James River Coal CO - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934.

For the fiscal year ended December 31, 2004

Commission File No.: 000-51129

JAMES RIVER COAL COMPANY

(Exact name of Registrant as specified in its charter)

Virginia

(State or other jurisdiction of incorporation or organization)

54-1602012

(I.R.S. Employer 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: None.

Name of each exchange on which registered: The Nasdaq National Market.


Securities registered pursuant to Section 12(g) of the Act:	Common Stock, Par Value $0.01 per share
	Series A Participating Cumulative Preferred Stock Purchase Rights

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 x 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 10K. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). YES o NO x.

The aggregate market value of the voting stock for non-affiliates (which for purposes hereof are all holders other than executive officers, directors and 10% shareholders) of the Registrant as of August 12, 2004, the first day the Registrant’s common stock was quoted on the Pink Sheets Electronic Quotation Service, is $382,852,852 (based on 12,350,092 shares held by non-affiliates at $31.00 per share, the last price quoted on the Pink Sheets Electronic Quotation Service on August 12, 2004). The Registrant’s common stock began trading on the Nasdaq National Market on January 25, 2005. See Item 5 and Item 12.

At February 24, 2005 there were 14,740,694 shares of Common Stock, par value $0.01 per share, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Proxy Statement for the 2005 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 for the year ended December 31, 2004.

JAMES RIVER COAL COMPANY

TABLE OF CONTENTS
FORM 10-K ANNUAL REPORT


	PART I
ITEM 1.	BUSINESS	2
ITEM 2.	PROPERTIES	35
ITEM 3.	LEGAL PROCEEDINGS	36
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	36
	PART II
ITEM 5.	MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	37
ITEM 6.	SELECTED FINANCIAL DATA	38
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	43
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	59
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	60
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	100
ITEM 9A.	CONTROLS AND PROCEDURES	100
ITEM 9B.	OTHER INFORMATION	101
	PART III
ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	102
ITEM 11.	EXECUTIVE COMPENSATION	102
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	102
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	102
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	102
	PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	103

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 450 Fifth Street, N.W., 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

We mine, process and sell bituminous, low sulfur, steam- and industrial-grade coal through five operating subsidiaries (“mining complexes”) located throughout Eastern Kentucky. Our five mining complexes include 17 mines and seven preparation plants, five of which have integrated rail loadout facilities and two of which use a common loadout facility at a separate location. In 2004, our mines produced 8.5 million tons of coal, and we purchased another 330,000 tons for resale. Of the 8.5 million tons produced, approximately 96.5% came from underground mines, while the remaining 3.5% came from surface mines. Approximately 83.4% of our revenues were generated from coal sales to electric utility companies and 16.6% came from coal sales to industrial and other companies or from synfuel handling fees. In 2004 we generated revenues of $345.6 million and income before reorganization items and income taxes of $9.8 million.

The majority of our coal is sold to customers in the Southeast region of the United States. According to the U.S. Energy Information Administration, or EIA, the Southeast region accounts for 33% of coal-generated electricity production in the United States, more than any other U.S. region. The long term outlook for coal demand in the Southeast is favorable, as coal-generated electricity production in that region is expected to grow at a rate of 1.8% per year. In addition, the Southeast region is projected by the EIA to account for 36% of the expansion of coal-generated electricity production in the United States between 2003 and 2025. We have been providing coal to coal-generated electricity producers in the Southeast since our formation in 1988. In 2004, Georgia Power and South Carolina Public Service Authority were our largest customers, representing approximately 30% and 20% of our revenues, respectively. No other customer accounted for more than 10% of our revenues.

We believe that coal-fired electric utilities value the high energy, low sulfur coal that comprises the majority of our reserves. As of March 31, 2004, based upon our most recent independent reserve report, we estimate that we controlled approximately 207 million tons of proven and probable coal reserves. As of December 31, 2004, we believe that we controlled approximately 207 million tons of proven and probable coal reserves. We believe 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 24 years of production.

In March 2005, we signed a definitive agreement to acquire Triad Mining Inc. (“Triad”), for $75.0 million, consisting of $64.0 million in cash and $11.0 million of our common stock. Triad operates six surface mines and one underground mine in Southern Indiana, and in 2004 produced approximately 3.4 million tons of coal. Based on unaudited 2004 results, Triad generated revenues of approximately $81.6 million and operating income of approximately $13.0 million. Depreciation, depletion, and amortization during 2004 were approximately $5.6 million. As of December 31, 2004, we believe that Triad controlled approximately 17.4 million tons of proven and probable coal reserves. See “The Triad Acquisition.”

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 2004:


	Tons (000)		Percentage of total coal obtained by the Company
Coal produced from Company-operated mines		7,987		90	%
Coal obtained from mines operated by independent contractors		534		6	%
Coal purchased from other third parties		330		4	%

		8,851		100	%

We also supply coal to a third party synfuel plant and receive fees for the handling, shipping and marketing of the synfuel product. Synfuel is a synthetic fuel product that is produced by chemically altering coal. In 2004, 2% of our total operating revenues came from synfuel handling, shipping and marketing.

Mining Operations

All of our coal production is conducted through our operation of five mining complexes:


	•		Bell County Coal Corporation;

	•		Bledsoe Coal Corporation;

	•		Blue Diamond Coal Corporation;

	•		Leeco, Inc.; and

	•		McCoy Elkhorn Coal Corporation.

We obtained rights to these mining complexes as follows: McCoy Elkhorn and Bell County were the original operating companies that made up James River Coal Company when we were formed in 1988 through the purchase of General Energy Corp. In 1992, we acquired the operations of Johns Creek Coal Company and the Bevins Branch Preparation Plant, both of which operations are now included within the McCoy Elkhorn complex. The Leeco and Bledsoe operating companies were both acquired in our acquisition of Transco Coal Company in 1995. The Blue Diamond operating company was purchased in 1998. In 1999, we acquired Shamrock Coal Company, which added mines, reserves, a preparation plant and the Clover loadout facility to the Bledsoe complex.

We generally do not own the land on which we conduct our mining operations; instead, approximately 97% of our coal reserves 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 or a percentage of gross sales price royalty payment to the lessor. The average royalties for coal reserves from our producing properties was approximately 7.9% of produced coal revenue for the year ended December 31, 2004.

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 summarizes information concerning each of our five mining complexes:

Bell County. The Bell County complex is located in Bell County in eastern Kentucky, and consists of two Company-operated underground mines and one contract surface mine. We use room and pillar mining to mine the Buckeye Springs seam of coal, and our contract mine operator uses the contour and auger method to mine multiple seams, including the Red Springs, the Hignite and the Stray seams. 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. Shipments from this complex totaled approximately 0.8 million tons in 2004 and approximately 1.3 million tons in 2003. Coal shipped from this complex in 2004 had average sulfur content of 1.37%, an average ash content of 8.82% and an average Btu content of 12,750, all on an as- received basis. As of December 31, 2004, we employed 81 mining and support personnel at this complex. As of December 31, 2004, based on the report prepared by MM&A and adjustments for subsequent production, acquisitions, divestures, and exploration activities, we estimate this complex contains approximately 13.3 million tons of proven and probable reserves, which we believe will support approximately 16 years of operations at current levels of production.

Bledsoe. The Bledsoe complex is located in Leslie, Harlan and Letcher counties in eastern Kentucky, and consists of three Company-operated underground mines. We use room and pillar mining to mine the Hazard #4 seam of coal at this complex. Coal is processed at one of two preparation plants and loaded into railcars at a separate location via a four-hour unit train loadout on the CSX railroad. Shipments from this

complex totaled approximately 2.4 million tons in 2004 and approximately 2.9 million tons in 2003. Coal shipped from this complex in 2004 had average sulfur content of 1.20%, an average ash content of 8.73% and an average Btu content of 12,704, all on an as-received basis. As of December 31, 2004, we employed 316 mining and support personnel at this complex. As of December 31, 2004, based on the report prepared by MM&A and adjustments for subsequent production, acquisitions, divestures, and exploration activities, we estimate this complex contains approximately 57.6 million tons of proven and probable reserves, which we believe will support approximately 24 years of operations at current levels of production.

Blue Diamond. The Blue Diamond complex is located in Leslie, Perry, Letcher and Harlan counties in eastern Kentucky, and consists of four Company-operated mines and one contract mine, all of which are underground mines. We use room and pillar mining to mine the Hazard #4 and Alma seams of coal and our contract mine operators uses the same method to mine the Leatherwood seam. Coal is processed at our preparation plant, and loaded into railcars via an integrated four-hour unit train loadout on the CSX railroad. Shipments from this complex totaled approximately 1.8 million tons in 2004 and approximately 1.4 million tons in 2003. Coal shipped from this complex in 2004 had average sulfur content of 0.84%, an average ash content of 9.28% and an average Btu content of 12,652, all on an as-received basis. As of December 31, 2004, we employed 211 mining and support personnel at this complex. As of December 31, 2004, based on the report prepared by MM&A and adjustments for subsequent production, acquisitions, divestures, and exploration activities, we estimate this complex contains approximately 65.3 million tons of proven and probable reserves, which we believe will support in excess of 25 years of operations at current levels of production.

Leeco. The Leeco complex is located in Knott and Perry counties in eastern Kentucky, and consists of one Company-operated underground mine and one contract surface mine. Our Company mine uses room and pillar mining to mine the Amburgy seam of coal and the contract mine operator uses the contour and auger method to mine the Hazard #8 seam. Coal is processed at our preparation plant and loaded into railcars via an integrated four-hour unit train loadout on the CSX railroad. Shipments from this complex totaled approximately 1.3 million tons in 2004 and approximately 1.4 million tons in 2003. Coal shipped from this complex in 2004 had average sulfur content of 0.79%, an average ash content of 8.66% and an average Btu content of 12,883, all on an as-received basis. As of December 31, 2004, we employed 142 mining and support personnel at this complex. As of December 31, 2004, based on the report prepared by MM&A and adjustments for subsequent production, acquisitions, divestures, and exploration activities, we estimate this complex contains approximately 35.0 million tons of proven and probable reserves, which we believe will support in excess of 25 years of operations at current levels of production.

McCoy Elkhorn. The McCoy Elkhorn complex is located in Pike and Floyd counties in eastern Kentucky, and consists of five Company-operated mines. All of the mines at this complex are underground mines. We use room and pillar mining to mine the Williamson, Elkhorn #2, Elkhorn #3, and Pond Creek seams of coal. Coal is processed at one of two preparation plants and loaded into railcars via integrated four-hour unit train loadouts on the CSX railroad. Shipments from this complex totaled approximately 2.6 million tons in 2004 and approximately 3.2 million tons in 2003. Coal shipped from this complex in 2004 had average sulfur content of 1.48%, an average ash content of 8.49% and an average Btu content of 12,756, all on an as-received basis. As of December 31, 2004, we employed 280 mining and support personnel at this complex. As of December 31, 2004, based on the report prepared by MM&A and adjustments for subsequent production, acquisitions, divestures, and exploration activities, we estimate this complex contains approximately 36.1 million tons of proven and probable reserves, which we believe will support approximately 14 years of operations at current levels of production.

Contract mining represented approximately 6% of our coal production in the year ended December 31, 2004. 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. They are generally responsible for all needed supplies, equipment repairs and maintenance. We generally own the infrastructure associated with the mine, including beltlines, ventilation systems and electrical systems. If the contract mine operator provides this infrastructure, the contract governing the relationship typically mandates a process for our valuation and purchase of those items if the contractor terminates the contract. 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. To enforce our contractual rights, we typically withhold a portion of the per ton amount otherwise due to the surface mine contractor until certain thresholds in the reclamation process, typically based on thresholds set by regulatory authorities, are met by the contractor. Contractors that operate underground mines typically have no obligation to perform reclamation activities on 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

Beginning in late 2003 and continuing into 2004, we increased our 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 engaged Marshall Miller & Associates, Inc. (“MM&A”) to prepare a detailed study of our reserves as of March 31, 2004 based on all of our geologic information, including our updated drilling and mining data. The coal reserve study conducted by MM&A was planned and performed to obtain reasonable assurance of our subject demonstrated (proven plus probable) reserves. In connection with the study, 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. MM&A completed their report in June 2004.

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.

As a result of this study, we reduced our reserve estimate from 285 million tons to 207 million tons as of March 31, 2004. MMA has not conducted a coal reserve study on our December 31, 2004 reserve estimate. We expect to continue with our drilling program and to update our 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, 2004, we estimated that we controlled approximately 207 million tons of proven and probable coal reserves, with an estimated weighted average quality of approximately 6.3% ash, 1.3% sulfur and 13,300 British thermal units per pound (“Btu/lb.”), all on an as-received basis at 5.5% moisture. Reserves 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 vast majority of our coal reserves are concentrated in eastern Kentucky, with the remaining amount located in north central Tennessee.

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 MM&A has reviewed our reserves at March 31, 2004 and found them to be reasonable (not withstanding unforeseen geological, market, labor or regulatory issues that may affect the operations), by assignment, MM&A has not performed an economic feasibility study for our reserves. In accordance with standard industry practice, we have performed our own economic feasibility analysis for our assigned 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.

The following table sets forth reserve information, as of March 31, 2004, at each of our mining complexes, based on the independent reserve study conducted by MM&A:


			Approximate Overall Reserve Quality (2)
Mining Complex	Proven & Probable Reserves (1) (millions of tons)		Ash Content (%)		Sulfur Content (%)		Heat Value (Btu/lb.)
Bell County		12.5		5.1		1.0		13,500
Bledsoe		59.1		7.8		1.2		13,000
Blue Diamond		66.2		4.7		1.1		13,700
Leeco		35.7		7.0		1.2		13,200
McCoy Elkhorn		33.8		5.7		1.6		13,300

Total/Average		207.3		6.3		1.3		13,300


(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.

Mining Methods

In our 14 Company-operated mines and the three mines operated by independent contractors, three different mining methods are used. These methods are:


	•		Room and pillar underground mining;


	•		Contour and auger surface mining; and


	•		Area mining (also known as mountaintop removal).

These three methods are described in more detail below.

Room and Pillar. We use the room and pillar mining method at all of our Company-operated mines. The four underground mines operated by contractors also use this method. In the underground room and pillar method of mining, continuous mining machines cut three 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. When retreat mining is completed to the mouth of the panel, the mined panel is abandoned.

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 or shuttle 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 ranges from less than 50% to more than 70%, depending on the shape of the reserve, the amount of low-cover areas, and the geological characteristics of the reserve body.

Contour and Auger. Our contract surface mine operators use the contour and auger method as well as area mining or mountaintop removal where appropriate. Contour 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. Augering can then take place where the seam is exposed in the highwall. An auger machine, which resembles a large, horizontal drill, drills into the seam with an auger of from less than 20” in diameter to more than 40” in diameter, depending on seam thickness and other conditions. The auger is drilled into the seam to an average depth of 150 feet. The coal is transported to the surface through the auger 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 35%.

Area. The area mining, or mountaintop removal, method is used where the seam is sufficiently close to the surface to allow removal of the overburden above an area of the coal seam. The overburden is removed and either placed in a valley fill or returned to the top of the mountain after the coal is extracted. With both area mining and mountaintop removal, coal can be removed across the entire breadth of the mountain. Reserve recovery is typically approximately 80%.

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.

All of our Company-operated mines are underground mines. Of these 14 Company-operated mines currently in operation, 12 are drift mines, and the remaining two are below drainage mines.

Processing and Transportation

Coal from each of our mine complexes is transported by conveyor belt or by truck to one of our seven preparation plants, 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.

Substantially all of our coal is 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.

Our mining complexes are supported by James River Coal Service Company, located in London, Kentucky, which provides 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 more than one year) 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 2004, we generated approximately 71% of our total revenues from seven long-term contracts to sell coal to electric utilities.

For the year ended December 31, 2004, Georgia Power (30%) and South Carolina Public Service Authority (20%) were our largest customers by revenues. No other customer accounted for more than 10% of revenues. Our Senior Secured Credit Facility contains a covenant that no single customer may represent more than 35% of our annual revenues.

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 market price at the time the re-opener provision is triggered. Re-opener provisions could result in early termination of a contract or in 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 14.6% (based on tonnage produced) of the total United States production in 2003, the latest year for which government statistics are available. The U.S. Department of Energy also reported 1,316 active coal mines in the United States in 2003. 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, 2004, we had 1,070 employees. None of our employees are currently represented by collective bargaining agreements. Relations with our employees are generally good.

The Triad Acquisition

General

On March 30, 2005, we entered into an agreement to acquire all of the outstanding capital stock of Triad Mining, Inc. (“Triad”).

Triad, with its wholly-owned subsidiary, Triad Underground Mining, LLC, owns and operates six surface mines and one underground mine in Southern Indiana. In 2004, Triad produced approximately 3.4 million tons of coal. Based on unaudited 2004 results, Triad generated revenues of approximately $81.6 million and operating income of approximately $13.0 million. Depreciation, depletion and amortization during 2004 were approximately $5.6 million. As of December 31, 2004, we believe that Triad controlled approximately 17.4 million tons of proven and probable coal reserves.

The Triad acquisition would allow us to diversify our operations into the Illinois coal basin, a region that we believe has favorable supply and demand dynamics. It also would allow us to expand our surface mining operations, and to diversify our customer base and sources of transportation.

Purchase Price

The consideration to be paid by us for the Triad stock consists of a combination of cash and shares of our common stock, as follows:


	•		$64.0 million in cash will be paid to Triad’s shareholders as of the closing date; and


	•		the remainder of the purchase price will be paid by issuing to Triad’s shareholders shares of our common stock having a market value equal to $11.0 million, based on the average closing price of our common stock on The Nasdaq Stock Market for the 15 consecutive trading days ending two trading days prior to the closing date.

The cash portion of the purchase price will be increased or decreased based on changes in Triad’s net working capital, less agreed upon distributions, between December 31, 2004 and the closing date.

Conditions and Termination

The Triad acquisition is subject to various conditions, including, but not limited to, the following:


	•		the Company having obtained financing for the acquisition on terms and conditions approved by our Board of Directors;


	•		the material accuracy of the representations and warranties of each party to the purchase agreement as of the closing date;


	•		receipt of all consents and regulatory approvals required to consummate the acquisition; and


	•		receipt by each party of certain legal opinions and other documents.

The Triad acquisition will not close unless we and the sellers satisfy or waive all of the conditions. We cannot assure you that we or the sellers will be able to satisfy the conditions required to close the acquisition. See “Risk Factors” for a discussion of certain risks related to our potential acquisition of Triad.

The stock purchase agreement may be terminated by us or by Triad if the transaction does not close on or before June 30, 2005 (which date may be extended in certain limited circumstances).

We anticipate that we will finance the cash portion of the consideration for the Triad acquistion with proceeds from underwritten offerings of debt and equity securities registered with the SEC. Any such offering will be made only by the prospectus filed with the SEC as part of the applicable registration statement.

Consulting Agreements

In connection with the Triad acquisition, we will also enter into consulting agreements with two of Triad’s principals. Under those agreements, we would pay those individuals an aggregate performance bonus of up to $5.0 million, payable in shares of our common stock if, prior to the second anniversary of the closing date, we obtain the right to own, lease, or mine certain proven and probable reserves. The bonus would be payable in increments of $100,000 for every 1.0 million tons of such reserves, up to the $5.0 million maximum amount. Any such bonus would be payable in shares of our common stock, based on the average closing price of our common stock on The Nasdaq Stock Market for the 15 consecutive trading days ending two trading days prior to established payment dates.

Registration Rights

In connection with the Triad acquisition, we will also enter into a registration rights agreement with the holders of Triad stock giving those holders the right to require us to register the shares of our common stock received by them in the acquisition (and pursuant to the consulting agreements). The holders will generally have the right to make one demand, but to the extent that the two Triad principals receive additional shares pursuant to their consulting agreements (as summarized above), those two individuals will have the right to make one additional demand. In addition, if we conduct a public offering (with certain limited exceptions), the Triad holders will have the right to register their shares in the same offering, subject to certain cutback rights.

Pursuant to the registration rights agreement, the Triad holders collectively will be prohibited from selling more than 33.3% of the total number of shares issued to them within any 90-day period. To the extent that the holders sell less than 33.3% in a given 90-day period, they would have the right to carry over and sell such additional amount in a subsequent period.

Recent Reorganization

On May 6, 2004, we emerged from Chapter 11 bankruptcy proceedings under our Joint Plan of Reorganization confirmed by the U.S. Bankruptcy Court presiding over our Chapter 11 case (the “Plan of Reorganization”). On that date, we:


	•		exchanged approximately $266 million in debt under various existing credit facilities for (1) restructured term debt of approximately $75 million, which is secured by a second lien on substantially all of our assets, and (2) a total of 13,799,994 shares of our new common stock, par value $0.01 per share, issued on a pro rata basis to the holders of the existing debt;


	•		distributed interests in an unsecured creditor liquidating trust (which trust initially held life insurance policies with cash surrender values of approximately $3.1 million, the right to receive certain refunds and the right to pursue certain derivative claims) to our general unsecured creditors in exchange for their claims, which were estimated to be valued at approximately $44.9 million;


	•		entered into a new senior secured credit facility providing borrowings of up to $50 million, which is secured by a first lien on substantially all of our assets;


	•		satisfied and discharged all of our obligations under our $20 million debtor-in-possession credit facility;


	•		rejected (i.e., terminated) certain agreements that we had entered into before the bankruptcy that were found to be unduly burdensome to us, and discharged the claims of creditors related to those agreements;


	•		canceled our existing equity securities;


	•		acknowledged that all intercompany debt was deemed to be extinguished;


	•		acknowledged that pre- and post-petition (i) environmental and regulatory obligations; (ii) obligations with respect to workers’ compensation and black lung programs; and (iii) regulatory obligations related to our employees would be unaffected by the Plan of Reorganization and would survive effectuation of the Plan of Reorganization; and


	•		elected and installed a new Board of Directors for the Company.

Fresh Start Accounting

Upon emergence from bankruptcy, we adopted “fresh start” accounting as described in the American Institute of Certified Public Accountant’s Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code (“SOP 90-7”). Entities that adopt fresh start accounting apply the following principles:


	•		The reorganization value of the entity should be allocated to the entity’s assets in conformity with SFAS No. 141 Business Combinations.


	•		Each liability existing at the plan confirmation date, other than deferred taxes, should be stated at present values of amounts to be paid as determined at appropriate current interest rates.


	•		Deferred taxes should be reported in conformity with generally accepted accounting principles. Benefits realized from pre-reorganization net operating loss carryforwards should first reduce reorganization value in excess of amounts allocable to identifiable assets and other intangibles until exhausted and thereafter be reported as a direct addition to paid-in capital.

Fresh start accounting principles require that we determine the reorganization value of the reorganized Company. We developed an enterprise value of the reorganized Company with our financial advisor during the bankruptcy case. Together, we worked closely with our pre-petition secured lenders, the Official Committee of Unsecured Creditors and their respective financial advisors. This enterprise value was based on a calculation of the present value of the free cash flows under our financial projections. The valuation and the projections underlying the valuation were submitted to the bankruptcy court and to our secured and unsecured creditors for review and objection as part of our disclosure statement accompanying the Plan of Reorganization. The enterprise value of the reorganized Company as contained in our disclosure statement accompanying the Plan of Reorganization was determined to be between $145 million and $165 million. For purposes of applying fresh start accounting, we have used an enterprise value for the reorganized Company of $155 million.

The reorganization value was derived from the enterprise value for the reorganized Company as follows (amounts in thousands):


Estimated enterprise value of the reorganized company	$	155,000
Borrowings under credit agreement		(6,400	)
Capital leases assumed		(1,396	)
Cash balance excluded from enterprise value		1,301
Administrative claims payable excluded from enterprise value		(10,214	)

		138,291
Less: new secured debt issued to extinguish prepetition debt		75,000

Fair value of common shares issued to extinguish prepetition debt	$	63,291

In connection with the implementation of fresh start accounting, we recorded a gain of approximately $178 million from the extinguishment of our debt. Other adjustments were made to reflect the provisions of the Plan of Reorganization and to adjust the assets of the reorganized Company to their estimated fair value and liabilities to their estimated present value. The estimated fair value of our fixed assets was based on an appraisal performed for one of our lenders in connection with our reorganization. For financial reporting purposes, these transactions were reflected in our operating results before emergence.

The consummation of the Plan of Reorganization has been reflected as of April 30, 2004, which was the end of our most recent month preceding the effective date of the Plan of Reorganization of May 6, 2004. The results of operations for the period from April 30, 2004 through May 5, 2004 were not material.

Our consolidated financial statements after emergence are those of a new reporting entity (the “Successor Company”) and are not comparable to the financial statements of the pre-emergence company (the “Predecessor Company”). See note 3 to our December 31, 2004 consolidated financial statements for our unaudited condensed balance sheets presenting our historical consolidated balance sheet as of April 30, 2004 before the application of fresh start accounting (Predecessor Company) and after the application of fresh start accounting and other adjustments to reflect the provisions of the Plan of Reorganization (Successor Company). The unaudited condensed balance sheets of the Predecessor Company and the Successor Company as of April 30, 2004 should be read in conjunction with our consolidated financial statements and related notes.

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 and wildlife and wetland protection;


	•		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 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 capital expenditures of approximately $150,000 per year for environmental control facilities in 2005 and 2006. 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 penalties ranging from $60 to $60,000 per violation, as well as closure of the mine. In addition, as part 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, requires 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.

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 $25.9 million at December 31, 2004. These obligations were unfunded at December 31, 2004.

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.

The Kentucky Supreme Court has taken discretionary review of a Kentucky Court of Appeals decision, Bartrum v. Hunter Excavating, which rendered unconstitutional a 2002 statute governing black lung claims. The Court of Appeals held that to the extent the statute limited evidence, it violated due process rights. The effect upon future black lung claims, if any, is dependent upon the Kentucky Supreme Court’s review.

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 is 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 workers’ compensation liabilities, including the current portion, were $50.3 million at December 31, 2004. These obligations are unfunded. The amount we expensed in the year ended December 31, 2004, was $9.3 million, while the related cash payment for this liability was $9.7 million. 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, 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; 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

The SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep 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. Kentucky has achieved primary jurisdiction for enforcement of the Act through approved state programs.

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 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 $0.35 per ton on surface-mined coal and $0.15 per ton on underground-mined coal.

Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143 (“Statement No. 143”) to account for the costs related to the closure of mines and the reclamation of the land upon exhaustion of coal reserves. This statement requires the fair value of an asset retirement obligation be 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. Asset retirement obligations primarily relate to the closure of mines and the reclamation of the land upon exhaustion of coal reserves. At December 31, 2004 and December 31, 2003, we had accrued $16.0 million and $14.7 million, respectively, 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 risk-free interest rate.

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, 2004 was $1.2 million, while the related cash payment for such liability during the same period was $585,000.

We also lease some of our coal reserves to third-party operators. Under the SMCRA, responsibility for 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 and revocation 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. In July 1997, the EPA adopted new, more 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.

On March 15, 2005, the U.S. Environmental Protection Agency adopted a new federal rule to cap and reduce mercury emissions from both new and existing coal-fired power plants. The reductions will be implemented in stages, primarily through a market-based cap-and-trade program. Nevertheless, the new regulations will likely require some power plants to install new equipment, at substantial cost, or discourage the use of certain coals containing higher levels of mercury.

Other new and proposed reductions in emissions of sulfur dioxides, nitrogen oxides, particulate matter or various 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. For example, the EPA recently proposed separate regulations to reduce the interstate transport of fine particulate matter and ozone through reductions in sulfur dioxides and nitrogen oxides throughout the eastern United States. The EPA continues to require reduction of nitrogen oxide emissions in 22 eastern states and the District of Columbia and will require reduction of particulate matter emissions over the next several years for areas that do not meet air quality standards for fine particulates and for certain major sources contributing to those exceedances. In addition, the EPA has issued draft regulations, and 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 may restrict 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 United States 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. Some of these lawsuits have settled, requiring the utilities to pay penalties, install pollution control equipment and/or undertake other emission reduction measures, and the remaining lawsuits or future lawsuits could require the utilities involved to take similar steps, which could adversely impact their demand for 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 $25,000 per year.

Framework Convention On Global Climate Change

The United States and more than 160 other nations are signatories to the 1992 United Nations Framework Convention on Climate Change, commonly known as the Kyoto Protocol, which is intended to reduce or offset emissions of greenhouse gases such as carbon dioxide. In December 1997, the signatories to the convention established a 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 94% of 1990 levels over a five-year budget period from 2008 through 2012. The U.S. Senate has not ratified the treaty commitments, and the Bush administration has officially opposed the Kyoto Protocol and has proposed an alternative to reduce the intensity of United States emissions of greenhouse gases. With Russia’s ratification of the Kyoto Protocol in 2004, it became binding on all ratifying countries. The implementation of the Kyoto Protocol in a number of 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 regulations focusing on greenhouse gas emissions are implemented 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 coal bed methane 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 effluent 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 all permits required under the Clean Water Act and corresponding state laws and are in substantial compliance with such permits. However, new requirements under the Clean Water Act and corresponding state laws may cause us to incur significant additional costs that could adversely affect our operating results.

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 cannot be predicted with certainty due to the lack of specific information available, the potential for new or changed laws and regulations and for the development of new remediation technologies and the uncertainty regarding the timing of work with respect to particular sites. 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 RCRA 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 and 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. Examples include statements related to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding. These forward-looking statements could also involve, among other things, statements regarding our intent, belief or expectation with respect to:


	•		our cash flows, results of operation or financial condition;


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


	•		governmental policies and regulatory actions;


	•		legal and administrative proceedings, settlements, investigations and claims;


	•		weather conditions or catastrophic weather-related damage;


	•		our production capabilities;


	•		availability of transportation;


	•		market demand for coal, electricity and steel;


	•		competition;


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


	•		employee workforce factors;


	•		our assumptions concerning economically recoverable coal reserve estimates;


	•		future economic or capital market conditions;


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


	•		the closing or successful integration of the Triad acquisition.

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; our dependency on one railroad for transportation of our products; failure to exploit additional coal reserves; failure to diversify our operations; increased capital expenditures; increased compliance costs; lack of availability of financing sources; the effects of regulation and competition; and the risk factors detailed in our registration statement on Form S-1, initially filed with the SEC as of August 13, 2004, as amended.

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 profitability to decline significantly.

We derived 83% of our total revenues (contract and spot) in 2004, and 88% of our total revenue in 2003, 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. Robust economic activity can cause much heavier demands for power, particularly if such activity results in increased utilization of industrial assets during evening and nighttime periods. The economic slowdown experienced during the last several years significantly slowed the growth of electrical demand and, in some locations, resulted in contraction of demand.

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.

Deregulation of the electric utility industry may cause our customers to be more price-sensitive in purchasing coal, which could 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; 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. According to Platts, the world’s largest energy information provider, although there are more than 600 coal producers in the United States, the ten largest coal companies accounted for approximately 63% of total domestic coal production in 2003. 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. Our coal is generally shipped via rail systems (CSX and Norfolk Southern), although we also transport a small portion of our coal by truck. During 2004, we shipped in excess of 95% of coal via CSX. 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 U.S. could become more attractive as a source of coal to consumers in the eastern U.S. if the costs of transporting coal from the West were significantly reduced.

We depend primarily upon railroads, and, in particular, the CSX railroad, to deliver coal to our customers. Disruption of railroad 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.

During 2004, the major eastern railroads (CSX and Norfolk Southern) experienced significant service problems. These problems were caused by an increase in overall rail traffic from the expanding economy and shortages of both equipment and personnel. The service problems had an adverse effect on our shipments during several months in 2004. If these service problems persist, they could have an adverse impact on our financial results in 2005 and beyond.

Also during 2004, both the State of West Virginia and the Commonwealth of Kentucky began to vigorously enforce loaded weight limits for trucks hauling coal on state and local roads. This has caused a disruption of service for several mining companies in our geographic area. These enforcement programs could disrupt our coal hauling service and/or impact hauling costs in the future.

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. As the demand for coal has increased, many producers have attempted to increase coal production, which 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 these 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;


	•		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, the volume of our coal sales and price or could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future.

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

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

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

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

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

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

New 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. 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 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.

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.

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. For example, the EPA has announced that it would regulate hazardous air pollutants from coal-fired power plants. Under the Clean Air Act, coal-fired power plants will be required to control hazardous air pollution emissions by no later than 2009, which likely will require significant new investment in controls by power plant operators. These standards and future standards could have the effect of decreasing demand for coal.

Other 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.

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 of our sales.

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, the volume of our coal sales and price. 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.

Other 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. For example, the Environmental Protection Agency recently proposed separate regulations 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 Environmental Protection Agency continues to require reduction of nitrogen oxide emissions in 22 eastern states and the District of Columbia and will require reduction of particulate matter emissions over the next several years for areas that do not meet air quality standards for fine particulates. In addition, 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 to the planning and building of utility power plants in the future.

To the extent that any new or proposed requirements affect our customers, this could adversely affect our operations and results.

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 the Kentucky Environmental and Public Protection Cabinet pursuant to the 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 which restrict our ability to conduct our mining operations or to do so profitably.

Prior to placing excess fill material in valleys, coal mining companies are required to obtain a permit from the U.S. Army Corps of Engineers under Section 404 of the Clean Water Act. The permit can be either a simplified Nation Wide Permit #21 (“NWP 21”) or a more complicated individual permit. On July 8, 2004, U.S. District Judge Joseph R. Goodwin of the Southern District of West Virginia, Huntington Division found that NWP 21 is in violation of the Clean Water Act. This ruling applies only to certain counties in southern West Virginia (where we do not now operate) and does allow permits to continue to be issued under the more costly and time consuming individual permit process. It is possible that in the future, a similar ruling could be made for our operating areas.

In January 2005, a virtually identical claim to that filed in West Virginia was filed in Kentucky. The plaintiffs in this case, Kentucky River Keeper, Inc., et al. v. Colonel Robert A. Rowlette, Jr., et al., Civil Action No 05-CV-36-JBC, seek the same relief as that sought in West Virginia. Though the matter has just been initiated, it is possible that an adverse ruling could be made in this matter, which would have an adverse effect on our operations.

Recent litigation could impact our ability to conduct underground mining operations.

On March 29, 2002, the United States District Court for the District of Columbia issued a ruling that could restrict underground mining activities conducted in the vicinity of public roads, within a variety of federally protected lands, within national forests and within a certain proximity of occupied dwellings. The lawsuit, Citizens Coal Council v. Norton, was filed in February 2000 to challenge regulations issued by the Department of Interior providing, among other things, that subsidence and underground activities that may lead to subsidence are not surface mining activities within the meaning of SMCRA. SMCRA generally contains restrictions and certain prohibitions on the locations where surface mining activities can be conducted. The District Court entered summary judgment on the plaintiffs’ claims that the Secretary of the Interior’s determination violated SMCRA. This decision was recently reversed by the United States Court of Appeals for the Fourth Circuit, which upheld the regulation. In December 2003, a petition for a writ of certiorari was filed by the Citizens Coal Council and others requesting U.S. Supreme Court review.

In the future, we intend to conduct deep mining activities on properties that are within federally protected lands or national forests where the above-mentioned restrictions within the meaning of the SMCRA could apply. Any reinstatement of the District Court decision by the Supreme Court would pose a potential restriction on underground mining within 100 feet of a public road as well as other restrictions. If these SMCRA restrictions ultimately apply to underground mining, considerable uncertainty would exist about the nature and extent of this restriction. While, even if that occurs, it could remain possible to obtain permits for underground mining operations in these areas, the time and expense of that permitting process would be likely to increase significantly and the restrictions placed on the mining of those properties could adversely affect our costs.

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

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

For 2004, we generated approximately 71% of our total revenues from several long-term contracts with electrical utilities, including 30% from our largest customer, Georgia Power Company, and 20% from South Carolina Public Service Authority. At December 31, 2004, we had coal supply agreements with these customers that expire at various times from 2005 to 2007. 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 during 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.

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. The current strength in the coal market may not continue. 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 profitability 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 (greater than one year) 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 a balance of contract sales to spot sales, or our markets become depressed for an extended period of time, our volumes and margins could decrease, negatively affecting our profitability.

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, if the Triad acquisition is completed, 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, if the Triad acquisition is completed, Southern Indiana. We may also consider opportunities in the natural gas and coalbed methane industries. 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 intend to expand our operations through strategic acquisitions of other coal mining companies, although we have no agreement, other than with respect to Triad, and no understanding for any other 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 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.

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 described below. Scrap steel prices have risen significantly in recent months, and historically, the prices of scrap steel and petroleum have fluctuated. 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 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 as profitably 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, as discussed in “Government Regulation” above. 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.

Our financial performance may suffer if we do not successfully develop our new mine at the McCoy Elkhorn mining complex.

We are currently developing a new underground mine at our McCoy Elkhorn mining complex. This mine will be below drainage; i.e., because the coal seam does not intersect the surface in the vicinity of the mining area, it must be accessed through excavated passageways from the surface. Accordingly, we will be required to construct a slope and a shaft for the transportation of miners, equipment and supplies to the mine. As a result, the time, expense and risk of developing such a below drainage mine may be greater than those of a drift mine. The capital expenditures required for this mine are expected to be approximately $23 million over a period of 12 months.

If our actual capital expenditures exceed forecasted levels, if mining conditions are less favorable than expected or if we are unable to successfully implement our planned development and production schedule for this new mine (including potential delays caused by weather, unforeseen geological conditions or otherwise), our financial performance could be negatively affected.

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 2005, we anticipate approximately 11% of our total production will come from mines operated by independent contract mine operators and that almost 2% of our total coal sold will come 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. The demand for contract mining companies has increased significantly due to the current strong market prices for coal from central Appalachia. Due to our bankruptcy and the current strong market conditions, we lost the services of several contract mining companies beginning in 2003 and continuing in 2004. We are actively recruiting replacements for these operators lost in 2004. 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 are based on studies conducted by Marshall Miller & Associates, Inc. in accordance with industry-accepted standards. 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. For a further discussion of our coal reserves, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates” and “Business – Reserves.”

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, 2004, we had outstanding surety bonds with third parties for post-mining reclamation totaling $28.2 million. Furthermore, we have surety bonds for an additional $42.7 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 senior secured credit facility also reduces amounts that we can borrow under our senior secured credit facility for other purposes. If we are unable to secure surety bonds for these obligations in the future, and are forced to secure letters of credit indefinitely, our profitability may be negatively affected.

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, 2004, the current and non-current portions of these obligations included $25.9 million for coal workers’ black lung benefits and $50.3 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 pension benefits to eligible employees. As of December 31, 2004, we estimated that our pension plan was underfunded by approximately $21.9 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 the Company’s assumptions are inaccurate, the Company could be required to expend greater amounts than anticipated.

As a result of our adoption of “fresh start” accounting in connection with our emergence from bankruptcy, you will not be able to compare our financial statements for periods before our emergence from bankruptcy with our financial results for periods after our emergence from bankruptcy.

As a result of the consummation of our Plan of Reorganization and the transactions contemplated thereby, we are operating our business under a new capital structure. In addition, we became subject to the fresh start accounting rules upon emerging from bankruptcy. Accordingly, our financial condition and results of operations disclosed for periods after our emergence from bankruptcy differ significantly from the financial condition or results of operations reflected in our financial statements for periods before our emergence from bankruptcy.

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, including a first lien held by Wells Fargo Foothill, Inc. securing our new senior secured credit facility and a second lien held by our pre-bankruptcy senior secured lenders securing our restructured term debt. If one of these security interest holders becomes entitled to exercise its rights as a secured party, it would have the right to foreclose upon and sell, or otherwise transfer, the collateral subject to its security interest, and the collateral accordingly would be unavailable to us and our other creditors, except to the extent, if any, that other creditors have a superior or equal security interest in the affected collateral or the value of the affected collateral exceeds the amount of indebtedness in respect of which these foreclosure rights are exercised.

We may be unable to comply with restrictions imposed by our credit facilities, which could result in a default under these agreements.

Our credit facilities impose a number of restrictions on us. A failure to comply with these restrictions could adversely affect our ability to borrow under our senior secured credit facility or result in an event of default under these agreements and our other debt. Our credit facilities contain financial and other covenants that create limitations on our ability to, among other things, borrow the full amount under the revolver component of our senior secured credit facility or incur additional debt, and require us to maintain various financial ratios and comply with various other financial covenants. These covenants include the following requirements:


	•		minimum fixed charge coverage ratio;


	•		maximum total leverage ratio;


	•		minimum levels of consolidated tangible net worth;


	•		minimum levels of Consolidated Total EBITDA (as defined in our credit facilities); and


	•		maximum limits on capital expenditures.

The levels for each of these financial covenants are based upon our projected operating performance. 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 an amendment 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 the costs of debt financings to us and impair our ability to obtain additional debt financing.

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.

The disallowance of Section 29 tax credits for synfuel plants by the Internal Revenue Service could decrease our revenues.

We supply coal to a third party synfuel plant and receive fees for the handling, shipping and marketing of the synfuel product. Synfuel is a synthetic fuel product that is produced by chemically altering coal. In 2004, 2% of our total revenues came from synfuel handling, shipping and marketing revenues. Sales of the fuel processed through these types of facilities are eligible for non-conventional fuels tax credits under Section 29 of the Internal Revenue Code. The owner of the facility that we supply with coal has obtained a Private Letter Ruling (“PLR”) from the Internal Revenue Service confirming that the facility produces a qualified fuel eligible for Section 29 tax credits. The Section 29 tax credit program is scheduled to expire on December 31, 2007. There is a risk that the IRS could modify or disallow the Section 29 tax credit, making operation of the synfuel plant unprofitable. If the synfuel plant ceases operations, we will no longer receive the handling, shipping and marketing fees for our services, which may negatively affect our profitability.

Our auditors have previously identified material weaknesses in our internal controls. Although we have remediated these material weaknesses, if additional internal control issues develop, we may be unable to accurately report our financial results, detect fraud or comply with the requirements of Section 404 of the Sarbanes-Oxley Act.

In August 2004, our independent auditors advised our Audit Committee that they had identified material weaknesses in our internal controls in connection with the audit of our 2003 financial statements. First, our auditors identified a material weakness related to our controls around the data provided to our actuaries that was used in the actuarial valuation of our workers' compensation and black lung benefit obligations. This material weakness led to a restatement of our 2002 and 2001 financial statements. Second, our auditors identified a material weakness related to the lack of controls over our year-end financial closing process and our ability to produce accurate consolidated financial statements. This weakness resulted in a significant number of audit adjustments that materially changed our preliminary 2003 consolidated financial statements. Our independent auditors also identified a need to add to the staff and strengthen the overall skills of our accounting department. We undertook remedial actions related to these material weaknesses. During the audit of our 2004 consolidated financial statements, our independent auditors did not identify any material weaknesses; however, their audit was not designed for the purpose of forming an opinion on the assessment or effectiveness of our internal controls over financial reporting. See Item 9A, “Controls and Procedures - Changes in Internal Controls Over Financial Reporting,” for a discussion of our responses to the identification of those weaknesses, and more recent developments with respect to those responses.

Achieving compliance with Section 404 within the prescribed period, and remedying any deficiencies, significant deficiencies or additional material weaknesses that we or our auditors may identify, will require us to incur significant costs and expend significant time and management resources. We cannot assure you that any of the measures we implement to remedy any such deficiencies will effectively mitigate or remediate such deficiencies. In addition, we cannot assure you that we will be able to complete the work necessary for our management to issue its management report in a timely manner, or that we will be able to complete any work required for our management to be able to conclude that our internal control over financial reporting is effective. If we fail to timely remedy any deficiencies, significant deficiencies or additional material weaknesses that we or our auditors may identify, we may be unable to accurately report our financial results, detect fraud or comply with the requirements of Section 404. In addition, we can give no assurance that our independent auditors will agree with our management’s assessment or conclude that our internal control over financial reporting is effective.

Our company could be less valuable if we are unable to close the Triad acquisition, or if we are unable to successfully integrate Triad into our operations.

The Triad acquisition would significantly increase our surface mining operations, thereby creating more balance between our surface and underground operations. However, the Triad acquisition is subject to certain conditions, including obtaining certain consents, and will not close unless we and other relevant parties satisfy or waive all of these conditions. We cannot assure you that we or any relevant party will be able to satisfy the conditions required to close the acquisition.

A failure to close the Triad acquisition, or a substantial delay in closing, could have a material adverse effect upon our business prospects, financial condition and results of operations. We would possess significantly more limited surface mining operations, as well as fewer reserves. For information about the Triad acquisition, including the conditions to which the acquisition is subject, see “The Triad Acquisition.”

In addition, if we close the Triad acquisition, we may be unable to successfully integrate Triad’s operations, or to operate those operations profitably. Our failure to successfully integrate Triad’s operations would have a material adverse effect on our results of operations and financial condition.

Triad’s current reserve base is limited.

Triad’s mines currently have rights to proven and probable reserves that we believe will be exhausted in 4 years at current levels of production, compared to our current mining complexes, which have reserves that we believe will last an average of approximately 24 years at current levels of production. If we complete the Triad acquisition, we intend to increase Triad’s reserves by acquiring rights to additional exploitable reserves that are either adjacent to or nearby Triad’s current reserves. If we are unable to successfully acquire such rights on acceptable terms, or if our exploration or acquisition activities indicates that such coal reserve 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. For information about the Triad acquisition, including the conditions to which the acquisition is subject, see “The Triad Acquisition.”

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, 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;


	•		potential initiation and subsequent changes in financial estimates by securities analysts;


	•		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 National Market, make it difficult to predict the market price for our common stock and cause the value of your investment to decline.

Dividends are prohibited by our credit facilities.

We do not anticipate paying any dividends on our common stock in the near future. In addition, covenants in our debt instruments will restrict our ability to pay cash dividends and may prohibit the payment of dividends and certain other payments. Some institutional investors may only invest in dividend-paying equity securities or may operate under other restrictions that may prohibit or limit their ability to invest in our common stock.

Provisions of our articles of incorporation, bylaws and shareholder rights agreements 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.

On May 25, 2004, our shareholders approved a 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 15% of the outstanding shares of our common stock, would entitle each right holder, other than the person or group triggering the plan, to receive, upon exercise of the right, shares of our common stock having a then-current fair value equal to twice the exercise price of a right. This shareholder rights agreement provides us with a defensive mechanism that decreases the risk that a hostile acquirer will attempt to take control of us without negotiating directly with our board of directors. The shareholder rights agreement may discourage acquirers from attempting to purchase us, which may adversely affect the price of our common stock.

ITEM 2. PROPERTIES

As of December 31, 2004, we controlled approximately 212,200 acres of land, of which approximately 204,900 acres were leased and the remainder was owned. In a mining context, control of a property is typically divided into three categories:


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


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


	•		fee control, which includes both mineral and surface rights.

Our rights with respect to properties that we lease vary from lease to lease, but encompass mineral rights, surface rights, or both. Our rights with respect to our owned properties are categorized as follows: fee ownership (100 acres), mineral rights ownership (1,200 acres) and surface rights ownership (6,000 acres).

Our coal properties 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. We hold over 300 leases, the terms of which vary significantly, including in 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.

Our corporate headquarters are located in Richmond, Virginia and are occupied pursuant to a lease that expires in June 2008.

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, 2004.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Market Information

On January 25, 2005, our common stock commenced trading on the Nasdaq National Market under the ticker symbol “JRCC”. From November 15, 2004 until January 24, 2005, our common stock was quoted on the Over-the-Counter Bulletin Board. The table below sets forth the high and low sales prices for our common stock for the periods indicated, as reported by Nasdaq or quoted through the OTC Bulletin Board. The per share quotations for the periods in which our common stock was traded in the over-the-counter market represent inter-dealer prices, without adjustment for retail mark ups, mark-downs or commissions and may not necessarily represent actual transactions. All sales prices have been adjusted retroactively to reflect the two-for-one stock split effected as of October 22, 2004, in the form of a 100% stock dividend.


	Range of Sales Price
		High		Low
Fiscal year ended December 31, 2004 Fourth quarter (a)	$	49.75	$	35.63


(a)		Covers the period starting November 15, 2004.

Recent Sales of Unregistered Securities

Effective May 6, 2004, all of our issued securities were cancelled pursuant to the Joint Plan of Reorganization confirmed by the U.S. Bankruptcy Court presiding over our Chapter 11 case, and we, in furtherance of our Plan of Reorganization, issued 13,799,994 shares of our common stock and $75 million in face amount of senior-subordinated notes, due May 6, 2011, in consideration for the cancellation of approximately $266 million in claims. The foregoing issuances and sales were conducted without registration of the securities under the Securities Act of 1933, as amended, in reliance upon the exemption from registration afforded by Section 1145(a)(1) of the Bankruptcy Code. Section 1145(a)(1) of the U.S. Bankruptcy Code exempts the offer and sale of securities under a plan of reorganization from registration under the Securities Act and state laws if: (i) the securities are offered and sold under a plan of reorganization; (ii) the securities are of a debtor, of an affiliate participating in a joint plan with the debtor, or of a successor to the debtor under the plan; and (iii) the recipients of the securities are issued such securities entirely in exchange for the recipient’s claim against or interest in the debtor or principally in such exchange and partly for cash or property.

Additionally, 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:


	No.		No.		Date of				Option Exercise
Recipient	Shares		Options		Issuance		Consideration		Price
Operating and senior management		881,700		150,000		May 7, 2004		Services rendered	$	10.80
		20,000		80,000		June 2, 2004		Services rendered	$	17.50
		8,000		-		November 1, 2004		Services rendered	$	N/A
		2,000		-		November 11, 2004		Services rendered	$	N/A
Non-employee directors (aggregate)		4,000		40,000		May 7, 2004		Services rendered	$	15.00

We have not included information regarding sales of unregistered securities that occurred before the effectiveness of our Plan of Reorganization, because all such pre- petition securities were cancelled pursuant to the Plan of Reorganization.

Holders

As of December 31, 2004, there were 106 record holders of the Common Stock.

Dividends

We have not paid any cash dividends on our common stock during the last two completed fiscal years or during 2004. We intend to retain our earnings and 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 credit facilities.

ITEM 6. SELECTED FINANCIAL DATA

In March 2003, the Company and all of its subsidiaries filed voluntary petitions with the United States Bankruptcy Court for the Middle District of Tennessee for reorganization under Chapter 11. Upon emergence from bankruptcy, we adopted “fresh start” accounting as contained in the American Institute of Certified Public Accountant’s Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code (“SOP 90-7”). In connection with the implementation of fresh start accounting, we recorded a gain of approximately $178.0 million from the extinguishment of our debt. Other adjustments were made to reflect the provisions of the Plan of Reorganization and to adjust the assets of the reorganized Company to their estimated fair value and liabilities to their estimated present value. For purposes of applying fresh start accounting, we have used an enterprise value for the reorganized Company of $155 million which was based on an appraisal performed for one of our lenders in connection with our reorganization. For financial reporting purposes, these transactions were reflected in our operating results before emergence.

Our consolidated financial statements after emergence are those of a new reporting entity (the “Successor Company”) and are not comparable to the financial statements of the pre-emergence company (the “Predecessor Company”). For a complete discussion of our application of fresh start accounting, please refer to note 3 of our December 31, 2004 consolidated financial statements.

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 for eight months ended December 31, 2004 (successor period) and for each of the years ended December 31, 2000 through December 31, 2003 and the four months ended April 30, 2004 (predecessor periods) are 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.

James River Coal Company and Subsidiaries
Selected Financial Data


	Successor				Predecessor
	Company				Company
	Eight				Four			Predecessor Company
	Months Ended				Months Ended			Year Ended December 31,
	12/31/04				4/30/04			2003			2002			2001			2000
				(in thousands, except share information and number of employees)
Consolidated Statement of Operations:
Revenues	$	231,698				113,949			304,052			397,599			384,248			416,756
Cost of coal sold		190,926				89,294			278,939			344,222			328,408			341,092
Depreciation, depletion, and amortization		21,765				12,314			40,427			46,393			43,175			43,272

Gross profit (loss)		19,007				12,341			(15,314	)		6,984			12,665			32,392
Selling, general, and administrative expenses		11,412				5,023			19,835			19,994			15,725			15,281
Other operating expenses		-				-			-			26,554			-			-

Operating income (loss)		7,595				7,318			(35,149	)		(39,564	)		(3,060	)		17,111
Interest expense		5,733				567			18,536			29,883			23,923			17,706
Interest income		(72	)			-			(144	)		(1,003	)		(662	)		-
Miscellaneous income, net		(833	)			(331	)		(1,519	)		(1,222	)		206			(3,977	)
Reorganization items, net		-				(100,907	)		7,630			-			-			-
Income tax expense (benefit)		791				-			(2,891	)		(8,125	)		(10,318	)		(2,503	)

Income (loss) before cumulative effect of accounting change		1,976				107,989			(56,761	)		(59,097	)		(16,209	)		5,885
Cumulative effect of accounting change		-				-			(3,045	)		-			-			-

Net income (loss)		1,976				107,989			(59,806	)		(59,097	)		(16,209	)		5,885
Preferred dividends		-				-			(340	)		(680	)		(595	)		(714	)
(Increase) decrease in redemption amount of redeemable common stock		-				-			-			8,798			45,831			14,311

Net income (loss) attributable to common shareholders		1,976				107,989			(60,146	)		(50,979	)		29,027			19,482

James River Coal Company and Subsidiaries
Selected Financial Data


	Successor Company Eight Months Ended			Predecessor Company Four Months Ended		Predecessor Company Year Ended December 31,
	12/31/04			4/30/04		2003			2002			2001		2000
			(in thousands, except share information and number of employees)
Basic earnings (loss) per common share:
Income (loss) before cumulative effect of accounting change	$	0.14			6,393.67		(3,380.78	)		(3,018.31	)		1,718.56		1,153.46
Cumulative effect of accounting change		0.00			0.00		(180.28	)		0.00			0.00		0.00

Net income (loss)		0.14			6,393.67		(3,561.06	)		(3,018.31	)		1,718.56		1,153.46
Shares used to calculate basic earnings (loss) per common share (1)		13,799,994			16,890		16,890			16,890			16,890		16,890
Diluted earnings (loss) per common share:
Income (loss) before cumulative effect of accounting change	$	0.14			6,393.67		(3,380.78	)		(3,018.31	)		1,718.56		1,153.46
Cumulative effect of accounting change		0.00			0.00		(180.28	)		0.00			0.00		0.00

Net income (loss)		0.14			6,393.67		(3,561.06	)		(3,018.31	)		1,718.56		1,153.46
Shares used to calculate diluted earnings (loss) per share (1)		14,622,620			16,890		16,890			16,890			16,890		16,890

Share numbers reflect shares of our common stock issued and outstanding as of the applicable periods. The shares outstanding for the Successor Company reflect the stock split effected on October 22, 2004.


	Successor Company			Predecessor Company			Predecessor Company December 31,
	12/31/04			4/30/04			2003			2002			2001			2000
			(in thousands)
Consolidated Balance Sheet Data:
Working capital (deficit)	$	10,046			5,896			9,009			(263,149	)		(241,857	)		(17,505	)
Property, plant, and equipment, net		255,727			254,259			257,156			270,989			310,643			306,399
Total assets		327,826			332,589			318,289			340,311			393,411			382,534
Long term debt, including current portion		95,000			6,400			-			252,437			249,576			232,734
Liabilities subject to compromise		-			319,451			319,595			-			-			-
Total shareholders’ equity (deficit)		65,585			(127,837	)		(123,601	)		(68,726	)		(9,034	)		(29,786	)


	Successor Company Eight Months Ended			Predecessor Company Four Months Ended			Predecessor Company Year Ended December 31
	12/31/04			4/30/04			2003			2002			2001			2000
				(in thousands, except share information, per ton information and number of employees)
Consolidated Statement of Cash Flow Data:
Net cash provided by (used in) operating activities	$	14,098			1,513			23,033			28,899			30,793			46,038
Net cash used in investing activities		(21,744	)		(9,463	)		(15,660	)		(33,522	)		(43,640	)		(34,061	)
Net cash provided by (used in) financing activities		10,224			4,361			(2,489	)		3,347			14,119			(11,981	)
Supplemental Operating Data:
Tons sold		5,775			3,107			10,083			13,926			14,065			15,961
Tons produced		5,770			3,081			9,294			12,350			13,134			15,599
Revenue per ton sold (excluding synfuel)	$	40.12			35.98			29.53			28.26			27.29			26.11
Number of employees		1,070			984			1,127			1,145			1,319			1,172
Capital expenditures	$	25,811			9,521			20,116			22,925			43,694			35,927

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our 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 believe that coal-fired electric utilities value the high energy, low sulfur coal that comprises the majority of our reserves. As of March 31, 2004, based on our most recent independent reserve report, we estimate that we controlled approximately 207 million tons of proven and probable coal reserves. As of December 31, 2004, we believe that we controlled approximately 207 million tons of proven and probable coal reserves. We believe 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 24 years of production.

Demand for coal increased significantly in 2004 due to a combination of conditions in the U.S. and worldwide that caused a shortage of certain grades of coal. Consequently, prices for the grades of coal we sell have risen significantly since mid-2003. Due to the fixed prices in the contractual commitments with utility customers that we renegotiated during the bankruptcy, we saw only a limited benefit from the current market environment in 2004.

Our revenues are impacted by the level of coal available for sale by us. That availability level decreased during 2003 and 2004, for the reasons discussed in “Results of Operations.” Those reasons include the filing of our bankruptcy petition (which led to termination of certain of our mine operator relationships); the loss of a supplier at our Blue Diamond complex; closure of higher-cost mines; and delays and other railroad services problems.

As compared to the prior year, we experienced a significant increase in mining costs during 2004. The increased costs were primarily due to higher royalties and severance taxes, lower operating productivity from our deep mines and preparation plants, an increase in roof support costs due to an increase in steel costs, and increased trucking costs resulting from vigorous enforcement of weight limits as previously discussed. We are focused on reducing our operating costs at each mine and improving miner productivity. We continue to make capital expenditures to upgrade our equipment, facilities, and infrastructure. We are also focused on enhancing our training programs to help our personnel be safer and more productive.

Reserves

Marshall Miller & Associates, Inc. (“MM&A”) prepared a detailed study of our reserves as of March 31, 2004 based on all of our geologic information, including our updated drilling and mining data. The coal reserve study conducted by MM&A was planned and performed to obtain reasonable assurance of our subject demonstrated reserves. In connection with the study, 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. MM&A completed their report in June 2004.

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 study and the foregoing assumptions and qualifications, and after giving effect to our operations from March 31, 2004 through December 31, 2004, we estimate that, as of December 31, 2004, we controlled approximately 207.4 million tons of proven and probable coal reserves. MM&A has not conducted a coal reserve study on our December 31, 2004 reserve estimate. The following table provides additional information regarding changes to our reserves since March 31, 2004 (in millions of tons):


	Three Months Ended December 31, 2004			Six Months Ended September 30, 2004
Proven and Probable Reserves beginning of period (1)		205.2			207.2
Coal Extracted		(1.9	)		(4.4	)
Acquisitions (2)		2.3			1.4
Adjustments (3)		1.8			1.0

Proven and Probable Reserves end of period		207.4			205.2


(1)			Calculated in the same manner, and based on the same assumptions and qualifications, as described above. 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 properties acquired during the relevant period. The Company calculated the reserves in the same manner, and based on the same assumptions and qualifications, as described above, but such estimates were not covered by the MM&A report.


(3)			Represents changes in reserves due to additional information obtained from exploration activities, production activities or discovery of new geologic information. The Company calculated the reserves in the same manner, and based on the same assumptions and qualifications, as described above, but such estimates were not covered by the MM&A report.

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/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, such as the current period, 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. Our operating costs are measured by our operating costs per ton produced. Our operating productivity is measured by Linear Feet (of mine advance) Per Man Hour (LFPMH). LFPMH gives us a good indication of labor productivity across a number of different mines.

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

We expect the current strong pricing environment for coal to weaken somewhat during the next one to two years. This is due to increased incremental production that has historically come into the markets during periods of strong pricing. We believe that the impact of this potentially increased production will be offset by the need of utilities to rebuild diminished coal inventories resulting from service difficulties that the major railroads experienced in 2004. According to the Energy Information Administration (EIA), coal stockpiles at utilities are currently below normal levels. Any effort by the utilities to rebuild their inventory positions should absorb a portion of any increased coal production. Any recurrence of the difficulties with rail transportation experienced during 2004 may also have an impact on increased production and market pricing. If marginal increases in the production of coal cannot be delivered to the utility customers by rail in a timely manner, the depressing effect of the increased production on market prices will be reduced. In addition, any new coal production would likely require additional permits, labor and equipment, which are currently difficult and time consuming to obtain.

Although the current pricing environment for U.S. coal is strong, coal prices are subject to change based on a number of factors beyond our control, 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;


		•		air emission standards and other environmental requirements for coal-fired power plants; and


		•		the price and availability of alternative fuels for electricity generation.

As discussed previously, our costs of production have recently increased. We expect the higher costs to continue for the next several years, due to a highly competitive market for a limited supply of skilled mining personnel and higher costs in worldwide commodity markets. We are actively recruiting and training new personnel to staff our mines. However, we expect the strong market pricing for coal to increase turnover of existing personnel and potentially lead to higher costs for employees that we retain. Our costs have also increased for steel and other commodities used in our mining operations. We believe these increases are the result of economic development in the Pacific Rim (notably China) and an expanding economy in the United States. We do not anticipate a change in these circumstances during the next one to two years.

Plan of Reorganization

In March 2003, we and all of our subsidiaries filed voluntary petitions with the United States Bankruptcy Court for the Middle District of Tennessee for reorganization under Chapter 11. In January 2004, we filed a Plan of Reorganization for the Chapter 11 cases. The plan was subsequently accepted by the required percentage of creditors entitled to vote on the plan and was confirmed by the bankruptcy court in April 2004.

On May 6, 2004, after securing a new senior secured line of credit and term loan facility, our Plan of Reorganization became effective, and we emerged from Chapter 11 bankruptcy proceedings, as more fully described under “Business – Recent Reorganization.” Our implementation of fresh start accounting pursuant to SOP 90-7 resulted in material changes to our consolidated financial statements, including the valuation of our assets and liabilities at fair value in accordance with principles of purchase accounting, and the valuation of equity based on a valuation of our business prepared by our independent financial advisors.

As a result of the reorganization transactions and the implementation of fresh start accounting, our results of operations after our emergence from bankruptcy are those of a new reporting entity (the “Successor Company”), and are not comparable to the results of operations of the pre-emergence Company (the “Predecessor Company”) for prior periods described in this management’s discussion and analysis and reported in our consolidated financial statements.

Financial statements for periods after March 25, 2003 and prior to April 30, 2004 include the effects of our bankruptcy proceedings. These include the classification of certain liabilities as “liabilities subject to compromise,” the classification of certain expenses, and gains and losses as reorganization items, and other matters described in the notes to our consolidated financial statements.

Workers’ Compensation Cost and Accrued Liabilities

Our cost and accrued liabilities for workers’ compensation and other employee benefits have risen dramatically during the past several years.

Our accrued liability for workers’ compensation as of December 31, 2004 was $50.3 million. Our expense for workers’ compensation was $9.3 million in 2004. Our expense in 2004 was impacted by favorable actuarial changes that resulted in a $3.5 million decrease in our workers’ compensation reserves during 2004. Our workers’ compensation expense has ranged from $9.3 million in 1999 to $14.5 million in 2003. Generally, we have experienced an increase over time in our workers’ compensation expense due to factors that impact the entire coal industry as well as factors that are unique to us.

For the coal industry, workers’ compensation costs have increased due to changes in laws, changes in the interpretation of the laws by the courts and an overall increase in both the number and amounts of disability awards. According to the 2003 Annual Report of the Kentucky Office of Workers’ Claims, for 1999-2003, the number of claims filed increased by 31%, and the total system cost of the workers’ compensation programs increased by 25%.

During the 1990s, we completed several acquisitions that included the assumption of all historical liabilities associated with workers’ compensation. These liabilities were greater than originally projected. In addition, our financial condition began to deteriorate in 1999. This caused us to reduce our spending for new equipment and for major repairs. We were also seeking a merger with or sale to other large firms in our industry. This caused a great deal of uncertainty for our employees. We believe that both of these facts led to a higher rate of reported accidents than would have otherwise been the case.

During the bankruptcy period, we stopped paying interest on our pre-petition secured debt and were able to negotiate interim price adjustments with our customers. The additional funds provided by these items have been used to purchase new equipment and complete major repairs to our equipment fleet, thereby improving the safety of our workplace. Since emerging from bankruptcy, we have begun to hire management and staff to assist us in managing our exposure to workers’ compensation claims. These employees have focused on improving our hiring practices, implementing new safety training procedures and better managing our workers’ compensation claims process.

Results of Operations

Year Ended December 31, 2004 Compared with the Year Ended December 31, 2003

In order to provide a basis for comparing the year ended December 31, 2004 with the year ended December 31, 2003, the operating results of the Successor Company for the eight months ended December 31, 2004 have been combined with the operating results for the Predecessor Company for the four months ended April 30, 2004, for purposes of the following table and discussion. The combining of the predecessor and successor accounting periods is not permitted by generally accepted accounting principles. Additionally, as explained above, the operating results of the Successor Company and the Predecessor Company are not comparable.

The following table shows selected operating results for the year ended December 31, 2004 compared to the year ended December 31, 2003:


	Year Ended December 31,
	2004		2003		Change
Volume (millions of tons)		8.9		10.1		(12	)%
Revenues (000)
Coal sales	$	338,297	$	297,713		14	%
Synfuel handling		7,350		6,339		16	%
Cost of coal sold (000)		280,220		278,939		1	%

Volume and revenues

We shipped 10.1 million tons of coal in 2003 and 8.9 million tons in 2004. Production from our company mines decreased by approximately 138,000 tons in 2004 as compared to 2003. This decrease in production from our company mines was due to adverse geological conditions at several of our mines and several major moves of mining equipment and personnel in the third and fourth quarters of 2004. In addition, there was a reduction during the year of 54% or 635,000 tons from contract mining operations. This reduction in coal obtained from contract mining operations is attributed to several underground mine contractors terminating our contract mine agreements to seek higher-priced opportunities with our competitors or closing operations due to depletion of reserves. We also experienced a decrease of 57%, or 448,000 tons, in coal purchased by us for resale. The reduction in coal purchased for resale from third parties is the result of the increased demand for purchased coal. We continue to be challenged in replacing contract mine operators and purchased coal sources due to the continued strong coal market.

Coal sales revenue increased from $297.7 million in 2003 to $338.3 million in 2004. This increase was due to an increase in spot coal sales, which commanded a higher price in 2004 than in 2003, as well as an increase in the average sales price per ton for sales under long-term contracts. For the year ended December 31, 2004, we sold 7.2 million tons of coal under long-term contracts (81% of total sales volume) at an average selling price of $35.22. For 2003, we sold 9.3 million tons of coal under long-term contracts (92% of total sales volume) at an average selling price of $28.91. The increase in average selling price from 2003 to 2004 was due to the renegotiation of below-market contract prices as part of our bankruptcy proceedings. For the year ended December 31, 2004, we sold 1.7 million tons of coal (19% of total sales volume) to the spot market at an average selling price of $50.09 per ton. For 2003, we sold 772,000 tons of coal (8% of total sales volume) to the spot market at an average selling price of $36.91 per ton.

Revenues related to the handling, loading and shipping of synfuel increased from $6.3 million for the year ended December 31, 2003 to $7.4 million for the year ended December 31, 2004. We processed and shipped 6% less coal as synfuel in 2004 than we processed and shipped in 2003. However, our fees, on a per ton basis, increased during the same period.

Operating Costs

The cost of coal sold, excluding depreciation, depletion and amortization, increased from $278.9 million in 2003 to $280.2 million in 2004, even though the amount of coal we shipped decreased by 1.2 million tons. Our cost per ton of coal sold increased from $27.67 per ton in 2003 to $31.55 per ton in 2004. This $3.88 increase in cost per ton of coal sold was due to several factors. For production from our company-operated mines, sales related costs (primarily royalties and severance taxes) increased by $1.42 per ton as a result of increased sales prices. Labor and benefit costs for those tons increased by $1.00 per ton in 2004 primarily due to lower productivity at several mines. The labor and benefit costs were partially offset by a reduction in workers compensation costs of $3.5 million or $0.40 per ton during the fourth quarter of 2004 reflecting improved actuarial trends. Variable costs increased by $1.12 per ton, primarily due to higher roof support and machine parts costs primarily related to the increased cost of steel. In addition, the cost of coal produced by independent contract mine operators (6% of our 2004 tonnage) increased by $2.89 per ton while the cost of coal purchased from outside parties for resale (4% of our 2004 tonnage) increased by $3.39 per ton for the period. The application of fresh start accounting required that we increase the value of our inventory by approximately $1.1 million on April 30, 2004. This adjustment increased our cost of coal sold and reduced gross profit during the eight months ended December 31, 2004 by a corresponding amount.

For the year ended December 31, depreciation, depletion and amortization, decreased from $40.4 million in 2003 to $34.1 million in 2004. On a per ton basis, depreciation, depletion and amortization was $4.01 in 2003 and $3.84 in 2004. This decrease was primarily due to the impact of fresh start accounting on our asset base.

Selling, general and administrative expenses decreased from $19.8 million in 2003 to $16.4 million in 2004. This decrease was primarily due to a $4.2 million reduction in certain costs due to our exit from bankruptcy. This decrease was offset by approximately $1.1 million of stock based compensation expense recorded in 2004. We had no stock based compensation expense in 2003.

Year Ended December 31, 2003 Compared with the Year Ended December 31, 2002

The following table shows selected operating results for the years ended December 31, 2003 and December 31, 2002:


	Year Ended December 31,
	2003			2002			Change
Volume (millions of tons)		10.1			13.9			(27	)%
Revenues (000)
Coal sales	$	297,713			393,512			(24	)%
Synfuel handling		6,339			4,087			55	%
Cost of coal sold (000)		278,939			344,222			(19	)%
Depreciation, depletion and amortization		40,427			46,393			(13	)%
Selling, general and administrative expenses		19,835			19,994			(1	)%
Other operating expenses		-			26,554
Operating loss		(35,149	)		(39,564	)

Volume and revenues

We shipped 13.9 million tons of coal in 2002 and 10.1 million tons in 2003. The decrease was due to the closure of higher-cost Company-operated mines (2.4 million tons), reduced purchased coal tonnage (749,000 tons) and reduced tonnage from contract mining operations (662,000 tons). The decrease in purchased coal tonnage was primarily due to the loss of a supplier of purchased coal for our Blue Diamond operation. The filing of our bankruptcy petition on March 25, 2003 adversely impacted our outside sources of coal, and resulted in several contract mine operators terminating their relationship with us. The majority of this adverse impact was felt in the months after our bankruptcy filing.

Coal sales revenue for the year ended December 31 declined from $393.5 million in 2002 to $297.7 million in 2003. The decrease in revenue was due to fewer tons being available for sale, including coal produced from our Company-operated mines, coal produced by our independent contract mine operators and coal purchased by us for resale. For 2003, we sold 9.3 million tons of coal under long-term contracts (92% of total sales volume) at an average selling price of $28.91. For 2002, we sold 12.4 million tons of coal under long-term contracts (89% of total sales volume) at an average selling price of $27.42. The increase in average selling price was due to interim contract price increases during 2003. For 2003, we sold 772,000 tons of coal (8% of total sales volume) to the spot market at an average selling price of $36.91 per ton. For 2002, we sold 1.5 million tons (11% of total sales volume) to the spot market at an average selling price of $34.92 per ton. The change in the average selling price per ton of spot coal was due to an overall strengthening in the coal and energy markets during the fourth quarter of 2003.

Revenues related to the handling, loading and selling of synfuel increased from $4.1 million for 2002 to $6.3 million for 2003. This change was due to more coal being processed and shipped as synfuel. We processed and shipped 56% more coal as synfuel in 2003 than we processed and shipped in 2002.

Operating costs

For the year ended December 31, the cost of coal sold, excluding depreciation, depletion and amortization, decreased from $344.2 million in 2002 to $278.9 million in 2003. This decrease was due to a change in the volume of coal mined and shipped. Costs per ton of coal sold increased approximately $2.95, or 12%, to $27.67 in 2003 compared with $24.72 in 2002. The increase in per ton costs was primarily caused by higher variable costs at the mines for supplies, maintenance items and repairs of $0.83 per ton, higher costs at preparation plants and loadout facilities of $0.57 per ton due to fixed costs being spread over fewer tons and from the increased cost of contract miners (labor) of $0.30 per ton. We also experienced difficult geologic conditions at one of our mine complexes during the fourth quarter of 2003, which increased our costs by approximately $0.67 per ton. Our Linear Feet per Man Hour (LFPMH) decreased from 1.66 in 2002 to 1.57 in 2003. Our Clean Tons per Linear Foot (CTPLF)

decreased from 2.53 in 2002 to 2.49 in 2003. Both of these changes increased our operating costs per ton by spreading fixed costs over fewer tons.

Depreciation, depletion and amortization decreased from $46.4 million in 2002 to $40.4 million in 2003. The decrease was caused by the reduction in tons sold offset by an increase in the per ton cost. On a per ton basis, depreciation, depletion and amortization was $3.33 in 2002 and $4.01 in 2003. A portion ($0.10) of this increase was due to us lowering our estimate of remaining reserves in 2003, which increased the amortization expense per ton mined in 2003. See “Business – Reserves” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates – Coal Reserves” for a discussion of how we estimate our mineral reserves.

Selling, general and administrative expenses decreased from $20.0 million in 2002 to $19.8 million in 2003.

Other operating expenses were $26.6 million in 2002. These expenses represent adjustment for loss on abandoned mining fixed assets ($9.1 million), mine development costs ($7.7 million), prepaid royalties on abandoned properties ($4.2 million), capitalized debt issuance costs ($4.1 million) and other items ($1.5 million). In 2002, as part of our efforts to eliminate unprofitable operations, several mines and a preparation plant were idled. We determined that those operations could not be operated profitably, due to uneconomical or depleted reserves, so the preparation plant and certain assets associated with the mines (i.e., mine development costs, certain equipment and prepaid royalties) were abandoned.

Interest expense

Interest expense decreased to $18.5 million for 2003, compared with $29.9 million for 2002. The decrease was primarily due to our Chapter 11 bankruptcy filing on March 25, 2003 and the automatic stay from accruing and paying interest on our pre-petition debt. In the first quarter 2003, an interest rate swap agreement that we had previously entered into was terminated due to an event of default. As a result, the balance of $9.3 million that was recorded in accumulated other comprehensive loss was charged to interest expense. The higher interest cost for 2002 was primarily due to the increased interest rate in 2002 on our outstanding debt due to defaults under our loan and note agreements.

Miscellaneous income

Miscellaneous income increased from a $1.2 million gain in 2002 to a $1.5 million gain in 2003. In 2002, we received a royalty settlement of $1.1 million, and, in 2003, we had a $1.0 million gain from the sale of an investment.

Reorganization items, net

Reorganization items were $7.6 million in 2003. These costs represented the reorganization professional costs incurred in connection with our bankruptcy filing. There were no reorganization items incurred in 2002.

Income taxes

Income tax benefit was $2.9 million for 2003, compared with $8.1 million for 2002. The $2.9 million benefit for 2003 resulted from recording a deferred tax benefit on a loss on an interest rate swap that was previously recorded in other comprehensive loss. We had no other income tax expense or benefit for 2003 as we continued to record a valuation allowance against all of our net deferred tax assets.

Due to continuing losses from operations, 2002 was the first year in which we recorded a full valuation allowance against net deferred tax assets. The tax benefit of $8.1 million is lower than the “expected” tax benefit, calculated at 34%, of $22.9 million due to the recording of a $14.2 million valuation allowance against our net deferred tax assets and a $0.6 million net adjustment primarily for percentage depletion and state income taxes.

Cumulative effect of accounting change

We adopted Statement No. 143 effective January 1, 2003, and the adoption changed our accounting for reclamation. The cumulative effect of the accounting change was a charge to operations of $3.0 million. We also increased total reclamation liability by $6.8 million. We recorded the related capitalized asset retirement cost by increasing property, plant and equipment, net of accumulated depreciation, by $3.8 million.

Liquidity and Capital Resources

Although our cash from operations has changed significantly in the periods discussed below, we do not believe that those periods are comparable due to our emergence from bankruptcy. We experienced unusual swings in working capital leading up to and entering bankruptcy. We also were able to renegotiate our coal contracts due to the bankruptcy, which increased our revenues. Our liquidity going forward will be generated by our gross profit on coal sales. The gross profit will be driven by the price of coal and our operating costs. Our capital expenditure payments for existing operations are expected to be paid out of the cash generated by the gross profit.

As of December 31, 2004, we had available liquidity of approximately $3.9 million, which consisted entirely of unrestricted cash on hand. We had $5.6 million of potential advances ($30 million less outstanding letters of credit) under the revolver component of our Senior Secured Credit Facility at December 31, 2004; however we had no availability, as advances under the revolver component of our Senior Secured Credit Facility may not exceed a borrowing base calculation derived as a percentage of eligible assets (accounts receivable, inventory and fixed assets). Our eligible assets, at December 31, 2004 were impacted by lower shipments in December as compared to the preceding months in 2004. As of March 30, 2005, we had availability of $5.6 million under the revolver component of our Senior Secured Credit Facility.

Excluding any financing undertaken in connection with the proposed Triad acquisition, our primary source of cash will be sales of coal to our utility and industrial customers. The price of coal received can change dramatically based on supply and demand 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. We are required to pay these when due, and are not required to set aside cash for these payments. We have posted surety bonds with state regulatory departments to guarantee these payments and have secured letters of credit as further security for these obligations. Recently, surety bond costs have increased, while 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. The benefit payments for workers’ compensation and black lung benefits will be paid as the claims are submitted over the lives of our employees. We believe that these benefit payments are reasonably predictable and we have reflected them in the contractual obligations table below.

Excluding any financing undertaken in connection with the proposed Triad acquisition, our secondary source of cash is the revolver component of our Senior Secured Credit Facility. We believe that cash on hand, cash generated from our operating activities, and availability under the revolver component of our Senior Secured Credit Facility will be sufficient to meet our working capital needs, to fund our capital expenditures for existing operations and to meet our debt service obligations for the next twelve months, excluding the Triad acquisition. Nevertheless, there are many factors beyond our control, including general economic and coal market conditions, that could have a material adverse impact on our ability to meet our liquidity needs.

We expect to seek external financing in connection with our proposed acquisition of Triad. Such financing may take the form of one or more public or private equity or debt offerings. We may also seek to refinance our existing credit facilities with one or more new credit facilities providing for incremental borrowings. The Triad acquisition is conditioned upon our ability to obtain adequate financing.

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 and/or seek additional financing. If debt financing is not available on favorable terms, we may seek to raise funds through the issuance of our equity securities. If such actions are not sufficient, we may need to limit our growth and/or reduce or curtail some of our operations to levels consistent with the constraints imposed by our available cash flow. Our ability to seek additional debt or equity financing may be limited by our existing and any future financing arrangements and/or economic and financial conditions. In particular, our Senior Secured Credit Facility restricts our ability to incur additional indebtedness. We cannot provide assurance that any reductions in our planned expenditures or in our expansion and personnel 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.

Other than ordinary course of business expenses and capital expenditures for existing mines during the next several years and the proposed Triad acquisition, our only large expected use of cash will be the development of a new mine at our McCoy Elkhorn complex and the other projects described under “Other Projects” below. We expect to invest approximately $23 million in additional expenditures during the next 12 months in the development of the new McCoy Elkhorn mine. We expect that such developments will be funded through cash on hand, cash generated by operations and from the revolver component of our Senior Secured Credit Facility.

The following chart reflects the components of our debt as of December 31, 2004:


Senior Secured Credit Facility:
Term loan component	$	20,000,000
Revolver component		-
Term Credit Facility		75,000,000

Total long term debt		95,000,000
Less amounts classified as current		2,700,000

Total long term debt, less current maturities	$	92,300,000

Effective May 6, 2004, we closed a $50 million senior secured credit facility with Wells Fargo Foothill, Inc. (the “Senior Secured Credit Facility”). This facility was used to repay outstanding amounts and replace letters of credit under our $20.0 million debtor-in-possession facility, to fund expenses associated with our exit from bankruptcy and to provide liquidity for general corporate purposes. The Senior Secured Credit Facility is comprised of a $30 million revolver component and a $20 million term component. The term loan was fully funded at closing. Borrowings under the revolver component bear interest at LIBOR + 2.5% or the Base Rate (as defined in the credit agreement) + 1.0%. Borrowings under the term component bear interest at LIBOR + 5.25% or the Base Rate + 3.85%. The term of the Senior Secured Credit Facility is five years. Principal payments on the term component of $900,000 per quarter commence on April 1, 2005 and continue through April 1, 2009, with the remaining principal balance due on May 6, 2009. Interest is payable in arrears, on the first day of each month on Base Rate borrowings while interest on LIBOR Rate borrowings is due on the last day of the LIBOR interest period. Advances under the Senior Secured Credit Facility are secured by a first priority lien on substantially all of our assets, and, except for the Term Credit Facility, we may not incur additional debt on the assets securing the Senior Secured Credit Facility. Advances under the revolver component may not exceed a borrowing base calculation derived as a percentage of eligible assets. The Senior Secured Credit Facility can be terminated with 90 days written notice by paying all outstanding principal, interest and making any prepayment premium payments due. The $30 million revolver component has a prepayment premium of 2.5% of the total revolver commitment for the first year, declining to 2.0% for the second year, 1.5% for the third year and 0.5% for the fourth year. There is not a prepayment premium for the fifth year of the facility. The $20 million term loan component has a prepayment premium of $200,000 (1.0%) if paid prior to April 30, 2007. There is no prepayment premium after April 30, 2007.

We also entered into a $75 million restructured term credit facility with our pre-petition secured lenders (the “Term Credit Facility”) in partial satisfaction of our prepetition obligations, pursuant to the Plan of Reorganization. The term of the Term Credit Facility is seven years, and our repayment of the Term Credit Facility is secured by a second priority lien on substantially all of our assets. Except for the Senior Secured Credit Facility, we may not incur additional debt on the assets securing the Term Credit Facility. In addition, we may not incur any unsecured debt (other than normal trade payables) and may not incur more than $5 million of recourse debt (including the

Senior Secured Credit Facility and the Term Credit Facility). The Term Credit Facility provides for an annual interest rate of 9%. There is no scheduled amortization of this facility for the first two years. The notes are payable over seven years with principal repayments of $1.5 million per quarter beginning June 30, 2006 and increasing to $2.5 million per quarter beginning June 30, 2008. All remaining principal and interest is due May 6, 2011. Borrowings under the Term Credit Facility may be prepaid without penalty.

The Senior Secured Credit Facility and the Term Credit Facility contain financial covenants for fixed charge coverage, total leverage, minimum consolidated tangible net worth, minimum Consolidated Total EBITDA (as defined in each of the credit facilities), and maximum capital expenditures. We were in compliance with all of the financial covenants for the Senior Secured Credit Facility and the Term Credit Facility as of December 31, 2004. As of such date, the covenants included a minimum fixed charge ratio of .75 to 1.0, minimum leverage ratio of 2.75 to 1.0, minimum consolidated tangible net worth of $20 million, minimum Consolidated Total EBITDA of $44.0 million and maximum annual limits on capital expenditures of $35.3 million for all projects other than the new underground mine under development at our McCoy Elkhorn mining complex, and $23.4 million for capital expenditures at that new mine during 2005.

Net cash provided by or used in operating activities reflects net income or 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 $15.6 million for the year ended December 31, 2004, and net cash provided by operating activities was $23.0 million for the year ended December 31, 2003. For the year ended December 31, 2004, the Company’s net income, as adjusted for non cash charges, was offset by a $30.2 million decrease in cash from operations due to changes in our working capital. This change in net working capital was primarily caused by changes in accounts receivable due to increased sales prices of coal and a decrease in accounts payable due to increased liquidity upon emergence from bankruptcy.

Net cash used by investing activities increased $15.5 million to $31.2 million for the year ended December 31, 2004 as compared to the year ended December 31, 2003. The change was primarily due to a $15.2 million increase in capital expenditures in 2004 to $35.3 million as compared to 2003, offset by a $4.0 million increase in proceeds on sales of property in 2004. Capital expenditures primarily consisted of new and replacement mine equipment and various projects to improve the efficiency of our mining operations. The cash used in investing activities in 2003 also included a $2.3 million reduction in restricted cash and $2.0 million from the sale of investments. Our cash used by investing activities in 2002 was $33.5 million and included $22.9 million of capital expenditures and a $10.6 million change in restricted cash.

Net cash provided by or used in financing activities primarily reflects changes in short- and long-term financing. Net cash provided by financing activities was $14.6 million for the year ended December 31, 2004 and net cash used in financing activities was $2.5 million for the year ended December 31, 2003. During 2004, the Company received $20.0 million in proceeds, less $2.2 million capitalized debt issuance costs, from the Senior Secured Credit Facility in May 2004. During 2004, the Company also borrowed and repaid $6.4 million under its Debtor in Possession Loan. The Company had no proceeds from borrowings and had $1.9 million in principal payments during the year ended December 31, 2003. Net cash provided by financing activities in 2002 was $3.3 million, primarily due to the issuance of $3.4 million of debt under our pre-petition credit agreements in 2002.

Contractual Obligations

The following is a summary of our contractual obligations and commitments as of December 31, 2004:


	Payment Due by Period (in thousands)
Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long term debt	$	95,000		2,700		17,700		29,100		45,500
Interest on long term debt ⁽¹⁾		51,469		11,158		21,491		14,214		4,606
Capital lease obligations⁽²⁾		1,142		459		683		-		-
Operating lease obligations⁽²⁾		1,239		605		552		82		-
Royalty obligations⁽³⁾		141,732		14,705		31,233		28,414		67,380
Purchase obligations⁽⁴⁾		603		603		-		-		-

	$	291,185		30,230		71,659		71,810		117,486


(1)			Includes interest payments on variable rate debt that is based on the interest rate in effect as of December 31, 2004.


(2)			Capital lease obligations include the amount of imputed interest over the terms of the leases. See Note 13 in the notes to the consolidated financial statements for additional information on capital and operating leases.


(3)			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.


(4)			Purchase obligations include agreements to purchase coal that include fixed quantities or minimum amounts and a fixed price provision. They do not include agreements to purchase coal with vendors that do not include quantities or minimum tonnages, or monthly purchase orders.

Additionally, the Company has liabilities relating to pension, workers compensation, black lung, and mine reclamation and closure. As of December 31, 2004, payments related to these items are estimated to be:


Payments Due by Years (In Thousands)
Within 1 Year		2 – 3 Years		4 – 5 Years
$	17,700	$	25,938	$	21,318

The Company’s 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 the Company’s assumptions are inaccurate, the Company could be required to expend greater amounts than anticipated. Moreover, in particular for periods after 2004, the Company’s estimates may change from the amounts included in the table, and may change significantly, if its assumptions change to reflect changing conditions. These assumptions are discussed in the Notes to the Consolidated Financial Statements and in the Critical Accounting Estimates of the Management’s Discussion & 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, 2004, we had $71.0 million of outstanding surety bonds with third parties. These bonds were in place to secure obligations as follows: post-mining reclamation bonds of $28.2 million, workers’ compensation bonds of $40.3 million, wage payment, collection bonds, and other miscellaneous obligation bonds of $2.5 million. Recently, surety bond costs have increased, while 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. At December 31, 2004, we had $30.0 million of letters of credit outstanding, including $7.8 million of letters of credit outstanding collateralized by $8.4 million of cash deposited in restricted, interest-bearing accounts pledged to issuing banks.

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 accounting principles generally accepted in the United States of America. Generally accepted accounting principles 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 affect on amounts reported in our consolidated financial statements.

Workers’ Compensation

Our most significant long-term obligation is the obligation to provide workers’ compensation benefits. We are liable under various state statutes for providing workers’ compensation benefits. To fulfill these obligations, we have used self-insurance programs with varying excess insurance levels, and, since June 7, 2002, a high-deductible, fully insured program. The high-deductible, fully insured program is comparable to a self-insured program where the excess insurance threshold equals the deductible level.

We accrue for the present value of certain workers’ compensation obligations as calculated 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 5.25% and 5.5% at December 31, 2004 and December 31, 2003, respectively. 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 5.25% to 4.25%, all other things being equal, the present value of our workers’ compensation obligation would increase by approximately $3.5 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, 2004 was $50.3 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 these benefits through self-insurance programs and, for those claims incurred with last exposure after June 6, 2002, a high-deductible, fully insured program.

An independent actuary has calculated the estimated pneumoconiosis liability based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents and interest rates. 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 5.25% and 5.5% at December 31, 2004 and December 31, 2003, respectively. 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 5.25% to 4.25%, all other things being equal, the present value of our black lung obligation would increase by approximately $3.3 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, 2004 was $25.9 million.

Defined Benefit Pension

The estimated cost and benefits of our non-contributory defined benefit pension plans are determined by independent actuaries, who, with our review and approval, use various actuarial assumptions, including discount rate, future rate of increase in compensation levels 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. At December 31, 2004, the discount rate used to determine the obligation was 5.5%, compared to the discount rate used at December 31, 2003 of 6.0%. 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 5.5% to 4.5%, all other things being equal, the present value of our pension liability would increase by approximately $11.0 million. The rate of increase in compensation levels is determined based upon our long-term plans for such increases. The rate of increase in compensation levels used was 4.0% for the years ended December 31, 2004 and December 31, 2003, respectively. 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 in each period was 8.0% for each of the years ended December 31, 2004 and 2003. Significant changes to these rates would introduce substantial volatility to our pension expense.

Reclamation and Mine Closure Obligation

The SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of underground mining. Our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering estimates related to these requirements. Statement No. 143 requires that asset retirement obligations be 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, as necessary. 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 based on interest rates of bonds with maturities similar to the estimated future cash flow. 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 Statement No. 143, then the costs should be lower. If governmental regulations change, then the costs of reclamation will be impacted. Statement No. 143 recognizes that the recorded liability will 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 of cash paid to settle the obligation, a gain or loss upon settlement is included in earnings.

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 of timing of current legal or environmental matters will have a material impact on our financial condition, results of operations, or cash flows. See “Legal Proceedings” and the notes to the consolidated financial statements for further discussion on our contingencies.

Income Taxes

We account for income taxes in accordance with FASB Statement No. 109, Accounting for Income Taxes (“Statement No. 109”), which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. Statement No. 109 also requires that deferred tax assets 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, but not relied upon, 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.

At December 31, 2004, we had a net deferred tax liability of $34.6 million, which consisted of a total gross deferred tax asset of $107.4 million, a valuation allowance of approximately $61.1 million and a gross deferred tax liability of $80.9 million. The valuation allowance, which includes approximately $14.6 million that was recorded as part of our fresh start entries, provides a reserve for our net operating loss and alternate minimum tax credit carryforwards.

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 assembled by our staff and analyzed by Marshall Miller & Associates, Inc. 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 our annual calculation for potential impairment. For a further discussion of our coal reserves, see “Business – Reserves.”

Recent Accounting Pronouncements

On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No.123 (revised 2004), “Share-Based Payment” (FAS 123R), which requires all public companies to measure compensation cost in the income statement for all share-based payments (including employee stock options) at fair value for interim or annual periods beginning after June 15, 2005. The Company intends to adopt FAS 123R on July 1, 2005 using the modified-prospective method. The Company has not completed its assessment of the impact of the adoption of this statement on its financial statements. SFAS 123R also requires the benefits of tax deductions in excess of recognized compensation cost be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption.

Other Supplemental Information

Labor and Turnover

Recruiting, hiring, and retaining skilled mine production personnel has become challenging during the past several years. This is due to the aging of the industry workforce and the availability of other suitable positions for potential employees. The current strong market prices have also contributed to a higher level of turnover as competing coal mining companies attempt to increase production.

Based on average employment of production personnel, our gross turnover has been approximately 17.9% during 2004. Our net turnover during this period, after considering employees that have left and been rehired, is approximately 8.0%. We believe that our retention of employees is equal to, or better, than other coal mining companies in our operating area.

We are actively working to improve our results in this area through the retention of current employees, the recruiting of new employees and the return of previous employees to our company.

Sales Commitments

As of December 31, 2004, we had the following contractual commitments (including long term and short term contracts) to ship coal at a fixed and known price:


	2005				2006				2007
	Average Price Per Ton		Tons		Average Price Per Ton		Tons		Average Price Per Ton		Tons
Total Sales Commitments	$	41.33		8,532,800	$	40.21		4,694,000	$	38.37		1,630,000

Since December 31, 2004, we have not entered into any additional long-term contracts for 2006 and 2007.

Project Development

We undertake projects to add production, replace production, improve productivity, improve efficiency, and add reserves. Currently, we have several projects underway:

Mine 15 - McCoy Elkhorn Coal Company

This project involves construction of a mine at our McCoy Elkhorn complex to access what we estimate to be approximately 14 million tons of controlled reserves in the Glamorgan, or Millard, seam. Included in the Mine 15 project are a slope and shaft along with related surface facilities and an upgrade to the adjacent Bevins Branch preparation plant. During 2004, capital expenditures for the Mine 15 project were $3.7 million. We expect the total budget cost for this project to increase modestly from the original budget of $22 million due to higher costs of steel and cement. Although the site development phase of the project fell well behind schedule due to adverse geology, the project remains on schedule to begin production during the fourth quarter of 2005, due to the pace at which the slope and shaft are being excavated. This excavation has progressed to the point that both the slope and the shaft have now reached the bottom of the coal seam. The fabrication and installation of the remaining mine infrastructure is expected to be completed before December 31, 2005. The mine is expected to have very limited production during the fourth quarter of 2005, before ramping up to full production levels during the first half of 2006. All of these milestones are within our expected development plans. Upon completion and after reaching full production levels, the mine is expected to produce approximately 1.5 million tons per year. Due to an ongoing review of all mine operations being conducted by our Chief Operating Officer and mine operations management, we are not able to provide guidance at this time as to replacement tonnage vs. incremental tonnage from Mine 15. We continue to negotiate with mineral owners to add additional contiguous reserves to the project.

Other Projects

In addition to Mine 15, we have identified several other projects in various stages of planning and development. These projects are estimated to cost approximately $8-10 million with the timing contingent upon our ability to access the necessary resources, including manpower, permits and equipment.

2005 Tonnage Guidance

We currently expect that coal shipments during 2005 will be between 9.1 and 9.5 million tons. This consists of company production of 8.2 to 8.5 million tons, coal from contract mining sources of 800,000 to 850,000 tons, and coal from purchased sources of 100,000 to 150,000 tons.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our $75 million Term Credit Facility has a fixed interest rate and is not sensitive to changes in the general level of interest rates. Our Senior Secured Credit Facility has floating interest rates based on LIBOR or the Base Rate as defined in the credit agreement. As of December 31, 2004, we had $20 million outstanding under the term component of the Senior Secured Credit Facility. We do not expect to 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 $0.2 million.

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 73% for the year ended December 31, 2004.

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

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Audited Financial Statements	Page
Report of Independent Registered Public Accounting Firm	61
Consolidated Balance Sheets as of December 31, 2004 (Successor) and December 31, 2003 (Predecessor)	62
Consolidated Statements of Operations for the eight months ended December 31, 2004 (Successor), the four months ended April 30, 2004 (Predecessor) and the years ended December 31, 2003 (Predecessor) and 2002 (Predecessor)	64
Consolidated Statements of Changes in Shareholders’ Equity (Deficit) and Comprehensive Income (Loss) for the eight months ended December 31, 2004 (Successor), the four months ended April 30, 2004 (Predecessor) and the years ended December 31, 2003 (Predecessor) and 2002 (Predecessor)	65
Consolidated Statements of Cash Flows for the eight months ended December 31, 2004 (Successor), the four months ended April 30, 2004 (Predecessor) and the years ended December 31, 2003 (Predecessor) and 2002 (Predecessor)	66
Notes to Consolidated Financial Statements	67

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, 2004 (Successor Company) and 2003 (Predecessor Company), and the related consolidated statements of operations, changes in shareholders' equity (deficit) and comprehensive income (loss), and cash flows for the eight months ended December 31, 2004 (Successor Company), the four months ended April 30, 2004, and the years ended December 31, 2003 and 2002 (Predecessor Company). These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the 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, 2004 (Successor Company) and 2003 (Predecessor Company), and the results of their operations and their cash flows for the eight months ended December 31, 2004 (Successor Company), the four months ended April 30, 2004, and the years ended December 31, 2003 and 2002 (Predecessor Company) in conformity with U.S. generally accepted accounting principles.

As described more fully in Notes 1 and 3 to the consolidated financial statements, the Company was reorganized under a plan of reorganization confirmed by the United States Bankruptcy Court for the Middle District of Tennessee, effective May 6, 2004. In connection with the Company's emergence from Chapter 11, all assets and liabilities were restated to their respective fair values in order to reflect the effects of fresh start accounting. As a result of the application of fresh start accounting, the consolidated financial statements of the Successor Company are presented on a different basis than those of the Predecessor Company and, therefore, are not comparable in all respects.

As discussed in Notes 1(f) and 9(d) to the consolidated financial statements, the Company changed its method of accounting for reclamation liabilities and its method of accounting for redeemable preferred stock in 2003.

/s/ KPMG LLP

Richmond, Virginia
March 25, 2005

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2004 and 2003

(in thousands, except share data)


	Successor		Predecessor
	December 31, 2004		December 31, 2003
Assets
Current assets:
Cash	$	3,879		4,890
Receivables:
Trade		23,871		17,631
Other		7,362		4,324

Total receivables		31,233		21,955

Inventories:
Coal		2,305		3,278
Materials and supplies		4,084		4,624

Total inventories		6,389		7,902

Prepaid royalties		4,358		8,417
Other current assets		6,337		4,742

Total current assets		52,196		47,906

Property, plant, and equipment, at cost:
Land		2,698		6,666
Mineral rights		162,577		216,336
Buildings, machinery and equipment		106,105		230,346
Mine development costs		5,729		11,208
Construction-in-progress		231		997

Total property, plant, and equipment		277,340		465,553
Less accumulated depreciation, depletion, and amortization		21,765		208,397

Property, plant and equipment, net		255,575		257,156
Restricted cash (note 1(c))		8,404		8,321
Other assets		11,651		4,906

Total assets	$	327,826		318,289

See accompanying notes to consolidated financial statements.

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2004 and 2003

(in thousands, except share data)


	Successor			Predecessor
	December 31, 2004			December 31, 2003
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Current maturities of long-term debt (note 5)	$	2,700			-
Current installments of obligations under capital leases		388			613
Accounts payable		15,116			18,566
Accrued salaries, wages, and employee benefits		2,093			2,275
Workers’ compensation benefits		12,090			9,000
Black lung benefits		2,600			2,200
Accrued taxes		3,530			3,449
Other current liabilities		3,633			2,794

Total current liabilities		42,150			38,897

Long-term debt, less current maturities (note 5)		92,300			-
Other liabilities:
Noncurrent portion of workers’ compensation benefits		38,223			41,782
Noncurrent portion of black lung benefits		23,341			11,508
Pension obligations		15,744			14,315
Asset retirement obligations		14,939			13,674
Obligations under capital leases, excluding current installments		637			1,457
Deferred income taxes		34,615			-
Other		292			662

Total other liabilities		127,791			83,398
Liabilities subject to compromise		-			319,595

Total liabilities		262,241			441,890

Shareholders’ equity (deficit):
Preferred Stock, $1.00 par value. Authorized 10,000,000 shares		-			-
Common stock, $.01 par value. Authorized 100,000,000 shares; (40,000shares as of December 31, 2003); issued and outstanding 14,715,694shares (16,890 shares as of December 31, 2003)		147			-
Paid-in-capital		71,784			226
Deferred stock-based compensation		(7,540	)		-
Retained earnings (accumulated deficit)		1,151			(107,989	)
Subscribed shares		-			(821	)
Accumulated other comprehensive income (loss)		43			(15,017	)

Total shareholders’ equity (deficit)		65,585			(123,601	)

Commitments and contingencies (note 14)
Total liabilities and shareholders’ equity (deficit)	$	327,826			318,289

See accompanying notes to consolidated financial statements.

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Consolidated Statements of Operations

(in thousands, except per share data)


	Successor			Predecessor			Predecessor			Predecessor
	Eight Months			Four Months			Year Ended			Year Ended
	Ended 12/31/04			Ended 04/30/04			12/31/2003			12/31/2002
Revenues	$	231,698			113,949			304,052			397,599
Cost of sales:
Cost of coal sold		190,926			89,294			278,939			344,222
Depreciation, depletion, and amortization		21,765			12,314			40,427			46,393

Total cost of sales		212,691			101,608			319,366			390,615

Gross profit (loss)		19,007			12,341			(15,314	)		6,984
Selling, general, and administrative expenses		11,412			5,023			19,835			19,994
Other operating expenses (note 15)		-			-			-			26,554

Total operating income (loss)		7,595			7,318			(35,149	)		(39,564	)

Interest expense		5,733			567			18,536			29,883
Interest income		(72	)		-			(144	)		(1,003	)
Miscellaneous income, net		(833	)		(331	)		(1,519	)		(1,222	)

Total other expense, net		4,828			236			16,873			27,658

Income (loss) before reorganization items and income tax expense		2,767			7,082			(52,022	)		(67,222	)
Reorganization items, net (note 16)		-			(100,907	)		7,630			-

Income (loss) before income taxes		2,767			107,989			(59,652	)		(67,222	)
Income tax expense (benefit)		791			-			(2,891	)		(8,125	)

Net income (loss) before cumulative effect of accounting change		1,976			107,989			(56,761	)		(59,097	)
Cumulative effect of accounting change (note 17)		-			-			(3,045	)		-

Net income (loss)		1,976			107,989			(59,806	)		(59,097	)
Preferred dividends (note 9(d))		-			-			(340	)		(680	)
Decrease in redemption amount of redeemable common stock (note 9(e))		-			-			-			8,798

Net income (loss) attributable to common shareholders	$	1,976			107,989			(60,146	)		(50,979	)

Earnings (loss) per common share (note 18)
Basic earnings (loss) per common share
Income (loss) before cumulative effect of accounting change	$	0.14			6,393.67			(3,380.78	)		(3,018.31	)
Cumulative effect of accounting change		-			-			(180.28	)		-

Net income (loss)	$	0.14			6,393.67			(3,561.06	)		(3,018.31	)

Shares used to calculate basic earnings (loss) per share		13,800			17			17			17

Diluted earnings (loss) per common share
Income (loss) before cumulative effect of accounting change	$	0.14			6,393.67			(3,380.78	)		(3,018.31	)
Cumulative effect of accounting change		-			-			(180.28	)		-

Net income (loss)	$	0.14			6,393.67			(3,561.06	)		(3,018.31	)

Shares used to calculate dilutive earnings (loss) per share		14,623			17			17			17

See accompanying notes to consolidated financial statements.

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Consolidated Statements of Changes in Shareholders’

Equity (Deficit) and Comprehensive Income (Loss)

Eight months ended December 31, 2004 (Successor), four months ended April 30, 2004 (Predecessor),

and years ended December 31, 2003 and 2002 (Predecessor)

(in thousands)


						Deferred stock-			Retained earnings						Accumulated other
	Common		Paid-in-			based			(accumulated			Subscribed			comprehensive
	stock		capital			Compensation			deficit)			shares			income (loss)			Total
Predecessor Company
Balances, December 31, 2001	$	-		226			-			3,137			(1,403	)		(10,995	)		(9,035	)
Net loss		-		-			-			(59,097	)		-			-			(59,097	)
Minimum pension liability adjustment		-		-			-			-			-			(7,546	)		(7,546	)
Change in fair value of cash flow hedges		-		-			-			-			-			(1,663	)		(1,663	)

Comprehensive loss		-		-			-			-			-			-			(68,306	)

Payments on subscribed shares		-		-			-			-			497			-			497
Preferred dividends		-		-			-			(680	)		-			-			(680	)
Change in redemption amount of redeemable common stock		-		-			-			8,797			-			-			8,797

Balances, December 31, 2002		-		226			-			(47,843	)		(906	)		(20,204	)		(68,727	)
Net loss		-		-			-			(59,806	)		-			-			(59,806	)
Minimum pension liability adjustment																(1,194	)		(1,194	)
Reclassification to interest expense, net of taxes of $2,890		-		-			-			-			-			6,381			6,381

Comprehensive loss																			(54,619	)

Forgiveness of receivable for subscribed shares		-		-			-			-			85			-			85
Preferred dividends		-		-			-			(340	)		-			-			(340	)

Balances, December 31, 2003		-		226			-			(107,989	)		(821	)		(15,017	)		(123,601	)
Net income		-		-			-			107,989			-			-			107,989
Minimum pension liability adjustment		-		-			-			-			-			(692	)		(692	)

Comprehensive income																			107,297

Application of fresh start accounting (note 3)
Cancellation of Predecessor common stock		-		(226	)		-			-			-			-			(226	)
Elimination of Predecessor accumulated other comprehensive loss and subscribed shares		-		-			-			-			821			15,709			16,530

Balances, April 30, 2004		-		-			-			-			-			-			-

Successor Company
Issuance of Successor common stock		138		63,153			-			-			-			-			63,291
Net income		-		-			-			1,976			-			-			1,976
Unrealized gain on marketable securities, net		-		-			-			-			-			43			43

Comprehensive Income																			2,019

Deferred compensation related to restricted stock awards		9		8,631			(8,640	)		-			-			-			-
Cost to register common stock		-		-			-			(825	)		-			-			(825	)
Amortization of deferred stock-based compensation		-		-			1,100			-			-			-			1,100

Balances, December 31, 2004	$	147		71,784			(7,540	)		1,151			-			43			65,585

See accompanying notes to consolidated financial statements.

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(in thousands, except share data)


	Successor			Predecessor			Predecessor			Predecessor
	Eight Months			Four Months			Year			Year
	Ended			Ended			Ended			Ended
	12/31/04			4/30/04			12/31/2003			12/31/2002
Cash flows from operating activities:
Net income (loss)	$	1,976			107,989			(59,806	)		(59,097	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, and amortization of property, plant, and equipment		21,765			12,314			40,692			46,664
Accretion of asset retirement obligations		807			397			1,128			-
Amortization of debt issue costs		275			-			-			5,750
Amortization of deferred stock-based compensation		1,100			-			-			-
Deferred income tax expense (benefit)		766			-			(2,891	)		(3,146	)
Gain (loss) on sale or disposal of property, plant, and equipment		(36	)		19			(23	)		18,881
Gain on sale of investment		-			-			(999	)		-
Provision for severance costs		-			-			-			2,879
Fresh start accounting adjustment		-			(111,533	)		-			-
Non-cash reorganization items		-			10,010			796			-
Cumulative effect of change in accounting principle		-			-			3,045			-
Realized loss on termination of interest rate swap agreement		-			-			9,272			-
Unrealized gain on interest rate swap		-			-			(949	)		111
Changes in operating assets and liabilities:
Receivables		4,604			(12,882	)		4,193			7,019
Inventories		6,619			(4,028	)		(233	)		2,226
Prepaid royalties and other current assets		3,093			(1,236	)		991			1,691
Other assets		(7,001	)		132			661			(656	)
Accounts payable		(11,177	)		(2,921	)		15,016			2,684
Accrued salaries, wages, and employee benefits		(2,408	)		1,429			(818	)		(1,169	)
Accrued taxes		(58	)		139			(651	)		(1,196	)
Other current liabilities		(404	)		1,535			6,574			3,880
Workers’ compensation benefits		(1,886	)		1,417			5,770			2,574
Black lung benefits		(830	)		(547	)		(630	)		(347	)
Pension obligations		(1,887	)		(609	)		2,906			451
Asset retirement obligation		(477	)		(108	)		(978	)		(164	)
Other liabilities		(743	)		(4	)		(33	)		(136	)

Net cash provided by operating activities		14,098			1,513			23,033			28,899

Cash flows from investing activities:
Additions to property, plant, and equipment		(25,811	)		(9,521	)		(20,116	)		(22,925	)
Proceeds from sale of property and equipment		4,123			86			179			-
Proceeds from sale of investment		-			-			2,000			-
(Increase) decrease in restricted cash		(56	)		(28	)		2,277			(10,597	)

Net cash used in investing activities		(21,744	)		(9,463	)		(15,660	)		(33,522	)

Cash flows from financing activities:
Proceeds from issuance of long-term debt		20,000			-			-			3,373
Proceeds from (repayments of) short-term borrowings		(6,400	)		6,400			(1,940	)		(74	)
Common stock registration costs		(825	)		-						-
Principal payments under capital lease obligations		(370	)		(165	)		(549	)		(449	)
Debt issuance costs		(2,181	)		(1,874	)		-			-
Proceeds from issuance of common stock and payments on subscribed shares		-			-			-			497

Net cash provided by (used in) financing activities		10,224			4,361			(2,489	)		3,347

Increase in cash		2,578			(3,589	)		4,884			(1,276	)
Cash at beginning of period		1,301			4,890			6			1,282

Cash at end of period	$	3,879			1,301			4,890			6

See accompanying notes to consolidated financial statements.

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)

(1) Summary of Significant Accounting Policies and Other Information

(a) Description of Business and Principles of Consolidation

The Company mines, processes and sells bituminous, low sulfur, steam- and industrial-grade coal through five operating subsidiaries located throughout Eastern Kentucky. Substantially all coal sales and accounts receivable 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.

(b) Bankruptcy and Restructuring

On March 25, 2003, James River Coal Company and subsidiaries (the Company) filed a voluntary petition for relief under Chapter 11 with the United States Bankruptcy Court for the Middle District of Tennessee. Under Chapter 11, certain claims against the Company in existence prior to the filing of the petition for relief were stayed while the Company continued business operations as Debtor-in-possession. These claims are reflected in the December 31, 2003 balance sheet as Liabilities Subject to Compromise.

On April 21, 2004 the United States Bankruptcy Court for the Middle District of Tennessee confirmed the Company’s Plan of Reorganization (the Plan). The Plan of Reorganization became effective May 6, 2004 (the Effective Date) which is the date on which the Company formally emerged from Chapter 11. As part of the Plan, the Company canceled the existing equity securities, extinguished approximately $266,000 in debt, accrued interest, and the terminated interest rate swap liability under existing credit facilities in exchange for a restructured term loan of $75,000, which is secured by a second lien on substantially all the Company’s assets, and 13,799,994 shares of new common stock, par value $0.01 per share, which were distributed on a pro-rata basis to the holders of the pre-petition credit facilities. Pursuant to the Plan, the Company’s unsecured creditors claims were discharged and terminated.

On the Effective Date, the Company entered into a new $50,000 loan and security agreement which is comprised of a $20,000 term loan and a $30,000 revolving credit facility (see Note 5). The Company borrowed $20,000 under the term loan component to make cash payments to satisfy certain claims, administrative expenses, and retire obligations under the debtor-in-possession credit facility required to be paid under the Plan. The remaining $30,000 revolving credit facility is available for the Company’s working capital requirements, general, and letter of credit needs, and is subject to customary borrowing conditions.

The Company’s accompanying consolidated financial statements for the four months ended April 20, 2004 and for the year ended December 31, 2003 have been prepared in accordance with the American Institute of Certified Public Accountants’ Statement of Position 90-7, Financial Reporting by Entities in Reorganization under the Bankruptcy Code (SOP 90-7), which provides guidance for financial reporting by entities that have filed petitions under Bankruptcy. As a result, all assets and liabilities were restated to reflect their respective fair values. Although the Effective Date of the Plan of Reorganization was May 6, 2004, the consummation of the Plan of Reorganization has been reflected as of April 30, 2004, the end of the Company’s most recent fiscal month prior to the Effective Date. The consolidated

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)

financial statements after emergence are those of a new reporting entity (the Successor) and are not comparable to the consolidated financial statements of the pre-emergence Company (the Predecessor). A black line has been drawn in the financial statements to distinguish Predecessor and Successor financial information. See notes 3, 6 and 16 for further discussion.

The historical consolidated financial statements for 2002 do not reflect the effects resulting from the Company filing Chapter 11. As such, the statements for 2002 do not reflect the results of implementing SOP 90-7.

(c) Restricted Cash

As of December 31, 2004 and 2003, $8,404 and $8,321, respectively, of the Company’s cash was restricted as to its use. Restrictions are imposed by the Company’s bank relating to a letter of credit issued to one of the Company’s insurers (see note 14).

(d) 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 and industry data. The Company has determined that no allowance is necessary for trade receivables as of December 31, 2004 and 2003. The Company does not have any off-balance sheet credit exposure related to its customers.

(e) 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. Coal is classified as inventory at the point and time that the coal is extracted and removed from the mine.

(f) Reclamation Costs

Effective January 1, 2003, the Company adopted Financial Accounting Standards Board (FASB) Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 requires that asset retirement obligations be 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, as necessary. 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 settle the liability, the obligation is paid, and to the extent there is a difference between the liability and the amount of cash paid, a gain or loss upon settlement is

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)

incurred. At December 31, 2004 and December 31, 2003, the Company had accrued $15,989 and $14,724, respectively, related to estimated mine reclamation costs.

The change in the reclamation obligation for the years ended December 31, 2004 and 2003 are as follows:


	12/31/2004			12/31/2003
Amount included in other current liabilities	$	1,050		$	1,405
Long term asset retirement obligations		13,674			6,319

Reclamation liability at beginning of year		14,724			7,724
Cumulative effect adjustment		—			6,849
Liabilities incurred in current period (Predecessor Company)		636			—
Accretion expense
Predecessor Company		398			1,128
Successor Company		806			—
Liabilities settled in current period
Predecessor Company		(131	)		(977	)
Successor Company		(454	)		—

Reclamation liability at end of year		15,979			14,724
Less amount included in other current liabilities		(1,040	)		(1,050	)

Total noncurrent liability	$	14,939		$	13,674

(g) 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. Amortization of mineral rights is provided by the units of production method over estimated total recoverable proven and probable reserves.

(h) Impairment of Long-Lived Assets

In accordance with Financial Accounting Standards Board (FASB) Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, long-lived assets, such as property, plant, and equipment, and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. 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

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)

Company did not recognize any impairment charges during the eight months ended December 31, 2004, the four months ended April 30, 2004 or the years ended December 31, 2003 and 2002.

(i) Mine Development Costs

Mine development costs are capitalized and amortized by the units of production method over estimated total recoverable proved and probable reserves.

(j) 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.

(k) 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 title 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.

(l) 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 bases 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 effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

(m) Accumulated Comprehensive Gain (Loss)

The accumulated other comprehensive loss at December 31, 2003 represents the aggregate minimum pension liability adjustment. The accumulated other comprehensive gain at December 31, 2004 represents the aggregate unrealized gain on marketable securities.

(n) Derivative Financial Instruments

The Company currently does not utilize any interest rate swaps, however, the Company has in the past utilized interest rate swaps to hedge the impact of changes in interest rates on its floating rate debt. Prior to January 1, 2003, the Company accounted for its interest rate swaps as cash flow hedges. Interest to be received or paid on the interest rate swaps was accrued monthly through March 2003 until the swap agreements were terminated (see note 5(e)).

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)

Under the terms of these interest rate swaps, the Company was the fixed rate payor and the floating rate receiver. The fair value of the interest rate swaps was recorded on the consolidated balance sheets with changes in the fair value included in other comprehensive loss. Prior to January 1, 2003, to the extent the hedge was not completely effective, the ineffective portion was charged or credited to interest expense in the consolidated statements of operations. The ineffective portion charged to interest expense during the year ended December 31, 2002 was approximately $111. The amounts recorded in other comprehensive loss were subsequently reclassified into interest expense as a yield adjustment in the same period in which the related interest expense on the underlying debt affected results of operations.

Subsequent to December 31, 2002, the Company did not make the required monthly interest payments on the floating rate debt and the future forecasted interest payments were no longer probable. Accordingly, the hedge designation for the related interest rate swaps was discontinued effective January 1, 2003. As a result, the balance in accumulated other comprehensive loss related to the swaps as of that date was recorded as interest expense in 2003. An unrealized gain of approximately $949 representing subsequent changes in the fair value of the swaps was credited to interest expense in 2003.

(o) Workers’ Compensation

The Company is liable for workers’ compensation benefits for traumatic injuries under state workers’ compensation laws in which it has operations. Subsequent to 2001, a portion of its workers’ compensation benefits are payable under a high-deductible, fully-insured workers’ compensation insurance policy. For claims incurred prior to 2002, the Company is self- insured, except for those claims incurred between 1979 and 1982, which are covered by a third party insurance company. Specific excess insurance with independent insurance carriers is in force to cover traumatic claims in excess of the self-insured limits.

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. To assist in the determination of this estimated liability, the Company utilizes the services of third party administrators who develop claim reserves from historical experience. These third parties provide information to independent actuaries, who after review and consultation with the Company with regards to actuarial assumptions, including the appropriate discount rate, prepare an evaluation of the estimated liabilities for workers’ compensation benefits.

(p) 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 for federal and state black lung claims through a self- insurance program. 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 relating to prior service for active employees projected to receive benefits.

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)

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. The Company amortizes unrecognized actuarial gains and losses 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.

(q) Health Claims

The 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 $1,144 and $1,013 as of December 31, 2004 and 2003, respectively, which is included in accrued salaries, wages, and employee benefits.

(r) Stock Plans

The Company accounts for stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. Accordingly, compensation cost for stock options granted to employees is measured as the excess, if any, of the quoted market price of the stock at the date of grant over the amount an employee must pay to acquire the stock. Compensation cost for stock appreciation rights and performance equity units is recorded based on the quoted market price of the Company’s stock at the end of the period. Stock-based compensation other than stock options is recorded to expense on a straight-line basis. The Company has implemented the disclosure-only provisions of FASB Statement No. 123 “Accounting for Stock-Based Compensation”. The Company has not recognized stock-based compensation expense related to stock options in any period as all options granted had an exercise price at least equal to the fair value of the underlying common stock on the date of the grant. The estimated fair value at grant dates for options granted during the eight months ended December 31, 2004 was less than $.01 per share. In performing the Statement No. 123 analysis for stock options, a risk free rate of 5% was assumed, expected volatility was zero, and no dividends were anticipated.

If the Company had followed the fair value method under FASB Statement No. 123 to account for stock based compensation cost for stock options, the amount of stock based compensation cost for stock options, net of related tax, which would have been recognized for each period and pro-forma net income for each period would have been as follows:

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)


	Eight Months December 31, 2004
Net Income, as reported	$	1,976
Add: Net stock-based employee compensation expense recorded for restricted and performance based stock grants		785
Deduct: Net stock-based employee compensation expense for restricted and performance based stock determined under Black-Scholes option pricing model		(479	)

Pro forma net income	$	2,282

Income per share:
Basic - as reported	$	0.14

Basic - pro forma	$	0.17

Diluted - as reported	$	0.14

Diluted - pro forma	$	0.16

(s) 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 accounting principles generally accepted in the United States of America. Significant estimates made by management include the valuation allowance for deferred tax assets, accrued reclamation and mine closure costs and amounts accrued related to the Company’s workers’ compensation, black lung, and health claim obligations. Actual results could differ from these estimates.

(3) Fresh Start Accounting

The Company implemented fresh start accounting and reporting in accordance with SOP 90-7 on April 30, 2004, the end of the Company’s most recent fiscal month prior to the Effective

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)

Date. Fresh start accounting requires that the reorganization value of the reorganized debtors be allocated to their assets in conformity with FASB Statement No. 141, Business Combinations, for transactions reported on the basis of the purchase method. The enterprise value (value of the net assets and liabilities excluding cash, debt, and capital leases) of the reorganized company was estimated to range from $145,000 to $165,000 based on a third-party valuation prepared in connection with the bankruptcy proceedings. For purposes of applying fresh start accounting, an enterprise value for the reorganized company of $155,000 was utilized.

The effects of the Plan and the application of fresh-start accounting on the Company’s pre-confirmation consolidated balance sheet include adjustments to record the gain on the debt extinguished under the plan and adjustments to record the assets of the Company at their estimated fair value and the liabilities of the Company at their estimated present values. The reorganization value was derived from the enterprise value for the reorganized company as follows:


Estimated enterprise value of the reorganized company	$	155,000
Borrowings under credit facility		(6,400	)
Capital leases assumed		(1,396	)
Cash balance excluded from enterprise value		1,301
Administrative claims payable excluded from enterprise value		(10,214	)

		138,291
Less: new secured debt issued to extinguish prepetition debt		75,000

Fair value of common shares issued to extinguish prepetition debt	$	63,291

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)


			Fresh Start Adjustments
Assets	Predecessor Company 4/30/04		Debt Extinguishment			Reorganization Adjustments			Successor Company 4/30/04
Cash	$	1,301		-			-			1,301
Receivables		35,838		-			-			35,838
Inventories		11,930		-			1,079	(2)		13,009
Prepaid royalties		9,932		-			(362	) (2)		9,570
Other current assets		4,463		-			(347	) (2)		4,116

Total current assets		63,464		-			370			63,834
Land and mineral rights		223,004		-			(57,567	) (2)		165,437
Buildings, machinery, and equipment		236,901		-			(155,050	) (2)		81,851
Mine development costs		12,984		-			(12,984	) (2)		-
Construction-in-progress		974		-			-			974

		473,863		-			(225,601	)		248,262
Less accumulated depreciation, depletion, and amortization		219,604		-			(219,604	) (2)		-

Net property, plant, and equipment		254,259		-			(5,997	)		248,262
Restricted cash		8,348		-			-			8,348
Other long-term assets		6,518		(3,110	) (1)		(734	) (2)		2,674

Total assets	$	332,589		(3,110	)		(6,361	)		323,118

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)


				Fresh Start Adjustments
Liabilities and Shareholders’ Equity (Deficit)	Predecessor Company 4/30/04			Debt Extinguishment			Reorganization Adjustments			Successor Company 4/30/04
Borrowings under DIP credit agreement	$	6,400			-			-			6,400
Current installments of obligations under capital leases		749			-			(272	) (3)		477
Accounts payable		26,293			-			-			26,293
Accrued salaries, wages and employee benefits		4,501			-			-			4,501
Workers’ compensation benefits		9,500			-			-			9,500
Black lung benefits		2,500			-			-			2,500
Accrued taxes		3,588			-			-			3,588
Other current liabilities		4,037			-			-			4,037

Total current liabilities		57,568			-			(272	)		57,296
Long term debt		-			75,000	(1)		-			75,000
Noncurrent portion of workers’ compensation benefits		42,699			-			-			42,699
Noncurrent portion of black lung benefits		10,661			-			13,610	(4)		24,271
Pension obligations		14,267			-			3,363	(5)		17,630
Asset retirement obligations		13,963			-			-			13,963
Obligations under capital leases, excluding current installments		1,159			-			(240	) (3)		919
Deferred income taxes		-			-			27,391	(6)		27,391
Other long term liabilities		658			-			-			658

Total other liabilities		83,407			-			44,124			127,531
Liabilities subject to compromise		319,451			(319,451	) (1)		-			-

Total liabilities		460,426			(244,451	)		43,852			259,827
Common stock		-			138	(1)		-			138
Paid-in-capital		226			63,153	(1)		(226	) (7)		63,153
Retained earnings (accumulated deficit)		(111,533	)		178,050	(1)		(66,517	) (7)		-
Subscribed shares		(821	)		-			821	(7)		-
Accumulated other comprehensive income (loss)		(15,709	)		-			15,709	(7)		-

Total shareholders’ equity (deficit)		(127,837	)		241,341			(50,213	)		63,291

Total liabilities and shareholders’ equity	$	332,589			(3,110	)		(6,361	)		323,118

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)

The following is a description of the fresh start adjustments for debt extinguishment and reorganization adjustments:

Extinguishment of Debt

(1) Liabilities subject to compromise that were extinguished in bankruptcy consist of:


Pre-petition bank loan agreement	$	207,807
Pre-petition senior note		37,953
Accrued and unpaid interest		12,234
Terminated interest rate swap		8,434

Total secured		266,428
Promissory notes		5,176
Redeemable preferred stock		8,500
Accounts payable and other		39,347

Total unsecured		53,023

Total liabilities subject to compromise	$	319,451

The Company issued new common shares, new secured debt, and transferred its interest in specified life insurance policies held in a rabbi trust to the creditors in full satisfaction of pre-petition claims. The gain on extinguishment of pre-petition claims is calculated as follows:


Liabilities subject to compromise	$	319,451
Less: Assets of rabbi trust transferred to creditors		(3,110	)
Less: New secured debt issued in exchange for pre-petition debt		(75,000	)
Less: Fair value of common shares issued		(63,291	)

Gain on extinguishment of pre-petition claims	$	178,050

Reorganization Adjustments


	(2)		In connection with the application of fresh start accounting, the Company made adjustments aggregating approximately $6,361 to record its identifiable assets at fair value as follows:


	Increase/(Decrease)
Coal inventories	$	1,079
Prepaid royalties		(362	)
Other current assets		(347	)
Land and mineral rights		(57,567	)
Buildings, machinery and equipment		(155,050	)
Mine development costs		(12,984	)
Less accumulated depreciation, depletion, and amortization		219,604
Other long-term assets		(734	)

Total fair value adjustments to identifiable assets	$	(6,361	)

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)


	(3)		Contractual terms of certain capital lease agreements were renegotiated during bankruptcy. Obligations under capital leases have been adjusted to reflect the revised terms.


	(4)		The liability for black lung benefits has been adjusted to reflect the total discounted benefit obligation.


	(5)		The pension liability has been adjusted to reflect the total discounted projected benefit obligation of the plan.


	(6)		Deferred income taxes have been adjusted to reflect differences in the book and tax basis of the revalued assets and liabilities of the Company after application of fresh start accounting.


	(7)		The equity of the predecessor company, including subscribed shares and accumulated other comprehensive loss, has been eliminated in fresh start accounting.

(4) Other Current Assets

Other current assets at December 31, 2004 and 2003 are as follows:


	2004		2003
Prepaid insurance	$	3,535	$	3,107
Income tax receivable		2,575		-
Other		227		1,635

	$	6,337	$	4,742

(5) Long Term Debt, DIP Financing, and Interest Expense

Long-term debt at December 31, 2004 is as follows:


	December 31, 2004
Senior secured credit facility:
Term loan component	$	20,000
Revolver component		-
Term credit facility		75,000

Total long-term debt		95,000
Less amounts classified as current		2,700

Total long-term debt, less current maturities	$	92,300

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
(in thousands, except share data)

Scheduled maturities of long-term debt are as follows:


Year ended December 31:
2005	$	2,700
2006		8,100
2007		9,600
2008		12,600
2009		16,500
Thereafter		45,500

Total Debt	$	95,000

(a) Senior Secured Credit Facility

Effective May 6, 2004, the Company closed a $50,000 senior secured credit facility with Wells Fargo Foothill, Inc. (the Senior Secured Credit Facility). This facility was used to repay outstanding amounts and replace letters of credit previously issued under the $20,000 debtor-in-possession facility as discussed in note 5(c), to pay expenses associated with the exit from bankruptcy and to provide liquidity for general corporate purposes. The Senior Secured Credit Facility is comprised of a $30,000 revolver component (the Revolver) and a $20,000 term component. The term loan was fully funded at closing. Borrowings under the Revolver bear interest at LIBOR + 2.5% or the Base Rate (as defined in the credit agreement) + 1.0%. Borrowings under the term component bear interest at LIBOR + 5.25% or the Base Rate + 3.85%. The Company’s interest rate was 7.53% at December 31, 2004. The term of the Senior Secured Credit Facility is five years. Principal payments on the term component of $900 per quarter commence on April 1, 2005 and continue through April 1, 2009, with the remaining principal balance due on May 6, 2009. Interest is payable in arrears, on the first day of each month on Base Rate borrowings while interest on LIBOR Rate borrowings is due on the last day of the LIBOR interest period. Advances under the Senior Secured Credit Facility are secured by a first priority lien on substantially all of the Company’s assets, and, except for the Term Credit Facility, the Company may not incur additional debt on the assets securing the Revolver. Advances under the Revolver may not exceed a borrowing base calculation derived as a percentage of eligible assets less outstanding letters of credit. Based on the Company’s eligible assets and letters of credit outstanding, the Company had no availability under the Revolver at December 31, 2004. The Senior Secured Credit Facility can be terminated with 90 days written notice by paying all outstanding principal and interest and making any prepayment premium payments due. The $30,000 Revolver has a prepayment premium of 2.5% of the total revolver commitment for the first year, declining to 2.0% for the second year, 1.5% for the third year and 0.5% for the fourth year. There is not a prepayment premium for the fifth year of the revolver component of the Senior Secured Credit Facility. The $20,000 term loan component has a prepayment premium of $200 (1.0%) if paid prior to April 30, 2007. There is no prepayment premium after April 30, 2007 for the term loan component. The Revolver has a commitment fee of .375% per annum on the unused portion reduced by outstanding letters of credit (note 14).

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

(b) Term Credit Facility

The Company also entered into a $75,000 term credit facility with the Company’s pre-petition secured lenders (the Term Credit Facility) in partial satisfaction of its prepetition obligations, pursuant to the Plan of Reorganization. The Term Credit Facility has a term of seven years, accrues interest at 9%, and is secured by a second priority lien on substantially all of the Company’s assets. Except for the Senior Secured Credit Facility, the Company may not incur additional debt on the assets securing the Term Credit Facility. In addition, the Company may not incur any unsecured debt (other than normal trade payables) and may not incur more than $5,000 of recourse debt (including the Senior Secured Credit Facility and the Term Credit Facility). There is no scheduled amortization of this facility for the first two years. The notes require repayments of $1,500 per quarter beginning June 30, 2006 and increasing to $2,500 per quarter beginning June 30, 2008. All remaining principal and interest is due May 6, 2011. Borrowings under the Term Credit Facility may be prepaid without penalty.

(c) Debtor-In-Possession Financing

On March 27, 2003, the Company entered into a Secured Super-Priority Debtor-In-Possession Revolving Credit Agreement (DIP Credit Agreement) with the lenders who are the parties to the Prepetition Credit Agreement. The DIP Credit Agreement provided, among other things, for a secured $20,000 revolving credit facility, a $5,000 swing loan facility and a $17,000 letter of credit facility. The combination of amounts drawn under the revolving credit, swing loan, and letter of credit facility could not exceed $20,000.

Amounts borrowed under the DIP Credit Agreement bore interest at a floating rate (based on the prime rate or the Federal Funds Rate), plus a margin of 2.5%. As security for the DIP Credit Agreement obligation the Company granted the lenders’ liens on all presently owned or hereafter acquired property and assets.

As of May 6, 2004, the Company had drawn $6,400 under the DIP Credit Agreement. There were no amounts outstanding under the DIP Credit Agreement as of December 31, 2003. There were $13,508 and $11,008 of letters of credit outstanding as of May 6, 2004 and December 31, 2003, respectively. The Company was charged a fee of 3% annually on letters of credits outstanding.

All outstanding amounts on the DIP Credit Agreement were repaid upon emergence from bankruptcy on May 6, 2004.

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

(d) Interest Expense and Other

During the eight months ended December 31, 2004, the Company paid $5,536 in interest.

The Senior Secured Credit Facility and the Term Credit Facility contain financial covenants including a fixed charge coverage, a minimum leverage, minimum consolidated tangible net worth, minimum consolidated total annualized EBITDDA (as defined in each of the credit facilities), and maximum annual limits on capital expenditures. The Company was in compliance with all of the financial covenants for the Senior Secured Credit Facility and the Term Credit Facility as of December 31, 2004. The Company’s debt covenants also prohibit payment of cash dividends.

(e) Prepetition Debt

Notes payable and debt at December 31, 2003 is as follows:


	2003
Bank Loan Agreement, revolving component	$	170,596
Bank Loan Agreement, term component		37,211
Senior Note, interest at 12.61%		37,953
Promissory note, interest at 5.32%		4,664
Promissory note, interest at 5.82%		512

Total notes payable and debt		250,936
Less amounts classified as liabilities subject to compromise (note 6)		250,936

Total long-term debt, less current maturities and debt in default	$	—

Until the date of filing of bankruptcy, the Company accrued interest. The Company determined that there was insufficient collateral to cover the interest portion of the scheduled payments on its prepetition debt obligation. As of the bankruptcy date the Company ceased accruing interest on the prepetition debt obligations. If such interest had continued to be accrued, interest expense for the four months ended April 30, 2004 and the year ended December 31, 2003 would have been approximately $7,639 and $16,270 higher than reported. During the four months ended April 30, 2004 and the years ended December 31, 2003 and 2002, the Company paid $273, $2,934 and $26,261, respectively, in interest.

At December 31, 2002, the Company was a party to interest rate swap agreements with a notional amount of $100,000, which required the Company to make fixed-rate interest payments in exchange for floating rate interest payments related to the Company’s Bank Loan Agreement. In 2003, the derivative instrument was terminated due to an event of default, and the balance due at the date of termination of approximately $8,434 is included in Liabilities Subject to Compromise as of December 31, 2003.

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

(6) Liabilities Subject to Compromise

At December 31, 2003 Liabilities Subject to Compromise due to the Chapter 11 filing consist of the following:


Prepetition Bank Loan Agreement	$	207,807
Prepetition Senior Note		37,953
Accrued and unpaid interest		12,234
Terminated interest rate swap		8,434

Total secured		266,428
Promissory notes		5,176
Redeemable preferred stock		8,500
Accounts payable and other		39,491

Total unsecured		53,167

Total liabilities subject to compromise	$	319,595

(7) Workers’ Compensation Benefits

As of December 31, 2004 and 2003, workers’ compensation benefit obligation consisted of the following:


	2004		2003
Workers’ compensation benefits	$	50,313	$	50,782
Less current portion		12,090		9,000

Noncurrent portion of workers’ compensation	$	38,223	$	41,782

Actuarial assumptions used in the determination of the liability for the self-insured portion of workers’ compensation benefits included a discount rate of 5.25%, 5.5% and 6.75% at December 31, 2004, 2003 and 2002, respectively.

(8) Pneumoconiosis (Black Lung) Benefits

As of December 31, 2004 and 2003, black lung benefits obligation consisted of the following:


	2004		2003
Black lung benefits	$	25,941	$	13,708
Less current portion		2,600		2,200

Noncurrent portion of black lung benefits	$	23,341	$	11,508

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

A reconciliation of the changes in the black lung obligation is as follows:


	2004			2003
Beginning of the year black lung obligation	$	13,708		$	22,528
Fresh Start adjustment (note 3)		13,610			-
Service cost:
Predecessor Company		99			350
Successor Company		221			-
Interest cost:
Predecessor Company		254			1,210
Successor Company		566			-
Actuarial loss:
Predecessor Company		261			6,269
Successor Company		2,789			-
Benefit payments:
Predecessor Company		(1,613	)		(3,039	)
Successor Company		(1,165	)		-

End of year accumulated black lung obligation		28,730			27,318
Unamortized actuarial loss		(2,789	)		(13,610	)

Accrued black lung obligation	$	25,941		$	13,708

The actuarial assumptions used in the determination of black lung benefits included a discount rate of 5.25%, 5.5% and 6.75% at December 31, 2004, 2003 and 2002, respectively.

(9) Equity

(a) Preferred Stock and Shareholder Rights Agreement

The Company has authorized 10,000,000 shares of preferred stock, $1.00 par value, 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 Preferred Stock for issuance under a shareholder rights agreement (the “Rights Agreement”)

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”) have acquired or announced the intention to acquire 15% or more of the Company’s outstanding common stock.

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

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

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.

(b) 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 1,650,000, and no more than 1,000,000 of the shares reserved under the Plan may be granted in the form of incentive stock options.

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, 2004, 464,300 shares were available under the Plan for future awards.

Restricted Stock Awards

Pursuant to the Plan certain employees and directors have been awarded restricted common stock with such shares vesting over three or five years, respectively, or earlier under certain conditions. The related expense is amortized over the vesting period. Restricted shares subject to continuing vesting requirements are included in diluted shares outstanding. For the eight months ended December 31, 2004, the Company recognized $538 in compensation expense related to these shares.

Performance Stock Awards

Performance stock awards have been made to certain employees pursuant to the Plan. The number of shares of common stock to be received under these awards by such employees at the end of the performance period will depend on the attainment of performance objectives based on achieving certain financial results and the successful development of a new mine. The expected cost of these shares is reflected in income over the performance period. For the eight months ended December 31, 2004, the Company recorded $562 in compensation expense related to these shares. Since performance-based unvested stock is contingent upon satisfying conditions, those unvested shares are considered to be contingently issuable shares and are not included in the computation of diluted earnings per share.

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

Stock Options Awards

There were 270,000 stock options granted during the eight months ended December 31, 2004. The following table summarizes information about the stock options outstanding at December 31, 2004.


					Weighted
					Average
			Weighted		Remaining
Range of	Outstanding		Average		Contractual Life
Exercise Price	Options		Exercise Price		(Years)
$10.80		150,000	$	10.80		4.3
$15.00-$17.50		120,000	$	16.70		3.8

$10.80-$17.50		270,000	$	13.41		4.1

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


		Performance Stock			Restricted Stock					Stock Options
			Estimated					Estimated				Weighted
	Number of		Fair Value		Number of			Fair Value		Number of		Average
	Shares		at Issue		Shares			at Issue		Shares		Exercise Price
Outstanding at April 30, 2004		-	$	-		-		$	-		-	$	-
Granted		100,000		4.59		839,000			4.59		270,000		13.41
Vested/Exercised		-		-		-			-		-		-
Canceled		-		-		(23,300	)		4.59		-		-

December 31, 2004		100,000	$	4.59		815,700		$	4.59		270,000	$	13.41

(c) Stock Split

On September 30, 2004, the Board of Directors approved a two-for-one stock split of the Company’s common stock. The capital stock accounts and all share and earnings per share data, in this report give effect to the stock split, applied retroactively, to all periods presented for the Successor Company.

(d) Redeemable Preferred Stock (Predecessor Company)

As of December 31, 2003, the Company had 8,500 shares of Class C, nonvoting, mandatorily redeemable preferred stock outstanding. The preferred shares had a par value of $1,000 per share and a dividend rate of 8%. The preferred stock outstanding was included in Liabilities Subject to Compromise at December 31, 2003.

On July 1, 2003, the Company adopted Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which required that dividends on redeemable preferred stock be reported as a financing cost in our consolidated statements of operations. Accordingly, preferred dividends of $227 for the four months

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

ended April 30, 2004 and $340 for the year ended December 31, 2003, are included in interest expense in the consolidated statements of operations. Prior to the adoption of Statement No. 150, preferred dividends are shown separately as preferred dividends in the consolidated statements of operations.

The preferred stock was cancelled on May 6, 2004 in accordance with the terms of the Plan of Reorganization.

(e) Redeemable Common Stock (Predecessor Company)

The Company had a put/call arrangement with a group of shareholders that owned 6,344 shares of the Company’s common stock at December 31, 2001. This arrangement gave these shareholders the right to require the Company to repurchase the shares for an amount per share as set forth in the underlying agreements. This put/call agreement was terminated in 2002. Changes in the redemption amount were included in net loss attributable to common shareholders.

(10) Income Taxes

Income tax expense (benefit) consists of:


	Eight months Ended		Four Months Ended		Year Ended
	12/31/2004		4/30/2004		2003			2002
Current:
Federal	$	25		-		-			(4,980	)
State		-		-		-			-

		25		-		-			(4,980	)
Deferred:
Federal		692		-		(2,528	)		(3,017	)
State		74		-		(363	)		(128	)

		766		-		(2,891	)		(3,145	)

	$	791		-		(2,891	)		(8,125	)

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:

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)


	Eight months Ended			Four Months Ended			Year Ended
	12/31/2004			4/30/2004			2003			2002

Federal income taxes at statutory rates		34.0	%		34.0	%		(34.0	)%		(34.0	)%
Percentage depletion		(42.0	)		(2.2	)		(0.5	)		(1.6	)
Other permanent items		12.3			-			-			-
Amortization of coal properties not deductable		-			-			0.8			0.9
Non-Taxable gain on debt discharge		-			(35.1	)		-			-
Non-deductable reorganization costs		-			3.3			-			-
Change in valuation allowance		23.8			-			28.5			21.2
State income taxes, net of federal		1.8			-			(0.4	)		(0.1	)
Other, net		(1.3	)		-			1.0			1.5

		28.6	%		-	%		(4.6	)%		(12.1	)%

As discussed in note 1(b), the Company emerged from Chapter 11 bankruptcy on May 6, 2004. Under provisions of certain federal and state income tax laws, emergence from bankruptcy will have the effect of substantially reducing the Company’s ability to utilize the net operating loss carryforwards during 2004 and eliminates most, if not all, future benefit associated with the net operating loss carryforwards and the alternative minimum tax credit carryforwards for 2005 and subsequent years. The income tax attributes of other assets may also be reduced. To the extent asset basis is reduced for tax purposes, depreciation, and amortization of assets will also be reduced and, as a result, a gain may be recognized (and, therefore more tax imposed) in conjunction with the disposition of such assets. The Company must generally reduce its tax attributes, such as NOLs, tax credits, capital loss carryforwards, and tax basis in its assets, by any cancellation of indebtedness (COI) income realized. This reduction is effective January 1, 2005.

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2004 and 2003 are presented below:


	2004			2003
Deferred tax assets:
Accruals for financial reporting purposes, principally workers’ compensation and black lung obligations	$	46,279		$	34,340
Alternative minimum tax credit carryforwards		5,450			5,425
Net operating loss carryforwards		55,631			56,213
Accumulated comprehensive income		26			7,162

Total gross deferred tax assets		107,386			103,140
Less valuation allowance		61,081			45,859

Net deferred tax asset		46,305			57,281

Deferred tax liabilities - property, plant and equipment, principally due to differences in depreciation, depletion and amortization		80,920			57,281

Net deferred tax asset (liability)	$	(34,615	)	$	-

At December 31, 2004, the Company has consolidated net operating loss carryforwards (NOLs) for federal income tax purposes of approximately $136,000, consolidated Kentucky net operating loss

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

carryforwards of approximately $97,000 and a separate company limited federal net operating loss of approximately $13,000 which was obtained via a 1998 acquisition. These net operating loss carryforwards generate a combined federal and state tax benefit of approximately $55,600. In addition, the Company has alternative minimum tax credit carryforwards of approximately $5,450. The Company has fully reserved its NOLs and alternative minimum tax credits.

At December 31, 2004, the Company had a $61,081 valuation allowance recorded for the portion of the deferred tax assets that are not anticipated to be realizable in the future. The tax valuation allowance includes $14,600 recorded due to the impact of the Fresh Start Accounting Entries. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon availability of the deferred tax assets and the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment.

In addition to the $27,391 increase in the deferred tax liability that was originally recorded in connection with the fresh start accounting adjustment (see note 3), the Company recorded an additional increase in the deferred tax liability of $6,458 to adjust the fair values assigned to certain assets and liabilities for purposes of applying fresh start accounting.

During the years ended December 31, 2003 and 2002, the Company received income tax refunds of $4,980 and $5,677 and made no income tax payments. The Company made income tax payments of $2,600 and $0 for the eight months ended December 31, 2004 and the four months ended April 30, 2004, respectively.

(11) Employee Benefit Plans

(a) Defined Benefit Pension Plan

Substantially all employees of the Company who meet certain length of service requirements are covered by a qualified noncontributory 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 cash and cash equivalents, corporate and government bonds, 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 8.0% over a full market cycle, approximately 5 to 7 years. Diversification of assets is employed to reduce risk. The 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

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

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 considered 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 8.0% long-term rate of return on assets assumption for the year ended December 31, 2004.

The fair value of the major categories of qualified defined benefit pension plan assets includes the following:


	2004						2003
	Amount		Percentage			Amount		Percentage
Equity securities	$	24,859		67.7	%	$	19,732		66.4	%
Debt securities		10,689		29.1	%		9,836		33.1	%
Other (includes cash and cash equivalents)		1,195		3.2	%		149		0.5	%

		36,743		100.0	%		29,717		100.0	%

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

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, 2004 and 2003:


	2004			2003
Change in benefit obligation:
Benefit obligation at beginning of year	$	48,522		$	41,013
Service cost		1,834			1,764
Interest cost		2,924			2,707
Actuarial loss		7,207			4,985
Benefits paid		(1,851	)		(1,947	)

Benefit obligation at end of year		58,636			48,522

Change in plan assets:
Fair value of plan assets at beginning of year		29,717			23,718
Actual return on plan assets		3,590			4,333
Employer contributions		5,287			3,613
Benefits paid		(1,851	)		(1,947	)

Fair value of plan assets at end of year		36,743			29,717

Reconciliation of funded status:
Funded status		(21,893	)		(18,805	)
Unrecognized actuarial loss		6,149			23,348
Unrecognized prior service cost		-			390

Net amount recognized		(15,744	)		4,933

Amounts recognized in the consolidated balance sheets consist of:
Accrued benefit liability		(15,744	)		(14,315	)
Intangible asset		-			390
Accumulated other comprehensive loss		-			18,858

Net amount recognized		(15,744	)		4,933

The accumulated benefit obligation of the plan was $52,446 and $44,032 as of December 31, 2004 and 2003, respectively. Company contributions in 2005 are expected to be approximately $5,046.

During Fresh Start Accounting (note 3), the Company adjusted the previously unrecognized actuarial loss and the previously unrecognized prior service costs to $0.

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

The components of net periodic benefit cost and the benefits paid by period are as follows:


	Successor			Predecessor
	Eight Months			Four Months			Year			Year
	Ended 12/31/04			Ended 4/30/04			Ended 2003			Ended 2002

Service cost	$	1,223			611			1,764			1,583
Interest cost		1,959			965			2,707			2,444
Expected return on plan assets		(1,721	)		(811	)		(2,092	)		(2,122	)
Amortization of prior service cost		-			130			843			843
Recognized actuarial loss		-			340			1,178			670

Net periodic benefit cost	$	1,461			1,235			4,400			3,418

Benefits Paid	$	1,288			563			1,947

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

The weighted-average assumptions used in determining pension benefit obligations and pension expense are as follows:


	2004			2003			2002
Discount rate		5.50	%		6.00	%		6.75	%
Expected return on plan assets		8.00	%		8.00	%		8.50	%
Rate of compensation increase		4.00	%		4.00	%		4.00	%
Measurement date		October 1, 2004			October 1, 2003			October 1, 2002

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


Year ended December 31:
2005	$	1,989
2006		2,122
2007		1,782
2008		1,982
2009		2,170
Thereafter		14,485

(b) Savings and Profit Sharing Plan

All eligible employees of the Company may participate in the Company’s Savings and Profit Sharing Plan. Employees may contribute up to 15% of their salary to the Plan. The Company is required to match up to 3% of the employee’s salary and may also make an additional discretionary contribution. The Company recognized approximately $588, $253, $832 and $965 of expense relating to the Savings and Profit Sharing Plan for the eight months ended December 31, 2004, the four months ended April 30, 2004 and the years ended December 31, 2003 and 2002, respectively.

(c) Nonqualified Retirement Plan

The Company sponsored a nonqualified plan that provided retirement benefits to certain officers to supplement benefits not provided under the qualified plan. The Company owned insurance policies designed to fund benefits under the nonqualified plan, which were placed in a Rabbi Trust. The cash surrender value of the life insurance policies totaled $3,132 at December 31, 2003. The Plan was terminated March 25, 2003.

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

The following table sets forth the benefit obligation of the nonqualified retirement plan at December 31, 2003:


	2003
Benefit obligation at beginning of year	$	4,244
Service cost		14
Interest cost		95
Actuarial (gain) loss		2,423
Benefits paid		(28	)
Benefits forfeited		(2,370	)

Benefit obligation at end of year	$	4,378

The components of net periodic benefit cost for the years ended December 31, 2003 and 2002 are as follows:


	2003			2002
Service cost	$	14		$	158
Interest cost		95			312
Amortization of prior service cost		28			111
Recognized actuarial loss		6			55
Recognized benefits forfeited		(2,371	)		-
Effect of plan termination		4,388			-

Net periodic benefit cost		2,160			636

The weighted-average assumptions used in determining pension benefit obligations and pension expense are as follows:


	2003		2002
Discount rate	6.00	%	6.75	%
Rate of compensation increase	4.00	%	4.00	%
Measurement date	March 25, 2003		October 1, 2002

As part of the Company’s Plan of Reorganization the assets of the Rabbi Trust were transferred to the unsecured creditors Liquidating Trust to pay unsecured creditors’ claims. Prior to the termination of the Plan, the Company recognized a gain on benefits forfeited by a Company employee as part of a settlement agreement. The Company also recorded an expense of $4,388 on March 25, 2003 when the Plan was terminated. The benefit obligation for the nonqualified plan is included in Liabilities Subject to Compromise at December 31, 2003.

(12) Major Customers

In the eight months ended December 31, 2004, approximately 50% of revenues were from two customers, the largest of which represented 30% of revenues. In the four months ended April 30, 2004, approximately 54% of revenues were from two customers, the largest of which represented

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

31% of revenues. In 2003, approximately 73% of total revenues was from three customers, the largest of which represented 43% of revenues. In 2002, approximately 60% of revenues were from two customers, the largest of which represented 39% of coal revenues.

(13) Leases

The Company is obligated under capital leases covering certain machinery and equipment that expire at various dates during the next three years. At December 31, 2004 and 2003, the gross amount of machinery and equipment and related accumulated amortization recorded under capital leases were as follows:


	2004		2003
Machinery and equipment	$	1,367		3,189
Less accumulated amortization		539		1,111

	$	828		2,078

Amortization of assets held under capital leases is included with depreciation expense. Future minimum lease payments under noncancelable operating leases (with initial or remaining lease terms in excess of one year) and future minimum capital lease payments as of December 31, 2004 are:


	Capital		Operating
	leases		leases
Year ended December 31:
2005	$	459	$	605
2006		444		312
2007		239		240
2008		-		82

		1,142	$	1,239

Less amount representing interest (at 8.5%)		117

Present value of net minimum capital lease payments		1,025
Less current portion of obligations under capital leases		388

Obligations under capital leases, excluding current portion	$	637

The Company incurred rent expense on equipment and offices space of approximately $462, $278, $1,090, and $1,299 for the eight months ended December 31, 2004, the four months ended April 30, 2004 and the years ended December 31, 2003, and 2002, respectively.

JAMES RIVER COAL COMPANY

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(in thousands, except share data)

(14) Commitments and Contingencies

Future minimum royalty commitments under coal lease agreements at December 31, 2004 were as follows:


	Royalty
	commitments
Year ended December 31:
2005	$	14,705
2006		15,919
2007		15,314
2008		14,512
2009 and thereafter		81,282

	$	141,732

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, the Company generally assumed that minimum royalties on such leases will be paid for a period of ten years.

The Company has established irrevocable letters of credit totaling $29,960 as of December 31, 2004 to guarantee performance under certain contractual arrangements. The Company has letters of credit totaling $7,822 that are collateralized by restricted cash (see note 1(c)). The remaining letters of credit totaling $22,138 were issued under the Senior Secured Credit Facility and reduce the Company’s availability under the $30,000 revolver component. The Company is charged a fee of 2.5% annually on letters of credit outstanding.

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.

(15) Other Operating Expenses

For the year ended December 31, 2002, other operating expenses consist of the following:


Fixed asset disposals	$	9,111
Write off of mine development costs		7,664
Write off of prepaid royalties on abandoned properties		4,167
Write off of capitalized debt issuance costs for terminated transactions		4,062
Accrual for legal obligations		1,512
Other		38

	$	26,554

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

(16) Reorganization Items, Net

Reorganization items consist of the following:


	Predecessor

	Four Months Ended 4/30/04			Year Ended 12/31/03

Professional fees and administrative expenses	$	10,685			8,399
Forgiveness of receivable for subscribed shares, including accrued interest		-			94
Gain on settlements of obligations, net		(111,533	)		(798	)
Interest income		(59	)		(65	)

	$	(100,907	)		7,630

Cash paid for reorganization items totaled $8,083, $1,208 and $9,882 for the eight months ended December 31, 2004, the four months ended April 30, 2004 and for the year ended December 31, 2003, respectively. The Company also received $900 during 2003 in a settlement of potential litigation related to collecting the remaining proceeds from the sale of mining property and retained royalty obligations in 1998.

(17) Cumulative Effect of Accounting Change for Reclamation Liabilities

Effective January 1, 2003 the Company changed its method of accounting for reclamation liabilities in accordance with the provisions of Statement No. 143. As a result of adoption of Statement No. 143, the Company recognized an increase in total reclamation liability of $6,849. The Company recorded the related capitalized asset retirement costs by increasing property, plant and equipment, net of accumulated depreciation, by $3,804. The cumulative effect of the change on prior years resulted in a charge to operations of $3,045.

The pro forma effect of the application of Statement No. 143, as if Statement No. 143 had been applied retroactively, is presented below:


	2002

Net loss, as reported	$	(59,097)
Pro forma net loss		(59,778)

(18) 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, excluding restricted common stock subject to continuing vesting requirements. 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.

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

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

Successor

Predecessor

Company

Eight Months

Four Months

Twelve Months

Ended 12/31/04

Ended 4/30/04

Ended 12/31/03

Ended 12/31/02

Weighted average number of common shares outstanding:

Basic

13,799,994

16,890

Effect of dilutive instruments

822,626

Diluted

14,622,620

16,890

On May 6, 2004 the Company emerged from bankruptcy under a joint plan of reorganization. On that date the Company cancelled all existing equity securities and issued 13,799,994 shares of new common stock, which were distributed pro-rata to the pre-petition secured creditors.

(19) 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, 2004, except for long-term debt obligations, the carrying amounts of all financial instruments approximate their fair values due to their short maturities. The Company believes that the fair value of its outstanding debt approximates fair value at December 31, 2004 based on the timing of the issuance of these securities.

As a result of the Company’s financial difficulties and default on its debt obligations the Company was unable to estimate the fair value of its debt obligations at December 31, 2003.

(20) Subsequent Event

In March 2005, the Company signed a definitive agreement to acquire Triad Mining Inc. (“Triad”) for approximately $75 million, consisting of $64 million in cash and $11 million of Company common stock. Triad operates six surface mines and one underground mine in Southern Indiana.

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)

(21) Quarterly Information (Unaudited)

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


	Three Months Ended (1)
	March 31,			June 30,			September 30,		December 31,
	2004			2004			2004		2004
Total revenue	$	80,858			97,576			89,881		77,332
Gross profit (loss)		5,879			18,099			8,276		(906	)
Income (loss) from operations		2,318			14,071			3,434		(4,910	)
Reorganization items gain (loss), net		(1,557	)		102,465			-		-
Income (loss) before taxes		411			115,650			1,780		(7,085	)
Net income (loss)		411			113,923			1,399		(5,768	)
Income per share (Basic and Diluted)	$	24.36			N/A	(2)		0.10		(0.42	)


	Three Months Ended (1)
	March 31,			June 30,			September 30,			December 31,
	2003			2003			2003			2003
Total revenue	$	77,372			78,704			79,885			68,092
Gross loss		(6,375	)		(1,015	)		(950	)		(6,974	)
Loss from operations		(14,495	)		(5,003	)		(4,650	)		(11,000	)
Reorganization items gain (loss), net		-			(2,541	)		(2,471	)		(2,618	)
Loss before taxes		(31,022	)		(7,681	)		(7,414	)		(13,534	)
Loss before cumulative effect of accounting change		(28,131	)		(7,681	)		(7,414	)		(13,534	)
Net loss		(31,176	)		(7,681	)		(7,414	)		(13,534	)
Loss per share (Basis and Diluted):
Loss before cumulative effect of accounting change	$	(1,665.56	)		(464.85	)		(438.97	)		(801.33	)
Net loss	$	(1,845.84	)		(464.85	)		(438.97	)		(801.33	)


(1)		The quarters ended in 2003 and the quarter ended March 31, 2004, represent the results of the Predecessor Company. The quarter ended June 30, 2004 includes the Predecessor Company for one month (April 2004) and the Successor Company for two months. The quarters ended September 30, 2004 and December 31, 2004 represent the results of the Successor Company. As discussed in Note 1, the consolidated financial statements of the Company after emergence from bankruptcy are those of a new reporting entity (the Successor) and are not comparable to the financial statements of the pre-emergence Company (the Predecessor).

JAMES RIVER COAL COMPANY
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(in thousands, except share data)


(2)		Information for the net income per share for the two months ended June 30, 2004 (Successor) and the one month ended April 30, 2004 (Predecessor) follows:


	Two Months		One Month
	Ended		Ended
	June 30, 2004		April 30, 2004
Total revenue	$	64,485		33,091
Gross profit (loss)		11,637		6,462
Income from operations		9,071		5,000
Reorganization items gain (loss), net		-		102,465
Income before taxes		8,072		107,578
Net income		6,345		107,578
Basic Earnings Per Share		0.46		6,369.32
Diluted Earning Per Share		0.43		6,369.32

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the fiscal year covered by this Form 10-K, we evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Accounting Officer, the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Accounting Officer concluded that our disclosure controls and procedures are effective as of the end of such fiscal quarter. Disclosure controls and procedures are controls and procedures that are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. During the fiscal year covered by this Form 10-K, we made the changes as described below in our internal controls 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 generally accepted accounting principles.

Changes in Internal Controls Over Financial Reporting

In August of 2004, the Audit Committee was advised by our independent audit firm that they had identified material weaknesses in our internal controls. First, the auditors identified a material weakness related to our controls around the data provided to our actuaries that was used in the actuarial valuation of our workers’ compensation and black lung benefit obligations. This material weakness led to a restatement of our 2002 and 2001 financial statements. Second, the auditors identified a material weakness related to the lack of controls over our year-end financial closing process and our ability to produce accurate consolidated financial statements. This weakness resulted in a significant number of audit adjustments under generally accepted accounting principles that materially changed our preliminary 2003 consolidated financial statements. Our independent auditors also identified a need to add to the staff and strengthen the overall skills of our accounting department.

We have taken the following steps to address these findings:


		•		During 2004 we hired a new Vice President of Risk Management who helped us ensure that the actuarial data provided to our actuary in connection with our 2004 consolidated financial statements was accurate. The new Vice President of Risk Management is also ensuring that the controls that we have in place will be adequate to continue to provide accurate data to the actuaries.


		•		In addition to the hiring of a new Vice President and Chief Accounting Officer in late 2003, we have also hired other experienced accounting personnel during 2004 to ensure the accuracy of our accounting entries and closing process. These individuals were involved with the closing of our 2004 consolidated financial statements. The addition of these new accounting personnel allowed the Company to strengthen our controls over financial reporting and improve analysis of financial information.

We believe that the corrective steps described above have addressed the material weaknesses identified by our independent auditor firm in connection with their audit of our 2003 consolidated financial statements. During the audit of our 2004 consolidated financial statements, our independent auditors did not identify any material weaknesses; however, their audit was not designed for the purpose of forming an opinion on the assessment or effectiveness of our internal controls over financial reporting. The scope of our auditors’ consideration of our internal control over financial reporting in connection with their audit of our 2004 consolidated financial statements is not as extensive as the procedures that will be performed by them in connection with their report on management’s

100

assessment and effectiveness over internal control over financial reporting as of December 31, 2005, as required by Section 404 of the Sarbanes-Oxley Act. As a result, we cannot assure you that we or they will not identify additional deficiencies, significant deficiencies or material weaknesses.

Beginning with our annual report for the year ending December 31, 2005, Section 404 of the Sarbanes-Oxley Act of 2002, or Section 404, will require us to include an internal control report of management with our annual report on Form 10-K. That report must include management’s assessment of the effectiveness of our internal control over financial reporting as of the end of the fiscal year and will also include our independent auditors’ evaluation of management’s assessment and the effectiveness of our internal control over financial reporting. We cannot assure you that we will be able to complete the work necessary for our management to issue its management report in a timely manner, or that we will be able to complete any work required for our management to be able to conclude that our internal control over financial reporting is effective. If we fail to timely remedy any deficiencies, significant deficiencies or additional material weaknesses that we or our auditors may identify, we may be unable to accurately report our financial results, detect fraud or comply with the requirements of Section 404. In addition, we can give no assurance that our independent auditors will agree with our management’s assessment or conclude that our internal control over financial reporting is effective.

ITEM 9B. OTHER INFORMATION

None.

101

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS 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 2005 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 2005 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

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 2005 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 2005 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 Certified Public Accountants” in the definitive Proxy Statement used in connection with the solicitation of proxies for the Company’s 2005 Annual Meeting of Shareholders, to be filed with the Commission, is hereby incorporated herein by reference.

102

PART IV

ITEM 15. EXHIBITS AND 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, 2004 (Successor) and December 31, 2003 (Predecessor)

Consolidated Statements of Operations for the eight months ended December 31, 2004 (Successor), the four months ended April 30, 2004 (Predecessor) and the years ended December 31, 2003 (Predecessor) and 2002 (Predecessor)

Consolidated Statements of Changes in Shareholders’ Equity (Deficit) and Comprehensive Income (Loss) for the eight months ended December 31, 2004 (Successor), the four months ended April 30, 2004 (Predecessor) and the years ended December 31, 2003 (Predecessor) and 2002 (Predecessor)

Consolidated Statements of Cash Flows for the eight months ended December 31, 2004 (Successor), the four months ended April 30, 2004 (Predecessor) and the years ended December 31, 2003 (Predecessor) and 2002 (Predecessor)

Notes to Consolidated Financial Statements

2. Financial Statement Schedules

None.

3. 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

	3.1#	Amended and Restated Articles of Incorporation of the Registrant, as Amended

	3.2#	Amended and Restated Bylaws of the Registrant

	4.1#	Specimen common stock certificate

103


Exhibit Number		Description
	4.2#	Rights Agreement between the Registrant and SunTrust Bank as Rights Agent, dated as of May 25, 2004

	10.1#	Registration Rights Agreement by and among the Registrant and the Shareholders identified therein, dated May 6, 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

	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

	10.4*#	Employment Agreement between the Registrant and Peter T. Socha, dated as of May 7, 2004

	10.5*#	2004 Equity Incentive Plan of the Registrant

	10.6#	Form of Indemnification Agreement between the Registrant and its officers and directors

	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

	10.8**#	Fuel Supply Agreement #141944 between South Carolina Public Service Authority and the Registrant, dated as of March 1, 2004

	21#	Subsidiaries of the Registrant

	23.1	Consent of Marshall Miller & Associates, Inc.

	23.2	Consent of KPMG LLP

	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.

	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.

	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.

	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.


*		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.

#		Filed in the Company’s Registration Statement on Form S-1, initially filed as of August 13, 2004, as amended.

104

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 31st day of March, 2005.


JAMES RIVER COAL COMPANY

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

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant in the capacities indicated on the 31st day of March, 2005.


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

/s/ Samuel M. Hopkins, II		Vice President and Chief Accounting Officer (principal financial officer and principal accounting officer)
Samuel M. Hopkins, II

/s/ Alan F. Crown		Director
Alan F. Crown

/s/ Leonard J. Kujawa		Director
Leonard J. Kujawa

/s/ Paul H. Vining		Director
Paul H. Vining

/s/ James F. Wilson		Director
James F. Wilson