10-K 1 a2213222z10-k.htm 10-K

Table of Contents

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 fiscal year ended December 31, 2012

or

o

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                                 to                                  

Commission File Number 001-13711

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

Delaware
(State or other jurisdiction of
incorporation or organization)
  13-3429953
(I.R.S. 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. o

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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, 2012, the registrant's most recently completed second fiscal quarter, as reported by the New York Stock Exchange, was approximately $2.8 billion.

         Number of shares of common stock outstanding as of January 31, 2013: 62,522,420

Documents Incorporated by Reference

Applicable portions of the Proxy Statement for the 2013 Annual Meeting of Stockholders of the Company are incorporated by reference in Part III of this Form 10-K.

   


Table of Contents


WALTER ENERGY, INC. AND SUBSIDIARIES
ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

 
   
  Page

Part I

       

Item 1.

 

Business

  6

Item 1A.

 

Risk Factors

  33

Item 1B.

 

Unresolved Staff Comments

  50

Item 2.

 

Properties

  51

Item 3.

 

Legal Proceedings

  59

Item 4.

 

Mine Safety Disclosures

  59

Part II

       

Item 5.

 

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

  60

Item 6.

 

Selected Financial Data

  62

Item 7.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

  64

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

  85

Item 8.

 

Financial Statements and Supplementary Data

  86

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  86

Item 9A.

 

Controls and Procedures

  86

Item 9B.

 

Other Information

  87

Part III

       

Item 10.

 

Directors, Executive Officers and Corporate Governance

  88

Item 11.

 

Executive Compensation

  90

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

  90

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

  90

Item 14.

 

Principal Accounting Fees and Services

  90

Part IV

       

Item 15.

 

Exhibits, Financial Statement Schedules

  90

 

Signatures

  91

i


Table of Contents


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, as amended (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), 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:

    Unfavorable economic, financial and business conditions;

    Global economic crisis;

    Market conditions beyond our control;

    Prolonged decline in the price of coal;

    Decline in global coal or steel demand;

    Prolonged or dramatic shortages or difficulties in coal production;

    Our customer's refusal to honor or renew contracts;

    Our ability to collect payments from our customers;

    Weather patterns and conditions affecting production;

    Geological, equipment and other operational risks associated with mining;

    Availability of adequate skilled employees and other labor relations matters;

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

    Availability of licenses, permits, and other authorizations may be subject to challenges;

    Concentration of our mineral operations in a limited number of areas subjects us to risk;

    A significant reduction of, or loss of purchases by our largest customer;

    Unavailability of cost-effective transportation for our coal;

    Availability, performance and costs of railroad, barge, truck and other transportation;

    Disruptions or delays at the port facilities used by the Company;

    Risks associated with our reclamation and mine closure obligations; including failure to obtain or renew surety bonds;

    Inaccuracies in our estimates of coal reserves;

    Estimates concerning economically recoverable coal reserves;

1


Table of Contents

    Significant cost increases and delays in the delivery of raw materials, mining equipment and purchased components;

    Failure to meet project development and expansion targets;

    Risks associated with operating in foreign jurisdictions;

    Significant increase in competitive pressures and foreign currency fluctuations;

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

    Greater than anticipated costs incurred for compliance with environmental liabilities or limitations on our ability to produce or sell coal;

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

    Risks related to our indebtedness and our ability to generate cash for our financial obligations;

    Inability to access needed capital;

    Events beyond our control may result in an event of default under one or more of our debt instruments;

    Costs related to our post-retirement benefit obligations and workers' compensation obligations;

    Downgrade in our credit rating;

    Adverse rulings in current or future litigation;

    Our ability to attract and retain key personnel;

    Our ability to identify suitable acquisition candidates to promote growth;

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

    Volatility in the price of our common stock;

    Our ability to pay regular dividends to stockholders;

    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.

        When considering forward-looking statements made by us in this Annual Report on Form 10-K ("Form 10-K"), or elsewhere, such statements speak only as of the date on which we make them. New risks and uncertainties arise 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 Form 10-K after the date of this Form 10-K, except as may be required by law. In light of these risks and uncertainties, keep in mind that any forward-looking statement made in this Form 10-K or elsewhere might not occur.

2


Table of Contents


GLOSSARY OF SELECTED MINING TERMS

        Anthracite coal.    A hard natural coal containing few 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 mine and begin mining operations.

        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 the coal on to a conveyor system 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 ingredient in the production of strong coke. It is evaluated based on the strength, yield and size distribution of coke produced from such coal 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 a limited resource.

        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 a shearer with two rotating drums pulled mechanically back and forth across a long exposed coal face. A hydraulic system supports the roof of the mine while the drums are mining the coal. Conveyors move the loosened coal to an underground mine conveyor which transports to the surface. Longwall mining is the most efficient underground mining method.

        Metallurgical coal.    The various grades of coal with suitable carbonization properties to make coke or be used as a pulverized injection ingredient 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

3


Table of Contents

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 particularly high Btu characteristics 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.

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

        PCI Coal.    Coal used by steelmakers for pulverized coal injection (PCI) into blast furnaces to use in combination with the coke used to produce steel. The use of PCI allows a steel maker to reduce the amount of coke needed in the steel making process.

        Preparation plant.    Preparation plants are 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; (b) grade and/or quality are computed from the results of detailed sampling; and (c) 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 behind within the seam (i.e. pillars left to hold up the ceiling, coal not economical to recover within the mine, etc.) and adjusted for reasonable preparation and handling losses.

        Reclamation.    The process of restoring land and the environment to their original or otherwise rehabilitated 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") without tunneling underground. About two-thirds of total U.S. coal production comes from surface mines.

4


Table of Contents

        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 in U.S. dollars 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, it is usually located several hundred feet or more below the earth's surface, an underground mine's coal is typically removed mechanically and transferred by shuttle car and conveyor to the surface. Underground mines account for about one-third of annual U.S. coal production.

5


Table of Contents


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 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, spun off our Financing business and certain other businesses and closed others to focus on the operations related to mining. With 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 and compliant thermal coal from the mines 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 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 form the core of the Blue Creek Energy Project which 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 and a barge load-out facility near the Port of Mobile terminal in Mobile, 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 our Canadian and U.K. Operations segment. Beginning with the second quarter of 2011, as a result of the Western Coal acquisition, 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. At our legacy Alabama underground mining operations we mine high quality metallurgical coal from the Blue Creek coal seam. Our legacy Alabama underground mines are 1,400 to 2,100 feet underground, making them some of the deepest vertical shaft coal mines in North America. Metallurgical coal mined from the Blue Creek seam contains very low sulfur, has strong

6


Table of Contents

coking properties and high heat value making it ideally suited as a coking coal for steel makers. The Alabama operations also mine thermal coal for sale to industrial and electric utility customers at our surface mines and the underground North River Mine. Our Alabama mining operations have convenient access to the port of Mobile, Alabama through barge and railroad allowing us to minimize our transportation costs. In 2012, the Alabama mining operations produced 6.5 million metric tons of hard coking coal and 2.7 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 seam degasification in the country, producing approximately 50 million cubic feet of gas daily from over 1,740 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. In 2011 and 2012, we temporarily idled the underground and surface operations, respectively, at the Gauley Eagle properties until such time as coal prices improve. Our West Virginia mining operations operate a rail-loading facility and utilize an extensive network of public roads to transport coal to markets or independent river terminals for transfer to barges along the Kanawha River. In 2012, the West Virginia mining operations produced approximately 480 thousand metric tons of metallurgical coal and 390 thousand metric tons of thermal coal.

        The Canadian and U.K. Operations segment includes the operations of surface mines in Northeast British Columbia (Canada) and an underground mine and surface mine in South Wales (U.K.) The Canadian operations consist of three surface mines that produce primarily hard coking and low-volatile PCI coals. The Canadian mines are located adjacent to or nearby existing infrastructure established for the Northeast British Columbia 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 operation mined anthracite coal from its underground mine and thermal coal from its surface mine. In 2012, the Company idled the development of the underground operations until such future time as coal prices adequately rebound and in 2013 the surface mine operations will be closed. All coal mined is processed at the Company's nearby preparation plants where both road and rail coal transportation are available. In 2012, the Canadian and U.K. mining operations produced 2.0 million metric tons of hard coking coal and 2.5 million metric tons of low volatile PCI coal.

        The financial results of our industry segments are included in Note 21 of "Notes to Consolidated Financial Statements" included in this Form 10-K.

Business Strategy

        Our objective is to increase shareholder value through sustained earnings growth and free cash flow generation. Our key strategies to achieve this objective are described below:

        Increasing Metallurgical Coal Production Capacity.    Full year 2012 metallurgical coal production was 11.5 million metric tons, of which 78% was hard coking coal and the remainder low-volatile PCI coal. We expect full year 2013 metallurgical coal production to be in line with production levels in 2012. We believe we are well positioned to increase production when market conditions warrant. Our long-term production growth is expected to be balanced between existing production assets and growth assets such as Blue Creek Energy, Belcourt-Saxon and Aberpergwm.

        Capitalizing on Favorable Long-Term Industry Dynamics.    Although coal prices have been volatile over the past several years, we believe the long-term fundamentals of the global metallurgical coal industry are favorable. Given our premium product and diverse operations, we believe we are well

7


Table of Contents

positioned to capitalize on the expected growth by delivering high quality metallurgical coal to the European, Asian and Latin American markets.

        Focusing on Reducing Costs.    We seek to maintain our focus on reducing costs. We plan on leveraging our infrastructure to increase production and to drive down our cost per ton through economies of scale. We anticipate reducing costs further through, among other initiatives, increased utilization of the Falling Creek Connector Road in Canada, longer panels on the Blue Creek No. 4 mine in Alabama, efficiencies from transitioning Brule to an owner-operated mine and a more centralized supply chain. We anticipate these improvements, combined with competitive transportation costs and a premium product, will expand our margins further.

        Continuing to Provide a Mix of Coal Types and Quantities to Satisfy Our Customers' Needs Across a Variety of Geographic Markets.    By having the ability to produce a variety of metallurgical coal types in three different countries with direct access to Atlantic and Pacific markets, we are able to source and blend our coal from multiple mines to meet the specific needs of our customers. Our broad geographic scope and mix of coal qualities provide us with the opportunities to work with leading steel producers across the globe and provide premium met coal to regions with high and/or growing demand for coal.

        Upholding Our Commitment to Excellence in Safety and Environmental Stewardship.    We intend to maintain our recognized leadership in operating safe mines and in achieving environmental excellence. In addition, our ability to minimize workplace incidents and environmental violations improves our operating efficiency, which directly improves our cost structure and operational performance.

The Coal Industry

        Coal is one of the most 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 largest coal users are in China, the U.S., India, Russia and Japan. The most significant uses for coal are for electricity generation, steel production, cement manufacturing and as a liquid fuel. According to the WCA, approximately 70% of global steel production relies directly on inputs of metallurgical coal. After coking 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 coking 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. The top five steel producing countries are China, Japan, the United States, India and Russia. In 2012, approximately 1.5 billion metric tons of steel was produced globally, relatively equal to that in 2011.

        According to the WCA, approximately 41% of the world's electricity is generated from coal while its use is expected to rise to over 50% to 2030 primarily to meet the expanded use of electricity. According to the International Energy Agency ("IEA"), during 2012, coal was used to generate approximately 45% of the electricity in the United States. Per the IEA, coal's share of the global energy mix will continue to rise, and by 2017 coal will come close to surpassing oil as the world's top energy source.

        Coal reserves, primarily thermal, are available in almost every country worldwide, with recoverable reserves in around 70 countries. According to the WCA it has been estimated that there are over 861 billion tons of proven coal reserves worldwide, which is enough coal to last approximately 112 years at current rates of consumption. The largest coal 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 over the long-term; and it is likely to remain the most affordable fuel available for power generation in many developing and industrialized nations for several decades per the WCA.

8


Table of Contents

        U.S. coal production declined 6.9% in 2012 driven by the decrease in domestic consumption, according to the Energy Information Administration's ("EIA") short-term energy outlook. U.S. coal production is expected to decline by a further 1.2% in 2013, as drawdowns for stock piled inventory combined with a small increase in coal imports are used to meet the small anticipated consumption increase in 2013. The top five coal producing countries in the world are China, the United States, India, Australia and Indonesia.

        Coal is traded all over the world, with coal shipped significant distances by sea to reach certain markets. Over the last 20 years, seaborne trade in thermal coal has increased on average by about 7% each year and seaborne coking coal trade has increased by 1.6% per year, according to the WCA. According to the WCA, the largest exporters of coal in 2012 were Australia, Indonesia, Russia and the United States. The leading exporters of metallurgical coal for steel making, per the WCA, are Australia, the United States and Canada. According to the EIA, U.S. coal exports are currently projected to total a record 125 million short tons in 2012 and are anticipated to decline in 2013. Although exports are anticipated to decline in 2013, exports are still expected to remain in excess of 100 million short tons making 2013 the third straight year at such levels. The primary reasons for the expected decline in coal exports include anticipated continuing economic weakness in Europe, lower international coal prices, and increasing production in Asia.

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"). 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 and PCI coal 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 89% of our proven and probable reserves have heat value characteristics above 13,500 Btus per pound, which make it very desirable to our customers.

        Sulfur Content:    Although sulfur content can differ from seam to seam, approximately 95% of our estimated 401.0 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 is the residue that 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 and increases the coal's weight both of which are undesirable. Our metallurgical coal, particularly the coal from the Blue Creek seam in Alabama, has a low ash rating and moisture content which is highly desirable to our customers.

        Coking Characteristics (metallurgical coal only):    Two important coking characteristics are coke strength and volatility. Volatility of coking coal is used to determine the percentage of coke that a given type of coal would produce. 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.

9


Table of Contents

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 rather injected directly into the lower region of blast furnaces to supply both energy and carbon for iron reduction. The use of PCI can be a substitute for some of the metallurgical coke that would otherwise have been used.

        Thermal and industrial coal is the most abundant form of coal and is commonly referred to as steam coal. Such coal has a 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. Due to our low production levels of anthracite thus far, we have been selling anthracite primarily as a domestic fuel in either hand fired stoker or automatic stoker furnaces. Once the Aberpergwm mine development is completed, our 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 mine coal using both underground and surface mining methods. The mining methods that we employ are 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 2012, 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 conveyor system, 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. The equipment is however 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 and the shields progress through the coal block.

        Underground mining with longwall technology drives greater production efficiency, improved safety, higher coal recovery and lower production costs. We currently operate four 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 main and longwall panel entries. Our operating plan is a longwall to continuous miner production ratio of approximately 80% to 20%.

        In room-and-pillar mining, a network of rooms are cut into the coal seam by remote-controlled continuous miners, while also 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 left behind 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 where longwall mining is not feasible.

        Surface Mining:    We employ surface mining methods when our coal reserves are located close to the surface. In 2012, approximately 40% of the coal we produced came from surface mining operations.

10


Table of Contents

        Surface mining involves removing the topsoil followed by a process of drilling and blasting the earth (overburden) covering the coal seam 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 reclaims disturbed areas. Once we replace the overburden and topsoil, we reestablish vegetation and plant life into the reclaimed area and make other improvements that provide local community and environmental benefits. Ultimate seam recovery for surface mining typically exceeds 80% and is dependent on overburden, coal thickness, geological factors, and equipment used.

Description of Our Business

        We operate our business through two principal business segments of the U.S. Operations and Canadian and U.K. Operations. Our business segment financial information is included in Note 21 within the "Notes to Consolidated Financial Statements" included herein. During 2012, we actively operated 11 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" contained within this Form 10-K.

        The following map shows the major locations of our mining operations:

GRAPHIC

U.S. Operations

        The U.S. Operations segment includes hard coking coal and thermal coal mines in both Alabama and West Virginia, a coke plant in Alabama, and coal bed methane extraction operations also located in Alabama. Metallurgical coal production totaled 7.0 million metric tons and thermal coal production totaled 3.1 million metric tons in 2012.

11


Table of Contents

        Alabama Operations:    Our mining operations in Alabama consist of two underground hard coking 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 hard coking coal mine (the Reid School Mine) and two surface hard coking and thermal coal mines (the Swann's Crossing Mine and the Choctaw Mine).

        Our Alabama underground mining operations are headquartered in Brookwood, Alabama and as of December 31, 2012 were estimated to have approximately 203.4 million metric tons of recoverable reserves located in west central Alabama between the cities of Birmingham and Tuscaloosa. Operating at approximately 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 seam, which contains 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 hard coking 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 hard coking coal. At forecasted production levels, we estimate the current reserves at these mines to have a 20 to 29 year life. As described previously, in May 2011 we acquired mineral rights for approximately 68 million additional metric tons of recoverable Blue Creek hard coking coal reserves located to the northwest of our No. 4 mine. The related mineral leases are expected to form the core of the Blue Creek Energy Project which is for the development of a new underground hard coking coal mine that has an estimated life of 40 to 45 years. Mines No. 4 and No.7 are located near Brookwood, Alabama, and are serviced by CSX rail. Both mines also 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 exported to our international customers via ocean vessels. Approximately 96% of the hard coking coal sales from our Alabama underground mining operations consist of sales to international customers.

        A coal producer is typically responsible for transporting the coal from the mine to an export coal-loading facility. Exported coal is usually sold at the loading port, with the buyer responsible for further transportation from the port to their location. Our Alabama mines are 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 2014.

        Our Alabama natural gas operations extract and sell coal bed methane gas from the coal seams owned or leased by the Company and others. Prior to May 2010, our natural gas operations consisted solely of the Black Warrior Methane Corp., an equal ownership venture with E&P Company, a subsidiary of EP Energy LLC (EP Energy). 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. In addition, these wells degasify methane from the area where our new Blue Creek Energy mine is located. As of December 31, 2012, we had 1,746 wells that produced approximately 18.1 billion cubic feet of natural gas in 2012. The degasification operations have improved mining operations and safety by reducing methane gas levels in our mines.

        We are currently operating three surface mines in Alabama. The Choctaw Mine is located near Parrish in Walker County, Alabama and produces thermal and hard coking coal. The mine has an

12


Table of Contents

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 hard coking coal. Access to Highway 79 provides delivery to local customers via truck. Hard coking 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 hard coking 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 once market conditions permit. This mine is located in Adamsville, Alabama near Highway 78 and expectations are that any coal produced would be delivered to local customers via truck.

        Additionally, we operate the, Walter Coke Plant, 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 up to 120 coke ovens with a capacity to annually produce up to 381,000 tons of metallurgical coke and is the second largest merchant foundry coke producer in the United States.

        West Virginia Operations:    We acquired four mines on two properties in West Virginia through the acquisition of Western Coal on April 1, 2011. Mines on these properties produce both hard coking and thermal coal. The two properties are the Gauley Eagle and Maple properties and each has an 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 are estimated to contain approximately 46.3 million metric tons of recoverable reserves within the Appalachian coal-producing region as of December 31, 2012. The Maple underground coal mine mines in the Eagle coal seam and employs room-and-pillar mining method with continuous miners to produce premium high volatile coking coal, which can be used in the steelmaking process. Due to the challenges in the short-term market outlook and the weak backdrop in demand in 2012, we reduced production at the Maple underground mine. The Gauley Eagle underground mine also employs the room-and-pillar mining method to produce a semisoft coking coal, which can be used in the steelmaking process or as a premium low-sulfur thermal coal. Coal produced at the Maple and Gauley Eagle surface mines is primarily sold in the thermal market. The Gauley Eagle underground mine and Gauley Eagle surface mine were temporarily idled in mid-2011 and mid-2012; respectively, due to economic conditions. The personnel and equipment at these mines was reallocated to the Maple underground and surface mines. At forecasted production levels, we estimate the current reserves in these properties 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 near its customers, ensures continuous and reliable delivery of our products.

        The coking coal produced by our West Virginia operations is sold to domestic coke plants 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 approximately 20 mineable seams which allow us to blend coal to many quality specifications that our customers request.

13


Table of Contents

Canadian and U.K. Operations

        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, including the Perry Creek (Wolverine Mine), EB and Hermann deposits; and the Brazion group, including 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 are estimated to have approximately 135.8 million metric tons of recoverable coal reserves including 72.1 million metric tons at potential future mine sites as of December 31, 2012. 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 2017. 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 2023. 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 2024.

        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 covers approximately 590 miles from our mines to the port at Prince Rupert, British Columbia. From the port facility, shipments are exported to our international customers via ocean 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 throughout 2012. 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 allowed us to increase our hauling capacity per truck and reduces the hauling distance as compared to the previous route from just over 62 miles down to 37 miles.

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

        Additionally, we have a 50% interest in the Belcourt Saxon Coal Limited Partnership which includes two multi-deposit metallurgical coal properties comprising 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.

14


Table of Contents

        Mine planning is progressing for the proposed EB and Hermann mines located near our existing Wolverine mine. These mines 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 2016.

        U.K. Operation:    Our U.K. mining operation consists of an underground and surface mine located in South Wales.

        Our U.K. underground operation is estimated to have approximately 15.5 million metric tons of recoverable reserves as of December 31, 2012. The U.K. operation's primary activity has been the development and expansion of the Aberpergwm underground coal mine located at Glynneath in the Neath Valley. In the fall of 2011, we stopped continuous miner development operations to allow us to focus our attention on completing the new drift opening. While we were able to complete the upper section of the drift during 2012, due to challenges related to an oversupply of coal and decreased demand, we took steps to reduce development spending in this U.K. mine until market conditions improve. This mine produces anthracite coal, which can be sold as a low-volatile PCI coal. The surface mine operations produced thermal coal and were temporarily idled in 2012 until such future time as coal prices adequately rebound.

        The U.K. operation is well located to take advantage of improved demand from U.K. steel mills and the European export market upon recovery of the global economy. Coal is processed in the operation's new preparation plant and loaded at a nearby rail load-out facility or transported to customers by road. In 2012 the mine supplied thermal coal and anthracite coal to a nearby electrical power plant and for various other commercial purposes.

Coal Preparation and Blending

        Our coal mines have coal preparation and blending facilities convenient to each mine. The coal preparation and blending facilities receive, blend, process and ship coal that is produced from the mines. Using these facilities, we are able to ensure a consistent quality and efficiently blend our coal to meet our customers' specifications.

Marketing, Sales and Customers

        Coal prices differ substantially by region and are impacted by many factors including the overall economy, demand for steel, demand for electricity, location, market, quality and type of coal, mine operation costs and the cost of customer alternatives. 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 considered 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 our Asian steel makers. Our marketing strategy is to focus on international markets mostly in Europe, South America and Asia where we have a transportation cost advantage and where our coal is in high demand.

        During 2012, approximately 48% of our metallurgical coal shipments were to customers in Europe, approximately 33% to Asia and approximately 16% to South America. 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 months. Some of our sales of metallurgical coal can, however, occur in the spot market as dictated by available supply and market demand.

15


Table of Contents

        The Company's revenues by coal destination for the year ended December 31, 2012, were as follows:

 
  December 31, 2012
(in thousands)
 

Europe

  $ 922,727  

Asia

    633,162  

North America

    532,078  

South America

    311,928  
       

Total

  $ 2,399,895  
       

        During 2012, our five largest customers represented approximately 27% of our sales and, for the year ended December 31, 2012, no single customer accounted for 10% or more of our consolidated revenues. 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 we believe 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 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

        Virtually 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. We primarily compete with producers of premium metallurgical coal from Australia, Canada and the United States. The principal factors on 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 hard coking 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

        Leading "Pure-Play" Metallurgical Coal Producer.    We are a leading, global, publicly traded producer and exporter of metallurgical coal for the global steel industry. We had total coal reserves of 401.0 million metric tons as of December 31, 2012, which primarily consists of high quality, premium metallurgical coal. We expect 2013 metallurgical coal production to be in line with production levels in 2012. We believe we are well positioned to increase production when market conditions warrant.

        Premium, High Quality Product.    Blue Creek coal from our Alabama mining operations is recognized to be among the highest quality coals in the world. Its characteristics include very low sulfur, low ash and low volatility. These high quality characteristics and high heat value make it ideally suited for steel makers as a coking coal. Contract prices for our premium hard coking coal are consistently equal to the benchmark for premium coking coals. Hard coking coal produced from the Canadian mining operations has been well accepted by steel makers, currently having six of the top ten

16


Table of Contents

largest steel mills in the region served as customers. The low-volatile PCI coal from the Canadian operations has also been widely accepted by customers.

        Attractive Industry Dynamics.    We expect that international demand for our metallurgical coal will increase in the future, driven by favorable projected global growth trends and the high quality of our coal compared to many other coal producing regions around the world. Metallurgical coal demand is underpinned by projected growth in world steel production of 3.2% in 2013, according to the World Steel Association. Steel producers are also rebuilding inventories and new supply of metallurgical coal is constrained by rail and port capacity in emerging supply basins.

        Sales and Geographic Diversification.    We operate up to twelve mines in three countries and have access to both the Atlantic and Pacific Seaborne markets. This geographical advantage provides important diversity in terms of production, markets, transportation and labor. We have operational flexibility due to this diversification, which makes us less reliant on any single mine for a significant portion of our earnings or cash flows. We believe the diversity of our operations and reserves also provides us with a significant advantage over competitors with operations in a single coal producing region as it allows us to diversify our customer base, with no one customer responsible for a significant portion of our revenues. This geographic diversification also allows us to source the high quality coals we produce from multiple sources and to blend to meet the exact specifications of our customers. In addition, with access to both the Atlantic and the Pacific markets, we believe that we are well positioned to take advantage of any growth in the seaborne coal market and to supply metallurgical coal to Latin America, Asia and Europe.

        Significant Organic Growth Opportunities.    We believe that our organic growth opportunities in metallurgical coal are well balanced between existing production assets and growth development projects such as Willow Creek, Aberpergwm, Blue Creek Energy and Belcourt Saxon. As the demand for high quality metallurgical coal in the global marketplace grows, we expect that we will be able to provide customers with increasing quantities of premium metallurgical coal.

        Strong Financial Profile.    Our premium priced coal and emphasis on low cost production provides strong margins and free cash flow generation over the long-term. As of December 31, 2012, we had $444.8 million of cash on hand and undrawn capacity under our revolving credit facility and no significant amount of debt maturing until 2015. With a significant portion of total debt prepayable, we expect to further enhance our credit profile through deleveraging.

        Port Capacity and Low Cost Transportation Infrastructure.    We believe we have sufficient port capacity to ship all of our current production and forecasted production growth. We have an agreement with the Port of Mobile in Alabama through July 31, 2016 with current capacity of approximately 6.5 million metric tons a year and capability to develop our port location properties to add additional capacity as needed. In Canada, Ridley Terminals, located in the port utilized by our Canadian operations, can handle 12 million metric tons per year of coal with the potential to expand to 24 million metric tons per year. We are able to minimize transportation costs due to the close proximity of our mines to our ports, as well as leverage our transportation infrastructure. Our principal mines in our Alabama operations are located a short distance from the Port of Mobile and are serviced by CSX rail. We also have port access through our barge load-out facility on the Black Warrior River. Because customers for our Alabama hard coking 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 rail lines, minimizing transportation costs to Ridley Terminal.

        Highly Regarded and Experienced Management Team.    Our top nine officers have an average of more than 30 years of experience. Our management team has demonstrated a history of increasing productivity, increasing production and maintaining strong customer relationships. We are committed to the safety and well-being of our employees and communities, respecting the environment in which we

17


Table of Contents

do business, the continued growth of the Company's assets, and putting in place a conservative capital structure while creating long-term shareholder value.

        We maintain excellent relationships with our customers.    Customers want high quality products, delivered on a timely basis at a fair price. Given our premium products and our production and transportation efficiencies, we have historically been able to reliably deliver premium products at competitive prices 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.    To meet the exact needs of our customers, we are able to blend the high quality coals we produce 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, 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 and local 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 at 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, continuation or expansion 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) related to the protection of the environment, 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.

        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 some expenditures continue to be made at several facilities to comply with ongoing

18


Table of Contents

monitoring or investigation obligations. Expenditures relating to environmental compliance are a major cost consideration for our 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 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 and local authorities data pertaining to the effect or impact that any proposed exploration project for 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 state, productive use or other permitted condition. The requirements are costly and time-consuming and may delay commencement or continuation of exploration, production or expansion at our operations. Typically we submit 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 certain monitoring and reporting requirements. We typically submit necessary permit renewal applications several months prior to expiration.

        Applications for permits and permit renewals at our mining, coking and gas 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, continuation or expansion of our mining, coking and gas 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.

U.S. Operations

Mine Safety and Health

        The Mine Safety and Health Administration ("MSHA") under the Federal Mine Safety and Health Act of 1977 (the "Mine Act"), 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 procedures. 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

19


Table of Contents

$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 (the "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 requirements related to mining safety and health matters. Section 1503 of the Dodd-Frank Act requires public companies that own or operate a "coal or other mine" in the United States to include certain specified disclosures regarding health and safety violations that may have previously been considered immaterial in their periodic reports filed under the Exchange Act. Section 1503 of the Dodd-Frank Act also requires a reporting company operating coal mines or with subsidiaries that operate coal mines to file a Current Report on Form 8-K upon receipt of written notice from MSHA of an imminent danger order under Section 107(a) of the Mine Act or of any warning from MHSA that the mine either has a pattern of health or safety violations, or has the potential for such a pattern. On August 13, 2012, our wholly-owned subsidiary, Jim Walter Resources, Inc. and the operator of our No. 7 Mine, received imminent danger Order No. 8522884 (the "Order") under section 107(a) of the Mine Act. In the Order, MSHA asserted that methane was allowed to accumulate in a roof cavity in a long crosscut on the underground No. 8 Continuous Miner Section. Shortly thereafter, according to the Order, a line curtain was used "to sweep the methane out," and the Order was quickly terminated. No injuries resulted from the condition described in the Order. See "Exhibit 95" included in this Form 10-K for information concerning mine safety violations and other regulatory matters pursuant to the requirements of Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K (17 CFR 229.104).

Workers' Compensation and Black Lung

        We are insured for workers' compensation benefits for work related injuries that occur within our U.S. operations. We retain the first $1 million to $2 million per accident for all of our U.S. subsidiaries and are insured above the deductible for statutory limits, with the exception of Jim Walter Resources located in Alabama, where we retain any amount in excess of $10 million per accident. 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 Mine Act, 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 Financial Condition and 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 and the West Virginia Department of Environmental Protection reviews and approves SMCRA permits in West Virginia.

20


Table of Contents

        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 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, imposes a general funding 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 another 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. This settlement agreement did not prescribe any specific provisions that must be included in either the proposed or the final rule. While this ongoing rulemaking takes place, the 2008 rule remains in effect on lands for which OSM is the regulatory authority. The OSM anticipates publishing a proposed rule and draft impact statement during 2013.

        We accrue for future reclamation costs anticipated for mine closures. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our experience related to similar activities. 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, timing of reclamation expenditures, and the assumed credit-adjusted risk-free interest rates. Furthermore, these obligations are typically 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. As of December 31, 2012, we accrued $55.5 million for our asset retirement obligations for all of our U.S. mining operations, most of which will be incurred at our underground mining operations near the end of the mines' lives. As of December 31, 2012, we had accrued $89.5 million for all our asset retirement obligations.

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 may also require posting of collateral, typically in the form of letters of credit, to secure the surety bonds. As of December 31, 2012, we had outstanding surety bonds with parties for post-mining reclamation at all of our U.S. mining operations totaling $68.6 million, plus $14.3 million for miscellaneous purposes. As of December 31, 2012, we maintained letters of credit totaling $10.8 million to secure these surety bonds.

21


Table of Contents

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, primarily the thermal 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 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, had the Senate ratified the Kyoto Protocol, which it did not, the United States would have been required to reduce emissions to 93% of 1990 levels from 2008 through 2012. Efforts to reach additional international agreements to regulate GHGs are on-going.

        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 the EPA to regulate GHGs from mobile sources, which in turn resulted in some initial regulation of GHGs from stationary sources under the Clean Air Act. The 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 the 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, the 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 the EPA's 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 the 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, much of the methane is captured and sold into the natural gas market and used as a clean fuel. 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, Jim Walter Resources 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

22


Table of Contents

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 could be reduced or eliminated.

        The EPA releases annual GHG reports that are filed by approximately 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). A three-judge panel of the U.S. Court of Appeals in Washington ruled that the EPA properly concluded that greenhouse gases are pollutants that endanger human health and that opponents don't have the legal right to challenge rules determining when states and industries must comply with regulations curtailing these emissions.

        On August 12, 2012, the Obama Administration finalized standards that require automakers to nearly double the average fuel economy of new cars and light-duty trucks to 54.5 miles per gallon by Model Year 2025. The standards issued by the U.S. Department of Transportation (DOT) and the EPA build on the standards for cars and light-duty trucks for Model Years 2011-2016 which raised average fuel efficiency by 2016 to the equivalent of 35.5 miles per gallon.

        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 agreement that would obligate major GHG emitting countries (including the U.S., China and India) to begin reducing 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 second commitment period of eight years was decided during COP-18. 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 the fuel source of energy production 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 negatively impacting our revenues as well as reduce the value of our reserves (although switching to a cleaner alternative fuel 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 CAA 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 CAA.

        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

23


Table of Contents

EPA has developed various industry-specific MACT standards pursuant to this requirement. The CAA requires the EPA to promulgate regulations establishing emission standards for each category of Hazardous Air Pollutants. The 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 National Emissions Standards for Hazardous Air Pollutants ("NESHAPS"). 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 enacted in the early 1990's. The portion of NESHAP which applies to coke ovens 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 the 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 the 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, the 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 the EPA re-sets these dates. On December 21, 2012, the EPA released its final rules setting requirements for industrial boilers and process heaters, as well as commercial and industrial waste incinerators. The magnitude of the impact of any such anticipated changes cannot be estimated at this time.

        The CAA also requires the EPA to develop and implement National Ambient Air Quality Standards ("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 the 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.

        The 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 committed the agency to publish designations for areas not attaining the 2008 ozone ambient air standard by May 31, 2012.

        Litigation over the 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 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 delay 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 and may adversely affect the demand for coal.

24


Table of Contents

        On April 30, 2012, the EPA published a final rule designating areas of the country not meeting the 2008 revisions to the ozone ambient air standards and attainment deadlines for meeting those standards. On May 31, 2012, the EPA completed area designations for the Chicago metropolitan area. The State of Indiana and industry groups have filed, in the U.S. Court of Appeals for the DC Circuit, a petition for review challenging the EPA's designation of the 11 county greater Chicago area as "nonattainment" of the 2008 ozone ambient air quality standards. On December 14, 2012, the EPA denied petitions from environmental and industry groups to reconsider the agency's final ozone attainment designations published in April.

        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 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 transitioning to alternative clean 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. The EPA has proposed to update emission limits for new power plants under the Mercury and Air Toxics Standards (MATS). The new proposed standards affect only new coal- and oil-fired power plants that will be built in the future. The proposal, issued on November 16, 2012, does not change the final emission limits for existing power plants. The EPA says it has reconsidered the new source limits for MATS based on new information and analysis that became available to the agency after the rule was finalized. The EPA says it projects that the proposed updates will result in no significant change in costs, emission reductions or health benefits from MATS. The EPA is also proposing to revise and clarify requirements that apply during periods of startup and shutdown in MATS and startup and shutdown for particulate matter in the Utility New Source Performance Standards (NSPS), and is proposing other minor technical corrections. The EPA is expected to issue a final rule in March 2013.

        On January 22, 2010, the 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. On January 20, 2012, the EPA designated all areas of the country as "unclassifiable/attainment" for the 2010 NO2 NAAQS. The available air quality data show that all monitored areas in the country meet the 2010 NO2 NAAQS for 2008-2010. Additional emission control expenditure may be required at coal-fueled power plants and may adversely affect the demand for coal.

        On June 2, 2010, the EPA revised the NAAQS for Sulfur Dioxide (SO2) by establishing a new one-hour standard and revoking the existing 24-hour and annual standards. On August 3, 2012, the EPA published a rule extending the deadline for designating areas not attaining the standard to June 3, 2013 and requires state implementation plans by 2014 and standards to be met by August, 2017. Additional emission control expenditures 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. The EPA's finding concerning GHG endangerment of public health and welfare (see Climate Change above) may lead to regulation of GHG emissions from stationary sources under the Clean Air Act. In connection with that finding, the EPA also finalized a tailoring rule which would set emission thresholds for GHG regulation under the EPA's current Clean Air Act stationary source permitting requirements. Finalized on May 13,

25


Table of Contents

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 CWA and corresponding state laws and are in substantial compliance with such permits. However, new requirements under the CWA 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, the RCRA also addresses the environmental effects of certain past hazardous waste treatment, storage and disposal practices. In addition, the 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.

        The 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 the RCRA. Any change or reclassification of this exemption could significantly increase our coal mining costs.

        Our coking operations entered into a RCRA Section 3008(h) Administrative Order on Consent (Order) with an effective date of September 24, 2012 with the EPA. The objectives of the 2012 Order are to perform Corrective Measure Studies, implement remedies if necessary, as well as implement and maintain institutional controls if necessary at the Walter Coke facility. As of December 31, 2012, the Company had an amount accrued that is probable and can be reasonably estimated for the costs to be incurred to identify and define remediation actions, as well as to perform certain remediation tasks which can be quantified. The amount of this accrual is not material to the financial statements. While it is probable that the Company will incur additional future costs to remediate environmental liabilities at the Walter Coke facility, the amount of such additional costs cannot be reasonably estimated at this time. For additional information regarding significant enforcement actions, capital expenditures and costs of compliance, see Part I, "Item 3. Legal Proceedings" and "Environmental Matters" in Note 18 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

26


Table of Contents

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, and (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

        We have operations within Canada 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 or place that is occupied or habitually occupied by one for more individuals of their species 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 British Columbia Forest and Range Practices Act 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.

        The species of the highest concern in respect of our 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. Delays in obtaining new or amended permits and mining tenures in areas frequented by caribou 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 $1.0 million Canadian dollars ("CAD"). In addition, in November 2012, the province of British Columbia announced the development of an implementation plan to increase the current

27


Table of Contents

population of Northern Caribou in the South Peace Region. Although the implementation plan to date has not been finalized, we could be required to pay certain in-lieu payments to offset the impact of our industrial activity in Northern Caribou habitat regions. These amounts would be paid into a trust fund set aside to support measures to increase the Northern Caribou population in the South Peace Region.

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, nitrate and sulphate 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.

        We are currently not meeting revised provincial water quality guidelines relating to selenium, nitrate and sulphate levels at the Brule mine, and are cooperating with the British Columbia Ministry of Environment to reduce selenium levels and other contaminants of concern in our effluent to meet these guidelines. As a result, we are considering various alternatives for water management and treatment at the Brule mine, which could 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 plants, as well as the disposal, release or spilling of some chemical products used by coal and coking companies in their 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 accommodations of the First Nation's rights by the company may be necessary prior to granting the requested authorization and therefore could detrimentally impact the development, production or expansion of our mining operations.

28


Table of Contents

        As we are governed by a significant number of permits in British Columbia and anticipate the need to both obtain new permits and amend existing permits in connection with our current and future operations, the government's duty to consult with First Nations may have a significant impact on our 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 our permits and authorizations to judicial review, lengthy court processes and the risk of cancellation of the government authorization.

        We strive to build beneficial relationships with the First Nations in our areas of operation and participate in any consultation process that relates to our operations. Although ultimately the duty to consult is a duty of the government, the consultation process would not progress without our involvement and our strong interest in ensuring that the process is carried out effectively and comprehensively. We are committed to engaging with First Nations in a meaningful way and devote 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, among 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 offense continues. Liability under the Act is for owners of the property or substance, as well as their directors, officers, agents, tenants, occupiers, partners or persons actually in charge of the property or substance.

        We are 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. If such determination is made, it could have an adverse impact on our development, production and expansion of mine operations and the related operational costs in the area.

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 we have 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 we consider that a federal environmental

29


Table of Contents

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.

        Our environmental assessment certificate in respect of our Hermann mine project is expiring in November 2013. We have submitted an application for a one-time five year extension of this environmental assessment certificate until November 2018.

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 an 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. We accrue for reclamation costs to be incurred related to the closure of our mines once they have reached the end of their life. Additionally, under the terms of each mine permit, we are required to submit an updated mine plan every five years. We are currently in the process of submitting an updated five year mine plan for Wolverine mine by March 2013 and Brule mine by December 2013.

        Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our experience for similar activities. As of December 31, 2012, we accrued $29.0 million for our asset retirement obligations at all of our Canadian mining operations.

        As of December 31, 2012, we had posted letters of credit for post-mining reclamation, as required by our Mines Act permits, totaling $22.7 million for all of our Canadian operations.

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 Wolverine 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 targets 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 imposed 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 the provincial government has not released the regulatory details of the proposed cap and trade system,

30


Table of Contents

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. 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 as well as any impact such enactment may have on our operations. Any such impact would have a significant adverse impact on our operations.

U.K. Environmental Laws

        Our 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 our results of operations in the most recently completed financial year and we do not expect that compliance with these laws will have a material impact on our results of operations in the current or future financial years. As of December 31, 2012, we have accrued $5.0 million for our asset retirement obligations at all of our U.K mining operations. Further, as of December 31, 2012, we had posted cash bonds for post-mining reclamation totaling $2.1 million for all of our U.K. operations.

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, 2012, we employed approximately 4,100 employees, of whom approximately 3,100 were hourly employees and 1,000 were salaried employees. As of December 31, 2012, unions represented approximately 2,300 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.

31


Table of Contents

Additional Information

        We were incorporated in Delaware in 1987. Our principal executive offices are located at 3000 Riverchase Galleria, Suite 1700, Birmingham, Alabama 35244, and our telephone number at that address is (205) 745-2000.

        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"). We also make available through our website other reports filed with or furnished to the SEC under the Exchange Act, including our proxy statements and reports filed by officers and directors under Section 16(a) of the Exchange Act. We do not intend for information contained in our website to be part of this Form 10-K. Additionally, we 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 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. 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."

32


Table of Contents

Item 1A.    Risk Factors

        Our business is subject to general risks and uncertainties which could materially adversely affect our business, financial condition, results of operations or stock price. Additional risks and uncertainties not currently known to us or that we may deem immaterial may also materially adversely affect our business, financial condition, results of operations or stock price.

Risks Related to 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 or 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 could 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, reliability and availability 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 as it compares to that of natural gas and the consumption patterns of the domestic electric power generation industry, which, in turn, is influenced by demand for electricity and

33


Table of Contents

technological developments. We estimate that a 10% decrease in the price of metallurgical coal for the full year 2012 would have resulted in an increase in our pre-tax loss by $194.0 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 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 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;

    availability of adequate skilled employees and other labor relations matters;

    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.

34


Table of Contents

        These risks and conditions could result in damage to or the destruction of our 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 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 over 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 or our financial position.

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

        Our right to mine some of our coal 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 or gas reserves until we have committed to developing those properties or coal or gas reserves. We may not commit to develop property or coal or gas 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 or coal or gas reserves 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 primarily 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 these areas.

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

        For the year ended December 31, 2012, we derived approximately 27% of our total sales revenues from sales to our five 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 otherwise unable to sell coal to those customers or on terms favorable to us, our profitability could suffer significantly.

35


Table of Contents

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 transport our products. Disruption of any of these transportation services because of weather related problems, which are variable and unpredictable; strikes, lock-outs; accidents; transportation delays or other events could impair our ability to supply our products to our customers, thereby resulting in lost sales and reduced profitability.

        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 our profits. In addition, there are limited cost effective alternatives to the port. Similar to the U.S. operations, substantially all of the coal produced by our Canadian operations is exported to port facilities by one railway for which there are limited alternatives. Additionally, all of our 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 our ability to operate and to the extent that alternate sources 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 our revenues as a result of delays of ocean vessels and could significantly affect our costs and relative competitiveness compared to the supply of coal and other products from our competitors.

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

        The consolidation of the 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.

36


Table of Contents

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 operations. 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.

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

        The majority of employees of our underground mining operations in Alabama are represented by the 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. Our collective bargaining agreement expires on December 31, 2016. The majority of our employees in our surface mines in Alabama are represented by the UMWA, and we are currently negotiating initial labor agreements with the UMWA for these operations. At our coking operation, our contract with the United Steelworkers of America expires on December 6, 2015. We experienced a strike at our coke facilities at the end of 2001 that lasted eight months.

        A majority of our employees at our Wolverine and Willow Creek mining operations in Canada are also unionized. The Wolverine employees are represented by the United Steelworkers, Local 1-424, and our collective agreement with the Steelworkers for that location expires on July 31, 2015. The employees at our Willow Creek mining operations are represented by Christian Labour Association of Canada ("CLAC"), and our collective agreement with CLAC for that location expires on November 30, 2013.

        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; the Mines Act (British Columbia) and the Reclamation Code for Mines in British Columbia in Canada; and the Environmental Protection Act 1990, Environment Act 1995, Environmental Permitting Regulations 2010, and Town and Country Planning Act 1990 in the U.K.

37


Table of Contents

have established operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. We accrue for reclamation costs associated with final mine closure. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our experience for similar activities. 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. As of December 31, 2012, we had accrued $89.5 million for all our asset retirement obligations.

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. 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. 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, such as 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 operational 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

38


Table of Contents

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 such First Nations rights. As issues relating to Aboriginal and Treaty rights and consultation continue to be heard, developed and resolved in Canadian courts, we will 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 our 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 our 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 on 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 and sell to customers 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. Such risks 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.

39


Table of Contents

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;

    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 one or more of 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 possible 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

40


Table of Contents

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 operations, 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 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 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 CWA 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, our construction and mining activities require Section 404 permits. The issuance of permits to construct valley fills and refuse impoundments under Section 404 of the CWA 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. Stringent water quality standards for materials such as selenium and arsenic have recently been issued. 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.

        In April 2010, the EPA issued comprehensive guidance to provide clarification as to the water quality standards that should apply when reviewing CWA 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. The U.S. District Court for the District of Columbia ruled that the EPA overstepped its statutory authority under the CWA and SMCRA, and

41


Table of Contents

infringed on the authority reserved to state regulators under those statutes when it issued the guidance. The EPA is appealing the decision.

        Additionally, in January 2011, the EPA rescinded a federal CWA 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. A federal judge reversed the decision by the EPA to revoke the permit and the EPA has appealed the decision.

        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 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 effects on caribou habitat, particularly in areas where caribou have been identified as a threatened species under the federal Species at Risk Act. It is unknown what future changes will be implemented to the permitting review and issuance process or to other aspects of surface mining operations 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 release resulting from 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. EPA. As part of the Fiscal Year 2008 Consolidated Appropriations Act, signed into law on December 26, 2007, the EPA was ordered to publish a rule requiring public reporting of GHG emissions from large sources. The GHG Reporting Program database was published for the first time on January 11, 2012 and includes data reported under the rule and provides the first comprehensive nationwide GHG

42


Table of Contents

emissions database for the United States, even though electric power plants have been reporting their carbon dioxide emissions for two decades under the CAA Amendments of 1990.

        Canadian legal and regulatory approaches include both federal and provincial regulations requiring the reporting of GHG emissions. 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 facility basis. In British Columbia, the government imposes 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 users switching from coal to other alternative clean fuel substitutes. The anticipation of such additional requirements could also lead to reduced demand for some of our products. Alternative clean 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 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 amount of damages assessed.

        We maintain extensive coal refuse areas and slurry impoundments or underground injection at 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 create liability for related personal injuries, property damages and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and the assessment of damages arising out of such 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 related 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" ("AMD"). Treatment 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.

43


Table of Contents

Other Business Risks

Our substantial indebtedness could adversely affect our financial position and our ability to meet our obligations under our debt instruments.

        We have a significant amount of indebtedness. As of December 31, 2012, we had indebtedness of approximately $2.4 billion outstanding under a $2.7 billion credit agreement ("Credit Agreement") and $500 million aggregate principal amount of 9.875% senior notes due in 2020. Under the repayment schedule relating to the Credit Agreement, we will not be required to make mandatory principal payments in 2013; however, in 2014 we will be required to make a minimum payment of $77 million. 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. We may be unable to generate sufficient cash flow from operations and future borrowings, or other financing may be unavailable in an amount sufficient to enable us to fund our future financial obligations or our other liquidity needs.

        Our substantial indebtedness could make it more difficult for us to borrow money in the future and may reduce the amount of money available to finance our operations and other business activities and may have other detrimental consequences, including the following:

    we may have to dedicate a substantial portion of our cash flow from operations to the payment of principal, premium, if any, and interest on our debt, which will reduce funds available for other purposes;

    limiting our ability to obtain additional financing to fund growth for areas such as new mergers and acquisitions, working capital and capital expenditure needs, or our ability to meet debt service requirements or other cash requirements;

    exposing us to the risk of increased interest costs if the underlying interest rates rise on our existing credit facility or other variable rate debt;

    making it more difficult to obtain surety bonds, letters of credit or other financing, particularly during periods in which credit markets are weak;

    causing a decline in our credit ratings;

    limiting our ability to compete with companies that are not as leveraged and that may be better positioned to withstand economic downturns;

    limiting our ability to acquire new coal reserves and/or plant and equipment needed to conduct operations; and

    limiting our flexibility in planning for, or reacting to, and increasing our vulnerability to, changes in our business, the industry in which we compete and general economic and market conditions.

        If we further increase our indebtedness, the related risks that we now face, including those described above, could intensify.

Our ability to generate the significant amount of cash needed to service our debt and financial obligations, to refinance all or a portion of our indebtedness or obtain additional financing depends on many factors beyond our control.

        Our ability to make payments on and to refinance our indebtedness depends on our ability to generate cash in the future. We are subject to general economic, climatic, industry, financial, competitive, legislative, regulatory and other factors that are beyond our control. In particular, economic conditions have previously caused and could in the future continue to cause the price of coal to fall and our revenue to decline and could adversely affect our ability to repay our indebtedness. As a

44


Table of Contents

result, we may need to refinance all or a portion of our indebtedness on or before maturity. Our ability to refinance our debt or obtain additional financing will depend on, among other things:

    our financial condition at the time;

    restrictions in the agreements governing our indebtedness; and

    other factors, including conditions in the financial and capital markets or coal industry.

        If our cash flows and capital resources are insufficient to fund our debt service obligations, we could face substantial liquidity problems and could be forced to reduce or delay investments and capital expenditures or to dispose of material assets or operations, seek additional debt or equity capital or restructure or refinance our indebtedness. We may not be able to affect any such alternative measures on commercially reasonable terms or at all and, even if successful, those alternative actions may not allow us to meet our scheduled debt service obligations. The Credit Agreement and the indenture governing our notes restrict our ability to dispose of assets and use the proceeds from those dispositions and may also restrict our ability to raise capital from debt or equity financings to repay other indebtedness when it becomes due. Additionally, we may not be able to consummate such dispositions or to obtain proceeds in an amount sufficient to meet any debt service obligations when due.

        In addition, we conduct a substantial portion of our operations through our subsidiaries. Accordingly, repayment of our indebtedness is dependent on the generation of cash flow by our subsidiaries and their ability to make such cash available to us, by dividend, debt repayment or otherwise. Unless they are guarantors of the notes or other indebtedness, our subsidiaries do not have any obligation to pay amounts due to our indebtedness or to make funds available for that purpose. Our subsidiaries may not be able to, or may not be permitted to, make distributions to enable us to make payments in respect to our indebtedness. Each subsidiary is a distinct legal entity and under certain circumstances, legal and contractual restrictions may limit our ability to obtain cash from our subsidiaries. While the indenture governing the notes and the Credit Agreement limit the ability of our subsidiaries to incur consensual restrictions on their ability to pay dividends or make other intercompany payments to us, these limitations are subject to qualifications and exceptions. In the event that we do not receive distributions from our subsidiaries we may be unable to make required principal and interest payments on our indebtedness.

        We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all. If our operations do not generate sufficient cash flows, and additional borrowings or refinancing are not available to us, we may not have sufficient cash to enable us to meet all of our obligations.

        If we cannot make scheduled payments on our debt or are not in compliance with our covenants and are not able to amend those covenants, we will be in default and holders of the notes could declare all outstanding principal and interest to be due and payable, the lenders under the Credit Agreement could terminate their commitments to loan money, the lenders could foreclose against the assets securing their borrowings and we could be forced into bankruptcy or liquidation. If we are not able to generate sufficient cash flow from operations, we may need to seek an amendment to our Credit Agreement to prevent us from potentially being in breach of our covenants.

A "change in control" under the Credit Agreement, which may occur as a result of events beyond our control, would result in an event of default that could materially and adversely affect our results of operations and our financial condition.

        A "change in control" as defined in our Credit Agreement is considered an event of default and is deemed to occur when any person or group beneficially owns 35% or more of our common stock or where our Board of Directors ceases to consist of a majority of continuing directors. Upon a change in control, the lenders could elect to declare due and payable immediately all amounts due, including

45


Table of Contents

principal and accrued interest. We may be unable to prevent a change in control from occurring at a time when we are unable to repay or refinance such indebtedness and the holders of such debt could proceed against the collateral securing that indebtedness. In addition, a change of control under our Credit Agreement could also result in an event of default under one or more of our other debt instruments.

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 or 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, our 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 of 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, 2012, we estimated that our pension plans' aggregate projected benefit obligation had a present value of approximately $295.9 million, and the fair value of plan assets was approximately $233.0 million. As of December 31, 2012, we estimated that our postretirement health care and life insurance plans' aggregate projected benefit obligation had a present value of approximately $662.5 million and such benefits are not required to be funded. In respect to the funding obligations for our pension plans, we must make minimum cash contributions on a quarterly basis. 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 to lose value. As a result, in such circumstances 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 the pension plan in 2013 is $6.8 million. We have estimated these obligations based on assumptions described under the heading "Critical Accounting Estimates—Employee Benefits" in Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," 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.

        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

46


Table of Contents

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 changes.

        Beginning in 2018, the 2010 healthcare legislation will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of this excise tax. Until these regulations or interpretations are published, it is impractical to reasonably estimate the ultimate impact of the excise tax on our future healthcare costs or postretirement benefit obligations. We have incorporated changes to our actuarial assumptions to determine our postretirement benefit obligations utilizing 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, failure of the Plan to meet ERISA's minimum funding requirements, lower than expected returns on pension fund assets, or other funding deficiencies.

        We face risks and uncertainties by participating in the 1974 Pension Plan. All assets contributed to the plan are pooled and available to provide benefits for all participants and beneficiaries. As a result, contributions made by us benefit the employees of other employers. If the 1974 Pension Plan fails to meet ERISA's minimum funding requirements or fails to develop and adopt a rehabilitation plan, a nondeductible excise tax of five percent of the accumulated funding deficiency may be imposed on an employer's contribution to this multi-employer pension plan. As a result of the 1974 Pension Plan's "seriously endangered" status, steps must be taken under the Pension Act to improve the funded status of the plan. In an effort to improve the Plan's funding situation, the Plan Settlors adopted a Funding Improvement Plan as of May 25, 2012. The Funding Improvement Plan states that the Plan must avoid a funding deficiency for any plan year during the funding improvement period and improve the Plan's funded status by at least 20% over a 15-year period. The funding improvement period begins July 1, 2014 and ends June 30, 2029. The Funding Improvement Plan calls for increased contributions beginning January 1, 2017 and lasting throughout the improvement period so that the Plan can meet the applicable benchmarks and emerge from seriously endangered status by the end of the Funding Improvement Period.

        Under current law governing multi-employer defined benefit plans, if we voluntarily withdrew from the 1974 Pension Plan, the currently underfunded multi-employer defined benefit plan would require us to make payments to the plan which would approximate the proportionate share of the multiemployer plan's unfunded vested benefit liabilities at the time of the withdrawal.

        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, we would be liable for a proportionate share of the plan's unfunded vested benefit liabilities upon our withdrawal. Through June 30, 2013, our estimated withdrawal liability for the multiemployer pension plans amounted to $627.6 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 could affect our internal cost of capital estimates and therefore impact operational and investment decisions.

47


Table of Contents

We are responsible for portions of our workers' compensation and certain medical and disability benefits, and greater than expected claims could reduce our profitability.

        We are responsible for portions of our 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 specific subsidiary 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 for portions of this liability 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 heading "Critical Accounting Estimates—Employee Benefits" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

        If the number or severity of claims 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, or have a material adverse effect on our business, financial condition or results of operations.

        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. In addition, such litigation could have a material adverse effect on our business, financial condition or results of operations. For information regarding our current significant legal proceedings, see Part I, "Item 3. Legal Proceedings," "Note 11—Income Taxes" and "Note 18—Commitments and Contingencies" to the "Notes to Consolidated Financial Statements" included in this Annual Report on Form 10-K.

Our executive officers and other key personnel are important to our success and the loss of one or more 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 key 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 and this could impair our growth.

        Our ability to grow depends in part 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

48


Table of Contents

cultures and achieving cost reductions and cross-selling opportunities. We may 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 and the effect this could have on commodity prices for our products;

    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 or customers;

    actions by our principal stockholders;

    trading volumes of our common stock;

    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 fund our obligations 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 required 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.

49


Table of Contents

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 takes 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, any tax resulting from such actions would be 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 or results of operations.

Item 1B.    Unresolved Staff Comments

        None

50


Table of Contents

Item 2.    Properties

        The administrative headquarters and production facilities of the Company and its subsidiaries as of December 31, 2012 are summarized as follows:

 
   
   
   
  Building
Square
Footage
 
 
  Business Unit /Location    
  Land
Acreage(1)
 
Reportable Segment
  Principal Operations   Leased   Owned  

U.S. Operations

  Alabama Operations:                        

  Blue Creek Coal Sales                        

 

Mobile, AL

 

Administrative headquarters

                1,151  

 

Mobile, AL

 

River terminal—Owned

    49              

  Blue Creek Energy, Inc.                        

 

Tuscaloosa County, AL

 

Coal mines and land holdings—Owned

    714              

 

Tuscaloosa County, AL

 

Coal mines and land holdings—Leased

    20,806              

  Jim Walter Resources                        

 

Brookwood, AL

 

Administrative headquarters & mine support facilities

                732,855  

 

Various Counties in AL

 

Coal mines, land holdings and coal bed methane fields—Owned

    16,423              

 

Various Counties in AL

 

Coal mines, land holdings and coal bed methane fields—Leased

    31,292              

  Walter Black Warrior Basin                        

 

Tuscaloosa County, AL

 

Administrative headquarters & mine support facilities

    31           15,425  

 

Tuscaloosa County, AL

 

Coal bed methane fields—Leased, developed

    366,568              

  Walter Minerals                        

 

Tuscaloosa County, AL

 

Mine support facilities—Barge load-out

    61           140  

 

Various Counties in AL

 

Real estate—Owned

    31,792              

 

Various Counties in AL

 

Real estate—Owned, mineral interest only

    171,750              

  Tuscaloosa Resources                        

 

Tuscaloosa County, AL

 

Administrative headquarters & mine support facilities

          664     7,764  

 

Tuscaloosa County, AL

 

Real estate—Owned

    696              

  Taft                        

 

Walker County, AL

 

Administrative headquarters & mine support facilities

          3,680     11,075  

 

Walker County, AL

 

Coal mines and land holdings—Owned

    1,512              

 

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

    2,090           50,083  

 

Nicholas County, WV

 

Coal mines and land holdings—Leased

    17,497              

  Maple Coal                        

      Fayette & Kanawha
        Counties, WV
 

Coal mines and land holdings—Owned

    5           47,100  

      Fayette & Kanawha
        Counties, WV
 

Coal mines and land holdings—Leased

    35,704              

  JW Walter, Inc.                        

 

Various Counties in WV

 

Coal mines and land holdings—Owned

    6,240              

51


Table of Contents

 
   
   
   
  Building
Square
Footage
 
 
  Business Unit /Location    
  Land
Acreage(1)
 
Reportable Segment
  Principal Operations   Leased   Owned  

Canadian and U.K. Operations

 


Canadian Operations

                       

  Walter Canada                        

 

Northeast, B.C. 

 

Chetwynd and Tumbler Ridge headquarters

          4,913        

  Wolverine's Perry Creek                        

 

Northeast, B.C. 

 

Coal mines and land holdings—Leased

    35,801              

 

Northeast, B.C. 

 

Coal mines and land holdings—Owned

    24              

 

Northeast, B.C. 

 

Administrative headquarters & mine support facilities

                44,737  

  Brazion's Brule                        

 

Northeast, B.C. 

 

Coal mines and land holdings—Leased

    28,434              

  Brazion's Willow Creek                        

 

Northeast, B.C. 

 

Coal mines and land holdings—Leased

    49,992              

 

Northeast, B.C. 

 

Coal mines and land holdings—Owned

    263              

 

Northeast, B.C. 

 

Administrative headquarters & mine support facilities

                9,250  

 

U.K. Operations

                       

  Energybuild                        

 

South Wales, U.K

 

Administrative headquarters & mine support facilities

          34,623     61,799  

 

South Wales, U.K

 

Coal mines and land holdings—Leased

    7,549              

 

South Wales, U.K

 

Real estate—Leased

    247              

Other

 

Other

                       

 

Birmingham, AL

 

Executive headquarters

          43,680        

 

Vancouver, B.C

 

Administrative headquarters

          16,472        

(1)
Real estate and land holdings include mineral interests owned and leased.

        As of December 31, 2012, we had estimated reserves totaling 401.0 million metric tons, of which 240.3 million tons, or approximately 60% are "assigned" recoverable reserves that are either currently being mined, are controlled and accessible from a currently active mine or located at idled facilities where limited capital expenditures would be required to initiate operations when conditions warrant. The remaining 160.7 million tons are classified as "unassigned", representing coal at currently non-producing locations which we anticipate mining in the future, but would require additional development capital before operations could begin.

        Our reserve estimates are predicated on engineering, economic and geological data assembled and analyzed by our internal engineers, geologists and finance associates, as well as, third party consultants. We update our reserve estimates annually to reflect the impacts of past coal production, new drilling information and other geological or mining data and acquisitions or sales of coal properties. During the year ended December 31, 2012, 57.7 million tons were added to proven and probable reserves as a result of on-going exploration projects.

52


Table of Contents

        The following table provides the location and coal reserves associated with each mine or potential mine as of December 31, 2012:


ESTIMATED RECOVERABLE(1) COAL RESERVES

AS OF DECEMBER 31, 2012

(In Thousands of Metric Tons)

 
   
   
   
   
   
   
   
  Reserve
Control(4)
 
 
   
   
   
   
  Recoverable Reserves(1)  
 
   
  Status of
Operation(5)
   
  Assigned/
Unassigned(3)
 
Location/Mine
  Type(8)   Coal Bed   Reserves(1)   Proven(2)   Probable(2)   Owned   Leased  

Alabama:

                                               

Jim Walter Resources, Inc.

                                               

No. 4

  U   Production   Mary Lee   Assigned     61,843     60,120     1,723     1,017     60,826  

No. 7

  U   Production   Mary Lee   Assigned     53,463     48,691     4,772     2,450     51,013  

North River

  U   Production   Pratt   Assigned     2,438     2,438         327     2,111  

Blue Creek Energy, Inc.

                                               

Blue Creek No. 1

  U   Development   Mary Lee   Unassigned     74,882     71,789     3,093         74,882  

Tuscaloosa Resources, Inc.

                                               

Carter/Swann's Crossing

  S   Production   Brookwood   Assigned     2,919     2,919         2,919      

Panther 3

  S   Idled   Brookwood   Assigned     262     262         262      

Taft Coal Sales & Associates

                                               

Choctaw

  S   Production   Pratt   Assigned     1,193     1,193             1,193  

Reid School

  S   Production   Black Creek   Assigned     34     34             34  

Gayosa South

  S   Development   Pratt   Assigned     352     352             352  

Robbins Road

  S   Development   Pratt   Assigned     1,225     1,225             1,225  

Walter Minerals, Inc.

                                               

Flat Top

  S   Development   Pratt   Unassigned     1,929     1,929         1,929      

Beltona East

  S   Development   Black Creek   Unassigned     1,013     1,013         1,013      

Morris

  S   Development   Mary Lee   Unassigned     1,801     525     1,276     1,801      
                                       

Total Alabama

                    203,354     192,490     10,864     11,718     191,636  
                                       

West Virginia:

                                               

Atlantic Leasco

                                               

Gauley Eagle

  U   Idled   Allegheny, Kanawha   Assigned     7,102     6,267     835         7,102  

Gauley Eagle

  S   Idled   Allegheny, Kanawha   Assigned     6,633     5,922     711         6,633  

Maple Coal Company

                                               

Eagle

  U   Production   Allegheny, Kanawha   Assigned     10,088     7,615     2,473         10,088  

Peerless

  U   Exploration   Allegheny, Kanawha   Unassigned     6,406     4,769     1,637         6,406  

Powellton

  U   Exploration   Allegheny, Kanawha   Unassigned     2,555     2,530     25         2,555  

Maple

  S   Production   Allegheny, Kanawha   Assigned     13,496     12,503     993         13,496  
                                       

Total West Virginia

                    46,280     39,606     6,674         46,280  
                                       

53


Table of Contents

 
   
   
   
   
   
   
   
  Reserve
Control(4)
 
 
   
   
   
   
  Recoverable Reserves(1)  
 
   
  Status of
Operation(5)
   
  Assigned/
Unassigned(3)
 
Location/Mine
  Type(8)   Coal Bed   Reserves(1)   Proven(2)   Probable(2)   Owned   Leased  

Northeast B.C., Canada:

                                               

Walter Canada

                                               

Wolverine's Perry Creek

  S   Production   Gates   Assigned     11,027     11,027             11,027  

Wolverine's Mt. Spieker (EB)

  S   Development   Gates   Unassigned     9,856     9,856             9,856  

Wolverine's Hermann

  S   Exploration   Gates   Unassigned     9,075     6,775     2,300         9,075  

Brazion's Brule

  S   Production   Gething   Assigned     19,369     19,369             19,369  

Brazion's Willow Creek

  S   Production   Gething   Assigned     19,029     17,749     1,280         19,029  

Brazion's Willow South

  S   Exploration   Gething   Assigned     14,252     7,186     7,066         14,252  

Brazion's Hudette

  S   Exploration   Gething   Unassigned     24,658     24,193     465         24,658  

Belcourt Saxon(6)

  S   Exploration   Gates   Unassigned     28,523     28,273     250         28,523  
                                       

Total Canada

                    135,789     124,428     11,361         135,789  
                                       

South Wales, U.K.:

                                               

Energybuild's Aberpergwm

  U   Development   9' & 18'(7)   Assigned     15,547     2,327     13,220         15,547  
                                       

Total Walter Energy

                    400,970     358,851     42,119     11,718     389,252  
                                       

(1)
Reserves are that part of a mineral deposit which can be economically and legally extracted or produced at the time of the reserve determination. Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law.

(2)
Reserves are further categorized as Proven and Probable as defined by Securities and Exchange Commission Guide 7 as follows: Proven Reserves are reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites of 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. Probable Reserves are 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 further 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.

(3)
"Assigned" reserves represent recoverable reserves that are either currently being mined, reserves that are controlled or accessible from a currently active mine or reserves at idled facilities where limited capital expenditures would be required to re-establish operations. "Unassigned" reserves represent coal at currently non-producing locations which would require significant additional capital spending before operations could begin.

(4)
"Reserve Control" of recoverable reserves is either through direct ownership of the property or through third party leases. Third party leases generally provide for terms or renewals through the anticipated life of the associated mine.

(5)
The "Status of Operation" for each mine is classified as follows: Exploration—mines where exploration has been conducted sufficient to define recoverable reserves, but the mine is not yet in development or production stage; Development—we are engaged in the preparation of an established commercially minable deposit (reserves) for extraction but are not yet in production; Production—the mine is actively operating; Idled—previously active mines that have been idled until such time as reinitiating operations are considered feasible. If conditions warrant, the mines could be re-opened with less capital investment than would be required to develop a new mine.

(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)
The reserves of this mine are contained within two seams named the "9' seam" and the "18' seam" which are contained in the South Wales Coal Basin—Lower Coal Measures coal bed.

(8)
Type of Mine: U = Underground; S = Surface

Note: Also see Glossary for definitions of technical terms

54


Table of Contents

The following table provides a summary of the quality of our reserves as of December 31, 2012:

ESTIMATED RECOVERABLE COAL RESERVES (Continued)

AS OF DECEMBER 31, 2012

(In Thousands of Metric Tons)

 
   
   
  Quality (Wet Basis)(3)    
 
 
   
   
  Average Coal
Seam Thickness
(in Feet)
 
Location/Mine
  Reserves   Type(1)   % Ash   % Sulfur   BTU/lb.  

Alabama:

                                     

Jim Walter Resources, Inc.

                                     

No. 4

    61,843     C     9.00     0.80     13,909     4.74  

No. 7

    53,463     C     9.00     0.75     13,952     4.19  

North River

    2,438     T     13.00     2.07     13,711     3.83  

Blue Creek Energy, Inc.

                                     

Blue Creek No. 1

    74,882     C     9.00     0.69     13,791     4.70  

Tuscaloosa Resources, Inc.

                                     

Carter/Swann's Crossing

    2,919     C/T     12.00     1.26     12,497     9.41  

Panther 3

    262     T     9.00     4.21     13,636     1.99  

Taft Coal Sales & Associates

                                     

Choctaw(2)

    1,193     C/T     12.36     1.87     12,927     6.47  

Reid School

    34     C     2.92     0.89     15,041     2.46  

Gayosa South(2)

    352     C/T     14.69     1.32     12,484     4.79  

Robbins Road(2)

    1,225     C/T     12.36     1.55     12,887     4.70  

Walter Minerals, Inc.

                                     

Flat Top

    1,929     T     10.90     2.13     13,590     5.66  

Beltona East

    1,013     C/T     7.79     2.58     1,462     4.88  

Morris

    1,801     T     20.80     1.60     12,175     5.46  
                                     

Total Alabama

    203,354                                
                                     

West Virginia:

                                     

Atlantic Leasco

                                     

Gauley Eagle underground

    7,102     C/T     7.45     1.04     12,944     3.80  

Gauley Eagle surface

    6,633     C/T     12.22     1.09     12,450     18.56  

Maple Coal Company

                                     

Eagle

    10,088     C     6.21     0.87     13,643     4.14  

Peerless

    6,406     T     5.13     2.08     13,333     3.59  

Powellton

    2,555     C     5.87     0.80     13,275     3.05  

Maple

    13,496     C/T     12.98     0.85     11,800     33.59  
                                     

Total West Virginia

    46,280                                
                                     

55


Table of Contents

 
   
   
  Quality (Wet Basis)(3)    
 
 
   
   
  Average Coal
Seam Thickness
(in Feet)
 
Location/Mine
  Reserves   Type(1)   % Ash   % Sulfur   BTU/lb.  

Northeast B.C., Canada:

                                     

Walter Canada

                                     

Wolverine's Perry Creek

    11,027     C     7.85     0.47     14,261     33.70  

Wolverine's Mt. Spieker (EB)

    9,856     C     8.72     0.49     14,116     39.80  

Wolverine's Hermann

    9,075     C     8.12     0.41     14,220     55.90  

Brazion's Brule

    19,369     P     7.43     0.51     14,242     36.80  

Brazion's Willow Creek

    19,029     C/P     7.50     0.58     14,500     32.50  

Brazion's Willow South

    14,252     P (2)   8.00     0.60     14,200     42.30  

Brazion's Hudette

    24,658     P (2)   8.00     0.60     14,250     55.30  

Belcourt Saxon Properties

    28,523     C     8.00     0.35     14,227     62.50  
                                     

Total Canada

    135,789                                
                                     

South Wales, U.K.:

                                     

Energybuild's Aberpergwm

    15,547     C/T     5.80     0.80     14,428     9.29  
                                     

Total Walter Energy

    400,970                                
                                     

(1)
Coal Type: C—Coking Coal; T—Thermal; P—Pulverized Coal Injection

(2)
Coals in this reserve area typically have metallurgical properties and, at a minimum, characterization of coal quality is sufficient to classify this reserve as Pulverized Coal Injection. Data suggests that a portion of this reserve may be coking coal, however, additional sampling and analysis is necessary before the classification can be confirmed and revised from PCI.

(3)
The majority of our reserves are marketed and sold into the metallurgical market. However some reserves are thermal (steam) coal that are marketed as compliant coal and used for industrial or power generation purposes. 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. However, electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with low sulfur coal.

Note: Also see Glossary for definitions of technical terms.

56


Table of Contents

        The following table provides a summary of information regarding our mining operations as of December 31, 2012:

 
   
   
   
   
   
  Preparation Plant    
 
   
   
   
  Transportation    
 
   
   
  Mining
Equipment(2)
  Capacity
(metric tons
per hr)
  Utilization
%
  Source of
Power(5)
Location/Mine
  Reserves   Type(1)   Rail   Other(3)

Alabama:

                                     

Jim Walter Resources, Inc

                                     

No. 4

    61,843   U   LW,CM   CSX   T,B     1,180     92%   APCO

No. 7

    53,463   U   LW,CM   CSX   T,B     2,180     90%   APCO

North River

    2,438   U   LW,CM   NS   N/A     900     87%   APCO

Blue Creek Energy, Inc.

                                     

Blue Creek No. 1

    74,882   U   In exploration or development

Tuscaloosa Resources, Inc.

                                     

Carter/Swann's Crossing

    2,919   S   E,L,T       T,B     N/A     N/A   APCO

Panther 3

    262   S   E,L,T       T,B     N/A     N/A   APCO

Taft Coal Sales & Associates

                                     

Choctaw(2)

    1,193   S   D,E,L,T   NS   T     110     85%   APCO

Reid School

    34   S   E,L,T       T     N/A     N/A   APCO

Gayosa South(2)

    352   S   In exploration or development

Robbins Road(2)

    1,225   S   In exploration or development

Walter Minerals, Inc.

                                     

Flat Top

    1,929   S   In exploration or development

Beltona East

    1,013   S   In exploration or development

Morris

    1,801   S   In exploration or development
                                     

Total Alabama

    203,354                                
                                     

West Virginia:

                                     

Atlantic Leasco

                                     

Gauley Eagle

    7,102   U   In exploration or development

Gauley Eagle

    6,633   S   E,L,T   CSX   T,B     N/A     N/A   Allegheny

Maple Coal Company

                                     

Eagle

    10,088   U   E,L,T       T,B     410     86%   AEP

Peerless

    6,406   U   In exploration or development

Powellton

    2,555   U   In exploration or development

Maple

    13,496   S   E,L,T       T,B     N/A     N/A   AEP
                                     

Total West Virginia

    46,280                                
                                     

Northeast B.C., Canada:

                                     

Walter Canada

                                     

Wolverine's Perry Creek

    11,027   S   E,L,T   CN         770     70%   BC Hydro

Wolverine's Mt. Spieker (EB)

    9,856   S   In exploration or development

Wolverine's Hermann

    9,075   S   In exploration or development

Brazion's Brule

    19,369   S   E,L,T   CN   T     N/A     N/A   BC Hydro

Brazion's Willow Creek

    19,029   S   E,L,T   CN         660     50% (4) BC Hydro

Brazion's Willow South

    14,252   S   In exploration or development

Brazion's Hudette

    24,658   S   In exploration or development

Belcourt Saxon

    28,523   S   In exploration or development
                                     

Total Canada

    135,789                                
                                     

South Wales, U.K.:

                                     

Energybuild's Aberpergwm

    15,547   U   CM             450     Idle   E. ON
                                     

Total Walter Energy

    400,970                                
                                     

(1)
Type of Mine: S = Surface; U = Underground

(2)
Mining Equipment: D = Dragline; S = Shovel/Excavator/Loader; T = Trucks; LW = Longwall; CM = Continuous Miner

57


Table of Contents

(3)
Transportation Other: T = Trucks; B = Barge Load-out Availability

(4)
Estimated Utilization; Plant began production in first quarter 2012.

(5)
Source of Power: APCO = Alabama Power Company; Allegheny = Allegheny Energy; AEP = American Electric Power; BC Hydro = BC Hydro and Power Authority; E.ON = E.ON Group

Note: Also see Glossary for definitions of technical terms.

        The following table provides the production (in thousands) and average coal selling price per metric ton for each of the three years in the period ended December 31, 2012:

 
   
   
   
   
   
   
  Date Mine:
 
  Production/Average Coal Selling Price Per Ton
 
  Acq/
Opened
  Ceased/
Idled
Location/Mine
  2012   2011   2010

Alabama:

                                           

Jim Walter Resources, Inc

                                           

No. 4

    1,727   $ 186.36     1,926   $ 272.61     2,537   $ 204.11   1976   N/A

No. 7

    4,322   $ 206.60     3,275   $ 275.88     3,511   $ 202.25   1978   N/A

North River

    2,040   $ 59.33     1,539   $ 43.56           May-11   N/A

Tuscaloosa Resources, Inc.

                                           

Carter/Swann's Crossing

    325   $ 107.38     183   $ 105.73           May-11   N/A

East Brookwood

            97   $ 112.59     421   $ 104.86   Sep-07   Jul-11

Taft Coal Sales & Associates

                                           

Choctaw

    558   $ 101.90     549   $ 90.74     601   $ 70.45   Sep-08   N/A

Reid School

    195   $ 155.27     221   $ 163.45     147   $ 150.98   May-10   N/A

Walter Minerals, Inc.

                                           

Hwy 59

            192   $ 105.19     201   $ 89.54   Aug-09   Aug-11
                                       

Total Alabama

    9,167           7,982           7,418              
                                       

West Virginia:

                                           

Atlantic Leasco

                                           

Gauley Eagle underground

            8   $ 114.17           Apr-11   June-11

Gauley Eagle surface

    187   $ 70.48     519   $ 64.79           Apr-11   June-12

Maple Coal Company

                                           

Eagle

    431   $ 163.82     448   $ 173.63           Apr-11   N/A

Maple

    252   $ 79.74     391   $ 71.36           Apr-11   N/A
                                       

Total West Virginia

    870           1,366                        
                                       

Northeast B.C., Canada:

                                           

Walter Canada

                                           

Wolverine's Perry Creek

    1,824   $ 201.59     1,083   $ 265.79           Apr-11   N/A

Brazion's Brule

    1,831   $ 159.43     1,100   $ 210.10           Apr-11   N/A

Brazion's Willow Creek

    868   $ 169.13     568   $ 215.22           Apr-11   N/A

Belcourt Saxon

                          Apr-11   N/A
                                       

Total Canada

    4,523           2,751                        
                                       

South Wales, U.K.:

                                           

Energybuild's Aberpergwm(1)

    63   $ 122.96     100   $ 121.67           Apr-11   Nov-11
                                       

Total Walter Energy

    14,623           12,199           7,418              
                                       

(1)
Tons produced and sold while under development.

58


Table of Contents

        Information provided within the previous tables 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 with the Canadian Securities regulatory authorities in respect of certain of our properties to comply with the requirements of NI 43-101 and these filings 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 relating to 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 "Business-Environmental and Other Regulatory Matters" in Part I, "Item 1." and Note 18 of "Notes to Consolidated Financial Statements," which are incorporated herein by reference.

Item 4.    Mine Safety Disclosures

        The information concerning mine safety violations and other regulatory matters is filed as Exhibit 95 to this Form 10-K 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).

59


Table of Contents


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, 2012
 
 
  High   Low  

1st Fiscal quarter

  $ 76.28   $ 56.87  

2nd Fiscal quarter

  $ 68.30   $ 43.34  

3rd Fiscal quarter

  $ 45.71   $ 30.73  

4th Fiscal quarter

  $ 40.14   $ 28.46  

 

 
  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  

        During the year ended December 31, 2012, we declared and paid a dividend of $0.125 per share to shareholders of record on each of February 20, May 7, August 6, and November 12. 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. Covenants contained in certain of the debt instruments referred to in Note 14 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. See also "Item 1A. Risk Factors" in Part I. As of February 22, 2013, there were 626 shareholders of record of the Common Stock.

60


Table of Contents

        The following graph shows changes over the past five-year period based on the value of $100 invested in (1) Walter Energy's Common stock; (2) the Russell 3000 Stock Index; and (3) the 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).

 
  2007   2008   2009   2010   2011   2012  

Walter Energy, Inc. 

    100.0     48.7     209.6     355.8     168.6     99.9  

Russell 3000 Stock Index

    100.0     61.3     76.9     88.3     87.4     99.7  

Dow Jones U.S. Coal Index

    100.0     37.6     78.9     105.1     55.7     38.8  

GRAPHIC

        The following table sets forth certain information relating to our equity compensation plans as of December 31, 2012:

 
  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

    675,731   $ 37.17     1,896,597  

1995 Long-term Incentive Stock Plan

    14,909   $ 6.58      

1996 Employee Stock Purchase Plan

            1,027,807  

Sales of Unregistered Securities

        On April 1, 2011, we issued 8,951,558 shares of Common Stock to partially fund the acquisition of Western Coal. Our Common Stock was issued without registration in reliance on Section 3(a)(10) of the Securities Act.

61


Table of Contents

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, 2012–January 31, 2012

              $ 0.2  

February 1, 2012–February 29, 2012

    7,846   $ 66.35       $ 0.2  

March 1, 2012–March 31, 2012

    2,221   $ 63.24       $ 0.2  

April 1, 2012–April 30, 2012

    186   $ 64.29       $ 0.2  

May 1, 2012–May 31, 2012

              $ 0.2  

June 1, 2012–June 30, 2012

              $ 0.2  

July 1, 2012–July 31, 2012

    964   $ 36.87       $ 0.2  

August 1, 2012–August 31, 2012

    324   $ 36.27       $ 0.2  

September 1, 2012–September 30, 2012

    262   $ 32.65       $ 0.2  

October 1, 2012–October 31, 2012

              $ 0.2  

November 1, 2012–November 30, 2012

              $ 0.2  

December 1, 2012–December 31, 2012

              $ 0.2  
                       

Total

    11,803                  
                       

(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 has been derived from our annual consolidated financial statements, including the consolidated balance sheets and the related consolidated statements of operations, comprehensive income, changes in stockholders' equity and 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 to significant

62


Table of Contents

accounting policies, Note 3 for acquisitions and Note 6 related to discontinued operations, and the other information contained elsewhere in this Form 10-K.

 
  Years ended December 31,  
(in thousands, except per share data)
  2012   Recast 2011   2010   2009   2008  

Revenues

  $ 2,399,895   $ 2,571,358   $ 1,587,730   $ 966,827   $ 1,149,684  

Income (loss) from continuing operations

 
$

(1,065,555

)

$

363,598
 
$

389,425
 
$

141,850
 
$

231,192
 

Basic income (loss) per share from continuing operations

 
$

(17.04

)

$

6.03
 
$

7.32
 
$

2.67
 
$

4.30
 

Number of shares used in calculation of basic income (loss) per share from continuing operations

   
62,536
   
60,257
   
53,179
   
53,076
   
53,791
 

Diluted income (loss) per share from continuing operations

 
$

(17.04

)

$

6.00
 
$

7.25
 
$

2.64
 
$

4.24
 

Number of shares used in calculation of diluted income (loss) per share from continuing operations

   
62,536
   
60,611
   
53,700
   
53,819
   
54,585
 

Capital expenditures

 
$

391,512
 
$

414,566
 
$

157,476
 
$

96,298
 
$

141,627
 

Net minerals, property, plant and equipment

 
$

4,697,688
 
$

4,687,591
 
$

790,001
 
$

522,931
 
$

504,585
 

Total assets(1)

 
$

5,768,420
 
$

6,856,508
 
$

1,651,853
 
$

1,244,159
 
$

1,195,695
 

Debt:

                               

2011 term loan A

 
$

756,974
 
$

894,837
 
$

 
$

 
$

 

2011 term loan B

 
$

1,127,770
 
$

1,333,163
 
$

 
$

 
$

 

2011 revolving credit facility

 
$

 
$

10,000
 
$

 
$

 
$

 

2005 Walter term loan

 
$

 
$

 
$

136,062
 
$

137,498
 
$

138,934
 

2005 Walter revolving credit facility

 
$

 
$

 
$

 
$

 
$

40,000
 

9.875% senior notes due December 15, 2020

 
$

496,510
 
$

 
$

 
$

 
$

 

Miscellaneous debt(2)

 
$

34,911
 
$

87,715
 
$

32,411
 
$

39,000
 
$

46,451
 

Quarterly cash dividend per common share

 
$

0.125
 
$

0.125
 
$

0.125
 
$

0.10
 
$

0.10
 

(1)
Excludes assets of discontinued operations.

(2)
This balance includes capital lease obligations and an equipment financing agreement.

63


Table of Contents

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

        The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and related Notes thereto included elsewhere in this Annual Report on Form 10-K.

OVERVIEW

        We are 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. We also produce thermal coal, anthracite coal, metallurgical coke and coal bed methane gas. As of December 31, 2012, we had approximately 401.0 million metric tons of recoverable reserves throughout the world.

        We currently operate 11 active coal mines, a coke plant and a coal bed methane extraction operation located throughout Alabama, West Virginia, Northeast British Columbia, and the U.K. We operate our business through two principal business segments: the U.S. Operations and Canadian and U.K. Operations. The U.S. Operations segment includes hard coking coal and thermal coal mines in both Alabama and West Virginia, a coke plant in Alabama, and coal bed methane extraction operations also located in Alabama. Our U.S. Operations are estimated to have approximately 249.6 million metric tons of recoverable reserves. 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). The Canadian mining operations is estimated to have approximately 135.8 million metric tons of recoverable reserves. Our U.K. mining operation consists of an idled underground and an idled surface mine located in South Wales. The underground mine produced anthracite coal, which can be sold as a low-volatile PCI coal and the surface mine operations produced thermal coal. Our U.K. mining operations is estimated to have approximately 15.5 million metric tons of recoverable reserves.

        Our sales of metallurgical coal in 2012, 2011 and 2010, which generally sells at a premium over our thermal coal, accounted for approximately 76%, 70% and 85%, respectively, of our annual coal sales volume, and our sales of thermal coal in 2012, 2011 and 2010 accounted for approximately 24%, 30% and 15%, respectively, of our annual coal sales volume. Our sales of metallurgical coal were made primarily to steel companies located in Europe, Asia and South America and our sales of thermal coal were made primarily to large utilities and industrial customers located primarily throughout Alabama, West Virginia, and the U.K. Approximately 78%, 76% and 76% of our total revenues in 2012, 2011 and 2010, respectively, were derived from sales made to customers outside of the United States, primarily in Japan, Brazil, Germany, Korea and Luxemborg.

        Although 2012 was a difficult year, we produced a total of 11.5 million metric tons of metallurgical coal in 2012, an increase of 30% as compared to 2011 metallurgical coal production of 8.8 million metric tons. We sold 10.4 million metric tons of metallurgical coal in 2012, up 19% from 8.7 million metric tons of metallurgical coal sales in 2011. We also achieved revenue of $2.4 billion, a decrease of 7% compared with $2.6 billion in 2011 while our average selling price for metallurgical coal decreased to $187.44 in 2012 from $236.55 in 2011, representing a decrease of 21%.

        The weakness in the metallurgical coal market during 2012 resulted from a combination of slowing Chinese demand growth, the weak economic environment in Europe, and the recovery of Australian supply, all of which resulted in an oversupply of metallurgical coal. This oversupply of metallurgical coal put pressure on the selling price of metallurgical coal reducing the price to levels not experienced in several years.

        In response to the weak metallurgical coal markets, we curtailed operations and projects, reduced costs and enhanced productivity. On August 1, 2012, we announced plans to reduce 2012 capital spending to approximately $400 million. We also reduced production and spending at two of our three

64


Table of Contents

Canadian mines in the fourth quarter, reduced production at the Maple mine in West Virginia, converted our Brule mine from contractor-operated to owner-operated, idled our Gauley Eagle surface mine operation in West Virginia and significantly reduced development spending at our Aberpergwm underground coal mine operations in the U.K.

INDUSTRY OVERVIEW AND OUTLOOK

        Global steel production for 2012 increased 1.2% to a record 1.55 billion metric tons from the previous record of 1.53 billion metric tons set in 2011. Annual 2012 steel production for Asia was 1.01 billion metric tons, an increase of 2.6% compared to 2011 making Asia's share of global steel production in 2012 65.4% as compared to 64.5% in 2011. Steel production in North America increased 2.5% for the year to 121.9 million metric tons, while production in South America and Europe decreased 3.0% and 2.7%, respectively, compared to 2011.

        According to the World Steel Association, global steel consumption is projected to increase approximately 3% in 2013 from 2012, driven largely by the China market which accounts for 40-50% of global steel demand. Although the short-term outlook for metallurgical coal is questionable, our long-term outlook remains constructive. The long-term demand for metallurgical coal within all of 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. While we remain positive on the long term outlook for metallurgical coal, we are focused on reducing spending and production until such time that coal prices and demand improve.

        We expect our 2013 metallurgical coal production to be in line with production levels in 2012 of which approximately 75% will be hard coking coal and 25% will be low-volatile PCI coal. We also expect our sales tons to significantly exceed production in 2013. We are well positioned to increase our production to capitalize on anticipated improvements in pricing and demand when market conditions warrant.

RESULTS OF CONTINUING OPERATIONS

2012 Summary Operating Results

 
  For the Year Ended December 31, 2012  
(in thousands)
  U.S. Operations   Canadian
and U.K.
Operations
  Other   Total  

Sales

  $ 1,712,872   $ 668,261   $ 627   $ 2,381,760  

Miscellaneous income

    15,491     52     2,592     18,135  
                   

Revenues

    1,728,363     668,313     3,219     2,399,895  

Cost of sales (exclusive of depreciation and depletion)

    1,153,271     642,021     1,699     1,796,991  

Depreciation and depletion

    173,140     141,713     1,379     316,232  

Selling, general and administrative

    45,674     43,972     43,821     133,467  

Postretirement benefits

    53,301         (449 )   52,852  

Asset impairment and restructuring

    39,961     9,109         49,070  

Goodwill impairment

    74,320     990,089         1,064,409  
                   

Operating income (loss)

  $ 188,696   $ (1,158,591 ) $ (43,231 )   (1,013,126 )
                     

Interest expense, net

                      (138,552 )

Other loss

                      (13,081 )

Income tax benefit

                      99,204  
                         

Loss from continuing operations

                    $ (1,065,555 )
                         

65


Table of Contents

 
  For the Year Ended December 31, 2011, recast  
(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

    155,702     74,203     776     230,681  

Selling, general and administrative

    61,622     28,100     76,027     165,749  

Postretirement benefits

    41,745         (1,360 )   40,385  
                   

Operating income (loss)

  $ 561,370   $ 86,538   $ (74,477 )   573,431  
                     

Interest expense, net

                      (96,214 )

Other income, net

                      17,606  

Income tax expense

                      (131,225 )
                         

Income from continuing operations

                    $ 363,598  
                         

 

 
  Increase (Decrease) for the Year Ended December 31, 2012  
(in thousands)
  U.S. Operations   Canadian
and U.K.
Operations
  Other   Total  

Sales

  $ (137,143 ) $ (43,061 ) $ (361 ) $ (180,565 )

Miscellaneous income (loss)

    (5,676 )   13,320     1,458     9,102  
                   

Revenues

    (142,819 )   (29,741 )   1,097     (171,463 )

Cost of sales (exclusive of depreciation and depletion)

    102,528     132,808     543     235,879  

Depreciation and depletion

    17,438     67,510     603     85,551  

Selling, general and administrative

    (15,948 )   15,872     (32,206 )   (32,282 )

Postretirement benefits

    11,556         911     12,467  

Asset impairment and restructuring

    39,961     9,109         49,070  

Goodwill impairment

    74,320     990,089         1,064,409  
                   

Operating income (loss)

  $ (372,674 ) $ (1,245,129 ) $ 31,246     (1,586,557 )
                     

Interest expense, net

                      (42,338 )

Other income (loss)

                      (30,687 )

Income tax benefit (expense)

                      230,429  
                         

Income (loss) from continuing operations

                    $ (1,429,153 )
                         

Year Ended December 31, 2012 as Compared to the Year Ended December 31, 2011

Overview of Consolidated Financial Results of Continuing Operations

        Our loss from continuing operations for the year ended December 31, 2012 was $1.1 billion, or $17.04 per diluted share, which compares to income of $363.6 million, or $6.00 per diluted share for the year ended December 31, 2011.

        Revenues in 2012 decreased $171.5 million, or 6.7% from 2011 due to lower global coal pricing on both metallurgical and thermal coals, partially offset by the impact of a full year of revenue from the Western Coal acquisition compared to only nine months in 2011 and increased sales volume at our legacy Alabama mines.

66


Table of Contents

        Cost of sales, exclusive of depreciation and depletion, increased $235.9 million to $1.8 billion in 2012 as compared to 2011, primarily due to the impact of a full year of results from the acquired Western Coal operations compared to only nine months for the prior year. Cost of sales also increased due to the acquisition of the North River mine in May of 2011. Cost of sales from these acquired operations was $857.7 million and $700.3 million during the years ended December 31, 2012 and 2011, respectively. Excluding the impact of the timing of acquisitions, the increase in cost of sales was primarily due to increased sales volumes.

        Depreciation and depletion expense in 2012 increased $85.6 million as compared to 2011 primarily due to the impact of a full year of results from the acquired Western Coal operations compared to only nine months for the prior year. The increase was also due to a full year of the North River mining operations in our U.S. segment compared to only eight months in the prior year. Depreciation and depletion from these acquired operations was $185.1 million during the year ended December 31, 2012, an increase of $74.7 million from the prior year comparable period.

        Selling, general & administrative expenses includes costs for corporate and direct administrative functions not directly assignable to an individual mine. Selling, general & administrative expenses decreased $32.3 million for the year ended December 31, 2012 as compared to 2011. The decrease was primarily attributable to a decrease of $23.2 million of costs incurred in 2011 associated with the acquisition of Western Coal combined with cost savings derived from integrating the operations, offset in part by a full year of expenses associated with these operations.

        The Company performed an interim goodwill impairment test as of July 31, 2012 and recorded a goodwill impairment charge of $1.1 billion to reduce the carrying value of goodwill to its implied fair value for two reporting units in the U.S. Operations segment and two reporting units in the Canadian and U.K. Operations segment. The Company also recorded an impairment charge of $40 million associated with the impairment of a capitalized shale natural gas exploratory project during the third quarter of 2012. Further, in connection with plans to reduce development spending at the Aberpergwm underground coal mine in the fourth quarter of 2012, the Company recorded a restructuring and asset impairment charge of $9.1 million, of which $6.0 million related to severance and other obligations and $3.1 million related to the impairment of property, plant and equipment as the carrying values of certain assets exceeded their fair value.

        The $13.1 million other loss for the year ended December 31, 2012 is primarily attributable to losses on the sale and remeasurement to fair value of equity investments acquired through the Western Coal acquisition. Other income of $17.6 million for the year ended December 31, 2011 was 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 that were acquired through the Western Coal acquisition.

        Interest expense, net of interest income was $138.6 million in 2012, an increase of $42.3 million compared to 2011. The increase reflects a full year of interest on borrowings of $2.35 billion on April 1, 2011 to fund a portion of the Western Coal acquisition as well as an increase in interest rates in the fourth quarter of 2012 due to the Third Amendment to the Credit Agreement combined with interest on the 2020 Notes issued on November 21, 2012.

        The Company recognized an income tax benefit of $99.2 million for the year ended December 31, 2012, compared to a tax provision of $131.2 million for the year ended December 31, 2011. The 2012 income tax benefit as compared to expense in 2011 was primarily due to the pretax operating loss for 2012 as compared to the pretax operating income for the same period in 2011. The level of ordinary income in 2012 decreased substantially from 2011, leading to income tax benefits in excess of income tax expense. The 2012 and 2011 effective rates also reflect the benefit of our Canadian and U.K. operations which are taxed at statutory rates lower than the statutory U.S. rate, and the benefits of tax

67


Table of Contents

losses in excess of losses from continuing operations related to foreign financing activities. Additionally, the Company recorded an impairment charge of $1.1 billion of nondeductible goodwill in 2012. See Note 4 of "Notes to Consolidated Financial Statements" included in this Form 10-K for further discussion.

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

Segment Analysis

    U.S. Operations

        Hard coking coal sales totaled 6.7 million metric tons in 2012, an increase of 18.6% as compared to 5.7 million metric tons during 2011. The average selling price of hard coking coal in 2012 was $191.87 per metric ton, a 19.5% decrease as compared to an average selling price of $238.27 per metric ton in 2011. The decrease in the average selling price of hard coking coal reflects the weak global economy and the resulting decrease in demand for hard coking coal. Hard coking coal production totaled 7.0 million metric tons in 2012, representing an increase of 17.8% as compared to 2011, primarily due to increased production at the Alabama underground mines.

        Thermal coal sales totaled 3.2 million metric tons in 2012 as compared to 3.7 million metric tons during 2011. The decrease was primarily due to decreased thermal coal sales at our West Virginia operations as we idled a thermal coal surface mine in response to softening demand. The average selling price in 2012 was $67.79 per metric ton, down 4.2% from the average selling price of $70.78 per metric ton in 2011. Lower average pricing also reflected the impact of a full year of lower prices for tons sold by the North River mine. Thermal coal production totaled 3.1 million metric tons in 2012, as compared to 3.4 million metric tons in 2011.

        Statistics for U.S. Operations are presented in the following table:

 
  For the year ended
December 31,
 
 
  2012   2011  

Tons of hard coking coal sold(1) (in thousands)

    6,705     5,655  

Tons of hard coking coal produced (in thousands)

    6,956     5,905  

Average hard coking coal selling price(1) (per metric ton)

  $ 191.87   $ 238.27  

Tons of thermal coal sold (in thousands)

    3,235     3,673  

Tons of thermal coal produced (in thousands)

    3,081     3,443  

Average thermal coal selling price (per metric ton)

  $ 67.79   $ 70.78  

(1)
Includes sales of both coal produced and purchased coal.

        Our U.S. Operations segment reported revenues of $1.7 billion in 2012, a decrease of $142.8 million from 2011. The decrease in revenues was attributable to lower average selling prices for both hard coking coal and thermal coal, partially offset by increased hard coking coal sales volumes primarily due to a full year of sales volume from the West Virginia and North River mining operations acquired in the second quarter of 2011. The decrease in average selling prices reflects the weak global economy.

        Cost of sales, exclusive of depreciation and depletion, increased $102.5 million to $1.2 billion during the year ended December 31, 2012 as compared to the same period in 2011. The increase in cost of sales was primarily a result of an increase in hard coking coal sales volume and a full year of cost of sales from the West Virginia and North River mining operations. Cost of sales related to these acquired operations were $215.7 million and $191.1 million during the years ended December 31, 2012 and 2011, respectively.

68


Table of Contents

        U.S. Operations reported operating income of $188.7 million in 2012, as compared to $561.4 million in 2011. The $372.7 million decrease in operating income was primarily due to a goodwill impairment charge of $74.3 million and an impairment of a capitalized shale natural gas exploratory project of $40.0 million coupled with lower average hard coking coal and thermal coal selling prices and increased cost of sales as a result of increased sales volumes.

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. Metallurgical coal sales for the year ended December 31, 2012 totaled 1.7 million metric tons of hard coking coal at an average selling price of $202.79 per metric ton and 2.0 million metric tons of low-volatile PCI coal at an average selling price of $160.00 per metric ton. Metallurgical coal sales for the year ended December 31, 2011 totaled 1.3 million metric tons of hard coking coal at an average selling price of $263.44 per metric ton and 1.7 million metric tons of low-volatile PCI coal at an average selling price of $210.40 per metric ton. The increase in sales volumes was primarily due to a full year of sales volume from these operations compared to only nine months for the prior year. The decrease in the average selling price of metallurgical coal was due to weaker worldwide demand.

        The Canadian and U.K. Operations segment produced a total of 2.0 million metric tons of hard coking coal and 2.5 million metric tons of low-volatile PCI coal for the year ended December 31, 2012. During the year ended December 31, 2011, the Canadian and U.K. Operations segment produced 1.1 million metric tons of hard coking coal and 1.8 million metric tons of low-volatile PCI coal. The increase in production volumes was primarily due to the impact of a full year of production volume from these operations acquired through the Western Coal acquisition compared to only nine months for the prior year coupled with significant improvements in productivity at both the Wolverine and Brule mines. Due to the strong production of these operations combined with the weak market demand, beginning in the third quarter, we reduced production at two of our three Canadian mines and made plans to reduce inventory while we await better market conditions. We also are taking steps to restrain spending in our Canadian and U.K. Operations segment and significantly reduced development spending in the Aberpergwm mine in the U.K. until market conditions improve.

        Statistics for Canadian and U.K. Operations are presented in the following table:

 
  For the year ended
December 31,
 
 
  2012   2011  

Tons of hard coking coal sold(1) (in thousands)

    1,662     1,321  

Tons of hard coking coal produced (in thousands)

    2,039     1,109  

Average hard coking coal selling price(1) (per metric ton)

  $ 202.79   $ 263.44  

Tons of low-volatile PCI coal sold (in thousands)

    2,011     1,732  

Tons of low-volatile PCI coal produced (in thousands)

    2,491     1,826  

Average low-volatile PCI coal selling price (per metric ton)

  $ 160.00   $ 210.40  

Tons of thermal coal sold (in thousands)

    63     94  

Tons of thermal coal produced (in thousands)

    63     91  

Average thermal coal selling price (per metric ton)

  $ 122.71   $ 112.95  

(1)
Includes sales of both coal produced and purchased coal.

        Our Canadian and U.K. Operations segment reported revenues of $668.3 million in 2012, a decrease of $29.7 million from 2011 reported revenues of $698.1 million. The decrease in the Canadian and U.K. Operations segment reported revenues was due to lower average selling prices for both hard coking coal and low-volatile PCI coal, partially offset by increased sales volumes.

69


Table of Contents

        Cost of sales, exclusive of depreciation and depletion, increased $132.8 million to $642.0 million during the year ended December 31, 2012 as compared to $509.2 million for the year ended December 31, 2011. The increase in cost of sales was primarily attributable to an increase in sales volume primarily due to the inclusion of a full year of results from these operations acquired through the Western Coal acquisition compared to only nine months included within the prior year.

        Our Canadian and U.K. Operations segment reported an operating loss of $1.2 billion for the year ended December, 2012 as compared to operating income of $86.5 million for the year ended December 31, 2011. The $1.2 billion decrease in operating income was primarily due to a goodwill impairment charge of $990.1 million and asset impairment and restructuring charges of $9.1 million for the year ended December 31, 2012, coupled with lower average hard coking coal and low-volatile PCI coal prices, in some cases to a point below cost.

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

    155,702     74,203     776     230,681  

Selling, general and administrative

    61,622     28,100     76,027     165,749  

Postretirement benefits

    41,745         (1,360 )   40,385  
                   

Operating income (loss)

  $ 561,370   $ 86,538   $ (74,477 )   573,431  
                     

Interest expense, net

                      (96,214 )

Other income, net

                      17,606  

Income tax expense

                      (131,225 )
                         

Income from continuing operations

                    $ 363,598  
                         

 

 
  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  
                         

70


Table of Contents

 
  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

    57,532     74,203     244     131,979  

Selling, general and administrative

    19,007     28,100     31,670     78,777  

Postretirement benefits

    (1,483 )       390     (1,093 )
                   

Operating income (loss)

  $ (73,072 ) $ 86,538   $ (34,097 )   (20,631 )
                     

Interest expense, net

                      (79,748 )

Other income, net

                      17,606  

Income tax expense

                      56,946  
                         

Income from continuing operations

                    $ (25,827 )
                         

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

Overview of Consolidated Financial Results of Continuing Operations

        Our income from continuing operations for the year ended December 31, 2011 was $363.6 million or $6.00 per diluted share, which compares to $389.4 million, or $7.25 per diluted share for the year ended December 31, 2010.

        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 $132.0 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 $110.5 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.

        Selling, general & administrative expenses includes costs for corporate and direct administrative functions not directly assignable to an individual mine. 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.

71


Table of Contents

        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 26.5% 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 nonconventional fuel source credits for our Walter Coke operations for the years 2006 through 2009.

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)

  $ 238.27   $ 200.28  

Tons of hard coking coal sold(1) (in thousands)

    5,655     6,270  

Average thermal coal selling price(1) (per metric ton)

  $ 70.78   $ 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 $561.4 million in 2011, as compared to $634.4 million in 2010. The $73.1 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 $86.5 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

72


Table of Contents

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 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.

FINANCIAL CONDITION

        Cash and cash equivalents decreased by $11.8 million to $116.6 million at December 31, 2012 from $128.4 million at December 31, 2011, primarily resulting from the use of cash during 2012 for capital expenditures of $391.5 million, $343.3 million of principal payments on our 2011 term loans in advance of scheduled maturity, $39.5 million of principal payments on capital lease obligations and dividends paid of $31.2 million. Offsetting these uses of cash was $329.9 million in cash flows provided by operating activities during 2012 and proceeds of $496.5 million related to the issuance of our 2020 Notes. See additional discussion in the Statement of Cash Flows section that follows.

        Net receivables were $257.0 million at December 31, 2012, a decrease of $56.4 million from December 31, 2011 primarily attributable to a decline in the average net selling price per metric ton of our hard coking and PCI coals.

        Inventories increased by $65.6 million at December 31, 2012 as compared to December 31, 2011 primarily due to increased production volumes coupled with decreased sales volumes.

        Net property, plant and equipment increased by $100.8 million at December 31, 2012 as compared to December 31, 2011, primarily due to capital expenditures during 2012 of $391.5 million, partially offset by depreciation expense.

        Accrued expenses were $184.9 million at December 31, 2012, a decrease of $44.2 million from December 31, 2011, primarily due to reduced capital spending resulting in lower capital accruals at year end.

        The long-term portion of the accumulated postretirement benefits obligation was $633.3 million at December 31, 2012, up $82.6 million from $550.7 million at December 31, 2011. The increase was primarily attributed to a decrease in the discount rate offset by a decrease in health care cost trend rates. This adjustment is recognized as a corresponding decrease to stockholders' equity.

        Other current liabilities and other long-term liabilities were $206.5 million and $251.3 million, respectively, at December 31, 2012 an increase and decrease of $142.7 million and $130.3 million, respectively, from December 31, 2011 primarily due to the reclassification of approximately $153.0 million in accrued interest, penalties, and liabilities related to uncertain tax positions from other long-term liabilities to other current liabilities. See Note 11 of "Notes to Consolidated Financial Statements" included in this Form 10-K for further discussion.

73


Table of Contents

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 sources of long-term funding are our bank term loans entered into on April 1, 2011 and our senior notes issued on November 21, 2012, as discussed below. Our available liquidity as of December 31, 2012 was $445 million, consisting of cash and cash equivalents of $117 million and $328 million available under the Company's $375 million revolving credit facility, net of outstanding letters of credit of $47 million.

        We were in compliance with all covenants under our Credit Agreement and the indenture governing our notes as of December 31, 2012. If operating results fall below our fiscal year 2012 results or other adverse factors occur, they could result in our being unable to comply with covenants in our Credit Agreement. A breach of covenants in the Credit Agreement, including the covenants that stipulate ratios based on Adjusted EBITDA, could result in a default under the Credit Agreement and the lenders thereunder could elect to declare all amounts borrowed due and payable. Any acceleration under the Credit Agreement could result in a default under the indenture governing our notes.

        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 of our operating needs