SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

JAMES RIVER COAL COMPANY

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code:  (804) 780-3000

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

Yes    o             No    ý

Indicate by a check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange 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 is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

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

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 the common stock held by non-affiliates of the registrant, based upon the closing sale price of Common Stock, par value $0.01 per share, on June 29, 2012 as reported on the Nasdaq Global Select Market, was approximately $95.6 million (affiliates being, for these purposes only, directors, executive officers and holders of more than 10% of the registrant’s Common Stock).

The number of shares of the registrant’s Common Stock, par value $.01 per share, outstanding as of February 15, 2013 was 35,862,549.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the registrant’s 2013 Annual Meeting of Shareholders, to be filed with the Securities and Exchange Commission (the “SEC”), are incorporated by reference into Part III of this Annual Report on Form 10-K.

FORWARD-LOOKING INFORMATION

From time to time, we make certain comments and disclosures in reports and statements, including this report, or statements made by our officers, which may be forward-looking in nature. These statements are known as “forward-looking statements,” as that term is used in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Examples include statements related to our future outlook, anticipated capital expenditures, projected cash flows and borrowings and sources of funding. We caution readers that forward-looking statements, including disclosures that use words such as “anticipate,” “believe,” “estimate,” “expect,” “goal,” “intend,” “may,” “should,” “could,” “objective,” “plan,””predict,” “project,” “target,” “will,” or their negatives and similar words or statements, are subject to certain risks, trends and uncertainties that could cause actual cash flows, results of operations, financial condition, cost reductions, acquisitions, dispositions, financing transactions, operations, expansion, consolidation and other events to differ materially from the expectations expressed or implied in such forward-looking statements. We have based any forward-looking statements we have made on our current expectations and assumptions about future events and circumstances that are subject to risks, uncertainties and contingencies that could cause results to differ materially from those discussed in the forward-looking statements, including, but not limited to:

We are including this cautionary statement in this document to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of us. Any forward-looking statements should be considered in context with the various disclosures made by us about our businesses, including without limitation the risk factors more specifically described below in Item 1A. Risk Factors of this Annual Report on Form 10-K.

Forward-looking statements speak only as if the date they are made. We disclaim any intent or obligation to update these forward-looking statements unless required by securities law, and we caution the reader not to rely on them unduly.

JAMES RIVER COAL COMPANY

TABLE OF CONTENTS

FORM 10-K ANNUAL REPORT

PART I

Available Information

The Company’s website address is http://www.jamesrivercoal.com.  The Company makes available free of charge through its website its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports as soon as reasonably practicable after filing or furnishing the material to the Securities and Exchange Commission (the “SEC”).   However, our website and any contents thereof should not be considered to be incorporated by reference into this document. You may read and copy documents the Company files at the SEC’s public reference room at 100 F Street, NE, Washington, D.C., 20549.   Please call the SEC at 1-800-SEC-0330 for information on the public reference room.   The SEC maintains a website that contains annual, quarterly and current reports, proxy statements and other information that issuers (including the Company) file electronically with the SEC.   The SEC’s website is http://www.sec.gov.

In Part III of this Form 10-K, we incorporate certain information by reference from our Proxy Statement for the 2013 Annual Meeting of Shareholders.  The Company expects to file the Proxy Statement with the SEC on or about March 27, 2013, and will make it available on the Company website as soon as reasonably practicable.  Please refer to the Proxy Statement when it is available.

Item 1.          Business

General Business

Overview

Unless the context requires otherwise, references to “we,” “us,” “our” or “the Company” are intended to mean consolidated James River Coal Company (James River) and its wholly-owned subsidiaries. This drafting style is suggested by the Securities and Exchange Commission and is not meant to indicate that the publicly-traded James River owns or operates any asset, business or property of any of its subsidiaries. The operations and businesses described in this filing are owned and operated, and management services provided, by distinct direct and indirect subsidiaries of James River. James River was incorporated in 1991 under the laws of the Commonwealth of Virginia.

We mine, process and sell thermal and metallurgical coal through eight active mining complexes located throughout eastern Kentucky, southern West Virginia and southern Indiana. The majority of our metallurgical coal was obtained in the April 18, 2011 acquisition (the IRP Acquisition) of International Resource Partners LP and its subsidiary companies (collectively IRP).   We have two reportable business segments based on the coal basins in which we operate – Central Appalachia (CAPP) and the Midwest (Midwest).   For additional information on our segments, see Item 15 of Part IV “Financial Statement – Note 15 – Segment Information.”

As of December 31, 2012, our eight mining complexes included 18 underground mines, 9 surface mines and 13 preparation plants. As of December 31, 2012, we believe that we controlled approximately 341.7 million tons of proven and probable coal reserves.  At current production levels, we believe these reserves would support greater than 30 years of production.

In 2012, our mines produced 9.5 million tons of coal (including 0.4 million tons of coal produced in our mines that are operated by contract mine operators) and we purchased another 2.0 million tons for resale. Of the 9.5 million tons produced from Company mines, approximately 64% came from underground mines, while the remaining 36% came from surface mines. In 2012, we generated revenues of $1.1 billion and had a net loss of $138.9 million.  Approximately 44% of our total revenues for 2012 were generated from coal sales to electric utility customers and the remaining 56% from coal sales (including metallurgical coal) to industrial and other customers. In 2012, US Steel, Steel Authority of India Limited and Georgia Power Company were our largest customers, representing approximately 13%, 13%, and 12% of our total revenues, respectively.  No other customer accounted for more than 10% of our total revenues.

The coal that we sell is obtained from three sources:  our Company-operated mines, our mines that are operated by independent contract mine operators, and other third parties from whom we purchase coal for resale.  Contract mining and coal purchased from other third parties provide flexibility to increase or decrease production based on market conditions.  The table below reflects the amount and percentage of coal obtained from those sources in 2012:

Mining Methods

Our Company-operated and contractor operated mines produce coal using different mining methods. These methods are room and pillar underground mining and contour and point removal surface mining. These methods are described in more detail below.

Room and Pillar. In the underground room and pillar method of mining, continuous mining machines cut five to nine entries into the coal seam and connect them by driving crosscuts, leaving a series of rectangular pillars, or columns of coal, to help support the mine roof and control the flow of air. Generally, openings are driven 20 feet wide and the pillars are 40 to 100 feet wide. As mining advances, a grid-like pattern of entries and pillars is formed. When mining advances to the end of a panel, or section of the mine, retreat mining may begin. In retreat mining, as much coal as is feasible is mined from the pillars that were created in advancing the panel, allowing the roof to cave.

The coal face is cut with continuous mining machines and the coal is transported from the continuous mining machine to the mine conveyor belts using a continuous haulage system, shuttle cars or ram cars. The mine conveyor system consists of a series of conveyor belts, which transport the coal from the active face areas to the surface. Once on the surface, the coal is transported to the preparation plants where it is processed to remove any impurities. The coal is then transported to the clean coal stockpiles or silos from which it is loaded for shipment to our customers. Reserve recovery, a measure of the percentage of the total coal in place that is ultimately produced, using this method of mining typically depends on the shape of the reserve, the amount of low-cover areas, and the geological characteristics of the reserve body.

Surface Mining. Surface mining is used when coal is found close to the surface. This method involves the removal of overburden (earth and rock covering the coal) with heavy earth-moving equipment and explosives, loading out the coal, replacing the overburden and topsoil after the coal has been excavated and reestablishing vegetation and plant life and making other improvements that have local community and environmental benefit. Overburden is typically removed at our mines by either hydraulic shovels or front-end loaders which place the overburden into large trucks.

In CAPP, we use the contour and highwall surface mining methods. Contour and highwall mining is used where removal of all the overburden overlying a coal seam is either uneconomical or impossible to remove due to property control or other issues. With contour mining, a contour cut is taken along the outcrop of the seam and the coal is removed from the exposed pit. Highwall mining can then take place where the seam is exposed in the highwall. A highwall miner resembles an underground continuous miner. The highwall miner cuts entries into the coal seam up to 10 feet wide and up to 900 feet deep. The coal is transported to the surface through the augers and loaded into trucks using a loader. The contour area is then reclaimed by returning overburden to the pit and restoring the mountainside to its approximate original contour.

As of December 31, 2012, we had 9 Company-operated surface mines, 2 of which had a highwall miner operated in connection with the surface operations. One of the contract highwall miners was operated by independent contractors.

Underground Mine Characteristics

Underground mines are characterized as either “drift” mines or “below drainage” mines.  Drift mines are mines that are developed into the coal seam at a point where the seam intersects the surface.  The area where the seam intersects the surface is commonly known as the “outcrop.”  Multiple entries are developed into the coal seam and are used as airways for mine ventilation, passageways for miners and supplies, and entries for conveyor belts that transport coal from the active production areas of the mine to the surface.

In below drainage mines, the coal seam does not intersect the surface in the vicinity of the mining area.  Therefore, the coal seam must be accessed through excavated passageways from the surface.  These passageways typically consist of vertical shafts and angled slopes.  The shafts are constructed with diameters ranging from 12 to 24 feet and are used as airways for mine ventilation and passageways for miners and supplies via elevators.  The slopes, when used to house conveyor belts to transport the mined coal from the active production areas of the mine to the surface, are typically driven at an angle of less than 17 degrees from the horizontal.  In addition, the slopes provide passageways for miners and supplies, and airways for mine ventilation. Below drainage mines can also be accessed from “box cut” openings from the surface.

As of December 31, 2012, we had 18 Company-operated underground mines, of which 11 were drift mines and the remaining 7 were below-drainage mines.

Mining Operations

Our coal production is conducted through seven mining complexes in the Central Appalachia Region and one mining complex in the Midwest Region.  We generally do not own the land on which we conduct our mining operations.  Rather, our coal reserves are controlled pursuant to leases from third party landowners.  We believe that greater than 95% and 90% of our coal reserves in the Central Appalachia Region and Midwest Region, respectively, are controlled pursuant to leases from third party landowners.  These leases typically convey mining rights to the coal producer in exchange for a per ton fee or royalty payment of a percentage of the gross sales price to the lessor.  The average royalties (including wheelage amounts and unrecoupable royalty prepayments) for coal reserves from our producing properties were approximately 8.9% and 4.5% of produced coal sales revenue for the year ended December 31, 2012, in the Central Appalachia Region and the Midwest Region, respectively.

All of our operations are located on or near public highways and receive electrical power from commercially available sources.  Existing facilities and equipment are maintained in good working condition and are continuously updated through capital expenditure investments.

The following table provides summary information on our mining complexes as of December 31, 2012:

The following summarizes additional information concerning each of our mining complexes:

Bell County. The Bell County complex is located in Bell County in eastern Kentucky.  We use room and pillar mining and mine the Garmeada seam of coal.  Coal is processed at our preparation plant and loaded into railcars via an integrated four-hour unit train loadout that is serviced by both the CSX and Norfolk Southern railroads.  As of December 31, 2012, we employed 95 mining and support personnel at this complex.

Bledsoe.  The Bledsoe complex is located in Leslie and Harlan counties in eastern Kentucky.  Our underground mines use room and pillar mining. We mine the Hazard #4 seam of coal at this complex.  Coal is processed at one of two preparation plants and loaded into railcars at a separate location via a four-hour unit train loadout on the CSX railroad. As of December 31, 2012, we employed 273 mining and support personnel at this complex.

Blue Diamond - Buckeye.  The Buckeye complex is located in Knott and Perry counties in eastern Kentucky.  Our underground mines use room and pillar mining and our surface mines use the contour and highwall mining methods.  We mine the Amburgy, #5A, #7, #8, and #9 seams of coal at this complex.  Coal is processed at our preparation plant and loaded into railcars via an integrated four-hour unit train loadout on the CSX railroad. As of December 31, 2012, we employed 215 mining and support personnel at this complex.

Blue Diamond - Leatherwood. The Leatherwood complex is located in Leslie, Perry and Letcher counties in eastern Kentucky.  We use room and pillar mining for our underground mines. We mine the Hazard #4 and Elkhorn #3 seams of coal at this complex.  Coal is processed at our preparation plant and loaded into railcars via an integrated four-hour unit train loadout on the CSX railroad. As of December 31, 2012, we employed 318 mining and support personnel at this complex.

Hampden. The Hampden Coal Complex is located in Mingo and Logan counties in southern West Virginia. The underground operations use room-and-pillar mining to produce metallurgical coal from the 2-Gas and Lower Cedar Grove seams. The surface mine produces metallurgical and steam coal from the Alma, Williamson and Lower Cedar Grove seams. Coal is processed at the Hampden Preparation Plant and loaded into railcars via 2 CSX load-outs and 1 Norfolk Southern Load-out. As of December 31, 2012, we employed approximately 391 mining and support personnel at this complex.

McCoy Elkhorn. The McCoy Elkhorn complex is located in Pike and Floyd counties in eastern Kentucky.  Our underground mines use room and pillar mining.  We mine the Millard and Elkhorn #3 seams at this complex.  Coal is processed at our three preparation plants and loaded into railcars via integrated four-hour unit train loadouts on the CSX railroad. As of December 31, 2012, we employed 350 mining and support personnel at this complex.

Laurel Mountain.  The Laurel Mountain complex is located in Floyd, Johnson, Lawrence and Knott counties in eastern Kentucky.  Our surface mines use both contour and highwall and area mining methods.  We mine the Hazard #9, #8, #7, #5A, Haddix, Fireclay, Whitesburg, Amburgy, Taylor and Elkhorn #3, #2, and #1 seams at this complex.  Coal is shipped directly to our McCoy Elkhorn complex to be process and loaded.  As of December 31, 2012, we employed 136 mining and support personnel at this complex.

Triad. The Triad complex is located in Pike and Knox counties in southern Indiana.  We use room and pillar mining to mine the Springfield seam of coal, and use the surface mine  method to mine multiple seams, including the Danville, Millersburg, Hymera, Bucktown and Springfield seams.  Coal is processed at one of four preparation plants (two of which are active) and loaded into trucks for delivery to the customer or by rail at our Switz City loadout.  The Switz City loadout is serviced by Indiana Railroad and the Indiana Southern Railroad.  As of December 31, 2012, we employed approximately 271 mining and support personnel at this complex.

Contract mining represented less than 5.0% of our coal production in the year ended December 31, 2012. Each mining complex monitors its contract mining operations and provides geological and engineering assistance to the contract mine operators. The contract mine operators generally provide their own equipment and operate the mines using their employees. Independent contract mine operators are paid a fixed rate for each ton of saleable product. We are primarily responsible for the reclamation activities involved with all contractor-operated mines. Our relationships with contract mine operators typically can be cancelled by either party without penalty by giving between 30 and 60 days notice.

Reserves

We have an ongoing mineral development drilling and exploration program on our coal properties.  The purpose of the drilling and exploration program is to assist us with planning our mining activities and to better assess our coal reserves.  Marshall Miller & Associates, Inc. (MM&A) prepared a detailed study of our CAPP reserves that we controlled as of March 31, 2004 based on all of our geologic information, including our then current drilling and mining data. For our Midwest reserves, MM&A prepared a detailed study as of February 1, 2005 for the reserves obtained in the acquisition of Triad Mining, Inc. and as of April 11, 2006 for certain additional reserves acquired in the second quarter of 2006 in the Midwest.   MM&A also prepared a detailed study as of December 31, 2010 for the reserves obtained in the IRP Acquisition.  We have used MM&A’s March 31, 2004 study of the CAPP reserves and the December 31, 2010 study of the reserves acquired from IRP (which was based in part on previous evaluations of the properties) as the basis for our current internal estimate of our Central Appalachia reserves and MM&A’s February 1, 2005 and April 11, 2006 studies as the basis for our current internal estimate of our Midwest reserves (collectively the “MM&A studies”).  However, MM&A has not conducted any coal reserve study on our December 31, 2012 estimate or since the respective dates of such studies.

The MM&A studies were planned and performed to obtain reasonable assurance of our subject demonstrated (proven plus probable) reserves.  In connection with the studies, MM&A prepared reserve maps and had certified professional geologists develop estimates based on data supplied by us and using standards accepted by government and industry.

After reviewing the maps and information we supplied, MM&A prepared an independent mapping and estimate of our demonstrated reserves using methodology outlined in U.S. Geological Survey Circular 891 and SEC Industry Guide 7.  MM&A developed reserve estimation criteria to assure that the basic geologic characteristics of the reserves (e.g., minimum coal thickness and wash recovery, interval between deep mineable seams, mineable area tonnage for economic extraction, etc.) are in reasonable conformity with present and recent mine operation capabilities on our various properties.

We continue to have an ongoing mineral development drilling and exploration program on our coal properties.  Any future negative changes in our reserves could have a material adverse impact on our depreciation, depletion and amortization expense.  A material adverse impact could also lead to a charge for impairment of the value of our coal property assets.

As of December 31, 2012, we estimated that we controlled approximately 299.7 million tons of proven and probable coal reserves in Central Appalachia and 42.0 million tons of proven and probable coal reserves in the Midwest.

Reserves for these purposes are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.  The reserve estimates have been prepared using industry-standard methodology to provide reasonable assurance that the reserves are recoverable, considering technical, economic and legal limitations.  Although the MM&A studies found our reserves to be reasonable (notwithstanding unforeseen geological, market, labor or regulatory issues that may affect the operations), the MM&A studies did not include an economic feasibility study of our reserves.  In accordance with standard industry practice, we have performed our own economic feasibility analysis for our reserves.  It is not generally considered to be practical, however, nor is it standard industry practice, to perform a feasibility study for a company’s entire reserve portfolio.  In addition, MM&A did not independently verify our control of our properties, and has relied solely on property information supplied by us.  Reserve acreage, average seam thickness, average seam density and average mine and wash recovery percentages were verified by MM&A to prepare a reserve tonnage estimate for each reserve.  There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves as discussed in “Critical Accounting Estimates – Coal Reserves”.

The following table provides information on our mining complexes reserves (the quality information is based on the MM&A studies):  

Processing and Transportation

Coal from each of our mine complexes is transported by conveyor belt or by truck to one of our preparation plants or directly to one of our load-outs, all of which are in close proximity to our mining operations.  These preparation plants remove impurities from the run-of-mine coal (the raw coal that comes directly from the mine) and offer the flexibility to blend various coals and coal qualities to meet specific customer needs.  We regularly upgrade and maintain all of our preparation plants to achieve a high level of coal cleaning efficiency and maintain the necessary capacity.

In Central Appalachia, coal consumed domestically is usually sold f.o.b. at the mine and transportation costs are normally borne by our customers. Export coal is usually sold at the loading port, with our customers responsible for further transportation. Producers usually pay shipping costs from the mine to the port. Our Central Appalachia produced coal is transported from the mines and to the customer primarily by rail, with the main rail carriers being CSX Transportation and Norfolk Southern Railway Company. The majority of our sales volume is shipped by rail, but a portion of our production is shipped by barge and truck.

In the Midwest, coal is shipped primarily by train and by truck to our customers.  The trucked coal is primarily sold f.o.b delivery point with transportation costs borne by either the customer or us.  Coal delivered by train and barge is sold f.o.b. at the point of loading.  Our Triad mining complex has rail service provided by Indiana Railroad and Indiana Southern Railroad.

Our mining complexes are supported by personnel primarily located in London and Lexington, Kentucky and Charleston, West Virginia who provide engineering and permitting assistance, project management, land management and lease administration, coal quality control and quality reporting, accounting and purchasing support, and railroad transportation scheduling services.

Customers and Coal Contracts

As is customary in the coal industry, we enter into long-term contracts (which we define as contracts with terms of one year or longer) with many of our customers. These arrangements allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. In 2012, we generated 44% of our total revenues from coal sales to electric utility customers and the remaining 56% from coal sales (including metallurgical coal) to industrial and other customers. For the year ended December 31, 2012, US Steel (13%), Steel Authority of India Limited (13%) and Georgia Power Company (12%) were our largest customers by total revenues. No other customer accounted for more than 10% of total revenues.

In 2012, we sold approximately 9.4 million tons of coal in the CAPP region at an average selling price of $97.37 per ton. In the CAPP region, we currently have approximately 5.0 million and 0.3 million tons contracted to be sold in 2013 and 2014, respectively, at average selling prices of approximately $81 per ton and $76 per ton, respectively. Current market prices for steam and metallurgical coal in the CAPP region are substantially below our average 2012 sales price for those coals. If the market does not strengthen, our sales price for future tons sold will be adversely impacted as compared to 2012.

In 2012, we sold approximately 2.3 million tons of coal in the Midwest region at an average selling price of $44.30 per ton. In the Midwest region, we currently have approximately 2.5 million and 0.9 million tons contracted to be sold in 2013 and 2014, respectively, at average selling prices of approximately $45 per ton and $48 per ton, respectively.

The terms of our contracts result from a bidding and negotiation process with our customers. Consequently, the terms of these contracts often vary significantly in many respects. Our long-term supply contracts typically contain one or more of the following pricing mechanisms:

A limited number of our contracts have features of several contract types, such as provisions that allow for renegotiation of prices on a limited basis within a base-price-plus-escalation agreement.  Such re-opener provisions allow both the customer and us an opportunity to adjust prices to a level close to the current market conditions.  Each contract is negotiated separately, and the triggers for re-opener provisions differ from contract to contract.  Some of our existing contracts with re-opener provisions adjust the contract price to the market price at the time the re-opener provision is triggered.  Re-opener provisions could result in early termination of a contract or a reduction in the volume to be purchased if the parties were to fail to agree on price.

Our long-term supply contracts also typically contain force majeure provisions allowing for the suspension of performance by the customer or us for the duration of specified events beyond the control of the affected party, including labor disputes.  Some contracts may terminate upon continuance of an event of force majeure for an extended period, which is generally three to six months.  Certain of our contracts are fixed in quantity but are priced on a quarterly or semi-annual basis. Contracts also typically specify minimum and maximum quality specifications regarding the coal to be delivered.  Failure to meet these conditions could result in substantial price reductions or termination of the contract, at the election of the customer.  Although the volume to be delivered under a long-term contract is stipulated, we, or the customer, may vary the timing of delivery within specified limits.

The terms of our long-term coal supply contracts also vary significantly in other respects, including: coal quantity parameters, flexibility and adjustment mechanisms, permitted sources of supply, treatment of environmental constraints, options to extend, suspension, termination and assignment provisions, and provisions regarding the allocation between the parties of the cost of complying with future government regulations.

Competition

The U.S. coal industry is highly competitive, with numerous producers in all coal producing regions.  We compete against various large producers and hundreds of small producers.  According to the U.S. Energy Information Administration, the largest producer produced approximately 18.5% (based on tonnage produced) of the total United States production in 2011, the latest year for which government statistics are available.  The U.S. Department of Energy also reported 1,325 active coal mines in the United States in 2011.  Demand for our coal by our principal customers is affected by:

Continued demand for our coal and the prices that we obtain are affected by demand for electricity, environmental and government regulation, technological developments and the availability and price of competing coal and alternative fuel supplies.

Employees

At December 31, 2012, we had 2,124 employees. None of our employees are currently represented by collective bargaining agreements. Relations with our employees are generally good.

Environmental and other Regulatory Matters  

The coal mining industry is subject to extensive regulation by federal, state and local authorities on matters such as:

Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations. We could incur substantial costs, including clean up costs, fines, civil or criminal sanctions and third party claims for personal injury or property damage as a result of violations of or liabilities under these laws and regulations.

In addition, the utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal. The possibility exists that new legislation or regulations may be adopted which would have a significant impact on our mining operations or our customers’ ability to use coal and may require us or our customers to change operations significantly or incur substantial costs.

Numerous governmental permits and approvals are required for mining operations. In connection with obtaining these permits and approvals, we are, or may be, required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment, the public, historical artifacts and structures, and our employees’ health and safety. The requirements imposed by such authorities may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Future legislation and administrative regulations may emphasize the protection of the environment and health and safety and, as a consequence, our activities may be more closely regulated. Such legislation and regulations, as well as future interpretations of existing laws, may require substantial increases in our equipment and operating costs and delays, interruptions or a termination of operations, the extent of which cannot be predicted.

While it is not possible to quantify the costs of compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. We estimate that we will make expenditures of approximately $5.9 million and $2.0 million for environmental control facilities and complying with safety regulations in 2013 and 2014, respectively. These costs are in addition to reclamation and mine closing costs and the costs of treating mine water discharge, when necessary. Compliance with these laws has substantially increased the cost of coal mining, but is, in general, a cost common to all domestic coal producers.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted on July 21, 2010. Section 1503 of the Dodd-Frank Act contains new reporting requirements regarding coal or other mine safety. On December 21, 2011, the Securities and Exchange Commission adopted final rules that implement Section 1503 of the Dodd-Frank Act, and these rules went into effect on January 27, 2012. Our mine safety disclosures required pursuant to the Dodd-Frank Act appear in Exhibit 95 to this Annual Report on Form 10-K.

Mine Safety and Health Laws

The Federal Mine Safety and Health Administration (“MSHA”) is the primary regulating agency for safety and health matters and issues rules and regulations addressing mine safety and health. Stringent federal health and safety standards were imposed by the Federal Coal Mine Safety and Health Act of 1969 and again with the adoption of the Federal Mine Safety and Health Act of 1977. Mine safety and health standards were further expanded in 2006 with the passage of the Mine Improvement and New Emergency Response Act (“MINER Act”). The combined federal regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, emergency response capabilities, availability of emergency breathable air, communication and tracking systems, blasting, the equipment used in mining operations and other matters.

Pattern of Violations

On January 17, 2013, MSHA announced a final rule revising MSHA’s Pattern of Violations regulations (“POV”) in 30 C.F.R. Part 104. The final rule allows MSHA to issue a POV notice without first issuing a potential POV notice and eliminates the existing requirement that MSHA can consider only final orders in its POV review. The final rule also establishes general criteria and procedures that MSHA will utilize to identify mines with a pattern of significant and substantial (“S&S”) citations, and restates the statutory requirement that, for mines in POV status, each S&S citation will result in a withdrawal order until a complete inspection finds no S&S violations. Under the final rule, MSHA will review at least once a year the compliance and accident, injury and illness records of mines to determine if any mines meet the POV criteria. MSHA’s review to identify mines with a pattern of S&S violations will include citations for S&S violations, orders under section 104(b) of the Mine Act for not abating S&S violations, citations and withdrawal orders under section 104(d) of the Mine Act, imminent danger orders under section 107(a), orders under section 104(g) for untrained miner withdrawal orders, enforcement measures other than section 104(e) of the Mine Act that have been applied at the mine, and other information that “demonstrates a serious safety or health management problem at the mine, such as accident, injury, and illness records.”

Total Incombustible Dust

On June 21, 2011, MSHA issued a final rule requiring that the total incombustible content (“TIC”) of the combined coal, rock and other dusts in underground coal mines be at least 80%. In addition, the final rule requires that where methane is present in any ventilating current, the TIC of such combined dust shall be increased 0.4% for each 0.1% of methane. The new rule revised the existing standard, which permitted TIC of combined dusts to be 65% in areas of a mine other than return air courses.

Respirable Dust Levels

On October 19, 2010, MSHA issued a proposed rule which would gradually lower the current 2.0 mg/m³ dust standard to 1.0 mg/m³ over a two-year period from the effective date, and to 0.5 mg/m³ in intake air. The proposed rule also addresses extended work shifts, redefines normal production shifts, requires additional medical surveillance examinations for miners, and provides for the use of a single, full-shift sample to determine compliance rather than averaging multiple dust samples of different miners’ exposures per current requirements.

In addition, the proposed rule would phase in the required use of the Continuous Personal Dust Monitor (“CPDM”). The CPDMs would electronically store all respirable dust sampling data collected during a shift and would be sent to MSHA electronically. The CPDMs would be optional for surface coal mines and for non-production areas of underground coal mines (such as outby areas).

Other changes include: requiring sampling of extended work shifts to account for occupational exposures of greater than eight hours per shift; requiring sampling when production is equivalent to or greater than the level of average production level over the last 30 production shifts; and requiring spirometry testing, occupational history and symptom assessment to be implemented, in addition to the chest x-ray exam currently required for underground coal miners and medical surveillance.

Other Safety Rules

On December 28, 2012, MSHA issued a final rule, 77 Fed. Reg. 249, 76406-76498, to revise its civil penalty assessment amounts. The revised rule increases certain penalties for citations and orders issued on or after January 28, 2013.

On April 6, 2012, MSHA issued a final rule, 77 Fed. Reg. 67, 20700-20716, to revise the requirements for pre-shift, supplemental, on-shift and weekly examinations of underground coal mines. The final rule adds the requirement that operators identify violations of mandatory health or safety standards and requires the mine operator to record and correct these violations, note the actions taken to correct the conditions and review with mine examiners (e.g., the mine foreman, assistant mine foreman or other certified persons) on a quarterly basis all citations and orders issued in areas where pre-shift, supplemental, on-shift and weekly examinations are required.

On August 31, 2011, MSHA published proposed rules, 76 Fed. Reg. 169, 54163-54179, that, if finalized, will require mine operators to install proximity detection systems on continuous mining machines. The proximity detection systems initiate a warning or shutdown the continuous miner depending on the proximity of the machine to a miner.

The states in which we operate have state mine safety and health regulation and enforcement similar to those at the federal level. Collectively, federal and state safety and health regulation in the coal mining industry is, perhaps, the most comprehensive for protection of employee health and safety affecting any segment of industry in the United States. While regulation has a significant effect on our operating costs, our United States competitors are subject to the same regulation.

Black Lung Legislation

Under the federal Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator is required to make black lung benefits or contribution payments to:

Federal black lung benefits rates are periodically adjusted according to the percentage increase of the federal pay rate.

In addition to federal black lung legislation, we also are liable under various state statutes for black lung claims. To a certain extent, our federal black lung liabilities are reduced by our state liabilities.

The Patient Protection and Affordable Care Act of 2010 (the “Act”) includes a black-lung provision that creates a rebuttable presumption that a miner with at least 15 years of service, with totally disabling pulmonary or respiratory lung impairment and negative radiographic chest x-ray evidence is disabled due to pneumoconiosis and is eligible for black lung benefits.  The Act also makes it easier for widows of miners to become eligible for benefits.  This legislation could significantly impact the Company’s future payments for black lung benefits.

In recent years, additional legislation on black lung reform has been introduced but not enacted in Congress and in the Kentucky legislature.  It is possible that additional legislation will be reintroduced for consideration by Congress.  If any of the proposals included in this or similar legislation is passed, the number of claimants who are awarded benefits could significantly increase.  Any such changes in black lung legislation, if approved, may adversely affect our business, financial condition and results of operations.

Environmental Laws and Regulations

We are subject to various federal environmental laws and regulatory entities, including:

We are also subject to state laws of similar scope in each state in which we operate.

These environmental laws require reporting, permitting and/or approval of many aspects of coal operations. Both federal and state inspectors regularly visit mines and other facilities to ensure compliance. We have ongoing compliance and permitting programs designed to ensure compliance with such environmental laws.

Given the retroactive nature of certain environmental laws, we have incurred and may in the future incur liabilities, including clean-up costs, in connection with properties and facilities currently or previously owned or operated as well as sites to which we or our subsidiaries sent waste materials.

Surface Mining Control and Reclamation Act (SMCRA)

SMCRA, and its state counterparts, establish operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of underground mining. 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 (OSM) or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the state becomes the regulatory authority with primacy and issues the permits with federal oversight from OSM.

SMCRA and similar state statutes, among other things, require that mined property be restored in accordance with specified standards and approved reclamation plans. The mine operator must submit a bond or otherwise secure the performance of these reclamation obligations. The earliest a reclamation bond can be fully released is five years after reclamation has been achieved. On May 1, 2012, OSM notified the state of Kentucky that OSM believes Kentucky’s bonding program is insufficient. The resolution of this issue could cause bonding costs for new or existing operations to increase.

All states impose on mine operators the responsibility for repairing or compensating for damage occurring on the surface as a result of mine subsidence, a possible consequence of underground mining. In addition, the Abandoned Mine Reclamation Fund, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore unreclaimed mines closed before 1977. Going forward, the maximum tax is $0.28 per ton on surface mined coal and $0.12 per ton on coal produced by underground mining.

Our future operating results would be adversely affected if our accruals for reclamation were determined to be insufficient. These obligations are unfunded. The amount that was expensed for reclamation during the year ended December 31, 2012 was $5.3 million, while the related cash payment for such liability during the same period was $2.1 million.

We also lease some of our coal reserves to third-party operators. Although specific criteria vary from state to state as to what constitutes an “owner” or “controller” relationship, under SMCRA, operators can be blocked from receiving permits to conduct mining where the operator is deemed to “own” or “control” third-parties who have unabated violations, unpaid civil penalties or unpaid reclamation fees.

The Clean Air Act and Related Rules

The federal Clean Air Act and similar state laws and regulations, which regulate emissions into the air, affect coal mining and processing operations primarily through permitting and/or emissions control requirements. In addition, the Environmental Protection Agency (the “EPA”) has issued certain, and is considering further, regulations relating to fugitive dust and particulate matter emissions that could restrict our ability to develop new mines or require us to modify our operations and may have a material adverse effect on our financial condition and results of operations.

The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coal is burned. New environmental regulations governing emissions from coal-fired electric generating plants could reduce demand for coal as a fuel source and affect the volume of our sales. For example, the federal Clean Air Act places limits on sulfur dioxide emissions from electric power plants. In order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), blend high sulfur coal with low sulfur coal or switch to low sulfur coal or other fuels. The cost of installing scrubbers is significant and emission allowances may become more expensive as their availability declines. Switching to other fuels may require expensive modifications to existing plants.

Cross State Air Pollution Rule

On August 8, 2011, the EPA published the final Cross State Air Pollution Rule (CSAPR) requiring reductions of sulfur dioxide and nitrogen oxide emissions from power plants in 27 states located in the eastern half of the U.S. CSAPR addresses interstate emissions of sulfur dioxide and nitrogen oxides that interfere with downwind states’ ability to meet or maintain national ambient air quality standards for ozone and/or particulate matter. A Texas utility filed suit against the EPA contesting the legality of CSAPR. On August 21, 2012 the United States Court of Appeals for the District of Columbia ruled against the EPA and invalidated CSAPR, finding that the EPA had exceeded its statutory authority. On October 5, 2012 the EPA filed for a rehearing of the case. The impact of CSAPR will depend on the final outcome of the legal proceedings and cannot be determined at this time.

Maximum Achievable Control Technology (“MACT”)

On February 16, 2012, the EPA published its final Utility MACT rule, which imposes stringent acid gases, mercury and particulate matter emission limits on coal- and oil-fired electric utility steam generating units. On July 9, 2012 several utilities and interested parties filed suit in the U.S. Court of Appeals for the District of Columbia asking the court to vacate the Utility MACT rule. Subsequently, on August 2, 2012, the EPA issued a partial stay of the Utility MACT rule to give the EPA time to reconsider the rule. The EPA plans to issue the revised Utility MACT rule by March 2013. In the meantime, the legal challenges to the Utility MACT rule have been suspended pending the EPA’s reissuance of the Utility MACT Rule.

On March 21, 2011 the EPA issued the Industrial Boiler MACT rule standards establishing emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including coal-fired boilers. At the same time of issuance of the rule, the EPA issued a notice of intent to reconsider the rule to allow for additional public review and comment. On December 20, 2012, the EPA finalized the Industrial Boiler MACT rule after taking into consideration industry comments. The Industrial Boiler MACT rule requires compliance by 2016 or 2018 depending on the type of boiler.

These new and proposed regulations will make it more costly to operate coal-fired plants and could make coal a less attractive fuel alternative in the planning and building of utility power plants and industrial boilers in the future. To the extent that any new and proposed requirements affect our customers, this could adversely affect our operations and results.

Regional Haze Program

In 1999, the EPA promulgated a regional haze program designed to protect and to improve visibility at and around so-called Class I Areas, which are generally National Parks, National Wilderness Areas and International Parks. This program may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around the Class I Areas. Moreover, the program requires certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxide and particulate matter. States were required to submit Regional Haze State Implementation Plans (“SIPs”) to the EPA by December 17, 2007. Many states did not meet the December 17, 2007 deadline, and on February 4, 2011, several environmental groups (including the Sierra Club and Environmental Defense Fund) notified the EPA that they intend to sue the EPA under the citizen suit provision of the Clean Air Act for failure to enforce the regional haze rule. In addition, the EPA issued a proposed rule on December 30, 2011 that would allow states subject to CSAPR to rely on the CSAPR trading program to meet some of the requirements in the regional haze program. However, as noted above, CSAPR has been invalidated by the courts but may be subject to additional legal proceedings. We are unable to predict the impact on the coal market of either the states’ failure to submit Regional Haze SIPs by the deadline or the potential litigation of CSAPR.

Initiatives to Reduce Greenhouse Gas Emissions

Considerable and increasing government attention in the United States and other countries is being paid to reducing greenhouse gas (“GHG”) emissions, including carbon dioxide (“CO2”) emissions from coal-fired power plants and methane emissions from mining operations. Although the United States has not ratified the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (“UNFCCC”), which became effective for many countries in 2005 and establishes a binding set of emission targets for greenhouse gases, the United States is actively participating in various international initiatives within and outside of the UNFCCC process to negotiate developed and developing nation commitments for GHG emission reductions and related financing. Any international GHG agreement in which the United States participates, if at all, could adversely affect the price and demand for coal.

In addition to possible future U.S. treaty obligations, regulation of GHG in the United States could occur pursuant to new or amended federal or state legislation, including but not limited to regulatory changes under the Clean Air Act, Public Utility Regulatory Policies Act, state initiatives, or otherwise. At the federal level, Congress actively considered in the past, and may consider in the future, legislation that would establish a nationwide GHG emissions cap-and-trade or other market-based program to reduce GHG emissions. There are other types of legislative proposals that would promote clean energy that Congress has also considered in the past, and is currently considering. Many of these proposals would tend to favor fuels that have a lower carbon content than coal, but such proposals also incent the construction and development of carbon capture and sequestration plants as well as other advanced coal technologies. We cannot predict the financial impact of future GHG or clean energy legislation on our operations or our customers at this time.

The EPA also is implementing plans to regulate GHG emissions. In October 2009, the EPA published its final Mandatory Greenhouse Gas Reporting Rule, which requires power plants and other large sources of GHGs to file reports disclosing GHG emissions. In November 2011, the EPA issued an amendment delaying to April 1, 2013 the reporting deadline for underground coal mines and certain other source categories to file their first annual reports disclosing GHG emissions.

In December 2009, the EPA issued a Final Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air Act, wherein the EPA concluded that GHGs endanger the public health and welfare. In April 2010, the EPA issued, along with the Department of Transportation, a rule to regulate GHG emissions from new cars and trucks. This rule took effect in January 2011, and according to EPA, established GHG emissions as “regulated pollutants” under the Clean Air Act. As a consequence, and in conjunction with an EPA Final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, it requires new and modified emission sources to meet Best Available Control Technology for GHG emissions.

On March 27, 2012, the EPA proposed a New Source Performance Standard rule that limits CO2 emissions from new fossil fuel burning power plants to 1,000 pounds of CO2 emissions for every one megawatt hour of power generated. This standard is achievable by most natural gas-fired power plants but is not economically achievable given current technology for coal-fired power generation. This rule, if effective, will likely prevent the construction of new coal-fired power generation for the foreseeable future. Federal legislation that would variously suspend or eliminate EPA’s regulatory authority over GHGs has been introduced in both the House and Senate.

In addition to federal GHG regulations, there are several new state programs to limit GHG emissions and others have been proposed. State and regional climate change initiatives are taking effect before federal action. Beginning January 1, 2009 the Regional Greenhouse Gas Initiative, a regional GHG cap-and-trade program calling for a ten percent reduction of emissions by 2018, was established by ten Northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont). In October 2011, the California Air Resources Board adopted regulations that establish a statewide cap and trade program to control GHG emissions. The program will take effect in 2013.

Predicting the economic effects of greenhouse gas legislation is difficult given the various alternatives proposed and the complexities of the interactions between economic and environmental issues. Coal-fired generators could switch to other fuels that generate less of these emissions, possibly reducing the construction of coal-fired power plants or causing some users of our coal to switch to a lower CO2 generating fuel, or more generally reducing the demand for coal-fired electricity generation. This could result in an indeterminate decrease in demand for coal nationally, and various mechanisms proposed to limit GHG emissions could impact the price of coal and the cost of coal-fired generation. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser's plant or results in specified increases in the cost of coal or its use to comply with applicable ambient air quality standards. In addition, if regulation of GHG emissions does not exempt the release of coalbed methane, we may have to curtail coal production, pay higher taxes, or incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines.

The Clean Water Act and Related Rules

The Clean Water Act of 1972 (the “CWA”) and corresponding state laws affect coal mining operations by imposing restrictions on the discharge of certain pollutants into water and on dredging and filling wetlands. The CWA establishes in-stream water quality standards and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water. These requirements are complex, lengthy and becoming increasingly stringent as new regulations or amendments to existing regulations are adopted. In addition, legal challenges to regulations may impact their content and the timing of their implementation.

Section 404 Permitting

Permits under Section 404 of the CWA are required for coal companies to conduct dredging or filling activities in jurisdictional waters for the purpose of creating slurry ponds, water impoundments, refuse disposal areas, valley fills or other mining activities. Jurisdictional waters typically include ephemeral, intermittent, and perennial streams and may in certain instances include man-made conveyances that have a hydrologic connection to a stream or wetland. The U.S. Army Corps of Engineers (COE) only has jurisdiction over the “navigable waters” of the United States, and outside these waters there is arguably no need to procure a 404 permit. The United States Supreme Court ruled in Rapanos v. United States in 2006 that upper reaches of streams which are intermittent or do not flow might not be jurisdictional waters requiring 404 permits. The case did not involve disposal of mining refuse, but has implications for the mining industry. Subsequently, in June 2007 the COE and EPA issued a joint guidance document to attempt to develop a policy that will apply the jurisdictional standards imposed by the Supreme Court. The guidance requires a case-by-case analysis of whether the area to be filled has a sufficient nexus to downstream navigable waters so as to require 404 permits. Review and implementation of this guidance by the COE field offices remains inconsistent; the extent to which decisions made pursuant to this guidance will be challenged remains an open question.

The COE’s issuance of 404 permits is subject to the National Environmental Policy Act (“NEPA”). NEPA defines the procedures by which a federal agency must administer its permitting programs. The law requires that a federal agency must take a “hard look” at any activity that may “significantly affect the quality of the human environment”. The COE typically conducts an initial Environmental Assessment (“EA”) to determine whether the project’s effects are significant enough to require an Environmental Impact Statement (“EIS”), which involves a very lengthy data collection and review process. In most cases, the COE issues a Finding of No Significant Impact (“FONSI”) at the conclusion of the EA and does not require an EIS to determine the impacts from impoundments, fills and other activities associated with coal mining. However, in some cases the full EIS process is being required for mining projects. Should a full EIS be required for every permit instead of, or in addition to, the less detailed EA, significant permitting delays could affect mining costs or cause operations not to be opened in the first instance, or to be idled or closed.

The COE is empowered to issue nationwide permits for specific categories of filling activity that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404. Nationwide Permit 21 (“NWP 21”) authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. Over the last decade several citizens groups have sued the COE in federal court in West Virginia and Kentucky seeking to invalidate nationwide permits utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. The plaintiffs sought to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators from additional use of existing nationwide permit approvals until they obtain more detailed individual permits. These litigation challenges have been followed by significant policy changes by the COE. In June 2010, the COE suspended use of the NWP 21 within a six-state region, including Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia. In February 2012, the COE reissued the NWP 21 permit with significant new limitations. The reissued NWP 21 permit only authorizes impacts to one-half acre of surface water and no more than 300 linear feet of stream bed. In addition, the construction of valley fills is not authorized in the permit. The new limitations in the NWP 21 permit may require us to undertake the more burdensome approach of obtaining individual Section 404 permits for new projects.

Since 2009, the federal Office of Surface Mining issued an advance notice of a proposed rulemaking on a new “stream protection rule” which would consider defining the term “material damage” to the hydrologic balance outside the permit area (which damage is prohibited under SMCRA), limiting or controlling operations which mined through or filled streams, and better defining the “approximate original contours” to which surface mines must ordinarily be restored.  OSM hired outside contractors to conduct an EIS on the rulemaking effort.  Their draft work identified several alternative rulemaking scenarios and the economic consequences of OSM’s “preferred” scenario.  Portions of their work was leaked to the public in early 2011 and predicted reductions in production and thousands of fewer mining jobs in Appalachia as a  result of the preferred alternatives. Criticism of OSM’s methodologies has caused it to slow its efforts and it has yet to issue a proposed rule, but OSM claims to still be developing a rule.

National Pollutant Discharge Elimination Permits

The Clean Water Act (“CWA”) requires that all of our operations obtain NPDES permits for discharges of water from all of our mining operations. NPDES permits for our operations normally contain limits for constitutes typically present in mining effluent, including iron, manganese, settleable solids and pH. Additionally, limits for other constitutes, including selenium and aluminum, may be required, depending on conditions at the site. Increasingly more restrictive limits are being added to NPDES permits in all states, which potentially could create requirements for treatment systems and higher costs to comply with permit conditions.

When a water discharge occurs and one or more parameters are outside the approved limits permitted in an NPDES permit, these exceedances of permit limits are self-reported to the pertinent agency. The agency may impose penalties for each such release in excess of permitted amounts. If factors such as heavy rains or geologic conditions cause persistent releases in excess of amounts allowed under NPDES permits, costs of compliance can be material, fines may be imposed, or operations may have to be idled until remedial actions are possible. Additionally, the CWA has citizen suit provisions which allow individuals or organized groups to file suit against permit holders or the EPA or state agencies for failure to enforce all aspects of the CWA. Although we are aware of citizen suit actions against a small number of our permits, we do not think these actions are material to our business, and we believe the citizen suit actions lack merit. Similar actions have recently been filed against other companies.

The Clean Water Act has specialized sections that address NPDES permit conditions for discharges to waters in which state-issued water quality standards are violated and where the quality exceeds the levels established by those standards. For those waters where conditions violate state water quality standards, states or the EPA are required to prepare a Total Maximum Daily Load (“TMDL”) by which new discharge limits are imposed on existing and future discharges in an effort to restore the water quality of the receiving streams. Likewise, when water quality in a receiving stream is better than required, states are required to adopt an “anti-degradation policy” by which further “degradation” of the existing water quality is reviewed and possibly limited. In the case of both the TMDL and anti-degradation review, the limits in our NPDES discharge permits could become more stringent, thereby potentially increasing our treatment costs and making it more difficult to obtain new surface mining permits. New standards may also require us to install expensive water treatment facilities or otherwise modify mining practices and thereby substantially increase mining costs. These increased costs may render some operations unprofitable.

In September 2009, the EPA announced it had identified 79 pending permit applications for Appalachian surface coal mining that warranted further review under an enhanced coordination process (“ECP”) with the COE and the United States Department of the Interior entered into in June 2009. These included four of our permit applications, three of which we have abandoned while the remaining permit was issued to us in July 2012. On October 17, 2012 two environmental groups, the Sierra Club and Kentuckians for the Commonwealth, filed suit against the COE in the U.S. District Court for the Western District of Kentucky claiming that the COE unlawfully issued the Section 404 permit to us because the COE failed to perform an Environmental Impact Statement and failed to consider alleged adverse effects on human health and welfare from surface coal mines before issuing the Section 404 permit. The Section 404 permit and the outcome of this case, which cannot be determined at this time, are not material to our operations.

In conjunction with this ECP, EPA published guidance in a July 21, 2011 Final Memorandum entitled “Improving EPA Review of Appalachian Surface Coal Mining Operations Under the Clean Water Act, National Environmental Policy Act, and the Environmental Justice Executive Order” (“EPA Mining Guidance”). The EPA Mining Guidance establishes threshold conductivity levels to be used as a basis for evaluating compliance with narrative water quality standards. Conductivity is a measure that reflects levels of various salts present in water. The EPA Administrator stated that these water quality standards may be difficult for most mining operations to meet.

The ECP as well as the EPA Mining Guidance were challenged in court by the National Mining Association and by several states. On October 6, 2011, a federal court vacated the ECP. Likewise, the EPA Mining Guidance was vacated on July 31, 2012, by a federal district court.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act (commonly known as Superfund) and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources. Our current and former coal mining operations incur, and will continue to incur, expenditures associated with the investigation and remediation of facilities and environmental conditions, including underground storage tanks, solid and hazardous waste disposal and other matters under these environmental laws. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

The magnitude of the liability and the cost of complying with environmental laws with respect to particular sites cannot be predicted with certainty due to the lack of specific information available, the potential for new or changed laws and regulations, the development of new remediation technologies, and the uncertainty regarding the timing of remedial work. As a result, we may incur material liabilities or costs related to environmental matters in the future and such environmental liabilities or costs could adversely affect our results and financial condition. In addition, there can be no assurance that changes in laws or regulations would not result in additional costs and affect the manner in which we are required to conduct our operations. 

Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act and corresponding state laws and regulations affect coal mining operations by imposing requirements for the treatment, storage and disposal of hazardous wastes. Facilities at which hazardous wastes have been treated, stored or disposed of are subject to corrective action orders issued by the EPA and other potential obligations, which could adversely affect our results of operations or financial condition.

Item 1A.          Risk Factors

Risks Related to the Coal Industry

Because the demand and pricing for coal is greatly influenced by consumption patterns of the domestic electricity generation industry and the worldwide steel industry, a reduction in the demand for coal by these industries would likely cause our revenues and profitability to decline significantly.

We derived 44% of our total revenues in 2012 and 56% of our total revenues in 2011, from our electric utility customers and the remaining 56% of our total revenues in 2012 and 44% of our total revenues in 2011 were derived from industrial and other customers, including those in the steel industry.

We compete with coal producers in the United States and overseas for domestic and international sales. Demand for our coal and the prices that we will be able to obtain primarily will depend upon coal consumption patterns of the electric utility industry and the worldwide steel industry. Consumption by the utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel supplies including natural gas, nuclear, oil and renewable energy sources, including hydroelectric power. In particular, coal fired electrical generation faces strong competition from natural gas as historically low natural gas prices have dramatically increased natural gas’ share of electrical generation. Gas-fired electrical generation has the potential to continue displacing coal-fired electrical generation due in part to increased natural gas supply from shale formations resulting in lower natural gas prices and environmental regulations that tend to favor natural gas over coal.   

Demand by the electricity industry is impacted by weather patterns, as well as overall economic activity and the associated demand for power by industrial users. Demand by the steel industry is primarily affected by economic growth and the demand for steel used in construction as well as appliances and automobiles. Prolonged decreases in global demand for electricity and steel production could adversely affect our financial condition and results of operations.

Due to economic and market conditions, our contracts for steam and metallurgical coal deliveries in 2013 provide lower sales prices than the average sales prices we received for deliveries of similar coal in 2012.  While we manage our coal contracts on a composite basis to maximize the returns on our coal sold by moving coal to higher priced markets where possible (for example moving coal between the industrial coal market and the domestic utility market) there can be no assurances that pricing we receive on tons sold in 2013 and beyond will be reflective of the per-ton price of coal that we have received in prior periods.    

Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on the prevailing conditions in the markets for metallurgical and steam coal. A decline in the metallurgical market relative to the steam market could cause us to shift coal from the metallurgical market to the steam market, potentially reducing the price we could obtain for this coal and adversely impacting our cash flows, results of operations or financial condition.

Any downward pressure on coal prices would likely cause our profitability to decline.

Electric utility deregulation is expected to provide incentives to generators of electricity to minimize their fuel costs and is believed to have caused electric generators to be more aggressive in negotiating prices with coal suppliers. To the extent utility deregulation causes our customers to be more cost-sensitive, deregulation may have a negative effect on our profitability.

Changes in the export and import markets for coal products could affect the demand for our coal, our pricing and our profitability.

We compete in a worldwide market. The pricing and demand for our products is affected by a number of factors beyond our control. These factors include:

Any decrease in the amount of coal exported from the United States, or any increase in the amount of coal imported into the United States, could have a material adverse impact on the demand for our coal, our pricing and our profitability. Ongoing uncertainty in European economies and slowing economies in China, India and Brazil have reduced and may continue to reduce near-term pricing and demand for coal exported from the United States.

Increased consolidation and competition in the U.S. coal industry may adversely affect our revenues and profitability.

During the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive.  Consequently, many of our competitors in the domestic coal industry are major coal producers who have significantly greater financial resources than us.  The intense competition among coal producers may impact our ability to retain or attract customers and may therefore adversely affect our future revenues and profitability.

If the coal industry experiences overcapacity in the future, our profitability could be impaired.

An increase in the demand for coal could attract new investors to the coal industry, which could spur the development of new mines, and result in added production capacity throughout the industry. Higher price levels of coal could also encourage the development of expanded capacity by new or existing coal producers. Any resulting increases in capacity could reduce coal prices and reduce our margins.

Fluctuations in transportation costs and the availability and dependability of transportation could affect the demand for our coal and our ability to deliver coal to our customers.

Increases in transportation costs could have an adverse effect on demand for our coal.  Customers choose coal supplies based, primarily, on the total delivered cost of coal.  Any increase in transportation costs would cause an increase in the total delivered cost of coal.  That could cause some of our customers to seek less expensive sources of coal or alternative fuels to satisfy their energy needs.  In addition, significant decreases in transportation costs from other coal-producing regions, both domestic and international, could result in increased competition from coal producers in those regions.  For instance, coal mines in the western United States could become more attractive as a source of coal to consumers in the eastern United States, if the costs of transporting coal from the West were significantly reduced.

Our Central Appalachia mines generally ship coal via rail systems, ocean vessels and barges.  During 2012, we shipped approximately 90% of our coal from our Central Appalachia mines via rail system, including coal that was transported by rail to export vessels.  In the Midwest, we shipped approximately 53% of our produced coal by rail and the remainder by truck or barge.  We believe that our 2013 transportation modes will continue to be comparable to those used in 2012.  Our dependence upon railroads, third party trucking companies, ocean vessels and barges impacts our ability to deliver coal to our customers.  Disruption of service due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and other events could temporarily impair our ability to supply coal to our customers, resulting in decreased shipments.  Decreased performance levels over longer periods of time could cause our customers to look elsewhere for their fuel needs, negatively affecting our revenues and profitability.

In past years, the major eastern railroads (CSX and Norfolk Southern) have experienced periods of increased overall rail traffic due to an expanding economy and shortages of both equipment and personnel.  This increase in traffic could impact our ability to obtain the necessary rail cars to deliver coal to our customers and have an adverse impact on our financial results.

Shortages or increased costs of skilled labor in the coal regions that we operate may hamper our ability to achieve high labor productivity and competitive costs.

Coal mining continues to be a labor-intensive industry.  In times of increased demand, many producers attempt to increase coal production, which historically has resulted in a competitive market for the limited supply of trained coal miners.  In some cases, this market situation has caused compensation levels to increase, particularly for “skilled” positions such as electricians and mine foremen.  To maintain current production levels, we may be forced to respond to increases in wages and other forms of compensation, and related recruiting efforts by our competitors.  Any future shortage of skilled miners, or increases in our labor costs, could have an adverse impact on our labor productivity and costs and on our ability to expand production.

Government laws, regulations and other requirements relating to the protection of the environment, health and safety and other matters impose significant costs on us, and future requirements could limit our ability to produce coal at a competitive price.

We are subject to extensive federal, state and local regulations with respect to matters such as:

Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations.  We could incur substantial costs, including clean up costs, fines, civil or criminal sanctions and third party claims for personal injury or property damage as a result of violations of or liabilities under these laws and regulations.

The coal industry is also affected by significant legislation mandating specified benefits for retired miners.  In addition, the utility industry, which is the most significant end user of coal, is subject to extensive regulation regarding the environmental impact of its power generating activities.  Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned.  Stricter environmental regulations of emissions from coal-fired electric generating plants could increase the costs of using coal, thereby reducing demand for coal as a fuel source or the volume and price of our coal sales, or making coal a less attractive fuel alternative in the planning and building of utility power plants in the future.

New legislation, regulations and orders adopted or implemented in the future (or changes in interpretations of existing laws and regulations) may materially adversely affect our mining operations, our cost structure and our customers’ operations or ability to use coal.

The majority of our coal supply agreements contain provisions that allow the purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in too great an increase in the cost of coal.  These factors and legislation, if enacted, could have a material adverse effect on our financial condition and results of operations.

Climate change initiatives could significantly reduce the demand for coal, increase our costs and reduce the value of our coal assets.

Global climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity, especially the emissions of greenhouse gases (“GHG”), such as carbon dioxide (CO2) and methane. Combustion of fossil fuels, such as the coal we produce, results in the creation of CO2 that is currently emitted into the atmosphere by coal end users, such as coal-fired electric generation power plants. Our underground mines emit methane, which must be expelled for safety reasons.

Considerable and increasing government attention in the United States and other countries is being paid to reducing greenhouse gas emissions, including CO2 emissions from coal-fired power plants and methane emissions from mining operations. Although the United States has not ratified the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (“UNFCCC”), which became effective for many countries in 2005 and establishes a binding set of emission targets for GHGs, the United States is actively participating in various international initiatives within and outside of the UNFCCC process to negotiate developed and developing nation commitments for GHG emission reductions and related financing. For example, in December 2009, approximately 190 countries participated in the UNFCC meetings in Copenhagen. The participants “took note” of a non-binding accord under which participating nations would report their commitments to reduce GHG emissions. Under this non-binding framework, the U.S. committed to cut GHG emissions by 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050. Any international GHG agreement in which the United States participates, if at all, could adversely affect the price and demand for coal.

U.S. legislative and regulatory action also may address GHG emissions. At the federal level, Congress actively considered in the past, and may consider in the future, legislation that would establish a nationwide GHG emissions cap-and-trade or other market-based program to reduce GHG emissions. The EPA also has commenced regulatory action that could lead to controls on CO2 from larger emitters such as coal-fired power plants and industrial sources. In advance of federal action, state and regional climate change initiatives, such as the Regional Greenhouse Gas Initiative of eastern states, the Western Regional Climate Action Initiative, and recently enacted legislation in California and other states are taking effect before federal action. In addition, some states and municipalities in the United States have adopted or may adopt in the future regulations on GHG emissions. Some states and municipal entities have commenced litigation in different jurisdictions seeking to have certain utilities, including some of our customers, reduce their emission of CO2. Apart from governmental regulation, certain large investment banks announced that they had adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of utility power plants which may make it more difficult for utilities to obtain financing for coal-fired plants.

Considerable uncertainty is associated with these climate change initiatives. The content of new treaties, legislation or regulation is not yet determined, and many of the new regulatory initiatives remain subject to review by the agencies or the courts. Predicting the economic effects of climate change legislation is difficult given the various alternatives proposed and the complexities of the interactions between economic and environmental issues. Any regulations on GHG emissions, however, are likely to impose significant emissions control expenditures on many coal-fired power plants and industrial boilers and could have the effect of making them unprofitable. As a result, these generators may switch to other fuels that generate less of these emissions, possibly reducing future demand for coal and the construction of coal-fired power plants. In this regard, many of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser's plant or results in specified increases in the cost of coal or its use to comply with applicable ambient air quality standards. Any switching of fuel sources away from coal, closure of existing coal-fired plants, or reduced construction of new plants could have a material adverse effect on demand for and prices received for our coal and a material adverse effect on our results of operations, cash flows and financial condition. In addition, if regulation of GHG emissions does not exempt the release of coalbed methane, we may have to curtail coal production, pay higher taxes, or incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines.

We are subject to the federal Clean Water Act and similar state laws which impose treatment, monitoring and reporting obligations.

The federal Clean Water Act and corresponding state laws affect coal mining operations by imposing restrictions on discharges into regulated waters.  Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters.  New requirements under the Clean Water Act and corresponding state laws could cause us to incur significant additional costs that adversely affect our operating results. 

Regulations have expanded the definition of black lung disease and generally made it easier for claimants to assert and prosecute claims, which could increase our exposure to black lung benefit liabilities.

The Patient Protection and Affordable Care Act of 2010 (Act) includes a black-lung provision that creates a rebuttable presumption that a miner with at least 15 years of service, with totally disabling pulmonary or respiratory lung impairment and negative radiographic chest x-ray evidence is disabled due to pneumoconiosis and is eligible for black lung benefits. The Act also makes it easier for widows of miners to become eligible for benefits. This legislation could significantly impact the Company’s future payments for black lung benefits.

In recent years, additional legislation on black lung reform has been introduced but not enacted in Congress and in the Kentucky legislature. It is possible that additional legislation will be reintroduced for consideration by Congress. If any of the proposals included in this or similar legislation is passed, the number of claimants who are awarded benefits could significantly increase. Any such changes in black lung legislation, if approved, may adversely affect our business, financial condition and results of operations.

Extensive environmental laws and regulations affect the end-users of coal and could reduce the demand for coal as a fuel source and cause the volume of our sales to decline.

The Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. Compliance with such laws and regulations, which can take a variety of forms, may reduce demand for coal as a fuel source because they can require significant emissions control expenditures for coal-fired power plants to attain applicable ambient air quality standards, which may lead these generators to switch to other fuels that generate less of these emissions, to retire or reduce production from older coal-fired power plants and/or to decrease the construction of coal-fired power plants.

The EPA has adopted more stringent National Ambient Air Quality Standards for nitrogen dioxide and sulfur dioxide, both of which are emitted from coal-fired combustion units. The EPA is considering whether to adopt a more stringent standard for ground-level ozone, to which emissions from coal combustion units can contribute. The demand for coal could be affected at electric generating facilities located in geographic areas that exceed the modified standards.

A regional haze program initiated by the EPA to protect and to improve visibility at and around national parks, national wilderness areas and international parks restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions.

The Clean Air Act also imposes standards on sources of hazardous air pollutants. The EPA’s Utility MACT rule, if enacted into law would impose stringent acid gases, mercury and particulate matter emission limits on coal- and oil-fired electric utility steam generating units.   The EPA’s Industrial Boiler MACT rule limits emissions from industrial boilers, including those fueled by coal. These standards and future standards could have the effect of decreasing demand for coal. So-called multi-pollutant bills, which could regulate additional air pollutants, have been proposed by various members of Congress. If such initiatives are enacted into law, power plant operators could choose other fuel sources to meet their requirements, reducing the demand for coal.

On August 8, 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR), which sets new power plant emission levels and could cause power plant operators to choose fuel sources other than coal. A Texas utility filed suit against the EPA contesting the legality of CSAPR. On August 21, 2012 the United States Court of Appeals for the District of Columbia ruled against the EPA and invalidated CSAPR, finding that the EPA had exceeded its statutory authority. On October 5, 2012, the EPA filed for rehearing of the case. The impact of CSAPR will depend on the final outcome of legal challenges and cannot be determined at this time.

As a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, 549 U.S. 497 (2007), finding that GHGs fall within the Clean Air Act definition of “air pollutant,” the EPA was required to determine whether emissions of GHGs “endanger” public health or welfare. In December 2009, the EPA published an “Endangerment Finding” stating that current and projected concentrations of CO2 and five other GHGs in the atmosphere threaten the public’s health and welfare. The EPA’s Endangerment Finding was challenged in federal court by numerous states (see, Coalition for Responsible Regulation, Inc. et al. v. EPA); however, on June 26, 2012, the U.S. District Court of Appeals for the District of Columbia ruled in favor of the EPA, validating the EPA’s Endangerment Finding and enabling the EPA to proceed with a broad regulatory program for the control of GHG emissions, including CO2 emissions. The EPA has recently completed several rulemaking actions indicating its intent to limit GHG emissions, including, among others, a final GHG reporting rule for certain major stationary source permitting programs, final regulations to control GHG emissions from light duty vehicles, proposed regulations limiting CO2 emissions from new, modified and reconstructed power plants, and a final “tailoring” rule explaining how it would implement the Clean Air Act’s Title V and prevention of significant deterioration permitting programs with respect to GHG emissions from major stationary sources.

In recent legislative sessions, both houses of Congress have considered, but failed to enact, new legislation that could establish a national cap on, or other regulation of, carbon emissions and other GHGs. Recent proposals include a cap and trade system that would require the purchase of emission permits, which could be traded on the open market. These and other proposals would make it more costly to operate coal-fired plants and could make coal a less attractive fuel for future power plants. Any new or proposed requirements adversely affecting the use of coal could adversely affect our operations and results.

The permitting of new coal-fired power plants has also recently been contested by state regulators and environmental organizations based on concerns relating to GHG emissions. In several litigation cases, plaintiffs are seeking various remedies, including injunctive relief, against power plant owners. However, the risk of an adverse outcome has been mitigated by the June 20, 2011 decision of the U.S. Supreme Court in Connecticut v. AEP.  The Supreme Court reversed the decision of the United States Court of Appeals for the Second Circuit which had allowed plaintiffs’ claims that public utilities’ GHG emissions created a “public nuisance” to go to trial.  The Supreme Court held that the EPA’s authority to regulate GHG emissions under the Clean Air Act displaces federal common law claims.  The effect of these recent cases may also be mitigated in the event Congress adopts GHG legislation and because the EPA has finalized the adoption of GHG emission standards. Nevertheless, increased efforts to control GHG emissions by state, federal, judicial or international authorities could result in reduced demand for coal.

The EPA has issued a proposed rule to regulate the management of coal ash that results from the combustion of coal.  The proposed rule would classify coal ash produced at electric power plants as a waste, thereby making it subject to significant restrictions on storage and disposal.  In conjunction with the rulemaking, EPA has conducted assessments of the integrity of dams, impoundments, and other structures where coal ash from electric power plants is deposited.  Although the rulemaking has been delayed, further scrutiny of coal ash management practices could result in reduced demand for coal.

We must obtain governmental permits and approvals for mining operations, which can be a costly and time consuming process and result in restrictions on our operations.

Numerous governmental permits and approvals are required for mining operations. Our operations are principally regulated under permits issued by state regulatory and enforcement agencies pursuant to the federal Surface Mining Control and Reclamation Act (SMCRA). Additionally, we often require permits under the Clean Water Act and the Clean Air Act. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of exploration or production operations. In addition, we often are required to prepare and present to federal, state and local authorities data pertaining to the effect or impact that proposed exploration for or production of coal might have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or, if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our mining operations or to do so profitably.

In particular, permit issuance under Section 404 of the Clean Water Act, which is often required for valley fills, ponds or impoundments, refuse, road building, placement of excess material and other mine development activities, is facing increasingly stringent regulatory and administrative requirements and a series of court challenges that have resulted in increased costs and delays in the permitting process. Previously, a Section 404 permit could be either a simplified Nationwide Permit #21 (NWP 21) or a more complicated individual permit. Litigation respecting the validity of the NWP 21 permit program has been ongoing for several years. In 2010, the Army Corps of Engineers (COE) announced its decision to suspend the use of NWP 21 in a six state Appalachian region, including Kentucky and West Virginia, where we operate. Recently, the COE reissued the NWP 21 permit with significant new limitations on authorized impacts to surface water, including a prohibition against valley fills. Litigation respecting the issuance of certain Section 404 permits has also been ongoing for several years, focusing primarily on whether the COE’s decision to issue such permits conformed to the requirements of the Clean Water Act and/or the National Environmental Policy Act. The matters at issue in such litigation are such that a ruling for the plaintiffs could have an adverse impact on our planned surface mining operations.

In 2009, the EPA announced publicly that it will exercise its statutory right to more actively review Section 404 permitting actions by the COE. In the third quarter of 2009, the EPA announced that it would further review 79 surface mining permit applications, including four of our permits. These 79 permits were identified as likely to impact water quality and therefore required additional review under the Clean Water Act. We abandoned three of our permits and the fourth was issued to us in July 2012. On October 17, 2012 two environmental groups, the Sierra Club and Kentuckians for the Commonwealth, filed suit against the COE in the U.S. District Court for the Western District of Kentucky claiming that the COE unlawfully issued the Section 404 permit to us because the COE failed to perform an Environmental Impact Statement and failed to consider alleged adverse effects on human health and welfare from surface coal mines before issuing the Section 404 permit. The Section 404 permit and the outcome of this case, which cannot be determined at this time, are not material to our operations.

More recently, the EPA announced acceptable levels for the conductivity of water in streams receiving discharge from permitted coal mining sites in a six-state area of Central Appalachia, including Kentucky and West Virginia. If such levels of conductivity are enforced as numerical limits, they could have a significant impact on our ability to secure Section 404 permits and have a material impact on our operations. The National Mining Association (NMA), on behalf of its member companies including coal producers such as ourselves, filed suit against the EPA and the COE contesting the legality of the enhanced review process and the imposition of such conductivity standard. The U.S. District Court for the District of Columbia granted the NMA’s motion for partial summary judgment and vacated the multi-criteria integrated resource assessment and the enhanced coordination process that were being applied to Section 404 permits. The court determined that in issuing the guidance, the EPA exceeded its statutory authority under the Clean Water Act. The court also determined those pronouncements to constitute legislative rules, and as such, to have been issued in violation of the Administrative Procedures Act because they were issued without public notice and an opportunity to submit comments. On July 31, 2012, the U.S. District Court for the District of Columbia issued its opinion on the remainder of the NMA’s complaint and overturned the EPA’s Final Guidance memorandum concerning conductivity of water in streams. The court held that the Final Guidance constituted final agency action and the EPA overstepped its authority under the Clean Water Act and SMCRA.

Environmental groups have recently filed lawsuits against multiple mining companies, including us, for alleged discharges of selenium in violation of applicable permit levels at coal mining sites. The lawsuits have been filed under the citizen suit provisions of the federal Clean Water Act. In the lawsuits, the environmental groups contend that the mining companies should install treatment facilities to limit the discharge of selenium and pay civil penalties for the alleged violations. Some of the cases have been resolved through settlements between the environmental groups and the mining companies. We currently do not believe that any lawsuit brought against us related to these matters will have a material impact on our operations.

For a discussion of the Clean Water Act, see Item 1 “Business – Environmental and Other Regulatory Matters” for discussion related to the Clean Water Act.

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

The SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of underground mining. We accrue for the costs of current mine disturbance and of final mine closure, including the cost of treating mine water discharge where necessary. Under U.S. generally accepted accounting principles we are required to account for the costs related to the closure of mines and the reclamation of the land upon exhaustion of coal reserves. The fair value of an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. 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 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.

Also, see “Critical Accounting Estimates – Reclamation and Mine Closure Obligation” for additional information regarding our accrued reclamation costs.

Our operations may adversely impact the environment which could result in material liabilities to us.

The processes required to mine coal may cause certain impacts or generate certain materials that might adversely affect the environment from time to time. The mining processes we use could cause us to 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 claim.

Certain coal that we mine needs to be cleaned at preparation plants, which generally requires coal refuse areas and/or slurry impoundments. Such areas and impoundments are subject to extensive regulation and monitoring. Slurry impoundments have been known to fail, releasing large volumes of coal slurry into nearby surface waters and property, resulting in damage to the environment and natural resources, as well as injuries to wildlife. We maintain coal refuse areas and slurry impoundments at a number of our mining complexes. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental impact and associated liability, as well as for fines and penalties.

Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as acid mine drainage (“AMD”). We include our estimated exposure for AMD in our accrued reclamation costs. 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.

These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to certain substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect us and could have a material adverse impact on our cash flows, results of operations or financial condition.

Foreign currency fluctuations could adversely affect the competitiveness of our coal abroad.

We rely on customers in other countries for a portion of our sales, with shipments to countries in North America, South America, Europe, Asia and Africa. We compete in these international markets against coal produced in other countries. Coal is sold internationally in United States dollars. As a result, mining costs in competing producing countries may be reduced in United States dollar terms based on currency exchange rates, providing an advantage to foreign coal producers. Currency fluctuations among countries purchasing and selling coal could adversely affect the competitiveness of our coal in international markets.

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 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. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers could cause 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. It is possible that any, or a combination, of these occurrences could have a material adverse effect on our business, financial condition and results of operations.

Risks Related to Our Operations

We have experienced operating losses in recent years and may experience losses in the future. 

We experienced operating losses in 2012 and 2011. We must continue to carefully manage our business, including the management of our contracts and our production costs. Although we seek to balance the open portion of our contracts to achieve optimal revenues over the long term, the market price of coal is affected by many factors that are outside of our control. We have experienced an increase in production costs in recent years. Our profitability in the future will be impacted by the price levels that we achieve on future long term contracts. Accordingly, we cannot assure you that we will be able to achieve profitability in the future.

The level of our indebtedness could adversely affect our ability to repay or refinance our existing debt and our financial condition and results of operations.

Our total consolidated long-term debt as of December 31, 2012 was $546.4 million (net of discounts on our convertible notes of $69.7 million).  Our level of indebtedness could result in the following:

Our operations may not generate sufficient cash to allow us to pay principal and interest on our existing debt or to refinance such debt as necessary, as they will be impacted by economic conditions and other factors, many of which are beyond our control. If we fail to make a payment on our debt, this could cause us to be in default on our outstanding indebtedness. If we fail to obtain financing in the future on favorable terms, it could have an adverse effect on our financial condition, results of operations and cash flows. In addition, we may incur additional indebtedness in the future, and, as a result, the related risks that we now face, including those described above, could intensify.

We may fail to realize the growth prospects and cost savings anticipated as a result of the IRP Acquisition.

The success of the April 2011 IRP Acquisition will depend, in part, on our ability to realize the anticipated business opportunities and growth prospects from combining our businesses with those of IRP. We may never realize these business opportunities and growth prospects. Integrating operations is complex and requires significant efforts and expenditures. Our management might have its attention diverted while trying to integrate operations and corporate and administrative infrastructures. We might experience increased competition that limits our ability to expand our business, and we might not be able to capitalize on expected business opportunities, including retaining current customers. If any of these factors limit our ability to integrate the operations successfully or on a timely basis, the expectations of future results of operations from the IRP Acquisition might not be met.

It is possible that the integration process could result in the loss of key employees, the disruption of each company’s ongoing businesses, tax costs or inefficiencies, or inconsistencies in standards, controls, information technology systems, procedures and policies, any of which could adversely affect our ability to maintain relationships with clients, employees or other third parties or our ability to achieve the anticipated benefits of the IRP Acquisition and could harm our financial performance.

The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.

In 2012, US Steel, Steel Authority of India Limited and Georgia Power Company were our largest customers, representing approximately 13%, 13%, and 12% of our total revenues, respectively. The execution of a substantial coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract. We could be materially adversely affected to the extent that we are unable to replace these expiring coal supply agreements with agreements providing similar profit margins.

Many of our coal supply agreements contain provisions that permit adjustment of the contract price upward or downward at specified times. Failure of the parties to agree on a price under those provisions may allow either party to either terminate the contract or reduce the coal to be delivered under the contract. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by the customer or us for the duration of specified events beyond the control of the affected party. Most coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as:

In some cases, failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. In addition, all of our contracts allow our customers to renegotiate or terminate their contracts in the event of changes in regulations or other governmental impositions affecting our industry that increase the cost of coal beyond specified limits. Further, we have been required in the past to make other pricing adjustments to comply with contractual requirements relating to the sulfur content of coal sold to our customers, and may be required to do so in the future.

The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustments and other provisions may increase our exposure to short term coal price volatility provided by those contracts.

Certain of our contracts are fixed in quantity but are priced on a quarterly or semi-annual basis. Our operating results are impacted by these changes in prices. A reduction in prices will result in a decrease to our profit margins.

In addition, our ability to receive payment for coal sold and delivered under these contracts depends on the continued creditworthiness of our customers. The bankruptcy of any of our customers could materially and adversely affect our financial position.

Our financial condition may be adversely affected if we are required by some of our customers or vendors to provide performance assurances for certain contracts.

Our customers and our vendors could require us to provide performance assurances if we experience a material adverse change or if they believe our creditworthiness has become unsatisfactory. Performance assurances are generally provided by the posting of a letter of credit, prepayment, cash collateral, other security, or a guaranty from a creditworthy guarantor. As of December 31, 2012 some electric utilities have required certain of our subsidiaries to post deposits or make twice-monthly payments. None of our customers have requested that we provide performance assurances. If we are required to post additional performance assurances on some or all of our contracts, there could be a material adverse impact on our cash flows, results of operations or financial condition.

Our operating results will be negatively impacted if we are unable to balance our mix of contract and spot sales.

We have implemented a sales plan that includes long term contracts (one year or greater) and spot sales/ short term contracts (less than one year). We have structured our sales plan based on the assumptions that demand will remain adequate to maintain current shipping levels and that any disruptions in the market will be relatively short-lived. If we are unable to maintain our planned balance of contract sales with spot sales, or our markets become depressed for an extended period of time, our volumes and margins could decrease, negatively affecting our operating results.

Our ability to operate our company effectively could be impaired if we lose senior executives or fail to employ needed additional personnel.

The loss of senior executives could have a material adverse effect on our business. There may be a limited number of persons with the requisite experience and skills to serve in our senior management positions. We may not be able to locate or employ qualified executives on acceptable terms. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. We might not continue to be able to employ key personnel, or to attract and retain qualified personnel in the future. Failure to retain senior executives or attract key personnel could have a material adverse effect on our operations and financial results.

Underground mining is subject to increased regulation, and may require us to incur additional cost.

Underground coal mining is subject to ever increasing federal and state regulatory control relating to mine safety and health and to ever increasing enforcement activities intended to compel compliance with such laws and regulations. Within the last few years the industry has seen enactment of the federal MINER Act and subsequent additional legislation and regulation imposing significant new safety initiatives and the Dodd-Frank Act imposing new mine safety information reporting requirements. Various states also have enacted their own new laws and regulations imposing additional requirements related to mine safety. These new laws and regulations have and will continue to cause us to incur substantial additional costs, which will adversely impact our operating performance.

The U.S. Department of Labor, Mine Safety and Health Administration (MSHA), periodically notifies certain coal mines that a potential pattern of violations may exist based upon an initial statistical screening of violation history and pattern criteria review by MSHA. In the past, certain of our mines have received notices that a potential pattern of violations might exist. Upon receipt of such a notification, we conduct a comprehensive review of the operation that received the notification and prepare and submit to MSHA a plan designed to enhance employee safety at the mine through better education, training, mining practices, and safety management. Following implementation of the plan, MSHA conducts a complete inspection of the mine and further evaluates the situation and then advises the operator whether a Pattern of Violation (POV) exists and whether further action will be taken. The failure to remediate the situation resulting in a finding that a POV does exist at a mine could have a significant impact on our operations, including the permanent or temporary closure of our mines.

On April 12, 2011, MSHA notified our subsidiary Bledsoe Coal Corporation that a POV exists at its Abner Branch Rider Mine.   As a result, if MSHA finds any violation of a mandatory health or safety standard that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard, MSHA shall require all persons in the areas affected by such violation, except those persons referred to in Section 104(c) of the Mine Act, to be withdrawn from, and to be prohibited from entering such area until MSHA determines the violation has been abated.  A POV can be terminated when 1) an inspection of the entire mine is completed and no significant and substantial health or safety violations are found, or 2) no withdrawal order is issued by MSHA in accordance with Section 104(e)(1) of the Mine Act within 90 days of the issuance of the pattern notice. On November 30, 2012 we idled the Abner Branch mine due to market conditions.

In 2010, a U.S. House of Representatives committee approved a mine safety bill which would give MSHA additional powers to temporarily close mines, mandate additional safety training and impose larger penalties on companies and their executives. A comparable bill introduced in the US Senate failed to receive the necessary votes for passage. If reintroduced and subsequently enacted, this or a similar bill could further increase our costs and impact operating performance.

Unexpected decreases in availability of raw materials or increases in raw material costs could significantly impair our operating results.

Our operations are dependent on reliable supplies of mining equipment, replacement parts, explosives, diesel fuel, tires, magnetite and steel-related products (including roof bolts). If the cost of any mining equipment or key supplies increases significantly, or if they should become unavailable due to higher industry-wide demand or less production by suppliers, there could be an adverse impact on our cash flows, results of operations or financial condition.

Coal mining is subject to conditions or events beyond our control, which could cause our quarterly or annual results to deteriorate.

Our coal mining operations are conducted in underground and surface mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production and the cost of mining at particular mines for varying lengths of time and have a significant impact on our operating results. These conditions or events have included:

Mining in Central Appalachia is complex due to geological characteristics of the region.

The geological characteristics of coal reserves in Central Appalachia, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. In addition, as compared to mines in other regions permitting, licensing and other environmental and regulatory requirements are more costly and time consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and customers’ ability to use coal produced by, operators in Central Appalachia, including us.

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

Our recoverable reserves decline as we produce coal. Since we attempt, where practical, to mine our lowest-cost reserves first, we may not be able to mine all of our reserves at a similar cost as we do at our current operations. Our planned development and exploration projects might not result in significant additional reserves, and we might not have continuing success developing additional mines. For example, our construction of additional mining facilities necessary to exploit our reserves could be delayed or terminated due to various factors, including unforeseen geological conditions, weather delays or unanticipated development costs. Our ability to acquire additional coal reserves in the future also could be limited by restrictions under our existing or future debt facilities, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

In order to develop our reserves, we must receive various governmental permits. We have not yet applied for the permits required or developed the mines necessary to mine all of our reserves. In addition, we might not continue to receive the permits necessary for us to operate profitably in the future. We may not be able to negotiate new leases from the government or from private parties or obtain mining contracts for properties containing additional reserves or maintain our leasehold interests in properties on which mining operations are not commenced during the term of the lease.

We face significant uncertainty in estimating our recoverable coal reserves, and variations from those estimates could lead to decreased revenues and profitability.

Forecasts of our future performance are based on estimates of our recoverable coal reserves. Estimates of those reserves initially were based on studies conducted by Marshall Miller & Associates, Inc. in 2004 for our CAPP reserves at that time, 2010 for the CAPP reserved acquired from IRP and 2005 and 2006 for our Midwest reserves in accordance with industry-accepted standards which we have updated for current activity using similar methodologies. A number of sources of information were used to determine recoverable reserves estimates, including:

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

Therefore, actual coal tonnage recovered from identified reserve areas or properties, and costs associated with our mining operations, may vary from estimates. These variations could be material, and therefore could result in decreased profitability.

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

We conduct substantially all of our mining operations on properties that we lease. The loss of any lease could adversely affect our ability to mine the associated reserves. Because we generally do not obtain title insurance or otherwise verify title to our leased properties, our right to mine some of our reserves has been in the past, and may again in the future be, adversely affected if defects in title or boundaries exist. In order to obtain leases or rights to conduct our mining operations on property where these defects exist, we have had to, and may in the future have to, incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases for properties containing additional reserves. Some leases have minimum production requirements. 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.

Factors beyond our control could impact the amount and pricing of coal supplied by our independent contractors and other third parties.

In addition to coal we produce from our Company-operated mines, we have mines that typically are operated by independent contract mine operators, and we purchase coal from third parties for resale. For 2013, we anticipate approximately 15% of our total production will come from mines operated by independent contract mine operators and from third party purchased coal sources. Operational difficulties, changes in demand for contract mine operators from our competitors and other factors beyond our control could affect the availability, pricing and quality of coal produced for us by independent contract mine operators. Disruptions in supply, increases in prices paid for coal produced by independent contract mine operators or purchased from third parties, or the availability of more lucrative direct sales opportunities for our purchased coal sources could increase our costs or lower our volumes, either of which could negatively affect our profitability.

Our operations could be adversely affected if we are unable to obtain required surety bonds.

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation and to satisfy other miscellaneous obligations. Certain insurance companies have informed us, along with other participants in the coal industry, that they no longer will provide surety bonds for workers’ compensation and other post-employment benefits without collateral. We have satisfied our obligations under these statutes and regulations by providing letters of credit, cash collateral or other assurances of payment. However, letters of credit can be significantly more costly to us than surety bonds. The issuance of letters of credit under our Revolver also reduces amounts that we can borrow under our Revolver. If we are unable to secure surety bonds for these obligations in the future, and are forced to secure letters of credit indefinitely, our profitability may be negatively affected. On May 1, 2012, the Federal Office of Surface Mining Reclamation notified the state of Kentucky that it believes Kentucky’s bonding program is insufficient. The resolution of this issue could cause bonding costs for new or existing operations to increase.

Our work force could become unionized in the future, which could adversely affect the stability of our production and reduce our profitability.

Our company owned mines are currently operated by union-free employees. However, our subsidiaries’ employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. Any unionization of our subsidiaries’ employees, or the employees of third-party contractors who mine coal for us, could adversely affect the stability of our production and reduce our profitability. The current administration has indicated that it will support legislation that may make it easier for employees to unionize.

We have significant unfunded obligations for long-term employee benefits for which we accrue based upon assumptions, which, if incorrect, could result in us being required to expend greater amounts than anticipated.

We are required by law to provide various long term employee benefits. We accrue amounts for these obligations based on the present value of expected future costs. We employed an independent actuary to complete estimates for our workers’ compensation and black lung (both state and federal) obligations.

We use a valuation method under which the total present and future liabilities are booked based on actuarial studies. Our independent actuary updates these liability estimates annually. However, if our assumptions are incorrect, we could be required to expend greater amounts than anticipated. All of these obligations are unfunded. In addition, the federal government and the governments of the states in which we operate consider changes in workers’ compensation laws from time to time. Such changes, if enacted, could increase our benefit expenses and payments.

See “Critical Accounting Estimates – Workers’ Compensation and Coal Miners’ Pneumoconiosis” for additional information regarding our workers’ compensation and black lung obligations.

We may be unable to adequately provide funding for our pension plan obligations based on our current estimates of those obligations.

We provide benefits under a defined benefit pension plan that was frozen in 2007. If future payments are insufficient to fund the pension plan adequately to cover our future pension obligations, we could incur cash expenditures and costs materially higher than anticipated. The pension obligation is calculated annually and is based on several assumptions, including then prevailing conditions, which may change from year to year. In any year, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated.

See “Critical Accounting Estimates – Defined Benefit Pension” for additional information regarding our pension plan obligations.

Substantially all of our assets are subject to security interests.

Substantially all of our cash, receivables, inventory and other assets are subject to various liens and security interests under our debt instruments. If one of these security interest holders becomes entitled to exercise its rights as a secured party, it would have the right to foreclose upon and sell, or otherwise transfer, the collateral subject to its security interest, and the collateral accordingly would be unavailable to us and our other creditors, except to the extent, if any, that other creditors have a superior or equal security interest in the affected collateral or the value of the affected collateral exceeds the amount of indebtedness in respect of which these foreclosure rights are exercised.

We may be unable to comply with restrictions imposed by the terms of our indebtedness, which could result in a default under these instruments.

Our debt instruments impose a number of restrictions on us. A failure to comply with these restrictions could adversely affect our ability to borrow under our Revolver or result in an event of default under our other debt instruments. Our Revolver contains financial covenants that require us to maintain a minimum Consolidated Fixed Charge Coverage Ratio and limits on our capital expenditures.

The Consolidated Fixed Charge Coverage Ratio covenant under our Revolver is only applicable if the sum of our unrestricted cash plus our availability under our Revolver falls below $35 million and would remain in effect until the sum of our unrestricted cash and availability under our Revolver exceeds $35 million for 90 consecutive days. If measured, we do not project that our actual Consolidated Fixed Charge Coverage Ratio during 2013 would meet the minimum Consolidated Fixed Charge Coverage Ratio required by the Revolver of 1.10 to 1.00.  Our Revolver limits the capital expenditures that we may make or agree to make in any fiscal year, but such limitation only will apply if the sum of our unrestricted cash plus our availability under our Revolver falls below $50 million for a period of 5 consecutive days and would remain in effect until the sum of our unrestricted cash and availability under our Revolver exceeds $50 million for 90 consecutive days. As of December 31, 2012, our unrestricted cash was $127.4 million and the unused availability under our Revolver was $8.5 million. 

Additional detail regarding the terms of our Revolver, including these covenants and the related definitions, can be found in our debt agreements, as amended, that have been filed as exhibits to our SEC filings.

In the event of a default, our lenders could terminate their commitments to us and declare all amounts borrowed, together with accrued interest and fees, immediately due and payable. If this were to occur, we might not be able to pay these amounts or we might be forced to seek amendments to our debt agreements which could make the terms of these agreements more onerous for us and require the payment of amendment or waiver fees. Failure to comply with these restrictions, even if waived by our lenders, also could adversely affect our credit ratings, which could increase our costs of debt financings and impair our ability to obtain additional debt financing. While the lenders have, to date, waived any covenant violations and amended the covenants, there is no guarantee they will continue to do so if future violations occur.

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, more restrictive covenants and the extension of less open credit. This, in turn, could affect our internal cost of capital estimates and therefore impact operational decisions.

Inability to satisfy contractual obligations may adversely affect our profitability.

From time to time, we have disputes with our customers over the provisions of long term contracts relating to, among other things, coal quality, pricing, quantity and delays in delivery. In addition, we may not be able to produce sufficient amounts of coal to meet our commitments to our customers. Our inability to satisfy our contractual obligations could result in our need to purchase coal from third party sources to satisfy those obligations or may result in customers initiating claims against us. We may not be able to resolve all of these disputes in a satisfactory manner, which could result in substantial damages or otherwise harm our relationships with customers.

We may be unable to exploit opportunities to diversify our operations.

Our future business plan may consider opportunities other than underground and surface mining in eastern Kentucky, southern West Virginia and southern Indiana. We may consider opportunities to expand both surface and underground mining activities in areas that are outside of eastern Kentucky, southern West Virginia and southern Indiana. We may also consider opportunities in other energy-related areas that are not prohibited by our debt instruments. If we undertake these diversification strategies and fail to execute them successfully, our financial condition and results of operations may be adversely affected.

There are risks associated with our acquisition strategy, including our inability to successfully complete acquisitions, our assumption of liabilities, dilution of your investment, significant costs and additional financing required.

We may explore opportunities to expand our operations through strategic acquisitions of other coal mining companies. Risks associated with our current and potential acquisitions, including the recent acquisition of IRP, include the disruption of our ongoing business, problems retaining the employees of the acquired business, assets acquired proving to be less valuable than expected, the potential assumption of unknown or unexpected liabilities, costs and problems, the inability of management to maintain uniform standards, controls, procedures and policies, the difficulty of managing a larger company, the risk of becoming involved in labor, commercial or regulatory disputes or litigation related to the new enterprises and the difficulty of integrating the acquired operations and personnel into our existing business.

We may choose to use shares of our common stock or other securities to finance a portion of the consideration for future acquisitions, either by issuing them to pay a portion of the purchase price or selling additional shares to investors to raise cash to pay a portion of the purchase price. If shares of our common stock do not maintain sufficient market value or potential acquisition candidates are unwilling to accept shares of our common stock as part of the consideration for the sale of their businesses, we will be required to raise capital through additional sales of debt or equity securities, which might not be possible, or forego the acquisition opportunity, and our growth could be limited. In addition, securities issued in such acquisitions may dilute the holdings of our current or future shareholders.

Our currently available cash may not be sufficient to finance any additional acquisitions.

We believe that our cash on hand, the availability under our Revolver and cash generated from our operations may not provide sufficient cash to fund any future acquisitions. Accordingly, we may need to conduct additional debt or equity financings in order to fund any such additional acquisitions, unless we issue shares of our common stock as consideration for those acquisitions. If we are unable to obtain any such financings, we may be required to forego future acquisition opportunities.

Surface mining is subject to increased regulation, and may require us to incur additional costs.

Surface mining is subject to numerous regulations related, among others, to blasting activities that can result in additional costs. For example, when blasting in close proximity to structures, additional costs are incurred in designing and implementing more complex blast delay regimens, conducting pre-blast surveys and blast monitoring, and the risk of potential blast-related damages increases. Since the nature of surface mining requires ongoing disturbance to the surface, environmental compliance costs can be significantly greater than with underground operations. In addition, the COE imposes stream mitigation requirements on surface mining operations. These regulations require that footage of stream loss be replaced through various mitigation processes, if any ephemeral, intermittent, or perennial streams are filled due to mining operations. In 2008, the U.S. Department of Interior’s Office of Surface Mining imposed regulatory requirements applicable to excess spoil placement, including the requirement that operators return as much spoil as possible to the excavation created by the mine. These regulations may cause us to incur significant additional costs, which could adversely impact our operating performance.

We are subject to various legal proceedings, which may have an adverse effect on our business.

We are party to a number of legal proceedings incidental to our normal business activities, including a large number of workers’ compensation claims. While we cannot predict the outcome of the proceedings, there is always the potential that the costs of defending litigation in an individual matter or the aggregation of many matters could have an adverse effect on our cash flows, results of operations or financial position.

Our ability to use net operating loss carryforwards may be subject to limitation

Section 382 of the U.S. Internal Revenue Code of 1986, as amended, imposes an annual limit on the amount of net operating loss carryforwards that may be used to offset taxable income when a corporation has undergone significant changes in its stock ownership or equity structure. Our ability to use net operating losses is limited by prior changes in our ownership, and may be further limited by issuances of common stock, in connection with the conversion of the existing convertible senior notes or by the consummation of other transactions. As a result, as we earn net taxable income, our ability to use net operating loss carryforwards to offset U.S. federal taxable income may become subject to limitations, which could potentially result in increased future tax liabilities for us.

Changes in federal or state income tax laws, particularly in the area of percentage depletion, could cause our financial position and profitability to deteriorate.

The federal government has been reviewing the income tax laws relating to the coal industry regarding percentage depletion benefits. If the percentage depletion tax benefit was reduced or eliminated, our cash flows, results of operations or financial condition could be materially impacted.

Risks Relating to our Common Stock

The market price of our common stock has been volatile and difficult to predict, and may continue to be volatile and difficult to predict in the future, and the value of your investment may decline.

The market price of our common stock has been volatile in the past and may continue to be volatile in the future. The market price of our common stock will be affected by, among other things:

Any of these factors could have a negative effect on the price of our common stock on the Nasdaq Global Select Market, make it difficult to predict the market price for our common stock in the future and cause the value of your investment to decline. 

We do not intend to pay cash dividends on our common stock in the foreseeable future.

We do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, covenants in our Revolver and our 2019 Senior Notes restrict our ability to pay cash dividends and may prohibit the payment of dividends and certain other payments.

Provisions of our articles of incorporation, bylaws and shareholder rights agreement could discourage potential acquisition proposals and could deter or prevent a change in control.

Some provisions of our articles of incorporation and bylaws, as well as Virginia statutes, may have the effect of delaying, deferring or preventing a change in control. These provisions may make it more difficult for other persons, without the approval of our Board of Directors, to make a tender offer or otherwise acquire substantial amounts of our common stock or to launch other takeover attempts that a shareholder might consider to be in such shareholder’s best interest. These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock.

We have a shareholder rights agreement which, in certain circumstances, including a person or group acquiring, or the commencement of a tender or exchange offer that would result in a person or group acquiring, beneficial ownership of more than 20% of the outstanding shares of our common stock, would entitle each right holder, other than the person or group triggering the plan, to receive, upon exercise of the right, shares of our common stock having a then-current fair value equal to twice the exercise price of a right.

This shareholder rights agreement provides us with a defensive mechanism that decreases the risk that a hostile acquirer will attempt to take control of us without negotiating directly with our Board of Directors. The shareholder rights agreement may discourage acquirers from attempting to purchase us, which may adversely affect the price of our common stock.

Item 1B.        Unresolved Staff Comments

None.

Item 2.          Properties

As of December 31, 2012, we owned approximately 14,100 acres of land. Our mineral rights are primarily controlled through leases. In a mining context, control of a property is typically divided into three categories:

Our rights with respect to properties that we lease vary from lease to lease, but encompass mineral rights, surface rights, or both.

The coal properties that we control in Central Appalachia are located primarily in eastern Kentucky and southern West Virginia. The coal properties that we control in the Midwest are part of the Illinois Coal basin and are located in southwest Indiana.

The terms of our leases can vary significantly, including the following provisions:

Our leases typically provide for periodic royalty payments, subject to specified annual minimums. The annual minimums are typically based on the forecasted tonnage of coal to be produced on the leased property over the term of the lease. Payments made pursuant to these minimums for years in which periodic royalty payments do not meet the minimums are typically recoupable against future periodic production royalties paid within a fixed period of time. We typically are responsible for the payment of property taxes due on the properties we have under lease.

For a discussion of our coal reserves see Item 1 Business “Reserves.”

Our corporate headquarters is located at 901 E. Byrd Street, Richmond, Virginia and is occupied pursuant to a lease that expires in 2014.

Item 3.          Legal Proceedings

We are parties to a number of legal proceedings incidental to our normal business activities, including a large number of workers’ compensation claims. While we cannot predict the outcome of these proceedings, in our opinion, any liability arising from these matters individually and in the aggregate should not have a material adverse effect on our consolidated financial position, cash flows or results of operations.

Item 4.          Mine Safety Disclosures

Information concerning mine safety and health violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this report.

PART II

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

Market Information

Our common stock trades on the Nasdaq Global Select Market under the ticker symbol “JRCC”. The table below sets forth the high and low closing sales prices for our common stock for the periods indicated, as reported by Nasdaq.

Recent Sales or Purchases of Unregistered Securities

We did not sell or purchase any unregistered securities during 2012.

Holders

As of December 31, 2012, there were 153 record holders of our common stock.

Dividends

We did not pay any cash dividends on our common stock during the years ended December 31, 2012, 2011 or 2010. We do not anticipate paying cash dividends in the foreseeable future. Any future determination as to the payment of cash dividends will depend upon such factors as earnings, capital requirements, our financial condition, restrictions in financing agreements and other factors deemed relevant by the Board of Directors. In addition, covenants in our Revolver and our 2019 Senior Notes restrict our ability to pay cash dividends and may prohibit the payment of dividends and certain other payments.

Securities Authorized for Issuance under Equity Compensation Plans

Please refer to note 7 of our December 31, 2012 consolidated financial statements for securities authorized to be issued under our 2004 and 2012 Equity Incentive Plans.

Stock Performance Graph

Set forth below is a line graph comparing the percentage change in the cumulative total shareholder return of James River Coal Company’s Common Stock against the cumulative total return of the NASDAQ Composite Index and the Dow Jones U.S. Coal Index on a quarterly basis for the period commencing on December 31, 2007 and ending on December 31, 2012. You are cautioned against drawing any conclusions from the data contained in this graph, as past results are not necessarily indicative of future performance.  The indices used are included for comparative purposes only and do not indicate an opinion of management that such indices are necessarily an appropriate measure of the relative performance of our stock.

Prepared by Zacks Investment Research, Inc. Used with permission. All rights reserved. Copyright 1980-2013

Index Data: Copyright NASDAQ OMX, Inc. Used with permission. All rights reserved.

Index Data: Copyright Dow Jones, Inc. Used with permission. All rights reserved.

Item 6.          Selected Financial Data

The following table presents our selected consolidated financial and operating data as of and for each of the periods indicated. The selected consolidated financial data is derived from our audited consolidated financial statements. The selected consolidated financial and operating data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes.

On April 18, 2011, we acquired International Resource Partners LP and its subsidiary companies (collectively IRP). Our financial position and supplemental operating data prior to 2011 and our results of operations for the years ended December 31, 2010, 2009 and 2008 do not include the financial results for IRP.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the accompanying notes and "Selected Financial Data" included elsewhere in this filing. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements as a result of numerous factors, including the risks discussed in "Risk Factors" in this filing. For more on forward looking statements, see the section entitled “Forward Looking Statements” at the beginning of this report.

Overview

We mine, process and sell thermal and metallurgical coal through eight active mining complexes located throughout eastern Kentucky, southern West Virginia and southern Indiana. The majority of our metallurgical coal was obtained in the April 18, 2011 acquisition (the IRP Acquisition) of International Resource Partners LP and its subsidiary companies (collectively IRP).  We have two reportable business segments based on the coal basins in which we operate (Central Appalachia (CAPP) and the Midwest (Midwest)).   IRP is included in our CAPP segment.  We derived 44% of our total revenues in 2012 from coal sales to electric utility customers and the remaining 56% from coal sales (including metallurgical coal) to industrial and other customers. In 2012, our mines produced 9.5 million tons of coal (including 0.4 million tons of contract coal) and we purchased another 2.0 million tons for resale. Of the 9.5 million tons produced from Company mines, approximately 64% came from underground mines, while the remaining 36% came from surface mines. In 2012, we generated total revenues of $1.1 billion and had a net loss of $138.9 million.  

CAPP Segment

In Central Appalachia, our thermal coal sales are primarily to customers in the southern portion of the South Atlantic region of the United States.  The South Atlantic Region includes the states of Florida, Georgia, South Carolina, North Carolina, West Virginia, Virginia, Maryland and Delaware. Our metallurgical coal is sold primarily to steel companies in North America, South America, Europe, Asia and Africa. Approximately 41% of our total revenues in the CAPP segment in 2012 were derived from sales made outside the United States, including Brazil, Canada, Egypt, France, Germany, India and the United Kingdom.  In 2012, our CAPP mines produced 7.2 million tons of coal (including 0.4 million tons of contract coal) and we purchased another 2.0 million tons for resale. Of the 7.2 million tons produced from CAPP company mines, 76% came from Company operated underground mines. In 2012, we shipped 9.4 million tons of coal and generated coal sale revenues of $915.4 million from our CAPP segment. In 2012, US Steel, Steel Authority of India Limited and Georgia Power Company were our largest customers, representing approximately 13%, 13%, and 12% of our total revenues, respectively. No other CAPP customer accounted for more than 10% of our total revenues.

As of December 31, 2012, we estimate that we controlled approximately 299.7 million tons of proven and probable coal reserves in our CAPP segment. Based on our most recent analysis prepared by Marshall Miller & Associates, Inc. (“MM&A”) as of March 31, 2004 and December 31, 2010, we estimate that these reserves have an average heat content of 13,200 Btu per pound and an average sulfur content of 1.2%. At current production levels, we believe these reserves would support more than 30 years of production.

Midwest Segment

In the Midwest, the majority of our coal is sold in the East North Central Region, which includes the states of Illinois, Indiana, Ohio, Michigan and Wisconsin. In 2012, our Midwest mines produced approximately 2.3 million tons of coal. Of the Midwest tons produced, 71% came from Company operated surface mines. In 2012, we shipped 2.3 million tons of coal and generated coal sale revenues of $103.1 million from our Midwest segment. No Midwest customer accounted for more than 10% of our total revenues.

As of December 31, 2012, we estimate that we controlled approximately 42.0 million tons of proven and probable coal reserves in our Midwest segment. Based on our most recent analyses prepared by MM&A as of February 1, 2005 and April 11, 2006, we estimate that these reserves have an average heat content of 12,000 Btu per pound and average sulfur content of 3.2%. At current production levels, we believe these reserves would support more than 15 years of production.

Reserves

MM&A prepared a detailed study of our CAPP reserves as of March 31, 2004 based on all of our geologic information, including our updated drilling and mining data.  MM&A also prepared a detailed study as of December 31, 2010 for the reserves obtained in the IRP Acquisition (which was based in part on previous evaluations of the properties).  For our Midwest reserves, MM&A prepared a detailed study as of February 1, 2005 for the reserves obtained in the acquisition of Triad Mining, Inc. and as of April 11, 2006 for certain additional reserves acquired in the second quarter of 2006 in the Midwest.  The MM&A studies were planned and performed to obtain reasonable assurance of the subject demonstrated reserves.  In connection with the studies, MM&A prepared reserve maps and had certified professional geologists develop estimates based on data supplied by us, Triad and IRP using standards accepted by government and industry.  We have used MM&A’s March 31, 2004 study of the CAPP reserves and the December 31, 2010 study of the reserves acquired from IRP as the basis for our current internal estimate of our CAPP reserves and MM&A’s February 1, 2005 and April 11, 2006 studies as the basis for our current internal estimate of our Midwest reserves.

Reserves for these purposes are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.  The reserve estimates were prepared using industry-standard methodology to provide reasonable assurance that the reserves are recoverable, considering technical, economic and legal limitations.  Although MM&A has reviewed our reserves and found them to be reasonable (notwithstanding unforeseen geological, market, labor or regulatory issues that may affect the operations), MM&A’s engagement did not include performing an economic feasibility study for our reserves.  In accordance with standard industry practice, we have performed our own economic feasibility analysis for our reserves.  It is not generally considered to be practical, however, nor is it standard industry practice, to perform a feasibility study for a company’s entire reserve portfolio.  In addition, MM&A did not independently verify our control of our properties, and has relied solely on property information supplied by us.  Reserve acreage, average seam thickness, average seam density and average mine and wash recovery percentages were verified by MM&A to prepare a reserve tonnage estimate for each reserve.  There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves as discussed in “Critical Accounting Estimates – Coal Reserves”.

Based on the MM&A reserve studies and the foregoing assumptions and qualifications, and after giving effect to our operations from the respective dates of the studies through December 31, 2012, we estimate that, as of December 31, 2012, we controlled approximately 299.7 million tons of proven and probable coal reserves in the CAPP region and 42.0 million tons in the Midwest region. The following table provides additional information regarding changes to our reserves for the year ended December 31, 2012 (in millions of tons):

Key Performance Indicators

We manage our business through several key performance metrics that provide a summary of information in the areas of sales, operations, and general and administrative costs.

In the sales area, our long-term metrics are the volume-weighted average remaining term of our contracts and our open contract position for the next several years. During periods of high prices, we may seek to lengthen the average remaining term of our contracts and reduce the open tonnage for future periods. In the short-term, we closely monitor the Average Selling Price per Ton (ASP), and the mix between our spot sales and contract sales.

In the operations area, we monitor the volume of coal that is produced by each of our principal sources, including company mines, contract mines, and purchased coal sources. For our company mines, we focus on both operating costs and operating productivity. We closely monitor the cost per ton of our mines against our budgeted costs and against our other mines.

EBITDA and Adjusted EBITDA are also measures used by management to measure operating performance. We define EBITDA as net income (loss) plus interest expense (net), income tax expense (benefit) and depreciation, depletion and amortization. We regularly use EBITDA to evaluate our performance as compared to other companies in our industry that have different financing and capital structures and/or tax rates. In addition, we use EBITDA in evaluating acquisition targets. EBITDA is not a recognized term under U.S generally accepted accounting principles (US GAAP) and is not an alternative to net income, operating income or any other performance measures derived in accordance with US GAAP or an alternative to cash flow from operating activities as a measure of operating liquidity.  Adjusted EBITDA is used in calculating compliance with our debt covenants and adjusts EBITDA for certain items as defined in our debt agreements, including stock compensation, acquisition costs and certain bank fees.

Trends and Uncertainties In Our Business

Coal prices continue to suffer from a mixture of lower natural gas prices, increased government regulation and the global economic slowdown.

Historically low natural gas prices have increased natural gas’ share of electricity production. Production of natural gas from non-traditional shale sources has resulted in growing natural gas inventories and lower prices. In recent months, the price of natural gas has rebounded from its April 2012 low of $1.95 per MMBtu to an average of $3.34 per MMBtu in December 2012. The U.S. Energy Information Administration (EIA) estimates that the 2013 average natural gas spot price will be $3.68 per MMBtu. By comparison, the average spot price for natural gas in 2008 was $8.86 per MMBtu.

Natural gas prices are expected to increase due to reductions in the number of natural gas rigs operating, which was 417 as of December 7, 2012, compared to 811 at the beginning of 2012, curbed production from less-profitable “dry” natural gas wells, and increased consumption in the eastern part of the United States where a more normal winter is expected after an unseasonably warm 2011 – 2012 winter.

The EIA forecasts that the year-over-year gains for natural gas’ share of electricity generation should slow and then reverse as higher natural gas prices, along with record coal inventories, encourage utilities to increase their utilization of coal-fired power plants. Coal’s share of electricity generation is forecasted to rise by 5% in 2013, in comparison to a 10.4% decline for natural gas. Nonetheless, use of natural gas for power generation will remain high by historical standards.

The weakness in the U.S. domestic coal market has been partially offset by strong U.S. coal exports. According to the EIA, in 2011, the U.S. exported 107 million short tons of coal, the highest since 1991, and is forecasted to have exported 124 million short tons in 2012. The EIA expects 2013 exports to decline but remain above 100 million short tons.

The Central Appalachia region, which accounts for all of our shipments to international markets, has been the primary beneficiary of the export market, largely due to Central Appalachia’s production of metallurgical coal. While we anticipate that the demand for metallurgical coal will continue to be strong in the future, recent uncertainty in Europe and slowing economies in China, India and Brazil have reduced near-term pricing and demand.

In response to the lower prices and weaker demand for both steam and metallurgical coal, a number of publicly traded Central Appalachia producers have announced production cuts and layoffs. Because the Central Appalachia production market is fragmented with numerous small operators, it is difficult to quantify the total of Central Appalachia production cuts. To address the weak market for coal, we have managed our production by idling five underground mines, two preparation plants and one load out and reducing production at three surface mines. These and previous changes will reduce our annual production capacity by 3 million tons and impact approximately 400 employees and contractors.

In addition to coal prices and demand, our profitability is affected by our production costs, which have increased in recent years.  We expect the higher costs to continue for the next several years, due to a number of factors, including increased governmental regulations, high prices in worldwide commodity markets, and a highly competitive market for a limited supply of skilled mining personnel. See Item 1A “Risk Factors” for additional information on factors beyond our control that could affect our production costs.

Results of Operations

Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011

The following table shows selected operating results for 2012 and 2011 (in thousands, except per ton amounts):

Volume and Revenues by Segment

The following tables show volume and revenue information by segment (in thousands, except per ton amounts). 

Total tons shipped decreased by 1% in 2012 as compared to 2011.   In the CAPP and Midwest region steam coal shipments decreased by 19% and 6%, respectively, which was attributed to lower demand. In the CAPP region metallurgical coal shipments increased 68% in 2012 as compared to 2011 primarily due to the increase in metallurgical coal shipments that resulted from the IRP acquisition in April 2011. Coal sales revenue decreased 8% in 2012 as compared to 2011. The decrease in coal sales revenue was primarily related to a lower average sales price in the CAPP region for both steam and metallurgical coal.

Freight and handling revenue consists of shipping and handling costs invoiced to coal customers and paid to third-party carriers. These revenues are directly offset by freight and handling costs.

Operating and Other Costs

The following tables show selected costs in total and by segment (in thousands, except per ton amounts).

Our cost per ton of coal sold in the CAPP region increased from $87.07 per ton in the 2011 to $87.36 per ton in the 2012 period.  Overall, there was an increase in the cost per ton of our steam coal operations which was offset by a decrease in the per ton costs of our metallurgical coal operations in 2012 as compared to 2011. The cost per ton was also impacted by an increase in metallurgical coal shipments during 2012 as compared to 2011. Our steam coal operations were responsible for 65% and 72% of total production in 2012 and 2011, respectively. Our steam coal operations’ costs increased $2.05 per ton in 2012 as compared to 2011. The increase in the steam coal operations’ costs includes a $2.07 per ton increase in labor costs and a $1.01 per ton increase in trucking and preparation costs, offset by a reduction in sales related costs of $1.34 per ton. Our metallurgical coal operations were responsible for 35% and 28% of total production in 2012 and 2011, respectively. Our metallurgical operations’ costs decreased by $7.47 per ton, which is primarily due to a decrease in the price of purchased metallurgical coal. Our costs continue to be impacted by lower productivity due to increased federal and state regulatory scrutiny, a decrease in tons produced in response to market conditions and an increase in commodity prices.  For more detail regarding the increased regulatory activity see “Part II – Item 1A – Risk Factors – Underground mining is subject to increased regulation, and may require us to incur additional cost.”

Our cost per ton of coal sold in the Midwest increased $0.98 per ton to $38.85 per ton in the 2012 as compared to 2011.  The major components of this increase include an increase in variable costs of $0.61 per ton and labor and benefit costs of $0.99 per ton offset by a decrease in trucking costs of $0.93 per ton.

Freight and handling costs

Freight and handling costs increased due to a higher volume of metallurgical shipments in 2012 as compared to the same period in 2011. The Company had no metallurgical shipments prior to the IRP Acquisition in April 2011.

Depreciation, depletion and amortization

Depreciation, depletion and amortization increased from $108.9 million in 2011 to $131.8 million in 2012.  In 2012 the CAPP region, depreciation, depletion and amortization increased $20.1 million to $116.6 million as compared to 2011, which is due to the increase in the asset base as a result of the IRP Acquisition offset by $7.9 million decrease in amortization on contracts acquired from IRP.  In the Midwest, depreciation, depletion and amortization increased $2.7 million to $15.1 million which is primarily due to a higher asset base on buildings, machinery and equipment in the 2012 period as compared to 2011.  

Selling, general and administrative

Selling, general and administrative expenses increased from $57.1 million in the 2011 period to $59.9 million in the 2012 period, which is primarily due to increased selling, general and administrative expenses as a result of the IRP Acquisition in April 2011.

Goodwill impairment.

In 2012, the goodwill associated with our Midwest segment was determined to be impaired and the full amount was expensed. See Item 15 of Part IV, “Financial Statements — Note 3 — Goodwill Impairment.”

Acquisition costs

In 2011, costs of $8.5 million were incurred related to the IRP Acquisition.

Interest Expense

Interest expense increased from $50.1 million in 2011 to $52.7 million in 2012. The increase was the result of the issuance of our 2018 Convertible Senior Notes and 2019 Senior Notes in March 2011, offset by the redemption in full of our 2012 Senior Notes in June 2011 and the reduction of interest as the result of our $61.3 million repurchases of our outstanding debt in 2012. These debt transactions are described below in Liquidity and Capital Resources. Interest expense for 2012 and 2011 includes $16.9 million and $14.7 million, respectively, related to the amortization of debt discounts and debt issuance costs.

Income Taxes

Our effective tax rate in 2012 was (0.3%) and our effective tax rate in 2011 was (61.9%).  

For 2012, our effective income tax rate was impacted primarily by the amount of the valuation allowance recorded.

For 2011, our effective income tax rate was impacted primarily by a valuation allowance and the effects of percentage depletion. In 2011, in connection with the completion of our forecasts which considered the decline in coal prices and market demand that occurred towards the end of 2011, and after weighing all positive and negative evidence, we concluded that it was not more likely than not to realize a portion of our gross deferred tax assets and as a result a valuation allowance of $37.3 million was recorded. Percentage depletion is an income tax deduction that is limited to a percentage of taxable income from each of our mining properties.  Because percentage depletion can be deducted in excess of cost basis in the properties, it creates a permanent difference and directly impacts the effective tax rate.  Fluctuations in the effective tax rate may occur due to the varying levels of profitability (and thus, taxable income and percentage depletion) at each of our mine locations.

The criteria for recording a valuation allowance are described in “Critical Accounting Estimates – Income Taxes.”  We recorded a $85.9 million and $37.2 million valuation allowance against our gross deferred tax assets as of December 31, 2012 and 2011, respectively.    

Year Ended December 31, 2011 Compared with the Year Ended December 31, 2010

The following table shows selected operating results for 2011 and 2010 (in thousands, except per ton amounts):

Volume and Revenues by Segment

The following tables show volume and revenue information by segment (in thousands, except per ton amounts).

Total tons shipped increased by 32% in 2011 as compared to 2010.   Coal sales revenue increased 58% in 2011 as compared to 2010.  The increase in tons shipped and coal sales revenue (including the change in mix to include metallurgical coal) was primarily related to contracts acquired in the IRP Acquisition and additional tons produced from the properties acquired in the IRP Acquisition.  The overall increase in tons was partially offset by a decrease in tons shipped in our Midwest Region in 2011 as compared to 2010.

Freight and handling revenue consists of shipping and handling costs invoiced to coal customers and paid to third-party carriers. These revenues are directly offset by freight and handling costs.

Operating and Other Costs

The following tables show selected costs in total and by segment (in thousands, except per ton amounts).

The cost of coal sold, excluding depreciation, depletion and amortization, increased from $512.3 million in 2010 to $905.5 million in 2011.  Our cost per ton of coal sold in the CAPP region increased from $68.68 per ton in 2010 to $87.07 per ton in the 2011.  Our costs in the CAPP region are impacted by increased costs as a result of the IRP Acquisition.  Generally, the mines acquired from IRP have more metallurgical coal than our legacy operations.  These metallurgical coal mines produce higher coal sales revenue but are more costly to mine.  Our costs were also impacted by an increase in metallurgical coal purchased that is used to blend with our metallurgical coal production to meet quality requirements under our sales contracts.  The impact of the change in our mix to additional metallurgical coal production is approximately $9.92 per ton.  The remaining increase of $8.47 over the prior year is primarily due to an increase in our labor and benefit costs of $1.79 per ton, variable costs of $3.88 per ton and preparation plants and raw trucking costs of $1.59 at our mines that do not produce metallurgical coal.   Our costs continue to be impacted by lower productivity due to increased federal and state regulatory scrutiny, a decrease in tons produced in response to market conditions and an increase in commodity prices.   For more detail regarding the increased regulatory activity see “Part II – Item 1A – Risk Factors – Underground mining is subject to increased regulation, and may require us to incur additional cost.”

Our cost per ton of coal sold in the Midwest increased $4.85 per ton to $37.87 per ton in the 2011 period as compared to the 2010 period.  The major components of this increase include an increase in the trucking and preparation costs of $1.75 per ton, variable costs of $1.23 per ton and labor and benefit costs of $1.06 per ton.  

Freight and handling costs

In 2011, freight and handling costs increased due an increase in export shipments of metallurgical coal primarily from operations acquired from IRP.

Depreciation, depletion and amortization

Depreciation, depletion and amortization increased from $64.4 million in 2010 to $108.9 million in 2011.  In the CAPP region, depreciation, depletion and amortization increased $43.0 million to $96.5 million, which is due to the increase in the asset base as a result of the IRP Acquisition and $5.9 million of amortization on contracts acquired from IRP.  In the Midwest, depreciation, depletion and amortization increased $1.6 million to $12.4 million.  

Selling, general and administrative

Selling, general and administrative expenses increased from $38.3 million in the 2010 period to $57.1 million in the 2011 period, which is primarily due to increased selling, general and administrative expenses as a result of the IRP Acquisition.

Acquisition costs

In 2011, costs of $8.5 million were incurred related to the IRP Acquisition.

Interest Expense

Interest expense increased from $29.9 million in 2010 to $50.1 million in 2011.  The increase in our interest expense was the result of the issuance of our 2018 Convertible Senior Notes and 2019 Senior Notes in March 2011, offset by the redemption in full of our 2012 Senior Notes in June 2011.  These debt transactions are described below in Liquidity and Capital Resources. Interest expense for 2011 and 2010 includes $14.7 million and $8.1 million, respectively, related to the amortization of debt discounts and debt issuance costs.

Income Taxes

Our effective tax rate in 2011 was an expense of 61.9% and our effective tax rate in 2010 was a benefit of 43.2%.  For 2011, our effective income tax rate was impacted primarily by a valuation allowance and the effects of percentage depletion.  In 2011, in connection with the completion of our forecasts which considered the decline in coal prices and market demand that occurred towards the end of 2011, and after weighing all positive and negative evidence, we concluded that it was not more likely than not to realize a portion of our gross deferred tax assets and as a result a valuation allowance of $37.3 million was recorded.  For 2010, our effective tax rate was reduced from the statutory federal rate of 35% primarily as the result of the reversal of our income tax valuation allowance (60.9%) and by percentage depletion (20.4%).

The criteria for recording a valuation allowance are described in “Critical Accounting Estimates – Income Taxes.”  As of December 31, 2011, we had recorded a $37.3 million valuation allowance against our gross deferred tax assets.    Percentage depletion is an income tax deduction that is limited to a percentage of taxable income from each of our mining properties.  Because percentage depletion can be deducted in excess of cost basis in the properties, it creates a permanent difference and directly impacts the effective tax rate.  Fluctuations in the effective tax rate may occur due to the varying levels of profitability (and thus, taxable income and percentage depletion) at each of our mine locations.

Liquidity and Capital Resources

The following chart reflects the components of our debt as of December 31, 2012 and 2011 (in thousands):

2019 Senior Note, 2018 Convertible Senior Notes and 2015 Convertible Senior Notes

During 2012, we repurchased $61.3 million of our outstanding debt, consisting of $5.0 million principal amount of the 2019 Senior Notes, $25.0 million principal amount of the 2018 Convertible Senior Notes and $31.3 million principal amount of the 2015 Convertible Senior Notes. The debt repurchases were made at a cost of $23.8 million, plus accrued interest of $0.8 million, in open market purchases. The repurchases resulted in a gain of $25.2 million, which includes the write-off of $1.0 million of financing costs.

There have been no changes to the terms of our 2019 Senior Notes, 2018 Convertible Senior Notes or 2015 Convertible Senior Notes during 2012.  See Item 15 of Part IV, “Financial Statements — Note 4 — Long Term Debt and Interest Expense” for a description of our 2019 Senior Notes, 2018 Convertible Senior Notes and 2015 Convertible Senior Notes.

Revolving Credit Agreement

There have been no changes to the terms of our Revolver under our Revolving Credit Agreement during 2012.  See Item 15 of Part IV, “Financial Statements — Note 4 — Long Term Debt and Interest Expense” for a description of our Revolving Credit Agreement.

As of December 31, 2012, we had used $60.8 million of the $69.3 million then available under the Revolver to secure outstanding letters of credit.

We were in compliance with all of the financial covenants under our outstanding debt instruments as of December 31, 2012. We cannot assure you that we will remain in compliance in subsequent periods.  If necessary, we will consider seeking a waiver or other alternatives to remain in compliance with the covenants.  For more detail regarding the covenants under our indebtedness, see Part I - Item 1A - Risk Factors - “We may be unable to comply with restrictions imposed by the terms of our indebtedness, which could result in a default under these instruments.”  

Liquidity

As of December 31, 2012, we had total liquidity of approximately $135.9 million, consisting of $8.5 million of unused borrowing capacity under the Revolver and $127.4 million of cash and cash equivalents (excluding restricted cash and short term investments).  As of December 31, 2012, we had used $60.8 million of the availability under the Revolver to secure outstanding letters of credit.

Our primary source of cash is expected to be sales of coal to our utility, industrial and steel customers. The price of coal received can change dramatically based on market factors and will directly affect this source of cash.  Our primary uses of cash include the payment of ordinary mining expenses to mine coal, capital expenditures, scheduled debt and interest payments and benefit payments. Ordinary mining expenses are driven by the cost of supplies, including steel prices and diesel fuel. Benefit payments include payments for workers’ compensation and black lung benefits paid over the lives of our employees as the claims are submitted. We are required to pay these when due, and are not required to set aside cash for these payments. We have posted surety bonds secured by letters of credit or issued letters of credit with state regulatory departments to guarantee these payments.  We believe that our Revolver provides us with the ability to meet the necessary bonding requirements. 

We currently project that in 2013 our capital expenditures will be approximately $70 million, cash interest on our long term debt to be approximately $34 million and fees under our Revolver for letters of credit will total approximately $4 million. We expect that such expenditures will exceed cash generated by operations and will need to be funded through cash on hand; however we expect that cash on hand will be sufficient throughout 2013 to meet our debt covenants. Our cash position beyond 2013 will depend on numerous factors such as the market for our coal, capital expenditures, commodity costs and absent improvements to current market conditions, we would likely need to secure additional sources of liquidity to meet our cash requirements.

We believe that currently available cash, cash generated from operations and borrowings under our Revolver will be sufficient to meet our working capital requirements, anticipated capital expenditures and scheduled debt payments throughout 2013. Nevertheless, our ability to satisfy our working capital requirements and debt service obligations (including refinancing debt that matures in 2015), or fund planned capital expenditures, will substantially depend upon our future operating performance, debt covenants, and financial, business and other factors, some of which are beyond our control.

In the event that the sources of cash described above are not sufficient to meet our future cash requirements, we will need to reduce certain planned expenditures, seek additional financing, or both. We may seek to raise funds through additional debt financing or the issuance of additional equity securities. If such actions are not sufficient, we may need to limit our growth, sell assets or reduce or curtail some of our operations to levels consistent with the constraints imposed by our available cash flow, or any combination of these options. Our ability to seek additional debt or equity financing may be limited by our existing and any future financing arrangements, economic and financial conditions, or all three. In particular, our existing 2019 Senior Notes, 2015 Convertible Senior Notes, 2018 Convertible Senior Notes and Revolver restrict our ability to incur additional indebtedness. We cannot provide assurance that any reductions in our planned expenditures or in our expansion would be sufficient to cover shortfalls in available cash or that additional debt or equity financing would be available on terms acceptable to us, if at all.

Our projected capital expenditures for 2013 of $70 million primarily consist of capital expenditures for normal mining activities including new and replacement mine equipment. Our projected capital expenditures for 2013 also include approximately $10 million for safety mandates and new mine and infrastructure development.

Net cash from operating activities reflects net income (loss) adjusted for non-cash charges and changes in net working capital (including non-current operating assets and liabilities). Net cash provided by operating activities was $32.4 million and $163.8 million in 2012 and 2011, respectively.  During 2012, our net loss of $138.9 million was adjusted by non cash charges of $161.5 million. During 2012, our net loss, as adjusted for non cash charges was decreased by a $9.8 million decrease in cash from our operating assets and liabilities. The $9.8 million change in our operating assets and liabilities for 2012 includes a $27.4 million decrease in inventories, $17.7 million decrease in accounts receivables and a $37.7 million decrease in accounts payable. During 2011, our net loss of $39.1 million was adjusted by non cash charges of $148.2 million. During 2011, our net loss, as adjusted for non cash charges was increased by a $54.7 million increase in cash from changes in our operating assets and liabilities.  The $54.7 million change in our operating assets and liabilities for 2011 includes a $69.0 million decrease in receivables and a $14.0 million increase in inventory.

Net cash used in investing activities decreased by $573.4 million to $80.9 million in 2012 as compared to 2011, which includes a payment for the IRP Acquisition net of cash acquired, of $516.0 million in 2011.  Capital expenditures for property, plant and equipment decreased $56.8 million to $81.6 million in 2012 as compared to 2011.  Capital expenditures primarily consisted of new and replacement mine equipment and various projects to improve the production and efficiency of our mining operations.  Additionally, during 2012 and 2011, our capital expenditures for property, plant and equipment included approximately $10.9 million and $37.5 million, respectively, for safety mandates and new mine and infrastructure development.

Net cash used in financing activities was $23.8 million in 2012 and consists of repayment of debt. Net cash provided by financing activities was $509.9 million in 2011 and consists of $491.2 million of net proceeds from the issuance of the 2019 Senior Notes and the 2018 Convertible Senior Notes, net of debt issuance costs; $170.5 million of net proceeds from the issuance of common stock, which were offset by $150.0 million used to repay the 2012 Senior Notes; and $1.9 million of costs in connection with the amendments and restatements to the Revolver.  

Contractual Obligations

The following is a summary of our contractual obligations and commitments as of December 31, 2012:

Additionally, we have liabilities relating to pension, workers’ compensation, black lung, and mine reclamation and closure. As of December 31, 2012, the undiscounted payments related to these items are estimated to be:

Our determination of these noncurrent liabilities is calculated annually and is based on several assumptions, including then prevailing conditions, which may change from year to year. In any year, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Moreover, in particular for periods after 2013, our estimates may change from the amounts included in the table, and may change significantly, if our assumptions change to reflect changing conditions. These assumptions are discussed in the Notes to the Consolidated Financial Statements and in the Critical Accounting Estimates in Management’s Discussion and Analysis.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements, including guarantees, operating leases, indemnifications, and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds.  Liabilities related to these arrangements are not reflected in our consolidated balance sheets, and, except for the operating leases, we do not expect any material impact on our cash flow, results of operations or financial condition from these off-balance sheet arrangements.

We use surety bonds to secure reclamation, workers’ compensation and other miscellaneous obligations. At December 31, 2012, we had $144.7 million of outstanding surety bonds with third parties. These bonds were in place to secure obligations as follows: post-mining reclamation bonds of $99.8 million, workers’ compensation bonds of $40.3 million, wage payment, collection bonds, and other miscellaneous obligation bonds of $4.6 million. Surety bond costs have increased over time and the market terms of surety bonds have generally become less favorable. To the extent that surety bonds become unavailable, we would seek to secure obligations with letters of credit, cash deposits, or other suitable forms of collateral.

We also use cash collateral accounts and bank letters of credit to secure our obligations for post-mining reclamation, workers’ compensation programs, various insurance contracts and other obligations. As of December 31, 2012, we had $60.8 million of letters of credit outstanding.  The letters of credit are issued under our Revolver.

Critical Accounting Estimates

Overview

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources are based upon our consolidated financial statements, which have been prepared in accordance with U.S generally accepted accounting principles (US GAAP). US GAAP require estimates and judgments that affect reported amounts for assets, liabilities, revenues and expenses. The estimates and judgments we make in connection with our consolidated financial statements are based on historical experience and various other factors we believe are reasonable under the circumstances. Note 1 of the notes to the consolidated financial statements lists and describes our significant accounting policies. The following critical accounting policies have a material effect on amounts reported in our consolidated financial statements.

Business Combinations

We account for our business combinations under the acquisition method of accounting.  The total cost of acquisitions is allocated to the underlying identifiable net tangible and intangible assets based on their respective estimated fair values.  Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, with assistance of third party valuation services, and often involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items.  

Workers' Compensation

We are liable under various state statutes for providing workers’ compensation benefits.  Except as indicated, we are self insured for workers’ compensation at our Kentucky operations, with specific excess insurance purchased from independent insurance carriers to cover individual traumatic claims in excess of the self-insured limits.  For the period June 2002 to June 2005, workers compensation coverage was insured through a third party insurance company using a large risk rating plan.  Our operations in Indiana are insured through a third party insurance company using a large risk rating plan.  Our operations in West Virginia are fully insured with a guaranteed cost policy through a third party insurance company for both Workers’ Compensation and Employers Liability coverage. 

We accrue for the present value of certain workers’ compensation obligations as calculated annually by an independent actuary based upon assumptions for work-related injury and illness rates, discount rates and future trends for medical care costs.  The discount rate is based on interest rates on bonds with maturities similar to the estimated future cash flows.  The discount rate used to calculate the present value of these future obligations was 2.8% at December 31, 2012.  Significant changes to interest rates result in substantial volatility to our consolidated financial statements. If we were to decrease our estimate of the discount rate from 2.8% to 2.3%, all other things being equal, the present value of our workers’ compensation obligation would increase by approximately $2.7 million. A change in the law, through either legislation or judicial action, could cause these assumptions to change. If the estimates do not materialize as anticipated, our actual costs and cash expenditures could differ materially from that currently estimated. Our estimated workers’ compensation liability as of December 31, 2012 was $76.9 million.

Coal Miners' Pneumoconiosis

We are required under the Federal Mine Safety and Health Act of 1977, as amended, as well as various state statutes, to provide pneumoconiosis (black lung) benefits to eligible current and former employees and their dependents. We provide for federal and state black lung claims through a self-insurance program for our operations in Kentucky.   For the period between June 2002 and June 2005, all black lung liabilities were insured through a third party insurance company using a large risk rating plan.  Our operations in Indiana are insured through a third party insurance company using a large risk rating plan.  Our operations in West Virginia are fully insured with a guaranteed cost policy through a third party insurance company.

An independent actuary calculates the estimated pneumoconiosis liability annually based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents and interest rates. The discount rate is based on interest rates on high quality corporate bonds with maturities similar to the estimated future cash flows. The discount rate used to calculate the present value of these future obligations was 3.9% at December 31, 2012. Significant changes to interest rates result in substantial volatility to our consolidated financial statements. If we were to decrease our estimate of the discount rate by 0.5% to 3.4%, all other things being equal, the present value of our black lung obligation would increase by approximately $5.2 million. A change in the law, through either legislation or judicial action, could cause these assumptions to change. If these estimates prove inaccurate, the actual costs and cash expenditures could vary materially from the amount currently estimated. Our estimated pneumoconiosis liability as of December 31, 2012 was $65.3 million.

Defined Benefit Pension

We have in place a non-contributory defined benefit pension plan under which all benefits were frozen in 2007.  The estimated cost and benefits of our non-contributory defined benefit pension plans are determined annually by independent actuaries, who, with our review and approval, use various actuarial assumptions, including discount rate and expected long-term rate of return on pension plan assets. In estimating the discount rate, we look to rates of return on high-quality, fixed-income investments with comparable maturities. At December 31, 2012, the discount rate used to determine the obligation was 3.8%. Significant changes to interest rates result in substantial volatility to our consolidated financial statements. If we were to decrease our estimate of the discount rate from 3.8% to 3.3%, all other things being equal, the present value of our projected benefit obligation would increase by approximately $7.4 million.  The expected long-term rate of return on pension plan assets is based on long-term historical return information and future estimates of long-term investment returns for the target asset allocation of investments that comprise plan assets. The expected long-term rate of return on plan assets used to determine expense was 7.5% for the period ended December 31, 2012. Significant changes to these rates would introduce volatility to our pension expense.  Our accrued pension obligation as of December 31, 2012 was $35.3 million.

Reclamation and Mine Closure Obligation

The Surface Mining Control Reclamation Act of 1977 establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of underground mining. Our asset retirement obligation liabilities consist of spending estimates related to reclaiming surface land and support facilities at both surface and underground mines in accordance with federal and state reclamation laws. Our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering estimates related to these requirements. US GAAP requires that asset retirement obligations be initially recorded as a liability based on fair value, which is calculated as the present value of the estimated future cash flows. Our management and engineers periodically review the estimate of ultimate reclamation liability and the expected period in which reclamation work will be performed. In estimating future cash flows, we considered the estimated current cost of reclamation and applied inflation rates and a third party profit. The third party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf. The discount rate is our estimate of our credit adjusted risk free rate. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. The actual costs could be different due to several reasons, including the possibility that our estimates could be incorrect, in which case our liabilities would differ. If we perform the reclamation work using our personnel rather than hiring a third party, as assumed under US GAAP, then the costs should be lower. If governmental regulations change, then the costs of reclamation will be impacted. US GAAP recognizes that the recorded liability could be different than the final cost of the reclamation and addresses the settlement of the liability. When the obligation is settled, and there is a difference between the recorded liability and the amount paid to settle the obligation, a gain or loss upon settlement is included in earnings. Our asset retirement obligation as of December 31, 2012 was $104.8 million.

Contingencies

We are the subject of, or a party to, various suits and pending or threatened litigation involving governmental agencies or private interests. We have accrued the probable and reasonably estimable costs for the resolution of these claims based upon management’s best estimate of potential results, assuming a combination of litigation and settlement strategies. Management does not believe that the outcome or timing of current legal or environmental matters will have a material impact on our financial condition, results of operations, or cash flows.  See the notes to the consolidated financial statements for further discussion on our contingencies.

Income Taxes

Deferred tax assets and liabilities are required to be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. Deferred tax assets are also required to be reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income. We have also considered tax planning strategies in determining the deferred tax asset that will ultimately be realized. If actual results differ from the assumptions made in the evaluation of the amount of our valuation allowance, we record a change in valuation allowance through income tax expense in the period such determination is made.

We have a valuation allowance of $85.9 million against our gross deferred tax assets as of December 31, 2012.  

Coal Reserves

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves. Many of these uncertainties are beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data initially assembled by our staff and analyzed by Marshall Miller & Associates, Inc. (MM&A). The reserve information has subsequently been updated by our staff. The updates to the reserves have been calculated in the same manner, and based on similar assumptions and qualifications, as used in the MM&A studies described above, but these updates to the reserve estimates have not been reviewed by MM&A.  A number of sources of information were used to determine accurate recoverable reserves estimates, including:

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

Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows may vary substantially. Actual production, revenue and expenditures with respect to reserves will likely vary from estimates, and these variances could be material. In particular, a variance in reserve estimates could have a material adverse impact on our annual expense for depreciation, depletion and amortization and on our annual calculation for potential impairment. For a further discussion of our coal reserves, see “Reserves.”

Evaluation of Goodwill for Impairment

Goodwill represents the excess of purchase price and related costs over the value assigned to the net tangible and identifiable intangible assets of businesses acquired.  Goodwill is not amortized but is tested for impairment annually, or if certain circumstances indicate a possible impairment may exist. Impairment testing is performed at a reporting unit level.

Our goodwill is contained in the Midwest Segment.  We performed our annual goodwill impairment test during the fourth quarter of 2012 using a two-step approach. Step one compared the fair value of equity for this reporting unit to its carrying value. We considered the market and income approaches in addition to the market capitalization method, to estimate the fair value of equity for the reporting unit.  The market capitalization approach is based on allocating the Company’s market capitalization to the Company’s reporting units based on financial and production matrices.  The market approach was based on a guideline public companies and guideline transactions within the coal industry. Under the guideline public company approach, certain operating metrics from a selected group of publicly traded comparable companies were used to estimate the fair value of equity for the Midwest reporting unit. Under the transaction method, recent merger and acquisition transactions for comparable companies were used to estimate the fair value of equity of the Midwest reporting unit.  The income approach was based on a discounted cash flow method in which expected future net cash flows were discounted to present value, using an appropriate after-tax weighted average cost of capital.  Given the market’s view concerning the long term uncertainties in the coal industry and the lack of comparable market transactions in the tested segment, it was concluded that the fair value of the equity for the reporting unit should be weighted more towards the market capitalization approach which resulted in the carrying value exceeding the fair value of the equity for the tested reporting unit.

In step two of the goodwill impairment test, we compared the carrying value of goodwill to its implied fair value. In estimating the implied fair value of goodwill at the reporting unit, we assigned the fair value of the reporting unit to all of the assets and liabilities associated with the reporting unit as if the reporting unit had been acquired in a business combination.

As a result of the goodwill impairment test, we wrote off $26.5 million of goodwill in the Midwest segment to reduce the carrying value of the goodwill to its implied fair value.  Subsequent to this write-off, we have no remaining goodwill.

Evaluation of Long-Lived Assets for Impairment

Long-lived assets, such as property, plant, and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable.  Events that trigger a test for recoverability include material adverse changes in projected revenues and expenses, significant underperformance relative to historical or projected future operating results, and significant negative industry or economic trends.  Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset.  If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset.  We did not recognize any impairment charges on long-lived assets during the periods presented.

Changes in assumptions or estimates could materially affect the determination of whether an impairment exists in our long-lived assets.  The following assumptions are key to our future cash flows expected to be generated by the tested assets:

Recent Accounting Pronouncements

See Item 15 of Part IV, “Financial Statements – Note 1 – Summary of Significant Accounting Policies and Other Information – Recent Accounting Pronouncements.

Item 7A.          Quantitative and Qualitative Disclosures about Market Risk

At December 31, 2012, all $546.4 million of our outstanding debt has a fixed interest rate and is not sensitive to changes in the general level of interest rates.  Our Revolver has floating interest rates based on our option of either the base rate or LIBOR rate.  As of December 31, 2012, we had no borrowings outstanding under the Revolver.  We currently do not use interest rate swaps to manage this risk.  A 100 basis point (1.0%) increase in the average interest rate for our floating rate borrowings would increase our annual interest expense by approximately $0.1 million for each $10 million of borrowings under the Revolver.

We manage our commodity price risk through the use of long-term coal supply agreements, rather than through the use of derivative instruments.  As of March 6, 2013, our commitments for 2013 and 2014 follow.