Edgar Filing: James River Coal CO

jrcc_10k-123110.htm

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

For the fiscal year ended	Commission File Number
December 31, 2010	000-51129

JAMES RIVER COAL COMPANY

(Exact name of registrant as specified in its charter)

Virginia		54-1602012
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

901 E. Byrd Street, Suite 1600
Richmond, Virginia		23219
(Address of principal executive offices)		(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:	Common Stock, par value $0.01 per share
	Series A Participating Cumulative Preferred
	Stock Purchase Rights
Name of each exchange on which registered:	The Nasdaq Global Select Market
Securities registered pursuant to Section 12(g) of the Act:	None

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 o No o

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

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.

Large accelerated filer o

Accelerated filer ý

Non-accelerated filer

oSmaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No ý

The aggregate market value of 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 30, 2010 as reported on the Nasdaq Global Market, was approximately $316,862,000 (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, 2011 was 27,779,351.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the registrant’s 2011 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.

JAMES RIVER COAL COMPANY

TABLE OF CONTENTS

FORM 10-K ANNUAL REPORT

PART I

Item 1.	Business	2
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	32
Item 2.	Properties	32
Item 3.	Legal Proceedings	33
Item 4.	[Removed and Reserved]	33

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Item 6.	Selected Financial Data	35
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	34
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	53
Item 8.	Financial Statements and Supplementary Data	53
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	53
Item 9A.	Controls and Procedures	53
Item 9B.	Other Information	56

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	59
Item 11.	Executive Compensation	59
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	59
Item 13.	Certain Relationships and Related Transactions, and Director Independence	59
Item 14.	Principal Accountant Fees and Services	59

PART IV

Item 15.	Exhibits, Financial Statement Schedules	60

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 2011 Annual Meeting of Shareholders. The Company expects to file the Proxy Statement with the SEC on or about April 30, 2011, 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

We mine, process and sell bituminous, steam- and industrial-grade coal through six operating subsidiaries (“mining complexes”) located throughout eastern Kentucky and in southern Indiana. As of December 31, 2010, our six mining complexes included 18 underground mines, 9 surface mines and 10 preparation plants, five of which have integrated rail loadout facilities and three of which use a common loadout facility at a separate location. As of December 31, 2010, we believe that we controlled approximately 271.3 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 2010, we produced 8.8 million tons of coal (including 0.1 million tons of coal produced in our mines that are operated by contract mine operators) and we purchased another 0.1 million tons for resale. Of the 8.8 million tons produced from Company mines, approximately 65% came from underground mines, while the remaining 35 % came from surface mines. In 2010, we generated revenues of $701.1 million and had net income of $78.2 million. Approximately 88% of our 2010 revenues were generated from coal sales to electric utility companies and the remainder came from coal sales to industrial and other companies. In 2010, South Carolina Public Service Authority, Georgia Power Company and Indianapolis Power and Light were our largest customers, representing approximately 39%, 32% and 11% of our revenues, respectively. No other customer accounted for more than 10% of our revenues.

The coal that we sell is obtained from three sources: our Company-operated mines, 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 2010:

	Tons (000s)	Percentage of total coal obtained by the Company
Coal produced from Company-operated mines	8,705	97.7%
Coal obtained from mines operated by independent contractors	77	0.9%
Coal purchased from third parties	128	1.4%
	8,910	100%

On March 6, 2011, we signed a definitive agreement (the “Purchase Agreement”) to purchase International Resource Partners LP (“IRP”) and its subsidiary companies for $475 million in an all-cash transaction. We have secured $375 million in committed bridge financing from Deutsche Bank AG Cayman Islands Branch (“Deutsche Bank”) and UBS Loan Finance LLC (“UBS”), which in addition to existing cash balances, is expected to be sufficient to finance the purchase price to IRP. Rather than borrow under the committed financing, we may seek to issue common stock, convertible notes, senior notes or other securities in one or more public or private offerings in connection with the proposed acquisition. There can be no assurance that we will undertake or complete any such financing transaction.

The Purchase Agreement contains customary representations, warranties, covenants and conditions, as well as indemnification provisions subject to specified limitations. The closing of the proposed acquisition is subject to the termination or expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, certain third party consents and other customary closing conditions. The proposed acquisition is expected to close in the first half of 2011.

IRP mines, processes and sells metallurgical and steam coal through its mining complexes in Southern West Virginia and Eastern Kentucky. IRP, through its wholly owned subsidiary Logan & Kanawha, also conducts coal brokering and trading operations. Including brokered coal, IRP had revenues of $490.3 million for the year ended December 31, 2010. IRP had approximately 86 million tons of proven and probable coal reserves as of December 31, 2010.

Mining Methods

Our Company-operated and contractor 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 the Central Appalachia Region (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 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, 2010, we had 9 Company-operated surface mines, two of which had a contract highwall miner operated in connection with the surface operations.

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.

As of December 31, 2010, we had 16 Company-operated underground mines and 2 contract underground mines in operation for a total of 18 mines, of which 15 were drift mines and the remaining three were below-drainage mines.

Mining Operations

Our coal production is conducted through five 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 for coal reserves from our producing properties were approximately 8.8% and 4.3% of produced coal revenue for the year ended December 31, 2010, 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, 2010:

	Number and Type of Mines						Quality of Shipments for the year ended 2010
Mining Complex	Underground	Surface (S) and Highwall (HW)	Total		Tons Shipped (000’s)		Average Sulfur Content (%)		Average Ash Content (%)		Average BTU Content
Central Appalachia
Bell County Coal Corporation	2	-		2		340		1.6		7.1		13,209
Bledsoe Coal Corporation	4	-		4		1,326		1.2		7.9		13,021
Blue Diamond Coal Corporation	3	1S		4		1,446		1.0		8.3		13,020
Leeco, Inc.	1	2S /1HW(1)		3		1,218		0.9		9.5		12,878
McCoy Elkhorn Coal Corporation	6	1S /1HW(1)		7		1,779		1.5		8.4		12,798

Midwest
Triad Mining, Inc	2	5S		7		2,810		3.2		8.8		11,242

(1) Highwall Miner operated in conjunction with surface mining.

The following summarizes additional information concerning each of our six 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 Jellico and Garmeada seams 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, 2010, we employed 127 mining and support personnel at this complex.

Bledsoe. The Bledsoe complex is located in Leslie and Harlan counties in eastern Kentucky. We use room and pillar mining and mine the Hazard #4 and #4 Rider seams 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, 2010, we employed 357 mining and support personnel at this complex.

Blue Diamond. The Blue Diamond complex is located in Leslie, Perry and Letcher counties in eastern Kentucky. We use room and pillar mining for our underground mines and we use the contour method for our surface mine. 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, 2010, we employed 303 mining and support personnel at this complex.

Leeco. The Leeco complex is located in Knott and Perry counties in eastern Kentucky. Our underground mine uses room and pillar mining and our surface mines use the contour and highwall mining methods. We mine the Amburgy seam of coal and the Hazard #4, #5, #6, #7, #8 and #9 seams 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, 2010, we employed 255 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 and our surface mine uses the contour and highwall mining methods. Two of the underground mines and the highwall miner at the McCoy Elkhorn complex are operated by contractors. We mine the Millard, Alma, Elkhorn #2 and Elkhorn #3 seams at this complex. Coal is processed at our two preparation plants and loaded into railcars via integrated four-hour unit train loadouts on the CSX railroad. As of December 31, 2010, we employed 362 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 three active preparation plants 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, 2010, we employed approximately 292 mining and support personnel at this complex.

Contract mining represented less than 1.0% of our coal production in the year ended December 31, 2010. 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. Contractors that operate surface mines, however, typically are contractually obligated to perform, on our behalf, the reclamation activities associated with the mines they operate. 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. In April 2004, we asked Marshall Miller & Associates, Inc. (“MM&A”) to prepare a detailed study of our reserves in Central Appalachia as of March 31, 2004 based on all of our geologic information, including our updated drilling and mining data. For the Triad properties, MM&A also prepared a detailed study of Triad’s reserves as of February 1, 2005 for the reserves obtained in the acquisition of Triad and as of April 11, 2006 for certain additional reserves acquired in the second quarter of 2006. We have used MM&A’s March 31, 2004 study 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 a coal reserve study on our December 31, 2010 estimate.

The coal reserve studies conducted by MM&A 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, 2010, we estimated that we controlled approximately 230.4 million tons of proven and probable coal reserves in Central Appalachia and 40.9 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):

			Approximate Overall Reserve Quality (2), (3)
Mining Complex	Proven & Probable Reserves As of December 31, 2010 (1),(4)	Estimated Years of Reserve Life Based on 2010 Production Levels	Ash Content (%)	Sulfur Content (%)	Heat Value (Btu/lb.)
Central Appalachia	(millions of tons)
Bell County	9.4	32.7	5.1	1.0	13,500

Bledsoe	55.5	43.0	7.8	1.2	13,000

Blue Diamond	76.7	49.3	4.7	1.1	13,700

Leeco	51.6	41.6	7.0	1.2	13,200

McCoy Elkhorn	37.2	21.1	5.7	1.6	13,300

Total/Average	230.4	37.6	6.3	1.3	13,300

Midwest
Triad	40.9	14.4	8.8	3.2	12,000

(1)

Proven reserves have the highest degree of geologic assurance and are reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings, or drill holes; (b) grade and/or quality are computed from the results of detailed sampling and (c) the sites for inspections, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. Probable reserves have a moderate degree of geologic assurance and are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation. This reserve information reflects recoverable tonnage on an as-received basis with 5.5% moisture.

(2)

Ash and sulfur content is expressed as the percent by weight of those constituents in the coal sample compared to the total weight of the sample being tested. Heat value is expressed as Btu per pound in the coal based on laboratory testing of coal samples. The samples are typically obtained from exploratory core borings placed at strategic locations within the coal reserve area. Approximately 82% of the reserve tons have representative samples (degree of representation varies from area to area) and 18% of the reserve tons have no site-specific samples (and are therefore not included in the overall quality estimate). The samples are sent to accredited laboratories for testing under protocols established by the American Society of Testing and Materials (ASTM). The estimated overall quality values are derived by a multiple step process, including: (a) for each mine or reserve area, an arithmetic average quality (dry basis) was prepared to represent the coal tons within the area, based on samples from the area; (b) the overall quality of reserves for each mine complex was determined by performing a tonnage-weighted average of the average quality of all mine and reserve areas within the division; and (c) the resulting dry basis overall quality was converted to wet product basis to reflect its anticipated moisture content at the time of sale. The actual quality of the shipped coal may vary from these estimates due to factors such as: (a) the particle size of the coal fed to the plant; (b) the specific gravity of the float media in use at the preparation plant; (c) the type of plant circuit(s); (d) the efficiency of the plant circuit(s); (e) the moisture content of the final product; and (f) customer requirements.

(3)

For the CAPP region, represents reserve quality information for our mining complexes as of March 31, 2004. For the Midwest region, represents weighted average reserve quality information as of February 1, 2005 and April 11, 2006, for the reserves obtained on the acquisition of the Triad mining complex and for a lease entered into during 2006, respectively. The reserve quality information is based on the MM&A studies.

(4)

Represents the Company’s estimate of reserves at December 31, 2010 based on additional information or reserves obtained from exploration and acquisition activities, production activities or discovery of new geologic information. We calculated the adjustments to the reserves in the same manner, and based on the same assumptions and qualifications, as used in the MM&A studies described above, but these December 31, 2010 estimates have not been reviewed by MM&A.

Processing and Transportation

Coal from each of our mine complexes is transported by conveyor belt or by truck to one of our ten 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, substantially all of our coal is shipped by train and sold f.o.b. the railcar at the point of loading; transportation costs are normally borne by the customer. In addition to our well-positioned unit train loadout facilities on the CSX Corporation railroad, our Bell County mining complex has dual service provided by the CSX and Norfolk Southern Corporation railroads in Bell County, Kentucky.

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, with transportation costs normally borne by the customer. Our Triad mining complex has rail service provided by Indiana Railroad and Indiana Southern Railroad.

Our mining complexes are supported by personnel located in London and Lexington, Kentucky 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 regularly 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 2010, we generated approximately 85% of our total revenues from long-term contracts to sell coal to electric utilities. For the year ended December 31, 2010, South Carolina Public Service Authority (39%), Georgia Power Company (32%) and Indianapolis Power and Light (11%) were our largest customers by revenues. No other customer accounted for more than 10% of revenues.

In 2010, we sold approximately 6.1 million tons of coal in the CAPP region at an average selling price of $95.77 per ton. In the CAPP region, we currently have approximately 5.1 million and 0.4 million tons contracted to be sold in 2011 and 2012, respectively, at average selling prices in excess of our 2010 average selling price. Current market prices for coal in the CAPP region are substantially below our average 2010 sales price. If the market does not strengthen, our sales price for future tons sold will be adversely impacted.

In 2010, we sold approximately 2.8 million tons of coal in the Midwest region at an average selling price of $41.30 per ton. In the Midwest region, we currently have approximately 2.6 million and 1.6 million tons contracted to be sold in 2011 and 2012, respectively, at average selling prices in excess of our 2010 average selling price.

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:

Fixed price contracts;

Annually negotiated prices that reflect market conditions at the time; or

Base-price-plus-escalation methods that allow for periodic price adjustments based on fixed percentages or, in certain limited cases, pass-through of actual cost changes.

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. 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. Department of Energy, the largest producer produced approximately 17.6% (based on tonnage produced) of the total United States production in 2009, the latest year for which government statistics are available. The U.S. Department of Energy also reported 1,406 active coal mines in the United States in 2009. Demand for our coal by our principal customers is affected by:

the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric power;

coal quality;

transportation costs from the mine to the customer; and

the reliability of supply.

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, 2010, we had 1,746 employees. None of our employees are currently represented by collective bargaining agreements. Relations with our employees are generally good.

Government Regulation

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

employee health and safety;

permitting and licensing requirements;

air quality standards;

water quality standards;

plant, wildlife and wetland protection;

blasting operations;

the management and disposal of hazardous and non-hazardous materials generated by mining operations;

the storage of petroleum products and other hazardous substances;

reclamation and restoration of properties after mining operations are completed;

discharge of materials into the environment, including air emissions and wastewater discharge;

surface subsidence from underground mining; and

the effects of mining operations on groundwater quality and availability.

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 $8.5 million and $3.5 million for environmental control facilities and complying with safety regulations in 2011 and 2012, 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 503 of the Dodd-Frank Act contains new reporting requirements regarding coal or other mine safety. We are currently evaluating the provisions of the Dodd-Frank Act and the potential impact that it may have on our operations.

Mine Health and Safety Laws

Stringent health and safety standards were imposed by federal legislation when the Federal Coal Mine Safety and Health Act of 1969 was adopted. The Federal Mine Safety and Health Act of 1977, which significantly expanded the enforcement of safety and health standards of the Federal Coal Mine Safety and Health Act of 1969, imposes safety and health standards on all mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The Federal Mine Safety and Health Administration monitors compliance with these federal laws and regulations and can impose under recently enacted regulations maximum penalties of up to $220,000 for certain violations, as well as closure of the mine. In addition, certain portions of the Federal Coal Mine Safety and Health Act of 1969 and the Federal Mine Safety and Health Act of 1977, the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, require payments of benefits to disabled coal miners with black lung disease and to certain survivors of miners who die from black lung disease.

In Kentucky, the Kentucky Mine Safety Review Commission, an independent agency, assesses penalties against anyone, including owners or part owners (defined as anyone owning one percent or more shares of publicly traded stock), whose intentional violations or order to violate mine safety laws place miners in imminent danger of serious injury or death. Mine safety training and compliance with state statutes and regulations related to coal mining is monitored by the Kentucky Office of Mine Safety and Licensing. The Commission can impose a penalty of up to $10,000 per violation, as well as suspension or revocation of the mine license. In Indiana, a Mining Board consisting of five members appointed by the Governor is in charge of executing and administering the laws of the state concerning coal mines. Underground coal mining is regulated by the Indiana Bureau of Mines and Mining Safety. The Director and inspectors working for the bureau regularly inspect the mines to make sure they are in compliance with federal mining regulations. They have the authority to close a mine or a portion thereof if a condition of willful neglect exists and to keep it closed until the condition is corrected.

Increased scrutiny of coal mining in general and underground coal mining in particular has led to new legislation. 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. Additionally, new requirements for prompt reporting of accidents, including requirements under the Dodd-Frank Act, and increased fines and penalties for violation of these and other regulations have been enacted.

It is our responsibility to our employees to provide a safe and healthy environment through training, communication, following and improving safety standards and investigating all accidents, incidents and losses to avoid reoccurrence. The combination of federal and state safety and health regulations in the coal mining industry is, perhaps, the most comprehensive system for protection of employee safety and health affecting any industry. Most aspects of mine operations are subject to extensive regulation. This regulation has a significant effect on our operating costs. However, our competitors are subject to the same level of regulation.

Black Lung Legislation

Under the federal Black Lung Benefits Act (as amended) (the “Black Lung Act”), each coal mine operator is required to make black lung benefits or contribution payments to:

current and former coal miners who are totally disabled from black lung disease;

certain survivors of a miner who dies from black lung disease or pneumoconiosis; and

a trust fund for the payment of benefits and medical expenses to any claimant whose last mine employment was before January 1, 1970, or where a miner’s last coal employment was on or after January 1, 1970 and no responsible coal mine operator has been identified for claims, or where the responsible coal mine operator has defaulted on the payment of such benefits.

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

In addition to the Black Lung Act, 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. Our total (federal and state) black lung benefit liabilities, including the current portions, totaled approximately $45.7 million at December 31, 2010. These obligations were unfunded at December 31, 2010.

In January 2001, the United States Department of Labor amended the regulations implementing the federal black lung laws to give greater weight to the opinion of a claimant’s treating physician, expand the definition of black lung disease and limit the amount of medical evidence that can be submitted by claimants and respondents. The amendments also alter administrative procedures for the adjudication of claims, which, according to the Department of Labor, results in streamlined procedures that are less formal, less adversarial and easier for participants to understand. These and other changes to the federal black lung regulations could significantly increase our exposure to black lung benefits liabilities.

The Patient Protection and Affordable Care Act of 2010 (the “Act”) was enacted into law on March 23, 2010 and included 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 would be disabled due to pneumoconiosis and be eligible for black lung benefits. The new Act also makes it easier for widows of miners to become eligible for benefits. The enactment of this new legislation could significantly impact the Company’s future payments for black lung benefits.

In recent years, 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.

Workers’ Compensation

We are required to compensate employees for work-related injuries. Our accrued workers’ compensation liabilities, including the current portion, were $64.9 million at December 31, 2010. These obligations are unfunded. Our expense for workers’ compensation was $12.8 million and $12.3 million in 2010 and 2009, respectively. Both the federal government and the states in which we operate consider changes in workers’ compensation laws from time to time. Such changes, if enacted, could adversely affect us.

Environmental Laws and Regulations

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

the Surface Mining Control and Reclamation Act of 1977;

the Clean Air Act;

the Clean Water Act;

the Toxic Substances Control Act;

the Comprehensive Environmental Response, Compensation and Liability Act;

the U.S. Army Corps of Engineers; and

the Resource Conservation and Recovery Act.

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)

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

The 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. 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 the SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore unreclaimed mines closed before 1977. The maximum tax is $0.315 per ton on surface mined coal and $0.135 per ton on coal produced by underground mining.

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. At December 31, 2010, we had accrued $48.4 million related to estimated mine reclamation costs. 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.

Our future operating results would be adversely affected if these accruals were determined to be insufficient. These obligations are unfunded. The amount that was expensed for the year ended December 31, 2010 was $3.3 million, while the related cash payment for such liability during the same period was $0.9 million.

We also lease some of our coal reserves to third-party operators. Although specific criteria varies from state to state as to what constitutes an “owner” or “controller” relationship, under the federal SMCRA, responsibility for reclamation or remediation, unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine operators can be imputed to other companies which are deemed, according to the regulations, to have “owned” or “controlled” the contract mine operator. Sanctions against the “owner” or “controller” are quite severe and can include being blocked, nationwide, from receiving new permits, or amendments and revisions to existing permits, and revocation, rescission and/or suspension of any permits that have been issued since the time of the violations or, in the case of civil penalties and reclamation fees, since the time such amounts became due.

Clean Air Act

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. The EPA has adopted stringent National Ambient Air Quality Standards for particulate matter, which may require some states to change existing implementation plans for particulate matter. Because coal mining operations and plants burning coal emit particulate matter, our mining operations and utility customers are likely to be directly affected when the revisions to the National Ambient Air Quality Standards are implemented by the states. Regulations under the Clean Air Act may restrict our ability to develop new mines or could require us to modify our existing 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.

The EPA has also adopted federal rules intended to reduce the interstate transport of fine particulate matter and ozone through reductions in sulfur dioxide and nitrogen oxide emissions from certain sources throughout the eastern United States. In 2008, these rules were struck down by the U.S. Court of Appeals for the D.C. Circuit and remanded to the EPA for further consideration. In July 2010, the EPA issued a proposed rule that calls for reductions of sulfur dioxides and nitrogen oxides that drift across state lines beginning in 2012. New and proposed reductions in emissions of sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases may require the installation of additional costly control technology or the implementation of other measures, including trading of emission allowances and switching to other fuels.

Congress and several states are now considering legislation, to further control air emissions of multiple pollutants from electric generating facilities and other large emitters. These new and proposed reductions 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 in the future. To the extent that any new and proposed requirements affect our customers, this could adversely affect our operations and results.

Along with these regulations addressing ambient air quality, 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. These requirements could limit the demand for coal in some locations.

The U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities and brought an administrative action against one government-owned utility for alleged violations of the Clean Air Act. We supply coal to some of the currently-affected utilities, and it is possible that other of our customers will be sued. These lawsuits could require the utilities to pay penalties, install pollution control equipment or undertake other emission reduction measures, any of which could adversely impact their demand for our coal.

Any reduction in coal’s share of the capacity for power generation could have a material adverse effect on our business, financial condition and results of operations. The effect such regulations, or other requirements that may be imposed in the future, could have on the coal industry in general and on us in particular cannot be predicted with certainty.

We believe we have obtained all necessary permits under the Clean Air Act. We monitor permits required by operations regularly and take appropriate action to extend or obtain permits as needed. Our permitting costs with respect to the Clean Air Act are typically less than $100,000 per year.

Framework Convention on Global Climate Change

The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, which is intended to limit or capture emissions of greenhouse gases, such as carbon dioxide. In December 1997, the signatories to the convention established a potentially binding set of emissions targets for developed nations. Although the specific emissions targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. The U.S. Senate has not ratified the treaty commitments. The current administration could support the effort to ratify the treaty. With Russia’s ratification of the Kyoto Protocol in 2004, it became binding on all ratifying countries. The implementation of the Kyoto Protocol in the United States and other countries, and other emissions limits, such as those adopted by the European Union, could affect demand for coal outside the United States. If the Kyoto Protocol or other comprehensive legislation or regulations focusing on greenhouse gas emissions is enacted by the United States, it could have the effect of restricting the use of coal. Other efforts to reduce emissions of greenhouse gases and federal initiatives to encourage the use of natural gas also may affect the use of coal as an energy source.

Clean Water Act

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. We believe we have obtained or applied for all permits required under the Clean Water Act and corresponding state laws and are in substantial compliance with such permits. However, new requirements under the Clean Water Act and corresponding state laws could cause us to incur significant additional costs that adversely affect our operating results.

New requirements under the Clean Water Act (such as the proposal discussed below in the risk factor “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”) and corresponding state laws could cause us to incur significant additional costs that adversely affect our operating results.

In addition, the U.S. Army Corps of Engineers 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 impacted due to mining operations. The federal Office of Surface Mining Reclamation and Enforcement has 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 also cause us to incur significant additional operating costs.

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.

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, future cash flows and borrowings, and sources of funding. These forward-looking statements could also involve, among other things, statements regarding our intent, belief or expectation with respect to:

our cash flows, results of operation or financial condition;

the consummation of acquisition, disposition or financing transactions and the effect thereof on our business;

governmental policies and regulatory actions;

legal and administrative proceedings, settlements, investigations and claims;

weather conditions or catastrophic weather-related damage;

our production capabilities;

availability of transportation;

market demand for coal, electricity and steel;

competition;

our relationships with, and other conditions affecting, our customers;

employee workforce factors;

our assumptions concerning economically recoverable coal reserve estimates;

future economic or capital market conditions;

our plans and objectives for future operations and expansion or consolidation;

the timing and completion of our proposed acquisition of International Resource Partners (the “IRP Acquisition”), including the possibility that various closing conditions may not be satisfied or waived or the failure of the IRP Acquisition to close for any other reason;

our ability to integrate successfully operations that we may acquire or develop in the future, including those of International Resource Partners, or the risk that any such integration could be more difficult, time-consuming or costly than expected;

the consummation of financing transactions, acquisitions or dispositions and the related effects on our business, including financing related to the IRP Acquisition;

uncertainty of our expected financial performance following completion of the IRP Acquisition; and

disruption from the IRP Acquisition making it more difficult to maintain relationships with customers, employees or suppliers.

Any forward-looking statements are subject to the risks 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 those expressed or implied in such forward-looking statements. Any forward-looking statements are also subject to a number of assumptions regarding, among other things, future economic, competitive and market conditions generally. These assumptions would be based on facts and conditions as they exist at the time such statements are made as well as predictions as to future facts and conditions, the accurate prediction of which may be difficult and involve the assessment of events beyond our control.

We wish to caution readers that forward-looking statements, including disclosures which use words such as “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, and similar statements, are subject to certain risks and uncertainties which could cause actual results to differ materially from expectations. These risks and uncertainties include, but are not limited to, the following: a change in the demand for coal by electric utility customers, as well as the perceived benefits of alternative sources of energy; the loss of one or more of our largest customers; inability to secure new coal supply agreements or to extend existing coal supply agreements at market prices; our dependency on one railroad for transportation of a large percentage of our products; failure to exploit additional coal reserves; the risk that reserve estimates and pension, workers compensation and post-retirement benefit liabilities are inaccurate; failure to diversify our operations; increased capital expenditures; encountering difficult mining conditions; inherent complexities associated in mining in Central Appalachia including special dangers and risks of underground mining; increased costs of complying with mine health and safety regulations; bottlenecks or other difficulties in transporting coal to our customers; delays in the development of new mining projects; increased costs of raw materials; the effects of litigation, regulation and competition; lack of availability of financing sources; our compliance with debt covenants; the risk that we are unable to successfully integrate acquired assets into our business; and the risk factors set forth in this Annual Report on Form 10-K under Item 1A “Risk Factors.” These risks are representative of factors that could affect the outcome of the forward-looking statements. These and the other factors discussed elsewhere in this document are not necessarily all of the important factors that could cause our results to differ materially from those expressed in our forward-looking statements. Forward-looking statements speak only as of the date they are made and we undertake no obligation to update them.

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, a reduction in the demand for coal by this industry would likely cause our revenues and profitability to decline significantly.

We derived 88% of our total revenues (contract and spot) in 2010 and 92% of our total revenues in 2009, from our electric utility customers. Fuel cost is a significant component of the cost associated with coal-fired power generation, with respect to not only the price of the coal, but also the costs associated with emissions control and credits (i.e., sulfur dioxide, nitrogen oxides, etc.), combustion by-product disposal (i.e., ash) and equipment operations and maintenance (i.e., materials handling facilities). All of these costs must be considered when choosing between coal generation and alternative methods, including natural gas, nuclear, hydroelectric and others.

Weather patterns also can greatly affect electricity generation. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increased generating requirements from all sources. Mild temperatures, on the other hand, result in lower electrical demand, which allows generators to choose the lowest-cost sources of power generation when deciding which generation sources to dispatch. Accordingly, significant changes in weather patterns could reduce the demand for our coal.

Overall economic activity and the associated demands for power by industrial users can have significant effects on overall electricity demand. Downward economic pressures can cause decreased demands for power, by both residential and industrial customers.

Any downward pressure on coal prices, whether due to increased use of alternative energy sources, changes in weather patterns, decreases in overall demand or otherwise, would 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:

	•	currency exchange rates;
	•	growth of economic development;
	•	price of alternative sources of electricity;
	•	world wide demand; and
	•	ocean freight rates

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.

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.

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. During 2010, we shipped in excess of 90% of our coal from our Central Appalachia mines via CSX. In the Midwest, we shipped in excess of 65% of our produced coal by truck and the remainder via the rail system or by barge. We believe that our 2011 transportation modes will continue to be comparable to those used in 2010. Our dependence upon railroads and third party trucking companies impacts our ability to deliver coal to our customers. Disruption of service due to weather-related problems, 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.

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

	·	employee health and safety;
	·	permitting and licensing requirements;
	·	air quality standards;
	·	water quality standards;
	·	plant, wildlife and wetland protection;
	·	blasting operations;
	·	the management and disposal of hazardous and non-hazardous materials generated by mining operations;
	·	the storage of petroleum products and other hazardous substances;
	·	reclamation and restoration of properties after mining operations are completed;
	·	discharge of materials into the environment, including air emissions and wastewater discharge;
	·	surface subsidence from underground mining; and
	·	the effects of mining operations on groundwater quality and availability.

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.

The passage of legislation responsive to the Framework Convention on Global Climate Change or similar governmental initiatives could result in restrictions on coal use.

The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, which is intended to limit or capture emissions of greenhouse gases, such as carbon dioxide. In December 1997, the signatories to the convention established a potentially binding set of emissions targets for developed nations. Although the specific emissions targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. The U.S. Senate has not ratified the treaty commitments. The current administration could support the effort to ratify the treaty. With Russia’s ratification of the Kyoto Protocol in 2004, it became binding on all ratifying countries. The implementation of the Kyoto Protocol in the United States and other countries, and other emissions limits, such as those adopted by the European Union, could affect demand for coal inside and outside the United States. If the Kyoto Protocol or other comprehensive legislation or regulations focusing on greenhouse gas emissions is enacted by the United States, it could have the effect of restricting the use of coal. Other efforts to reduce emissions of greenhouse gases and federal initiatives to encourage the use of natural gas also may affect the use of coal as an energy source.

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 (such as the proposal discussed below in the risk factor “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”) 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) was enacted into law on March 23, 2010 and included 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 would be disabled due to pneumoconiosis and be eligible for black lung benefits. The new Act also makes it easier for widows of miners to become eligible for benefits. The enactment of this new legislation could significantly impact the Company’s future payments for black lung benefits.

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 and may also reduce future demand for 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. 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.

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 greenhouse gases fall within the Clean Air Act definition of “air pollutant,” the EPA was required to determine whether emissions of greenhouse gases “endanger” public health or welfare. In December 2009, the EPA published its finding that current and projected concentrations of carbon dioxide and five other greenhouse gases in the atmosphere threaten the public’s health and welfare. This finding enables the EPA to proceed with a broad regulatory program for the control of greenhouse gas emissions, including carbon dioxide emissions. The EPA has recently completed several rulemaking actions indicating its intent to do so, including, among others, a final greenhouse gas reporting rule for certain major stationary source permitting programs, final regulations to control greenhouse gas emissions from light duty vehicles, 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 greenhouse gas 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 greenhouse gases. 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.

In December 2009, approximately 190 countries participated in the United Nations Climate Change Conference in Copenhagen. The participants “took note” of a non-binding accord under which participating nations would report, by January 31, 2010, their commitments to reduce greenhouse gas emissions. Under this non-binding framework, the U.S. has committed to cut greenhouse gas emissions by 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050.

The permitting of new coal-fired power plants has also recently been contested by state regulators and environmental organizations based on concerns relating to greenhouse gas emissions. In addition, in September 2009, the United States Court of Appeals for the Second Circuit issued its decision in Connecticut v. AEP allowing plaintiffs’ claims that public utilities’ greenhouse gas emissions created a “public nuisance” to go to trial over defendants’ objections based upon political question, preemption and lack of standing. In December 2010, the U.S. Supreme Court granted certiorari review of this decision by the Second Circuit. The plaintiffs in this case are seeking various remedies, including injunctive relief. These cases expose other significant contributors to greenhouse gas emissions to similar litigation risk. The effect of these recent cases may be mitigated in the event Congress adopts greenhouse gas legislation and because the EPA has finalized the adoption of greenhouse gas emission standards. Nevertheless, increased efforts to control greenhouse gas emissions by state, federal, judicial or international authorities could result in reduced demand for coal.

The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion. As a result, they may switch to other fuels, which would affect the volume or price of our sales.

Coal contains impurities, including sulfur, nitrogen oxide, 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, and the volume and price of our coal sales. Stricter regulations could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future.

For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users may 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 other fuels. Each option has limitations. Lower sulfur coal may be more costly to purchase on an energy basis than higher sulfur coal depending on mining and transportation costs. 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 modification of existing plants.

In 2005, the EPA adopted federal rules intended to reduce the interstate transport of fine particulate matter and ozone through reductions in sulfur dioxides and nitrogen oxide emissions from certain sources throughout the eastern United States. The reductions were to be implemented in stages, some through a market-based cap-and-trade program. Such new regulations would likely require some power plants to install new equipment, at substantial cost, or discourage the use of certain coals containing higher levels of mercury. The particular rules introduced by the EPA in March 2005 were subsequently struck down by the U.S. Court of Appeals for the D.C. Circuit on July 11, 2008. On December 23, 2008, the U.S. Court of Appeals for the D.C. Circuit remanded consolidated cases to the EPA without vacatur of the Clean Air Interstate Rule in order that the EPA could remedy flaws in the Rule. In July 2010, the EPA issued a proposed Clean Air Transport Rule in response to the Court’s prior remand of the 2005 rule. The recently proposed rule calls for reductions of sulfur dioxides and nitrogen oxides that drift across state lines in phases beginning in 2012. New and proposed reductions in emissions of sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases may require the installation of additional costly control technology or the implementation of other measures, including trading of emission allowances and switching to other fuels. 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.

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). 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.

Prior to placing excess fill material in valleys in connection with surface mining operations, coal mining companies are required to obtain a permit from the U.S. Army Corps of Engineers (Corps) under Section 404 of the Clean Water Act (404 Permit). Previously, this 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. Recently, the Corps announced its decision to suspend the use of NWP 21 in a six state Appalachian region, including Kentucky, where we operate. Litigation respecting the issuance of certain Section 404 permits has also been ongoing for several years, focusing primarily on whether the Corps’ 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 Corps. 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 requiring additional review under the Clean Water Act. EPA oversight could further delay and/or restrict the issuance of such permits, either of which events could have an adverse impact on our planned mining 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, where we operate. If such levels of conductivity are permanently imposed, 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, has filed suit against the EPA and the Corps contesting the legality of the enhanced review process and the imposition of such conductivity standard. Recently, the U.S. District Court for the District of Columbia, before which this suit was brought, issued its opinion denying the EPA’s motion to dismiss the case on grounds that there was no final agency action, that the case was not ripe for adjudication and that the NMA lacked standing. The court also denied the NMA’s motion for a preliminary injunction of EPA’s exercise of such oversight and the imposition of such standard. The states of West Virginia and Kentucky, and the coal associations in those states, have also filed suits contesting these actions by the EPA.

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. At December 31, 2010, we had accrued $48.4 million related to estimated mine reclamation costs. 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.

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 and net losses in recent years and may experience losses in the future.

We experienced operating losses and net losses in each of the years ended December 31, 2008 and 2007. While we were profitable in the years ended December 31, 2010 and 2009, we must continue to carefully manage our business, including the balance of our long-term and short-term sales contracts and our production costs. Although we seek to balance our contract mix to achieve optimal revenues over the long term, the market price of coal is affected by many factors that are outside of our control. Our production costs have increased in recent years, and we expect higher costs to continue for the next several years. Additionally, certain of our long term contracts for sales of coal are priced substantially above current spot prices for coal. 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 loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.

For 2010, we generated approximately 88% of our total revenues from several long-term contracts and spot sales with electrical utilities, including 39% from South Carolina Public Service Authority, 32% from Georgia Power Company and 11% from Indianapolis Power and Light. At December 31, 2010, we had coal supply agreements with these customers that expire in 2011 to 2012. 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.

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:

	·	British thermal units (Btu’s);
	·	sulfur content;
	·	ash content;
	·	grindability; and
	·	ash fusion temperature.

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 purchase sulfur credits or 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 adjustment and other provisions may increase our exposure to short-term coal price volatility provided by those contracts. If a substantial portion of our coal supply agreements expire or are modified or terminated, we could be materially adversely affected to the extent that we are unable to find alternate buyers for our coal at the same level of profitability. As a result, we might not be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire or are modified or terminated.

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 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 exists and whether further action will be taken. No pattern of violations has been found to exist at any of our mines that have received such a notification. The failure to remediate the situation resulting in a finding that a pattern of violation does exist at a mine could have a significant impact on our operations, including the permanent or temporary closure of our mines.

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.

The Dodd-Frank Act includes new requirements for reporting certain mine safety information on a Form 8-K, and for including additional mine safety disclosures in our periodic reports filed with the SEC. Under the Dodd-Frank Act, the SEC is authorized to issue rules and regulations regarding mine safety disclosures, and the SEC has issued proposed rules as of the date of this Form 10-K. While the new rules are not yet in effect, such rulemaking by the SEC may cause us to incur additional costs in complying with the new reporting and disclosure requirements.

Unexpected increases in raw material costs could significantly impair our operating results.

Our coal mining operations use significant amounts of steel, petroleum products and other raw materials in various pieces of mining equipment, supplies and materials, including the roof bolts required by the room and pillar method of mining. Recently and historically, petroleum prices and other commodity prices have been volatile. If the price of steel or other of these materials increase, our operational expenses will increase, which could have a significant negative impact on our cash flow and operating results.

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 large part, in underground mines and, to a lesser extent, at 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:

variations in thickness of the layer, or seam, of coal;

variations in geological conditions;

amounts of rock and other natural materials intruding into the coal seam;

equipment failures and unexpected major repairs;

unexpected maintenance problems;

unexpected departures of one or more of our contract miners;

fires and explosions from methane and other sources;

accidental minewater discharges or other environmental accidents;

other accidents or natural disasters; and

weather conditions.

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.

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 2011, we anticipate less than 10% 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.

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 were initially based on studies conducted by Marshall Miller & Associates, Inc. in 2004 for our CAPP reserves 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:

	•	currently available geological, mining and property control data and maps;
	•	our own operational experience and that of our consultants;
	•	historical production from similar areas with similar conditions;
	•	previously completed geological and reserve studies;
	•	the assumed effects of regulations and taxes by governmental agencies; and
	•	assumptions governing future prices and future operating costs.

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

	•	mining activities;
	•	new engineering and geological data;
	•	acquisition or divestiture of reserve holdings; and
	•	modification of mining plans or mining methods.

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.

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. As of December 31, 2010, we had outstanding surety bonds with third parties for post-mining reclamation totaling $60.2 million. Furthermore, we have surety bonds for an additional $44.9 million in place for our federal and state workers’ compensation obligations and other miscellaneous obligations. 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.

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. Legislation has been proposed to the United States Congress to enact a law allowing our workers to choose union representation solely by signing election cards (“Card Check”), which would eliminate the use of secret ballots to elect union representation. While the impact is uncertain, if Card Check legislation is enacted into law, it will be administratively easier to unionize coal mines and may lead to more coal mines becoming unionized.

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. At December 31, 2010, the current and non-current portions of these obligations included $45.7 million for coal workers’ black lung benefits and $64.9 million for workers’ compensation benefits.

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.

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. As of December 31, 2010, we estimated that our obligation under the pension plan was underfunded by approximately $12.0 million. 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.

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.

Our current leverage amount may harm our financial condition and results of operations.

Our total consolidated long-term debt as of December 31, 2010 was $284.0 million (net of a discount on our convertible notes of $38.5 million), $150.0 million of which matures in June 2012. Our level of indebtedness could result in the following:

	•	it could affect our ability to satisfy our outstanding obligations;
	•	a substantial portion of our cash flows from operations will have to be dedicated to interest and principal payments and may not be available for operations, working capital, capital expenditures, expansion, acquisitions or general corporate or other purposes;
	•	it may impair our ability to obtain additional financing in the future;
	•	it may limit our flexibility in planning for, or reacting to, changes in our business and industry; and
	•	it may make us more vulnerable to downturns in our business, our industry or the economy in general.

Our operations may not generate sufficient cash to enable us to service our debt. If we fail to make a payment on our debt, this could cause us to be in default on our outstanding indebtedness. 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 expect that our indebtedness will increase in connection with the proposed acquisition of IRP.

We currently have $150 million of Senior Notes outstanding that are due in June 2012. There is no assurance that cash, future borrowings or equity financing will be available for the payment or refinancing of the Senior Notes at their maturity. If we are unable to refinance our indebtedness or obtain additional financing on favorable terms, we could face substantial liquidity pressures and might be required to sell material assets or operations to meet our debt service requirements.

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 revolving credit facility or result in an event of default under our debt instruments. Our debt instruments contain financial and other covenants that create limitations on our ability to, among other things, utilize the full amount on our revolver for borrowings or to issue letters of credit or incur additional debt, and require us to maintain various financial ratios and comply with various other financial covenants. The minimum Adjusted EBITDA and Leverage Ratio covenants are only applicable if our unrestricted cash falls below $75 million and remain in effect until our unrestricted cash exceeds $75 million for 90 consecutive days (the Trigger Event). As of December 31, 2010, our unrestricted cash was $180.4 million. These most restrictive covenants include the following:

If we have a Trigger Event, our revolving credit facility requires that we achieve a minimum Adjusted EBITDA, which is defined in that agreement as “Consolidated EBITDA”. Adjusted EBITDA is measured at the end of each quarter for the preceding 12 months. If measured, the required minimum Adjusted EBITDA would be $105.0 million during 2011. In order to meet the twelve month Adjusted EBITDA target at December 31, 2010, we needed Adjusted EBITDA of $105.0 million in the year ended December 31, 2010. Our Adjusted EBITDA for the year ended December 31, 2010 was $156.6 million. The most directly comparable US GAAP financial measure is net income. For the year ended December 31 2010, we had net income of $78.2 million. Adjusted EBITDA is defined and reconciled to EBITDA and Net Loss under “Reconciliation of Non-GAAP Measures” in Part I – Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.

If we have a Trigger Event, our revolving credit facility requires that our Leverage Ratio (as defined in the revolving credit facility) not exceed a specified multiple at the end of each quarter. If measured, the Leverage Ratio would be permitted to be 0.63X to 0.60X during 2011. Our Leverage Ratio was 0.38X as of December 31, 2010.

Our revolving credit facility limits the Capital Expenditures (as defined in the revolving credit facility) that we may make or agree to make in any fiscal year. For 2010, we were limited to Capital Expenditures of $100.0 million and we made actual Capital Expenditures of $95.4 million. For 2011, we cannot make Capital Expenditures in excess of $119.6 million which includes $4.6 million of unused Capital expenditures from 2010 that we are allowed to carry forward and use only in 2011 (where they shall be deemed to be spent last).

Additional detail regarding the terms of our revolving credit facility, 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.

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.

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 and southern Indiana. We will consider opportunities to further increase the percentage of coal that comes from surface mines. We may also consider opportunities to expand both surface and underground mining activities in areas that are outside of eastern Kentucky and southern Indiana. We may also consider opportunities in other energy-related areas that are not prohibited by the Indenture governing our senior notes due 2012 or other financing agreements. 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 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 revolving credit facility and cash generated from our operations will provide us with adequate liquidity through 2011. However, such funds 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

Our current reserve base in the Midwest is limited.

Our southern Indiana mining complex currently has rights to proven and probable reserves that we believe will be exhausted in approximately 14 years at 2010 levels of production, compared to our current Central Appalachia mining complexes, which have reserves that we believe will last an average of approximately 37 years at 2010 levels of production. We intend to increase our reserves in southern Indiana by acquiring rights to additional exploitable reserves that are either adjacent to or nearby our current reserves. If we are unable to successfully acquire such rights on acceptable terms, or if our exploration or acquisition activities indicate that such coal reserves or rights do not exist or are not available on acceptable terms, our production and revenues will decline as our reserves in that region are depleted. Exhaustion of reserves at particular mines also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines.

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 U.S. Army Corps of Engineers 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 the issuance of common stock in connection with the convertible notes issued in 2009, 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.

The IRP Acquisition may not be consummated, and if consummated, we may fail to realize the growth prospects and cost savings anticipated as a result of the IRP Acquisition.

There are a number of risks and uncertainties relating to the IRP Acquisition. For example, the IRP Acquisition may not be consummated or may not be consummated in the timeframe or manner currently anticipated, as a result of several factors, including, among other things, the failure of one or more of the conditions to closing. There can be no assurance that the conditions to closing of the IRP Acquisition will be satisfied or waived or that other events will not intervene to delay or result in the termination of the IRP Acquisition. Any delay in closing or a failure to close could have a negative impact on our business and stock price.

The success of the 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 will be complex and will require significant efforts and expenditures on the part of both us and IRP. 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 expected to result from the IRP Acquisition might not be met.

In addition, James River Coal Company and International Resource Partners have operated and, until the completion of the IRP Acquisition, will continue to operate, independently. 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 customers, employees or other third parties or our ability to achieve the anticipated benefits of the IRP Acquisition and could harm our financial performance.

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:

	•	variations in our quarterly operating results;
	•	changes in financial estimates by securities analysts;
	•	sales of shares of our common stock by our officers and directors or by our shareholders;
	•	changes in general conditions in the economy or the financial markets;
	•	changes in accounting standards, policies or interpretations;
	•	other developments affecting us, our industry, clients or competitors; and
	•	the operating and stock price performance of companies that investors deem comparable to us.

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.

Dividends are limited by our revolving credit facility, senior notes and convertible senior notes.

We do not anticipate paying any cash dividends on our common stock in the near future. In addition, covenants in our revolving credit facility, senior notes and convertible 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, 2010, we owned approximately 11,800 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:

mineral rights, which allows the controlling party to remove the minerals on the property;

surface rights, which allows the controlling party to use and disturb the surface of the property; and

fee control, which includes both mineral and surface rights.

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 in the Big Sandy, Hazard and Upper Cumberland coal districts of the Central Appalachian coal basin in eastern Kentucky and north central Tennessee. These three coal districts are located in the Appalachian Plateau structural and physiographic province. 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:

length of term;

renewal requirements;

minimum royalties;

recoupment provisions;

tonnage royalty rates;

minimum tonnage royalty rates;

wheelage rates;

usage fees; and

other factors.

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. [Removed and Reserved]

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.

	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Fiscal year ended December 31, 2010
High	$22.18	19.39	19.83	25.33
Low	$15.17	14.67	15.28	16.00
Fiscal year ended December 31, 2009
High	$18.30	24.11	21.15	22.31
Low	$9.09	12.62	13.50	17.20

Recent Sales of Unregistered Securities

We issued restricted shares of common stock and options to purchase common stock to the following persons or classes of persons, in reliance upon the exemption contained in Section 4(2) of the Securities Act of 1933, as follows:

Recipient

No.

Options

Date of

Issuance

Consideration

Option

Exercise

Price

Operating and senior management

282,622

April 21, 2010

Services rendered

N/A

Non-employee directors (aggregate)

5,000

20,000

April 21, 2010

Services rendered

$17.01

Holders

As of December 31, 2010, there were 139 record holders of our common stock.

Dividends

We did not pay any cash dividends on our common stock during the years ended December 31, 2010, 2009 or 2008. 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. The payment of cash dividends is also currently prohibited by our revolving credit facility, our convertible senior notes and our senior notes.

Securities Authorized for Issuance under Equity Compensation Plans

Please refer to note 7 of our December 31, 2010 consolidated financial statements for securities authorized to be issued under our 2004 Equity Incentive Plan.

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 for the period commencing on December 31, 2005 (the date the Company’s Common Stock began trading on the Nasdaq Global Market) and ending on December 31, 2010.

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.

	Year Ended December 31,
	2010			2009			2008			2007			2006
Consolidated Statement of Operations:
Revenues	$	701,116			681,558			568,507			520,560			564,791
Cost of coal sold		514,515			508,888			527,888			473,347			496,799
Gain on curtailment of pension plan		-			-			-			(6,091	)		-
Depreciation, depletion, and amortization		64,368			62,078			70,277			71,856			74,562
Gross profit (loss)		122,233			110,592			(29,658	)		(18,552	)		(6,570	)

Selling, general, and administrative expenses		38,347			39,720			34,992			32,191			30,867
Operating income (loss)		83,886			70,872			(64,650	)		(50,743	)		(37,437	)

Interest expense		29,943			17,057			17,746			19,764			16,782
Interest income		(683	)		(60	)		(469	)		(471	)		(366	)
Charges associated with repayment and amendment of debt		-			1,643			15,618			2,421			-
Miscellaneous (income) expense, net		27			(281	)		(1,279	)		(598	)		(533	)
Income tax expense (benefit)		(23,566	)		1,559			(273	)		(17,844	)		(27,151	)

Net income (loss)	$	78,165			50,954			(95,993	)		(54,015	)		(26,169	)

Basic earnings (loss) per common share:		2.82			1.85			(3.91	)		(3.29	)		(1.65	)
Diluted earnings (loss) per common share:		2.82			1.85			(3.91	)		(3.29	)		(1.65	)

	December 31,
	2010		2009		2008			2007			2006
	(in thousands, except per share, per ton and number of employees information)
Consolidated Balance Sheet Data:
Working capital (deficit)	$	191,625		109,998		(54,961	)		(8,471	)		(2,589	)
Property, plant, and equipment, net		385,652		354,088		344,848			319,204			337,780
Total assets		784,569		669,312		463,546			439,287			451,254
Long term debt, including current portion		284,022		278,268		168,000			188,800			167,493
Total shareholders’ equity		247,383		170,342		65,238			69,774			86,397

	Year Ended December 31
	2010			2009			2008			2007			2006
Consolidated Statement of Cash Flow Data:
Net cash provided by (used in) operating activities	$	169,062			27,559			(1,576	)		4,022			31,680
Net cash used in investing activities		(95,344	)		(72,010	)		(73,589	)		(49,201	)		(54,738	)
Net cash provided by financing activities		(1,273	)		149,058			73,076			48,785			15,929

Supplemental Operating Data:
Tons sold		8,919			9,623			11,383			12,049			13,128
Tons produced		8,910			9,877			11,355			12,051			13,054
Revenue per ton sold (a)	$	78.61			70.83			49.94			42.63			42.67
Number of employees		1,746			1,736			1,751			1,681			1,742
Capital expenditures	$	95,426			72,159			74,697			49,343			62,507

(a)	Revenue per ton sold in 2007 and 2006 excludes synfuel handling revenue.

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.

Overview

We mine, process and sell bituminous, steam- and industrial-grade coal through six operating subsidiaries (“mining complexes”) located throughout eastern Kentucky and in southern Indiana. We have two reportable business segments based on the coal basins in which we operate (Central Appalachia (CAPP) and the Midwest (Midwest)). We derived 88% of our total revenues (contract and spot) in 2010 from coal sales to electric utility customers and the remaining 12% from coal sales to industrial and other customers. In 2010, our mines produced 8.8 million tons of coal (including 0.1 million tons of contract coal) and we purchased another 0.1 million tons for resale. Of the 8.8 million tons produced from Company mines, approximately 65% came from underground mines, while the remaining 35% came from surface mines. In 2010, we generated revenues of $701.1 million and net income of $78.2 million.

On March 6, 2011, we signed a definitive agreement to purchase IRP and its subsidiary companies for $475 million in an all-cash transaction. We have secured $375 million in committed bridge financing from Deutsche Bank and UBS, which in addition to existing cash balances, is expected to be sufficient to finance the purchase price for IRP. Rather than borrow under the committed financing, we may seek to issue common stock, convertible notes, senior notes or other securities in one or more public or private offerings in connection with the proposed acquisition. There can be no assurance that we will undertake or complete any such financing transaction.

CAPP Segment

In Central Appalachia, the majority of our coal is primarily sold 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. According to the most recent information available from the US Energy Information Administration (EIA), in 2009 the South Atlantic region consumed 149 million tons of coal or about 16% of all coal for electric generation in the United States. We have been providing coal to customers in the South Atlantic region since our formation in 1988. In 2010, South Carolina Public Service Authority and Georgia Power Company were our largest customers, representing approximately 39% and 32% of our total revenues, respectively. No other CAPP customer accounted for more than 10% of our total revenues.

According to the EIA, coal production for Eastern Kentucky and West Virginia was 210 million tons in 2009. During 2010, our CAPP segment shipped 6.1 million tons of coal. As of December 31, 2010, we estimate that we controlled approximately 230.4 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, we estimate that these reserves have an average heat content of 13,300 Btu per pound and an average sulfur content of 1.3%. At current production levels, we believe these reserves would support approximately 37 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. According to the EIA, in 2009 the East North Central Region consumed about 218 million tons of coal or 23% of all coal consumed for electric generation in the United States. In 2010, our Midwest segment’s largest customer, Indianapolis Power and Light, represented approximately 11% of our total revenues. No other Midwest customer accounted for more than 10% of our total revenues.

During 2010, our Midwest segment shipped 2.8 million tons of coal. We believe that coal-fired electric utilities and industrial customers value the high energy coal that comprises the majority of our Midwest reserves. As of December 31, 2010, we estimate that we controlled approximately 40.9 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 approximately 14 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 completed their report on our CAPP reserves in June 2004. For the Triad properties, MM&A also prepared a detailed study of Triad’s reserves as of February 1, 2005 for the reserves obtained in the acquisition of Triad and as of April 11, 2006 for certain additional reserves acquired in the second quarter of 2006. 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 and Triad using standards accepted by government and industry. We have used MM&A’s March 31, 2004 study 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.

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, 2010, we estimate that, as of December 31, 2010, we controlled approximately 230.4 million tons of proven and probable coal reserves in the CAPP region and 40.9 million tons in the Midwest region. The following table provides additional information regarding changes to our reserves for the year ended December 31, 2010 (in millions of tons):

	CAPP			Midwest			Total

Proven and Probable Reserves, as of December 31, 2009 (1)		231.2			39.9			271.1
Coal Extracted		(6.1	)		(2.8	)		(8.9	)
Acquisitions (2)		0.8			-			0.8
Adjustments (3)		5.1			3.8			8.9
Divestitures (4)		(0.6	)		-			(0.6	)
Proven and Probable Reserves, as of December 31, 2010 (1)		230.4			40.9			271.3

(1) Calculated in the same manner, and based on the same assumptions and qualifications, as used in the MM&A studies described above, but these estimates have not been reviewed by MM&A. Proven reserves have the highest degree of geologic assurance and are reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings, or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspections, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. Probable reserves have a moderate degree of geologic assurance and are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation. This reserve information reflects recoverable tonnage on an as-received basis with 5.5% moisture.

(2) Represents estimated reserves on leases entered into or properties acquired during the relevant period. We calculated the reserves in the same manner, and based on the same assumptions and qualifications, as used in the MM&A studies described above, but these estimates have not been reviewed by MM&A.

(3) Represents changes in reserves due to additional information obtained from exploration activities, production activities or discovery of new geologic information. We calculated the adjustments to the reserves in the same manner, and based on the same assumptions and qualifications, as used in the MM&A studies described above, but these estimates have not been reviewed by MM&A.

(4) Represents changes in reserves due to expired or transferred leases.

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 and certain bank fees. See “Other Supplemental Information — Reconciliation of Non-US GAAP Measures.”

Trends In Our Business

Near-term, the global economic slowdown has lowered demand for coal which has resulted in a decline in spot coal prices. The price of spot coal has also been impacted by a decrease in the price of competing fuel sources including natural gas. The coal industry has made cutbacks in supply in response to the decrease in demand for coal and has experienced additional declines due to a number of regulatory factors. Due to the uncertainties in the global market place, we are unable to forecast the price or demand for coal over the next few years. Long-term, we believe that the demand for coal worldwide will continue to be strong and that supply challenges will continue in the regions that we mine coal. We also believe that in the United States coal will continue to be one of the most economical energy sources. A number of factors beyond our control impact coal prices, including:

the supply of domestic and foreign coal;

the demand for electricity;

the demand for steel and the continued financial viability of the domestic and foreign steel industries;

the cost of transporting coal to the customer;

domestic and foreign governmental regulations and taxes;

world economic conditions

air emission standards for coal-fired power plants; and

the price and availability of alternative fuels for electricity generation.

As discussed previously, our costs of production 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.

Our business is very sensitive to changes in supply and demand for coal and we carefully manage our mines to maximize operating results. As our current long term contracts are fulfilled, our profitability in the future will be impacted by the price levels that we achieve on future long term contracts. Events beyond our control could impact our profit margins.

Results of Operations

Year Ended December 31, 2010 Compared with the Year Ended December 31, 2009

The following table shows selected operating results for 2010 and 2009 (in thousands, except per ton amounts):

	Year Ended December 31,
	2010				2009				Change
	Total		Per Ton		Total		Per Ton		Total
Volume Shipped (tons)		8,919				9,623				-7	%

Coal sales revenue	$	701,116	$	78.61	$	681,558	$	70.83		3	%
Cost of coal sold		514,515		57.69		508,888		52.88		1	%
Depreciation, depletion and amortization		64,368		7.22		62,078		6.45		4	%
Gross profit		122,233		13.70		110,592		11.49		11	%
Selling, general and administrative		38,347		4.30		39,720		4.13		-3	%

Volume and Revenues by Segment

	Year Ended December 31,
	2010				2009

	CAPP		Midwest		CAPP		Midwest

Volume Shipped (tons)		6,109		2,810		6,525		3,098

Coal sales revenue	$	585,064	$	116,052	$	579,108	$	102,450

Average sales price per ton		95.77		41.30		88.75		33.07

In 2010, we shipped 8.9 million tons of coal compared to 9.6 million tons in 2009. Coal sales revenue increased from $681.6 million in 2009 to $701.1 million in 2010. This increase was due to an increase in the average sales price per ton in the CAPP and Midwest regions, which was partially offset by a decrease in tons shipped in the CAPP and Midwest regions.

In 2010, the CAPP region sold approximately 4.8 million tons of coal under long-term contracts (79% of total CAPP sales volume) at an average selling price of $103.14 per ton. In 2009, the CAPP region sold approximately 6.0 million tons of coal under long-term contracts (92% of total CAPP sales volume) at an average selling price of $89.55 per ton. In 2010, the CAPP region sold 1.3 million tons of coal (21% of total CAPP sales volume) under short term contracts (includes spot sales) at an average selling price of $67.42 per ton. In 2009, the CAPP region sold 0.5 million tons of coal (8% of total CAPP sales volume) under short term contracts (includes spot sales) at an average selling price of $79.31 per ton.

The Midwest’s region sales of coal were primarily sold under long term contracts for both 2010 and 2009. In 2010, the Midwest region sold 2.8 million tons at an average sales price of $41.30 per ton. In 2009, the Midwest region sold 3.1 million tons at an average sales price of $33.07 per ton.

Cost of Coal Sold

	Year Ended December 31,
	2010						2009

	CAPP		Midwest		Corporate		CAPP		Midwest		Corporate

Cost of Coal Sold	$	419,564	$	94,951	$	-	$	416,721	$	92,167	$	-

Per ton		68.68		33.79		-		63.87		29.75		-

Depreciation, depletion, and amortization		53,467		10,840		61		49,380		12,646		52

Per ton		8.75		3.86		-		7.57		4.08		-

The cost of coal sold, excluding depreciation, depletion and amortization, increased from $508.9 million in 2009 to $514.5 million in 2010. Our cost per ton of coal sold in the CAPP region increased from $63.87 per ton in 2009 to $68.68 per ton in the 2010. Our costs continue to be impacted by lower productivity due to increased federal and state regulatory scrutiny and a decrease in tons produced in response to market conditions. The major components of the $4.81 per ton increase in the cost per ton of coal sold from 2009 to 2010 include an increase in our labor and benefit costs of $1.71 per ton, sales related costs of $1.48 per ton and variable costs of $0.74 per ton. 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 $4.04 per ton from $29.75 in the 2009 period to $33.79 per ton in the 2010 period. The major components of this increase include an increase in the variable costs of $1.63 per ton, labor and benefit costs of $0.82 per ton, and sales related costs of $0.83 per ton. The increase in the variable costs was primarily due to an increase in diesel and explosives costs.

Depreciation, depletion and amortization

Depreciation, depletion and amortization increased from $62.1 million in 2009 to $64.4 million in 2010. In the CAPP region, depreciation, depletion and amortization increased $4.1 million to $53.5 million or $8.75 per ton. In the Midwest, depreciation, depletion and amortization decreased $1.8 million to $10.8 million or $3.86 per ton.

Selling, general and administrative

Selling, general and administrative expenses decreased from $39.7 million in 2009 to $38.3 million in 2010. This decrease was primarily due to a decrease in bank fees associated with the issuance of letters of credit.

Interest Expense

Interest expense increased from $17.1 million in 2009 to $29.9 million in 2010. This increase was the result of additional interest expense associated with our convertible senior notes that were issued in the fourth quarter of 2009. During 2010 and 2009, we recorded $13.5 million and $1.4 million of interest expense, respectively, on our convertible senior notes, including $5.8 million and $0.6 million, respectively, related to the non-cash amortization of the debt discount recorded on this issuance.

Income Taxes

Our effective tax (benefit) rates for 2010 and 2009 were (43.2%) and 3.0%, respectively. Our effective income tax rate, as compared to the statutory federal rate, is impacted primarily by the amount of the valuation allowance recorded against our deferred tax assets, including our net operating loss carryforwards, and percentage depletion. 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%). As described further in “Critical Accounting Estimates – Income Taxes,” the reversal of our income tax valuation allowance, during 2010, was the result of the conclusion that our deferred tax assets that were previously reduced by a valuation allowance were more likely than not to ultimately be realizable. In making this conclusion we considered our forecasts of future taxable income and other relevant factors, including a history of recent positive operating results. For 2009 our effective tax rate was reduced from the statutory federal tax rate primarily by percentage depletion (25.8%) and a change in the valuation allowance (6.2%).

As of December 31, 2010, we had no valuation allowance against gross deferred tax assets based on the conclusion that our deferred tax assets, including our net operating loss carryforwards, are more likely than not to be realized. The criteria for recording a valuation allowance are described in “Critical Accounting Estimates – Income Taxes.” 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.

Results of Operations

Year Ended December 31, 2009 Compared with the Year Ended December 31, 2008

The following table shows selected operating results for 2009 and 2008 (in thousands, except per ton amounts):

	Year Ended December 31,
	2009				2008						Change
	Total		Per Ton		Total			Per Ton			Total
Volume Shipped (tons)		9,623				11,383						-15	%

Coal sales revenue	$	681,558	$	70.83	$	568,507		$	49.94			20	%
Cost of coal sold		508,888		52.88		527,888			46.38			-4	%
Depreciation, depletion and amortization		62,078		6.45		70,277			6.17			-12	%
Gross profit (loss)		110,592		11.49		(29,658	)		(2.61	)		N/A
Selling, general and administrative		39,720		4.13		34,992			3.07			14	%

Volume and Revenues by Segment

	Year Ended December 31,
	2009				2008

	CAPP		Midwest		CAPP		Midwest

Volume Shipped (tons)		6,525		3,098		8,271		3,112

Coal sales revenue	$	579,108	$	102,450	$	467,609	$	100,898

Average sales price per ton		88.75		33.07		56.54		32.42

In 2009, we shipped 9.6 million tons of coal compared to 11.4 million tons in 2008. Coal sales revenue increased from $568.5 million in 2008 to $681.6 million in 2009. This increase was due to an increase in the average sales price per ton in the CAPP region, which was partially offset by a decrease in tons shipped in the CAPP region.

In 2009, the CAPP region sold approximately 6.0 million tons of coal under long-term contracts (92% of total CAPP sales volume) at an average selling price of $89.55 per ton. In 2008, the CAPP region sold approximately 4.6 million tons of coal under long-term contracts (56% of total CAPP sales volume) at an average selling price of $52.52 per ton. In 2009, the CAPP region sold 0.5 million tons of coal (8% of total CAPP sales volume) under short term contracts (includes spot sales) at an average selling price of $79.31 per ton. In 2008, the CAPP region sold 3.7 million tons of coal (44% of total CAPP sales volume) under short term contracts (includes spot sales) at an average selling price of $61.62 per ton.

The Midwest’s region sales of coal were primarily sold under long term contracts for both 2009 and 2008. In 2009, the Midwest region sold 3.1 million tons at an average sales price of $33.07 per ton. In 2008, the Midwest region sold 3.1 million tons at an average sales price of $32.42 per ton.

Cost of Coal Sold

	Year Ended December 31,
	2009						2008

	CAPP		Midwest		Corporate		CAPP		Midwest		Corporate

Cost of Coal Sold	$	416,721	$	92,167	$	-	$	433,781	$	94,107	$	-
Per ton		63.87		29.75		-		52.45		30.24		-

Depreciation, depletion, and amortization		49,380		12,646		52		55,979		14,218		80
Per ton		7.57		4.08		-		6.77		4.57		-

The cost of coal sold, excluding depreciation, depletion and amortization, decreased from $527.9 million in 2008 to $508.9 million in 2009 due to less tons sold. Our cost per ton of coal sold in the CAPP region increased from $52.45 per ton in 2008 to $63.87 per ton in 2009. This $11.42 increase in cost per ton of coal sold was primarily the result of lower productivity due to increased federal and state regulatory scrutiny which caused an increase in labor costs as compared to prior year, a decrease in tons produced in response to market conditions, an increase in machine parts and repairs costs, and the impact of increased average sales prices on our sales related costs (primarily royalties and severance taxes). The major components of this increase include an increase in the Company’s sales related costs of $4.32 per ton, labor and benefit costs of $2.74 per ton, preparation and loading costs of $1.86 per ton and variable mine costs of $1.45 per ton. 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 decreased $0.49 per ton from $30.24 per ton in 2008 period to $29.75 per ton in 2009. The decrease in cost per ton of coal sold was due to a $1.63 per ton decrease in variable costs, offset by a $0.91 per ton increase in preparation plant costs. The decrease in the variable costs was primarily due to a decrease in diesel and explosives costs.

Depreciation, depletion and amortization

Depreciation, depletion and amortization decreased from $70.3 million in 2008 to $62.1 million in 2009. In the CAPP region, depreciation, depletion and amortization decreased $6.6 million to $49.4 million or $7.57 per ton. In the Midwest, depreciation, depletion and amortization decreased $1.6 million to $12.6 million or $4.08 per ton.

Selling, general and administrative

Selling, general and administrative expenses increased from $35.0 million in 2008 to $39.7 million in 2009. The increase was primarily due to higher letter of credit fees, and an increase in certain salary and benefit amounts. The increase in the letter of credit fees is due to an increase in the usage fee under our Letter of Credit Facility.

Charges associated with repayment and amendment of debt

In 2009, we expensed $1.6 million in 2009 in connection with a fee to terminate a letter of credit facility.

In 2008, we expensed approximately $13.3 million of costs associated with the various credit amendments. Additionally, we wrote-off approximately $2.4 million of unamortized financing charges.

Income Taxes

Our effective tax (benefit) rates for 2009 and 2008 were 3.0% and (0.3%), respectively. Our effective income tax rate is impacted primarily by the amount of the valuation allowance recorded against our deferred tax assets including our net operating loss carryforwards and percentage depletion. For 2009 our effective tax rate was decreased by 25.8% for percentage depletion. In 2008, our effective tax benefit rate was increased by 3.8% for percentage depletion. For 2009 our effective rate was decreased by 6.2% and our effective tax benefit rate 39.2%, for a change in the valuation allowance. As of December 31, 2009, we had a $33.2 million valuation allowance against gross deferred tax assets based on the conclusion that the net operating loss was, at that time, not more likely than not to be realized. The criteria for recording a valuation allowance are described in “Critical Accounting Estimates – Income Taxes. In 2009, the effective tax rate was positively impacted by a reduction in the valuation allowance due to the generation of taxable income and the utilization of a portion of the net operating loss carryforwards. 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, 2010 and 2009 (in thousands):

	2010		2009
Senior Notes	$	150,000	$	150,000
Convertible Senior Notes, net of discount		134,022		128,268
Revolver		-		-
Total long-term debt		284,022		278,268
Less amounts classified as current		-		-
Total long-term debt, less current maturities	$	284,022	$	278,268

Senior Notes and Convertible Senior Notes

There have been no changes to the terms of our Senior Notes or Convertible Senior Notes during 2010. See Item 15 of Part IV, “Financial Statements — Note 4 — Long Term Debt and Interest Expense” for a description of our Senior Notes and Convertible Senior Notes.

Revolving Credit Agreement

In January 2010, we amended and restated our existing Revolving Credit Agreement (as amended and restated the Revolving Credit Agreement is referred to as the Revolver). The following is a summary of significant terms of the Revolver.

Maturity	February 2012
Interest/Usage Rate	Company’s option of Base Rate(a) plus 3.0% or LIBOR plus 4.0% per annum
Maximum Availability	Lesser of $65.0 million or the borrowing base (b)
Periodic Principal Payments	None

	(a)	Base rate is the higher of (1) the Federal Fund Rate plus 3.0%, (2) the prime rate and (3) a LIBOR rate plus 1.0%.
	(b)	The Revolver’s borrowing base is based on the sum 85% of the Company’s eligible accounts receivable plus 65% of the eligible inventory minus reserves from time to time set by the administrative agent. The eligible accounts receivable and inventories are further adjusted as specified in the agreement. The Company’s borrowing base can also be increased by 95% of any cash collateral that the Company maintains in a cash collateral account.

The Revolver provides that we can use the Revolver availability to issue letters of credit. The Revolver provides for a 4.25% fee on any outstanding letters of credit issued under the Revolver and a 0.5% fee on the unused portion of the Revolver. The Revolver requires certain mandatory prepayments from certain asset sales, incurrence of indebtedness and excess cash flow. The Revolver includes financial covenants that require the Company to maintain a minimum Adjusted EBITDA and a maximum Leverage Ratio and limit capital expenditures, each as defined by the agreement. However, the minimum Adjusted EBITDA and maximum Leverage Ratio covenants are only applicable if our unrestricted cash balance falls below $75.0 million and would remain in effect until the our unrestricted cash exceeds $75.0 million for 90 consecutive days.

As of December 31, 2010, we had used $58.8 million of the $65.0 million available under the Revolver to secure outstanding letters of credits.

We were in compliance with all of the financial covenants under our outstanding debt instruments as of December 31, 2010. 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 the Facilities, 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, 2010, we had total liquidity of approximately $186.6 million, consisting of $6.2 million of unused borrowing capacity under the Revolver and $180.4 million of cash and cash equivalents (excluding restricted cash and short term investments). As of December 31, 2010, we have used $58.8 million of the Revolver’s availability to secure outstanding letters of credits.

Our primary source of cash is expected to be sales of coal to our utility and industrial 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 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.

Additionally, on March 6, 2011, we signed a definitive agreement to purchase IRP and its subsidiary companies for $475 million in an all-cash transaction. We have secured $375 million in committed financing from Deutsche Bank and UBS, which in addition to existing cash balances, is expected to be sufficient to finance the purchase price for IRP. Rather than borrow under the committed financing, we may seek to issue common stock, convertible notes, senior notes or other securities in one or more public or private offerings in connection with the proposed acquisition. There can be no assurance that we will undertake or complete any such financing transaction.

We believe that cash generated from operations, borrowings under our credit facilities and future debt and equity offerings, if any, will be sufficient to complete the proposed acquisition of IRP and to meet working capital requirements, anticipated capital expenditures, and scheduled debt payments throughout 2011 and for the next several years. Nevertheless, our ability to satisfy our working capital requirements and debt service obligations, or fund planned capital expenditures, will substantially depend upon our future operating performance (which will be affected by prevailing economic conditions in the coal industry), debt covenants, and financial, business and other factors, some of which are beyond our control. We expect that our indebtedness will increase in connection with the proposed acquisition of IRP. Additionally, we have $150 million of Senior Notes outstanding that are due in June 2012. There is no assurance that cash, future borrowings or equity financing will be available for the payment or refinancing of the Senior Notes at their maturity. If we are unable to refinance our indebtedness or obtain additional financing on favorable terms, we could face substantial liquidity pressures and might be required to sell material assets or operations to meet our debt service requirements.

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 Convertible Senior Notes, 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.

Currently, our primary use of cash during the next several years is expected to be ordinary course of business expenses, capital expenditures for existing mines and the repayment our Senior Notes which mature in June 2012. We currently project that our capital expenditures for 2011 will be approximately $115 million. Our projected capital expenditures primarily consist of capital expenditure for normal mining activities including new and replacement mine equipment. Our projected capital expenditures for 2011 also include approximately $30 million for safety mandates and new mine and infrastructure development. We expect that such expenditures will be funded through cash on hand and cash generated by operations.

Net cash provided by or used in operating activities reflects net income or net 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 $169.1 million and $27.6 million in 2010 and 2009, respectively. We had net income of $78.2 million in 2010 as compared to net income of $51.0 million in 2009. During 2010, our net income, as adjusted for non cash charges was decreased by a $31.7 million decrease in cash from our operating assets and liabilities. The $31.7 million change in our operating assets and liabilities for 2010, includes a $38.5 million decrease in restricted cash and short term investments, a $16.7 million increase in accounts receivables and a $10.9 million increase in accounts payable. During 2009, our net income, as adjusted for non cash charges was decreased by a $96.6 million decrease in cash from our operating assets and liabilities. The $96.6 million change in our operating assets and liabilities for 2009, includes a $56.8 million increase in restricted cash and short term investments to secure our letters of credit, a $10.0 million increase in accounts receivables, a $15.0 million increase in inventories and a $10.6 million decrease in accounts payable.

Net cash used by investing activities increased $23.3 million to $95.3 million for 2010, as compared to 2009. Capital expenditures were $95.4 million in 2010 and $72.2 million in 2009. 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 2010, our capital expenditures also included approximately $30.0 million for safety mandates and new mine and infrastructure development.

Net cash used by financing activities was $1.3 million in 2010 and consisted primarily of debt issuance costs on the amendment to the Revolver. During 2009 net cash provided by financing activities was $149.1 million and consisted primarily of the receipt of $167.0 million of net proceeds from our Convertible Senior Notes and $18.0 million of payments on our revolving credit facility.

Contractual Obligations

The following is a summary of our contractual obligations and commitments as of December 31, 2010:

	Payment Due by Period (in thousands)

Contractual Obligations	Total		2011		2012-2013		2014-2015		Thereafter
Long term debt (1)	$	322,500		-		150,000		172,500		-
Cash interest on long term debt and fees under our Revolver for letters of credit (2)		63,129		24,587		23,017		15,525		-
Operating lease obligations(3)		12,730		7,393		4,609		728		-
Royalty obligations(4)		214,949		25,042		47,020		42,236		100,651
Purchase obligations(5)