James River Coal CO - FORM 10-K

Attached files

file	filename
EX-32.1 - CERTIFICATION - James River Coal CO	jrcc_10k-ex3201.htm
EX-10.8 - AGREEMENT NO. 2 FOR PURCHASE AND SALE OF COAL - James River Coal CO	jrcc_10k-ex1008.htm
EX-12.1 - COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - James River Coal CO	jrcc_10k-ex1201.htm
EX-23.2 - CONSENT - James River Coal CO	jrcc_10k-ex2302.htm
EX-31.1 - CERTIFICATION - James River Coal CO	jrcc_10k-ex3101.htm
EX-23.1 - CONSENT - James River Coal CO	jrcc_10k-ex2301.htm
EX-32.2 - CERTIFICATION - James River Coal CO	jrcc_10k-ex3202.htm
EX-31.2 - CERTIFICATION - James River Coal CO	jrcc_10k-ex3102.htm
EX-10.8A - FIRST AMENDMENT TO AGREEMENT NO. 2 FOR PURCHASE AND SALE OF COAL - James River Coal CO	jrcc_10k-ex1008a.htm
EX-10.9A - FUEL SUPPLY AGREEMENT - James River Coal CO	jrcc_10k-ex1009a.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, 2009	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 o

Smaller Reporting Company o

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

The aggregate market value of 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, 2009 as reported on the Nasdaq Global Market, was approximately $336,982,000 (affiliates being, for these purposes only, directors, executive officers and holders of more than 10% of the registrant’s Common Stock).

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes ý No o

The number of shares of the registrant’s Common Stock, par value $.01 per share, outstanding as of February 15, 2010 was 27,544,878.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the registrant’s 2010 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	31
Item 2.	Properties	31
Item 3.	Legal Proceedings	32
Item 4.	Submission of Matters to a Vote of Security Holders	32
PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters
	and Issuer Purchases of Equity Securities	33
Item 6.	Selected Financial Data	34
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	34
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	54
Item 8.	Financial Statements and Supplementary Data	54
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	54
Item 9A.	Controls and Procedures	54
Item 9B.	Other Information	55

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	56
Item 11.	Executive Compensation	56
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
	Matters	56
Item 13.	Certain Relationships and Related Transactions, and Director Independence	56
Item 14.	Principal Accountant Fees and Services	56
PART IV

Item 15.	Exhibits, Financial Statement Schedules	57

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 SEC. 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.

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, 2009, our six mining complexes included 14 underground mines, 10 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, 2009, we believe that we controlled approximately 271.1 million tons of proven and probable coal reserves. At current production levels, we believe these reserves would support greater than 27 years of production.

In 2009, we produced 9.8 million tons of coal (including 0.3 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 9.5 million tons we produced from Company-operated mines, approximately 66% came from underground mines, while the remaining 34% came from surface mines. In 2009, we generated revenues of $681.6 million and had net income of $51.0 million. Approximately 92% of our 2009 revenues were generated from coal sales to electric utility companies and the remainder came from coal sales to industrial and other companies. In 2009, Georgia Power Company and South Carolina Public Service Authority were our largest customers, representing approximately 39% and 37% 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 2009:

	Tons (000s)	Percentage of total coal obtained by the Company
Coal produced from Company-operated mines	9,448	95.6%
Coal obtained from mines operated by independent contractors	322	3.3%
Coal purchased from third parties	107	1.1%
	9,877	100%

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 either 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. Reserve recovery using this method of mining is typically approximately 70%.

As of December 31, 2009, we had 10 surface mines one 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, 2009, we had 14 Company-operated underground mines in operation, of which 11 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 8.7% and 3.1% of produced coal revenue for the year ended December 31, 2009 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, 2009:

	Number and Type of Mines				Quality of Shipments for the year ended 2009
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	452	1.4	8.3	12,973
Bledsoe Coal Corporation	4	-	4	1,465	1.6	10.6	12,543
Blue Diamond Coal Corporation	3	1S/1HW (1)	4	1,704	1.0	8.8	12,827
Leeco, Inc.	1	2S /1HW (1)	3	1,281	0.8	9.4	12,930
McCoy Elkhorn Coal Corporation	3	1S	4	1,623	1.6	8.4	12,880

Midwest
Triad Mining, Inc	1	6S	7	3,098	3.1	8.7	11,294

(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 Garmedia 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, 2009, we employed 118 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, 2009, we employed 334 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 mine and we use the contour and highwall method for our surface mine. We mine the Hazard #4 and Elkhorn #3 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, 2009, we employed 313 mining and support personnel at this complex.

Leeco. The Leeco complex is located in Knott and Perry counties in eastern Kentucky. Our underground mines use room and pillar mining and our surface mine uses 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, 2009, we employed 254 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 mining methods. We mine the Millard, Elkhorn #2 and Elkhorn #3 seams at this complex. Coal is processed at one of our two preparation plants and loaded into railcars via integrated four-hour unit train loadouts on the CSX railroad. As of December 31, 2009, we employed 376 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, 2009, we employed approximately 288 mining and support personnel at this complex.

Contract mining represented approximately 3.3% of our coal production in the year ended December 31, 2009. 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 15.8 million tons of reserves acquired in the second quarter of 2006 (collectively, the “MM&A studies”). 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, 2009 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 and plan to update our third party reserve study from time to time. 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, 2009, we estimated that we controlled approximately 231.2 million tons of proven and probable coal reserves in Central Appalachia and 39.9 millions 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), MM&A’s 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, 2009 (1),(4)	Estimated Years of Reserve Life Based on 2009 Production Levels	Ash Content (%)	Heat Value (Btu/lb.)
Central Appalachia	(millions of tons)
Bell County	10.2	23.1	5.1	13,500

Bledsoe	54.2	36.3	7.8	13,000

Blue Diamond	78.3	44.1	4.7	13,700

Leeco	52.8	40.1	7.0	13,200

McCoy Elkhorn	35.7	20.0	5.7	13,300

Total/Average	231.2	34.3	6.3	13,300

Midwest
Triad	39.9	12.8	8.8	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; 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)

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, 2009 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, 2009 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 purchaser. 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 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 is sold f.o.b. the railcar at the point of loading, with transportation costs normally borne by the purchaser. 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 2009, we generated approximately 91% of our total revenues from long-term contracts to sell coal to electric utilities. For the year ended December 31, 2009, Georgia Power Company (39%) and South Carolina Public Service Authority (37%) were our largest customers by revenues. No other customer accounted for more than 10% of revenues.

In 2009, we sold approximately 6.5 million tons of coal in the CAPP region at an average selling price of $88.75 per ton. In the CAPP region, we currently have approximately 5.9 million and 2.4 million tons sold in 2010 and 2011, respectively, at average selling prices in excess of our 2009 average selling price. Current market prices for coal in the CAPP region are substantially below our average 2009 sales price. If the market does not strengthen, our sales price for future tons sold will be adversely impacted.

In 2009, we sold approximately 3.1 million tons of coal in the Midwest region at an average selling price of $33.07 per ton. In the Midwest region, we currently have approximately 2.9 million and 1.4 million tons sold in 2010 and 2011, respectively, at average selling prices in excess of our 2009 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 then 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 are 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 buyer, 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 17.1% (based on tonnage produced) of the total United States production in 2008, the latest year for which government statistics are available. The U.S. Department of Energy also reported 1,458 active coal mines in the United States in 2008. 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, 2009, we had 1,736 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 $10.0 million and $3.0 million for environmental control facilities and complying with safety regulations in 2010 and 2011, 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.

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 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 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 2001, Kentucky made significant changes to its mining laws. A new independent agency, the Kentucky Mine Safety Review Commission, was created to assess 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.

Increased scrutiny of coal mining in general and underground coal mining in particular has led to new legislation. Legislation has been enacted at the state and federal level that creates requirements for maintaining caches of self-contained self-rescuers throughout underground mines; equipping all underground miners with wireless communications devices and tracking devices; and installing cable lifelines from the mine portal to all sections of the mine for assistance in emergency escape. Additionally, new requirements for prompt reporting of accidents and increased fines and penalties for violation of these and other regulations have been enacted. The Federal Mine Safety and Health Administration issued final regulations in December 2006 that place new or amended requirements on all underground mines relating to the storage and use of self-contained self-rescuers, evacuation training for miners, the installment and maintenance of lifelines and notification of MSHA in the event of an accident. In addition, new Federal Mine Safety and Health Administration regulations issued in December 2008 include requirements for providing refuge alternatives and improving flame-resistant conveyor belts and other fire protection measures.

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 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 $32.8 million at December 31, 2009. These obligations were unfunded at December 31, 2009.

The United States Department of Labor issued a final rule, effective January 19, 2001, amending the regulations implementing the Black Lung Act. The amendments give greater weight to the opinion of the 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 black lung regulations could significantly increase our exposure to federal black lung benefits liabilities. Experience to date related to these changes is not sufficient to determine the impact of these changes. The National Mining Association challenged the amendments but the courts, to date, with minor exception, affirmed the rules. However, the decision left many contested issues open for interpretation. Consequently, we anticipate increased litigation until the various federal District Courts have had an opportunity to rule on these issues.

In recent years, proposed legislation on black lung reform has been introduced in, but not enacted by, Congress and the Kentucky legislature. It is possible that legislation on black lung reform will be reintroduced for consideration by these legislative bodies. If any of the proposals that have been introduced are passed, the number of claimants who are awarded benefits could significantly increase. Any such changes in black lung legislation, if approved, or in state or federal court rulings, 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 $59.3 million at December 31, 2009. These obligations are unfunded. Our expense for workers’ compensation was $12.3 million and $10.8 million in 2009 and 2008, 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, 2009, we had accrued $44.8 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, 2009 was $3.2 million, while the related cash payment for such liability during the same period was $0.7 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 modification of existing plants.

The EPA has also adopted new federal rules intended to reduce the interstate transport of fine particulate matter and ozone through reductions in sulfur dioxides and nitrogen oxides through 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. The EPA continues to address the issues raised in the Court’s opinions issued on July 11, 2008 and December 23, 2008. 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.

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 and Section 21E of the Securities Exchange Act of 1934. 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; and

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

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; 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 are inaccurate; failure to diversify our operations; increased capital expenditures; encountering difficult mining conditions; 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.” Those 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 92% of our total revenues (contract and spot) in 2009 and 81% of our total revenues in 2008, 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 2009, we shipped in excess of 95% of our coal from our Central Appalachia mines via CSX. In the Midwest, we shipped approximately 63% of our produced coal by truck and the remainder via rail systems. We believe that our 2010 transportation modes will be comparable to those used in 2009. 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 Central Appalachian coal region 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 the Central Appalachian region. 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.

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

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

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

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.

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 this legislation will be reintroduced for consideration by Congress. If any of the proposals included in this or similar legislation is passed, the number of claimants who are awarded benefits could significantly increase. Any such changes in black lung legislation, if approved, may adversely affect our business, financial condition and results of operations.

Extensive environmental laws and regulations, including those relating to greenhouse gas emissions, 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 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.

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 April 2009, the EPA proposed a finding of such endangerment and has announced plans’ to soon finalize its proposed endangerment finding. This could result in the EPA issuing 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, proposed regulations to control greenhouse gas emissions from light duty vehicles, and a proposed “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 the second quarter of 2009, a bill passed the House that would reduce greenhouse gas emissions to 17% below 2005 levels by 2020 and 80% below 2005 levels by the middle of the century, and both Houses of Congress are also actively considering new legislation that could establish a national cap on, or other regulation of, carbon emissions and other greenhouse gases. Current proposals include a cap and trade system that would require the purchase of emission permits, which could be traded on the open market. These proposals will make it more costly to operate coal-fired plants and could make coal a less attractive fuel for future power plants. Any new or proposed requirements adversely affecting the use of coal could adversely affect our operations and results.

The permitting of new coal-fueled 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. A similar ruling was issued in October 2009 by the Fifth Circuit in Comer v. Murphy Oil involving a lawsuit against several coal, chemical, oil and gas, and utility companies. The plaintiffs in these cases are seeking various remedies, including monetary damages and 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 the EPA finalizes 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 March 2005, the EPA adopted new federal rules intended to reduce the interstate transport of fine particulate matter and ozone through reductions in sulfur dioxides and nitrogen oxides through 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. The EPA continues to address the issues raised in the Court’s opinions issued on July 11, 2008 and December 23, 2008. 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.

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). The permit can be either a simplified Nation Wide Permit #21 (NWP 21) or a more complicated individual permit. Litigation respecting the validity of the NWP 21 permit program as currently administered has been ongoing for several years. On March 23, 2007, U.S. District Judge Robert Chambers of the Southern District of West Virginia struck down several 404 permits that had been issued by the Corps and found that the Corps’ decisions to issue such permits did not conform to the requirements of the Clean Water Act or the National Environmental Policy Act because the Corps failed to do a full assessment of all of the impacts of eliminating headwater streams. This ruling was subsequently reversed on appeal to the 4th Circuit Court of Appeals. While the lower court ruling applied only to the permits at issue in the case before Judge Chambers and thus would have had precedence only with respect to certain counties in southern West Virginia (where we do not now operate), the matters at issue in that case may be litigated in the future in jurisdictions in which we do operate and a ruling for the plaintiffs in such litigation or the NWP 21 litigation could have an adverse impact on our planned surface mining operations.

In January 2005, a virtually identical claim to that filed in West Virginia was filed in Kentucky. The plaintiffs in this case, Kentucky Riverkeepers, Inc., et al. v. Colonel Robert A. Rowlette, Jr., et al., Civil Action No 05-CV-36-JPC, seek the same relief as that sought in West Virginia. The court heard oral arguments on plaintiffs’ preliminary injunction motion and/or motion for summary judgment in late 2005 and those motions were denied as moot as the 2002 NWP being challenged had expired before a decision was rendered in the case. The presiding judge has allowed the plaintiffs to renew the challenge against the 2007 permits and the case continues to move forward. A ruling for the plaintiffs in this matter could have an adverse impact on our planned surface mining operations.

Most recently, the Environmental Protection Agency (EPA) has 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. Such oversight could further delay and/or restrict the issuance of such permits, either of which events could have an adverse impact on our planned surface mining operations.

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, 2009, we had accrued $44.8 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 the each of the years ended December 31, 2008 and 2007. While we have been profitable in the year ended December 31, 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 2009, we generated approximately 92% of our total revenues from several long-term contracts and spot sales with electrical utilities, including 39% from Georgia Power Company, and 37% from South Carolina Public Service Authority. At December 31, 2009, we had coal supply agreements with these customers that expire in 2010 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 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.

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 federal and state laws and regulations relating to safety in underground coal mines and enforcement activities by federal and state regulators. These laws and regulations, the most significant of which is the federal MINER Act, include requirements for constructing and maintaining caches for the storage of additional self-contained self rescuers throughout underground mines; installing rescue chambers in underground mines; constant tracking of and communication with personnel in the mines; utilizing carbon dioxide monitors, installing cable lifelines from the mine portal to all sections of the mine to assist in emergency escape; submission and approval of emergency response plans; new and additional safety training; providing refuge alternatives; and improving flame-resistant conveyor belts and other fire protection measures. In 2007, implementation of the MINER Act continued with new penalty regulations that significantly increased regular penalty amounts and special assessments. In addition, a new emergency temporary standard was issued relating to mine seal requirements. Various states also have enacted their own new laws and regulations addressing many of these same subjects. These new laws and regulations will 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. Certain of our mines have received such notices in the past. Upon receipt of such a notification, we conduct a comprehensive review of the operation that received the notification and prepare and submit to MSHA plans designed to enhance employee safety at the mine through better education, training, mining practices, and safety management. Following implementation of the plans, 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 notification. The failure to remediate the situation resulting in a finding that a pattern of violation does exists at a mine could have a significant impact on our operations.

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. 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 2010, 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, 2009, we had outstanding surety bonds with third parties for post-mining reclamation totaling $60.2 million. Furthermore, we have surety bonds for an additional $43.8 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 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 he negatively affected.

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

In 2009, our company owned mines were 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, 2009, the current and non-current portions of these obligations included $32.8 million for coal workers’ black lung benefits and $59.3 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, 2009, we estimated that our obligation under the pension plan was underfunded by approximately $14.8 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, 2009 was $278.3 million (net of a discount on our convertible notes of $44.2 million). Our level of indebtedness could result in the following:

it could effect 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.

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). 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 range from $94.0 million to $105.0 million during 2010. Our Adjusted EBITDA for the twelve months ended December 31, 2009 was $146.1 million. The most directly comparable US GAAP financial measure is net income. For the year ended December 31, 2009, we had net income of $51.0 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 0.68X to 0.62X during 2010. Our Leverage Ratio was 0.0X as of December 31, 2009.

Our revolving credit facility limits the Capital Expenditures (other than Mandated Capital Expenditures) (as both are defined in the revolving credit facility) that we may make or agree to make in any fiscal year. For the fiscal year ended December 31, 2010, we cannot make Capital Expenditures in excess of $75.0 million (excludes Mandatory Capital Expenditures).

Additional detail regarding the terms of the facilities, 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. We currently have no agreement or understanding for any specific acquisition. 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 2010. However, such funds, together with the proceeds from this offering, 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 13 years at 2009 levels of production, compared to our current Central Appalachia mining complexes, which have reserves that we believe will last an average of approximately 34 years at 2009 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.

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, if 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.

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. In 2009, an amendment to the Rights Agreement reduced, until December 5, 2010, the threshold at which a person or group becomes an “Acquiring Person” under the Rights Agreement from 20% to 4.9% of the Company’s then-outstanding shares of common stock.

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, 2009, we owned approximately 11,400 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.

Ourrights 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 are located in Richmond, Virginia and are 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. Submission of Matters to a Vote of Security Holders

There were no matters submitted to a vote of security holders of the Company through a solicitation of proxies or otherwise during the fourth quarter of the Company’s year ended December 31, 2009.

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, 2009
High	$18.30	24.11	21.15	22.31
Low	$9.09	12.62	13.50	17.20
Fiscal year ended December 31, 2008
High	$19.65	62.14	58.79	21.25
Low	$8.57	17.22	20.34	5.09

Recent Sales of Unregistered Securities

We issued 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. Shares	No. Options	Date of Issuance	Consideration	Option Exercise Price

Operating and senior management	213,708	-	April 6, 2009	Services rendered	N/A

Non-employee directors (aggregate)	5,000	20,000	April 6, 2009	Services rendered	$13.87

Please refer to note 7 of our December 31, 2009 consolidated financial statements for securities authorized to be issued under our 2004 Equity Incentive Plan.

Holders

As of December 31, 2009, there were 135 record holders of our common stock.

Dividends

We did not pay any cash dividends on our common stock during the years ended December 31, 2009, 2008 or 2007. 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.

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 Global Market (U.S.) Index and the Dow Jones U.S. Coal Index for the period commencing on January 25, 2005 (the date the Company’s Common Stock began trading on the Nasdaq Global Market) and ending on December 31, 2009.

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,
	2009			2008			2007			2006			2005
Consolidated Statement of Operations:
Revenues	$	681,558			568,507			520,560			564,791			453,999
Cost of coal sold		508,888			527,888			473,347			496,799			389,222
Gain on curtailment of pension plan		-			-			(6,091	)		-			-
Depreciation, depletion, and amortization		62,078			70,277			71,856			74,562			51,822
Gross profit (loss)		110,592			(29,658	)		(18,552	)		(6,570	)		12,955

Selling, general, and administrative expenses		39,720			34,992			32,191			30,867			25,453
Operating income (loss)		70,872			(64,650	)		(50,743	)		(37,437	)		(12,498	)

Interest expense		17,057			17,746			19,764			16,782			12,892
Interest income		(60	)		(469	)		(471	)		(366	)		(226	)
Charges associated with repayment of debt		1,643			15,618			2,421			-			2,524
Miscellaneous income, net		(281	)		(1,279	)		(598	)		(533	)		(1,067	)
Income tax expense (benefit)		1,559			(273	)		(17,844	)		(27,151	)		(14,283	)

Net income (loss)	$	50,954			(95,993	)		(54,015	)		(26,169	)		(12,338	)

Basic earnings (loss) per common share:	$	1.85			(3.91	)		(3.29	)		(1.65	)		(0.83	)
Diluted earnings (loss) per common share:		1.85			(3.91	)		(3.29	)		(1.65	)		(0.83	)

	December 31,
	2009		2008			2007			2006			2005
	(in thousands, except per share, per ton and number of employees information)
Consolidated Balance Sheet Data:
Working capital (deficit)	$	109,998		(54,961	)		(8,471	)		(2,589	)		6,123
Property, plant, and equipment, net		354,088		344,848			319,204			337,780			360,000
Total assets		669,312		463,546			439,287			451,254			472,669
Long term debt, including current portion		278,268		168,000			188,800			167,493			150,000
Total shareholders’ equity		170,342		65,238			69,774			86,397			111,267

	Year Ended December 31
	2009			2008			2007			2006			2005
Consolidated Statement of Cash Flow Data:
Net cash provided by (used in) operating activities	$	27,559			(1,576	)		4,022			31,680			48,990
Net cash used in investing activities		(72,010	)		(73,589	)		(49,201	)		(54,738	)		(135,362	)
Net cash provided by financing activities		149,058			73,076			48,785			15,929			91,429

Supplemental Operating Data:
Tons sold		9,623			11,383			12,049			13,128			11,091
Tons produced		9,877			11,355			12,051			13,054			11,155
Revenue per ton sold (excluding synfuel)	$	70.83			49.94			42.63			42.67			40.19
Number of employees		1,736			1,751			1,681			1,742			1,429
Capital expenditures	$	72,159			74,697			49,343			62,507			84,987

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)). In 2009, our mines produced 9.8 million tons of coal (including 0.3 million tons of contract coal) and we purchased another 0.1 million tons for resale. Of the 9.5 million tons we produced from Company operated mines, approximately 66% came from underground mines, while the remaining 34% came from surface mines. In 2009, we generated revenues of $681.6 million and net income of $51.0 million.

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 2008 the South Atlantic region consumed 180.4 million tons of coal or about 17% 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 2009, Georgia Power Company and South Carolina Public Service Authority were our largest customers, representing approximately 39% and 37% of our total revenues, respectively. No other customer accounted for more than 10% of our revenues.

According to the EIA, coal production for Eastern Kentucky and West Virginia was 248 million tons in 2008. During 2009, our CAPP segment shipped 6.5 million tons of coal at an average selling price of $88.75 per ton. As of December 31, 2009, we estimate that we controlled approximately 231 million tons of proven and probable coal reserves in our CAAP 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 34 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 2008 the East North Central Region consumed about 239.2 million tons of coal or 23% of all coal consumed for electric generation in the United States. In 2009, our Midwest segment’s largest customer represented approximately 6% of our total revenues.

During 2009, our Midwest segment shipped 3.1 million tons of coal at an average selling price of $33.07 per ton. 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, 2009, we estimate that we controlled approximately 40 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 13 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, 2009, we estimate that, as of December 31, 2009, we controlled approximately 231.2 million tons of proven and probable coal reserves in the CAPP region and 39.9 millions tons in the Midwest region. The following table provides additional information regarding changes to our reserves since December 31, 2009 (in millions of tons):

	CAPP			Midwest			Total

Proven and Probable Reserves, as of December 31, 2008 (1)		235.1			42.0			277.1
Coal Extracted		(6.7	)		(3.1	)		(9.8	)
Acquisitions (2)		0.7			0.9			1.6
Adjustments (3)		2.5			0.1			2.6
Divestures (4)		(0.4	)		-			(0.4	)
Proven and Probable Reserves, as of December 31, 2009 (1)		231.2			39.9			271.1

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 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 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.”

In the selling, general and administrative area, we closely monitor the gross dollars spent per mine operation and in support functions. We also regularly measure our performance against our internally-prepared budgets.

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 oil and natural gas. The coal industry has made cutbacks in supply in response to decrease in demand for coal. 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 as 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, 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 the 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 is 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.

Year Ended December 31, 2008 Compared with the Year Ended December 31, 2007

The following table shows selected operating results for 2008 and 2007 (in thousands, except per ton amounts):

	Year Ended December 31,
	2008						2007						Change
	Total			Per Ton			Total			Per Ton			Total
Volume Shipped (tons)		11,383						12,049						-6%

Coal sales revenue	$	568,507		$	49.94		$	513,706		$	42.63			11%
Synfuel handling		-						6,854						N/A
Cost of coal sold		527,888			46.38			473,347			39.29			12%
Gain on curtailment of pension plan		-			-			(6,091	)		(0.51	)		N/A
Depreciation, depletion and amortization		70,277			6.17			71,856			5.96			-2%
Gross profit (loss)		(29,658	)		(2.61	)		(18,552	)		(1.54	)		60%
Selling, general and administrative		34,992			3.07			32,191			2.67			9%

Volume and Revenues by Segment

	Year Ended December 31,
	2008				2007

	CAPP		Midwest		CAPP		Midwest

Volume Shipped (tons)		8,271		3,112		8,893		3,156

Coal sales revenue	$	467,609	$	100,898	$	422,429	$	91,277

Average sales price per ton		56.54		32.42		47.50		28.92

In 2008, we shipped 11.4 million tons of coal compared to 12.0 million tons in 2007. Coal sales revenue increased from $513.7 million in 2007 to $568.5 million in 2008. This increase was due to an increase in the average sales price per ton in both the CAPP and Midwest regions, partially offset by a decrease in the volume of tons shipped.

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 2007, the CAPP region sold approximately 7.7 million tons of coal under long-term contracts (86% of total CAPP sales volume) at an average selling price of $46.30 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. In 2007, the CAPP region sold 1.2 million tons of coal (14% of total CAPP sales volume) under short term contracts (includes spot sales) at an average selling price of $54.94 per ton.

Prior to 2008, we received revenues from coal supplied to a third party synfuel plant and received fees for the handling, shipping and marketing of the synfuel product. After January 1, 2008, we no longer received any revenues related to synfuel.

The Midwest’s region sales of coal were primarily sold under long term contracts for both the 2008 and 2007. In 2008, the Midwest region sold 3.1 million tons at an average sales price of $32.42. In 2007, the Midwest region sold 3.2 million tons at an average sales price of $28.92.

Cost of Coal Sold

	Year Ended December 31,
	2008						2007

	CAPP		Midwest		Corporate		CAPP		Midwest		Corporate

Cost of Coal Sold	$	433,781	$	94,107	$	-	$	396,639	$	76,708	$	-

Per ton		52.45		30.24		-		44.60		24.31		-

Depreciation, depletion, and amortization		55,979		14,218		80		56,506		15,199		151

Per ton		6.77		4.57		-		6.35		4.82		-

The cost of coal sold, excluding depreciation, depletion and amortization increased from $473.3 million in 2007 to $527.9 million in 2008. Our cost per ton of coal sold in the CAPP region increased from $44.60 per ton in the 2007 period to $52.45 per ton in the 2008 period. This $7.85 increase in cost per ton of coal sold was primarily the result of lower productivity due to increased federal and state regulatory scrutiny, adverse geological conditions, a tight labor market, rising commodity prices including diesel fuel and steel, and the impact of increased average sales prices on our sales related costs. The major components of this increase include an increase in the Company’s labor and benefit costs of $2.53 per ton, variable costs of $1.61 per ton and sales related costs of $1.13 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 region increased from $24.31 in 2007 to $30.24 in 2008. The increase in cost per ton of coal sold was primarily due to an increase of $3.59 per ton in variable costs. The increase in the variable costs was due to increased costs for diesel fuel and explosives. Our labor and benefit costs and trucking costs also increased $0.61 and $0.62 per ton, respectively. The increase in labor costs was due to an increase in wages as compared to prior year and trucking costs increased due to an increase in rates.

Depreciation, depletion and amortization

Depreciation, depletion and amortization decreased from $71.9 million in 2007 to $70.3 million in 2008. In the CAPP region, depreciation, depletion and amortization decreased $0.5 million to $56.0 million or $6.77 per ton. In the Midwest, depreciation, depletion and amortization decreased $1.0 million to $14.2 million or $4.57 per ton.

Selling, general and administrative

Selling, general and administrative expenses increased from $32.2 million for 2007 to $35.0 million for 2008. The increase was primarily due to increases in employee stock compensation, bank service costs including letter of credit fees, and bonding and permitting costs.

Charges associated with repayment and amendment of debt

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.

In 2007, we wrote off $2.4 million of financing charges in connection with the repayment of the Prior Senior Secured Credit Facility. The write off of the financing charges is classified as charges associated with repayment of debt.

Income Taxes

Our effective income tax rate is impacted primarily by the amount of the valuation allowance recorded and percentage depletion. For 2008, we had a 0.3% effective tax rate primarily based on the conclusion that the benefit of the expected 2008 net operating loss is not more likely than not to be realized. The criteria for recording a valuation allowance are described in “Critical Accounting Estimates – Income Taxes.” As of December 31, 2008, we had a $54.3 million valuation allowance against gross deferred tax assets. Our effective tax rate for 2007 was 24.8%. We recorded an $8.8 million valuation allowance for tax purposes for the year ended December 31, 2007, which reduced our effective tax rate for 2007 by 13.2%. 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, 2009 and 2008 (in thousands):

	2009		2008
Senior Notes	$	150,000		150,000
Convertible Senior Notes, net of discount		128,268		-
Revolver		-		18,000
Total long-term debt		278,268		168,000
Less amounts classified as current		-		18,000
Total long-term debt, less current maturities	$	278,268		150,000

Senior Notes

The Senior Notes are due on June 1, 2012. The Senior Notes are unsecured and accrue interest at 9.375% per annum. Interest payments on the Senior Notes are required semi-annually. We may redeem the Senior Notes, in whole or in part, at any time at redemption prices from 102.34% in 2010 to 100% in 2011. The Senior Notes limit our ability, among other things, to pay cash dividends. In addition, if a change of control occurs (as defined in the Indenture), each holder of the Senior Notes will have the right to require us to repurchase all or a part of the Senior Notes at a price equal to 101% of their principal amount, plus any accrued interest to the date of repurchase.

Convertible Senior Notes

During the fourth quarter of 2009, we issued $172.5 million of 4.5% Convertible Senior Notes due on December 1, 2015 (the “Convertible Senior Notes”). We recorded a discount on the Convertible Senior Notes of $44.8 million related to the portion of the proceeds that were allocated to the equity component of the Convertible Senior Notes. The Convertible Senior Notes are unsecured and are convertible under certain circumstances and during certain periods at an initial conversion rate of 38.7913 shares of the Company’s common stock per $1,000 principal amount of Convertible Senior Notes, representing an initial conversion price of approximately $25.78 per share of the Company’s stock. Interest payments on the Convertible Senior Notes are required semi-annually. The Convertible Senior Notes are shown net of a $44.2 million discount on the consolidated financials statements as of December 31, 2009.

In connection with the Convertible Senior Notes, we terminated a prior letter of credit facility and secured 105% of the letters of credit that were outstanding under the prior letter of credit facility with approximately $62.0 million in cash. We expensed $1.6 million in 2009 in connection with a fee to terminate the Prior Facility. The remaining proceeds from the Convertible Senior Notes will be used for working capital and general corporate purposes. We incurred approximately $5.5 million of costs in connection with the issuance of the Convertible Senior Notes.

None of the Convertible Senior Notes are currently eligible for conversion. The Convertible Senior Notes are convertible at the option of the holders (with the length of time the Convertible Senior Notes are convertible being dependent upon the conversion trigger) upon the occurrence of any of the following events:

·	At any time from September 1, 2015 until December 1, 2015;

If the closing sale price of the Company’s common stock for each of 20 or more trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the conversion price of the Convertible Senior Notes in effect on the last trading day of the immediately preceding calendar quarter;

If the trading price of the Convertible Senior Notes for each trading day during any five consecutive trading day period, as determined following a request of a holder of such Convertible Senior Notes, was equal to or less than 97% of the “Conversion Value” of the Convertible Senior Notes on such trading day; or

·	If the Company elects to make certain distributions to the holders of its common stock or engage in certain corporate transactions.

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 our eligible accounts receivable plus 65% of the eligible inventory minus reserves from time to time set by 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 us to maintain a minimum Adjusted EBITDA and a maximum Leverage Ratio and limit capital expenditures, each as defined by the agreement. The minimum EBITDA and maximum Leverage Ratio are only measured if our unrestricted cash balance is less than $75.0 million.

We expect to use the Revolver to secure our outstanding letters of credit. We intend to place cash in a restricted account to provide us with the maximum borrowing base under the Revolver.

We were in compliance with all of the financial covenants under our outstanding debt instruments as of December 31, 2009. 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 II - 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, 2009, we had total liquidity of approximately $142.9 million, consisting of $35.0 million of borrowing capacity under our Revolver and $107.9 million of cash and cash equivalents. As discussed above, in January 2010, we increased the borrowing capacity of the Revolver to $65.0 million. Our intention is to use the Revolver to support our existing letters of credit. As we secure the letters of credit with our Revolver, our cash that is currently being held as security for the letters of credit will become unrestricted and be available to us for use. A portion of this cash may be used to ensure that we have adequate capacity under the Revolver to support our outstanding letters of credit.

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.

We believe that cash generated from operations, borrowings under our credit facilities and future debt and equity offerings, if any, will be sufficient to meet working capital requirements, anticipated capital expenditures and scheduled debt payments throughout 2010 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.

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 and capital expenditures for existing mines. We currently project that our capital expenditures for 2010 will be approximately $85 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 2010 also include approximately $10.0 million for safety mandates and $6.0 million for mine 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 $27.6 million for the year ended December 31, 2009 and net cash used in operating activities was $1.6 million for the year ended December 31, 2008. We had net income in 2009 of $51.0 million as compared to a net loss of $96.0 million in 2008. In reconciling our net income (loss) to cash provided by or used in operating activities, $73.2 million was added for non cash charges during 2009 as compared to $81.8 million during 2008. 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 increase in restricted cash 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. During 2008, our net loss, as adjusted for non cash charges, was increased by a $12.6 million increase in cash from our operating assets and liabilities. The $12.6 million change in our operating assets and liabilities for 2008, includes a $7.7 million decrease in accounts receivable, a $9.8 million increase in accounts payables, a $9.6 million increase in other assets and an $8.7 million increase in other current liabilities.

Net cash used by investing activities decreased $1.6 million to $72.0 million for 2009, as compared to 2008. Capital expenditures were $72.2 million in 2009 and $74.7 million in 2008. In 2008, capital expenditures included $20.0 million paid by the Company for a mineral rights acquisition. Excluding the mineral rights acquisition, capital expenditures primarily consisted of new and replacement mine equipment and various projects to improve the production and efficiency of our mining operations.

Net cash provided by financing activities was $149.1 million 2009. During 2009 our primary financing activities were the receipt of $167.0 of net proceeds from our Convertible Senior Notes and $18.0 million of payments on our revolving credit facility. During 2008 our primary financing activities were the receipt of $93.8 million of net proceeds from the issuance of our common stock, net borrowings of $18.0 million on our Revolver and the repayment $38.8 million under our Term Loan.

Contractual Obligations

The following is a summary of our contractual obligations and commitments as of December 31, 2009:

	Payment Due by Period (in thousands)

Contractual Obligations	Total		2010		2011-2012	2013-2014	Thereafter
Long term debt (1)	$	322,500		-	150,000	-		172,500
Interest on long term debt and fees under our Revolver for letters of credit (2)		87,715		24,587	39,841	15,525		7,762
Operating lease obligations (3)		10,664		6,817	3,445	402		-
Royalty obligations (4)		203,356		24,957	43,367	41,124		93,908
Purchase obligations (5)		-		-	-	-		-
	$	624,235		56,361	236,653	57,051		274,170

(1)

Consists of our Senior Notes and our Convertible Senior Notes as of December 31, 2009.

(2)

Consists of interest payments on our Senior Notes and Convertible Senior Notes. Also includes a charge associated with outstanding letter of credit fees under the Revolver through the Revolver’s maturity (assume the full amount of the Revolver capacity is used for letters of credit).

(3)

See Note 11 in the notes to the consolidated financial statements for additional information on leases.

(4)

Royalty obligations include minimum royalties payable on leased coal rights. Certain coal leases do not have set expiration dates but extend until completion of mining of all merchantable and mineable coal reserves. For purposes of this table, we have generally assumed that minimum royalties on such leases will be paid for a period of ten years. Certain coal leases require payment based on minimum tonnage, for these contracts an average sales price of $80.00 per ton was used to project the future commitment.

(5)

Purchase obligations do not include agreements to purchase coal with vendors that do not include quantities or minimum tonnages, or monthly purchase orders.

Additionally, we have liabilities relating to pension, workers compensation, black lung, and mine reclamation and closure. As of December 31, 2009, the undiscounted payments related to these items are estimated to be:

Payments Due by Years (In Thousands)
Within 1 Year	2 - 3 Years	4 - 5 Years
$18,880	31,125	36,797

Our determination of these noncurrent liabilities is calculated annually and is based on several assumptions, including then prevailing conditions, which may change from year to year. In any year, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Moreover, in particular for periods after 2010, our estimates may change from the amounts included in the table, and may change significantly, if our assumptions change to reflect changing conditions. These assumptions are discussed in the Notes to the Consolidated Financial Statements and in the Critical Accounting Estimates in Management’s Discussion and Analysis.

Off-Balance Sheet Arrangements

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

We use surety bonds to secure reclamation, workers’ compensation and other miscellaneous obligations. At December 31, 2009, we had $104.0 million of outstanding surety bonds with third parties. These bonds were in place to secure obligations as follows: post-mining reclamation bonds of $60.2 million, workers’ compensation bonds of $40.3 million, wage payment, collection bonds, and other miscellaneous obligation bonds of $3.5 million. Surety bond costs have increased over time and the market terms of surety bonds have generally become less favorable. To the extent that surety bonds become unavailable, we would seek to secure obligations with letters of credit, cash deposits, or other suitable forms of collateral.

We also use bank letters of credit to secure our obligations for workers’ compensation programs, various insurance contracts and other obligations. As of December 31, 2009, we had $59.1 million of letters of credit outstanding. The letters of credit were secured by $62.0 million of cash.

Critical Accounting Estimates

Overview

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

Workers' Compensation

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

We accrue for the present value of certain workers’ compensation obligations as calculated annually by an independent actuary based upon assumptions for work-related injury and illness rates, discount rates and future trends for medical care costs. The discount rate is based on interest rates on bonds with maturities similar to the estimated future cash flows. The discount rate used to calculate the present value of these future obligations was 5.3% at December 31, 2009. Significant changes to interest rates result in substantial volatility to our consolidated financial statements. If we were to decrease our estimate of the discount rate from 5.3% to 4.8%, all other things being equal, the present value of our workers’ compensation obligation would increase by approximately $1.9 million. A change in the law, through either legislation or judicial action, could cause these assumptions to change. If the estimates do not materialize as anticipated, our actual costs and cash expenditures could differ materially from that currently estimated. Our estimated workers’ compensation liability as of December 31, 2009 was $59.3 million.

Coal Miners' Pneumoconiosis

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

An independent actuary calculates the estimated pneumoconiosis liability annually based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents and interest rates. The discount rate is based on interest rates on high quality corporate bonds with maturities similar to the estimated future cash flows. The discount rate used to calculate the present value of these future obligations was 5.8% at December 31, 2009. Significant changes to interest rates result in substantial volatility to our consolidated financial statements. If we were to decrease our estimate of the discount rate by 0.5% to 5.3%, all other things being equal, the present value of our black lung obligation would increase by approximately $2.2 million. A change in the law, through either legislation or judicial action, could cause these assumptions to change. If these estimates prove inaccurate, the actual costs and cash expenditures could vary materially from the amount currently estimated. Our estimated pneumoconiosis liability as of December 31, 2009 was $32.8 million.

Defined Benefit Pension

We have in place a non-contributory defined benefit pension plan under which all benefits were frozen in 2007. The estimated cost and benefits of our non-contributory defined benefit pension plans are determined annually by independent actuaries, who, with our review and approval, use various actuarial assumptions, including discount rate and expected long-term rate of return on pension plan assets. In estimating the discount rate, we look to rates of return on high-quality, fixed-income investments with comparable maturities. At December 31, 2009, the discount rate used to determine the obligation was 5.9%. Significant changes to interest rates result in substantial volatility to our consolidated financial statements. If we were to decrease our estimate of the discount rate from 5.9% to 5.4%, all other things being equal, the present value of our projected benefit obligation would increase by approximately $4.5 million. The expected long-term rate of return on pension plan assets is based on long-term historical return information and future estimates of long-term investment returns for the target asset allocation of investments that comprise plan assets. The expected long-term rate of return on plan assets used to determine expense was 7.5% for the period ended December 31, 2009. Significant changes to these rates would introduce volatility to our pension expense. Our accrued pension obligation as of December 31, 2009 was $14.8 million.

Reclamation and Mine Closure Obligation

The Surface Mining Control Reclamation Act of 1977 establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of underground mining. Our asset retirement obligation liabilities consist of spending estimates related to reclaiming surface land and support facilities at both surface and underground mines in accordance with federal and state reclamation laws. Our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering estimates related to these requirements. US GAAP requires that asset retirement obligations be initially recorded as a liability based on fair value, which is calculated as the present value of the estimated future cash flows. Our management and engineers periodically review the estimate of ultimate reclamation liability and the expected period in which reclamation work will be performed. In estimating future cash flows, we considered the estimated current cost of reclamation and applied inflation rates and a third party profit. The third party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf. The discount rate is our estimate of our credit adjusted risk free rate. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. The actual costs could be different due to several reasons, including the possibility that our estimates could be incorrect, in which case our liabilities would differ. If we perform the reclamation work using our personnel rather than hiring a third party, as assumed under US GAAP, then the costs should be lower. If governmental regulations change, then the costs of reclamation will be impacted. US GAAP recognizes that the recorded liability could be different than the final cost of the reclamation and addresses the settlement of the liability. When the obligation is settled, and there is a difference between the recorded liability and the amount paid to settle the obligation, a gain or loss upon settlement is included in earnings. Our asset retirement obligation as of December 31, 2009 was $44.8 million.

Contingencies

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

Income Taxes

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

We have recorded a $33.2 million valuation allowance against our gross deferred tax assets as of December 31, 2009 for the portion of the gross deferred tax asset that does not meet the more likely than not criteria to be realized. In 2009, we recorded an income tax benefit for the reduction in our valuation allowance related to the net operating loss carryforwards that will be utilized.

Coal Reserves

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

·	all currently available data;

·	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.

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

Evaluation of Goodwill and Long-Lived Assets for Impairment

Goodwill is not amortized, but is subject to periodic assessments of impairment. Impairment testing is performed at the reporting unit level. We test goodwill for impairment annually during the fourth quarter, or when changes in circumstances indicate that the carrying value may not be recoverable. Long-lived asset groups are tested for recoverability when changes in circumstances indicate the carrying value may not be recoverable. Events that trigger a test for recoverability include material adverse changes in projected revenues and expenses, significant underperformance relative to historical or projected future operating results and significant negative industry or economic trends.

The estimates used to determine whether impairment has occurred to goodwill and long-lived assets are subject to a number of management assumptions. We estimate the fair value of a reporting unit or asset group based on market prices (i.e., the amount for which the asset could be bought by or sold to a third party), when available. When market prices are not available, we estimate the fair value of the reporting unit or asset group using the income approach and/or the market approach, which are subject to a number of management assumptions. The income approach uses cash flow projections. Inherent in our development of cash flow projections are assumptions and estimates derived from a review of our operating results, approved operating budgets, expected growth rates and cost of capital. We also make certain assumptions about future economic conditions, interest rates, and other market data. Many of the factors used in assessing fair value are outside the control of management, and these assumptions and estimates can change in future periods.

Changes in assumptions or estimates could materially affect the determination of fair value of an asset group, and therefore could affect the amount of potential impairment of the asset. The following assumptions are key to our income approach:

We make assumptions about coal production, sales price for unpriced coal, cost to mine the coal and estimated residual value of property, plant and equipment. These assumptions are key inputs for developing our cash flow projections. These projections are derived using our internal operating budget and are developed on a mine by mine basis. These projections are updated annually and reviewed by the Board of Directors. Historically, the Company’s primary variances between its projections and actual results have been with regard to assumptions for future coal production, sales prices of coal and costs to mine the coal. These factors are based on our best knowledge at the time we prepare our budgets but can vary significantly due to regulatory issues, unforeseen mining conditions, change in commodity prices, availability and costs of labor and changes in supply and demand. While we make our best estimates at the time we prepare our budgets it is reasonably likely that these estimates will change in future budgets, due to the changing nature of the coal environment;

Economic Projections – Assumptions regarding general economic conditions are included in and affect the assumptions used in our impairment tests. These assumptions include, but are not limited to, supply and demand for coal, inflation, interest rates, and prices of raw materials (commodities); and

Discount Rate – When measuring a possible impairment, future cash flows are discounted at a rate that we believe represents our cost of capital.

Recent Accounting Pronouncements

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

Other Supplemental Information

Reconciliation of Non-GAAP Measures

EBITDA is a measure used by management to measure operating performance. We define EBITDA as net income or loss plus interest expense (net), income tax expense (benefit) and depreciation, depletion and amortization (EBITDA), to better measure our operating performance. 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.

Adjusted EBITDA and the leverage ratio are the amounts used in our current debt covenants. Adjusted EBITDA is defined as EBITDA further adjusted for certain cash and non-cash charges and the leverage ratio limits are debt to a multiple of adjusted EBITDA. Adjusted EBITDA and the leverage ratio are used to determine compliance with financial covenants and our ability to engage in certain activities such as incurring additional debt and making certain payments.

EBITDA, Adjusted EBITDA, and the leverage ratio are not recognized terms under US GAAP and are 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. Because not all companies use identical calculations, this presentation of EBITDA, Adjusted EBITDA and the leverage ratio may not be comparable to other similarly titled measures of other companies. Additionally, EBITDA or Adjusted EBITDA are not intended to be a measure of free cash flow for management’s discretionary use, as they do not reflect certain cash requirements such as tax payments, interest payments and other contractual obligations.

The leverage ratio is calculated as the Company’s Senior Funded Indebtedness divided by annualized adjusted EBITDA as calculated below. The Senior Funded Indebtedness includes the amounts outstanding under our revolver and the amount of letters of credits issued under our revolver. As of December 31, 2009, we had no Senior Funded Indebtedness outstanding.

	Year Ended
	December 31			December 31
	2009			2008

Net income (loss)	$	50,954			(95,993	)
Income tax expense (benefit)		1,559			(273	)
Interest expense		17,057			17,746
Interest income		(60	)		(469	)
Depreciation, depletion, and amortization		62,078			70,277
EBITDA (before adjustments)		131,588			(8,712	)
Other adjustments specified
in our current debt agreement:
Charges associated with repayment of debt		1,643			15,618
Other adjustments		12,868			10,665
Adjusted EBITDA	$	146,099			17,571

Item 7a. Quantitative and Qualitative Disclosures about Market Risk

Our $150 million Senior Notes and $172.5 million Convertible Senior Notes have a fixed interest rate and are not sensitive to changes in the general level of interest rates. Our Revolver has floating interest rates based on our option of either the base rate or LIBOR rate. As of December 31, 2009, we had no borrowings outstanding under the Revolver. We currently do not use interest rate swaps to manage this risk. A 100 basis point (1.0%) increase in the average interest rate for our floating rate borrowings would increase our annual interest expense by approximately $0.1 million for each $10 million of borrowings under the Revolver.

We manage our commodity price risk through the use of long-term coal supply agreements, which we define as contracts with a term of one year or more, rather than through the use of derivative instruments. The percentage of our sales pursuant to long-term contracts was approximately 94% for the year ended December 31, 2009.

All of our transactions are denominated in U.S. dollars, and, as a result, we do not have material exposure to currency exchange-rate risks.

We are not engaged in any foreign currency exchange rate or commodity price-hedging transactions and we have no trading market risk.

Item 8. Financial Statements and Supplementary Data

See Financial Statements beginning on page F-1.

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

None.

Item 9A. Controls and Procedures

Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 (“Exchange Act”), the Company carried out an evaluation, with the participation of the Company’s management, including the Company’s Chief Executive Officer (“CEO”) and Chief Accounting Officer (“CAO”) (the Company’s principal financial and accounting officer), of the effectiveness of the Company’s disclosure controls and procedures (as defined under Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, the Company’s CEO and CAO concluded that the Company’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in the reports that the Company files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Company’s CEO and CAO, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of consolidated financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. There has been no change in the Company’s internal control over financial reporting during the year ended December 31, 2009 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

The Company’s management, including the Company’s CEO and CAO, does not expect that the Company’s disclosure controls and procedures or the Company’s internal controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of the controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected.

Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.

Item 9B. Other Information

None.

PART III

Item 10. Director, Executive Officers and Corporate Governance of the Registrant

The information contained under the headings “Election of Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance” "Board Matters" and "Management" in the definitive Proxy Statement used in connection with the solicitation of proxies for the Company’s 2010 Annual Meeting of Shareholders, to be filed with the Commission, is hereby incorporated herein by reference.

Item 11. Executive Compensation

The information contained under the headings “Compensation Committee Report,” “Executive Compensation,” “Equity Compensation Plans,” and “Compensation Committee Interlocks and Insider Participation” in the definitive Proxy Statement used in connection with the solicitation of proxies for the Company’s 2010 Annual Meeting of Shareholders, to be filed with the Commission, is hereby incorporated herein by reference.

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

The information contained under the headings “Principal Shareholders and Securities Ownership of Management,” and “Equity Compensation Plans” in the definitive Proxy Statement used in connection with the solicitation of proxies for the Company’s 2010 Annual Meeting of Shareholders, to be filed with the Commission, is hereby incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions

The information contained under the heading “Compensation Committee Interlocks and Insider Participation” in the definitive Proxy Statement used in connection with the solicitation of proxies for the Company’s 2010 Annual Meeting of Shareholders, to be filed with the Commission, is hereby incorporated herein by reference.

Item 14. Principal Accountant Fees and Services

The information contained under the heading “Independent Registered Public Accountants” in the definitive Proxy Statement used in connection with the solicitation of proxies for the Company’s 2010 Annual Meeting of Shareholders, to be filed with the Commission, is hereby incorporated herein by reference.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a) The following documents are filed as part of this Report:

1.	Financial Statements

The following financial statements and related report of Independent Registered Public Accounting Firm are incorporated in Item 8 of this report:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2009 and 2008

Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007

Consolidated Statements of Changes in Shareholders’ Equity and Comprehensive Income (Loss) for the years ended December 31, 2009, 2008 and 2007

Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007

Notes to Consolidated Financial Statements

2.	Financial Statement Schedules

None.

Exhibits

The following exhibits are required to be filed with this Report by Item 601 of Regulation S-K:

Exhibit Number	Description


2.1	Second Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code of the Registrant and its Subsidiaries, dated as of April 20, 2004, incorporated herein by reference to Exhibit 2 to the Registrant’s Registration Statement on Form S-1 filed August 13, 2004

2.2	Stock Purchase Agreement by and among James River Coal Company, Triad Mining, Inc. and the Stockholders of Triad Mining, Inc. dated as of March 30, 2005, incorporated herein by reference to Exhibit 2.2 to the Registrant’s Registration Statement on Form S-1 filed April 19, 2005

3.1	Amended and Restated Articles of Incorporation of the Registrant, as Amended, incorporated herein by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 filed August 13, 2004

3.2	Amended and Restated Bylaws of the Registrant, incorporated herein by reference to Exhibit 3.2 to the Registrant’s Quarterly Report on Form 10-Q filed August 9, 2007


4.1	Specimen common stock certificate, incorporated herein by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form S-1 filed August 13, 2004

4.2	Rights Agreement between the Registrant and SunTrust Bank as Rights Agent, dated as of May 25, 2004, incorporated herein by reference to Exhibit 4.2 to the Registrant’s Registration Statement on Form S-1 filed August 13, 2004

4.3	Amendment No. 1 to Rights Agreement between the Registrant and Computershare Trust Company, N.A., successor to SunTrust Bank, as Rights Agent, dated as of November 3, 2006, incorporated herein by reference to Exhibit 4.2 to the Registrant’s Quarterly Report on Form 10-Q filed November 9, 2006

4.4	Amendment No. 2 to Rights Agreement between the Registrant and Computershare Trust Company, N.A., successor to SunTrust Bank, as Rights Agent, dated as of August 2, 2007, incorporated herein by reference to Exhibit 4.2 to the Registrant’s Quarterly Report on Form 10-Q filed August 9, 2007

4.5	Amendment No. 3 to Rights Agreement between Registrant and Computershare Trust Company, N.A., successor to SunTrust Bank, as Rights Agent, dated as of November 3, 2009, incorporated herein by reference to Exhibit 4.1 to the Registrant’s Amendment No. 1 to Form 8-K filed November 3, 2009

4.6	Form of rights certificate, incorporated herein by reference to Exhibit 4.3 to the Registrant’s Registration Statement on Form 8-A filed January 24, 2005

4.7	Indenture among the Registrant, certain of its subsidiaries and U.S. Bank, National Association, as Trustee, dated as of May 31, 2005, incorporated herein by reference to Exhibit 4.3 to the Registrant’s Registration Statement on Form S-1/A filed May 24, 2005

4.8	Form of Senior Debt Indenture, incorporated herein by reference to Exhibit 4.8 to the Registrant’s Registration Statement on Form S-3 filed June 7, 2007

4.9	Form of Subordinated Debt Indenture, incorporated herein by reference to Exhibit 4.10 to the Registrant’s Registration Statement on Form S-3 filed June 7, 2007

4.10	Indenture related to the 4.50% Convertible Senior Notes due 2015, dated as of November 20, 2009, between James River Coal Company and U.S. Bank National Association, as trustee (including the form of 4.50% Convertible Senior Notes due 2015), incorporated herein by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed November 25, 2009

10.1	Registration Rights Agreement by and among the Registrant and the Shareholders identified therein, dated May 6, 2004, incorporated herein by reference to Exhibit 10.1 to the Registrant’s Registration Statement on Form S-1 filed August 13, 2004

10.2	Loan and Security Agreement by and among the Registrant and its Subsidiaries, the Lenders that are Signatories thereto, Wells Fargo Foothill, Inc. and Morgan Stanley Senior Funding, Inc., dated as of May 6, 2004, incorporated herein by reference to Exhibit 10.2 to the Registrant’s Registration Statement on Form S-1 filed August 13, 2004

10.3	$75,000,000 Term Loan Agreement by and among the Registrant and its Subsidiaries, the Lenders from time to time party thereto and BNY Asset Solutions LLC, dated as of May 6, 2004, incorporated herein by reference to Exhibit 10.3 to the Registrant’s Registration Statement on Form S-1 filed August 13, 2004

10.4*	Employment Agreement between the Registrant and Peter T. Socha, dated as of May 7, 2004, incorporated herein by reference to Exhibit 10.4 to the Registrant’s Registration Statement on Form S-1 filed August 13, 2004


10.4a*	Amendment to Employment Agreement between the Registrant and Peter T. Socha, dated as of December 31, 2008

10.5*	2004 Equity Incentive Plan of the Registrant, incorporated herein by reference to Exhibit 10.5 to the Registrant’s Registration Statement on Form S-1 filed August 13, 2004

10.6	Form of Indemnification Agreement between the Registrant and its officers and directors, incorporated herein by reference to Exhibit 10.6 to the Registrant’s Registration Statement on Form S-1 filed August 13, 2004

10.7**	Agreement for Purchase and Sale of Coal among Georgia Power Company, the Registrant and James River Coal Sales, Inc., dated as of March 11, 2004, incorporated herein by reference to Exhibit 10.7 to the Registrant’s Registration Statement on Form S-1 filed August 13, 2004

10.8**	Agreement No. 2 for Purchase and Sale of Coal among Georgia Power Company, the Registrant and James River Coal Sales, Inc., dated as of May 15, 2008

10.8a**	First Amendment to Agreement No. 2 for Purchase and Sale of Coal among Georgia Power Company, the Registrant and James River Coal Sales, Inc., dated as of July 21, 2008

10.9**	Fuel Supply Agreement #141944 between South Carolina Public Service Authority and the Registrant, dated as of March 1, 2004, incorporated herein by reference to Exhibit 10.8 to the Registrant’s Registration Statement on Form S-1 filed August 13, 2004

10.9a**	Amendment to Fuel Supply #141944 between South Carolina Public Service Authority, the Registrant and James River Coal Sales, Inc., dated April 7, 2009.

10.10	Credit Agreement between Registrant and PNC Bank, National Association and Morgan Stanley Senior Funding, Inc. dated as of May 31, 2005, incorporated herein by reference to Exhibit 10.9 to the Registrant’s Quarterly Report on Form 10-Q filed November 14, 2005

10.11	Amendment No. 1 and Waiver to the Credit Agreement between the Registrant and PNC Bank, National Association and Morgan Stanley Senior Funding, Inc., dated as of February 22, 2006, incorporated herein by reference to Exhibit 10.11 to the Registrant’s Annual Report on Form 10-K filed March 16, 2006

10.12	Amendment No. 2 and Waiver to the Credit Agreement between the Registrant and PNC Bank, National Association and Morgan Stanley Senior Funding, Inc., dated as of May 30, 2006, incorporated herein by reference to Exhibit 10.13 to the Registrant’s Quarterly Report on Form 10-Q filed August 9, 2006

10.13	Amendment No. 3 and Waiver to the Credit Agreement between the Registrant and PNC Bank, National Association and Morgan Stanley Senior Funding, Inc., dated as of November 7, 2006, incorporated herein by reference to Exhibit 10.13 to the Registrant’s Annual Report on Form 10-K filed March 16, 2007

10.14	Amendment No. 4 to the Credit Agreement between the Registrant and PNC Bank, National Association and Morgan Stanley Senior Funding, Inc., dated as of December 27, 2006, incorporated herein by reference to Exhibit 10.14 to the Registrant’s Annual Report on Form 10-K filed March 16, 2007

10.15	Registration Rights Agreement between the Registrant and the Shareholders named therein, dated as of May 31, 2005, incorporated herein by reference to Exhibit 10.9 to the Registrant’s Annual report on Form 10-K filed March 16, 2006

10.16*	Severance and Retention Plan, effective as of March 13, 2006, incorporated herein by reference to Exhibit 10.12 to the Registrant’s Quarterly Report on Form 10-Q filed August 9, 2006

10.16a*	Amendment to Severance and Retention Plan dated as of December 31, 2008

10.17	$100,000,000 Term Credit Agreement by and among the Registrant, certain of its subsidiaries, the Lenders thereto, Morgan Stanley Senior Funding, Inc., as Administrative Agent, Sole Bookrunner and Lead Arranger, and Morgan Stanley & Co. Incorporated, as Collateral Agent, dated as of February 26, 2007, incorporated herein by reference to Exhibit 10.15 to the Registrant’s Annual Report on Form 10-K filed March 16, 2007


10.18	$35,000,000 Revolving Credit Agreement by and among the Registrant, certain of its subsidiaries, the Lenders thereto, and General Electric Capital Corporation, as Co-Lead Arranger, Administrative Agent and Collateral Agent, with Morgan Stanley Senior Funding, Inc., having acted as Co-Lead Arranger, dated as of February 26, 2007, incorporated herein by reference to Exhibit 10.16 to the Registrant’s Annual Report on Form 10-K filed March 16, 2007

10.19	Waiver, Consent and Second Amendment to Term Credit Agreement by and among the Registrant, certain of its subsidiaries, the Lenders thereto, Morgan Stanley Senior Funding, Inc., as Administrative Agent, Sole Bookrunner and Lead Arranger, and Morgan Stanley & Co. Incorporated, as Collateral Agent, dated as of August 7, 2007, incorporated herein by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed August 8, 2007

10.19a	Fifth Amendment to Term Credit Agreement by and among the Registrant, certain of its subsidiaries, and the other credit parties thereto, as guarantors, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as Administrative Agent and as Sole-Bookrunner and Lead Arranger, and Morgan Stanley & Co. Incorporated, as Collateral Agent, dated as of November 20, 2009, incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed November 25, 2009

10.20	Waiver, Consent and First Amendment to Revolving Credit Agreement by and among the Registrant, certain of its subsidiaries, the Lenders thereto, and General Electric Capital Corporation, as Co-Lead Arranger, Administrative Agent and Collateral Agent, with Morgan Stanley Senior Funding, Inc., having acted as Co-Lead Arranger, dated as of August 7, 2007, incorporated herein by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed August 8, 2007

10.21*	Annual Incentive Compensation Plan, incorporated herein by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed August 9, 2007

10.21a*	Amendment to Annual Incentive Compensation Plan, dated December 31, 2008

10.22	Amended and Restated Revolving Credit Agreement by and among the Registrant, James River Coal Service Company, Leeco, Inc., Triad Mining, Inc., Triad Underground Mining, LLC, Bledsoe Coal Corporation, Johns Creek Elkhorn Coal Corporation, Bell County Coal Corporation, James River Coal Sales, Inc., Bledsoe Coal Leasing Company, Blue Diamond Coal Company, and McCoy Elkhorn Coal Corporation, as Borrowers, the other Credit Parties thereto from time to time, as Guarantors, the Lenders party thereto from time to time, and General Electric Capital Corporation, as Administrative Agent and Collateral Agent, GE Capital Markets, Inc., and UBS Securities LLC, as Joint Lead Arrangers and Joint Bookrunners, and UBS Securities LLC, as Documentation Agent, dated as of January 28, 2010, incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K, dated February 3, 2010

12.1	Computation of Ratio of Earnings to Fixed Charges

21	Subsidiaries of the Registrant, incorporated herein by reference to Exhibit 21 to the Registrant’s Annual Report on Form 10-K filed March 16, 2006

23.1	Consent of Marshall Miller & Associates, Inc. (filed herewith)

23.2	Consent of KPMG LLP (filed herewith)

24	Power of Attorney (see signature page)


31.1	Certification of Peter T. Socha, President and Chief Executive Officer of James River Coal Company, pursuant to rule 13a-14(a) or 15d-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith)

31.2	Certification of Samuel M. Hopkins, II, Vice President and Chief Accounting Officer of James River Coal Company, pursuant to rule 13a-14(a) or 15d-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith)

32.1	Certification of Peter T. Socha, President and Chief Executive Officer of James River Coal Company, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith)

32.2	Certification of Samuel M. Hopkins, II, Vice President and Chief Accounting Officer of James River Coal Company, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith)


*	Management contract or compensatory plan or arrangement.
**	Portions of these documents have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment of the omitted portions.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Audited Financial Statements	Page

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2009 and 2008	F-3
Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007	F-5
Consolidated Statements of Changes in Shareholders’ Equity and Comprehensive Income (Loss) for the years ended December 31, 2009, 2008 and 2007	F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007	F-7
Notes to Consolidated Financial Statements	F-8

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors

James River Coal Company:

We have audited the accompanying consolidated balance sheets of James River Coal Company and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, changes in shareholders’ equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2009. We also have audited the Company’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of James River Coal Company and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ KPMG LLP

Richmond, VA

February 25, 2010

F-2

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Consolidated Balance Sheets

(in thousands, except share data)

	December 31, 2009		December 31, 2008
Assets

Current assets:
Cash and cash equivalents	$	107,931		3,324
Receivables:
Trade		43,289		33,086
Other		260		475
Total receivables		43,549		33,561
Inventories:
Coal		22,727		6,847
Materials and supplies		10,462		9,581
Total inventories		33,189		16,428
Prepaid royalties		6,045		2,803
Other current assets		3,292		5,094
Total current assets		194,006		61,210
Property, plant, and equipment, at cost:
Land		7,194		6,693
Mineral rights		231,919		229,841
Buildings, machinery and equipment		362,654		320,982
Mine development costs		41,069		39,596
Total property, plant, and equipment		642,836		597,112
Less accumulated depreciation, depletion, and amortization		288,748		252,264
Property, plant and equipment, net		354,088		344,848
Goodwill		26,492		26,492
Restricted cash (note 12)		62,042		5,222
Other assets		32,684		25,774
Total assets	$	669,312		463,546


See accompanying notes to consolidated financial statements.

F-3

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Consolidated Balance Sheets

(in thousands, except share data)

	December 31, 2009			December 31, 2008
Liabilities and Shareholders' Equity

Current liabilities:
Current maturities of long-term debt	$	-			18,000
Accounts payable		46,472			57,068
Accrued salaries, wages, and employee benefits		6,982			6,642
Workers' compensation benefits		8,950			9,300
Black lung benefits		1,782			1,539
Accrued taxes		4,383			4,457
Other current liabilities (note 3)		15,439			19,165
Total current liabilities		84,008			116,171
Long-term debt, less current maturities		278,268			150,000
Other liabilities:
Noncurrent portion of workers' compensation benefits		50,385			46,477
Noncurrent portion of black lung benefits		31,017			29,029
Pension obligations		14,827			19,693
Asset retirement obligations		39,843			36,409
Other		622			529
Total other liabilities		136,694			132,137
Total liabilities		498,970			398,308

Commitments and contingencies (note 12)
Shareholders' equity:
Preferred stock, $1.00 par value. Authorized 10,000,000 shares		-			-
Common stock, $.01 par value. Authorized 100,000,000 shares; issued and outstanding 27,544,878 and 27,393,493 shares as of December 31, 2009 and 2008, respectively		275			274
Paid-in-capital		320,079			272,366
Accumulated deficit		(136,758	)		(187,712	)
Accumulated other comprehensive loss		(13,254	)		(19,690	)
Total shareholders' equity		170,342			65,238

Total liabilities and shareholders' equity	$	669,312			463,546

See accompanying notes to consolidated financial statements.

F-4

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Consolidated Statements of Operations

(in thousands, except per share data)

	Year			Year			Year
	Ended			Ended			Ended
	December 31,			December 31,			December 31,
	2009			2008			2007

Revenues	$	681,558			568,507			520,560
Cost of sales:
Cost of coal sold		508,888			527,888			473,347
Gain on curtailment of pension plan		-			-			(6,091	)
Depreciation, depletion, and amortization		62,078			70,277			71,856
Total cost of sales		570,966			598,165			539,112
Gross profit (loss)		110,592			(29,658	)		(18,552	)
Selling, general, and administrative expenses		39,720			34,992			32,191
Total operating income (loss)		70,872			(64,650	)		(50,743	)
Interest expense		17,057			17,746			19,764
Interest income		(60	)		(469	)		(471	)
Charges associated with repayment and amendment of debt (note 4)		1,643			15,618			2,421
Miscellaneous income, net		(281	)		(1,279	)		(598	)
Total other expenses, net		18,359			31,616			21,116
Income (loss) before income taxes		52,513			(96,266	)		(71,859	)
Income tax expense (benefit)		1,559			(273	)		(17,844	)
Net income (loss)	$	50,954			(95,993	)		(54,015	)
Income (loss) per common share (note 13)
Basic income (loss) per common share	$	1.85			(3.91	)		(3.29	)

Diluted income (loss) per common share	$	1.85			(3.91	)		(3.29	)

See accompanying notes to consolidated financial statements.

F-5

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Consolidated Statements of Changes in Shareholders’

Equity and Comprehensive Income (Loss)

(in thousands)

Predecessor Company	Common stock shares			Common stock par value			Paid-in- capital			Retained earnings (accumulated deficit)			Accumulated other comprehensive income (loss)			Total

Balances, December 31, 2006		16,669		$	167			124,191			(37,704	)		(257	)		86,397
Net loss		-			-			-			(54,015	)		-			(54,015	)
Amortization of black lung liability		-			-			-			-			(180	)		(180	)
Black lung obligation adjustment, net of $(812) of tax		-			-			-			-			4,909			4,909
Pension liability adjustment, net of $969 of tax		-			-			-			-			(2,601	)		(2,601	)
Comprehensive loss																	(51,887	)
Issuance on common stock net of offering costs of $213		5,175			52			32,337			-			-			32,389
Issuance of restricted stock awards, net of forfeitures		135			1			(1	)		-			-			-
Repurchase of shares for tax withholding		(73	)		(1	)		(977	)		-			-			(978	)
Stock based compensation		-			-			3,853			-			-			3,853
Balances, December 31, 2007		21,906			219			159,403			(91,719	)		1,871			69,774
Net loss		-			-			-			(95,993	)		-			(95,993	)
Amortization of black lung liability		-			-			-			-			(562	)		(562	)
Black lung obligation adjustment		-			-			-			-			(5,334	)		(5,334	)
Pension liability adjustment		-			-			-			-			(15,665	)		(15,665	)
Comprehensive loss																	(117,554	)
Issuance on common stock, net of offering costs of $421		4,913			49			93,771			-			-			93,820
Common stock issued for acquisition of mineral rights (note 2)		388			4			15,996			-			-			16,000
Issuance of restricted stock awards, net of forfeitures		238			2			(2	)		-			-			-
Repurchase of shares for tax withholding		(72	)		-			(2,474	)		-			-			(2,474	)
Exercise of stock options		20			-			542			-			-			542
Stock based compensation		-			-			5,130			-			-			5,130
Balances, December 31, 2008		27,393			274			272,366			(187,712	)		(19,690	)		65,238
Net Income		-			-			-			50,954			-			50,954
Amortization of pension actuarial amount		-			-			-			-			1,606			1,606
Black lung obligation adjustment		-			-			-			-			(574	)		(574	)
Pension liability adjustment		-			-			-			-			5,404			5,404
Comprehensive income																	57,390
Equity component of convertible debt offering, net of offering costs of $1,433 (note 4)								43,385			-			-			43,385
Issuance of restricted stock awards, net of forfeitures		234			2			(2	)		-			-			-
Repurchase of shares for tax withholding		(87	)		(1	)		(1,712	)		-			-			(1,713	)
Exercise of stock options		5			-			75			-			-			75
Stock based compensation		-			-			5,967			-			-			5,967
Balances, December 31, 2009		27,545		$	275			320,079			(136,758	)		(13,254	)		170,342




See accompanying notes to consolidated financial statements.

F-6

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(in thousands)

	Year			Year			Year
	Ended			Ended			Ended
	December 31,			December 31,			December 31,
	2009			2008			2007
Cash flows from operating activities:
Net income (loss)	$	50,954			(95,993	)		(54,015	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, and amortization of property, plant, and equipment		62,078			70,277			71,856
Accretion of asset retirement obligations		3,212			2,768			2,270
Amortization of debt discount and issue costs		1,813			1,411			1,569
Stock-based compensation		5,967			5,130			3,853
Deferred income tax benefit		180			4			(18,572	)
Loss on sale or disposal of property, plant, and equipment		(61	)		(163	)		(87	)
Write-off of deferred financing costs		-			2,383			2,421
Gain on curtailment of pension plan		-			-			(6,091	)
Changes in operating assets and liabilities:
Receivables		(9,988	)		7,745			6,930
Inventories		(15,025	)		(2,236	)		(1,232	)
Prepaid royalties and other current assets		(1,440	)		100			(58	)
Restricted cash		(56,820	)		(5,222	)		-
Other assets		(4,233	)		(4,403	)		(2,929	)
Accounts payable		(10,596	)		9,762			4,576
Accrued salaries, wages, and employee benefits		340			632			1,277
Accrued taxes		(1,787	)		(2,251	)		(2,772	)
Other current liabilities		(3,626	)		8,702			(1,030	)
Workers' compensation benefits		3,558			2,185			8
Black lung benefits		1,657			538			1,435
Pension obligations		2,144			(1,395	)		(3,129	)
Asset retirement obligations		(861	)		(1,082	)		(1,457	)
Other liabilities		93			(468	)		(801	)
Net cash provided by (used in) operating activities		27,559			(1,576	)		4,022
Cash flows from investing activities:
Additions to property, plant, and equipment		(72,159	)		(74,697	)		(49,343	)
Proceeds from sale of property, plant and equipment		149			1,108			142
Net cash used in investing activities		(72,010	)		(73,589	)		(49,201	)
Cash flows from financing activities:
Proceeds from issuance of long-term debt		172,500			-			40,000
Repayment of long-term debt		-			(38,800	)		(1,200	)
Proceeds from Revolver		12,500			26,500			31,043
Repayments of Revolver		(30,500	)		(8,500	)		(48,536	)
Net proceeds from issuance of common stock		-			93,820			32,389
Principal payments under capital lease obligations		-			-			(262	)
Debt issuance costs		(5,517	)		(486	)		(4,649	)
Proceeds from exercise of stock options		75			542			-
Net cash provided by financing activities		149,058			73,076			48,785
Increase (decrease) in cash		104,607			(2,089	)		3,606
Cash and cash equivalents at beginning of period		3,324			5,413			1,807
Cash and cash equivalents at end of period	$	107,931			3,324			5,413


See accompanying notes to consolidated financial statements.

F-7

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(1)	Summary of Significant Accounting Policies and Other Information

Description of Business and Principles of Consolidation

James River Coal Company and its wholly owned subsidiaries (collectively the Company) mine, process and sell bituminous, steam- and industrial-grade coal through five operating complexes located throughout eastern Kentucky and one in southern Indiana. Substantially all coal sales and account receivables relate to the electric utility and industrial markets.

The consolidated financial statements include the accounts of James River Coal Company and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

Cash and Cash Equivalents and Restricted Cash

Cash and cash equivalents are stated at cost. Cash equivalents consist of highly-liquid investments with an original maturity of three months or less when purchased.

Restricted cash is stated at cost. The restricted cash is held in an account to secure the Company’s letters of credit (note 12).

Trade Receivables

Trade receivables are recorded at the invoiced amount and do not bear interest. The Company evaluates the need for an allowance for doubtful accounts based on review of historical write off experience. The Company has determined that no allowance is necessary for trade receivables as of December 31, 2009 and 2008. The Company does not have any off-balance sheet credit exposure related to its customers.

Inventories

Inventories of coal and materials and supplies are stated at the lower of cost or market. Cost is determined using the average cost for coal inventories and the first-in, first-out method for materials and supplies. Coal inventory costs include labor, supplies, equipment cost, depletion, royalties, black lung tax, reclamation tax and preparation plant cost.

Asset Retirement Obligations

The Company’s asset retirement obligation liabilities primarily consist of spending estimates related to reclaiming surface land and support facilities at both surface and underground mines in accordance with federal and state reclamation laws. Asset retirement obligations are initially recorded as a liability based on fair value, which is calculated as the present value of the estimated future cash flows, in the period in which it is incurred. The estimate of ultimate reclamation liability and the expected period in which reclamation work will be performed is reviewed periodically by the Company’s management and engineers. In estimating future cash flows, the Company considers the estimated current cost of reclamation and applies inflation rates and a third party profit. The third party profit is an estimate of the approximate markup that would be charged by contractors for work performed on behalf of the Company. When the liability is initially recorded, the offset is capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Accretion expense is included in cost of produced coal. To the extent there is a difference between the liability recorded and the cost incurred, a gain or loss upon settlement is recognized. The following table sets forth the changes in the Company’s asset retirement obligations at December 31, 2009 and 2008 (in thousands):

F-8

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

	2009			2008
Asset retirement obligations at beginning of year	$	41,509		$	34,318
Liabilities incurred		1,246			5,508
Liabilities disposed		(621	)		-
Revisions in estimated cash flows		190			-
Accretion expense		3,212			2,768
Liabilities settled		(693	)		(1,085	)
Asset retirement obligations at end of year		44,843			41,509
Less amount included in other current liabilities		(5,000	)		(5,100	)
Total non-current liability	$	39,843		$	36,409

Property, Plant, and Equipment

Expenditures for maintenance and repairs are charged to expense, and the costs of mining equipment rebuilds and betterments that extend the useful life are capitalized. Depreciation is provided principally using the straight-line method based upon estimated useful lives, generally ten to 20 years for buildings and one to seven years for machinery and equipment. Equipment held under capital leases is amortized using the straight line method over the lesser of the lease term or the estimated useful life of the asset. Mine development costs are capitalized and amortized by the units of production method over estimated total recoverable proven and probable reserves. Amortization of mineral rights is provided by the units of production method over estimated total recoverable proven and probable reserves.

Impairment of Long-Lived Assets

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

Goodwill

Goodwill represents the excess of purchase price and related costs over the value assigned to the net tangible and identifiable intangible assets of businesses acquired. Goodwill is not amortized but is tested for impairment annually, or if certain circumstances indicate a possible impairment may exist. Impairment testing is performed at a reporting unit level. An impairment loss generally would be recognized when the carrying amount of the reporting unit exceeds the fair value of the reporting unit, with the fair value of the reporting unit determined using a discounted cash flow analysis.

Prepaid Royalties

Mineral rights are often acquired in exchange for advance royalty payments. Royalty payments representing prepayments recoupable against future production are capitalized, and amounts expected to be recouped within one year are classified as a current asset. As mining occurs on these leases, the prepayment is offset against earned royalties and is included in the cost of coal sold. Amounts determined to be nonrecoupable are charged to expense.

F-9

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Revenue Recognition

Revenues include sales to customers of Company-produced coal and coal purchased from third parties. The Company recognizes revenue from the sale of Company-produced coal and coal purchased from third parties at the time delivery occurs and risk of loss passes to the customer, which is either upon shipment or upon customer receipt of coal based on contractual terms. Also, the sales price must be determinable and collection reasonably assured.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.

The Company evaluates its deferred tax assets to determine the necessity of a valuation allowance. A valuation allowance is required if it is more likely than not that some portion of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, the Company takes into account various factors, including the expected level of future taxable income. The Company also considers tax planning strategies in determining the deferred tax asset that will ultimately be realized.

Our effective income tax rate is impacted by the amount of the valuation allowance recorded and percentage depletion. 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 the cost bases of the properties, it creates a permanent difference and directly impacts the effective tax rate. Fluctuations in the effective tax rate may occur between fiscal periods due to the varying levels of profitability (and thus, taxable income and percentage depletion) at each of our mine locations.

The Company records interest and penalties, if any, associated with income taxes as a component of income tax expense.

Accumulated Other Comprehensive Income (Loss)

The accumulated other comprehensive income (loss) at December 31, 2009, includes a $12.8 million actuarial loss on the Company’s pension plan and a $0.4 million actuarial loss on its black lung obligation. The accumulated other comprehensive loss at December 31, 2008, includes a $19.9 million actuarial loss on the Company’s pension plan and a $0.2 million actuarial gain on its black lung obligation.

Workers’ Compensation

The Company is liable for workers’ compensation benefits for traumatic injuries under state workers’ compensation laws in which it has operations. Except as indicated, the Company is self insured for workers’ compensation for its Kentucky operations, with specific excess insurance purchased from independent insurance carriers to cover individual traumatic claims in excess of the self-insured limits. For the period June 2002 to June 2005, workers compensation coverage was insured through a third party insurance company using a large risk rating plan. The Company’s operations in Indiana are insured through a third party insurance company using a large risk rating plan.

The Company accrues for workers’ compensation benefits by recognizing a liability when it is probable that the liability has been incurred and the cost can be reasonably estimated. The Company provides information to independent actuaries, who after review and consultation with the Company with regards to actuarial assumptions, including the discount rate, prepare an estimate of the liabilities for workers’ compensation benefits.

F-10

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Black Lung Benefits

The Company is responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, and various states’ statutes for the payment of medical and disability benefits to employees and their dependents resulting from occurrences of coal worker’s pneumoconiosis disease (black lung). The Company provides coverage for federal and state black lung claims through its self-insurance programs for its Central Appalachia operations. For the period between June 2002 and June 2005, all black lung liabilities were insured through a third party insurance company using a large risk rating plan. The Company’s operations in Indiana are insured through a third party insurance company using a large risk rating plan. The Company uses the service cost method to account for its self-insured black lung obligation. The liability measured under the service cost method represents the discounted future estimated cost for former employees either receiving or projected to receive benefits, and the portion of the projected liability relative to prior service for active employees projected to receive benefits.

The periodic expense for black lung claims under the service cost method represents the service cost, which is the portion of the present value of benefits allocated to the current year, interest on the accumulated benefit obligation, and amortization of unrecognized actuarial gains and losses. Actuarial gains and losses are included as a component of accumulated other comprehensive income (loss) and are amortized over the average remaining work life of the workforce.

Annual actuarial studies are prepared by independent actuaries using certain assumptions to determine the liability. The calculation is based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents, and interest rates. These assumptions are derived from actual Company experience and industry sources.

Health Claims

Company is self-insured for certain health care coverage. The cost of this self-insurance program is accrued based upon estimates of the costs for known and anticipated claims. The Company recorded an estimated amount to cover known claims and claims incurred but not reported of $2.2 million and $2.8 million as of December 31, 2009 and 2008, respectively, which is included in accrued salaries, wages, and employee benefits.

Equity-Based Compensation Plan

The Company’s stock compensation expense is based on estimated grant-date fair values. Compensation expense is adjusted for estimated forfeitures and is recognized on a straight-line basis over the requisite service period of the award. The Company’s estimated future forfeiture rates are based on its historical experience.

Use of Estimates

Management of the Company has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in order to prepare these consolidated financial statements in conformity with U.S. generally accepted accounting principles (U.S. GAAP). Significant estimates made by management include the valuation allowance for deferred tax assets, asset retirement obligations and amounts accrued related to the Company’s workers’ compensation, black lung, pension and health claim obligations. Actual results could differ from these estimates.

Recent Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162. This statement modifies the Generally Accepted Accounting Principles (“GAAP”) hierarchy by establishing only two levels of GAAP, authoritative and nonauthoritative accounting literature. Effective July 2009, the FASB Accounting Standards Codification (“ASC”), also known collectively as the “Codification,” is considered the single source of authoritative U.S. accounting and reporting standards, except for additional authoritative rules and interpretive releases issued by the SEC. Nonauthoritative guidance and literature would include, among other things, FASB Concepts Statements, American Institute of Certified Public Accountants Issue Papers and Technical Practice Aids and accounting textbooks. The Codification was developed to organize GAAP pronouncements by topic so that users can more easily access authoritative accounting guidance. It is organized by topic, subtopic, section, and paragraph, each of which is identified by a numerical designation. All accounting references have been updated, and therefore SFAS references have been replaced with ASC references.

F-11

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

The guidance in Earnings Per Share Topic, ASC 260-10-45, addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting, and therefore need to be included in the earnings allocation in computing earnings per share under the two-class method. Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share pursuant to the two-class method. The Company’s unvested restricted stock awards are considered “participating securities” because they contain non-forfeitable rights to dividends. The guidance in ASC 260-10-45-59(A) is effective for the Company’s financial statements January 1, 2009, and all prior-period earnings per share data presented has been adjusted retrospectively (note 13).

(2)	Acquisition of Mineral Rights

In July 2008, the Company closed a transaction under an Asset Purchase Agreement to acquire certain coal reserves and permits from Cheyenne Resources, Inc. The acquired assets include approximately 10.2 million tons of proven and probable surface reserves and 3.6 million tons of proven and probable underground reserves, plus additional surface resources. The purchase price for the acquisition was $36 million, comprised of $16 million in cash at closing, a short term promissory note for $4 million that was paid in full September 2008 and 387,973 shares of newly issued common stock of the Company, valued at $16 million (shares valued based on the most recent closing price prior to closing).

(3)	Other Current Liabilities

Other current liabilities at December 31, 2009 and 2008 are as follows (in thousands):

	2009		2008
Accrued interest and amendment fees	$	2,069		6,689
Current portion of asset retirement obligation		5,000		5,100
Accrued royalties		7,746		5,508
Other		624		1,868
	$	15,439		19,165

(4)	Long Term Debt and Interest Expense

Long-term debt is as follows at December 31, 2009 and 2008 (in thousands):

	2009		2008
Senior Notes	$	150,000		150,000
Convertible Senior Notes, net of discount		128,268		-
Revolver / Prior Revolver		-		18,000
Total long-term debt		278,268		168,000
Less amounts classified as current		-		18,000
Total long-term debt, less current maturities	$	278,268		150,000

F-12

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Scheduled maturities of long-term debt are as follows (in thousands):

Year ended December 31:
2010	$	-
2011		-
2012		150,000
2013		-
2014		-
Thereafter		172,500
	$	322,500

Senior Notes

The $150 million of Senior Notes are due on June 1, 2012 (the Senior Notes). The Senior Notes are unsecured and accrue interest at 9.375% per annum. Interest payments on the Senior Notes are required semi-annually. The Company may redeem the Senior Notes, in whole or in part, at any time at redemption prices ranging from 102.34% in 2010 to 100% in 2011.

The Senior Notes limit the Company’s ability, among other things, to pay cash dividends. In addition, if a change of control occurs (as defined in the Indenture), each holder of the Senior Notes will have the right to require the Company to repurchase all or a part of the Senior Notes at a price equal to 101% of their principal amount, plus any accrued interest to the date of repurchase.

Convertible Senior Notes

During the fourth quarter of 2009, the Company issued $172.5 million of 4.5% Convertible Senior Notes due on December 1, 2015 (the “Convertible Senior Notes”). The Company recorded a discount on the Convertible Senior Notes of $44.8 million related to the portion of the proceeds that were allocated to the equity component of the Convertible Senior Notes. The Convertible Senior Notes are unsecured and are convertible under certain circumstances and during certain periods at an initial conversion rate of 38.7913 shares of the Company’s common stock per $1,000 principal amount of Convertible Senior Notes, representing an initial conversion price of approximately $25.78 per share of the Company’s stock. Interest payments on the Convertible Senior Notes are required semi-annually. The Convertible Senior Notes are shown net of a $44.2 million discount on the consolidated financials statements as of December 31, 2009.

The Company used approximately $62.0 million of the net proceeds in connection with the termination of its Prior Letter of Credit Facility (see below), and the remaining for working capital and general corporate purposes. The Company incurred approximately $5.5 million of costs in connection with the issuance of the Convertible Senior Notes issuance. The issuance costs allocated to the debt are being amortized using the effective interest rate method over the life of the Convertible Senior Notes.

None of the Convertible Senior Notes are currently eligible for conversion. The Convertible Senior Notes are convertible at the option of the holders (with the length of time the Notes are convertible being dependent upon the conversion trigger) upon the occurrence of any of the following events:

At any time from September 1, 2015 until December 1, 2015;

If the closing sale price of the Company’s common stock for each of 20 or more trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the conversion price of the Notes in effect on the last trading day of the immediately preceding calendar quarter;

If the trading price of the Convertible Senior Notes for each trading day during any five consecutive business day period, as determined following a request of a holder of Notes, was equal to or less than 97% of the “Conversion Value” of the Notes on such trading day; or

If the Company elects to make certain distributions to the holders of its common stock or engage in certain corporate transactions.

F-13

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Revolver

In January 2010, the Company amended and restated its 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 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 the Company 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 EBITDA and maximum Leverage Ratio covenants are only applicable if the Company’s unrestricted cash balance falls below $75.0 million and remain in effect until the Company’s unrestricted cash exceeds $75 million for 90 consecutive days.

The Company expects to use the Revolver to secure its outstanding letters of credit. The Company intends to place cash in a restricted account to provide it with the maximum borrowing base under the revolver.

Prior Revolver and Prior Term Credit Agreement

In 2007, the Company entered into a $35.0 million Revolving Credit Agreement (the Prior Revolver) and a Prior Term Credit Agreement (collectively the Facilities). The Prior Term Credit Agreement consisted of a term facility (the Prior Term Facility) and a $60.0 million letter of credit facility (the Prior Letter of Credit Facility).

As discussed above, the terms of the Prior Revolver were amended and restated in January 2010. There were no amounts outstanding on the Prior Revolver as of December 31, 2009.

The Company repaid the outstanding balance of the Prior Term Facility in October 2008 and used $5.2 million of the Company’s cash to secure letters of credit under the Prior Letter of Credit Facility. The Companies fees under the Prior Letter of Credit Facility were 10.0% effective January 1, 2009 and 12.5% effective April 1, 2009. In December 2009, the Company terminated the Prior Letter of Credit Facility and secured 105% of the letters of credit that were outstanding under the Prior Letter of Credit Facility with approximately $62.0 million in cash. The cash used to secure the letters of credit is shown as restricted cash on the Company’s consolidated balance sheets. The Company expensed $1.6 million in 2009 in connection with a fee to terminate the Prior Letter of Credit Facility and included the fee in charges associated with the repayment and amendment of debt in the consolidated financials statements for the year ended December 31, 2009.

F-14

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

In connection with repayment of the Prior Term Facility, the Company expensed approximately $2.4 million of unamortized financing charges on the Prior Term Facility in the year ended December 31, 2008. In 2008, the Company expensed and paid approximately $7.8 million of costs associated with the two credit amendments to the Facilities. In 2008, the Company also expensed and had unpaid fees of approximately $5.5 million of costs associated with the amendments that were paid in 2009. The write-off of the unamortized financing charges and the expenses associated with the amendments to the Credit Amendments are included in charges associated with the repayment and amendment of debt in the consolidated financials statements for the year ended December 31, 2008.

Prior Senior Secured Credit

During the year ended December 31, 2007, the Company wrote off $2.4 million of financing charges in connection with the repayment of a Prior Senior Secured Credit Facility. The write off of the financing charges is classified as charges associated with repayment and amendment of debt in the accompanying consolidated statements of operations.

Interest Expense

During the years ended December 31, 2009, 2008 and 2007, the Company paid $14.4 million, $16.8 million, and $18.2 million in interest, respectively.

Other

The Convertible Senior Notes rank equally with all of the Company’s existing and future senior unsecured indebtedness, including the Company’s unsecured Senior Notes. The Convertible Senior Notes are not guaranteed by any of James River Coal Company’s subsidiaries, while the Company’s unsecured Senior Notes are guaranteed by certain of James River Coal Company’s subsidiaries. The Convertible Senior Notes are effectively subordinated to all of the Company’s existing and future secured indebtedness (to the extent of the assets securing such indebtedness) and structurally subordinated to all existing and future liabilities of James River Coal Company’s subsidiaries, including their trade payables. The Revolver is secured by substantially all of the Company’s assets.

The Company was in compliance with all of the financial covenants under its outstanding debt instruments as of December 31, 2009.

(5)	Workers’ Compensation Benefits

As of December 31, 2009 and 2008, workers’ compensation benefit obligation consisted of the following (in thousands):

	2009		2008
Workers' compensation benefits	$	59,335		55,777
Less current portion		8,950		9,300
Noncurrent portion of workers' compensation benefits	$	50,385		46,477

Actuarial assumptions used in the determination of the liability for the self-insured portion of workers’ compensation benefits included a discount rate of 5.3%, 6.0%, and 6.0% at December 31, 2009, 2008 and 2007, respectively.

F-15

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(6)	Pneumoconiosis (Black Lung) Benefits

As of December 31, 2009 and 2008, black lung benefits obligation consisted of the following (in thousands):

	2009		2008
Black lung benefits	$	32,799		30,568
Less current portion		1,782		1,539
Noncurrent portion of black lung benefits	$	31,017		29,029

A reconciliation of the changes in the black lung benefit obligation is as follows (in thousands):

	2009			2008
Beginning of the year black lung obligation	$	30,568			24,134
Black lung actuarial liability adjustment		575			5,334
Service cost		1,225			480
Interest cost		1,712			1,962
Benefit payments		(1,281	)		(1,342	)
End of year accumulated black lung obligation	$	32,799			30,568

The actuarial assumptions used in the determination of accumulated black lung obligations as of December 31, 2009 and 2008 included a discount rate of 5.8% and 5.8%, respectively. A 1.0% decrease in the discount rate used at December 31, 2009, would increase the black lung obligation by approximately $4.6 million. For purposes of determining net periodic expense related to such obligations, the Company used a discount rate of 5.8%, 6.5%, and 5.5% for the years ended December 31, 2009, 2008 and 2007.

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

	2009		2008			2007
Service cost	$	1,225		480			388
Interest cost		1,712		1,962			1,589
Amortization of actuarial amount		-		(562	)		(180	)
Net periodic benefit cost	$	2,937		1,880			1,797

As of December 31, 2009, the Company has a $0.4 million actuarial loss recorded in accumulated other comprehensive income (loss) on its black lung obligation. The Company expects that it will not recognize any of this actuarial loss during the year ended December 31, 2010.

(7)

Equity

Preferred Stock and Shareholder Rights Agreement

The Company has authorized 10,000,000 shares of preferred stock, $1.00 par value per share, the rights and preferences of which are established by the Board of the Directors. The Company has reserved 500,000 of these shares as Series A Participating Cumulative Preferred Stock for issuance under a shareholder rights agreement (the Rights Agreement).

F-16

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

On May 25, 2004, the Company’s shareholders approved the Rights Agreement and declared a dividend of one preferred share purchase right (Right) for each two shares of common stock outstanding. Each Right entitles the registered holder to purchase from the Company one one-hundredth (1/100) of a share of our Series A Participating Cumulative Preferred Stock, par value $1.00 per share, at a price of $200 per one one-hundredth of a Series A preferred share. The Rights are not exercisable until a person or group of affiliated or associated persons (an Acquiring Person) has acquired or announced the intention to acquire 20% or more of the Company’s outstanding common stock.

In 2009, an amendment to the Rights Agreement reduced, until December 5, 2010, the threshold at which a person or group becomes an “Acquiring Person” under the Rights Agreement from 20% to 4.9% of the Company’s then-outstanding shares of common stock. The Rights Agreement, as amended, exempts shareholders whose beneficial ownership as of November 3, 2009 exceeded 4.9% of the Company’s then-outstanding shares of common stock so long as they do not acquire more than an additional 0.5% of the Company’s then-outstanding shares of common stock without the advance approval of the Company’s board of directors.

In the event that the Company is acquired in a merger or other business combination transaction or 50% or more of the Company’s consolidated assets or earning power is sold after a person or group has become an Acquiring Person, each holder of a Right, other than the Rights beneficially owned by the Acquiring Person (which will thereafter be void), will receive, upon the exercise of the Right, that number of shares of common stock of the acquiring company which at the time of such transaction will have a market value of two times the exercise price of the Right. In the event that any person becomes an Acquiring Person, each Right holder, other than the Acquiring Person (whose Rights will become void), will have the right to receive upon exercise that number of shares of common stock having a market value of two times the exercise price of the Right.

The rights will expire May 25, 2014, unless that expiration date is extended. The Board of Directors may redeem the Rights at a price of $0.001 per Right at any time prior to the time that a person or group becomes an Acquiring Person.

Equity Based Compensation

Under the 2004 Equity Incentive Plan (the Plan), participants may be granted stock options (qualified and nonqualified), stock appreciation rights (SARs), restricted stock, restricted stock units, and performance shares. The total number of shares that may be awarded under the Plan is 2,400,000, and no more than 1,000,000 of the shares reserved under the Plan may be granted in the form of incentive stock options. The Company currently has the following types of equity awards outstanding under the Plan.

Restricted Stock Awards

Pursuant to the Plan certain directors and employees have been awarded restricted common stock with such shares vesting over two to five years. The related expense is amortized over the vesting period.

Stock Option Awards

Pursuant to the Plan certain directors and employees have been awarded options to purchase common stock with such options vesting ratably over three to five years. The Company’s stock options have been issued at exercise prices equal to or greater than the fair value of the Company’s stock at the date of grant.

Shares awarded or subject to purchase under the Plan that are not delivered or purchased, or revert to the Company as a result of forfeiture or termination, expiration or cancellation of an award or that are used to exercise an award or for tax withholding, will be again available for issuance under the Plan. At December 31, 2009, there were 843,816 shares available under the Plan for future awards.

F-17

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

The following table highlights the expense related to share-based payment for the periods ended December 31 (in thousands):

	2009		2008		2007
Restricted stock	$	5,655		4,813		3,535
Stock options		312		317		318
Stock based compensation	$	5,967		5,130		3,853

The fair value of the restricted stock issued and outstanding is equal to the value of shares at the grant date. At this time, the Company does not expect any of its restricted shares or options to be forfeited before vesting. The fair value of stock options was estimated using the Black-Scholes option pricing model. The Company used the following assumptions to value the stock options issued during the periods indicated below:

	Year Ended	Year Ended	Year Ended
	December 31, 2009	December 31, 2008	December 31, 2007
Dividend yield	0.0%	0.0%	0.0%
Expected volatility factor(1)	90.0%	70.0%	50.0%
Weighted average expected volatility	90.0%	70.0%	50.0%
Risk-free interest rate(2)	2.6%	3.4%	4.8%
Expected term (in years)	6.5	6.5	6.5

(1)	The Company used historical experience to estimate its volatility.

(2)	The risk-free interest rate for periods is based on U.S. Treasury yields in effect at the time of grant.

The following is a summary of restricted stock and stock option awards:

	Restricted Stock					Stock Options
				Weighted					Weighted
	Number of			Average		Number of			Average
	Shares			Fair Value		Shares			Exercise
	Outstanding			at Issue		Outstanding			Price
January 1, 2007		739,720		$	18.25		261,001		$	16.07
Granted		148,036			4.65		25,000			14.60
Exercised/Vested		(198,509	)		16.37		-			-
Canceled		(12,940	)		17.39		(21,667	)		17.72
December 31, 2007		676,307			15.84		264,334			15.79
Granted		244,140			35.68		20,000			36.30
Exercised/Vested		(212,598	)		15.62		(20,000	)		27.12
Canceled		(5,800	)		19.16		(3,334	)		14.84
December 31, 2008		702,049			22.78		261,000			16.51
Granted		234,311			13.87		20,000			13.87
Exercised/Vested		(218,708	)		16.27		(5,000	)		15.00
Canceled		-			-		-			-
December 31, 2009		717,652		$	21.86		276,000		$	16.34

F-18

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

The following table summarizes additional information about the stock options outstanding at December 31, 2009.

	Range of Exercise Price	Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (1) (in 000's)

Outstanding at December 31, 2009	$10.80-$36.30	276,000	$	16.34	5.5	$	1,404

Exercisable at December 31, 2009	$10.80-$36.30	236,004	$	15.47	4.9	$	1,286

Vested and expected to vest at December 31, 2009		276,000	$	16.34	5.5	$	1,404

(1) The difference between a stock award's exercise price and the underlying stock's market price at December 31, 2009
No value is assigned to stock awards whose option price exceeds the stock's market price at December 31, 2009.

The following table summarizes the Company’s total unrecognized compensation cost related to stock based compensation as of December 31, 2009.

			Weighted Average
			Remaining Period
	Unearned		Of Expense
	Compensation		Recognition
	(in 000's)		(in years)
Stock Options	$	414		1.7
Restricted Stock		9,850		2.7
Total	$	10,264

(8)	Income Taxes

Income tax expense (benefit) consists of the following (in thousands):

	2009		2008			2007
Current:
Federal	$	1,354		-			-
State		25		(277	)		728
		1,379		(277	)		728
Deferred:
Federal		165		53			(16,320	)
State		15		(49	)		(2,252	)
		180		4			(18,572	)
	$	1,559		(273	)		(17,844	)

F-19

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

A reconciliation of income taxes computed at the statutory federal income tax rate to the expense (benefit) for income taxes included in the consolidated statements of operations is presented below:

	2009			2008			2007

Federal income taxes at statutory rates		34.0	%		(34.0	) %		(34.0	) %
Percentage depletion		(25.8	)		(3.8	)		(3.8	)
Effect of state tax rate change, net		(0.2	)		(0.1	)		-
Change in valuation allowance		(6.2	)		39.2			13.2
State income taxes, net of federal		0.4			(2.4	)		(1.9	)
Other, net		0.8			0.8			1.7
		3.0	%		(0.3	) %		(24.8	) %

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2009 and 2008 are presented below (in thousands):

	2009		2008
Deferred tax assets:
Accruals for financial reporting purposes, principally workers' compensation and black lung obligations	$	55,001		50,523
Net operating loss carryforwards		73,504		84,930
Accumulated comprehensive income, principally pension		4,718		7,012
Other		1,405		-
Total gross deferred tax assets		134,628		142,465
Less valuation allowance		33,247		54,299
Net deferred tax asset		101,381		88,166
Deferred tax liabilities:
Discount on Senior Convertible Notes		15,824		-
Other - principally property, plant and equipment due to differences in depreciation, depletion and amortization		80,486		82,915
Total gross deferred tax liability		96,310		82,915
Net deferred tax asset	$	5,071		5,251

The net deferred tax asset is included in other assets. The valuation allowance is based on an assumption that not all of the gross deferred tax asset recorded will more likely than not be realized.

At December 31, 2009, the Company has consolidated NOLs for federal income tax purposes of approximately $204 million that expire beginning in 2023 and consolidated Kentucky net operating loss carryforwards of approximately $98 million which expire beginning in 2023. Approximately $88 million of the federal NOLs and $54 million of the state NOLs are limited in the amount that can be used in a given year by Section 382 of the Internal Revenue Code. Prior to application of the valuation allowance, these net operating loss carryforwards generate a combined federal and state tax benefit of approximately $73.5 million.

The Company has analyzed filing positions in all of the federal and state jurisdictions where it is required to file income tax returns, as well as all open tax years in these jurisdictions. The Company has identified its federal tax return and its state tax returns in Virginia, Kentucky and Indiana as “major” tax jurisdictions. The only periods subject to examination for the Company’s federal return are the 2006 through 2009 tax years. The periods subject to examination for the Company’s state returns in Virginia are years 2006 through 2009; Kentucky are years 2005 through 2009 and Indiana are years 2006 through 2009. The Company believes that its income tax filing positions and deductions will be sustained on audit and does not anticipate any adjustments that will result in a material change to its consolidated financial position. Therefore, no reserves for uncertain income tax positions have been recorded.

F-20

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

During the year ended December 31, 2009, the Company paid income taxes of $1.6 million. The Company received $0.1 million of income tax refunds during 2008. The Company received no income tax refunds during 2007. The income tax benefit (expense) includes no interest and penalties for the year ended December 31, 2009 and 2008 and $0.2 million of interest and penalties for the year ended December 31, 2007.

(9)	Employee Benefit Plans

Defined Benefit Pension Plan

In 2007, the Company froze pension plan benefit accruals for all employees covered under its qualified non-contributory defined benefit pension plan. The Company’s funding policy is to contribute annually an amount at least equal to the minimum funding requirements actuarially determined in accordance with the Employee Retirement Income Security Act of 1974.

The plan assets for the qualified defined benefit pension plan are held by an independent trustee. The plan’s assets include investments in cash and cash equivalents and mutual funds holding corporate and government bonds and preferred and common stocks. The Company has an internal investment committee that sets investment policy, selects and monitors investment managers and monitors asset allocation.

The investment policy for the pension plan assets includes the objectives of providing growth of capital and income while achieving a target annual rate of return of 7.5% over a full market cycle, approximately 5 to 7 years. Diversification of assets is employed to reduce risk. The current target asset allocation is 70% for equity securities (including 45% Large Cap, 15% Small Cap, 10% International) and 30% for cash and interest bearing securities. The investment policy is based on the assumption that the overall portfolio volatility will be similar to that of the target allocation. Given the volatility of the capital markets, strategic adjustments in various asset classes may be required to rebalance asset allocation back to its target policy. Investment fund managers are not permitted to invest in certain securities and transactions as outlined by the investment policy statements specific to each investment category without prior investment committee approval.

To develop the expected long-term rate of return on assets assumption, the Company performs a periodic analysis which considers the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of the pension portfolio. This evaluation resulted in the selection of the 7.5% long-term rate of return on assets assumption for the year ended December 31, 2009.

The Company utilizes a fair value hierarchy, which maximizes the use of observable inputs and minimizes the use of unobservable inputs when measuring fair value. The plan assets are valued at level 1 of the fair value hierarchy by using unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The fair value of the major categories of qualified defined benefit pension plan assets includes the following (in thousands):

	2009				2008
	Amount		Percentage		Amount		Percentage
Mutual funds - equity	$	28,987		57.6%	$	21,754		51.1%
Mutual funds - international equity		4,980		9.9%		4,062		9.6%
Mutual funds - fixed taxable		16,097		32.0%		16,462		38.7%
Money market funds and cash		270		0.5%		271		0.6%
	$	50,334		100.0%	$	42,549		100.0%

F-21

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

The following table sets forth changes in the plan’s benefit obligations, changes in the fair value of plan assets, and funded status at December 31, 2009 and 2008 (in thousands):

	2009			2008
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	62,242			63,974
Interest cost		3,660			3,645
Actuarial (gain) loss		1,582			(2,530	)
Benefits paid		(2,323	)		(2,847	)
Projected benefit obligation at end of year	$	65,161			62,242
Change in plan assets:
Fair value of plan assets at beginning of year	$	42,549			58,550
Actual return on plan assets		10,085			(13,837	)
Employer contributions		23			683
Benefits paid		(2,323	)		(2,847	)
Fair value of plan assets at end of year	$	50,334			42,549
Reconciliation of funded status:
Funded status	$	(14,827	)		(19,693	)
Net amount recognized	$	(14,827	)		(19,693	)
Amounts recognized in the consolidated balance sheets
consist of:
Accrued benefit liability	$	(14,827	)		(19,693	)

The accumulated benefit obligation of the plan was $65.2 million and $62.2 million as of December 31, 2009 and 2008, respectively. Company contributions in 2010 are expected to be approximately $3.1 million.

The components of net periodic benefit cost and benefits paid by period are as follows (in thousands):

	2009			2008			2007
Service cost	$	-			-			2,173
Interest cost		3,660			3,645			3,611
Expected return on plan assets		(3,099	)		(4,358	)		(4,203	)
Recognized net actuarial loss		1,606			-			-
Gain on curtailment		-			-			(6,110	)
Net periodic benefit cost	$	2,167			(713	)		(4,529	)

Benefits paid	$	2,323			2,847			2,777

As of December 31, 2009 and 2008 the Company had a $12.8 million and a $19.9 million net actuarial loss recorded in accumulated other comprehensive loss on its defined benefit plan. The Company expects to recognize $0.8 million of the net actuarial loss in the year ended December 31, 2010.

F-22

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

The weighted-average assumptions used to determine the pension benefit obligations are as follows:

	2009	2008
Discount rate	5.9%	6.0%
Expected return on plan assets	7.5%	7.5%
Measurement date	December 31, 2009	December 31, 2008

The weighted-average assumptions used to determine the net periodic benefit cost are as follows:

			Three months	Nine months
			Ended	Ended
			December 31,	September 30,
	2009	2008	2007	2007
Discount rate	6.0%	5.8%	6.0%	5.6%
Expected return on plan assets	7.5%	7.5%	7.5%	7.5%
Rate of compensation increase	Not applicable	Not applicable	Not applicable	4.0%
Measurement date	December 31, 2008	December 31, 2007	September 30, 2007	October 1, 2006

The following benefit payments are expected to be paid (based on the assumptions described above (in thousands)).

Year ended December 31:
2010	$	2,763
2011		2,965
2012		3,143
2013		3,296
2014		3,527
2015-2019		19,959

Savings and Profit Sharing Plan

The Company sponsors defined contribution pension plans and profit sharing plans. All U.S. employees are eligible for at least one of the Company’s plans. The Company’s contributions vary depending on the plan and cannot exceed the maximum allowable for tax purposes. The Company recognized approximately $3.3 million, $3.7 million and $3.6 million of expense relating to these plans for the years ended December 31, 2009, 2008 and 2007, respectively.

(10)	Major Customers

During 2009, approximately 76% of total revenues were from two customers, the largest of which represented 39% of revenues. During 2008, approximately 48% of total revenues were from two customers, the largest of which represented 36% of revenues. During 2007, approximately 47% of total revenues were from two customers, the largest of which represented 28% of revenues. The revenues from these customers for 2009, 2008 and 2007 are included in the CAPP segment in Note 15.

F-23

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(11)

Leases

The Company leases equipment and various other properties under non-cancelable long-term leases, expiring at various dates. Certain leases contain options that would allow the Company to extend the lease or purchase the leased asset at the end of the base lease term. Future minimum lease payments under noncancelable operating leases (with initial or remaining lease terms in excess of one year) as of December 31, 2009 were as follows (in thousands):

	Operating
	leases
Year ended December 31:
2010	$	6,817
2011		2,603
2012		842
2013		239
2014		163
Thereafter		-
	$	10,664

The Company incurred rent expense on equipment and offices space of approximately $10.8 million, $10.7 million and $7.3 million for the years ended December 31, 2009, 2008 and 2007, respectively.

(12)	Commitments and Contingencies

Future minimum royalty commitments under coal lease agreements at December 31, 2009 were as follows (in thousands):

	Royalty
	commitments
Year ended December 31:
2010	$	24,957
2011		21,966
2012		21,401
2013		21,379
2014		19,745
2015 and thereafter		93,908
	$	203,356

(a)	Certain coal leases do not have set expiration dates but extend until completion of mining of all merchantable and mineable coal reserves. For purposes of this table, we have generally assumed that minimum royalties on such leases will be paid for a period of ten years.

(b)	Certain coal leases require payment based on minimum tonnage, for these contracts an average sales price of $80.00 per ton was used to project the future commitment.

The Company has established irrevocable letters of credit totaling $59.1 million as of December 31, 2009 to guarantee performance under certain contractual arrangements. The letters of credit are secured by $62.0 million of cash that is included in restricted cash on the accompanying consolidated balance sheets.

The Company is involved in various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity.

F-24

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(13)	Earnings (Loss) Per Share

Basic earnings (loss) per share is computed by dividing net income (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is calculated based on the weighted average number of common shares outstanding during the period and, when dilutive, potential common shares from the exercise of stock options and restricted common stock subject to continuing vesting requirements, pursuant to the treasury stock method.

The following table provides a reconciliation of the number of shares used to calculate basic and diluted earnings (loss) per share (in thousands):

	2009			2008			2007
Basic earnings per common share:
Net income (loss)	$	50,954			(95,993	)		(54,015	)
Income allocated to participating securities		(1,395	)		-			-
Net income (loss) available to common shareholders	$	49,559			(95,993	)		(54,015	)

Weighted average number of common and
common equivalent shares outstanding:
Basic number of common shares outstanding		26,765			24,520			16,412
Dilutive effect of unvested restricted stock
(participating securities)		754			-			-
Dilutive effect of stock options		49			-			-
Diluted number of common shares and
common equivalent shares outstanding		27,568			24,520			16,412

Basic earnings (loss) per common share	$	1.85			(3.91	)		(3.29	)


Diluted net income per common share:
Net income (loss)	$	50,954			(95,993	)		(54,015	)
Income allocated to participating securities		-			-			-
Net income (loss) available to potential common
shareholders	$	50,954			(95,993	)		(54,015	)

Diluted net earnings (loss) per share	$	1.85			(3.91	)		(3.29	)

For periods in which there was a loss, the Company has excluded from its diluted loss per share calculation options to purchase shares and the unvested portion of time vested restricted shares, as inclusion of these securities would have reduced the net loss per share. The excluded instruments would have increased the diluted weighted average number of common and common equivalent shares outstanding by approximately 0.8 million and 0.7 million for the years ended December 31, 2008 and 2007, respectively. In addition, in periods of net losses, the Company has not allocated any portion of such losses to participating securities holders for its basic loss per share calculation as such participating securities holders are not contractually obligated to fund such losses.

F-25

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(14)	Fair Value of Financial Instruments

The estimated fair value of financial instruments has been determined by the Company using available market information. As of December 31, 2009 and 2008, except for long-term debt obligations, the carrying amounts of all financial instruments approximate their fair values due to their short maturities.

The carrying value and fair value of our Senior Notes and Convertible Notes are as follows (in thousands)

	2009		2008
	Carrying Value	Fair Value	Carrying Value	Fair Value
Senior Notes and Convertible Senior Notes	$322,500	$325,400	$150,000	$112,100

The carrying amounts and fair values of our Senior Notes and Convertible Senior Notes are based on available market data at the date presented. The carrying value of the Convertible Senior Notes reflected in long-term debt in the table above reflects the full face amount of $172.5 million, which has been adjusted in the Consolidated Balance Sheets for a discount related to its convertible feature (Note 4).

The Company believes that the carrying amount of the Revolver approximated the fair value at December 31, 2008, due to the variable interest rate and a recent amendment to that facility.

(15)	Segment Information

The Company has two segments based on the coal basins in which the Company operates. These basins are located in Central Appalachia (CAPP) and in the Midwest (Midwest). The Company’s CAPP operations are located in eastern Kentucky and the Company’s Midwest operations are located in southern Indiana. Coal quality, coal seam height, transportation methods and regulatory issues are generally consistent within a basin. Accordingly, market and contract pricing have been developed by coal basin. The Company manages its coal sales by coal basin, not by individual mine complex. Mine operations are evaluated based on their per-ton operating costs. Operating segment results are shown below (in thousands).

F-26

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

	Years Ended
	December 31,
	2009			2008			2007
Revenues
CAPP	$	579,108			467,609			429,283
Midwest		102,450			100,898			91,277
Corporate		-			-			-
Total	$	681,558			568,507			520,560

Depreciation, depletion and amortization
CAPP	$	49,380			55,979			56,506
Midwest		12,646			14,218			15,199
Corporate		52			80			151
Total	$	62,078			70,277			71,856

Total operating income (loss)
CAPP	$	98,485			(35,861	)		(30,841	)
Midwest		(4,909	)		(10,296	)		(3,276	)
Corporate (2)		(22,704	)		(18,493	)		(16,626	)
Total	$	70,872			(64,650	)		(50,743	)

Interest Income (1)
Corporate	$	(60	)		(469	)		(471	)
Total	$	(60	)		(469	)		(471	)

Interest Expense (1)
Corporate	$	17,057			17,746			19,764
Total	$	17,057			17,746			19,764

Income tax expense (benefit) (1)
Corporate	$	1,559			(273	)		(17,844	)
Total	$	1,559			(273	)		(17,844	)

Net earnings (loss) (1)
CAPP	$	98,485			(35,861	)		(30,841	)
Midwest		(4,909	)		(10,296	)		(3,276	)
Corporate (2)		(42,622	)		(49,836	)		(19,898	)
Total	$	50,954			(95,993	)		(54,015	)

(1)

The Company does not allocate interest income, interest expense or income taxes to its segments.

(2)

Corporate includes a $6.1 million gain on curtailment of the pension plan (note 9) in the yearended December 31, 2007.

F-27

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

	December 31,
	2009		2008
Total Assets
CAPP	$	421,825	$	336,631
Midwest		88,815		89,792
Corporate		158,672		37,123
Total	$	669,312	$	463,546

Goodwill
CAPP	$	-	$	-
Midwest		26,492		26,492
Corporate		-		-
Total	$	26,492	$	26,492


	Years Ended
	December 31,
Capital Expenditures		2009		2008		2007
CAPP	$	58,147	$	66,467	$	42,379
Midwest		13,840		8,167		6,564
Corporate		172		63		400
Total	$	72,159	$	74,697	$	49,343

F-28

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(16) Quarterly Information (Unaudited)

Set forth below is the Company’s quarterly financial information for the previous two fiscal years (in thousands):

	Three Months Ended
	March 31,		June 30,		September 30,		December 31,
	2009		2009		2009		2009

Total revenue	$	192,121		171,649		168,320		149,468
Gross profit		44,941		28,006		24,387		13,258
Income from operations		35,654		17,447		14,121		3,650
Income (loss) before taxes		31,680		13,748		10,246		(3,161	)
Net income (loss)		28,171		16,178		9,808		(3,203	)
Earning (loss) per share (Basic and Diluted):	$	1.03		0.59		0.36		(0.12	)

	Three Months Ended
	March 31,			June 30,			September 30,			December 31,
	2008			2008			2008			2008

Total revenue	$	138,188			137,703			151,842			140,774
Gross profit (loss)		(4,832	)		(8,716	)		(4,189	)		(11,921	)
Loss from operations		(12,166	)		(17,448	)		(13,246	)		(21,790	)
Loss before taxes		(16,688	)		(24,006	)		(21,712	)		(33,860	)
Net loss		(16,688	)		(24,006	)		(21,712	)		(33,587	)
Loss per share (Basic and Diluted):	$	(0.78	)		(0.97	)		(0.86	)		(1.26	)

F-29

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 26th day of February, 2010.

	JAMES RIVER COAL COMPANY

	By: /s/ Peter T. Socha
	Peter T. Socha
	Chairman of the Board,
	President and Chief Executive Officer
	(principal executive officer)

Know all men by these presents, that each person whose signature appears below constitutes and appoints Peter T. Socha and Samuel M. Hopkins, II, or either of them, as attorneys-in-fact, with power of substitution, for him in any and all capacities, to sign any amendments to this annual report on Form 10-K, and to file the same, with exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that said attorneys-in-fact may do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant in the capacities indicated on the 26th day of February, 2010.

Signature	Title
/s/ Peter T. Socha Peter T. Socha	Chairman of the Board, President and Chief Executive Officer (principal executive officer)
/s/ Samuel M. Hopkins, II Samuel M. Hopkins, II	Vice President and Chief Accounting Officer (principal financial officer and principal accounting officer)
/s/ Alan F. Crown Alan F. Crown	Director
/s/ Ronald J. FlorJancic Ronald J. FlorJancic	Director
/s/ Leonard J. Kujawa Leonard J. Kujawa	Director
/s/ Joseph H. Vipperman Joseph H. Vipperman	Director

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