10-K 1 a2207633z10-k.htm 10-K

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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 filer ý   Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller
reporting company)
  Smaller reporting company o

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

   


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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:

    Deteriorating conditions in the financial markets;

    Global economic crisis;

    Market conditions beyond our control;

    Prolonged decline in the price of coal;

    Decline in global steel demand;

    Our customer's refusal to honor or renew contracts;

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

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

    Weather patterns and conditions affecting production;

    Geological, equipment and operational risks associated with mining;

    Unavailability of cost-effective transportation for our coal;

    Significant increase in competitive pressures;

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

    Availability of adequate skilled employees and other labor relations matters;

    Greater than anticipated costs incurred for compliance with environmental liabilities;

    Our ability to attract and retain key personnel;

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

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

    Adverse rulings in current or future litigation;

    Inability to access needed capital;

    Downgrade in our credit rating;

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    Our ability to identify suitable acquisition candidates to promote growth;

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

    Volatility in the price of our common stock;

    Our ability to pay regular dividends to stockholders;

    Potential suitors could be discouraged by our stockholder rights agreement;

    Our exposure to indemnification obligations; and

    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 considered thermal coal or metallurgical 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 considered Assigned 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 4th) 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 at www.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 at http://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 the Mines 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:

    quality of the coal;

    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;

    the percentage of coal ultimately recoverable;

    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;

    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:

    permitting and licensing requirements;

    employee health and safety, including:

    occupational safety and health;

    mine health and safety;

    workers' compensation;

    black lung;

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    reclamation and restoration of property;

    environmental laws and regulations, including:

    greenhouse gases and climate change;

    air quality standards;

    water quality standards;

    management of materials generated by mining and coking operations;

    the storage, treatment and disposal of wastes;

    remediation of contaminated soil and groundwater; and

    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 issue force majeure notices which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of force 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 federal Species 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;

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    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 1/1000th 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

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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

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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              

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  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.

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        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  
                                           

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  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 extends 1/4 mile from any point of observation or measurement. Probable coal is projected to extend from 1/4 mile to 3/4 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

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        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  

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  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.

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        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.

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        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).

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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.

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        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  

GRAPHIC

        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.

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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

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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.

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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

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      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.

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        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  
                         

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  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.

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    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,

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      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

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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

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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

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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.

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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.

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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.

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        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.

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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") in Internal 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

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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

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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.

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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 at www.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.

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SIGNATURES

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

    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
       

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

F-1


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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

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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

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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  
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