to comply with certain water quality-based effluent limitations for selenium concentrations in discharges from its mining operations.

        Maple sought a permit modification to extend the selenium compliance date beyond April 5, 2010. That permit modification application was denied by the WVDEP. Maple appealed that denial to the West Virginia Environmental Quality Board ("EQB"), which issued a Stay of those limits, to be effective until it had issued a ruling. The Kanawha County (West Virginia) Circuit Court also issued Stay Orders, preventing the selenium effluent limits in Maple's National Pollutant Discharge Elimination System ("NPDES") permit from taking effect until the exhaustion of all appeals from the WVDEP denial and the conclusion of the WVDEP's civil enforcement action.

        The EQB ruled against Maple's appeal. Maple has filed an appeal of these rulings (consolidated into one case) with the Fayette County (West Virginia) Circuit Court. In connection with this administrative appeal, Maple has also obtained a Stay Order from the Fayette County Circuit Court, suspending the effective date of the selenium limits in its NPDES permit pending the outcome of that appeal. The parties to that appeal agreed to defer briefing, pending negotiation of a comprehensive settlement of all such issues (discussed below) and the Court entered an order suspending the briefing schedule.

        In a related action, in June, 2010 the WVDEP instituted a civil enforcement action against Maple seeking to enforce effluent limits for non-selenium parameters found in the Maple permit, asserting violations of various in-stream water quality standards, and alleging a violation of the April 5, 2007 selenium compliance order. Maple has entered into a comprehensive Consent Decree with the WVDEP with civil penalties of $229,350 resolving that case and the EQB case mentioned above.

        In a second related action, in January, 2011 three environmental interest groups filed a Clean Water Act citizen's suit against Maple, seeking more than $14 million in civil penalties for selenium violations since April, 2010 and injunctive relief in the form of mandatory treatment plant installations. The plaintiffs filed a Motion for Partial Summary Judgment on Jurisdiction and Liability, and Maple filed a Cross-Motion for Summary Judgment. On September 2, 2011, the Court issued a Memorandum Opinion and Order (the "Sept. 2 Order") granting, in part, and denying, in part, both motions. In partially granting Maple's motion, the Court held that the plaintiffs' members had not shown a sufficient connection to establish standing to bring a claim as to discharges from one of the outlet

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under the Maple NPDES Permit at issue. The Court upheld jurisdiction over claims based on discharges from one of the outlets, and found that the plaintiffs were entitled to summary judgment on liability as to past and continuing selenium discharges from that outlet. The plaintiffs filed a Motion to Amend Judgment, asking the Court to reverse its Sept. 2 Order as to their dismissed claims, that was denied by Order dated October 24, 2011. Maple, in turn, filed a motion seeking the right to file an interlocutory appeal of that part of the Court's Sept. 2 Order that denied its motion to dismiss based on the WVDEP's diligent enforcement against Maple, which the Court denied by Order dated December 19, 2011. Maple has filed a Motion for Summary Judgment on the basis of mootnes with the entering into a Consent Order with WVDEP. As of the date of filing this annual report on Form 10-K, a ruling has not been received. A trial on civil penalties for past violations and injunctive relief to address continuing violations at the remaining outlet is scheduled for May, 2012.

        In addition, these same plaintiffs served a second Notice of Intent to Sue under the Clean Water Act on September 23, 2011, alleging that Maple Coal is liable for having caused selenium water quality standard violations authorized under a different NPDES permit. Maple responded to that Notice on October 31, 2011, and plaintiffs have not filed a lawsuit or amended their existing suit addressing those threatened claims.

        At present the likelihood of an unfavorable outcome as to the federal court citizens' suit is neither remote nor probable and no opinion can be offered regarding the likelihood of the citizens suit plaintiffs succeeding in this action. As such, the Company has not made a provision for these claims in its consolidated financial statements. Regardless of the manner of their disposition, however, civil penalties, mandatory treatment facility costs, and other costs that may ultimately be incurred as a result of these proceedings could be material.

Jim Walter Resources

        In July, 2011, Jim Walter Resources, Inc. ("JWR") reported a slurry spill at its North River mine to the Alabama Department of Environmental Management ("ADEM") and the Alabama Surface Mining Commission ("ASMC"). As a result, a penalty of $145,200 was assessed and paid to ASMC in November, 2011. A penalty of $60,000 was assessed by ADEM in December, 2011. JWR has expended approximately $5.0 million in remediation costs which is substantially complete and is pursuing insurance claims.

Securities Class Actions and Shareholder Derivative Actions

        On January 26, 2012, a putative class action was filed against Walter Energy and some of its current and former senior executive officers in the U.S. District Court for the Northern District of Alabama (Rush v. Walter Energy, Inc., et al.). The three executive officers named in the complaint are: Keith Calder, Walter's former CEO; Walter Scheller, the Company's current CEO; and Neil Winkelmann, former President of Walter's Canadian and European Operations (collectively the "Individual Defendants"). The complaint was filed by Peter Rush, a purported shareholder of Walter Energy who seeks to represent a class of Walter shareholders who purchased the common stock of Walter between April 20, 2011 and September 21, 2011.

        The complaint alleges that Walter and the Individual Defendants made false and misleading statements regarding the Company's operations outlook for the second quarter of 2011. The complaint further alleges that the Company and the Individual Defendants knew that these statements were misleading and failed to disclose material facts that were necessary in order to make the statements not misleading. Plaintiff claims violations of Section 10(b) of the Securities Exchange Act of 1934, Rule 10b-5 promulgated thereunder, and Section 20(a) of the 1934 Act. The Court has not yet appointed lead plaintiff or lead plaintiff's counsel. Defendants have yet to be served with a complaint

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in this action. Walter Energy and the other named defendants believe that there is no merit to the claims alleged and intend to vigorously defend the action.

        On February 7, 2012, a shareholder derivative lawsuit was filed in the 10th Judicial Circuit of Alabama (Israni v. Clark et al.). On February 10, 2012 a second shareholder derivative suit was filed in the same court (Himmel v. Scheller et al.), and on February 16, 2010 a third derivative suit was filed (Walters v. Scheller et al.). All three complaints name as defendants the Company's current Board of Directors, Keith Calder and Neil Winkelmann. The Company is named as a nominal defendant in each complaint. The three complaints allege similar facts to those alleged in the Rush complaint. The complaints variously assert state law claims, for breaches of fiduciary duties for alleged failures to maintain internal controls and to properly manage the Company, unjust enrichment, waste of corporate assets, gross mismanagement and abuse of control. The three derivative actions seek, among other things, recovery for the company for damages that the company suffered as a result of alleged wrongful conduct.

        Walter Energy and the other named defendants believe that there is no merit to the claims alleged and intend to vigorously defend these actions.

        In November, 2009, Western Coal was named as a defendant in a statement of claim issued by a plaintiff who seeks leave of the Ontario Courts to proceed with a securities class action. This claim also named Western Coal's former President and director, John Hogg, and two of its non-executive directors, John Brodie and Robert Chase, as defendants.

        The plaintiff subsequently delivered an amended claim that added new allegations that seeks to have the amended claim certified as a class action separately from the proposed securities class action allegations. The new allegations focused on certain transactions the plaintiff claims were oppressive and unfair to the interests of shareholders. The amended claim included additional defendants of Western Coal's former Chairman, John Byrne, its remaining non-executive directors John Conlon and Charles Pitcher, Audley European Opportunities Master Fund Limited, Audley Capital Management Limited, and Audley Advisors LLP.

        The proposed securities claims allege that those persons who acquired or disposed of Western Coal shares between November 14, 2007 and December 10, 2007 should be entitled to recover $200 million for general damages and $20 million in punitive damages. The plaintiff alleges that Western Coal's consolidated financial statements for the second quarter of fiscal 2008 and the accompanying news release issued on November 14, 2007 misrepresented Western Coal's financial condition and that Western Coal failed to make full, plain and true disclosure of all material facts and changes.

        The plaintiff's oppression claims are advanced in respect of security holders in the period between April 26, 2007 and July 13, 2009. The claims are that the defendants caused Western Coal to enter into transactions that had a dilutive effect on the interests of shareholders. The damages associated with these alleged dilutive effects have not been developed or quantified.

        The plaintiff's motions to proceed with securities claims and also to certify the securities and oppression claims as class actions were rescheduled to allow the plaintiff additional time to answer the Company's position. This has now been done. The hearing dates are set for June 2012.

        Western Coal and the other named defendants continue to, and will vigorously defend the allegations. They maintain that there is no merit to the claims and that the damages are without foundation and excessive. Accordingly, the Company has made no provision for the claims in its financial statements.

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Miscellaneous Litigation

        The Company and its subsidiaries are parties to a number of other lawsuits arising in the ordinary course of their businesses. The Company records costs relating to these matters when a loss is probable and the amount can be reasonably estimated. The effect of the outcome of these matters on the Company's future results of operations cannot be predicted with certainty as any such effect depends on future results of operations and the amount and timing of the resolution of such matters. While the results of litigation cannot be predicted with certainty, the Company believes that the final outcome of such other litigation will not have a material adverse effect on the Company's consolidated financial statements.

Commitments and Contingencies—Other

        In the opinion of management, accruals associated with contingencies incurred in the normal course of business are sufficient. Resolution of existing known contingencies is not expected to significantly affect the Company's financial position and results of operations.

Undistributed Foreign Earnings

        The Company has not provided U.S. income taxes and foreign withholding taxes on the undistributed earnings of foreign subsidiaries as of December 31, 2011 because it intends to indefinitely reinvest such earnings outside the U.S. If this intent changes, additional income tax expense would likely be recorded due to the differential in tax rates between the U.S. and the international jurisdictions. If these foreign earnings were to be repatriated in the future, the related U.S. tax liability on such repatriation may be partially reduced by any foreign income taxes previously paid on these earnings. Determination of the amount of taxes that might be paid on these undistributed earnings if eventually remitted is not practicable.

Ridley Terminal Services Agreement

        In connection with the acquisition of Western Coal, the Company assumed a terminal services agreement (the "Agreement") with Ridley Terminals Inc. located in British Columbia. The Agreement contains minimum throughput obligations each calendar year through December 31, 2020. If the Company does not meet its minimum throughput obligation, the Company shall pay Ridley Terminals a contractually specified amount per metric ton for the difference between the actual throughput and the minimum throughput requirement. The Company expects to meet future minimum throughput requirements and as such no liability has been established at December 31, 2011.

Lease Obligations

        The Company's leases are primarily for mining equipment, automobiles and office space. The total cost of assets under capital leases was $118.8 million and $9.4 million at December 31, 2011 and 2010, respectively. Accumulated amortization on assets under capital leases was $16.8 million and $4.2 million at December 31, 2011 and 2010, respectively. Amortization expense for capital leases is included in depreciation and depletion expense. Rent expense was $21.0 million, $13.7 million, and $10.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. Future minimum payments under

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non-cancellable capitalized and operating leases obligations as of December 31, 2011 are as follows (in thousands):

	Capitalized Leases			Operating Leases
2012	$	29,843		$	22,435
2013		20,948			16,310
2014		17,273			13,471
2015		5,980			7,327
2016		61			4,869
Thereafter		—			2,936
Total		74,105		$	67,348
Less: amount representing interest and other executory costs		(6,002	)
Present value of minimum lease payments	$	68,103

        A substantial amount of the coal we mine is produced from mineral reserves leased from third-party land owners. These leases convey mining rights to the coal producer in exchange for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Although coal leases have varying renewal term and conditions, they generally last for the economic life of the reserves. Coal royalty expense was $111.5 million, $88.8 million and $41.6 million for the years ended December 31, 2011, 2010 and 2009 respectively.

NOTE 15—Derivative Financial Instruments

Interest Rate Swaps

        On June 27, 2011, the Company entered into an interest rate swap agreement with a notional value of $450.0 million. The objective of the swap is to protect against the variability in expected future cash flows attributable to changes in the benchmark interest rate related to interest payments required under the 2011 Credit Agreement. The interest rate on the debt is subject to change due to fluctuations in the benchmark interest rate of 3-month LIBOR. The structure of the hedge is a three year amortizing interest rate swap based on a 1.17% fixed rate with fixed rate and floating rate payment dates effective July 18, 2011. The hedge will be settled upon maturity and is being accounted for as a cash flow hedge. Changes in the fair value of the hedge that take place through the date of maturity are reported in accumulated other comprehensive income (loss) and reclassified into earnings in the same period or periods during which the hedged transactions affect earnings.

        On December 30, 2008, the Company entered into an interest rate hedge agreement with a notional value of $31.5 million. The objective of the hedge is to protect against the variability in expected future cash flows attributable to changes in the benchmark interest rate related to 62 of the 64 monthly interest payments required under an equipment financing arrangement for a new longwall shield system entered into on October 21, 2008. The interest rate on the debt is subject to change due to fluctuations in the benchmark interest rate of 1-month LIBOR. The structure of the hedge is a 62 month amortizing interest rate swap based on a 1.84% fixed rate with fixed rate and floating rate payment dates effective February 1, 2009. The hedge will be settled upon maturity and is being accounted for as a cash flow hedge. Changes in the fair value of the hedge that take place through the date of maturity are reported in accumulated other comprehensive income (loss) and reclassified into earnings in the same period or periods during which the hedged transactions affect earnings.

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Interest Rate Cap

        On June 27, 2011, the Company entered into an interest rate cap agreement related to interest payments required under the 2011 Credit Agreement with a notional value of $255.0 million. The objective of the cap is to protect against the variability in expected future cash flows attributable to changes in the benchmark interest rate above 2.00%. The interest rate on the debt is subject to change due to fluctuations in the benchmark interest rate of 3-month LIBOR. The structure of the hedge is a three year amortizing interest rate cap based on a strike price of 2.00% with fixed rate and floating rate payment dates effective July 7, 2011. The hedge will be settled upon maturity and is being accounted for as a cash flow hedge. Changes in the fair value of the hedge that take place through the date of maturity are reported in accumulated other comprehensive income (loss) and reclassified into earnings in the same period or periods during which the hedged transactions affect earnings.

Natural Gas Hedge

        Revenues derived from the sale of natural gas are subject to volatility based on changes in market prices. In order to reduce the risk associated with natural gas price volatility, on June 7, 2011 the Company entered into a one year swap contract to hedge 4.2 million MMBTUs of natural gas sales beginning in July 2011 and ending June 2012, at a price of $5.00 per MMBTU. The swap agreement will hedge approximately 35% of anticipated natural gas sales from July 2011 through June 2012. The hedge will be settled upon maturity and is being accounted for as a cash flow hedge. Changes in the fair value of the hedge that take place through the date of maturity are reported in accumulated other comprehensive income (loss) and reclassified into earnings in the same period or periods during which the hedged transactions affect earnings.

        The following table presents the fair values of the Company's derivative instruments as well as the classification in the Condensed Consolidated Balance Sheets (in thousands). See Note 16 for additional information related to the fair values of our derivative instruments.

	December 31, 2011		December 31, 2010
Asset derivatives designated as cash flow hedging instruments:
Natural gas hedge(1)	$	4,050	$	—
Interest rate cap(2)		432		—
Total asset derivatives	$	4,482	$	—
Liability derivatives designated as cash flow hedging instruments:
Interest rate swaps(3)	$	5,683	$	386

(1)

Included in other current assets.

(2)

$143 thousand is included in other current assets and $289 thousand is included in other long-term assets.

(3)

As of December 31, 2011, $1.8 million is included in other current liabilities and $3.9 million is included in other long-term liabilities. The December 31, 2010 balance was included in other long-term liabilities.

F-44

        The following tables present the gains and losses from derivative instruments for the years ended December 31, 2011 and 2010 and their location within the Consolidated Financial Statements (in thousands). The Company utilizes only cash flow hedges that are considered highly effective.

Derivatives designated as cash flow hedging instruments	Gain (loss) recognized in accumulated other comprehensive income, net of tax						Gain (loss) reclassified from accumulated other comprehensive income (loss) to earnings						Gain (loss) recognized in earnings
	For the years ended December 31,						For the years ended December 31,						For the years ended December 31,
	2011			2010			2011			2010			2011		2010
Natural gas hedges(1)	$	2,309		$	(386	)	$	2,387		$	3,017		$	—	$	—
Interest rate swaps(2)		(3,294	)		(210	)		(1,342	)		(375	)		—		—
Interest rate cap(2)		269			—			—			—			—		—
Total	$	(716	)	$	(596	)	$	1,045		$	2,642		$	—	$	—

(1)

Amounts recorded in miscellaneous income in the Consolidated Statements of Operations

(2)

Amounts recorded in interest expense in the Consolidated Statements of Operations

NOTE 16—Fair Value of Financial Instruments

        Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A three level hierarchy has been established for valuing assets and liabilities based on how transparent (observable) the inputs are that are used to determine fair value, with the inputs considered most observable categorized as Level 1 and those that are the least observable categorized as Level 3. Hierarchy levels are defined as follows:

Level 1:	Quoted prices in active markets for identical assets and liabilities;
Level 2:	Quoted prices for similar assets and liabilities in active markets; quoted prices for identical or similar instruments in markets that are not active; and
Level 3:	Unobservable inputs that are supported by little or no market data which require the reporting entity to develop its own assumptions.

        The following table presents information about the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2011 and indicate the fair value hierarchy of the valuation techniques utilized to determine such values. For some assets, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. When this is the case, the asset is categorized based on the level of the most significant input to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and considers factors specific to the assets being valued. The

F-45

Company's assets and liabilities measured at fair value on a recurring basis were not material at December 31, 2010.

	December 31, 2011
	Fair Value Measurements Using
							Total Fair Value
(in thousands)	Level 1		Level 2		Level 3
Assets:
Equity securities, trading	$	12,369	$	—	$	—	$	12,369
Equity securities, available-for-sale		12,099		—		—		12,099
Interest rate cap		—		432		—		432
Natural gas hedge		—		4,050		—		4,050
Total assets	$	24,468	$	4,482	$	—	$	28,950
Liabilities:
Interest rate swaps	$	—	$	5,683	$	—	$	5,683

        Below is a summary of the Company's valuation techniques for Level 1 and Level 2 financial assets and liabilities:

        Equity securities—As of December 31, 2011 the Company held equity investments in other current assets classified as trading and available-for-sale. Changes in the fair value of trading securities are recorded in other income and determined using observable market prices. For the year ended December 31, 2011 a loss of $2.9 million was recorded related to trading securities held at the reporting date. Changes in the fair value of available-for-sale securities are recorded in accumulated other comprehensive income (loss) and determined using observable market prices.

        Interest rate cap—The fair value of the interest rate cap was determined using quoted dealer prices for similar contracts in active over-the-counter markets.

        Natural gas hedge—The fair value of the natural gas hedge was determined using quoted dealer prices for similar contracts in active over-the-counter markets.

        Interest rate swaps—The fair value of interest rate swaps were determined using quoted dealer prices for similar contracts in active over-the-counter markets.

        The following methods and assumptions were used to estimate the fair value for which the fair value option was not elected:

        Cash and cash equivalents, receivables and accounts payable—The carrying amounts reported in the balance sheet approximate fair value.

        Debt—On April 1, 2011, the Company entered into a $2.725 billion credit agreement to partially fund the acquisition of Western Coal and to pay off all outstanding loans under the 2005 Credit Agreement (see Note 10). Debt associated with the Company's 2011 term loan A, term loan B and revolving credit facility in the amount of $894.8 million, $1.333 billion and $10.0 million at December 31, 2011, respectively, are carried at cost. The estimated fair value of the Company's term loan A, term loan B and revolving credit facility was $880.6 million, $1.319 billion and $9.7 million at December 31, 2011, respectively, based on similar transactions and yields in an active market for similarly rated debt (Level 2).

F-46

NOTE 17—Segment Information

        The Company's reportable segments are strategic business units arranged geographically which have separate management teams. The business units have been aggregated into three reportable segments following the Western Coal acquisition described in Note 1. These reportable segments are U.S. Operations, Canadian and U.K. Operations, and Other. Both the U.S. Operations and Canadian and U.K. Operations reportable segments primary business is that of mining and exporting metallurgical coal for the steel industry. The U.S. Operations segment includes Walter Energy's historical operating segments of Underground Mining, Surface Mining and Walter Coke as well as the results of the West Virginia mining operations acquired through the acquisition of Western Coal. The Canadian and U.K. segment includes the results of the mining operations located in Northeast British Columbia (Canada) and South Wales (United Kingdom). The Other segment primarily includes corporate expenses. Previously reported segment amounts have been restated to conform to the current period presentation.

        The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance primarily based on operating income of the respective business segments.

        Summarized financial information concerning the Company's reportable segments is shown in the following tables (in thousands):

	For the years ended December 31,
	2011			2010			2009
Revenues:
U.S. Operations	$	1,871,182		$	1,584,734		$	964,358
Canadian and U.K. Operations		698,054			—			—
Other		2,122			2,996			2,469
Total Revenues(a)	$	2,571,358		$	1,587,730		$	966,827
Segment operating income (loss):(b)
U.S. Operations	$	565,731		$	634,442		$	231,256
Canadian and U.K. Operations		67,349			—			—
Other		(74,477	)		(40,380	)		(29,086	)
Operating income		558,603			594,062			202,170
Less interest expense, net		(96,214	)		(16,466	)		(18,176	)
Other income, net		17,606			—			—
Income from continuing operations before income tax expense		479,995			577,596			183,994
Income tax expense		(130,819	)		(188,171	)		(42,144	)
Income from continuing operations	$	349,176		$	389,425		$	141,850

F-47

	For the years ended December 31
	2011		2010		2009
Depreciation and depletion:
U.S. Operations	$	151,341	$	98,170	$	72,533
Canadian and U.K. Operations		93,392		—		—
Other		776		532		406
Total	$	245,509	$	98,702	$	72,939
Capital expenditures:
U.S. Operations	$	149,996	$	152,299	$	95,672
Canadian and U.K. Operations		264,476		—		—
Other		94		5,177		626
Total	$	414,566	$	157,476	$	96,298

	As of December 31,
	2011		2010		2009
Identifiable assets by segment:
U.S. Operations	$	1,087,430	$	1,021,534	$	800,238
Canadian and U.K. Operations		5,008,237		—		—
Other		716,536		630,319		443,920
Assets of discontinued operations		—		5,912		15,198
Total	$	6,812,203	$	1,657,765	$	1,259,356
Long-lived assets by country:
U.S.	$	1,069,863	$	790,001	$	522,931
Canada		3,191,615		—		—
U.K.		321,817		—		—
Total	$	4,583,295	$	790,001	$	522,931

(a)

Export sales were $2.0 billion, $1.2 billion and $728.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. Export sales to customers in foreign countries in excess of 10% of consolidated revenues for the years ended December 31, 2011, 2010 and 2009 were as follows:

	Percent of Consolidated Revenues For the years ended December 31,
Country	2011			2010			2009
Brazil		10.5	%		24.9	%		20.2	%
U.K.		6.2	%		10.3	%		12.6	%
Germany		9.8	%		13.7	%		14.0	%

(b)

Segment operating income (loss) amounts include expenses for postretirement benefits. A breakdown by segment of postretirement benefits (income) expense is as follows (in thousands):

	For the years ended December 31,
	2011			2010			2009
U.S. Operations	$	41,745		$	43,228		$	31,902
Canadian and U.K. Operations		—			—			—
Other		(1,360	)		(1,750	)		(1,069	)
	$	40,385		$	41,478		$	30,833

F-48

NOTE 18—Related Party Transactions

        The Company owns a 50% interest in the joint venture Black Warrior Methane ("BWM"), which is accounted for under the proportionate consolidation method. The Company has granted the rights to produce and sell methane gas from its coal mines to BWM. The Company also supplies labor to BWM and incurs costs, including property and liability insurance, to support the joint venture. The Company charges the joint venture for such costs on a monthly basis. These charges for 2011, 2010 and 2009 were $2.9 million, $2.5 million and $2.5 million, respectively.

        In connection with the acquisition of Western Coal on April 1, 2011, the Company acquired a 50% interest in the Belcourt Saxon Coal Limited Partnership ("Belcourt Saxon"). Belcourt Saxon owns two multi-deposit coal properties which are located approximately 40 to 80 miles south of the Wolverine surface mine in Northeast British Columbia. The joint venture was formed for the future exploration and development of surface coal mines. Belcourt Saxon is accounted for under the proportionate consolidation method. Costs associated with the joint venture were not material for 2011. No field work was conducted on the Belcourt Saxon properties during 2011, other than maintenance of environmental monitoring stations.

NOTE 19—Restructuring and Impairments

        In December 2009, the Company closed its Walter Coke fiber plant. The fiber plant produced approximately 100,000 tons of various slag wool fiber products annually. The closure resulted in a restructuring and impairment charge of $3.6 million, of which $2.2 million related to the impairment of property, plant and equipment and $1.4 million related to severance and other obligations. In addition, Walter Coke recorded a charge of $0.9 million included in cost of sales in the 2009 statement of operations related to inventory write-downs. Approximately $0.1 million of cash was used in 2009 for severance and other obligations, with the remainder expended in 2010. As a result, there were no restructuring obligations remaining at December 31, 2010. The property, plant and equipment of the fiber plant was written down to fair value of $0.2 million, which was estimated using comparable transactions of similar assets, less the cost to dispose of the assets.

NOTE 20—Recent Accounting Pronouncements

        In June 2011, the Financial Accounting Standards Board ("FASB") issued an accounting standard update that requires companies to present the components of net income and other comprehensive income either in a single continuous statement or as two separate but consecutive statements. The accounting standard update eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders' equity, and is effective for interim and annual periods beginning after December 15, 2011. The adoption of this accounting standard update will not have an impact on the Company's operating results or financial position as it only requires a change in the format of our current presentation of comprehensive income.

Supplemental Summary Quarterly Financial Information (Unaudited)
(in thousands, except per share amounts)

	Quarter ended
Fiscal Year 2011(1)	March 31		June 30		September 30		December 31
Revenues	$	408,734	$	773,000	$	690,069	$	699,555
Operating income	$	119,767	$	153,649	$	148,650	$	136,537
Net income	$	81,813	$	107,358	$	76,221	$	83,784
Diluted income per share:(2)
Net income per share	$	1.53	$	1.71	$	1.21	$	1.34

F-49

	Quarter ended
Fiscal Year 2010	March 31			June 30		September 30			December 31
Revenues	$	312,049		$	410,622	$	464,262		$	400,797
Operating income	$	71,307		$	170,223	$	207,787		$	144,735
Income from continuing operations	$	42,695		$	116,110	$	136,972		$	93,648
Income (loss) from discontinued operations	$	(1,144	)	$	53	$	(757	)	$	(1,780	)
Net income	$	41,551		$	116,163	$	136,215		$	91,868
Diluted income (loss) per share:(2)
Income from continuing operations	$	0.79		$	2.16	$	2.57		$	1.75
Loss from discontinued operations		(0.02	)		—		(0.02	)		(0.03	)
Net income per share	$	0.77		$	2.16	$	2.55		$	1.72

(1)

Results include the Western Coal operations since the date of acquisition on April 1, 2011

(2)

The sum of quarterly EPS amounts may be different than annual amounts as a result of the impact of variations in shares outstanding.

F-50

EXHIBIT INDEX

Exhibit Number		Description of Exhibit
2	—	Amended Joint Plan of Reorganization of Registrant and certain of its subsidiaries, dated as of December 9, 1994 (Incorporated by reference to Exhibit T3E2 to Registrant's Applications for Qualification of Indentures on Form T-3, filed on February 6, 1995).
2.1	—	Modification to the Amended Joint Plan of Reorganization of Registrant and certain of its subsidiaries, as filed in the Bankruptcy Court on March 1, 1995 (Incorporated by reference to Exhibit T3E24 to Registrant's Amendment No. 2 to the Applications for Qualification of Indentures on Form T-3, filed on March 7, 1995).
2.2	—	Findings of Fact, Conclusions of Law and Order Confirming Amended Joint Plan of Reorganization of Walter Energy, Inc. and certain of its subsidiaries, as modified (Incorporated by reference to Exhibit 2(a)(iii) to the Registration Statement on Form S-1 (File No. 33-59013), filed on May 2, 1995).
2.3	—	Arrangement Agreement, dated as of December 2, 2010, between Registrant and Western Coal Corp. (Incorporated by reference to Exhibit 2.1 of the Registrant's Current Report on Form 8-K, filed on December 3, 2010).
3.1	—	Amended and Restated Certificate of Incorporation (Incorporated by reference to Exhibit 3.1 of the Registrant's Current Report on Form 8-K, filed on April 28, 2009).
3.2	—	Amended and Restated By-Laws (Incorporated by reference to Exhibit 3.1 of the Registrant's Current Report on Form 8-K, filed on February 23, 2012).
4	—	Form of Specimen Certificate for Registrant's Common Stock (Incorporated by reference to Exhibit 4(b) to Registration Statement on Form S-1 (No. 033-59013), filed on May 2, 1995).
4.1	—	Rights Agreement, dated as of April 24, 2009, between Walter Energy, Inc. and Mellon Investor Services LLC, as Rights Agent, which includes the Form of Certificate of Designations of Junior Participating Preferred Stock as Exhibit A, Form of Right Certificate as Exhibit B and the Summary of Rights as Exhibit C (Incorporated by reference to Exhibit 4.1 of the Registrant's Registration Statement on Form 8-A, filed on April 28, 2009).
4.2	—	Form of Certificate of Designations of Junior Participating Preferred Stock, filed with the Secretary of State of Delaware on April 24, 2009 (Incorporated by reference to Exhibit A to Exhibit 4.1 of the Registrant's Registration Statement on Form 8-A, filed on April 28, 2009).
10.1*	—	Director and Officer Indemnification Agreement, dated as of March 3, 1995, among the Registrant and the Indemnities parties thereto (Incorporated by reference to Exhibit 10(g) to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 33-59013), filed on August 9, 1995).
10.2*	—	Form of Indemnification Agreement for Directors and Executive Officers (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on November 24, 2008).
10.2.1*	—	Form of Indemnification Agreement for Directors and Executive Officers.

E-1

Exhibit Number		Description of Exhibit
10.3*	—	Form of Amended and Restated Executive Change-in-Control Severance Agreement (for executives executing agreements on or prior to January 1, 2010) (Incorporated by reference to Exhibit 10.2 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008).
10.4*	—	Form of Executive Change-in-Control Severance Agreement (for executives executing agreements after January 1, 2010 and prior to April 1, 2011).
10.4.1*	—	Form of Executive Change-in-Control Severance Agreement (for executives executing agreements after April 1, 2011).
10.5*	—	Registrant's Executive Deferred Compensation and Supplemental Retirement Plan.
10.6*	—	Registrant's Amended and Restated Directors' Deferred Fee Plan.
10.7*	—	Registrant's Amended and Restated Supplemental Pension Plan (Incorporated by reference to Exhibit 10.5 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008).
10.8*	—	Executive Incentive Plan (Incorporated by reference to Appendix A to the Registrant's Proxy Statement for the 2006 Annual Meeting of Stockholders, filed on March 31, 2006).
10.8.1*	—	First Amendment to the Registrant's Executive Incentive Plan (Incorporated by reference to Exhibit 10.6.1 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008).
10.9*	—	Amended 1995 Long-Term Incentive Stock Plan (Incorporated by reference to Exhibit B to the Registrant's Proxy Statement for the 1997 Annual Meeting of Stockholders, filed on August 12, 1997).
10.9.1*	—	Amendment to Amended 1995 Long-Term Incentive Stock Plan (Incorporated by reference to Exhibit 10.7.1 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008).
10.10*	—	2011 Executive Incentive Plan.
10.11*	—	Amended and Restated Western Stock Option Plan (Incorporated by reference to Exhibit 4.5 of the Registrant's Registration Statement on Form S-8 filed on April 6, 2011).
10.11.1*	—	Form of Director Stock Option Agreement for the Amended and Restated Western Stock Option Plan.
10.12*	—	Amended and Restated 2002 Long-Term Incentive Award Plan (Incorporated by reference to Appendix C to the Registrant's Proxy Statement for the 2009 Annual Meeting of Stockholders, filed on March 31, 2009).
10.13*	—	Form of Restricted Stock Unit Award Agreement (for executives executing agreements prior to February 23, 2012) (Incorporated by reference to Exhibit 10.9 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008).
10.13.1*	—	Form of Restricted Stock Unit Award Agreement (for executives executing agreements after February 23, 2012).
10.14*	—	Form of Retention Restricted Stock Unit Agreement.

E-2

Exhibit Number		Description of Exhibit
10.14.1*	—	Form of Retention Restricted Stock Unit Agreement.
10.15*	—	Form of Director Restricted Stock Unit Award Agreement.
10.16*	—	Form of Non-Qualified Stock Option Agreement (for executives executing agreements prior to February 23, 2012) (Incorporated by reference to Exhibit 10.10 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008).
10.16.1*	—	Form of Non-Qualified Stock Option Agreement (for executives executing agreements after February 23, 2012).
10.17*	—	Form of Director Stock Option Award Agreement.
10.18*	—	Amended and Restated Employee Stock Purchase Plan (Incorporated by reference to Appendix B to the Registrant's Proxy Statement for the 2004 Annual Meeting of Stockholders, filed on March 19, 2004).
10.19*	—	Registrant's Involuntary Severance Benefit Plan (Incorporated by reference to Exhibit 10.23.1 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008).
10.19.1*	—	First Amendment to the Walter Energy, Inc. Involuntary Severance Benefit Plan (Incorporated by reference to Exhibit 10.23.1 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008).
10.20*	—	Agreement dated September 12, 2011 between the Company and Walter J. Scheller, III (Incorporated by reference to Exhibit 10.1 of the Registrant's Quarterly Report on Form 10-Q, filed on November 7, 2011).
10.21*	—	Agreement dated March 1, 2011 between the Company and Keith Calder (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on March 2, 2011).
10.22*	—	Agreement dated July 15, 2011 between the Company and Robert P. Kerley (Incorporated by reference to Exhibit 10.1 of the Registrant's Quarterly Report on Form 10-Q, filed on August 9, 2011).
10.22.1*	—	Agreement dated February 28, 2012 between the Company and Robert P. Kerley.
10.23*	—	Agreement dated March 14, 2006 between the Company and Lisa A. Honnold (Incorporated by reference to Exhibit 10.18 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2010).
10.24.1*	—	Amendment Agreement dated December 22, 2008 between the Company and Lisa A. Honnold (Incorporated by reference to Exhibit 10.18.1 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2010).
10.24.2*	—	Retention and Severance Agreement with Lisa A. Honnold dated February 2, 2011.
10.25*	—	Agreement dated April 1, 2011 between the Company and Michael T. Madden.

E-3

Exhibit Number		Description of Exhibit
10.25.1*	—	Amended and Restated Change-in-Control Agreement dated as of December 18, 2008 between the Company and Michael T. Madden (Incorporated by reference to Exhibit 10.5 of the Registrant's Quarterly Report on Form 10-Q, filed on May 7, 2010).
10.26*	—	Agreement dated April 1, 2011 between the Company and Neil Winklemann.
10.27*	—	Agreement dated June 24, 2011 between the Company and James Griffin.
10.27.1*	—	Amendment No. 1, dated October 28, 2011 to Agreement dated June 24, 2011 between the Company and James Griffin.
10.28*	—	Agreement dated June 24, 2011 between the Company and Graham Foyle-Twining.
10.29	—	Income Tax Allocation Agreement, dated as of May 26, 2006, between Registrant and Mueller Water Products, Inc. (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed on May 30, 2006).
10.30	—	Joint Litigation Agreement, effective as of December 14, 2006, between Registrant and Mueller Water Products, Inc. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on December 20, 2006).
10.31	—	Tax Separation Agreement, dated as of April 17, 2009, between Registrant and Walter Investment Management, LLC (Incorporated by reference to Exhibit 10.3 of the Registrant's Current Report on Form 8-K, filed on April 23, 2009).
10.32	—	Joint Litigation Agreement, dated as of April 17, 2009, between Registrant and Walter Investment Management, LLC (Incorporated by reference to Exhibit 10.4 of the Registrant's Current Report on Form 8-K, filed on April 23, 2009).
10.33	—	Share Purchase Agreement, dated as of November 17, 2010, between Registrant and Audley Capital Management Limited, Audley European Opportunities Master Fund Limited, Audley Investment I and Audley Investment II (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on November 18, 2010).
10.34	—	Credit Agreement, dated as of April 1, 2011, between the Registrant and Walter Energy Canada Holdings, Inc. and the various lenders, including Morgan Stanley Senior Funding, Inc., as administrative agent and collateral agent and the other agents named therein. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on April 6, 2011).
10.35	—	Amendment No. 1 to the Credit Agreement, dated as of January 20, 2012, by and among the Registrant, Western Coal Corp., Walter Energy Canada Holdings, Inc., the various lenders thereunder, Morgan Stanley Senior Funding, Inc., as Administrative Agent and the other agents named therein. (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed on January 25, 2012).

E-4

Exhibit Number		Description of Exhibit
14	—	Business Ethics and Code of Conduct. (Incorporated by reference to Exhibit 14.1 of the Registrant's Current Report on Form 8-K, filed on November 7, 2011).
21	—	Subsidiaries of the Company
23.1	—	Consent of Ernst & Young LLP
24	—	Power of Attorney
31.1	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002—Chief Executive Officer
31.2	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002—Chief Financial Officer
32.1	—	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350—Chief Executive Officer
32.2	—	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350—Chief Financial Officer
95	—	Mine Safety Disclosures Pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 299.104)
101	—	XBRL (Extensible Business Reporting Language)—The following materials from Walter Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Income, (iii) the Condensed Consolidated Statement of Changes in Stockholders' Equity and Comprehensive Income, (iv) the Condensed Consolidated Statements of Cash Flows, (v) Notes to Condensed Consolidated Financial Statements, tagged as blocks of text.

The Exhibits identified above with an asterisk (*) are management contracts or compensatory plans or arrangements.

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