Edgar Filing: International Coal Group, Inc.

frm10-k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2010

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

Commission file number: 001-32679

International Coal Group, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware		20-2641185
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

300 Corporate Centre Drive

Scott Depot, WV 25560

(Address of Principal Executive Offices—Zip Code)

(304) 760-2400

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:		Name on each exchange on which registered:
Common Stock, par value $0.01 per share		The New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes ¨ No x

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 ¨

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if an, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

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

Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨

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

Aggregate market value of common stock held by non-affiliates of the registrant as of June 30, 2010, the last business day of the registrant’s most recently completed second fiscal quarter, at a closing price of $3.85 per share as reported by the New York Stock Exchange, was $510,359,330.

Number of shares of common stock outstanding as of February 1, 2011 was 203,837,411.

DOCUMENTS INCORPORATED BY REFERENCE

Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2011 annual meeting of stockholders, which proxy statement will be filed on or about April 8, 2011.

INDEX TO ANNUAL REPORT

ON FORM 10-K

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Item 1.	BUSINESS	1
Item 1A.	RISK FACTORS	31
Item 1B.	UNRESOLVED STAFF COMMENTS	56
Item 2.	PROPERTIES	57
Item 3.	LEGAL PROCEEDINGS	63
Item 4.	(REMOVED AND RESERVED)	63
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	64
Item 6.	SELECTED FINANCIAL DATA	66
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	68
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	100
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	100
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	100
Item 9A.	CONTROLS AND PROCEDURES	100
Item 9B.	OTHER INFORMATION	103
Item 10.*	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	112
Item 11.*	EXECUTIVE COMPENSATION	112
Item 12.*	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	112
Item 13.*	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	112
Item 14.*	PRINCIPAL ACCOUNTING FEES AND SERVICES	112
Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	113

The information required by Items 10, 11, 12, 13 and 14, to the extent not included in this document, is incorporated herein by reference to the information included under the captions “Election of Directors,” “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” “Certain Relationships and Related Party Transactions,” “Audit Matters” and “ Executive Officers” in the registrant’s definitive proxy statement which is expected to be filed on or about April 8, 2011.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Statements in this Annual Report on Form 10-K that are not historical facts are forward-looking statements within the “safe harbor” provision of the Private Securities Litigation Reform Act of 1995 and may involve a number of risks and uncertainties. We have used the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project” and similar terms and phrases, including references to assumptions, in this report to identify forward-looking statements. These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to various risks, uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those matters expressed in or implied by these forward-looking statements. The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

•	market demand for coal, electricity and steel;

•	availability of qualified workers;

•	future economic or capital market conditions;

•	weather conditions or catastrophic weather-related damage;

•	our production capabilities;

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

•	a significant number of conversions of our convertible senior notes prior to maturity;

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

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

•	availability and costs of key supplies or commodities such as diesel fuel, steel, explosives and tires;

•	availability and costs of capital equipment;

•	prices of fuels which compete with or impact coal usage, such as oil and natural gas;

•	timing of reductions or increases in customer coal inventories;

•	long-term coal supply arrangements;

•	reductions and/or deferrals of purchases by major customers;

•	risks in or related to coal mining operations, including risks relating to third-party suppliers and carriers operating at our mines or complexes;

•	unexpected maintenance and equipment failure;

•	adoption by Appalachian states of EPA guidance regarding stringent water quality-based limitations in CWA Section 402 wastewater discharge permits and CWA Section 404 dredge and fill permits;

•	environmental, safety and other laws and regulations, including those directly affecting our coal mining and production, and those affecting our customers’ coal usage;

•	ability to obtain and maintain all necessary governmental permits and authorizations;

•	competition among coal and other energy producers in the United States and internationally;

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•	railroad, barge, trucking and other transportation availability, performance and costs;

•	employee benefits costs and labor relations issues;

•	replacement of our reserves;

•	our assumptions concerning economically recoverable coal reserve estimates;

•	availability and costs of credit, surety bonds and letters of credit;

•	title defects or loss of leasehold interests in our properties which could result in unanticipated costs or inability to mine these properties;

•	the impact of the mine explosion at a competitor’s mine on federal and state authorities’ decisions to enact laws and regulations that result in more frequent mine inspections, stricter enforcement practices and enhanced reporting requirements;

•	future legislation and changes in regulations or governmental policies or changes in interpretations or enforcement thereof, including with respect to safety enhancements and environmental initiatives relating to global warming and climate change;

•	impairment of the value of our long-lived and deferred tax assets;

•	our liquidity, including our ability to adhere to financial covenants related to our borrowing arrangements;

•	adequacy and sufficiency of our internal controls; and

•	legal and administrative proceedings, settlements, investigations and claims, including those related to citations and orders issued by regulatory authorities, and the availability of related insurance coverage.

You should keep in mind that any forward-looking statements made by us in this Annual Report on Form 10-K or elsewhere speaks only as of the date on which the statements were made. New risks and uncertainties arise from time to time, and it is impossible for us to predict these events or how they may affect us or anticipated results. We have no duty to, and do not intend to, update or revise the forward-looking statements in this report after the date of this report, except as may be required by law. In light of these risks and uncertainties, you should keep in mind that any forward-looking statement made in this report might not occur.

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PART I

Introduction

This report is both our 2010 annual report to stockholders and our 2010 Annual Report on Form 10-K required under the federal securities laws.

Unless the context otherwise indicates, as used in this annual report, the terms “ICG,” “we,” “our,” “us” and similar terms refer to International Coal Group, Inc. and its consolidated subsidiaries.

The term “coal reserves” as used in this report means proven and probable reserves that are the part of a mineral deposit that can be economically and legally extracted or produced at the time of the reserve determination and the term “non-reserve coal deposits” in this report means a coal bearing body that has been sufficiently sampled and analyzed to assume continuity between sample points, but does not qualify as a commercially viable coal reserve as prescribed by Securities and Exchange Commission (“SEC”) rules until a final comprehensive SEC-prescribed evaluation is performed.

Because certain terms used in the coal industry may be unfamiliar to many investors, we have provided a “Glossary of Selected Terms” at the end of Item 1.

ITEM 1.

BUSINESS

Overview

We are a leading producer of coal in Northern and Central Appalachia with a broad range of mid- to high-Btu, low- to medium-sulfur steam and metallurgical coal. Our 12 Appalachian mining complexes are located in West Virginia, Kentucky, Virginia and Maryland. We also have a complementary mining complex of mid- to high-sulfur steam coal strategically located in the Illinois Basin. We market our coal to a diverse customer base of largely investment grade electric utilities, as well as domestic and international industrial customers. The high quality of our coal and the availability of multiple transportation options, including rail, truck and barge, throughout the Appalachian region enable us to participate in both the domestic and international coal markets. Coal markets, particularly Appalachian coal markets, have exhibited significant price volatility in recent years and may continue to do so due to a number of factors, including regulatory and other actions delaying the issuance of necessary permits, general economic conditions and customer usage of coal.

As of December 31, 2010, management estimates that we owned or controlled approximately 318 million tons of metallurgical quality coal reserves and approximately 770 million tons of steam coal reserves. Management’s estimates were developed considering an initial evaluation, as well as subsequent acquisitions, dispositions, depleted reserves, changes in available geological or mining data and other factors. Further, we own or control approximately 434 million tons of non-reserve coal deposits. Our assets are high-quality reserves strategically located in Appalachia and the Illinois Basin.

For the year ended December 31, 2010, we sold 16.3 million tons of coal, of which approximately 15.8 million tons were produced from our mining activities and approximately 0.5 million tons were purchased through brokered coal contracts (coal purchased from third parties for resale), at an average sale price of $66.38 and $53.85, respectively. Of the tons sold, 14.0 million tons were steam coal and 2.3 million tons were metallurgical coal. Our steam coal sales volume in 2010 consisted of mid- to high-quality, high-Btu (greater than 12,000 Btu/lb.), low- to medium-sulfur (1.5% or less) coal, which typically sells at a premium to lower quality, lower Btu, higher sulfur steam coal. Our three largest customers for the year ended December 31, 2010 were Progress Energy, Dominion Energy and Santee Cooper, and we derived approximately 34% of our revenues from sales to our five largest customers. We did not derive more than 10% of our revenues from any single customer in 2010.

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International Coal Group, Inc. was incorporated in Delaware in 2005. We have three reportable business segments, which are based on the coal regions in which we operate: (i) Central Appalachian, comprised of both surface and underground mines, (ii) Northern Appalachian, comprised of both surface and underground mines and (iii) Illinois Basin, representing one underground mine. Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States of America, as of and for the years ended December 31, 2010, 2009 and 2008 is included in Note 20 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

The Coal Industry

A major contributor to the world energy supply, coal represents over 27% of the world’s primary energy consumption according to the World Coal Institute. The primary use for coal is to fuel electric power generation. In 2009, coal-fired plants generated approximately 45% of the electricity produced in the United States, according to the Energy Information Administration (“EIA”), a statistical agency of the U.S. Department of Energy.

Coal Markets

Coal produced in the United States is used primarily by utilities to generate electricity, by the steel industry to produce coke for use in blast furnaces and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. Significant quantities of coal are also exported from both East and West Coast terminals. Coal used as fuel to generate electricity is commonly referred to as “steam coal” or “thermal coal.”

Coal has long been favored as an electricity generating fuel by regulated utilities because of its basic economic advantage. The largest cost component in electricity generation is fuel. According to the National Mining Association, coal is the most affordable source of power fuel per million Btu, historically averaging less than one-quarter the price of both petroleum and natural gas.

The other major market for coal is the steel industry. The type of coal used in steel making is referred to as “metallurgical coal” and is distinguished by special quality characteristics that include high carbon content, favorable coking characteristics and various other chemical attributes. Metallurgical coal is also generally higher in heat content (as measured in Btus), and therefore is also desirable to utilities as fuel for electricity generation. Consequently, metallurgical coal producers have the ongoing opportunity to select the market that provides maximum revenue and margins. The premium price offered by steel makers for the metallurgical quality attributes is typically higher than the price offered by utility coal buyers that value only the heat content.

Coal Mining Methods

We produce coal using two mining methods: underground room-and-pillar mining using continuous mining equipment and surface mining, which are explained as follows:

Underground Mining

Underground mines in the United States are typically operated using one of two different mining methods: room-and-pillar or longwall. In 2010, approximately 52% of our produced and processed coal volume came from underground mining operations using the room-and-pillar method with continuous mining equipment.

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Room-and-pillar mining. In room-and-pillar mining, rooms are cut into the coal seam leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of air. Continuous mining equipment is used to cut the coal from the mining face. Generally, openings are driven 20 feet wide and the pillars are rectangular in shape measuring 35-50 feet wide by 35-80 feet long. As mining advances, a grid-like pattern of entries and pillars is formed. Shuttle cars are used to transport coal from the continuous mining machine to the conveyor belt for transport to the surface. When mining advances to the end of a panel, 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 room-and-pillar method is often used to mine smaller coal blocks or thinner seams. It is also employed whenever subsidence is prohibited. Seam recovery ranges from 35% to 70%, with higher seam recovery rates applicable where retreat mining is combined with room-and-pillar mining.

Longwall mining. The other underground mining method commonly used in the United States is longwall mining. We do not currently have any longwall mining operations, but we expect to use this mining method in the development of our Tygart Valley property in Taylor County, West Virginia. In longwall mining, a rotating drum is trammed mechanically across the face of coal and a hydraulic system supports the roof of the mine while it advances through the coal. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface.

Surface Mining

Surface mining is used when coal is found close to the surface. In 2010, approximately 48% of our produced and processed coal volume came from surface mines. This method involves the removal of overburden (earth and rock covering the coal) with heavy earth moving equipment and explosives, extraction of the coal, replacing the overburden and topsoil to restore the land after the coal has been removed, reestablishing vegetation and frequently making other improvements that have local community and environmental benefit.

Overburden is typically removed at our mines using large, rubber-tired diesel loaders or hydraulic shovels. Coal is loaded into haul trucks for transportation to a preparation plant or unit train loadout facility. Seam recovery for surface mining is typically between 80% and 90%. Productivity depends on equipment, geological composition and mining ratios.

Area mining. Area mining is a surface mining method that removes all or part of the coal seam(s) in the upper fraction of a mountain, ridge or hill and the disturbed areas are subsequently restored to approximate original contour, or an approved alternate configuration.

Cross-ridge mining. Cross-ridge mining is a form of area mining that is employed where the terrain is dominated by long narrow ridges.

Contour mining. Contour mining is a surface mining method used in mountainous terrain that recovers coal along the outcrop of the coal seam by progressively excavating the overburden from above the coal seam to create a narrow bench, removing the coal and then replacing the overburden to restore the approximate original contour of the mined area.

Mountaintop removal mining. Mountaintop removal mining is a surface mining method that removes the entire coal seam(s) in an upper fraction of a mountain, ridge or hill and creates a level plateau or a gently rolling contour with no highwalls. This mining method is limited in application to sites where the approved post-mining land use requires relatively flat terrain. We do not currently have any mountaintop removal operations.

Highwall mining. Highwall mining is a surface mining method generally utilized in conjunction with contour surface mining. We do not currently have any highwall mining operations. At a highwall contour mining operation, a modified continuous miner with an attached beltline system cuts horizontal passages from the highwall into a seam. These passages can penetrate to a depth of up to 1,600 feet. This method typically can recover up to 65% of the reserve block penetrated.

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Coal Preparation and Blending

Depending on coal quality and customer requirements, raw coal may in some cases be shipped directly from the mine to the customer. Generally, raw coal from surface mines can be shipped in this manner. However, the quality of most underground raw coal does not allow it to be shipped directly to the customer without processing in a preparation plant. Preparation plants physically separate impurities from coal. This processing upgrades the quality and heating value of the coal by removing or reducing sulfur and ash-producing materials, but entails additional expense and results in some loss of coal. Coals of various sulfur and ash contents can be mixed, or “blended,” at a preparation plant or loading facility to meet the specific combustion and environmental needs of customers. Coal blending helps increase profitability by meeting the quality requirements of specific customer contracts, while maximizing revenue through optimal use of coal inventories.

Coal Characteristics

In general, coal of all geological composition is characterized by end use as either steam coal or metallurgical coal. Heat value and sulfur content are the most important variables in the profitable marketing and transportation of steam coal, while ash, sulfur and various coking characteristics are important variables in the profitable marketing and transportation of metallurgical coal. We mine, process, market and transport bituminous steam and metallurgical coal, characteristics of which are described below.

Heat Value

The heat value of coal is commonly measured in Btus per pound of coal. A Btu is the amount of heat needed to raise one pound of water one degree Fahrenheit. Coal found in the eastern and Midwestern regions of the United States tends to have a heat content ranging from 10,000 to 14,000 Btus per pound, as received. As received Btus per pound includes the weight of moisture in the coal on an as sold basis. Most coal found in the western United States ranges from 8,000 to 10,000 Btus per pound, as received.

Bituminous Coal

Bituminous coal is a relatively soft black coal with a heat content that ranges from 10,000 to 14,000 Btus per pound. This coal is located primarily in Appalachia, Arizona, Colorado, the Midwest and Utah, and is the type most commonly used for electricity generation in the United States. Bituminous coal is also used for industrial steam purposes by utility and industrial customers, and as metallurgical coal in steel production.

Sulfur Content

Sulfur content can vary from coal seam to coal seam, and sometimes within each seam. When coal is burned, it produces sulfur dioxide, the amount of which varies depending on the chemical composition and the concentration of sulfur in the coal. Compliance coal is coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btus and complies with the requirements of the Clean Air Act Acid Rain Program. Low-sulfur coal is coal which, when burned, emits approximately 1.6 pounds or less of sulfur dioxide per million Btus. Mid-sulfur coal is characterized as coal which, when burned, emits greater than 1.6 pounds of sulfur dioxide per million Btus, but less than 2.5 pounds of sulfur dioxide per million Btus. High-sulfur coal is generally characterized as coal which, when burned, emits greater than 2.5 pounds per million Btus.

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High-sulfur coal can be burned in electric utility plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by up to 99%. Plants without scrubbers can burn high-sulfur coal by blending it with lower sulfur coal or by purchasing emission allowances on the open market. Each emission allowance permits the user to emit a ton of sulfur dioxide. Additional scrubbing will provide new market opportunities for our medium- to high- sulfur coal. All new coal-fired electric utility generation plants built in the United States will use clean coal-burning technology.

Other Characteristics

Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from coal seam to coal seam. Ash content is an important characteristic of coal because it increases transportation costs and electric generating plants must handle and dispose of ash following combustion.

Moisture content of coal varies by the type of coal, the region where it is mined and the location of coal within a seam. In general, high moisture content decreases the heat value per pound of coal, thereby increasing the delivered cost per Btu. Moisture content in coal, as sold, can range from approximately 5% to 30% of the coal’s weight.

Operations

As of December 31, 2010, we operated a total of 13 underground and 10 surface coal mines located in West Virginia, Kentucky, Maryland, Virginia and Illinois. Approximately 52% of our 2010 production came from underground mines, and the remaining 48% of our production came from our surface mines. These mining facilities include 11 preparation plants, each of which receive, blend, process and ship coal that is produced from one or more of our 23 active mines. Our underground mines generally consist of one or more single or dual continuous miner sections, which are made up of the continuous miner, shuttle cars, roof bolters and various ancillary equipment. Our surface mines are a combination of area, contour and cross-ridge operations using truck/loader equipment fleets along with large production tractors. Most of our preparation plants are modern heavy media plants that generally have both coarse and fine coal cleaning circuits. We currently own most of the equipment utilized in our mining operations. We employ preventive maintenance and rebuild programs to ensure that our equipment is modern and well maintained. The mobile equipment utilized at our mining operations is replaced on an on-going basis with new, more efficient units based on equipment age and mechanical condition. Each year we endeavor to replace the oldest units, thereby maintaining productivity while minimizing capital expenditures.

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The following table provides summary information regarding our principal active operations as of December 31, 2010:

			Type and Number of Mines
Mining Complexes	Location	Preparation Plants	Under- ground	Surface	Total	Mining Method (1)	Transportation

Eastern	Cowen, WV	1	—	1	1	AM	Rail
Hazard	Hazard, KY	—	—	4	4	AM, CTR	Rail, Truck
Flint Ridge	Hazard, KY	1	1	—	1	R&P	Rail, Truck
Knott County	Kite, KY	1	2	—	2	R&P	Rail
Raven	Raven, KY	1	3	—	3	R&P	Rail
East Kentucky	Pike Co., KY	—	—	1	1	AM, CTR	Rail
Beckley	Eccles, WV	1	1	—	1	R&P	Rail
Vindex Energy Corporation	Garrett Co., MD	2	1	3	4	CRM, R&P	Rail, Truck
Patriot Mining Company	Monongalia Co., WV	—	—	1	1	AM	Barge, Rail, Truck
Wolf Run Mining Buckhannon Division	Upshur Co., WV	1	2	—	2	R&P	Rail, Truck
Powell Mountain	St. Charles, VA	1	1	—	1	R&P	Rail
Sentinel	Barbour Co., WV	1	1	—	1	R&P	Rail, Truck
Illinois	Williamsville, IL	1	1	—	1	R&P	Truck

(1)	AM = Area Mining; CRM = Cross-Ridge Mining; CTR = Contour Mining; R&P = Room-and-pillar

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The following table provides the last three years annual production and the average prices received for our coal for each of our mining complexes:

	2010			2009			2008
Mining Complexes	Tons Produced	Sales Realizations (1)		Tons Produced	Sales Realizations (1)		Tons Produced	Sales Realizations (1)
Eastern	1,690,006	$	66.90	2,500,707	$	66.92	3,234,517	$	55.36
Hazard	3,437,008	$	70.41	3,669,581	$	65.72	4,055,874	$	54.56
Flint Ridge	851,559	$	71.44	800,792	$	66.25	1,055,996	$	55.05
Knott County	416,316	$	63.04	518,095	$	64.84	948,445	$	52.57
Raven	747,844	$	67.77	728,487	$	66.81	664,265	$	54.45
East Kentucky	669,816	$	53.69	933,030	$	55.49	1,058,092	$	58.39
Beckley(2)	981,395	$	113.01	750,478	$	91.89	531,842	$	106.66
Vindex Energy Corporation	964,659	$	66.24	740,084	$	48.02	939,141	$	54.43
Patriot Mining Company	695,446	$	51.37	744,908	$	51.14	929,645	$	40.56
Wolf Run Mining Buckhannon Division	1,066,139	$	49.94	1,042,384	$	57.59	993,807	$	56.48
Powell Mountain(3)	234,019	$	102.60	203,110	$	106.45	100,322	$	132.17
Sentinel	1,293,989	$	92.32	1,367,597	$	57.42	1,007,425	$	60.73
Illinois	2,475,261	$	36.78	2,251,951	$	33.63	2,261,028	$	29.94
	15,523,457			16,251,204			17,780,399

(1)	Excludes freight and handling revenue.
(2)	Beckley was in development until the fall of 2008.
(3)	Powell Mountain was acquired in 2008.

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Northern and Central Appalachian Mining Operations

Below is a map showing the location and access to our coal properties in Northern and Central Appalachia as of December 31, 2010:

Our Northern and Central Appalachian mining facilities and reserves are strategically located across West Virginia, Kentucky, Maryland, Virginia and Ohio and are used to produce and ship coal to our customers located primarily in the eastern half of the United States.

Our mines in Central Appalachia produced 9.0 million tons of coal in 2010 and our mines in Northern Appalachia produced 4.0 million tons of coal in 2010. The quality of the produced coal was, on average, 12,316 Btu/lb., 1.35% sulfur and 12.19% ash by content. Shipments bound for electric utilities accounted for approximately 99% of the thermal coal shipped by these mines in 2010 compared to 92% of shipments in 2009. Within each mining complex, mines have been developed at strategic locations in proximity to our preparation plants and rail shipping facilities. The mines located in Central Appalachia ship the majority of their coal via the CSX railroad and, to a lesser extent, via the Norfolk Southern rail system. Some shipments may also be delivered by truck or barge, depending on the customer. Northern Appalachia shipments are primarily via CSX rail with some barge and truck to customer shipments.

As of December 31, 2010, these mines had 2,188 employees.

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Eastern

Eastern operates the Birch River surface mine, located 60 miles east of Charleston, near Cowen in Webster County, West Virginia. Birch River is extracting coal from the Freeport, Upper Kittanning, Middle Kittanning, Upper Clarion and Lower Clarion coal seams. Birch River controls an estimated 7.7 million tons of coal reserves, of which approximately 2.0 million tons are deep minable. Eastern’s first underground mine will be developed in 2011. Additional potential reserves, mineable by both surface and deep mining methods, have been identified in the immediate vicinity of the Birch River mine and exploration activities are currently being conducted in order to add those potential reserves to the reserve base.

The coal reserves are predominantly leased. The leases are retained by annual minimum payments and by tonnage-based royalty payments. Most of the leased reserves are held by five lessors. Most of the leases can be renewed until all mineable and merchantable coal has been exhausted. Overburden is removed by an excavator, front-end loaders, end dumps and bulldozers. Approximately one-third of the total coal sales are run-of-mine, while the other two-thirds are washed at Birch River’s preparation plant. Coal is transported by conveyor belt from the preparation plant to Birch River’s rail loadout, which is served by CSX via the A&O Railroad, a short-line carrier that is partially owned by CSX.

Hazard

Hazard currently operates four surface mines, a unit train loadout (Kentucky River Loading) and other support facilities in eastern Kentucky, near Hazard. Hazard’s four surface mines include East Mac & Nellie, Rowdy Gap, Bearville and Thunder Ridge. The coal from these mines is being extracted from the Hazard 10, Hazard 9, Hazard 8, Hazard 7 and Hazard 5A seams. Nearly all of the coal is marketed as a blend of run-of-mine product with the remainder being washed. Overburden is removed by front-end loaders, end dumps, bulldozers and cast blasting. East Mac & Nellie also utilizes a large capacity hydraulic shovel. Coal is transported by on-highway trucks from the mines to the Kentucky River Loading rail loadout, which is served by CSX. Some coal is direct shipped to the customer by truck from the mine pits.

We estimate that Hazard controls 75.5 million tons of coal reserves, including approximately 10.4 million tons of deep mineable reserves. Hazard also controls 10.3 million tons of coal that is classified as non-reserve coal deposits. Most of the property has been adequately explored, but additional core drilling will be conducted within specified locations to better define the reserves.

Approximately 63% of Hazard’s reserves are leased. Most of the leased reserves are held by seven lessors. In several cases, Hazard has multiple leases with each lessor. The leases are retained by annual minimum payments and by tonnage-based royalty payments. Most of the leases can be renewed until all mineable and merchantable coal has been exhausted.

Flint Ridge

Flint Ridge, located near Breathitt County, Kentucky, operates one underground mine and one preparation plant. The mine operates in the Hazard 8 seam.

Flint Ridge’s underground mine is a room-and-pillar operation, utilizing continuous miners and shuttle cars. All of the run-of-mine coal is processed at the Flint Ridge preparation plant. Since July 2005, it has been processing coal from the Hazard and Flint Ridge mining complexes.

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The majority of the processed coal is trucked to the Kentucky River Loading rail loadout. Some processed coal is trucked directly to the customer from the preparation facility.

We estimate that Flint Ridge controls 20.3 million tons of coal reserves, plus 0.1 million tons of non-reserve coal deposits. Approximately 97% of Flint Ridge’s reserves are leased, while 3% are owned in fee. The leases are retained by annual minimum payments and by tonnage-based royalty payments. Most of the leases can be renewed until all mineable and merchantable coal has been exhausted.

Knott County

Knott County operates two underground mines, the Supreme Energy preparation plant and rail loadout and other facilities necessary to support the mining operations near Kite, Kentucky. Knott County is producing coal from the Elkhorn 3 coal seam in the Classic and Kathleen mines. Mining of the Calvary mine was completed in 2010. Two additional properties are in the process of being permitted for underground mine development. We estimate Knott County controls 18.1 million tons of coal reserves. A significant portion of the property has been explored, but additional core drilling will be conducted within specified locations to better define the reserves.

Approximately 13% of Knott County’s reserves are owned in fee, while approximately 87% are leased. The leases are retained by annual minimum payments and by tonnage-based royalty payments. The leases typically can be renewed until all mineable and merchantable coal has been exhausted.

Knott County’s two underground mines are room-and-pillar operations, utilizing continuous miners and shuttle cars. The coal is processed at the Supreme Energy preparation plant. All of Knott County’s coal is transported by rail from loadouts served by CSX.

Raven

Raven, located in Knott County, Kentucky, operates three underground mines (Raven #1, Slones Branch and Lige Hollow) and the Raven preparation plant. Raven #1 and Slones Branch are producing coal from the Elkhorn 2 coal seam and Lige Hollow is producing coal from the Amburgy seam. Two additional properties are in the process of being permitted for underground mine development. We estimate Raven controls 19.5 million tons of coal reserves. Most of the property has been extensively explored, but additional core drilling will be conducted within specified locations to better define the reserves.

The Raven #1 and Slones Branch reserves are all leased from one lessor, Penn Virginia Resource Partners, L.P. Lige Hollow’s leased reserves are held by multiple lessors. The leases are retained by annual minimum payments and by tonnage-based royalty payments.

Raven’s three underground mines are room-and-pillar operations, utilizing continuous miners and shuttle cars. The coal is processed at the Raven preparation plant. Nearly all of Raven’s coal is transported by rail via CSX.

East Kentucky

East Kentucky is a surface mining operation located in Martin and Pike Counties, Kentucky, near the Tug Fork River. East Kentucky currently operates the Mt. Sterling surface mine and the Sandlick loadout. The loadout is serviced by Norfolk Southern railroad. Mining of the Peelpoplar surface mine was completed in 2010.

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Mt. Sterling is a surface mine that produces coal from the Taylor, Coalburg, Winifrede, Buffalo and Stockton coal seams. All of the coal is sold run-of-mine. We estimate that the Mt. Sterling mine controls 0.9 million tons of coal reserves, of which 84% are owned. No additional exploration is required. Overburden at the Mt. Sterling mine is removed by front-end loaders, end dumps, bulldozers and cast blasting. Coal from the pits is transported by truck to the Sandlick loadout. Leased reserves are retained by annual minimum payments and by tonnage-based royalty payments. Most of the leases can be renewed until all mineable and merchantable coal has been exhausted.

Beckley

The Beckley Pocahontas Mine, located near Beckley in Raleigh County, West Virginia, was placed into production in the fall of 2008 and accesses a 30.2 million-ton deep reserve of high quality low-volatile metallurgical coal in the Pocahontas No. 3 seam. Most of the 16,800 acre Beckley reserve is leased from three land companies: Western Pocahontas Properties, Crab Orchard Coal and Land Company and Beaver Coal Company.

Underground production is by means of the room-and-pillar method with continuous miners and shuttle cars. Coal produced from the Beckley operation is marketed to domestic steel producers and for export. Additionally, we have the ability to produce metallurgical coal by reprocessing a nearby coal refuse pile located at Eccles, West Virginia.

Powell Mountain

Acquired in 2008, Powell Mountain, located in Lee County, Virginia and Harlan County, Kentucky, currently operates the Darby mine, a room-and-pillar mine operating two sections with continuous miners and shuttle cars. The mine is operating in the Darby seam with all coal being trucked to the Mayflower preparation plant for processing. Coal is shipped by rail through the dual service rail loadout facility with rail service provided by both the Norfolk Southern and CSX railroads. Some purchased coal is brought into the facility for processing and blending. We plan to begin operation of the new Middle Splint mine in 2011.

Vindex Energy Corporation

Vindex Energy Corporation operates three surface mines: Carlos, Island and Jackson Mountain, located in Garrett and Allegany Counties, Maryland. The reserves at Vindex are leased from multiple landowners. All surface mines operated by Vindex Energy are truck-and-shovel/loader mining operations which extract coal from the Upper Freeport, Middle Kittanning, Pittsburgh, Little Pittsburgh and Redstone seams. In 2007, Vindex added the Cabin Run property and the Buffalo properties to its reserve base. The total surface mineable reserves at Vindex amount to approximately 10.4 million tons.

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Vindex also controls approximately 49.9 million tons of deep mineable reserves in the Bakerstown and Upper Freeport seams. These reserves are low-volatile metallurgical coals suitable for steel making. Vindex opened its first underground mine, the Bismarck Mine, in the Bakerstown reserves in 2010.

Most of the surface mine production is shipped directly to the customer as run-of-mine product; however, a portion of the surface production is targeted toward the low-volatile metallurgical market. The Bismarck deep mine coal is also processed for the metallurgical market. Any coal that must be washed is processed at our preparation plant located near Mount Storm, West Virginia, where the product is shipped to the customer by either truck or rail. A second preparation plant with rail access, the newly refurbished Dobbin Ridge preparation plant, began processing coal in January 2011.

Patriot Mining Company

Patriot Mining Company currently consists of the Guston Run surface mine, located near Morgantown in Monongalia County, West Virginia. The majority of the coal and surface is leased under renewable contracts with small annual minimum holding costs. Coal is extracted from the Waynesburg seam using dozers, loaders and trucks. As mining progresses, reserves are being acquired and permitted for future operations. The coal is shipped to the customer by rail, truck or barge using a loading facility which is located near Morgantown, West Virginia. Patriot Mining Company currently controls approximately 8.7 million tons of coal reserves, 100% of which are leased.

Buckhannon Division

Wolf Run Mining Company’s Buckhannon Division currently consists of two active underground mines: the Imperial mine located in Upshur County, West Virginia, near the town of Buckhannon, and the Sycamore No. 2 mine located in Harrison County, West Virginia, approximately ten miles west of Clarksburg. Nearly all of the reserves in Upshur County are owned, while those in Harrison County are leased. The Buckhannon Division currently controls approximately 52.6 million tons of reserves, all of which are suited for underground mining.

The Imperial mine extracts coal from the Middle Kittanning seam. The coal produced at the Imperial mine is processed through the nearby Sawmill Run preparation plant and shipped by CSX rail with origination by the A&O railroad, although some coal is trucked to local industrial customers. The reserves at the Buckhannon Division have characteristics that make it marketable to both steam and export metallurgical coal customers.

The Sycamore No. 2 mine produces coal from the Pittsburgh seam by the room-and-pillar mining method with continuous miners and shuttle cars. The reserve is primarily leased from one landowner with an annual minimum holding costs and an automatic renewal based on an annual minimum production of 250,000 tons. An independent contractor has operated the mine since September 2007. The coal produced from the Sycamore No. 2 mine is sold on a raw basis and transported to Allegheny Power Service Corporation’s Harrison Power Station by truck.

Sentinel

Sentinel consists of one underground mine that extracts coal from the Clarion seam using the room-and-pillar mining method. Clarion seam reserves at the Sentinel mine amount to approximately 12.3 million tons, of which approximately 13% is owned and 87% is leased. Additionally, 19.4 million tons of underground reserves in the Lower Kittanning seam are accessible from the Sentinel mine.

Coal is fed directly from the mine to a preparation plant and loadout facility served by the CSX railroad with origination by the A&O railroad. The product can be shipped to steam or metallurgical markets, by either rail or truck.

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New Appalachian Mine Developments

Tygart Valley Property

The Tygart Valley property, located in Taylor County, West Virginia, near Grafton, includes approximately 186.1 million tons of deep coal reserves of both steam and metallurgical quality coal in the Lower Kittanning seam, covering approximately 65,000 acres. The reserve extends into parts of Barbour, Marion and Harrison Counties as well. ICG owns the Tygart Valley coal reserve, in addition to nearly 4,000 acres of surface property to accommodate the development of two projected mining operations. In addition to the Lower Kittanning reserves, significant non-reserve coal deposits in the Kittanning, Freeport, Clarion and Mercer seams exist on the Tygart Valley property.

The West Virginia Department of Environmental Protection (the “WVDEP”) issued a surface mine permit on June 5, 2007 for the Tygart Valley No. 1 underground longwall mine and preparation plant complex located on the Tygart Valley property. Local opponents of the mine project stopped construction of the mine complex by filing repeated appeals of the WVDEP permit decision to the WV Surface Mine Board. However, the third and final appeal was denied when the Board unanimously upheld the WVDEP’s permit decision in an order issued on June 9, 2010, which the opposition did not contest.

As a result of our successful permit defense, construction of the Tygart Valley No. 1 mining complex resumed in June 2010. Construction at the new Tygart Valley No. 1 deep mine complex experienced minor weather-related delays near the end of 2010, but major earthwork is now complete with site development expected to wrap up in March 2011. Construction of the slope commenced in early November 2010 and work on the shafts began in December 2010. Initial coal production is projected for late fourth quarter 2011. At full output, currently projected for early 2014, Tygart Valley No. 1 is expected to produce 3.5 million tons annually of high quality coal that is well suited to both the utility market and the high volatile metallurgical market.

White Wolf Property

Our White Wolf (formerly known as Big Creek) reserve, located in Central Appalachia, covers 10,000 acres of leased coal lands located north of the town of Richlands in Tazewell County, Virginia. Total recoverable reserves are 25.9 million tons in the Jawbone and War Creek seams. The White Wolf reserve is all leased from Southern Regional Industrial Realty. The War Creek mine, which is permitted as a room-and-pillar mining operation, is expected to be developed in the future as market conditions warrant. We receive an overriding royalty on coalbed methane production from this property.

Jennie Creek Property

The Jennie Creek reserve, located in Mingo County, West Virginia, is a 41.8 million ton reserve of surface and deep mineable steam coal. This property contains 14.2 million tons of surface mineable, low-sulfur coal reserves and 27.6 million tons of high-Btu, mid-sulfur underground reserves in the Alma seam. Efforts are underway to secure an Army Corps of Engineers Section 404 authorization to complete permitting for surface mining on this property. We intend to produce the coal by area, contour and highwall mining. Also, permitting is now in progress for an Alma seam underground mine. Development of the property is dependent upon future market conditions.

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Illinois Basin Mining Operations

Below is a map showing the location and access to our coal properties in the Illinois Basin as of December 31, 2010:

Illinois operates one large underground coal mine, the Viper mine, in central Illinois. Viper commenced mining operations in 1982 and produces coal from the Illinois No. 5 seam, also referred to as the Springfield seam. Viper controls approximately 47.6 million tons of coal reserves. Approximately 83% of the coal reserves are leased, while 17% are owned in fee. The leases are retained by annual minimum payments and by tonnage-based royalty payments.

The Viper mine is a room-and-pillar operation, utilizing continuous miners and battery coal haulers. All of the raw coal is processed at Viper’s preparation plant and shipped by truck to utility and industrial customers located in North Central Illinois. A major rail line is located a short distance from the plant, giving Viper the option of constructing a rail loadout. Shipments to electric utilities account for approximately 74% of coal sales.

Development of a new portal facility is underway that will allow Illinois to eliminate the operation and maintenance of over five miles of underground beltlines and to seal and close the previously mined area.

As of December 31, 2010, this mine had 318 employees.

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Other Operations

Brokered coal sales

In addition to the coal we mine, we purchase and resell coal produced by third parties to fulfill certain sales obligations.

ADDCAR Systems

We manufacture and sell highwall mining systems using our patented ADDCAR highwall mining system. ADDCAR(TM) is the registered trademark of ICG. The ADDCAR highwall mining system is an innovative and efficient mining system often deployed at reserves that cannot be economically mined by other methods. In addition to manufacturing systems for sale, ADDCAR also has three of its highwall mining systems in operation conducting contract highwall mining services for third parties.

A typical ADDCAR highwall mining system consists of a launch vehicle, continuous miner, conveyor cars, a stacker conveyor, electric generator, water tanker for cooling and dust suppression and a wheel loader with forklift attachment.

A five person crew operates the entire ADDCAR highwall mining system with control of the continuous miner being performed remotely by one person from the climate-controlled cab. Our system utilizes a navigational package to provide horizontal guidance, which helps to control rib width, and thus roof stability. In addition, the system provides vertical guidance for avoiding or limiting out of seam dilutions. The ADDCAR highwall mining system is equipped with high-quality video monitors to provide the operator with visual displays of the mining process from inside the entry being mined.

The mining cycle begins by aligning the ADDCAR highwall mining system onto the desired heading and starting the entry. As the remotely controlled continuous miner penetrates the coal seam, ADDCAR conveyor cars are added behind it, forming a continuous cascading conveyor train. This continues until the entry is at the planned full depth of up to 1,200 to 1,500 feet. After retraction, the launch vehicle is moved to the next entry, leaving a support pillar of coal between entries. This process recovers as much as 65% of the reserves while keeping all personnel outside the coal seam in a safe working environment. A wide range of seam heights can be mined with high production in seams as low as 3.5 feet and as high as 15 feet in a single pass. If the seam height is greater than 15 feet, then multi-lifts can be mined to create an unlimited entry height. The navigational features on the ADDCAR highwall mining system allow for multi-lift mining while ensuring that the designed pillar width is maintained.

During the mining cycle, in addition to the tramming effort provided by the crawler drive of the continuous miner, the ADDCAR highwall mining system increases the cutting capability of the machine through additional forces provided by hydraulic cylinders which transmit thrust to the back of the miner through blocks mounted on the side of the conveyor cars. This additional energy allows the continuous miner to achieve maximum cutting and loading rates as it moves forward into the seam.

In addition to its standard highwall mining system, ADDCAR has also developed for manufacture and sale a narrow bench highwall mining system and a steep-dip highwall mining system. The narrow bench highwall mining system has a smaller operational footprint that allows operation on narrower mine benches that are often found in Appalachia. The steep-dip highwall mining system allows for mining in steeply dipping coal seams often found in the western U.S. and Canada.

We currently have the exclusive North American distribution rights, as well as certain international patent rights for the ADDCAR highwall mining system.

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Coalbed methane

Our subsidiary, CoalQuest, has entered into a lease and joint operating agreement pursuant to which it leases coalbed methane, which is pipeline quality gas that resides in coal seams, and participates in certain coalbed methane wells, from its properties in Barbour, Harrison and Taylor counties in West Virginia. Our coalbed methane lessee developed other wells in which CoalQuest is not a partial owner. In the eastern United States, conventional natural gas fields are typically located in various sedimentary formations at depths ranging from 2,000 to 15,000 feet. Exploration companies often put capital at risk by searching for gas in commercially exploitable quantities at these depths. By contrast, the coal seams from which we recover coalbed methane are typically less than 1,000 feet deep and are usually better defined than deeper formations. We believe that this contributes to lower exploration costs than those incurred by producers that operate in deeper, less defined formations. We believe this project is part of the first application of proprietary horizontal drilling technology for coalbed methane in northern West Virginia coalfields. We have not filed reserve estimates with any federal agency.

We receive an overriding royalty on coalbed methane production from the Crab Orchard Coal and Land Company and Beaver Coal Company coal reserves leased by ICG Beckley in Raleigh County, West Virginia and from the leased Big Creek coal reserves in Tazewell County, Virginia. We also lease coalbed methane from certain of our property in Kentucky and will receive rents and royalties on future production.

Customers and Coal Contracts

Customers

Our primary customers are investment grade electric utility companies predominantly in the eastern half of the United States, as well as domestic and international steel producers. The majority of our customers purchase coal for terms of one year or longer, but we also supply coal on a short-term or spot market basis for some of our customers. Our three largest customers for the year ended December 31, 2010 were Progress Energy, Dominion Energy and Santee Cooper and we derived approximately 34% of our revenues from sales to our five largest customers. We did not derive more than 10% of our revenues from any single customer in 2010.

Long-term coal supply agreements

As is customary in the coal industry, we enter into long-term supply contracts (exceeding one year in duration) with many of our customers when market conditions are appropriate. These contracts allow customers to secure a supply for their future needs and provide us with greater predictability of sales volumes and prices. For the year ended December 31, 2010, approximately 72% of our coal sales revenues were derived from long-term supply contracts. We sell the remainder of our coal through short-term contracts and on the spot market. We have also entered into certain brokered transactions to purchase certain amounts of coal to meet our sales commitments. These purchase coal contracts expired in 2010.

We have certain contracts which are below current market rates because they were entered into during periods of lower coal prices. As the net costs associated with producing coal have increased due to higher energy, transportation and steel prices, the price adjustment mechanisms within several of our long-term contracts do not reflect current market prices. This has resulted in certain counterparties to these contracts benefiting from below-market prices for our coal.

The terms of our coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary significantly by customer, including price adjustment features, price reopener terms, coal quality requirements, quantity adjustment mechanisms, permitted sources of supply, future regulatory changes, extension options, force majeure provisions and termination and assignment provisions.

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Some of our long-term contracts provide for a pre-determined adjustment to the stipulated base price at times specified in the agreement or at other periodic intervals to account for changes due to inflation or deflation in prevailing market prices.

In addition, most of our contracts contain provisions to adjust the base price due to new statutes, ordinances or regulations that impact our costs related to performance of the agreement. Also, some of our contracts contain provisions that allow for the recovery of costs impacted by modifications or changes in the interpretations or application of any applicable government statutes.

Price reopener provisions are present in several of our long-term contracts. These price reopener provisions may automatically set a new price based on prevailing market price or, in some instances, require the parties to agree on a new price, sometimes within a specified range of prices. In a limited number of agreements, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Under some of our contracts, we have the right to match lower prices offered to our customers by other suppliers.

Quality and volumes for the coal are stipulated in coal supply agreements and, in some instances, buyers have the option to vary annual or monthly volumes. Most of our coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash, hardness and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts.

Transportation

We ship coal to our customers by rail, truck or barge. We typically pay the transportation costs for our coal to be delivered to the barge or rail loadout facility, where the coal is then loaded for final delivery. Once the coal is loaded in the barge or railcar, our customer is typically responsible for the freight costs to the ultimate destination. Transportation costs vary greatly based on the customer’s proximity to the mine and our proximity to the loadout facilities. We use a variety of independent companies for our transportation needs and typically enter into multiple agreements with transportation companies throughout the year.

In 2010, approximately 87% of our coal sales from our Appalachian operations were delivered to our customers by rail generally on either the Norfolk Southern or CSX rail lines, with the remaining 13% delivered by truck or barge. For our Illinois Basin operations, all of our coal was delivered by truck to customers, generally within an 80-mile radius of our Illinois mine.

We believe we enjoy good relationships with rail carriers and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation and distribution employees.

Suppliers

In 2010, we spent more than $316.9 million to procure goods and services in support of our business activities, excluding capital expenditures. Principal commodities include maintenance and repair parts and services, fuel, roof control and support items, explosives, tires, conveyance structure, ventilation supplies and lubricants. Our outside suppliers perform a significant portion of our equipment rebuilds and repairs both on- and off-site, as well as construction and reclamation activities.

Each of our regional mining operations has developed its own supplier base consistent with local needs. We have a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods and to support the business units. The supplier base has been relatively stable for many years, but there has been some consolidation. We are not dependent on any one supplier in any region. We promote competition between suppliers and seek to develop relationships with those suppliers whose focus is on lowering our costs. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

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Competition

The coal industry is intensely competitive. Our main competitors are Massey Energy Company, Arch Coal, Consol Energy, Alpha Natural Resources, James River Coal Company, Patriot Coal Corporation and various other smaller, independent producers. The most important factors on which we compete are coal price at the mine, coal quality and characteristics, transportation costs and the reliability of supply. Demand for coal and the prices that we are able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry, which accounted for approximately 94% of domestic coal consumption in 2009. These coal consumption patterns are influenced by factors beyond our control, including the demand for electricity which is significantly dependent upon economic activity, weather patterns in the United States, government regulation, technological developments and the location, availability, quality and price of competing sources of coal, changes in international supply and demand, alternative fuels such as natural gas, oil and nuclear and alternative energy sources, such as hydroelectric power.

Employees

As of December 31, 2010, we had 2,766 employees of which 23% were salaried and 77% were hourly. We believe our relationship with our employees is positive. Our entire workforce is union free.

Reclamation

Reclamation expenses are a significant part of any coal mining operation. Prior to commencing mining operations, a company is required to apply for numerous permits in the state where the mining is to occur. Before a state will approve and issue these permits, it requires the mine operator to present a reclamation plan which meets regulatory criteria and to secure a surety bond to guarantee performance of reclamation in an amount determined under state law. Bonding companies also require posting of collateral, typically in the form of letters of credit, to secure the surety bonds. As of December 31, 2010, we had $65.8 million in letters of credit supporting our reclamation surety bonds. While bonds are issued against reclamation liability for a particular permit at a particular site, collateral posted in support of the bond is not allocated to a specific bond, but instead is part of a collateral pool supporting all bonds issued by that particular insurer. Bonds are released in phases as reclamation is completed in a particular area.

Environmental, Safety and Other Regulatory Matters

Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as permitting and licensing requirements, employee health and safety, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. These laws and regulations have had, and will continue to have, a significant effect on our costs of production and competitive position. Future legislation, regulations or orders may be adopted or become effective which may adversely affect our mining operations, cost structure or the ability of our customers to use coal. For instance, new legislation, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, may require substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which we cannot predict. Future legislation, regulations or orders or negative perceptions due to environmental issues may also cause coal to become a less attractive fuel source, resulting in a reduction in coal’s share of the market for fuels used to generate electricity.

We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, due in part to the extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry and at our operations.

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Mining Permits and Approvals

Numerous governmental permits or approvals are required for mining operations. In connection with obtaining these permits and approvals, we may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations and could have a material adverse effect on our business. Applications for permits are subject to public comment and may be subject to litigation from third parties seeking to deny issuance of a permit, which may also delay commencement or continuation of mining operations and could have a material adverse effect on our business. Regulations also provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position to control another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits. In addition, legislation has been introduced in the U.S. Congress that would restrict or prevent mountaintop mining.

In order to obtain mining permits and approvals from state regulatory authorities, mine operators must also submit a comprehensive plan for mining and restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically, we submit our necessary mining permit applications for our planned mines promptly upon securing the necessary property rights and required geologic and environmental data. In our experience, mining permit approvals generally require 12 to 18 months after initial submission; however, in the current regulatory environment, with enhanced scrutiny by regulators, increased opposition by environmental groups and others and potential resultant delays and permit application denials, we now anticipate that mining permit approvals will take even longer than previously experienced, and some permits may not be issued at all. Significant delays in obtaining, or denial of, permits could have a material adverse effect on our business.

Surface Mining Control and Reclamation Act

The Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is administered by the Department of Interior’s Office of Surface Mining Reclamation and Enforcement (“OSMRE”), establishes mining, environmental protection and reclamation standards for all aspects of surface mining, as well as for the surface effects of deep mining. Mine operators must obtain SMCRA permits and permit renewals from the OSMRE, or the appropriate state regulatory agency, for authorization of certain mining operations that result in a disturbance of the surface. If a state adopts a regulatory program as comprehensive as the federal mining program under SMCRA, the state becomes the regulatory authority. States in which we have active mining operations have achieved primary control of enforcement through federal approval of the state program.

SMCRA permit provisions include requirements for coal prospecting, mine plan development, topsoil removal, storage and replacement, selective handling of overburden materials, mine pit backfilling and grading, protection of the hydrologic balance, subsidence control for underground mines, surface drainage control, mine drainage and mine discharge control and treatment and revegetation. These requirements seek to limit the adverse impacts of coal mining and more restrictive requirements may be adopted from time to time.

The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of SMCRA, the state programs and the complementary environmental programs that impact coal mining.

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Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land, and documents required by the OSMRE’s Applicant Violator System, including the mining and compliance history of officers, directors and principal owners of the entity.

Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice and opportunity for public comment on a proposed permit is required before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and typically take 12 to 18 months, or even longer, to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has rights to comment on, and otherwise engage in, the permitting process, including through intervention in the courts. From time to time, litigation is brought to modify, revoke or enjoin the issuance of SMCRA and other permits. For example, our Hazard Thunder Ridge permit was previously the subject of litigation seeking to enjoin the construction of certain valley fills.

Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed or abandoned prior to 1977. On December 7, 2006, the Abandoned Mine Land Program was extended for 15 years.

SMCRA stipulates compliance with many other major environmental statutes, including: the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act (“RCRA”), and the Comprehensive Environmental Response, Compensation and Liability Act (“Superfund”).

Surety Bonds

Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations, including mine closure or reclamation costs, coal leases and other miscellaneous obligations. Many of these bonds are renewable on a yearly basis.

Surety bond costs have increased in recent years while the market terms of such bonds have generally become more unfavorable. In addition, the number of companies willing to issue surety bonds has decreased. Bonding companies also require posting of collateral, typically in the form of letters of credit, to secure the surety bonds. As of December 31, 2010, we had $65.8 million in letters of credit supporting our reclamation surety bonds.

Clean Air Act

The federal Clean Air Act, and comparable state laws that regulate air emissions, directly affect coal mining operations, but have a far greater indirect effect. Direct impacts on coal mining and processing operations may occur through permitting requirements and/or emission control requirements relating to particulate matter, such as fugitive dust, or fine particulate matter measuring 2.5 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired electricity generating plants and coke ovens. Major sources of greenhouse gas emissions are also subject to regulation under the Clean Air Act. The general effect of such extensive regulation of emissions from coal-fired power plants could be to reduce demand for coal.

Clean Air Act requirements that may directly or indirectly affect our operations include the following:

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Acid Rain

Title IV of the Clean Air Act required a two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and extended the Title IV requirements to all coal-fired power plants with generating capacity greater than 25 megawatts. The affected electricity generators have sought to meet these requirements by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years.

Criteria Pollutants

The Clean Air Act authorizes the U.S. Environmental Protection Agency (the “EPA”) to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”) for pollutants. Among the pollutants for which standards have been adopted (criteria pollutants) are sulfur dioxide, nitrogen oxides, ozone, particulate matter and fine particulates. Areas that are not in compliance with these standards (non-attainment areas) must take steps to reduce emissions levels. The EPA is required to regularly review these standards and may revise them following such reviews. Revisions to the standards typically make them more stringent and increase compliance costs as they are implemented.

Following identification of non-attainment areas, each individual state will identify the sources of emissions and develop emission reduction plans. These plans may be state-specific or regional in scope. Future regulation and enforcement of the most recent ozone and PM2.5 standards will affect many power plants, especially coal-fired plants and all plants in non-attainment areas.

Significant additional emissions control expenditures will be required at coal-fired power plants to meet the current NAAQS for ozone and fine particulate matter by further limiting their emissions of nitrogen oxides and sulfur dioxides. On July 6, 2010, the EPA issued a proposal that the agency believes will by 2014, in conjunction with other state and EPA actions, result in nitrogen oxide reductions of 52 percent compared to 2005 levels and sulfur dioxide reductions of 71 percent compared to 2005 levels. This proposal applies to electric generating units with a capacity of 25 megawatts or more located within 31 states in the eastern United States and the District of Columbia. The EPA has proposed setting an emissions budget for each state and two options for compliance and trading emission allowances. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding in the years ahead.

New source review requirements, which are imposed on major sources of pollutants, such as coal-fired power plants, and new source performance standards could impose control and emission requirements.

Installation of additional control measures, such as selective catalytic reduction devices, will make it more costly to operate coal-fired electricity generating plants and industrial boilers, thereby making coal a less attractive fuel and reducing demand for our products.

Mercury

The EPA has announced that it intends to initiate a rulemaking to adopt technology-based standards for mercury emissions from coal-fired power plants in response to a court order which vacated and remanded its 2005 Clean Air Mercury Rule, which would have reduced mercury emissions from such plants by a nationwide average of nearly 70%. The parties that overturned this rule seek even greater reductions in mercury emissions uniformly applied to all power plants. Some parties contend that during the pendency of this rulemaking, these plants are subject to mercury emission limitations determined on a case-by-case basis applying maximum achievable control technology.

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Other proposals for controlling mercury emissions from coal-fired power plants have been made, such as establishing state or regional emission standards. If these proposals were enacted, the mercury content and variability of our coal would become a factor in future sales and could reduce demand for our products. In addition, seven Northeastern states have prepared and submitted to the EPA a Northeast Regional Mercury Total Maximum Daily Load to reduce mercury in natural water courses by reducing air deposition of mercury primarily from coal-fired power plants in the Midwest.

Regional Haze

The EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. These limitations could affect the future market for coal.

Climate Change

Global climate change concerns have a potentially far-reaching impact upon our business, including our reputation and results of operations. Concerns over measurements, estimates and projections of global climate change, particularly global warming, have resulted in widespread calls for the reduction, by regulation and voluntary measures, of the emission of greenhouse gases, which include carbon dioxide and methane. These measures could impact the market for our coal and coalbed methane, increase our own energy costs and affect the value of our coal reserves. The United States has not ratified the Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, which would require our nation to reduce greenhouse gas emissions to 93% of 1990 levels by 2012. The United States is participating in international discussions to develop a treaty or other agreement to require reductions in greenhouse gas emissions after 2012 and has signed the Copenhagen Accord, which includes a non-binding commitment to reduce greenhouse gas emissions. In addition, the U.S. Congress has considered a variety of legislative proposals which would restrict and/or tax the emission of greenhouse gases from the combustion of coal and other fuels and which would mandate or encourage the generation of electricity by new facilities that do not use coal.

A step toward federal restriction on greenhouse gas emissions under the Clean Air Act was taken on December 7, 2009 when the EPA issued its so-called Endangerment Finding in response to a decision of the Supreme Court of the United States. The EPA found that the emission of six greenhouse gases, including carbon dioxide (which is emitted from coal combustion) and methane (which is emitted from coal beds) may reasonably be anticipated to endanger public health and welfare. Based on this finding, the EPA determined these six greenhouse gases to be air pollutants subject to regulation under the Clean Air Act. Although the EPA has stated a preference that greenhouse gas regulation be based on new federal legislation rather than the existing Clean Air Act, many sources of greenhouse gas emissions may be regulated without the need for further legislation. The EPA has already adopted regulations that impact major stationary sources of greenhouse gas emissions, including coal-fired power plants and has announced plans to propose additional regulations restricting greenhouse gas emissions. The EPA has adopted regulations which require reporting of greenhouse gas emissions by certain sources, including surface and underground coal mining. Under these regulations we are required to report our greenhouse gas emissions beginning in 2012 for the preceding year. In addition, the EPA has announced plans to set new source performance standards by May 2012, which would require pollution controls or other emission reduction measures at certain power plants.

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In addition to materially adversely impacting our markets and the demand for our products, regulations enacted due to climate change concerns could affect our operations by increasing our costs. Our energy costs could increase and we may have to incur higher costs to control emissions of carbon dioxide, methane or other pollutants from our operations.

While advocating for comprehensive federal legislation, many states have adopted measures, sometimes as part of a regional collaboration, to reduce greenhouse gases generated within their own jurisdiction. These measures include emission regulations, including regional cap and trade programs, mandates for utilities to generate a portion of their electricity without using coal and incentives or goals for generating electricity using renewable resources. Some municipalities have also adopted similar measures. Even in the absence of mandatory requirements, some entities are electing to purchase electricity generated by renewable resources for a variety of reasons, including participation in programs calling for voluntary reductions in greenhouse gas emissions. Some states, municipalities and individuals have also pursued common law nuisance suits against power, coal, oil and gas companies, alleging that their operations are contributing to climate change.

Passage of additional state or federal laws or regulations regarding greenhouse gas emissions or other actions to limit greenhouse gas emissions could result in fuel switching, from coal to other fuel sources, by electric generators. Such laws and regulations could, for example, include mandating decreases in greenhouse gas emissions from coal-fired power plants, imposing taxes on greenhouse gas emissions, requiring certain technology to capture and sequester greenhouse gases from new coal-fired power plants and encouraging the production of non-coal-fired power plants. Political and regulatory uncertainty over future emissions controls have been cited as major factors in decisions by power companies to postpone new coal-fired power plants. If measures such as these or other similar measures, like controls on methane emissions from coal mines, are ultimately imposed on the coal industry by federal or state governments or pursuant to international treaty, our operating costs may be materially and adversely affected. Similarly, alternative fuels (non-fossil fuels) could become more attractive than coal in order to reduce greenhouse gas emissions, which could result in a reduction in the demand for coal and, therefore, our revenues.

Clean Water Act

The federal Clean Water Act (“CWA”) and corresponding state laws affect coal mining operations by imposing restrictions on the discharge of certain pollutants into water and on dredging and filling wetlands and jurisdictional waters. The CWA establishes instream water quality standards, including anti-degradation standards, and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water.

From time to time additional and more stringent standards are adopted and incorporated into our NPDES permits. Compliance with these standards increases our costs, as does any failure to comply with our NPDES permits, which could subject us to penalties.

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Permits under Section 404 of the CWA are required for coal companies to conduct dredging or filling activities in jurisdictional waters for the purpose of conducting any instream activities, including installing culverts, creating water impoundments, constructing refuse areas, creating slurry ponds, placing valley fills or performing other mining activities. Jurisdictional waters typically include intermittent and perennial streams and may, in certain instances, include man-made conveyances that have a hydrologic connection to a stream or wetland. The Army Corps of Engineers (“ACOE”) authorizes instream activities under either a general “nationwide” permit or under an individual permit, based on the expected environmental impact. A nationwide permit may be issued for specific categories of filling activity that are determined to have minimal environmental adverse effects; however, the effective term of such permits is limited to no longer than five years. An individual permit typically requires a more comprehensive application process than a nationwide permit, including public notice and comment, but an individual permit can be issued for the project life. We have previously secured nationwide permits and individual permits, depending on the expected duration and timing of the proposed instream activity. We may seek nationwide permit authorizations for certain limited projects, such as activities related to surface facilities for underground mines, but will apply for individual permits in all other instances.

Pursuant to a June 11, 2009 memorandum of understanding (“MOU”) entered into by OSMRE, the EPA and ACOE to implement an interagency plan to significantly reduce the harmful environmental consequences of Appalachian surface coal mining, the signatory agencies have taken several actions which make obtaining permits to mine coal more difficult and more costly. For example, on April 1, 2010 the EPA issued guidance imposing new, stringent conductivity standards on water discharges from coal mining operations in Appalachia. The issuance of this guidance is being appealed by the National Mining Association, Kentucky Coal Association, the State of West Virginia and the Commonwealth of Kentucky.

Subsequent to the MOU, in September 2009, the EPA announced that 79 pending permit applications for Appalachian coal mining warranted further review because of continuing concerns about water quality and/or regulatory compliance issues. These included four of our permit applications. We elected to withdraw three of those applications and are proceeding with the fourth, which is a coarse refuse fill at Knott County. While the EPA has stated that its identification of these 79 permits does not constitute a determination that the mining involved cannot be permitted under the Clean Water Act and does not constitute a final recommendation from the EPA to the ACOE on these projects, it is unclear how long the further review will take for our remaining permit application or what the final outcome will be. It is also unclear what impact this process may have on our future applications for surface coal mining permits. Excessive delays in permitting may require adjustment of our production budget and mining plans.

Also in accordance with the MOU, on November 30, 2009, the OSMRE published an Advance Notice of Proposed Rulemaking announcing its intent to revise the stream buffer zone rule. After receiving over 30,000 comments during a brief public comment period, the OSMRE decided to expand its formal rulemaking to encompass issues beyond the stream buffer zone rule. The OSMRE in April and June 2010 published Notices of Intent to conduct an Environmental Impact Statement for a Stream Protection Rule, which would replace the 2008 stream buffer zone rule. The notices included a list of concepts under consideration for the proposed rule, such as requirements for coal mining companies to gather more specific baseline data on a proposed mine site's hydrology, geology, and aquatic biology; a proposal to establish a definition of the term "material damage to the hydrologic balance" of watersheds outside the permit area; revising regulations for mining activities in, near or beneath streams; and development of revised and expanded requirements for mine operators seeking a variance from the requirement that mined areas be reclaimed to their approximate original contour. The proposed revised rule is expected to be released for public review and comment in early 2011.

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The coal mining industry, and on occasion our operations, has been subject to litigation to prevent, restrict or delay the issuance of permits under the Clean Water Act. This litigation has resulted in more voluminous and costly permit applications and requirements and delays in obtaining permits.

The Sierra Club appealed the issuance of a modification to the NPDES permit for Patriot’s New Hill West surface mine on September 3, 2010, to the West Virginia Environmental Quality Board (“EQB”). The complaint alleges that the permit did not contain certain limits on discharge. At the conclusion of a four-day hearing in December 2010, the EQB directed all parties to submit briefs in preparation for closing arguments, and a final ruling is expected in March 2011 or shortly thereafter.

In September 2008 the Sixth Circuit Court of Appeals partly affirmed and partly rejected a federal district court’s decision that had upheld the EPA’s approval of Kentucky’s new antidegradation regulations. Antidegradation regulations prohibit diminution of water quality in streams. The court upheld Kentucky’s general approach to antidegradation but remanded to the EPA some provisions of the regulation, citing concerns regarding the cumulative effects of “no significant impact” exemptions, and the EPA’s review and approval process for several categories of discharges exempted from antidegradation review. The antidegradation policy regulation was modified to address the issues remanded by the Court. Kentucky removed all six exemptions cited in the remand from the regulation and now requires all of those formerly excepted categories of discharges to satisfy antidegradation requirements as a part of the application and permitting process. The process resulted in an amended regulation that became effective on July 30, 2009, after review by two legislative committees. The amended regulation was submitted to the EPA for approval in November 2009. In a letter dated November 9, 2010, the EPA approved the revised antidegradation regulation with the exception of four provisions that require further clarification. Of particular note to the Company, the EPA cited regulatory wording concerns regarding how antidegradation is addressed in general permits. The Company utilizes the Kentucky Pollutant Discharge Elimination System (KPDES) general permit wherever applicable in lieu of securing NPDES individual permits.

Mine Safety and Health

Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. Generally, the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. The federal Mine Improvement and New Emergency Response Act of 2006 (the “MINER Act”) was signed into law on June 15, 2006 and implementation of the specific requirements of the MINER Act is currently underway. While mine safety and health regulation has a significant effect on our operating costs, our U.S. competitors are subject to the same degree of regulation. However, pending legislation in various states could result in differing operating costs in different states and, therefore, our competitors operating in states with less stringent new legislation may not be subject to the same degree of regulation.

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The trust fund is funded by an excise tax on production of up to $1.10 per ton for underground coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the United States. In 2010, we recognized $10.4 million of expense related to this excise tax.

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Resource Conservation and Recovery Act

The RCRA affects coal mining operations by establishing requirements for the treatment, storage and disposal of hazardous wastes. Certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management.

Subtitle C of the RCRA exempted fossil fuel combustion of byproducts from hazardous waste regulation until the EPA completed a report to Congress and, in 1993, made a determination on whether the combustion byproducts should be regulated as hazardous. In the 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion byproducts (“CCBs”) generated at electric utility and independent power producing facilities, such as coal ash.

In May 2000, the EPA concluded that CCBs do not warrant regulation as hazardous waste under the RCRA and that the hazardous waste exemption applied to these CCBs. The EPA also determined that national non-hazardous waste regulations under the RCRA Subtitle D are needed for CCBs disposed in surface impoundments and landfills and used as mine-fill. The agency also concluded beneficial uses of these CCBs, other than for mine-filling, pose no significant risk and no additional national regulations are needed. However, on June 21, 2010 the EPA issued a proposed rule to regulate the disposal of CCBs under the RCRA. The proposed rule presents two options for comment, one of which would regulate CCBs as hazardous or special waste and the other as non-hazardous waste. The proposal does not affect placement of CCBs in mines or non-minefill uses of CCBs at coal mine sites. The EPA defers to OSMRE for any regulation of CCBs at coal mines. As long as the current exemption remains in effect, it is not anticipated that regulation of CCBs will have any material effect on the amount of coal used by electricity generators. Most state hazardous waste laws also exempt CCBs and instead treat them as a solid waste.

Due to the hazardous waste exemption for CCBs such as ash, some of the CCBs are currently put to beneficial use. For example, at certain mines, we sometimes use ash from fluidized bed combustion (“FBC”) boilers as a beneficial use under our reclamation plan. The alkaline FBC ash used for this purpose serves to help alleviate the potential for acid mine drainage. Also, we are paid to dispose of CCBs at our Illinois mine by our customers. Efforts continue by environmental groups and others for the adoption of more stringent disposal requirements for CCBs. Any increased costs associated with handling or disposal of CCBs would increase our customers’ operating costs and potentially reduce their coal purchases. Increased regulation may cause us increased costs due to substitute reclamation materials or decreased revenue due to discontinuing disposal on behalf of our customers. In addition, contamination caused by the past disposal of ash can lead to material liability.

Federal and State Superfund Statutes

Superfund and similar state laws affect coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources caused by such releases. Under such laws, joint and several liability may be imposed on waste generators, site owners or operators and others regardless of fault. In addition, mining operations may have reporting obligations under these laws.

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Coal Industry Retiree Health Benefit Act of 1992

Unlike many companies in the coal business, we do not have significant liabilities under the Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”), which requires the payment of substantial sums to provide lifetime health benefits to union-represented miners (and their dependents) who retired before 1992, because liabilities under the Coal Act that had been imposed on our predecessor or acquired companies were retained by the sellers and, if applicable, their parent companies in the applicable acquisition agreements, except for Anker Coal Group, Inc. (“Anker"). We should not be liable for these liabilities retained by the sellers unless they and, if applicable, their parent companies fail to satisfy their obligations with respect to Coal Act claims and retained liabilities covered by the acquisition agreements. Upon the consummation of the business combination with Anker, we assumed Anker’s Coal Act liabilities, which were estimated to be $1.4 million at December 31, 2010.

Endangered Species Act

The federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to our properties are protected under the Endangered Species Act. However, based on the species that have been identified to date and the current application of applicable laws and regulations, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.

Emergency Planning and Community Right to Know Act

Some of our subsidiary operations utilize materials and/or store substances that require certain reporting to local and state authorities under the federal Emergency Planning and Community Right to Know Act. If required reporting is missed, it can result in the assessment of fines and penalties. We do not believe that any potential fines or penalties that could potentially arise under the federal Emergency Planning and Community Right to Know Act would materially or adversely affect our ability to mine coal.

Other Regulated Substances

Some of our subsidiary operations utilize certain substances, such as ammonia or caustic soda, for managing water quality in discharges from their mine sites. These materials are considered hazardous and require safeguards in handling and use and, if present in sufficient quantities, create emergency planning and response requirements. The storage of petroleum products in certain quantities can also trigger reporting, planning and response requirements. Our subsidiaries are required to maintain careful control over the storage and use of these substances. The subsidiaries attempt to minimize the amount of materials stored at their operations that give rise to such concerns and to maximize the use of less hazardous materials whenever feasible. If quantities are sufficient, utilization of CCBs for reclamation can trigger certain reporting requirements for constituent trace elements contained in CCBs.

Additional Information

We file annual, quarterly and current reports, as well as amendments to those reports, proxy statements and other information with the SEC. You may access and read our SEC filings without charge through our website, www.intlcoal.com, or the SEC’s website, www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at (800) SEC–0330 for further information on the public reference room. You may also request copies of our filings, at no cost, by telephone at (304) 760-2400 or by mail at: International Coal Group, Inc., 300 Corporate Centre Drive, Scott Depot, West Virginia 25560, Attention: Secretary.

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GLOSSARY OF SELECTED TERMS

Ash. Impurities consisting of silica, alumina, calcium, iron and other incombustible matter that are contained in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the burning characteristics of coal.

Bituminous coal. A middle rank coal (between sub-bituminous and anthracite) formed by additional pressure and heat on lignite. It is the most common type of coal with moisture content less than 20% by weight and heating value of 10,000 to 14,000 Btus per pound. It is dense and black and often has well-defined bands of bright and dull material. It may be referred to as soft coal.

British thermal unit or Btu. A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit). On average, coal contains about 22 million Btu per ton.

Byproduct. Useful substances made from the gases and liquids left over when coal is changed into coke.

Central Appalachia. Coal producing area in eastern Kentucky, Virginia and southern West Virginia.

Coal seam. A bed or stratum of coal. Usually applies to a large deposit.

Coke. A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel. Its production results in a number of useful byproducts.

Compliance coal. Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu, as required by Phase II of the Clean Air Act Acid Rain program.

Continuous miner. A machine that simultaneously extracts and loads coal. This is distinguished from a conventional, or cyclic, unit, which must stop the extraction process for loading to commence.

Deep mine. See Underground mine below.

Fluidized bed combustion. A process with a high success rate in removing sulfur from coal during combustion. Crushed coal and limestone are suspended in the bottom of a boiler by an upward stream of hot air. The coal is burned in this bubbling, liquid-like (or fluidized) mixture. Rather than released as emissions, sulfur from combustion gases combines with the limestone to form a solid compound recovered with the ash.

Fossil fuel. Fuel such as coal, crude oil or natural gas formed from the fossil remains of organic material.

High-Btu coal. Coal which has an average heat content of 12,500 Btus per pound or greater.

High-sulfur coal. Coal which, when burned, emits 2.5 pounds or more of sulfur dioxide per million Btu.

Highwall. The unexcavated face of exposed overburden and coal in a surface mine or in a face or bank on the uphill side of a contour mine excavation.

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Illinois Basin. Coal producing area in Illinois, Indiana and western Kentucky.

Longwall mining. The most productive underground mining method in the United States. One of three main underground coal mining methods currently in use. Employs a rotating drum, or less commonly a steel plow, which is pulled mechanically back and forth across a face of coal that is usually about a thousand feet long. The loosened coal falls onto a conveyor for removal from the mine.

Low-sulfur coal. Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btu.

Medium-sulfur coal. Coal which, when burned, emits between 1.6 and 2.5 pounds of sulfur dioxide per million Btu.

Metallurgical coal. The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as “met” coal, its quality depends on four important criteria: volatile matter, which affects coke yield; the level of impurities including sulfur and ash, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Met coal typically has a particularly high-Btu level, but low ash and sulfur content.

Nitrogen oxide (NOx). A gas formed in high temperature environments such as coal combustion. It is a harmful pollutant that contributes to acid rain.

Non-reserve coal deposits. Non-reserve coal deposits are coal bearing bodies that have been sufficiently sampled and analyzed, but do not qualify as a commercially viable coal reserve as prescribed by SEC rules until a final comprehensive SEC-prescribed evaluation is performed.

Northern Appalachia. Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.

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

Pillar. An area of coal left to support the overlying strata in a mine; sometimes left permanently to support surface structures.

Powder River Basin. Coal producing area in northeastern Wyoming and southeastern Montana. This is the largest known source of coal reserves and the largest producing region in the United States.

Preparation plant. Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content.

Probable reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

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Proven Reserves. Reserves for which 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 the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

Reclamation. The process of restoring land and environmental values to a mining site after the coal is extracted. Reclamation operations are usually underway where the resources have already been taken from a mine, even as production operations are taking place elsewhere at the site. This process commonly includes recontouring or reshaping the land to its approximate original appearance, restoring topsoil and planting native grasses, trees and ground covers. Mining reclamation is closely regulated by both state and federal law.

Recoverable reserve. The amount of coal that can be recovered from the Reserves. The recovery factor for underground mines is approximately 60% and for surface mines approximately 80% to 90%.

Reserve. That part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination.

Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place.

Room-and-pillar mining. A method of underground mining in which about half of the coal is left in place to support the roof of the active mining area. Large “pillars” are left at regular intervals while “rooms” of coal are extracted.

Scrubber (flue gas desulfurization system). Any of several forms of chemical/physical devices which operate to neutralize sulfur compounds formed during coal combustion. These devices combine the sulfur in gaseous emissions with other chemicals to form inert compounds, such as gypsum, that must then be removed for disposal. Although effective in substantially reducing sulfur from combustion gases, scrubbers require approximately 6% to 7% of a power plant’s electrical output and thousands of gallons of water to operate.

Steam coal. See Thermal coal below.

Sub-bituminous coal. Dull coal that ranks between lignite and bituminous coal. Its moisture content is between 20% and 30% by weight, and its heat content ranges from 7,800 to 9,500 Btus per pound of coal.

Sulfur. One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous byproduct of coal combustion.

Thermal coal. Coal used by electric power plants and industrial steam boilers to produce electricity, steam or both. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

Tons. A “short,” or net, ton is equal to 2,000 pounds. A “long,” or British, ton is equal to 2,240 pounds. A “metric” ton is approximately 2,205 pounds. The short ton is the unit of measure referred to in this report.

Truck-and-shovel/loader mining. Similar forms of mining where large shovels or front-end loaders are used to remove overburden, which is used to backfill pits after the coal is removed. Smaller shovels load coal in haul trucks for transportation to the preparation plant or rail loadout.

Underground mine. Also known as a deep mine. Usually located several hundred feet below the earth’s surface, an underground mine’s resource is removed mechanically and transferred by conveyor to the surface. Most common in the coal industry, underground mines primarily are located east of the Mississippi River.

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ITEM 1A.

RISK FACTORS

Risks Relating to Our Business

A decline in coal prices could reduce our revenues and the value of our coal reserves.

Our results of operations are dependent upon the prices we receive for our coal, as well as our ability to improve productivity and control costs. Any decreased demand would cause spot prices to decline and require us to increase productivity and decrease costs in order to maintain our margins. A decrease in the price we receive for our coal could adversely affect our operating results and our ability to generate the cash flows we require to meet our bank loan requirements, improve our productivity and invest in our operations. The prices we receive for coal depend upon factors beyond our control, including:

•	supply of and demand for domestic and foreign coal;

•	demand for electricity;

•	domestic and foreign demand for steel and the continued financial viability of the domestic and/or foreign steel industry;

•	proximity to, capacity of and cost of transportation facilities;

•	domestic and foreign governmental legislation, regulations and taxes;

•	the imposition of regulatory requirements which restrict the ability of electric power companies to use coal to generate electricity;

•	regulatory, administrative and judicial decisions;

•	price and availability of alternative fuels, including the effects of technological developments; and

•	effect of worldwide energy conservation measures.

Our coal mining operations are subject to operating risks that could result in decreased coal production, which could reduce our revenues.

Our revenues depend on our level of coal mining production. The level of our production is subject to operating conditions and events beyond our control that could disrupt operations and affect production at particular mines for varying lengths of time. These conditions and events include:

•	unavailability of qualified labor;

•	our inability to acquire, maintain or renew necessary permits or mining or surface rights in a timely manner, if at all;

•	unfavorable geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposits;

•	failure of reserve estimates to prove correct;

•	changes in governmental regulation of the coal industry, including the imposition of additional taxes, fees or actions to suspend or revoke our permits or changes in the manner of enforcement of existing regulations, or changes in governmental regulation affecting the use of coal by our customers;

•	mining and processing equipment failures and unexpected maintenance problems;

•	adverse weather and natural disasters, such as heavy rains and flooding;

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•	increased water entering mining areas and increased or accidental mine water discharges;

•	increased or unexpected reclamation costs;

•	interruptions due to transportation delays;

•	unavailability of required equipment of the type and size needed to meet production expectations; and

•	unexpected mine safety accidents, including fires and explosions.

These conditions and events may increase our cost of mining and delay or halt production at particular mines either permanently or for varying lengths of time.

Reduced coal consumption by North American electric power generators could result in lower prices for our coal, which could reduce our revenues and adversely impact our earnings and the value of our coal reserves.

Restrictions on the emission of greenhouse gases, including carbon dioxide, continue to be proposed and adopted by various legislative and regulatory bodies at federal, state and local levels of government and at the international level. The intended effect of these restrictions is to discourage the combustion of fossil fuels in general, and the generation of electricity by coal in particular, in favor of "alternative sources" of energy which do not involve the combustion of fossil fuels. The enactment of federal legislation designed to restrict greenhouse gas emissions is uncertain. Federal legislation has been proposed and may continue to be proposed that would create or expand a myriad of federal programs designed to reduce energy produced by burning fossil fuels and increase alternative energy sources. One such program proposed to reduce greenhouse gas emissions via a cap and trade system for larger emitters, including coal-fired power plants. The imposition of such programs, or the effect of negative public perceptions of coal due to climate change issues, may result in more electric power generators shifting from coal to natural gas-fired plants or alternative energy sources. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of steam coal that we mine and sell, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

The United States is participating in international discussions to develop a treaty or other agreement to require reductions in greenhouse gas emissions after 2012 and has signed the Copenhagen Accord, which includes a non-binding commitment to reduce greenhouse gas emissions. The outcome of these discussions is also uncertain.

Restrictions on greenhouse gas emissions under the Clean Air Act are being adopted by the EPA. In its “Endangerment Finding,” the EPA found that the emission of six greenhouse gases, including carbon dioxide (which is emitted from coal combustion) and methane (which is emitted from coal beds) may reasonably be anticipated to endanger public health and welfare. Based on this finding, the EPA determined these six greenhouse gases to be air pollutants subject to regulation under the Clean Air Act. Although the EPA has stated a preference that greenhouse gas regulation be based on new federal legislation rather than the existing Clean Air Act, the EPA has already adopted regulations that impact major stationary sources of greenhouse gas emissions, including coal-fired power plants and has announced plans to propose additional regulations restricting greenhouse gas emissions.

States have adopted a variety of greenhouse gas control programs which impact electric utilities in particular. In addition to programs that would cap or otherwise control greenhouse gas emissions, various programs require electric utilities to generate a percentage of their electricity using alternative energy sources. There have also been public nuisance lawsuits brought against power, coal, oil and gas companies, alleging that their operations are contributing to climate change. See “Climate Change” contained in Item 1 of this Annual Report on Form 10-K for additional discussion of greenhouse gas regulation.

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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. An economic slowdown can significantly slow the growth of electrical demand and, in some locations, result in contraction of demand. The economy suffered a significant slowdown in the fourth quarter of 2008 that resulted in lower 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.

The capability and profitability of our operations may be adversely affected by the status of our long-term coal supply agreements and changes in purchasing patterns in the coal industry.

We sell a significant portion of our coal under long-term coal supply agreements, which we define as contracts with a term greater than 12 months. For the year ended December 31, 2010, approximately 72% of our coal sales revenues were derived from coal sales that were made under long-term coal supply agreements. As of that date, we had 25 long-term sales agreements with a volume-weighted average term of approximately 4.2 years. The prices for coal shipped under these agreements are typically fixed for at least the initial year of the contract, subject to certain adjustments in later years and thus may be below the current market price for similar type coal at any given time, depending on the timeframe of contract execution or initiation. As a consequence of the substantial volume of our sales that are subject to these long-term agreements, we have less coal available with which to capitalize on higher coal prices, if and when they arise. In addition, in some cases, our ability to realize the higher prices that may be available in the spot market may be restricted when customers elect to purchase higher volumes allowable under some contracts. When our current contracts with customers expire or are otherwise renegotiated, our customers may decide not to extend or enter into new long-term contracts or, in the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including under different pricing terms.

Furthermore, as electric utilities seek to adjust to requirements of the Clean Air Act, and the potential for more stringent requirements, they could become increasingly less willing to enter into long-term coal supply agreements and instead may purchase higher percentages of coal under short-term supply agreements. To the extent the electric utility industry shifts away from long-term supply agreements, it could adversely affect us and the level of our revenues. For example, fewer electric utilities will have a contractual obligation to purchase coal from us, thereby increasing the risk that we will not have a market for our production. Furthermore, spot market prices tend to be more volatile than contractual prices, which could result in decreased revenues.

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Certain provisions in our long-term supply agreements may provide limited protection during periods of adverse economic conditions. For example, the customer may be forced to reduce electricity output due to weak demand. If the low demand were to persist for an extended period, the customer might be forced to delay our contract shipments thereby reducing our revenue.

Price adjustment, price reopener and other similar provisions in long-term supply agreements may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Most of our coal supply agreements contain provisions that allow for the purchase price to be renegotiated at periodic intervals. These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to agree on a new price, sometimes between a specified range of prices. In some circumstances, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price would result in decreased revenues. Accordingly, supply contracts with terms of one year or more may provide only limited protection during adverse market conditions.

Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers during the duration of specified events beyond the control of the affected party. Additionally, most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as heat value (measured in Btus), sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or, in the extreme, termination of the contracts.

Consequently, due to the risks mentioned above, we may not achieve the revenue or profit we expect to achieve from our long-term supply agreements.

A decline in demand for metallurgical coal would limit our ability to sell our high quality steam coal as higher-priced metallurgical coal.

Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on the prevailing conditions in the metallurgical and steam coal markets. A decline in the metallurgical market relative to the steam market could cause us to shift coal from the metallurgical market to the steam market, thereby reducing our revenues and profitability. However, some of our mines operate profitably only if all or a portion of their production is sold as metallurgical coal to the steel market. If demand for metallurgical coal declined to the point where we could earn a more attractive return marketing the coal as steam coal, these mines may not be economically viable and may be subject to closure. Such closures would lead to accelerated reclamation costs, as well as reduced revenue and profitability.

Inaccuracies in our estimates of economically recoverable coal reserves could result in lower than expected revenues, higher than expected costs or decreased profitability.

We base our reserves information on engineering, economic and geological data assembled and analyzed by our staff, which includes various engineers and geologists, and which is periodically reviewed by outside firms. The reserves estimates as to both quantity and quality are updated quarterly to reflect production of coal from the reserves, acquisitions, dispositions, depleted reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities and qualities of and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and assumptions, all of which may vary considerably from actual results such as:

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•	geological and mining conditions which may not be fully identified by available exploration data or which may differ from experience in current operations;

•	historical production from the area compared with production from other similar producing areas; and

•	assumed effects of regulation and taxes by governmental agencies and assumptions concerning coal prices, operating costs, mining technology improvements, severance and excise taxes, development costs and reclamation costs.

For these reasons, estimates of the economically recoverable quantities and qualities attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of net cash flows expected from particular reserves prepared by different engineers or by the same engineers at different times may vary substantially. Actual coal tonnage recovered from identified reserve areas or properties, and revenues and expenditures with respect to our reserves, may vary materially from estimates. These estimates, thus, may not accurately reflect our actual reserves. Any inaccuracy in our estimates related to our reserves could result in lower than expected revenues, higher than expected costs or decreased profitability.

Disruptions in transportation services could limit our ability to deliver coal to our customers, which could cause revenues to decline.

We depend primarily upon railroads, trucks and barges to deliver coal to our customers. Disruption of railroad service due to weather-related problems, strikes, lockouts and other events could temporarily impair our ability to supply coal to our customers, resulting in decreased shipments and related sales revenues. 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.

Several of our mines depend on a single transportation carrier or a single mode of transportation. Disruption of any of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and other events could temporarily impair our ability to supply coal to our customers. Our transportation providers may face difficulties in the future that may impair our ability to supply coal to our customers, resulting in decreased revenues.

If there are disruptions of the transportation services provided by our primary rail carriers that transport our produced coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

Fluctuations in transportation costs could impair our ability to supply coal to our customers.

Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources.

Conversely, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, coordination of the many eastern loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make shipments originating in the eastern United States inherently more expensive on a per-mile basis than shipments originating in the western United States. The increased competition could have a material adverse effect on our business, financial condition and results of operations.

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The unavailability of an adequate supply of coal reserves that can be mined at competitive costs could cause our profitability to decline.

Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by our customers. Because our reserves decline as we mine our coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. 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. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our profitability and financial condition. 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. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

Unexpected increases in raw material costs or decreases in availability could significantly impair our operating profitability.

Our coal mining operations use significant amounts of steel, rubber, petroleum products and other raw materials in various pieces of mining equipment, supplies and materials. Scrap steel prices have risen significantly and, historically, the prices of scrap steel and petroleum have fluctuated. There may be other acts of nature, terrorist attacks or threats or other conditions that could also increase the costs of raw materials. If the price of steel, rubber, petroleum products or other of these materials increase, our operational expenses will increase, which could have a significant negative impact on our profitability. Additionally, shortages in raw materials used in the manufacturing of supplies and mining equipment could limit our ability to obtain such items which could have an adverse effect on our ability to carry out our business plan.

A shortage of skilled labor in the mining industry could pose a risk to achieving optimal labor productivity and competitive costs, which could adversely affect our profitability.

Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least a year of experience and proficiency in multiple mining tasks. In order to support our planned expansion opportunities, we intend to continue sponsoring both in-house and vocational coal mining programs at the local level in order to train additional skilled laborers. Competitive labor markets require competitive compensation packages. As a result, $16.50 of our cost of coal sales per ton in 2010 was attributable to labor and benefits, compared to $15.48 for 2009. In the event that a shortage of experienced labor were to arise or we are unable to train the necessary amount of skilled laborers, there could be an adverse impact on our labor productivity and costs and our ability to expand production, which could have a material adverse effect on our earnings.

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Our ability to operate our company effectively could be impaired if we fail to attract and retain key personnel.

Our senior management team averages 27 years of experience in the coal industry, which includes developing innovative, low-cost mining operations, maintaining strong customer relationships and making strategic, opportunistic acquisitions. The loss of any of our 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 personnel with coal industry experience. Competition for these persons in the coal industry is intense and we may not be able to successfully recruit, train or retain qualified personnel. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future. Our failure to retain or attract key personnel could have a material adverse effect on our ability to effectively operate our business.

Acquisitions that we may undertake involve a number of inherent risks, any of which could cause us not to realize the anticipated benefits.

We continually seek to expand our operations and coal reserves through selective acquisitions. If we are unable to successfully integrate the companies, businesses or properties we acquire, our profitability may decline and we could experience a material adverse effect on our business, financial condition or results of operations. Acquisition transactions involve various inherent risks, including:

•	uncertainties in assessing the value, strengths and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental or mine safety liabilities) of, acquisition candidates;

•	potential loss of key customers, management and employees of an acquired business;

•	ability to achieve identified operating and financial synergies anticipated to result from an acquisition;

•	discrepancies between the estimated and actual reserves of the acquired business;

•	problems that could arise from the integration of the acquired business; and

•	unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the acquisition.

Any one or more of these factors could cause us not to realize the benefits anticipated to result from an acquisition. Any acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. In addition, future acquisitions could result in our assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous acquisitions.

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Risks inherent to mining could increase the cost of operating our business.

Our mining operations are subject to conditions that can impact the safety of our workforce or delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include:

•	fires and explosions from methane gas or coal dust;

•	accidental minewater discharges;

•	weather, flooding and natural disasters;

•	unexpected maintenance problems;

•	key equipment failures;

•	variations in coal seam thickness;

•	variations in the amount of rock and soil overlying the coal deposit; and

•	variations in rock and other natural materials and variations in geologic conditions.

We maintain insurance policies that provide limited coverage for some of these risks, although there can be no assurance that these risks would be fully covered by our insurance policies. Despite our efforts, significant mine accidents could occur and have a substantial impact.

Inability of contract miner or brokerage sources to fulfill the delivery terms of their contracts with us could reduce our profitability.

In conducting our mining operations, we utilize third-party sources of coal production, including contract miners and brokerage sources, to fulfill deliveries under our coal supply agreements. Our profitability or exposure to loss on transactions or relationships such as these is dependent upon the reliability (including financial viability) and price of the third-party supply, our obligation to supply coal to customers in the event that adverse geologic mining conditions restrict deliveries from our suppliers, our willingness to participate in temporary cost increases experienced by our third-party coal suppliers, our ability to pass on temporary cost increases to our customers, the ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market and other factors. Brokerage sources and contract miners may experience adverse geologic mining and/or financial difficulties that make their delivery of coal to us at the contractual price difficult or uncertain, which could temporarily impair our ability to fill our customers' orders or require us to pay higher prices in order to obtain the required coal from other sources. If we have difficulty with our third-party sources of coal, our profitability could decrease.

We may be unable to generate sufficient taxable income from future operations to fully utilize our significant tax net operating loss carryforwards or maintain our deferred tax assets.

As a result of our acquisition of Anker and of historical financial results, we have recorded deferred tax assets. If we fail to generate profits in the foreseeable future, our deferred tax assets may not be fully utilized. We evaluate our ability to utilize our net operating loss (“NOL”) and tax credit carryforwards each period and, in compliance with FASB Accounting Standards Codification (“ASC”) Topic 740, Income Taxes (“ASC 740”), record any resulting adjustments that may be required to deferred income tax expense. In addition, we will reduce the deferred income tax asset for the benefits of NOL and tax credit carryforwards used in future periods and will recognize and record federal and state income tax expense at statutory rates in future periods. If, in the future, we determine that it is more likely than not that we will not realize all or a portion of the deferred tax assets, we will record a valuation allowance against deferred tax assets which would result in a charge to income tax expense.

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Failure to obtain or renew surety bonds in a timely manner and on acceptable terms could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal.

Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations, such as mine closure or reclamation costs and federal and state workers’ compensation costs. Certain business transactions, such as coal leases and other obligations, may also require bonding. These bonds are typically renewable annually. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral or other less favorable terms upon those renewals. The ability of surety bond issuers and holders to demand additional collateral or other less favorable terms has increased as the number of companies willing to issue these bonds has decreased over time. Our failure to maintain, or our inability to acquire, surety bonds that are required by state and federal law would affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal. That failure could result from a variety of factors including, without limitation:

•	lack of availability, higher expense or unfavorable market terms of new bonds;

•	restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our amended and restated credit facility; and

•	exercise by third-party surety bond issuers of their right to refuse to renew the surety.

Failure to maintain capacity for required letters of credit could limit our ability to obtain or renew surety bonds.

At December 31, 2010, we had $86.3 million of letters of credit in place, of which $65.8 million serve as collateral for reclamation surety bonds and $20.5 million secured miscellaneous obligations. Our asset-based loan facility (“ABL Loan Facility”) provides for a revolving credit facility of $125.0 million, all of which may be used for letters of credit. If we do not maintain sufficient borrowing capacity under our ABL Loan Facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our mining operations.

Our business requires continued capital investment, which we may be unable to provide.

Our business strategy requires continued capital investment for, among other purposes, managing acquired assets, acquiring new equipment, maintaining the condition of our existing equipment and maintaining compliance with environmental laws and regulations. To the extent that cash generated internally and cash available under our credit facilities are not sufficient to fund capital requirements, we will require additional debt and/or equity financing. However, this type of financing may not be available, or if available, may not be on satisfactory terms. Future debt financings, if available, may result in increased interest and amortization expense, increased leverage and decreased income available to fund further acquisitions and expansion. In addition, future debt financings may limit our ability to withstand competitive pressures and render us more vulnerable to economic downturns. If we fail to generate sufficient earnings or to obtain sufficient additional capital in the future or fail to manage our capital investments effectively, we could be forced to reduce or delay capital expenditures, sell assets or restructure or refinance our indebtedness.

In addition, the ABL Loan Facility contains covenants that, in the event our liquidity falls below a specified amount, limits the amount of capital expenditures and requires us to maintain a minimum ratio of EBITDA to fixed charges.

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The ABL Loan Facility also contains customary events of default, including, but not limited to, failure to pay principal or interest, breach of covenants or representations and warranties, cross-default to other indebtedness, judgment default and insolvency. If an event of default occurs under the ABL Loan Facility, the lenders under the ABL Loan Facility will be entitled to take various actions, including demanding payment for all amounts outstanding thereunder and foreclosing on any collateral. If the lenders were to do so, our other debt obligations including the senior notes and the convertible notes, would also have the right to accelerate those obligations which we would be unable to satisfy.

Increased consolidation and competition in the U.S. coal industry may adversely affect our ability to retain or attract customers and may reduce domestic coal prices.

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 the EIA, in 1995, the top ten coal producers accounted for approximately 50% of total domestic coal production. By 2009, however, the top ten coal producers’ share had increased to approximately 67% of total domestic coal production. 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.

The demand for U.S. coal exports is dependent upon a number of factors outside of our control, including the overall demand for electricity in foreign markets, currency exchange rates, ocean freight rates, the demand for foreign-produced steel both in foreign markets and in the U.S. market (which is dependent in part on tariff rates on steel), general economic conditions in foreign countries, technological developments and environmental and other governmental regulations and any other pressures placed on companies that are connected to the emission of greenhouse gases. If foreign demand for U.S. coal were to decline, this decline could cause competition among coal producers in the United States to intensify, potentially resulting in additional downward pressure on domestic coal prices.

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base is changing with an increasing focus on metallurgical sales to domestic and export steel customers. Despite the recent improvement in steel output, the steel industry experienced a dramatic downturn in late 2008 that continued for most of 2009, with most of the industry experiencing steep losses. If the current recovery does not continue, our ability to collect from some of our customers could be impaired.

Continued deregulation by our utility customers that sell their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear on payment default. These new power plant owners may have credit ratings that are below investment grade. Further, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default.

In the current economic climate certain of our customers and their customers may be affected by cash flow problems, which can increase the time it takes to collect accounts receivable.

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

We conduct a significant part of our mining operations on properties that we lease. A title defect or the loss of any lease upon expiration of its term, upon a default or otherwise, could adversely affect our ability to mine the associated reserves and/or process the coal that we mine. Title to most of our owned or leased properties and mineral rights is not usually verified until we make a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our lessors or grantors. Our right to mine some of our reserves has in the past been, and may again in the future be, adversely affected if defects in title or boundaries exist or if a lease expires. Any challenge to our title or leasehold interests could delay the exploration and development of the property and could ultimately result in the loss of some or all of our interest in the property. Mining operations from time to time may rely on an expired lease that we are unable to renew. From time to time we also may be in default with respect to leases for properties on which we have mining operations. In such events, we may have to close down or significantly alter the sequence of such mining operations which may adversely affect our future coal production and future revenues. If we mine on property that we do not own or lease, we could incur liability for such mining. Also, in any such case, the investigation and resolution of title issues would divert management’s time from our business and our results of operations could be adversely affected. Additionally, if we lose any leasehold interests relating to any of our preparation plants, we may need to find an alternative location to process our coal and load it for delivery to customers, which could result in significant unanticipated costs.

In order to obtain leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases or mining contracts for properties containing additional reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease. 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.

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

All of our coal production is from mines operated by union-free employees. However, our subsidiaries’ employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. If the terms of a union collective bargaining agreement are significantly different from our current compensation arrangements with our employees, any unionization of our subsidiaries’ employees could adversely affect the stability of our production and reduce our profitability.

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

During the mid-1970s and early 1980s, a growing coal market and increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in production capacity in excess of market demand throughout the industry. Similarly, increases in future coal prices could encourage the development of expanded capacity by new or existing coal producers.

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We are subject to various legal and governmental proceedings which may have a material adverse effect on our business.

We are party to a number of legal proceedings incidental to normal business activities, including several complaints related to an accident at our Sago mine in January 2006, a breach of contract complaint by one of our customers related to the idling of our Sycamore No. 2 mine and a class action lawsuit that alleges that the registration statements filed in connection with our initial public offering contained false and misleading statements, and that investors relied upon those securities filings and suffered damages as a result. Some actions brought against us from time to time may have merit and, in addition, there may be claims asserted against us that are not covered, in whole or in part, by our insurance policies. There is always the potential that an individual matter or the aggregation of many matters could have an adverse effect on our financial condition, results of operations or cash flows. See “Legal Proceedings” contained in Item 3 of this Annual Report on Form 10-K.

Although we strive to maintain compliance with all applicable laws at all times, from time to time we receive citations, orders and notices of violation from applicable governmental authorities, particularly those governing health, safety and the environment. When this occurs, we attempt to abate immediately the condition cited, whether or not we agree as to whether it constitutes a violation. When we receive citations, orders or notices of violation, we either pay the assessed penalties, or if we dispute the fact of such alleged violation or the amount of the penalty relative to such violation, we contest such matter. While such matters typically would not be expected to have a material adverse effect, they could in the future have a material adverse effect on our business. None of our mines has ever received a notice of a potential pattern of violations. If one or more of our operations, however, were placed on a pattern of violations by the regulatory authorities, such designation and the enhanced enforcement regime that such designation entails, could have a material adverse effect on our business.

Risks Relating to Government Regulation

Extensive government regulations impose significant costs on our mining operations, and future regulations could increase those costs or limit our ability to produce and sell coal.

The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to matters such as:

•	limitations on land use;

•	employee health and safety;

•	mandated benefits for retired coal miners;

•	mine permitting and licensing requirements;

•	reclamation and restoration of mining properties after mining is completed;

•	air quality standards;

•	water pollution;

•	construction and permitting of facilities required for mining operations, including valley fills and other structures, including those constructed in natural water courses and wetlands;

•	protection of human health, plantlife and wildlife;

•	discharge of materials into the environment;

•	surface subsidence from underground mining; and

•	effects of mining on groundwater quality and availability.

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In particular, federal and state statutes require us to restore mine property in accordance with specific standards and an approved reclamation plan, and require that we obtain and periodically renew permits for mining operations. If we do not make adequate provisions for all expected reclamation and other costs associated with mine closures, it could harm our future operating results.

Federal and state safety and health regulation in the coal mining industry may be the most comprehensive and pervasive system for protection of employee safety and health affecting any segment of the U.S. industry. It is costly and time-consuming to comply with these requirements and new regulations or orders may materially adversely affect our mining operations or cost structure, any of which could harm our future results.

Under federal law, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and contribute to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry before July 1973. The trust fund is funded by an excise tax on coal production. If this tax increases, or if we could no longer pass it on to the purchaser of our coal under many of our long-term sales contracts, it could increase our operating costs and harm our results. Recently, there has been a renewed focus on rates of black lung disease among coal workers. As a result, there may be greater federal scrutiny of the industry that could lead to new and more costly regulation which may increase our cost of contributions to the trust fund.

The costs, liabilities and requirements associated with existing and future regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Failure to comply with these regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. We must compensate employees for work-related injuries. If we do not make adequate provisions for our workers’ compensation liabilities, it could harm our future operating results. If we are pursued for these sanctions, costs and liabilities, our mining operations and, as a result, our profitability could be adversely affected. See “Item 1. Business—Environmental, Safety and Other Regulatory Matters.”

The possibility exists that new legislation and/or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. New legislation or administrative regulations (or new judicial interpretations or administrative enforcement of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. These regulations, if proposed and enacted in the future, could have a material adverse effect on our financial condition and results of operations.

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Restrictions on the disposal of mining spoil material could significantly increase our operating costs, discourage customers from purchasing our coal and materially harm our financial condition and operating results.

Mining in the mountainous terrain of Appalachia typically requires the use of valley fills for the disposal of excess spoil (rock and soil material) generated by construction and mining activities. In our surface mining operations, we select the mining method that allows us to recover more tons of coal per acre and facilitates the permitting of larger projects, which enables mining to continue over a longer period of time. All methods of surface mining in Appalachia depend on valley fills to dispose of excess mining spoil material. Construction of roads, underground mine portal sites, coal processing and handling facilities and coal refuse embankments or impoundments related to both surface and underground mining also require the development of valley fills. We obtain permits to construct and operate valley fills and surface impoundments from the Army Corps of Engineers (the “ACOE”) under the auspices of Section 404 of the federal Clean Water Act. Regulations that govern the issuance of such permits are under agency review and may become more stringent in the future. Lawsuits challenging the ACOE’s authority to authorize surface mining activities under comprehensive individual permits have been instituted by environmental groups, which also advocate for changes in federal and state laws that would prevent or further restrict the issuance of such permits.

Litigation of this type, which is designed to prevent or delay the issuance of permits needed for mining or to make permitting or regulatory standards more stringent, whether brought directly against us or against governmental agencies that establish environmental standards and issue permits, could greatly lengthen the time needed to permit the mining of reserves, significantly increase our operating costs, make it more difficult to economically recover a significant portion of our reserves and lead to a material adverse effect on our financial condition and results of operation. We may not be able to increase the price of our coal to cover higher production costs without reducing customer demand for our coal.

New government regulations as a result of recent mining accidents could continue increasing our costs.

Both the federal and state governments impose stringent health and safety standards on the mining industry. Regulations are comprehensive and affect nearly every aspect of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. As a result of past mining accidents, including the explosion at our Sago mine in January 2006, additional federal and state health and safety regulations have been adopted that have increased operating costs and affect our mining operations. State and federal legislation has been adopted that, among other things, requires additional oxygen supplies, communication and tracking devices, refuge chambers, stronger seal construction and monitoring standards and mine rescue teams. As a result of the April 5, 2010 explosion that caused fatal injuries to 29 workers at a competitor’s mine, both the federal government and the state of West Virginia have announced that they are considering additional changes to mine safety rules and regulations which may require changes to our mining practices that could further increase our capital and operating costs and decrease our productivity, which would adversely affect our results of operations. We expect that increased efforts to expand investigations and types of violations, as well as increased penalties for non-compliance will increase our costs related to worker health and safety. Additionally, we could be subject to civil penalties and other penalties if we violate mining regulations.

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Mining in Northern and Central Appalachia is more complex and involves more regulatory constraints than mining in the other areas, which could affect productivity and cost structures of these areas.

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

We must obtain governmental permits and approvals for mining operations, which can be a costly and time-consuming process, can result in restrictions on our operations and is subject to litigation that may delay or prevent us from obtaining necessary permits.

Our operations are principally regulated under surface mining permits issued pursuant to the Surface Mining Control and Reclamation Act and state counterpart laws. Such permits, which are issued for terms of five years with the right of successive renewal, grant approval for surface mining or the surface effects of underground mining. Separately, the CWA requires permits for operations that discharge water or place fill material into waters of the United States. Water discharges are authorized under CWA Section 402 permits typically issued by state regulatory agencies under EPA oversight while valley fills, refuse impoundments and other types of disturbances in streams are authorized under CWA Section 404 permits issued by the ACOE. The EPA has the authority, which it has rarely exercised until recently, to object to permits issued by the ACOE. While the ACOE is authorized to issue permits even when the EPA has objections, the EPA does have the ability to override the ACOE decision and veto the permits.

A Memorandum of Understanding executed on June 11, 2009 between the EPA, the ACOE and the Department of the Interior provided a blueprint for proposed changes to the regulation of coal mining activities in the Appalachian region of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia. The OSMRE stated that it intended to revise certain rules to afford greater protections to streams and to revisit its regulation of surface mine restoration. The EPA announced an enhanced coordination procedure for the review of all pending CWA Section 404 permit applications for mining in Appalachia.

In September 2009, the EPA announced 79 pending CWA Section 404 permit applications for Appalachian coal mining warranted further review because of continuing concerns about water quality and/or regulatory compliance issues. The list included four of our permit applications. Three of our four permit applications were withdrawn following our evaluation of other spoil disposal options, which are less economical than the proposed projects. Our application for a coarse refuse fill at our Knott County mine remains pending. While the EPA has stated that its identification of these 79 permits does not constitute a determination that the mining involved cannot be permitted under the CWA and does not constitute a final recommendation from the EPA to the ACOE on these projects, it is unclear how long the further review will take for our permits or what the final outcome will be. Excessive delays in permitting may require adjustments of our production budget and mining plans.

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On April 1, 2010, the EPA released a guidance document entitled “Improving EPA Review of Appalachian Surface Coal Mining Operations under the Clean Water Act, National Environmental Policy Act, and the Environmental Justice Executive Order.” This guidance, if applied by states within this six-state region (KY, OH, PA, TN, VA and WV), will result in the imposition of exceedingly stringent water quality-based limitations in CWA Section 402 wastewater discharge permits and CWA Section 404 dredge and fill permits. Specifically, a maximum conductivity limitation of 500 microSiemens per centimeter is not considered attainable for water discharges from most mining operations, including underground mines. This guidance may cause delays in our ability to obtain permits, may increase our operating and capital costs to comply with permits or, may prevent our ability to obtain permits that will allow us to conduct certain operations. The issuance of this guidance is being appealed by the National Mining Association, Kentucky Coal Association, the State of West Virginia and the Commonwealth of Kentucky.

Additionally, certain operations (particularly preparation plants) have permits issued pursuant to the Clean Air Act and state counterpart laws allowing and controlling the discharge of air pollutants. Regulatory authorities exercise considerable discretion in the timing of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in, or in some instances preclude, the commencement or continuation of development or production operations. Adverse outcomes in lawsuits challenging permits or failure to comply with applicable regulations could result in the suspension, denial or revocation of required permits, which could have a material adverse impact on our financial condition, results of operations or cash flows.

The Mine Safety and Health Administration or other federal or state regulatory agencies may order certain of our mines to be temporarily or permanently closed, which could adversely affect our ability to meet our customers’ demands.

The Mine Safety and Health Administration (“MSHA”) or other federal or state regulatory agencies may order certain of our mines to be temporarily or permanently closed. Our customers may challenge our issuance of force majeure notices in connection with such closures. If these challenges are successful, we may have to purchase coal from third-party sources to satisfy those challenges, incur capital expenditures to re-open the mines and negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery, terminate customers’ contracts or face claims initiated by our customers against us. The resolution of these challenges could have an adverse impact on our financial position, results of operations or cash flows.

Federal or state legislation that restricts disposal of mining spoil material or coal refuse material could eliminate certain mining methods, significantly increase our operating costs and materially harm our financial condition and operating results.

The U.S. Congress and state legislatures have in the past and are currently considering proposals that would effectively prohibit the placement of materials generated by coal mining into waters of the United States, which practice is essential to surface mining in central Appalachia. A prohibition against excess spoil placement in streams would essentially eliminate surface mining in steep terrain, thus rendering much of our coal reserves unmineable. Restrictions on the placement of coal refuse material in streams or in abandoned underground coal mines could limit the life of existing coal processing operations, potentially block new coal preparation plants and at minimum significantly increase our operating costs. Public concerns regarding the environmental, health and aesthetic impacts of surface mining could, independent of regulation, affect our reputation and reduce demand for our coal.

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Promulgation of a federal stream protection plan regulation that would restrict disposal of mining spoil material or place stringent restrictions on mining in, near or beneath streams could eliminate certain mining methods, significantly increase our operating costs and materially harm our financial condition and operating results.

The OSMRE published an Advance Notice of Proposed Rulemaking (“ANPRM”) in November 2009 regarding the alternatives under consideration for revision of its Stream Buffer Zone rule which solicits public comment on changes to mining regulatory programs that are more restrictive than indicated by the ANPRM. The OSMRE, after receiving over 30,000 comments during a brief public comment period, decided to expand its formal rulemaking to encompass issues beyond the stream buffer zone rule. The OSMRE in April and June 2010 published Notices of Intent to conduct an Environmental Impact Statement for a Stream Protection Rule, which would replace the 2008 Stream Buffer Zone Rule. The notice included a list of concepts under consideration for the proposed rule, such as requirements for coal mining companies to gather more specific baseline data on a proposed mine site's hydrology, geology, and aquatic biology; a proposal to establish a definition of the term "material damage to the hydrologic balance" of watersheds outside the permit area; revising regulations for mining activities in, near or beneath streams; and development of revised and expanded requirements for mine operators seeking a variance from the requirement that mined areas be reclaimed to their approximate original contour. The proposed revised rule is expected to be released for public review and comment in early 2011. If any of these or other more restrictive stream protection alternatives are adopted, such added requirements could impact coal mining operations, particularly in Appalachia, by reducing locations where coal mining operations can be conducted. Such measures could impact the cost and productivity of mining and may affect the economic viability of mining certain reserves. Certain of the proposed alternatives would effectively prohibit the placement of materials generated by coal mining into intermittent or perennial streams, which practice is essential to surface mining in central Appalachia. A prohibition against excess spoil placement in such streams would essentially eliminate surface mining in steep terrain, thus rendering much of our coal reserves unmineable. A prohibition on impacts to streams due to mining in, near or beneath such streams would adversely affect certain mining methods, including longwall mining.

We may be unable to obtain and renew permits necessary for our operations, which would reduce our production, cash flow and profitability.

Mining companies must obtain numerous permits that impose strict regulations on various environmental and safety matters in connection with coal mining. These include permits issued by various federal and state agencies and regulatory bodies. The permitting rules are complex and may change over time or become more stringent, making our ability to comply with the applicable requirements more difficult or even impossible, thereby precluding continuing or future mining operations. The public has certain rights to comment upon and otherwise engage in the permitting process, including through court intervention. Furthermore, in the current regulatory environment, with enhanced scrutiny by regulators, increased opposition by environmental groups and others and potential resultant delays and permit application denials, we now anticipate that mining permit approvals will take even longer than previously experienced, and some permits may not be issued at all. Accordingly, the permits we need may not be issued, maintained or renewed, may not be issued or renewed in a timely fashion, may involve requirements that restrict our ability to conduct our mining operations. An inability to conduct our mining operations pursuant to applicable permits would reduce our production, cash flows and profitability.

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

The SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining, as well as the surface effects of deep mining. Estimates of our total reclamation and mine closure liabilities are based upon permit requirements, engineering studies and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is updated annually by an independent engineering consulting firm and reviewed periodically by our management and engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Asset retirement obligations are recorded as a liability based on fair value, which is calculated as the present value of the estimated future cash flows. 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 behalf of us. The resulting estimated reclamation and mine closure obligations could change significantly if actual amounts change significantly from our assumptions.

Our operations may substantially impact the environment or cause exposure to hazardous materials, and our properties may have significant environmental contamination, any of which could result in material liabilities to us.

We use, and in the past have used, hazardous materials and generate, and in the past have generated, hazardous wastes. In addition, many of the locations that we own or operate were used for coal mining and/or involved hazardous materials usage either before or after we were involved with those locations. We may be subject to claims under federal and state statutes and/or common law doctrines for personal injury, property damages, natural resource damages and other damages, as well as the investigation and clean up of soil, surface water, groundwater and other media. Such claims may arise, for example, out of current or former activities at sites that we own or operate currently, as well as at sites that we or predecessor entities owned or operated in the past, and at contaminated sites that have always been owned or operated by third parties. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the remediation costs or other damages, or even for the entire share. We have from time to time been subject to claims arising out of contamination at our own and other facilities and may incur such liabilities in the future.

We use, and in the past have used, alkaline coal combustion byproducts (“CCBs”) during the reclamation process at certain of our mines to aid in preventing the formation of acid mine drainage and we have agreed to dispose of CCBs in some instances. Use of CCBs on a mined area is subject to regulatory approval and is allowed only after it is proved to be a beneficial use. The EPA has issued a proposed regulation discussing potential regulatory options for CCBs generated by electricity generators under the Resource Conservation and Recovery Act, one of which is the regulation of CCBs as hazardous or special waste and the other as non-hazardous waste. This proposed rule contains an exemption, the scope of which is not completely clear, for the use of CCBs as minefills at coal mines, and the EPA has stated that it will defer to the OSMRE to undertake regulatory action. If in the future CCBs were to be classified as a hazardous or special waste or if more stringent disposal requirements were to be otherwise established for these wastes, we may be required to cease using or disposing of CCBs at certain of our mines and find a replacement alkaline material for this purpose, which may add to the cost of mine reclamation or decrease our revenue generated from disposal contracts with certain of our customers.

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We maintain extensive coal slurry impoundments at a number of our mines. Such impoundments are subject to stringent regulation. Slurry impoundments maintained by other coal mining operations have been known to fail, releasing large volumes of coal slurry. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure, unless preventive measures are implemented in a timely manner. We have commenced such measures to modify our method of operation at one surface impoundment containing slurry wastes in order to reduce the risk of releases to the environment from it, a process that has been incorporated into the construction sequence of the impoundment and thus will take several years to complete. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.

These and other impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations and environmental conditions at our properties, could result in costs and liabilities that would materially and adversely affect us.

Extensive environmental regulations affect our customers and could reduce the demand for coal as a fuel source and cause 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 and other compounds emitted into the air from coke ovens and electric power plants, which are the largest end users of our coal. Such regulations will require significant emissions control expenditures for many coal-fired power plants to comply with applicable ambient air quality standards. As a result, these generators may switch to other fuels that generate less of these emissions, possibly reducing future demand for coal and the construction of coal-fired power plants.

The Federal Clean Air Act, including the Clean Air Act Amendments of 1990, and corresponding state laws that regulate emissions of materials into the air affect coal mining operations both directly and indirectly. Measures intended to improve air quality that reduce coal’s share of the capacity for power generation could diminish our revenues and harm our business, financial condition and results of operations. The price of lower sulfur coal may decrease as more coal-fired utility power plants install additional pollution control equipment to comply with stricter sulfur dioxide emission limits, which may reduce our revenues and harm our results. In addition, regulatory initiatives including the sulfur dioxide and nitrogen oxide rules, new ozone and particulate matter standards, regional haze regulations, new source review, new source performance standards, regulation of mercury emissions and legislation or regulations that establish restrictions on greenhouse gas emissions or provide for other multiple pollutant reductions could make coal a less attractive fuel to our utility customers and substantially reduce our sales.

Various new and proposed laws and regulations may require further significant reductions in emissions from coal-fired utilities. More stringent emissions standards may require many coal-fired sources to install additional pollution control equipment, such as wet scrubbers. Increasingly, the EPA has been undertaking multi-pollutant rulemakings to reduce emissions from coal-fired utilities. The EPA has issued a proposed rule to regulate the disposal of CCBs under the Resource Conservation and Recovery Act. These and other future standards could have the effect of making the operation of coal-fired plants less profitable, thereby decreasing demand for coal. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use.

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There have been several recent proposals in Congress that are designed to further reduce emissions of sulfur dioxide, nitrogen oxides and mercury from power plants, and certain ones could regulate additional air pollutants. If such initiatives are enacted into law, power plant operators could choose fuel sources other than coal to meet their requirements, thereby reducing the demand for 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.

New and pending laws regulating the environmental effects of emissions of greenhouse gases could impose significant additional costs to doing business for the coal industry and/or a shift in consumption to non-fossil fuels.

Greenhouse gas emissions have increasingly become the subject of a large amount of international, national, regional, state and local attention. Future regulation of greenhouse gas could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act or new climate change legislation. Increased efforts to control greenhouse gas emissions could result in reduced demand for coal if electric power generators switch to lower carbon sources of fuel.

Coal-fired power plants can generate large amounts of greenhouse gas emissions, and, as a result, have become subject to challenge, including the opposition to any new coal-fired power plants or capacity expansions of existing plants, by environmental groups seeking to curb the environmental effects of emissions of greenhouse gases. Various legislation has been and may continue to be introduced in Congress which reflects a wide variety of strategies for reducing greenhouse gas emissions in the United States. These strategies include mandating decreases in greenhouse gas emissions from coal-fired power plants, instituting a tax on greenhouse gas emissions, banning the construction of new coal-fired power plants that are not equipped with technology to capture and sequester carbon dioxide, encouraging the growth of renewable energy sources (such as wind or solar power) or nuclear for electricity production, and financing the development of advanced coal burning plants which have greatly reduced greenhouse gas emissions. Most states in the United States have taken steps to regulate greenhouse gas emissions. Under the Clean Air Act, the EPA has published its finding that greenhouse gases pose a threat to public health and declared that six greenhouse gases constitute air pollutants. The EPA has adopted regulations that would impact new or modified major stationary sources of greenhouse gas emissions, including coal-fired power plants, beginning January 2, 2011. Emissions of greenhouse gas emissions from coal mining have come under increased regulatory attention, as the EPA has extended its greenhouse gas emissions reporting rules to underground coal mines and has received a petition to adopt regulations to restrict greenhouse gas emissions, including methane, and other pollutants from surface, underground and abandoned coal mines.

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These or additional state or federal laws or regulations regarding greenhouse gas emissions or other actions to limit greenhouse gas emissions could result in fuel switching, from coal to other fuel sources, by electric generators. Political and regulatory uncertainty over future emissions controls have been cited as major factors in decisions by power companies to postpone new coal-fired power plants. If measures such as these or other similar measures, like controls on methane emissions from coal mines, are ultimately imposed on the coal industry by federal or state governments or pursuant to international treaty, our operating costs may be materially and adversely affected. Similarly, alternative fuels (non-fossil fuels) could become more attractive than coal in order to reduce greenhouse gas emissions, which could result in a reduction in the demand for coal and, therefore, our revenues. Public concerns regarding climate change could, independent of regulatory developments, adversely affect our reputation and reduce demand for our coal.

Risks Relating to Our Common Stock

The market price of our common stock may be volatile, which could cause the value of our common stock to decline.

The market price of our common stock has experienced, and may continue to experience, significant volatility. Between January 1, 2009 and December 31, 2010, the trading price of our common stock on the New York Stock Exchange ranged from a low of $1.09 per share to a high of $8.59 per share. There are numerous factors contributing to the market price of our common stock, including many over which we have no control. These risks include, among other things:

•	our operating and financial performance and prospects;

•	our ability to repay our debt;

•	investor perceptions of us and the industry and markets in which we operate;

•	changes in earnings estimates or buy/sell recommendations by analysts; and

•	general financial, domestic, international, economic and other market conditions.

In addition, the stock market in recent years has experienced extreme price and trading volume fluctuations that often have been unrelated or disproportionate to the operating performance of individual companies. These broad market fluctuations may adversely affect the price of our common stock, regardless of our operating performance. Furthermore, stockholders may initiate securities class action lawsuits if the market price of our stock drops significantly, which may cause us to incur substantial costs and could divert the time and attention of our management.

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Sales of additional shares of our common stock could cause the price of our common stock to decline.

Sales of substantial amounts of our common stock in the public market, or the perception that those sales may occur, could adversely affect the price of our common stock. In addition, future issuances of equity securities, including pursuant to our shelf registration statement or the exercise of options, could dilute the interests of our existing stockholders and could cause the market price for our common stock to decline. We may issue equity securities in the future for a number of reasons, including financing our operations and business strategy, to adjust our ratio of debt to equity, to satisfy our obligations upon the exercise of outstanding convertible securities, warrants or options or for other reasons.

As of December 31, 2010, there were:

•	5,739,583 shares of common stock issuable upon the exercise of stock options outstanding at a weighted-average exercise price of $4.91;

•	1,145,006 shares of nonvested restricted stock; and

•	315,420 restricted share units issued to directors to be converted to common stock upon separation of service.

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

Our total consolidated long-term debt as of December 31, 2010 was approximately $326.4 million. Our level of debt could have important consequences on our future operations, including:

•	making it more difficult for us to meet our payment and other obligations under our outstanding senior and convertible notes and our other outstanding debt;

•	resulting in an event of default if we fail to comply with the financial and other restrictive covenants contained in our debt agreements, which could result in all of our debt becoming immediately due and payable;

•	subjecting us to the risk of increased sensitivity to interest rate increases on our debt with variable interest rates, including borrowings under our ABL Loan Facility;

•	reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions and other general corporate purposes, and limiting our ability to obtain additional financing for these purposes;

•	limiting our flexibility in planning for, or reacting to, and increasing our vulnerability to, changes in our business, the industry in which we operate and the general economy; and

•	placing us at a competitive disadvantage compared to our competitors that have less debt or are less leveraged.

If we or our subsidiaries incur additional debt, the related risks that we and they now face could intensify.

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Our ability to pay principal and interest on and to refinance our debt depends upon the operating performance of our subsidiaries, which will be affected by, among other things, general economic, financial, competitive, legislative, regulatory and other factors, some of which are beyond our control. In particular, economic conditions could cause the price of coal to fall, our revenue to decline and hamper our ability to repay our debt.

Our business may not generate sufficient cash flow from operations and future borrowings may not be available to us under our ABL Loan Facility or otherwise in an amount sufficient to enable us to pay our debt, or to fund our other liquidity needs.

In the event that we need to refinance all or a portion of our outstanding debt before maturity or as it matures, we may not be able to obtain terms as favorable as the terms of our existing debt or refinance our existing debt at all. If prevailing interest rates or other factors existing at the time of refinancing result in higher interest rates upon refinancing, then the interest expense relating to the refinanced debt would increase. Furthermore, if any rating agency negatively changes our credit rating or outlook, our debt and equity securities could be negatively affected, which could adversely affect our financial condition and results of operations.

The conditional conversion features of the 2017 Convertible Notes, if triggered, may adversely affect our financial condition and operating results.

In the event the conditional conversion features of the 2017 Convertible Notes are triggered, holders of notes will be entitled to convert the 2017 Convertible Notes at any time during specified periods at their option. If one or more holders elect to convert their 2017 Convertible Notes, unless we elect to satisfy our conversion obligation by delivering solely shares of our common stock (other than solely cash in lieu of any fractional share) or if we have irrevocably elected full physical settlement of the 2017 Convertible Notes, we would be required to make cash payments to satisfy all or a portion of our conversion obligation based on the applicable conversion rate, which could adversely affect our liquidity. In addition, even if holders do not elect to convert their 2017 Convertible Notes, we could be required under applicable accounting rules to reclassify all or a portion of the outstanding principal of the 2017 Convertible Notes as a current rather than long-term liability, which could result in a material reduction of our net working capital.

Our money market funds are vulnerable to market-specific risks that could adversely affect our financial position, future earnings or cash flows.

We currently have a portion of our assets invested in money market funds which invest in direct obligations of the U.S. Treasury, repurchase agreements that are secured by U.S. Treasury securities or secured with collateral issued or guaranteed by the U.S. Government or its agencies or instrumentalities, debt securities issued or guaranteed by the U.S. Government or its agencies or instrumentalities, and high grade overnight repurchase agreements. These investments are subject to investment market risk and our income from these investments could be adversely affected by a decline in value. In the case of these money market accounts, the value of the assets may decline as a result of changes in interest rates, an issuer’s actual or perceived creditworthiness or an issuer’s ability to meet its obligations. A significant decrease in the net asset value of the securities underlying the money market fund could cause a material decline in our net income and cash flows.

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Provisions of our debt could discourage an acquisition of us by a third-party.

Certain provisions of our debt could make it more difficult or more expensive for a third-party to acquire us. Upon the occurrence of certain transactions constituting a fundamental change, holders of both series of notes will have the right, at their option, to require us to repurchase, at a cash repurchase price equal to 100% of the principal amount plus accrued and unpaid interest on the notes, all of their notes or any portion of the principal amount of such notes in integral multiples of $1,000. We may also be required to issue additional shares of our common stock upon conversion of such notes in the event of certain fundamental changes.

Anti-takeover provisions in our charter documents and Delaware corporate law may make it difficult for our stockholders to replace or remove our current board of directors and could deter or delay third parties from acquiring us, which may adversely affect the marketability and market price of our common stock.

Provisions in our amended and restated certificate of incorporation and bylaws and in Delaware corporate law may make it difficult for stockholders to change the composition of our board of directors in any one year, and thus prevent them from changing the composition of management. In addition, the same provisions may make it difficult and expensive for a third-party to pursue a tender offer, change in control or takeover attempt that is opposed by our management and board of directors. Public stockholders who might desire to participate in this type of transaction may not have an opportunity to do so. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change in control or change our management and board of directors and, as a result, may adversely affect the marketability and market price of our common stock.

We are also subject to the anti-takeover provisions of Section 203 of the Delaware General Corporation Law. Under these provisions, if anyone becomes an “interested stockholder,” we may not enter into a “business combination” with that person for three years without special approval, which could discourage a third-party from making a takeover offer and could delay or prevent a change of control. For purposes of Section 203, “interested stockholder” means, generally, someone owning more than 15% or more of our outstanding voting stock or an affiliate of ours that owned 15% or more of our outstanding voting stock during the past three years, subject to certain exceptions as described in Section 203.

Under any change of control, the lenders under our credit facilities would have the right to require us to repay all of our outstanding obligations under the facility.

There may be circumstances in which the interests of our major stockholders could be in conflict with the interests of a stockholder or noteholder.

As of December 31, 2010, funds sponsored by WL Ross & Co. LLC (“WLR”) own approximately 6% of our common stock and funds sponsored by Fairfax Financial Holdings Limited (“Fairfax”) own approximately 11% of our common stock. Circumstances may occur in which WLR, Fairfax or other major investors may have an interest in pursuing acquisitions, divestitures or other transactions, including among other things, taking advantage of certain corporate opportunities that, in their judgment, could enhance their investment in us or another company in which they invest. These transactions might involve risks to our other holders of common stock or adversely affect us or other investors.

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Future sales of our common stock by our major stockholders may depress our share price and influence our management policies.

WLR and Fairfax, which respectively own approximately 6% and 11% of our common stock as of December 31, 2010, may seek alternatives for the disposition of shares of our common stock. We have previously granted each of WLR and Fairfax “demand” and “piggyback” registration rights relating to their shares of our common stock. Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, if either WLR or Fairfax were to sell its entire holdings to one person, that person could have significant influence over our management policies.

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

We have never declared or paid a cash dividend, and we currently do not anticipate paying any cash dividends in the foreseeable future. See “Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Dividend Policy.” If we were to decide in the future to pay dividends, our ability to do so would be dependent on the ability of our subsidiaries to make cash available to us, by dividend, debt repayment or otherwise. The ability of our subsidiaries to make cash available to us is limited by restrictions in our ABL Loan Facility and the indenture governing our 2018 Senior Notes.

The covenants in our ABL Loan Facility and the indentures governing our debt instruments impose restrictions that limit our operating and financial flexibility.

The ABL Loan Facility includes negative covenants that, subject to exceptions, limit our ability and the ability of our subsidiaries to, among other things:

•	make, create, incur, assume or suffer to exist liens, other than specified permitted liens;

•	engage in mergers, acquisitions, consolidations, sale-leasebacks and asset sales;

•	make investments and loans;

•	create, incur, assume or permit to exist additional indebtedness or guarantees;

•	pay dividends, make payments or redeem or repurchase capital stock;

•	engage in certain transactions with affiliates;

•	prepay, redeem or purchase indebtedness;

•	amend or otherwise alter terms of certain indebtedness;

•	make capital expenditures in excess of specified limitations; and

•	alter the business that our subsidiaries conduct.

In addition, the ABL Loan Facility contains covenants that, in the event our liquidity falls below a specified amount, limits the amount of annual capital expenditures and requires us to maintain a minimum ratio of EBITDA to fixed charges.

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The indenture that governs the 2018 Senior Notes contains a number of significant restrictions and covenants that may limit our ability and our subsidiaries’ ability to, among other things:

•	incur additional indebtedness;

•	subordinate indebtedness to other indebtedness unless such subordinated indebtedness is also subordinated;

•	pay dividends or make other distributions or repurchase or redeem our stock or subordinated indebtedness;

•	make investments;

•	sell assets and issue capital stock of restricted subsidiaries;

•	incur liens;

•	enter into agreements restricting our subsidiaries’ ability to pay dividends;

•	enter into sale and leaseback transactions;

•	enter into transactions with affiliates; and

•	consolidate, merge or sell all or substantially all of our assets.

Operating results below current levels or other adverse factors, including a significant increase in interest rates, could result in us being unable to comply with certain debt covenants. If we violate these covenants and are unable to obtain waivers, our debt under these agreements would be in default and could be accelerated and could permit the lenders to foreclose on our assets securing the debt thereunder. If the indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms or on terms that are acceptable to us. If our debt is in default for any reason, our cash flows, results of operations or financial condition could be materially and adversely affected. In addition, complying with these covenants may also cause us to take actions that are not favorable to holders of our common stock and may make it more difficult for us to successfully execute our business strategy and compete against companies that are not subject to such restrictions.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

Table of Contents

ITEM 2.

PROPERTIES

Coal Reserves

“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. “Proven (Measured) Reserves” are defined by SEC Industry Guide 7 as reserves for which (1) 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 (2) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. “Probable reserves” are defined by SEC Industry Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) 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 (measured) reserves, is high enough to assume continuity between points of observation.

We estimate that there are approximately 312 million tons of coal reserves that can be developed by our existing operations, which will allow us to maintain current production levels for an extended period of time. Our unassigned reserves contain approximately 776 million tons of mid- to high-Btu, low- and high-sulfur coal located in Kentucky, West Virginia, Maryland, Illinois, Virginia and Ohio. Our multi-region base and flexible product line allows us to adjust to changing market conditions and sustain high sales volume by supplying a wide range of customers.

Table of Contents

Our total coal reserves could support current production levels for more than 70 years. The following table provides the location of our mining operations and the type of coal produced at those operations as of December 31, 2010:

Mining Operations	Assigned or Unassigned(1)	Operating or Development	State	Mining Method Surface (S) or Underground (UG)	Total Proven and Probable Reserves (2)	Owned Proven and Probable Reserves(2)	Leased Proven and Probable Reserves(2)	Steam Proven and Probable Reserves(2)	Metallurgical Proven and Probable Reserves(2)(3)(4)
					(in million tons)
Northern Appalachian
Vindex Energy Corp.	Assigned	O	MD/WV	S/UG	12.58	0.00	12.58	5.86	6.72
	Unassigned	D	MD/WV	S/UG	47.70	0.35	47.35	38.24	9.46
Total Vindex Energy Corp.					60.28	0.35	59.93	44.10	16.18
Patriot Mining Co.	Assigned	O	WV	S	8.67	0.01	8.66	8.67	0.00
Wolf Run Mining Buckhannon Division	Assigned	O	WV	UG	22.03	11.83	10.20	9.63	12.40
	Unassigned	D	WV	UG	30.55	28.81	1.74	0.00	30.55
Total Wolf Run Mining Buckhannon Division					52.58	40.64	11.94	9.63	42.95
Sentinel	Assigned	O	WV	UG	44.28	30.12	14.16	0.00	44.28
	Unassigned	D	WV	UG	4.94	4.94	0.00	0.00	4.94
Total Sentinel					49.22	35.06	14.16	0.00	49.22
CoalQuest Development LLC	Unassigned	D	WV	UG	186.09	186.09	0.00	32.71	153.38
	(Tygart Valley)
ICG Natural Resources	Unassigned	D	OH	UG	94.26	94.26	0.00	94.26	0.00
	(Paw Paw Creek)
Total Northern Appalachian					451.10	356.41	94.69	189.37	261.73
Central Appalachian
Eastern	Assigned	O	WV	S/UG	7.67	0.10	7.57	7.67	0.00
Hazard	Assigned	O	KY	S	65.13	27.01	38.12	65.13	0.00
	Unassigned	D	KY	UG	10.40	0.65	9.75	10.40	0.00
Total Hazard					75.53	27.66	47.87	75.53	0.00
Flint Ridge	Assigned	O	KY	UG	20.24	0.58	19.66	20.24	0.00
Knott County	Assigned	O	KY	UG	15.74	2.37	13.37	15.74	0.00
	Unassigned	D	KY	UG	2.40	0.00	2.40	2.40	0.00
Total Knott County					18.14	2.37	15.77	18.14	0.00
Raven	Assigned	O	KY	UG	18.52	1.51	17.01	18.52	0.00
	Unassigned	D	KY	UG	0.96	0.85	0.11	0.96	0.00
Total Raven					19.48	2.36	17.12	19.48	0.00
East Kentucky	Assigned	O	KY	S	0.91	0.76	0.15	0.91	0.00
ICG Natural Resources	Assigned	D	WV	S	14.17	0.00	14.17	14.17	0.00
	Unassigned	D	WV	UG	27.62	0.00	27.62	27.62	0.00
	(Jennie Creek)
Total ICG Natural Resources					41.79	0.00	41.79	41.79	0.00
Powell Mountain	Assigned	O	KY/VA	UG	4.61	0.00	4.61	4.61	0.00
	Unassigned	D	KY/VA	S/UG	20.90	0.00	20.90	20.90	0.00
Total Powell Mountain					25.51	0.00	25.51	25.51	0.00
Beckley	Assigned	O	WV	UG	30.23	1.28	28.95	0.00	30.23
White Wolf Energy, Inc.	Unassigned	D	VA	UG	25.91	0.00	25.91	0.00	25.91
	(Big Creek)
Total Central Appalachian					265.41	35.11	230.30	209.27	56.14
Illinois Basin
Illinois	Assigned	O	IL	UG	47.57	8.03	39.54	47.57	0.00
	(Viper)
ICG Natural Resources	Unassigned	D	IL	UG	324.10	324.10	0.00	324.10	0.00
Total Illinois Basin					371.67	332.13	39.54	371.67	0.00
Total Proven and Probable Reserves					1,088.18	723.65	364.53	770.31	317.87

(1)	“Assigned reserves” means coal which has been committed by the coal company to operating mine shafts, mining equipment and plant facilities, and all coal which has been leased by the coal company to others. “Unassigned reserves” represent coal which has not been committed, and which would require new mineshafts, mining equipment or plant facilities before operations could begin in the property. The primary reason for this distinction is to inform investors which coal reserves will require substantial capital investment before production can begin.
(2)	The proven and probable reserves are reported as recoverable reserves, which is that part of a coal deposit which could be economically and legally extracted or produced at the time of the reserve determination, taking into account mining recovery and preparation plant yield.
(3)	White Wolf Energy, Inc. meets historical metallurgical coal quality specifications.
(4)	We sold coal with ash and/or sulfur contents as high as 10% and 1.5%, respectively, into the metallurgical market from Vindex Energy, Buckhannon and Sentinel in 2010. Similarly, we believe approximately half of the production from Tygart Valley could be sold into the metallurgical market when production begins.
	For a description of mining properties, see Item 1. Business under the headings “Northern and Central Appalachian Mining Operations” and “Illinois Basin Mining Operations.”

Table of Contents

The following table provides the “quality” (average moisture, ash and sulfur contents and Btu per pound) of our coal reserves as of December 31, 2010:

		As Received Quality					Total Proven and Probable Reserves(2)
Mining Operations	Assigned or Unassigned(1)	% Moisture	% Ash	% Sulfur	Btu/lb.	Lbs. SO2/ million Btus	<1.2 lbs. SO2 Compliance	>1.2 lbs. SO2 Non-Compliance
Northern Appalachian
Vindex Energy Corp(4)	Assigned	5.14	14.73	1.61	12,449	2.58	0.00	12.58
	Unassigned	6.00	13.69	2.00	12,492	3.20	0.00	47.70
Total Vindex Energy Corp.		5.82	13.91	1.91	12,483	3.07	0.00	60.28
Patriot Mining Co.	Assigned	6.00	14.56	3.16	11,879	5.33	0.00	8.67
Wolf Run Mining Buckhannon Division(4)	Assigned	6.00	8.35	2.05	13,034	3.14	0.00	22.03
	Unassigned	6.00	8.92	0.99	13,069	1.52	0.00	30.55
Total Wolf Run Mining Buckhannon Division		6.00	8.68	1.43	13,054	2.20	0.00	52.58
Sentinel	Assigned	6.00	8.42	1.47	13,183	2.23	0.00	44.28
	Unassigned	6.00	8.04	1.44	13,353	2.15	0.00	4.94
Total Sentinel		6.00	8.38	1.47	13,200	2.22	0.00	49.22
CoalQuest Development LLC(4)	Unassigned	6.00	9.25	1.15	13,145	1.76	0.00	186.09
	(Tygart Valley)
ICG Natural Resources	Unassigned	6.00	7.62	2.07	13,021	3.18	0.00	94.26
	(Paw Paw Creek)
Total Northern Appalachian							0.00	451.10
Central Appalachian
Eastern	Assigned	6.00	13.13	1.23	12,181	2.02	0.00	7.67
Hazard	Assigned	6.00	12.98	1.38	11,995	2.30	0.00	65.13
	Unassigned	6.00	6.55	0.84	12,890	1.30	0.00	10.40
Total Hazard		6.00	12.09	1.31	12,118	2.15	0.00	75.53
Flint Ridge	Assigned	6.00	8.15	1.39	12,768	2.17	1.33	18.91
Knott County	Assigned	6.01	5.65	1.45	13,311	2.17	0.00	15.74
	Unassigned	6.00	6.70	1.67	13,102	2.55	0.00	2.40
Total Knott County		6.01	5.79	1.48	13,283	2.22	0.00	18.14
Raven	Assigned	6.00	7.05	1.33	12,983	2.05	0.00	18.52
	Unassigned	6.00	4.10	2.07	13,477	3.07	0.00	0.96
Total Raven		6.00	6.90	1.37	13,007	2.10	0.00	19.48
East Kentucky	Assigned	6.00	9.18	0.83	12,430	1.33	0.00	0.91
ICG Natural Resources	Assigned	7.00	9.69	0.75	12,274	1.23	9.13	5.04
	Unassigned	7.00	4.92	1.27	13,254	1.92	0.00	27.62
	(Jennie Creek)
Total ICG Natural Resources		7.00	6.54	1.09	12,922	1.69	9.13	32.66
Powell Mountain	Assigned	6.00	3.84	0.59	13,663	0.86	4.61	0.00
	Unassigned	6.00	7.78	1.94	12,872	3.02	6.13	14.77
Total Powell Mountain		6.00	7.07	1.70	13,015	2.61	10.74	14.77
Beckley(3)	Assigned	6.00	4.87	0.70	13,913	1.01	30.23	0.00
White Wolf Energy, Inc.(3)	Unassigned	6.00	4.09	0.63	14,150	0.89	25.91	0.00
	(Big Creek)
Total Central Appalachian							77.34	188.07
Illinois Basin
Illinois	Assigned	16.00	8.80	2.86	10,692	5.35	0.00	47.57
	(Viper)
ICG Natural Resources	Unassigned	12.76	9.28	2.87	10,962	5.24	0.00	324.10
Total Illinois Basin		13.17	9.22	2.87	10,928	5.26	0.00	371.67
Total Proven and Probable Reserves							77.34	1,010.84

(1)	“Assigned reserves” means coal which has been committed by the coal company to operating mine shafts, mining equipment and plant facilities, and all coal which has been leased by the coal company to others. “Unassigned reserves” represent coal which has not been committed, and which would require new mine shafts, mining equipment or plant facilities before operations could begin in the property. The primary reason for this distinction is to inform investors which coal reserves will require substantial capital investment before production can begin.
(2)	The proven and probable reserves are reported as recoverable reserves, which is that part of a coal deposit which could be economically and legally extracted or produced at the time of the reserve determination, taking into account mining recovery and preparation plant yield.
(3)	White Wolf Energy, Inc. meets historical metallurgical coal quality specifications.
(4)	We sold coal with ash and/or sulfur contents as high as 10% and 1.5%, respectively, into the metallurgical market from Vindex Energy, Buckhannon and Sentinel in 2010. Similarly, we believe approximately half of the production from Tygart Valley could be sold into the metallurgical market when production begins.
	For a description of mining properties, see Item 1. Business under the headings “Northern and Central Appalachian Mining Operations” and “Illinois Basin Mining Operations.”

Table of Contents

Our reserve estimates are based on geological data assembled and analyzed by our staff of geologists and engineers. Reserve estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Acquisitions, sales or dispositions of coal properties will also change the reserve estimates. We estimate that we controlled 1.1 billion tons of reserves at December 31, 2010. Changes in mining methods may increase or decrease the recovery basis for a coal seam, as will plant processing efficiency tests. We maintain reserve information in secure computerized databases, as well as in hard copy. The ability to update and/or modify the reserves is restricted to a few individuals and the modifications are documented.

Actual reserves may vary substantially from the estimates. Estimated minimum recoverable reserves are comprised of coal that is considered to be merchantable and economically recoverable by using mining practices and techniques prevalent in the coal industry at the time of the reserve study, based upon then-current prevailing market prices for coal. We use the mining method that we believe will be most profitable with respect to particular reserves. We believe the volume of our current reserves exceeds the volume of our contractual delivery requirements. Although the reserves shown in the table above include a variety of qualities of coal, we presently blend coal of different qualities to meet contract specifications. See “Risk Factors—Risks Relating To Our Business.”

We currently own approximately 67% of our coal reserves, with the remainder of our coal reserves subject to leases from third-party landowners. Generally, these leases convey mining rights to the coal producer in exchange for a percentage of gross sales in the form of a royalty payment to the lessor, subject to minimum payments. Leases generally last for the economic life of the reserves. The average royalties paid by us for coal reserves from our producing properties was $3.69 per ton in 2010, representing approximately 5.6% (net of freight and handling) of our coal sales revenue in 2010. Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased priorities are not completely verified until we prepare to mine those reserves.

Non-Reserve Coal Deposits

Non-reserve coal deposits are coal-bearing bodies that have been sufficiently sampled and analyzed in trenches, outcrops, drilling and underground workings to assume continuity between sample points and, therefore, warrant further exploration stage work. However, this coal does not qualify as a commercially viable coal reserve as prescribed by SEC standards until a final comprehensive evaluation based on unit cost per ton, recoverability and other material factors concludes legal and economic feasibility. Non-reserve coal deposits may be classified as such by limited property control, geologic limitations or both.

Table of Contents

The following table provides the location of our mining operations and the type and amount of non-reserve coal deposits at those complexes as of December 31, 2010:

Mining Operations

Assigned or

Unassigned(1)

Operating or

Development

State

Mining Method

Surface (S) or

Underground

(UG)

Total

Non-Reserve

Coal

Deposits

Steam

Non-Reserve

Coal

Deposits

Metallurgical

Non-Reserve

Coal Deposits(2)(3)

(in million tons)

Northern Appalachian

Vindex Energy Corp.

Unassigned

MD/WV

0.44

0.00

0.44

Wolf Run Mining Buckhannon Division

Assigned

0.42

0.00

Unassigned

2.24

0.00

Total Wolf Run Mining Buckhannon Division

2.66

0.00

Sentinel

Assigned

1.64

0.00

Unassigned

0.76

0.00

Total Sentinel

2.40

0.00

CoalQuest Development LLC

Unassigned

38.14

0.00

(Tygart Valley)

Upshur Property

Unassigned

92.97

0.00

(Upshur)

ICG Natural Resources

Unassigned

5.77

0.00

(Paw Paw Creek)

Total Northern Appalachian

142.38

141.94

0.44

Central Appalachian

Eastern

Assigned

S/UG

1.67

0.02

1.65

Hazard

Assigned

10.30

0.00

Flint Ridge

Assigned

0.09

0.00

Knott County

Assigned

0.82

0.00

ICG Natural Resources

Assigned

0.22

0.00

(Jennie Creek)

ICG Natural Resources

Unassigned

S/UG

35.59

0.00

(Martin Co.,

Muhlenberg Co.)

ICG Natural Resources

Unassigned

S/UG

21.62

0.00

(Mobil)

Powell Mountain

Unassigned

KY/VA

46.07

0.00

Beckley

Unassigned

1.88

0.00

1.88

Juliana Mining Co., Inc.

Unassigned

S/UG

3.10

0.00

White Wolf Energy, Inc.

Unassigned

2.57

0.00

(Big Creek)

Total Central Appalachian

123.93

120.40

3.53

Illinois Basin

Illinois

Assigned

38.47

0.00

(Viper)

ICG Natural Resources

Unassigned

58.46

0.00

(Illinois)

Total Illinois Basin

96.93

0.00

Table of Contents

Mining Operations

Assigned or

Unassigned(1)

Operating or

Development

State

Mining Method

Surface (S) or

Underground

(UG)

Total

Non-Reserve

Coal Deposits

Steam

Non-Reserve

Coal Deposits

Metallurgical

Non-Reserve

Coal Deposits(2)(3)

Ancillary

(in million tons)

ICG Natural Resources

Unassigned

39.15

0.00

(Arkansas)

Unassigned

10.00

0.00

(California)

Unassigned

12.00

0.00

(Montana)

Unassigned

9.86

0.00

(Washington)

Total Ancillary

71.01

0.00

Total Non-Reserve Coal Deposits

434.25

430.28

3.97

(1)	“Assigned non-reserve coal deposits” mean coal which has been committed by the coal company to operating mine shafts, mining equipment and plant facilities, and all coal which has been leased by the coal company to others. “Unassigned non-reserve coal deposits” represent coal which has not been committed, and which would require new mine shafts, mining equipment or plant facilities before operations could begin in the property.
(2)	White Wolf Energy, Inc. meets historical metallurgical coal quality specifications.
(3)	We sold coal with ash and/or sulfur contents as high as 10% and 1.5%, respectively, into the metallurgical market from Vindex Energy, Buckhannon and Sentinel in 2010. Similarly, we believe approximately half of the production from Tygart Valley can be sold into the metallurgical market.
	For a description of mining properties, see Item 1. Business under the headings “Northern and Central Appalachian Mining Operations” and “Illinois Basin Mining Operations.”

The following table provides the “quality” (average moisture, ash and sulfur contents and Btu per pound) of our non-reserve coal deposits as of December 31, 2010:

		As Received Quality
Mining Operations	Assigned or Unassigned(1)	% Moisture	% Ash	% Sulfur	Btu/ lb.	Lbs. SO2/ million Btus
Northern Appalachian
Vindex Energy Corp.(3)	Unassigned	6.00	14.15	1.49	12,409	2.40
Wolf Run Mining Buckhannon Division(3)	Assigned	6.00	8.16	2.25	13,011	3.46
	Unassigned	6.00	9.00	1.20	13,000	1.85
Sentinel	Assigned	6.00	8.30	1.40	13,100	2.14
	Unassigned	6.00	8.30	1.40	13,100	2.14
Upshur Property	Unassigned	6.00	43.00	2.00	8,000	5.00

ICG Natural Resources	Unassigned	6.00	7.62	2.07	13,021	3.18
	(Paw Paw Creek)
Central Appalachian
Eastern	Assigned	6.00	7.41	1.07	13,221	1.62
Hazard	Assigned	6.00	12.84	1.20	12,008	2.00
Flint Ridge	Assigned	6.00	8.15	1.39	12,768	2.18
Knott County	Assigned	6.00	6.07	1.60	13,205	2.42
ICG Natural Resources	Assigned	7.00	7.78	0.63	12,609	1.01
	(Jennie Creek)
ICG Natural Resources	Unassigned	6.00	11.47	1.91	11,780	3.24
	(Martin Co., Muhlenberg Co.)
ICG Natural Resources	Unassigned	6.00	12.50	1.10	12,000	1.83
	(Mobil)
Powell Mountain	Unassigned	6.00	5.78	1.21	13,348	1.81
Beckley(2)	Unassigned	6.00	4.80	0.70	13,800	1.01
Juliana Mining Co., Inc.	Unassigned	6.00	7.50	0.82	13,100	1.25
White Wolf Energy, Inc.(2)	Unassigned	6.00	7.40	0.60	13,500	0.89
	(Big Creek)

Table of Contents

		As received quality
Mining operations	Assigned or Unassigned(1)	% Moisture	% Ash	% Sulfur	Btu/ lb.	Lbs. SO2/ million Btus
Illinois Basin
Illinois	Assigned	16.00	9.50	3.50	10,500	6.67
	(Viper)
ICG Natural Resources	Unassigned	13.00	9.00	3.00	11,000	5.45
	(Illinois)
Ancillary
ICG Natural Resources	Unassigned	*	8.00	0.40	5,650	1.42
	(Arkansas)
	Unassigned	6.00	13.00	3.50	11,700	5.98
	(California)
	Unassigned	*	8.00	0.30	8,900	0.67
	(Montana)
	Unassigned	*	8.00	0.50	7,025	1.42
	(Washington)

(1)	“Assigned non-reserve coal deposits” mean coal which has been committed by the coal company to operating mine shafts, mining equipment and plant facilities, and all coal which has been leased by the coal company to others. “Unassigned non-reserve coal deposits” represent coal which has not been committed, and which would require new mineshafts, mining equipment or plant facilities before operations could begin in the property.
(2)	White Wolf Energy, Inc. meets historical metallurgical coal quality specifications.
(3)	We sold coal with ash and/or sulfur contents as high as 10% and 1.5%, respectively, into the metallurgical market from Vindex Energy, Buckhannon and Sentinel in 2010. Similarly, we believe approximately half of the production from Tygart Valley can be sold into the metallurgical market.
*	Undeterminable
	For a description of mining properties, see Item 1. Business under the headings “Northern and Central Appalachian Mining Operations” and “Illinois Basin Mining Operations.”

ITEM 3.

LEGAL PROCEEDINGS

See Note 16–Commitments and Contingencies–Legal Matters to the audited consolidated financial statements included in Item 15 of this Annual Report on Form 10-K relating to certain legal proceedings, which information is incorporated herein by reference.

ITEM 4.

(REMOVED AND RESERVED)

Table of Contents

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the New York Stock Exchange (the “NYSE”) under the symbol “ICO.” The following table sets forth, for the quarterly periods indicated, the high and low sales prices per share of our common stock as reported on the NYSE.

	Stock Price
	High		Low
2010
January 1, 2010 through March 31, 2010	$	4.89	$	3.36
April 1, 2010 through June 30, 2010		5.71		3.59
July 1, 2010 through September 30, 2010		5.49		3.62
October 1, 2010 through December 31, 2010		8.59		5.24

2009
January 1, 2009 through March 31, 2009	$	3.24	$	1.09
April 1, 2009 through June 30, 2009		3.70		1.54
July 1, 2009 through September 30, 2009		4.59		2.24
October 1, 2009 through December 31, 2009		5.35		3.47

These quotes are provided solely for informational purposes and may not be indicative of any price at which the shares of common stock may trade in the future.

As of February 1, 2011, there were approximately 254 holders of record of our common stock.

Summary of Equity Compensation Plans

Shown below is information concerning our equity compensation plans and individual compensation arrangements as of December 31, 2010.

	Equity Compensation Plan Information
Plan Category	Number of Securities To Be Issued Upon Exercise of Outstanding Options	Weighted Average Exercise Price of Outstanding Options		Number of Securities Remaining Available For Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by stockholders(1)	5,420,531	$	4.56	9,752,668
Equity compensation plans not approved by stockholders(2)	319,052		10.97	—
	5,739,583	$	4.91	9,752,668

(1)	We have one compensation plan: the 2005 Equity and Performance Incentive Plan, as amended by stockholder approval on May 20, 2009.
(2)	Represents stock option grant to purchase 319,052 shares of our common stock to our President and Chief Executive Officer pursuant to his employment agreement.

For additional information regarding our equity compensation plans, refer to the discussion in Note 11 to the audited consolidated financial statements included in Item 15 of this Annual Report on Form 10-K.

Table of Contents

Issuer Purchases of Equity Securities

Period	Number of Shares Purchased(1)	Weighted Average Price Paid per Share(1)		Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
January 1, 2010 through January 31, 2010	—	$	—	—	—
February 1, 2010 through February 28, 2010	—		—	—	—
March 1, 2010 through March 31, 2010	2,627		4.45	—	—
April 1, 2010 through April 30, 2010	35,914		5.27	—	—
May 1, 2010 through May 31, 2010	—		—	—	—
June 1, 2010 through June 30, 2010	330		3.85	—	—
July 1, 2010 through July 31, 2010	—		—	—	—
August 1, 2010 through August 31, 2010	—		—	—	—
September 1, 2010 through September 30, 2010	—		—	—	—
October 1, 2010 through October 31, 2010	—		—	—	—
November 1, 2010 through November 30, 2010	—		—	—	—
December 1, 2010 through December 31, 2010	—		—	—	—
Total	38,871	$	5.21	—	—

(1)

During the year ended December 31, 2010, we withheld 38,871 shares of common stock from employees to satisfy estimated tax obligations upon the vesting of restricted stock under the terms of our Amended and Restated 2005 Equity and Performance Incentive Plan. The value of the common stock that was withheld was based upon the closing price of our common stock on the applicable vesting dates.

Dividend Policy

We have never declared or paid a dividend on our common stock. We may retain any future earnings to support the development and expansion of our business or make additional payments under our credit facilities and, as a result, we may not pay cash dividends in the foreseeable future. Our payment of any future dividends will be at the discretion of our board of directors after taking into account various factors, including our financial condition, operating results, cash needs, growth plans and the terms of any credit agreements that we may be a party to at the time. Our credit facility and indenture governing the senior notes limits us from paying cash dividends or other payments or distributions with respect to our capital stock in excess of certain limitations. In addition, the terms of any future credit agreement may contain similar restrictions on our ability to pay dividends or make payments or distributions with respect to our capital stock.

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ITEM 6.

SELECTED FINANCIAL DATA

The selected historical consolidated financial data is derived from International Coal Group, Inc.’s audited consolidated financial statements as of December 31, 2010 and 2009 and for the years ended December 31, 2010, 2009 and 2008, which are included elsewhere in this Annual Report on Form 10-K. The selected historical consolidated financial data of International Coal Group, Inc. as of December 31, 2008, 2007 and 2006 and for the years ended December 31, 2007 and 2006 is derived from audited consolidated financial statements which are not included in this Annual Report on Form 10-K.

During the year ended December 31, 2010, we completed public offerings of 24,444,365 shares of our common stock, par value $0.01 per share (the “Common Stock”), at a public offering price of $4.47 per share, $115.0 million aggregate principal amount of 4.00% Convertible Senior Notes due 2017 (the “2017 Convertible Notes”) and $200.0 million aggregate principal amount of 9.125% Senior Secured Second-Priority Notes due 2018 (the “2018 Senior Notes”) pursuant to a shelf registration statement deemed effective by the Securities and Exchange Commission on January 15, 2010. We used $169.5 million of the net proceeds from the Common Stock and 2017 Convertible Notes offerings to finance the repurchase of $138.8 million aggregate principal amount of our 9.00% Convertible Senior Notes due 2012 (the “2012 Convertible Notes”). We used $189.0 million of the net proceeds from the 2018 Senior Notes offering to finance the repurchase of $175.0 million aggregate principal amount of our 10.25% Senior Notes due 2014 (the “2014 Senior Notes”). As a result of the repurchases, we recognized losses on extinguishment of the related debt totaling $24.0 million for the year ended December 31, 2010. Additionally, we entered into a series of exchange agreements in December 2009 (see below). One exchange agreement, as amended, provided for closing of additional exchanges on each of January 11, 2010 and January 19, 2010 for exchange transactions occurring in 2010. Subsequent to December 31, 2009, the noteholder exchanged $22,000 aggregate principal amount of 2012 Convertible Notes for 6,198,668 shares of our common stock. As a result of the exchanges settled in January 2010, we recognized a loss on extinguishment of the related debt totaling $5.4 million during the year ended December 31, 2010.

During the year ended December 31, 2009, we entered into a series of privately negotiated agreements pursuant to which we issued a total of 18,660,550 shares of our common stock in exchange for $63.5 million aggregate principal amount of our 9.00% Convertible Senior Notes due 2012. As a result of the exchanges, we recognized losses on extinguishment of the related debt totaling $13.3 million for the year ended December 31, 2009.

During the years ended December 31, 2008 and 2007, we recognized impairment losses of $37.4 million and $170.4 million, respectively. For 2008, $30.2 million of the loss related to impairment of goodwill at our ADDCAR subsidiary and $7.2 million related to impairment of long-lived assets. For 2007, the impairment loss related to impairment of goodwill at various of our business units.

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You should read the following data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with the financial information included elsewhere in this Annual Report on Form 10-K, including the consolidated financial statements of International Coal Group, Inc. and the related notes thereto. Amounts shown are in thousands, except per share data.

	Year ended December 31,
	2010			2009			2008			2007			2006
Statement of Operations Data:
Coal sales revenues	$	1,078,246		$	1,006,606		$	998,245		$	770,663		$	833,998
Freight and handling revenues		35,411			26,279			45,231			29,594			18,890
Other revenues		52,814			92,464			53,260			48,898			38,706
Total revenues		1,166,471			1,125,349			1,096,736			849,155			891,594
Costs and Expenses:
Cost of coal sales		850,328			832,214			882,983			732,112			739,914
Freight and handling costs		35,411			26,279			45,231			29,594			18,890
Cost of other revenues		48,331			36,089			35,672			34,046			29,418
Depreciation, depletion and amortization		104,566			106,084			96,047			86,517			72,218
Selling, general and administrative		35,569			32,749			38,147			33,325			34,578
Gain on sale of assets		(4,243	)		(3,659	)		(32,518	)		(38,656	)		(1,125	)
Goodwill impairment loss		—			—			30,237			170,402			—
Long-lived asset impairment loss		—			—			7,191			—			—
Total costs and expenses		1,069,962			1,029,756			1,102,990			1,047,340			893,893
Income (loss) from operations		96,509			95,593			(6,254	)		(198,185	)		(2,299	)
Interest and Other Income (Expense):
Loss on extinguishment of debt		(29,409	)		(13,293	)		—			—			—
Interest expense, net		(40,736	)		(53,044	)		(43,643	)		(35,989	)		(18,091	)
Other, net		—			—			—			319			2,113
Total interest and other income (expense)		(70,145	)		(66,337	)		(43,643	)		(35,670	)		(15,978	)
Income (loss) before income taxes		26,364			29,256			(49,897	)		(233,855	)		(18,277	)
Income tax benefit (expense)		3,750			(7,732	)		23,670			85,944			9,015
Net income (loss)		30,114			21,524			(26,227	)		(147,911	)		(9,262	)
Net (income) loss attributable to noncontrolling interest		(3	)		(66	)		—			349			(58	)
Net income (loss) attributable to International Coal Group, Inc.	$	30,111		$	21,458		$	(26,227	)	$	(147,562	)	$	(9,320	)

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	Year ended December 31,
	2010			2009			2008			2007			2006
Earnings Per Share:
Basic	$	0.15		$	0.14		$	(0.17	)	$	(0.97	)	$	(0.06	)
Diluted		0.15			0.14			(0.17	)		(0.97	)		(0.06	)
Weighted-Average Common Shares Outstanding:
Basic		197,366,978			153,630,446			152,632,586			152,304,461			152,028,165
Diluted		205,283,999			155,386,263			152,632,586			152,304,461			152,028,165
Balance Sheet Data (at year end):
Cash and cash equivalents	$	215,276		$	92,641		$	63,930		$	107,150		$	18,742
Total assets		1,479,697			1,367,960			1,350,647			1,303,363			1,316,891
Long-term debt and capital leases		326,350			384,309			432,870			391,248			180,035
Total liabilities		725,432			758,726			841,530			771,595			655,326
Total stockholders’ equity		754,265			609,234			509,117			531,768			661,565
Total liabilities and stockholders’ equity		1,479,697			1,367,960			1,350,647			1,303,363			1,316,891
Statement of Cash Flows Data:
Net cash from:
Operating activities	$	187,431		$	115,754		$	78,729		$	22,471		$	55,591
Investing activities		(89,341	)		(73,158	)		(124,040	)		(126,907	)		(160,769	)
Financing activities		24,545			(13,885	)		2,091			192,844			114,733
Capital expenditures		102,912			66,345			132,800			160,807			165,658

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion contains forward-looking statements that include numerous risks and uncertainties. Actual results could differ materially from those discussed in the forward-looking statements as a result of these risks and uncertainties, including those set forth in this Annual Report on Form 10-K under “Special Note Regarding Forward-Looking Statements” and under “Risk Factors.” You should read the following discussion in conjunction with “Selected Financial Data” and the audited and unaudited consolidated financial statements and notes thereto of International Coal Group, Inc. and its subsidiaries appearing elsewhere in this Annual Report on Form 10-K.

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Overview

We produce, process and sell coal from 13 regional mining complexes, which, as of December 31, 2010 were supported by 13 active underground mines, 10 active surface mines and 11 preparation plants located throughout West Virginia, Kentucky, Virginia, Maryland and Illinois. We have three reportable business segments, which are based on the coal regions in which we operate: (i) Central Appalachian, comprised of both surface and underground mines, (ii) Northern Appalachian, also comprised of both surface and underground mines and (iii) Illinois Basin, representing one underground mine. For more information about our reportable business segments, please see our audited consolidated financial statements and the notes thereto included in Item 15 of this Annual Report on Form 10-K. We also broker coal produced by others, the majority of which is shipped directly from the third-party producer to the ultimate customer. Our coal sales are primarily to large utilities and industrial customers in the eastern region of the United States and domestic and international steel companies and brokers. In addition, we generate other revenues from contract mining income, coalbed methane sales, ash disposal services, equipment and parts sales, equipment rebuild and maintenance services, royalties and coal handling and processing income.

Our primary expenses are wages and benefits, repair and maintenance, diesel fuel, blasting supplies, coal transportation, purchased coal, royalties, freight and handling and taxes incurred in selling our coal.

Certain Trends and Economic Factors Affecting the Coal Industry

Our revenues depend on the price at which we are able to sell our coal. The pricing environment for domestic steam and metallurgical coal during 2010 strengthened from the weak pricing experienced throughout most of 2009. Thermal coal prices and demand began to rapidly recover by mid-2010 driven by economic recovery, favorable weather and declining supply. Despite some weakening during the fourth quarter, thermal prices closed 2010 at significantly higher levels when compared to 2009. Metallurgical pricing also rebounded strongly throughout the year from the recessionary levels of 2009, again driven by global economic recovery. At the end of 2010, massive flooding in Australia created metallurgical supply shortages that continued to drive prices even higher. Conversely, continued regulatory constraints and rapidly increasing global commodity prices may significantly increase our costs, resulting in lower margins.

For additional information regarding some of the risks and uncertainties that affect our business and the industry in which we operate, see Item 1A. Risk Factors.

Critical Accounting Policies and Estimates

Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities. Management evaluates its estimates on an on-going basis. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Actual results may differ from the estimates used. Our actual results have generally not differed materially from our estimates. However, we monitor such differences and, in the event that actual results are significantly different from those estimated, we disclose any related impact on our results of operations, financial position and cash flows. Note 2 to our audited consolidated financial statements included in Item 15 of this Annual Report on Form 10-K provides a description of our significant accounting policies. We believe that of these significant accounting policies, the following involve a higher degree of judgment or complexity:

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Revenue Recognition

Coal revenues result from sales contracts (long-term coal agreements or purchase orders) with electric utilities, industrial companies or other coal-related organizations, primarily in the eastern United States. Revenue is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable and the title or risk of loss has passed in accordance with the terms of the sales agreement. Under the typical terms of these agreements, risk of loss transfers to the customers at the mine or port, when the coal is loaded on the rail, barge, truck or other transportation sources that deliver coal to its destination.

Coal sales revenues also result from the sale of brokered coal produced by others. The revenues related to brokered coal sales are included in coal sales revenues on a gross basis and the corresponding cost of the coal from the supplier is recorded in cost of coal sales in accordance with ASC Subtopic 605-45, Principal Agent Considerations (“ASC 605-45”).

Freight and handling costs paid to third-party carriers and invoiced to coal customers are recorded as freight and handling costs and freight and handling revenues, respectively.

Other revenues primarily consist of contract mining income, coalbed methane sales, ash disposal services, equipment and parts sales, equipment rebuild and maintenance services, royalties and coal handling and processing income. With respect to other revenues recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and do not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the seller’s price to the buyer is fixed or determinable and collectibility is reasonably assured. Advance payments received are deferred and recognized in revenue when earned.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts represents management’s best estimate of the amount of probable credit losses in our existing accounts receivable. We establish provisions for losses on accounts receivable when it is probable that all or part of the outstanding balance will not be collected. Management regularly reviews collectability and establishes or adjusts the allowance as necessary. Although we believe the estimate of credit losses we have made is reasonable and appropriate, inability to collect outstanding accounts receivable amounts could materially impact our reported financial results.

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Reclamation

Our asset retirement obligations arise from the Federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. We record these reclamation obligations according to the provisions of ASC Topic 410, Asset Retirement and Environmental Obligations (“ASC 410”). ASC 410 requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which the legal obligation associated with the retirement of the long-lived asset is incurred. Fair value of reclamation liabilities is determined based on the present value of the estimated future expenditures. 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 future value, and the capitalized cost is depreciated over the useful life of the related asset. If the assumptions used to estimate the liability do not materialize as expected or regulatory changes were to occur, reclamation costs or obligations to perform reclamation and mine closure activities could be materially different than currently estimated. To settle the liability, the mine property is reclaimed and, to the extent there is a difference between the liability and the amount of cash paid to perform the reclamation, a gain or loss upon settlement is recognized. On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures and revisions to cost estimates and productivity assumptions to reflect current experience. At December 31, 2010, we had recorded asset retirement obligation liabilities of $79.1 million, including amounts reported as current liabilities. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2010, we estimate that the aggregate undiscounted cost of final mine closure is approximately $155.5 million.

Advance Royalties

We are required, under certain royalty lease agreements, to make minimum royalty payments whether or not mining activity is being performed on the leased property. These minimum payments may be recoupable once mining begins on the leased property. The recoupable minimum royalty payments are capitalized and amortized based on the units-of-production method at a rate defined in the lease agreement once mining activities begin. Unamortized deferred royalty costs are expensed when mining has ceased or a decision is made not to mine on such property. We have recorded an allowance for such circumstances based upon management’s plans for the continuing operation of existing mine sites or for when properties will be developed and/or mined. We believe the estimate for losses is appropriate. However, actual amounts that we recoup through mining activity could vary resulting in a material impact to our financial results.

Inventories

Coal inventories are stated at lower of average cost or market and represent coal contained in stockpiles, including those tons that have been mined and hauled to our loadout facilities, but not yet shipped to customers. These inventories are stated in clean coal equivalent tons and take into account any loss that may occur during the processing stage. Coal must be of a quality that can be sold on existing sales orders to be carried as coal inventory. Coal inventory volumes are determined through survey procedures. The surveys involve assumptions, inherent uncertainties and the application of management judgment.

Parts and supplies inventories are valued at average cost, less an allowance for obsolescence. We establish provisions for losses in parts and supplies inventory values through analysis of turnover of inventory items and adjust the allowance as necessary.

Although we believe the estimates we have made with respect to the valuation of our coal and parts and supplies inventories are reasonable and appropriate, changes in assumptions (coal inventories) or actual utilization of items (parts and supplies inventories) could materially impact our reported financial results.

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Depreciation, Depletion and Amortization

Property, plant, equipment and mine development, which includes coal lands and mineral rights, are recorded at cost, which includes construction overhead and interest, where applicable. Expenditures for major renewals and betterments are capitalized, while expenditures for maintenance and repairs are expensed as incurred.

Mine development, coal lands and mineral rights costs are amortized or depleted using the units-of-production method, based on estimated recoverable tons. There are uncertainties inherent in estimating quantities of recoverable tons related to particular mine development, coal lands and mineral rights areas. Recoverable tons contained in an area are based on engineering estimates which can, and often do, change as the tons are mined. Any change in the number of recoverable tons contained in mine development, coal lands and mineral rights areas will result in a change in the depletion or amortization rate and corresponding expense. For the year ended December 31, 2010, we recognized $7.8 million of depletion expense.

Other property, plant and equipment are depreciated using the straight-line method based on estimated useful lives.

Coal Reserves

There are numerous uncertainties inherent in estimating quantities of economically recoverable coal reserves, many of which 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 internal engineers and geologists. Reserve estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Acquisitions, sales or dispositions of coal properties will also change the amount of economically recoverable coal reserves. Some of the factors and assumptions that impact economically recoverable reserve estimates include geological conditions, historical production from the area compared with production from other producing areas, the assumed effects of regulations and taxes by governmental agencies, assumptions governing future prices and future operating costs.

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 the classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to these reserves will likely vary from estimates, and these variances may be material. At December 31, 2010, we estimate that we had 1.1 billion tons of coal reserves.

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Asset Impairments

We follow ASC Subtopic 360-10-45, Impairment or Disposal of Long-Lived Assets, which requires that projected future cash flows from use and disposition of assets be compared with the carrying amounts of those assets when impairment indicators are present. When the sum of projected cash flows is less than the carrying amount, impairment losses are indicated. If the fair value of the assets is less than the carrying amount of the assets, an impairment loss is recognized. In determining such impairment losses, discounted cash flows or asset appraisals are utilized to determine the fair value of the assets being evaluated. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine’s underlying costs are not recoverable in the future, reclamation and mine closure obligations are accelerated and the mine closure accrual is increased accordingly. To the extent it is determined asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized. Recognition of an impairment will decrease asset values, increase operating expenses and decrease net income. In December 2008, we made the decision to permanently close our Sago mine during the first quarter of 2009. Upon making this decision, we performed an impairment test of related mine development costs, which resulted in a $7.2 million non-cash impairment charge to reduce the carrying amount of these assets to their estimated fair value. There were no other impairment charges related to long-lived assets recognized in the periods covered by this Annual Report on Form 10-K as a result of our impairment tests.

Financial Instruments

Pursuant to ASC Subtopic 470-20, Debt with Conversion and Other Options, our convertible notes are accounted for as convertible debt and the embedded conversion option in the convertible notes has been accounted for as a component of equity.

Coal Supply Agreements

Our below-market coal supply agreements (sales contracts) represent coal supply agreements acquired through acquisitions accounted for as business combinations for which the prevailing market price for coal specified in the contract was in excess of the contract price. In accordance with ASC Topic 805, Business Combinations, value was based on discounted cash flows resulting from the difference between the below-market contract price and the prevailing market price at the date of acquisition. The below-market coal supply agreements are amortized on the basis of tons shipped over the term of the respective contract. Determination of fair value requires management judgment and often involves the use of significant estimates and assumptions.

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Share Based Compensation

We account for our share based awards in accordance with ASC Topic 718, Compensation—Stock Compensation (“ASC 718”). Share based compensation expense is generally measured at the grant date and recognized as expense over the vesting period of the award. We utilize restricted stock and stock options as part of our share based compensation program. Determining fair value requires us to make a number of assumptions, including expected volatility, expected term and risk-free interest rate. Expected volatility is estimated using both historical and market data. Expected term is based on historical data and expected behavior. Risk-free interest rates are based on the rates of zero coupon U.S. Treasury bonds with similar maturities on the date of grant. The assumptions used in calculating the fair value of share based awards represent our best estimates and involve inherent uncertainties and the application of management judgment. Although we believe the assumptions and estimates we have made are reasonable and appropriate, different assumptions could materially impact our reported financial results.

Debt Issuance Costs

Debt issuance costs reflect fees incurred to obtain financing. Debt issuance costs related to our outstanding debt are amortized over the life of the related debt. From time to time, we write-off deferred financing fees as a result of amending or canceling related debt and/or credit agreements. Such write-offs could be material and occur in the period that the amendment or cancellation occurs.

Income Taxes

We account for income taxes in accordance with ASC Topic 740, Income Taxes (“ASC 740”), which requires the recognition of deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. ASC 740 also requires that deferred tax assets, if it is more likely than not that some portion or all of the deferred tax asset will not be realized, be reduced by a valuation allowance. In evaluating the need for a valuation allowance, we take into account various factors, including the timing of the realization of deferred tax liabilities, the expected level of future taxable income and available tax planning strategies. If future taxable income is lower than expected or if expected tax planning strategies are not available as anticipated, we may record a change to the valuation allowance through income tax expense in the period the determination is made.

A tax position is initially recognized in the financial statements when it is more likely than not the position will be sustained upon examination by applicable tax authorities. Such tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with the tax authority assuming full knowledge of the position and all relevant facts.

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Postretirement Medical Benefits

Some of our subsidiaries have liabilities for postretirement benefit cost obligations. Liabilities for postretirement benefits are not funded. The liability is actuarially determined and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for postretirement benefits. The discount rate assumption reflects the rates available on a hypothetical portfolio of high-quality fixed income debt instruments whose cash flows match the timing and amount of expected benefit payments. Our estimates of these costs are adjusted based upon actuarially determined amounts using a rate of 5.50% as of December 31, 2010. If we were to decrease our estimate of the discount rate to 4.50%, the present value of our postretirement liability would increase by approximately $8.9 million. If we were to increase our estimate of the discount rate to 6.50%, the present value of our postretirement liability would decrease by approximately $7.0 million. We make assumptions related to future trends for medical care costs in the estimates of retiree healthcare and work-related injury and illness obligations. The future healthcare cost trend rate represents the rate at which healthcare costs are expected to increase over the life of the plan. The healthcare cost trend rate assumptions are determined primarily based upon our, and our predecessor’s, historical rate of change in retiree healthcare costs. The postretirement expense in the operating period ended December 31, 2010 was based on an assumed heath care inflationary rate of 7.1% in the operating period decreasing to 4.7% in 2081, which represents the ultimate healthcare cost trend rate for the remainder of the plan life. A one-percentage point increase in the assumed ultimate healthcare cost trend rate would increase the service and interest cost components of the postretirement benefit expense for the year ended December 31, 2010 by $1.6 million and increase the accumulated postretirement benefit obligation at December 31, 2010 by $9.4 million. A one-percentage point decrease in the assumed ultimate healthcare cost trend rate would decrease the service and interest cost components of the postretirement benefit expense for the year ended December 31, 2010 by $1.3 million and decrease the accumulated postretirement benefit obligation at December 31, 2010 by $7.6 million. If our assumptions do not materialize as expected or if regulatory changes were to occur, actual cash expenditures and costs that we incur could differ materially from our current estimates.

Workers’ Compensation

Workers’ compensation is a system by which individuals who sustain personal injuries due to job-related accidents are compensated for their disabilities, medical costs and, on some occasions, for the costs of their rehabilitation, and by which the survivors of workers who suffer fatal injuries receive compensation for lost financial support. The workers’ compensation laws are administered by state agencies with each state having its own rules and regulations regarding compensation that is owed to an employee who is injured in the course of employment or the beneficiary of an employee that suffers fatal injuries in the course of employment. Our operations are covered through a combination of participation in a state run program and insurance policies. Our estimates of these costs are adjusted based upon actuarially determined amounts using a discount rate of 4.5% as of December 31, 2010. The discount rate assumption reflects the rates available on a hypothetical portfolio of high-quality fixed income debt instruments whose cash flows match the timing and amount of expected benefit payments. If we were to decrease our estimate of the discount rate to 3.5%, the present value of our workers’ compensation liability would increase by approximately $0.5 million. If we were to increase our estimate of the discount rate to 5.5%, the present value of our workers’ compensation liability would decrease by approximately $0.4 million. At December 31, 2010, we have recorded an accrual of $10.4 million for workers’ compensation benefits. Actual losses may differ from these estimates, which could increase or decrease our costs.

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Coal Workers’ Pneumoconiosis

We are responsible under various federal statutes, and various states’ statutes, for the payment of medical and disability benefits to eligible employees resulting from occurrences of coal workers’ pneumoconiosis disease (black lung). Our operations are covered through a combination of participation in a state run program and insurance policies. We accrue for any self-insured liability by recognizing costs when it is probable that a covered liability has been incurred and the cost can be reasonably estimated. Our estimates of these costs are adjusted based upon actuarially determined amounts using a discount rate of 5.5% as of December 31, 2010. The discount rate assumption reflects the rates available on a hypothetical portfolio of high-quality fixed income debt instruments whose cash flows match the timing and amount of expected benefit payments. If we were to decrease our estimate of the discount rate to 4.5%, the present value of our black lung benefit liability would increase by approximately $5.2 million. If we were to increase our estimate of the discount rate to 6.5%, the present value of our black lung benefit liability would decrease by approximately $4.0 million. At December 31, 2010, we have recorded an accrual of $26.3 million for black lung benefits. Individual losses in excess of $0.5 million at the state level and $0.5 million at the federal level are covered by our large deductible stop loss insurance. Actual losses may differ from these estimates, which could increase or decrease our costs.

Coal Industry Retiree Health Benefit Act of 1992

The Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”) provides for the funding of health benefits for certain union retirees and their spouses or dependants. The Coal Act established the Combined Fund into which employers who are “signatory operators” and “related persons” are obligated to pay annual premiums for beneficiaries. The Coal Act also created a second benefit fund for miners who retired between July 21, 1992 and September 30, 1994 and whose former employers are no longer in business. Upon the consummation of the business combination with Anker, we assumed Anker’s Coal Act liabilities, which were estimated to be $1.4 million at December 31, 2010. Actual losses may differ from these estimates, which could increase or decrease our costs. Our estimates of these costs are adjusted based upon actuarially determined amounts using a discount rate of 4.75% as of December 31, 2010. The discount rate assumption reflects the rates available on a hypothetical portfolio of high-quality fixed income debt instruments whose cash flows match the timing and amount of expected benefit payments. If we were to decrease our estimate of the discount rate to 3.75%, the present value of our Coal Act liability would increase by approximately $0.1 million. If we were to increase our estimate of the discount rate to 5.75%, the present value of our Coal Act liability would decrease by approximately $0.1 million. Prior to the business combination with Anker, we did not have any liability under the Coal Act.

Corporate Vacation Policy

During 2009, we changed our policy related to when employees are credited with vacation time. Under the original policy, employees earned their vacation in the year prior to vesting, and were vested with 100% of their annual vacation time on January 1st of each year. Under the revised policy, employees are vested in their vacation time ratably throughout the year as it is earned. Accordingly, we did not record accruals in 2009 for vacation time to be vested in 2010. If we continued to account for vacation under the old policy, we would have recognized additional cost of coal sales, cost of other revenues and selling, general and administrative expenses of $7.0 million, $0.4 million and $0.5 million, respectively, for the year ended December 31, 2009.

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Results of Operations

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

Revenues, coal sales revenues by reportable segment and tons sold by reportable segment

The following table depicts consolidated revenues for the years ended December 31, 2010 and 2009 for the indicated categories:

	Year ended December 31,				Increase (Decrease)
	2010		2009		$ or Tons			%
	(in thousands, except percentages and per ton data)
Coal sales revenues	$	1,078,246	$	1,006,606	$	71,640		7	%
Freight and handling revenues		35,411		26,279		9,132		35	%
Other revenues		52,814		92,464		(39,650	)	(43	)%
Total revenues	$	1,166,471	$	1,125,349	$	41,122		4	%

Tons sold		16,342		16,833		(491	)	(3	)%
Coal sales revenue per ton	$	65.98	$	59.80	$	6.18		10	%

The following table depicts coal sales revenues by reportable segment for years ended December 31, 2010 and 2009:

	Year ended December 31,				Increase (Decrease)
	2010		2009		$			%
	(in thousands, except percentages)
Central Appalachian	$	683,994	$	682,088	$	1,906		*	%
Northern Appalachian		278,877		207,022		71,855		35	%
Illinois Basin		87,654		75,817		11,837		16	%
Ancillary		27,721		41,679		(13,958	)	(33	)%
Total coal sales revenues	$	1,078,246	$	1,006,606	$	71,640		7	%

The following table depicts tons sold by reportable segment for the years ended December 31, 2010 and 2009:

	Year ended December 31,				Increase (Decrease)
	2010		2009		Tons		%
	(in thousands, except percentages)
Central Appalachian		9,324		9,984	(660	)	(7	)%
Northern Appalachian		4,120		3,803	317		8	%
Illinois Basin		2,383		2,254	129		6	%
Ancillary		515		792	(277	)	(35	)%
Total tons sold		16,342		16,833	(491	)	(3	)%

* Not meaningful

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Coal sales revenues—Coal sales revenues are derived from sales of produced coal and brokered coal contracts. Coal sales revenues increased for the year ended December 31, 2010 compared to the year ended December 31, 2009, primarily due to an increase in sales realization of $6.18 per ton resulting from favorable pricing of metallurgical coal. Offsetting the increase in sales realization was a 3% decrease in tons sold.

Central Appalachian. Coal sales revenues from our Central Appalachian segment for the year ended December 31, 2010 increased over the year ended December 31, 2009 due to an increase in sales realization of $5.04 per ton, primarily driven by higher average contract prices for metallurgical coal. Partially offsetting this increase in sales realization was a 7% decrease in tons sold, largely driven by the expiration of certain coal supply agreements.

Northern Appalachian. For the year ended December 31, 2010, our Northern Appalachian coal sales revenues increased compared to the year ended December 31, 2009 as a result of increased sales realization of $13.27 per ton, as well as an 8% increase in tons sold. The increase in sales realization and tons sold is a result of increased participation in the spot market due to more favorable pricing of metallurgical coal.

Illinois Basin. The increase in coal sales revenues from our Illinois Basin segment for the year ended December 31, 2010 was primarily due to an increase in sales realization of $3.15 per ton, as well as a 6% increase in tons sold, primarily on long-term thermal coal supply contracts.

Ancillary. Our Ancillary segment’s coal sales revenues are comprised of coal sold under brokered coal contracts. For the year ended December 31, 2010, our Ancillary coal sales revenues decreased 33% due to a 35% decrease in tons sold related to the expiration of certain coal supply agreements, as well as to decreased shipments on various remaining contracts. This decrease was partially offset by increased realization of $1.23 per ton sold.

Freight and handling revenues and costs—Freight and handling revenues represent reimbursement of freight and handling costs for shipments under certain contracts for which we initially pay the costs and are then reimbursed by the customer. Freight and handling revenues and costs increased for the year ended December 31, 2010 compared to the year ended December 31, 2009, primarily due to an increase in sales volumes on shipments for which the related freight and handling costs are reimbursed. Additionally, our subsidiary, ADDCAR, sold a highwall mining machine during the year ended December 31, 2010, with the related shipping cost reimbursement included in freight and handling revenues and costs. There were no comparable shipping costs incurred during the year ended December 31, 2009.

Other revenues—The decrease in other revenues for the year ended December 31, 2010 compared to the year ended December 31, 2009 was due to $34.9 million in payments for early termination of coal supply agreements and lost margin on pre-termination shipments and a $7.7 million gain on the termination of a below-market contract during 2009, as well as to decreased contract mining revenues in 2010. Partially offsetting these decreases was an increase in revenues from the sale of highwall mining systems.

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Costs and expenses

The following table depicts cost of operations for the years ended December 31, 2010 and 2009 for the indicated categories:

	Year ended December 31,						Increase (Decrease)
	2010			2009			$			%
	(in thousands, except percentages and per ton data)
Cost of coal sales	$	850,328		$	832,214		$	18,114		2	%
Freight and handling costs		35,411			26,279			9,132		35	%
Cost of other revenues		48,331			36,089			12,242		34	%
Depreciation, depletion and amortization		104,566			106,084			(1,518	)	(1	)%
Selling, general and administrative expenses		35,569			32,749			2,820		9	%
Gain on sale of assets		(4,243	)		(3,659	)		(584	)	(16	)%
Total costs and expenses	$	1,069,962		$	1,029,756		$	40,206		4	%

Cost of coal sales per ton	$	52.03		$	49.44		$	2.59		5	%

The following table depicts cost of coal sales by reportable segment for the years ended December 31, 2010 and 2009:

	Year ended December 31,				Increase (Decrease)
	2010		2009		$			%
	(in thousands, except percentages)
Central Appalachian	$	542,942	$	554,368	$	(11,426	)	(2	)%
Northern Appalachian		216,127		182,607		33,520		18	%
Illinois Basin		65,880		62,958		2,922		5	%
Ancillary		25,379		32,281		(6,902	)	(21	)%
Cost of coal sales	$	850,328	$	832,214	$	18,114		2	%

Cost of coal sales—For the year ended December 31, 2010, cost of coal sales increased compared to the year ended December 31, 2009, primarily as a result of a 5% increase in cost of coal sales per ton, partially offset by a 3% decrease in tons sold.

Central Appalachian. Cost of coal sales from our Central Appalachian segment decreased primarily due to a 7% decrease in tons sold. Offsetting the decrease in tons sold was an increase in cost of coal sales per ton from $55.53 per ton for the year ended December 31, 2009 to $58.23 per ton for the year ended December 31, 2010. The increase in cost of coal sales per ton is primarily due to increases in labor costs and royalties, taxes and fees. Labor costs per ton increased in 2010 primarily as a result of a change in our policy during the year ended December 31, 2009 related to when employees are credited with vacation time, as well as by enhanced regulatory compliance standards. Royalties, taxes and fees increased on a per ton basis as a result of increased realization per ton sold and increased royalty rates on certain leased reserves. Cost of coal sales per ton also increased due to higher roof control costs, benefit costs and other miscellaneous direct costs. Partially offsetting these increases in cost per ton was a decrease in fuel, lubricants and chemicals as diesel fuel costs have declined as compared to the year ended December 31, 2009.

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Northern Appalachian. Our Northern Appalachian segment cost of coal sales increased due to an 8% increase in tons sold and an increase in cost of coal sales per ton from $48.01 per ton for the year ended December 31, 2009 to $52.47 per ton for the year ended December 31, 2010. The increase in cost per ton was primarily due to increases in labor, royalties, taxes and fees and repairs and maintenance costs. Labor costs increased in 2010 primarily as a result of a change in our policy during the year ended December 31, 2009 related to when employees are credited with vacation time, enhanced regulatory compliance standards and increased contractor rates. Royalties, taxes and fees increased on a per ton basis as a result of increased realization per ton sold and increased royalty rates on certain leased reserves. Repairs and maintenance costs increased on a per ton basis as more resources were directed towards repairing rather than replacing equipment.

Illinois Basin. For the year ended December 31, 2010, cost of coal sales from our Illinois Basin segment increased due to a 6% increase in tons sold, offset by a decrease in cost per ton from $27.93 for the year ended December 31, 2009 to $27.64 for the year ended December 31, 2010. Cost of coal sales per ton decreased primarily due to decreases in labor costs and benefit costs. Labor costs per ton decreased as a result of improved recovery of coal due to favorable mining conditions. Benefit costs decreased due to a decrease in worker’s compensation expense. Partially offsetting these decreases were increases in contract labor, operating supplies and repairs and maintenance costs. Contract labor increased as a result of enhanced regulatory compliance standards. Operating supplies and repairs and maintenance per ton increased primarily as a result of purchasing more materials required to maintain aging areas of the mine and delays in replacing equipment.

Ancillary. Cost of coal sales from our Ancillary segment decreased for the year ended December 31, 2010 due to a 35% decrease in tons sold related to the expiration of certain brokered coal contracts, partially offset by an $8.54 increase in cost per ton.

Cost of other revenues—For the year ended December 31, 2010, cost of other revenues increased primarily due to a $10.0 million payment made for the early termination of a coal supply agreement and an increase in costs related to sales of highwall mining systems. Partially offsetting these increases in cost of other revenues was a decrease in labor and benefit costs as a result of the termination of certain contract mining contracts.

Depreciation, depletion and amortization—Depreciation, depletion and amortization expense remained relatively consistent compared to the year ended December 31, 2009.

Selling, general and administrative expenses—Selling, general and administrative expenses for the year ended December 31, 2010 increased primarily due to the resolution of certain legal matters during the year ended December 31, 2009, as well as an increase in legal and professional fees in 2010.

Gain on sale of assets—Gain on sale of assets increased for the year ended December 31, 2010 due to a $3.5 million gain related to the sale of a highwall mining system previously used in operations during the year ended December 31, 2010 versus a $2.9 million gain on the sale of a loadout facility during the year ended December 31, 2009.

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Adjusted EBITDA by Reportable Segment

Adjusted EBITDA represents net income before deducting interest, income taxes, depreciation, depletion, amortization, loss on extinguishment of debt and noncontrolling interest. Adjusted EBITDA is presented because it is an important supplemental measure of our performance used by our chief operating decision maker in such areas as capital investment and allocation of resources. Other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. Adjusted EBITDA is reconciled to its most comparable GAAP measure on page 83 of this Annual Report on Form 10-K and in Note 20 to our consolidated financial statements for the year ended December 31, 2010.

The following table depicts reportable segment Adjusted EBITDA for the years ended December 31, 2010 and 2009:

	Year ended December 31,						Increase (Decrease)
	2010			2009			$			%
	(in thousands, except percentages)
Central Appalachian	$	146,700		$	169,842		$	(23,142	)	(14	)%
Northern Appalachian		58,622			31,005			27,617		89	%
Illinois Basin		23,736			14,405			9,331		65	%
Ancillary		(27,983	)		(13,575	)		(14,408	)	(106	)%
Total Adjusted EBITDA	$	201,075		$	201,677		$	(602	)	*	%

* Not meaningful

Central Appalachian. Adjusted EBITDA for the year ended December 31, 2010 decreased compared to the year ended December 31, 2009, primarily due to $27.5 million received for early termination of coal supply agreements and lost margin on pre-termination shipments and a $7.7 million gain on the termination of a below-market contract in 2009, as well as a 660,000 ton decrease in tons sold. Partially offsetting these decreases was a $2.34 per ton increase in profit margins.

Northern Appalachian. The increase in Adjusted EBITDA was due to increased profit margins of $8.81 per ton as a result of increased participation in the spot market due to more favorable pricing of metallurgical coal. Adjusted EBITDA also increased due to an increase of approximately 317,000 tons sold. Offsetting these increases was a $10.0 million payment made in 2010 for the early termination of a coal supply agreement.

Illinois Basin. Adjusted EBITDA increased during the year ended December 31, 2010 due to an increase in profit margins of $3.44 per ton, as well as an increase of approximately 129,000 tons sold.

Ancillary. The decrease in Adjusted EBITDA was primarily due to a decrease in profit margins of $7.31 per ton and a decrease of approximately 277,000 tons sold related to the expiration of brokered coal contracts, as well as to decreased shipments on various remaining contracts. Further contributing to the decrease from our Ancillary segment was a decrease of $7.4 million received in the settlement of contract terminations during the year ended December 31, 2009 and decreased contract mining income. Offsetting these decreases was an increase in Adjusted EBITDA related to sales of highwall mining machines.

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Reconciliation of Adjusted EBITDA to Net income (loss) by Reportable Segment

The following tables reconcile Adjusted EBITDA to net income (loss) by reportable segment for the years ended December 31, 2010 and 2009:

	Year ended December 31,				Increase (Decrease)
	2010		2009		$			%
	(in thousands, except percentages)
Central Appalachian
Net income attributable to International Coal Group, Inc.	$	72,131	$	91,841	$	(19,710	)	(21	)%
Depreciation, depletion and amortization		70,045		71,298		(1,253	)	(2	)%
Interest expense, net		4,463		4,488		(25	)	(1	)%
Income tax expense		61		2,215		(2,154	)	(97	)%
Adjusted EBITDA	$	146,700	$	169,842	$	(23,142	)	(14	)%

	Year ended December 31,				Increase (Decrease)
	2010		2009		$			%
	(in thousands, except percentages)
Northern Appalachian
Net income attributable to International Coal Group, Inc.	$	31,612	$	7,994	$	23,618		295	%
Depreciation, depletion and amortization		20,491		20,991		(500	)	(2	)%
Interest expense, net		690		531		159		30	%
Income tax expense		5,826		1,423		4,403		309	%
Noncontrolling interest		3		66		(63	)	(95	)%
Adjusted EBITDA	$	58,622	$	31,005	$	27,617		89	%

	Year ended December 31,						Increase (Decrease)
	2010			2009			$			%
	(in thousands, except percentages)
Illinois Basin
Net income attributable to International Coal Group, Inc.	$	15,035		$	6,080		$	8,955		147	%
Depreciation, depletion and amortization		9,131			7,957			1,174		15	%
Interest expense, net		247			579			(332	)	(57	)%
Income tax benefit		(677	)		(211	)		(466	)	(221	)%
Adjusted EBITDA	$	23,736		$	14,405		$	9,331		65	%

	Year ended December 31,						Increase (Decrease)
	2010			2009			$			%
	(in thousands, except percentages)
Ancillary
Net loss attributable to International Coal Group, Inc.	$	(88,667	)	$	(84,457	)	$	(4,210	)	(5	)%
Depreciation, depletion and amortization		4,899			5,838			(939	)	(16	)%
Interest expense, net		35,336			47,446			(12,110	)	(26	)%
Income tax (benefit) expense		(8,960	)		4,305			(13,265	)	(308	)%
Loss on extinguishment of debt		29,409			13,293			16,116		121	%
Adjusted EBITDA	$	(27,983	)	$	(13,575	)	$	(14,408	)	(106	)%

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	Year ended December 31,					Increase (Decrease)
	2010			2009		$			%
	(in thousands, except percentages)
Consolidated
Net income attributable to International Coal Group, Inc.	$	30,111		$	21,458	$	8,653		40	%
Depreciation, depletion and amortization		104,566			106,084		(1,518	)	(1	)%
Interest expense, net		40,736			53,044		(12,308	)	(23	)%
Income tax (benefit) expense		(3,750	)		7,732		(11,482	)	(148	)%
Loss on extinguishment of debt		29,409			13,293		16,116		121	%
Noncontrolling interest		3			66		(63	)	(95	)%
Adjusted EBITDA	$	201,075		$	201,677	$	(602	)	*	%

* Not meaningful

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Results of Operations

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

Revenues, coal sales revenues by reportable segment and tons sold by reportable segment

The following table depicts consolidated revenues for the years ended December 31, 2009 and 2008 for the indicated categories:

	Year ended December 31,				Increase (Decrease)
	2009		2008		$ or Tons			%
	(in thousands, except percentages and per ton data)
Coal sales revenues	$	1,006,606	$	998,245	$	8,361		1	%
Freight and handling revenues		26,279		45,231		(18,952	)	(42	)%
Other revenues		92,464		53,260		39,204		74	%
Total revenues	$	1,125,349	$	1,096,736	$	28,613		3	%

Tons sold		16,833		18,914		(2,081	)	(11	)%
Coal sales revenue per ton	$	59.80	$	52.78	$	7.02		13	%

The following table depicts coal sales revenues by reportable segment for years ended December 31, 2009 and 2008:

	Year ended December 31,				Increase (Decrease)
	2009		2008		$			%
	(in thousands, except percentages)
Central Appalachian	$	682,088	$	672,077	$	10,011		1	%
Northern Appalachian		207,022		209,932		(2,910	)	(1	)%
Illinois Basin		75,817		69,796		6,021		9	%
Ancillary		41,679		46,440		(4,761	)	(10	)%
Total coal sales revenues	$	1,006,606	$	998,245	$	8,361		1	%

The following table depicts tons sold by reportable segment for the years ended December 31, 2009 and 2008:

	Year ended December 31,				Increase (Decrease)
	2009		2008		Tons		%
	(in thousands, except percentages)
Central Appalachian		9,984		11,617	(1,633	)	(14	)%
Northern Appalachian		3,803		3,937	(134	)	(3	)%
Illinois Basin		2,254		2,331	(77	)	(3	)%
Ancillary		792		1,029	(237	)	(23	)%
Total tons sold		16,833		18,914	(2,081	)	(11	)%

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Coal sales revenues—Coal sales revenues are derived from sales of produced coal and brokered coal contracts. Coal sales revenues increased 1% for the year ended December 31, 2009 compared to the year ended December 31, 2008, primarily due to a 13% increase in sales realization per ton resulting from favorable pricing on sales contracts entered into throughout 2008. Partially offsetting the impact of the improved realization per ton was an 11% decrease in tons sold, primarily resulting from decreased participation in the spot market.

Central Appalachian. Coal sales revenues from our Central Appalachian segment for the year ended December 31, 2009 increased over the year ended December 31, 2008, primarily due to an increase in sales realization of $10.47 per ton, which was driven by higher average contract prices of our coal. Partially offsetting the increase in realization was a 14% decrease in tons sold, largely driven by decreased spot market sales.

Northern Appalachian. For the year ended December 31, 2009, our Northern Appalachian coal sales revenues decreased over the same period in 2008 due to a 3% decrease in tons sold, primarily due to reduced spot market sales. Partially offsetting the decrease in tons sold was an increase in sales realization of $1.11 per ton resulting from higher average prices of coal sold under our coal supply contracts.

Illinois Basin. The increase in coal sales revenues from our Illinois Basin segment for the year ended December 31, 2009 was due to an increase in sales realization of $3.69 per ton, partially offset by a 3% decrease in tons sold.

Ancillary. Our Ancillary segment’s coal sales revenues are comprised of coal sold under brokered coal contracts. For the year ended December 31, 2009, our Ancillary coal sales revenues decreased due to a 23% decrease in tons sold related to the expiration of certain coal supply agreements, as well as to decreased shipments on various remaining contracts. This decrease in tons sold was partially offset by an increase in sales realization of $7.53 per ton sold.

Freight and handling revenues and costs—Freight and handling revenues represent reimbursement of freight and handling costs for shipments under certain contracts for which we initially pay the costs and are then reimbursed by the customer. Freight and handling revenues and costs decreased for the year ended December 31, 2009 compared to the year ended December 31, 2008 primarily due to a decrease in sales volumes on shipments for which the related freight and handling costs are reimbursed. Additionally, transportation rates and fuel surcharges were reduced as a result of decreased fuel prices.

Other revenues—The increase in other revenues for the year ended December 31, 2009 compared to the year ended December 31, 2008 was due to $34.9 million in payments received for the early termination of coal supply agreements and the lost margin on pre-termination shipments and a $7.7 million non-cash gain on the termination of a below-market contract, as well as a sale of a highwall mining system during the year ended December 31, 2009. Partially offsetting these increases were decreases in coalbed methane revenue, contract mining income and sales of scrap materials.

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Costs and expenses

The following table depicts cost of operations for the years ended December 31, 2009 and 2008 for the indicated categories:

	Year ended December 31,						Increase (Decrease)
	2009			2008			$			%
	(in thousands, except percentages and per ton data)
Cost of coal sales	$	832,214		$	882,983		$	(50,769	)	(6	)%
Freight and handling costs		26,279			45,231			(18,952	)	(42	)%
Cost of other revenues		36,089			35,672			417		1	%
Depreciation, depletion and amortization		106,084			96,047			10,037		10	%
Selling, general and administrative expenses		32,749			38,147			(5,398	)	(14	)%
Gain on sale of assets		(3,659	)		(32,518	)		28,859		89	%
Impairment loss		—			37,428			(37,428	)	(100	)%
Total costs and expenses	$	1,029,756		$	1,102,990		$	(73,234	)	(7	)%

Cost of coal sales per ton	$	49.44		$	46.68		$	2.76		6	%

The following table depicts cost of coal sales by reportable segment for the years ended December 31, 2009 and 2008:

	Year ended December 31,				Increase (Decrease)
	2009		2008		$			%
	(in thousands, except percentages)
Central Appalachian	$	554,368	$	595,683	$	(41,315	)	(7	)%
Northern Appalachian		182,607		193,389		(10,782	)	(6	)%
Illinois Basin		62,958		57,424		5,534		10	%
Ancillary		32,281		36,487		(4,206	)	(12	)%
Cost of coal sales	$	832,214	$	882,983	$	(50,769	)	(6	)%

Cost of coal sales—For the year ended December 31, 2009, our cost of coal sales decreased 6% compared to the year ended December 31, 2008, primarily as a result of an 11% decrease in tons sold. Partially offsetting the decrease in tons sold was a 6% increase in cost per ton.

Central Appalachian. Our Central Appalachian segment cost of coal sales decreased primarily as a result of a 14% decrease in tons sold. The decrease in cost of coal sales is due to decreased tons sold partially offset by an increase in costs to $55.53 per ton for the year ended December 31, 2009 from $51.28 per ton for the year ended December 31, 2008. The increase in cost of coal sales per ton is primarily due to increases in labor and benefit costs and royalties, taxes and fees. Labor and benefit costs per ton increased due to wage increases in the fourth quarter of 2008 in an effort to remain competitive in a tight labor market, lower production volumes associated with idled operations and an increase in medical benefits over the year ended December 31, 2008. Royalties, taxes and fees increased on a per ton basis as a result of increased sales realization per ton sold and increased royalty rates on certain leased reserves, as well as increased severance and property tax obligations.

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Northern Appalachian. Cost of coal sales from our Northern Appalachian segment decreased for the year ended December 31, 2009 as a result of a decrease in costs of $1.11 per ton and a 3% decrease in tons sold compared to the year ended December 31, 2008. The decrease in cost per ton is primarily due to decreases in transportation, fuel, lubricants and chemicals and coal purchased for blending to meet customer specifications. Partially offsetting these decreases in cost per ton were increases in labor and benefits, reclamation and engineering costs and contract labor costs.

Illinois Basin. For the year ended December 31, 2009, our Illinois Basin cost of coal sales increased as a result of an increase in costs of $3.30 per ton primarily due to increased labor and benefits costs and repairs and maintenance costs. Labor and benefits increased subsequent to the year ended December 31, 2008 as a result of increased wages in an effort to retain skilled miners. Additionally, repairs and maintenance costs were higher due to our increased utilization of underground mining equipment. Partially offsetting these increases in cost per ton was a 3% decrease in tons sold.

Ancillary. Cost of coal sales from our Ancillary segment decreased for the year ended December 31, 2009 primarily due to decreased purchased coal costs related to the expiration of certain brokered coal contracts, as well as to decreased shipments on various remaining contracts in 2009 as compared to 2008. These decreases were partially offset by an increase of $5.33 per ton sold, primarily as a result of increased reclamation and property tax expense at certain non-operating locations.

Cost of other revenues—For the year ended December 31, 2009, cost of other revenues increased primarily due to the related costs of the highwall mining system sold during the year and increased labor and benefit costs at our ADDCAR subsidiary. Partially offsetting these increases in cost of other revenues were decreases in coalbed methane gathering fees, repairs and maintenance costs and water treatment costs.

Depreciation, depletion and amortization—Depreciation, depletion and amortization expense increased for the year ended December 31, 2009, primarily as a result of capital spending throughout 2008 and 2009. Further impacting the increase was increased depletion expense resulting from increased mining of company-owned reserves, as well as a decrease in amortization income related to the completion or termination of shipments on certain below-market contracts. These increases were partially offset by a decrease in amortization of coalbed methane well development costs.

Selling, general and administrative expenses—Selling, general and administrative expenses for the year ended December 31, 2009 decreased primarily due to the recovery of a potential bad debt and the favorable resolution of certain legal and tax matters.

Gain on sale of assets—Gain on sale of assets decreased significantly for the year ended December 31, 2009. During the year ended December 31, 2008, we recognized a $24.6 million pre-tax gain on exchange of coal reserves with a third-party and a $3.6 million gain related to the sale of a highwall mining system previously used in operations. These decreases were partially offset by a gain of $2.9 million in 2009 related to the sale of a loadout facility.

Impairment loss—The impairment loss reflects the write-off of goodwill in 2008 associated with our ADDCAR subsidiary as a result of the negative impact of several contributing factors, which resulted in a reduction in the forecasted cash flows used to estimate fair value. Additionally, as a result of making the decision to close the Sago mine, related development costs were deemed to be impaired and were written-off during 2008. No comparable impairment occurred during 2009.

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Adjusted EBITDA by Reportable Segment

Adjusted EBITDA represents net income before deducting interest, income taxes, depreciation, depletion, amortization, loss on extinguishment of debt, impairment charges and noncontrolling interest. Adjusted EBITDA is presented because it is an important supplemental measure of our performance used by our chief operating decision maker in such areas as capital investment and allocation of resources. Other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. Adjusted EBITDA is reconciled to its most comparable GAAP measure on page 90 of this Annual Report on Form 10-K and in Note 20 to our consolidated financial statements for the year ended December 31, 2009.

The following table depicts reportable segment Adjusted EBITDA for the years ended December 31, 2009 and 2008:

	Year ended December 31,						Increase (Decrease)
	2009			2008			$			%
	(in thousands, except percentages)
Central Appalachian	$	169,842		$	107,186		$	62,656		58	%
Northern Appalachian		31,005			23,687			7,318		31	%
Illinois Basin		14,405			14,784			(379	)	(3	)%
Ancillary		(13,575	)		(18,436	)		4,861		26	%
Total Adjusted EBITDA	$	201,677		$	127,221		$	74,456		59	%

Central Appalachian. Adjusted EBITDA for the year ended December 31, 2009 increased compared to the year ended December 31, 2008 primarily due to $27.5 million received for the early termination of two related coal supply agreements and lost margin on pre-termination shipments coupled with a $6.22 per ton increase in profit margins. Partially offsetting these increases was a decrease of approximately 1,633,000 tons sold.

Northern Appalachian. The increase in Adjusted EBITDA was due to improved profit margins of $2.22 per ton attributable to a combination of an increase in sales realization of $1.11 per ton and a decrease of $1.11 in cost per ton.

Illinois Basin. Adjusted EBITDA decreased during the year ended December 31, 2009 due to a decrease of approximately 77,000 tons sold. Partially offsetting this decrease in tons sold were increased profit margins of $0.39 per ton.

Ancillary. The increase in Adjusted EBITDA was primarily due to $7.4 million received for contract settlements and an increase in profit margins of $2.20 per ton due to an increase in sales realization of $7.53 per ton, offset by a $5.33 increase in cost per ton. Further contributing to the increase in Adjusted EBITDA from our Ancillary segment was the sale of a highwall mining system during the year ended December 31, 2009, offset by decreased revenue from coalbed methane wells and a decrease of approximately 237,000 tons sold related to the expiration of brokered coal contracts throughout 2008 and decreased shipments of various remaining contracts.

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Reconciliation of Adjusted EBITDA to Net income (loss) by Reportable Segment

The following tables reconcile Adjusted EBITDA to net income (loss) by reportable segment for the years ended December 31, 2009 and 2008:

	Year ended December 31,					Increase (Decrease)
	2009		2008			$		%
	(in thousands, except percentages)
Central Appalachian
Net income attributable to International Coal Group, Inc.	$	91,841	$	47,244		$	44,597	94	%
Depreciation, depletion and amortization		71,298		64,132			7,166	11	%
Interest expense, net		4,488		2,145			2,343	109	%
Income tax (benefit) expense		2,215		(6,335	)		8,550	*	%
Adjusted EBITDA	$	169,842	$	107,186		$	62,656	58	%

	Year ended December 31,					Increase (Decrease)
	2009		2008			$			%
	(in thousands, except percentages)
Northern Appalachian
Net income attributable to International Coal Group, Inc.	$	7,994	$	3,217		$	4,777		148	%
Depreciation, depletion and amortization		20,991		17,884			3,107		17	%
Interest expense, net		531		717			(186	)	(26	)%
Income tax (benefit) expense		1,423		(5,322	)		6,745		*	%
Impairment loss		—		7,191			(7,191	)	(100	)%
Noncontrolling interest		66		—			66		100	%
Adjusted EBITDA	$	31,005	$	23,687		$	7,318		31	%

	Year ended December 31,					Increase (Decrease)
	2009			2008		$			%
	(in thousands, except percentages)
Illinois Basin
Net income attributable to International Coal Group, Inc.	$	6,080		$	6,959	$	(879	)	(13	)%
Depreciation, depletion and amortization		7,957			7,342		615		8	%
Interest expense, net		579			327		252		77	%
Income tax (benefit) expense		(211	)		156		(367	)	*	%
Adjusted EBITDA	$	14,405		$	14,784	$	(379	)	(3	)%

	Year ended December 31,						Increase (Decrease)
	2009			2008			$			%
	(in thousands, except percentages)
Ancillary
Net loss attributable to International Coal Group, Inc.	$	(84,457	)	$	(83,647	)	$	(810	)	1	%
Depreciation, depletion and amortization		5,838			6,689			(851	)	(13	)%
Interest expense, net		47,446			40,454			6,992		17	%
Income tax (benefit) expense		4,305			(12,169	)		16,474		*	%
Loss on extinguishment of debt		13,293			—			13,293		100	%
Impairment loss		—			30,237			(30,237	)	(100	)%
Adjusted EBITDA	$	(13,575	)	$	(18,436	)	$	4,861		26	%

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	Year ended December 31,					Increase (Decrease)
	2009		2008			$			%
	(in thousands, except percentages)
Consolidated
Net income (loss) attributable to International Coal Group, Inc.	$	21,458	$	(26,227	)	$	47,685		*	%
Depreciation, depletion and amortization		106,084		96,047			10,037		10	%
Interest expense, net		53,044		43,643			9,401		22	%
Income tax (benefit) expense		7,732		(23,670	)		31,402		*	%
Loss on extinguishment of debt		13,293		—			13,293		100	%
Impairment loss		—		37,428			(37,428	)	(100	)%
Noncontrolling interest		66		—			66		100	%
Adjusted EBITDA	$	201,677	$	127,221		$	74,456		59	%

* Not meaningful

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Liquidity and Capital Resources

Our business is capital intensive and requires substantial capital expenditures for, among other things, purchasing and upgrading equipment used in developing and mining our reserves, as well as remaining in compliance with environmental laws and regulations. Our principal liquidity requirements are to finance our coal production, fund capital expenditures and service our debt and reclamation obligations. We may also engage in acquisitions from time to time. Our primary sources of liquidity to meet these needs are cash on hand, cash flows from operations, borrowings under our asset-based loan facility and equipment financing arrangements.

We believe the principal indicators of our liquidity are our cash position and remaining availability under our asset-based loan facility. As of December 31, 2010, our available liquidity was $234.9 million, including cash and cash equivalents of $215.3 million and $19.6 million available for borrowing under our $125.0 million asset-based loan facility. Total debt represented 30% of our total capitalization at December 31, 2010. Our total capitalization represents our current and long-term debt combined with our total stockholders’ equity.

Under a universal shelf registration statement, which became effective January 15, 2010, we have the remaining capacity to offer and sell, from time to time, up to $175.7 million aggregate value of securities, including common stock and debt securities. This registration statement allows us to access the capital markets based on our liquidity and capital needs subject to favorable market and other conditions.

Pursuant to this shelf registration statement, in March 2010, we completed public offerings of 24,444,365 shares of our common stock, par value $0.01 per share (the “Common Stock”), at a public offering price of $4.47 per share, $115.0 million aggregate principal amount of 4.00% Convertible Senior Notes due 2017 (the “2017 Convertible Notes”) and $200.0 million aggregate principal amount of 9.125% Senior Secured Second-Priority Notes due 2018 (the “2018 Senior Notes”). We used $169.5 million of the net proceeds from the Common Stock and 2017 Convertible Notes offerings to finance the repurchase of $138.8 million aggregate principal amount of our 2012 Convertible Notes. We used $189.0 million of the net proceeds from the 2018 Senior Notes offering to finance the repurchase of $175.0 million aggregate principal amount of our 10.25% Senior Notes due 2014 (the “2014 Senior Notes”). The remaining proceeds were used for general corporate purposes.

We also secured a new four-year $125.0 million asset-based loan facility (the “ABL Loan Facility”) to replace our prior revolving credit facility which was set to expire in June 2011. The ABL Loan Facility, which provides up to $25.0 million in additional borrowing capacity and contains minimal financial covenants, primarily consisting of a fixed-charge ratio and a capital expenditure limitation if our liquidity falls below certain thresholds, matures in February 2014. Any available borrowing capacity is available for loans or the issuance of letters of credit. The ABL Loan Facility has been used primarily for issuing letters of credit that collateralize our reclamation bonds. Subject to certain conditions, at any time prior to maturity, we will be able to elect to increase the size of the ABL Loan Facility, up to a maximum of $200.0 million. Availability under the ABL Loan Facility is determined using a borrowing base calculation.

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We currently expect our total capital expenditures will be between $225.0 million to $245.0 million in 2011 for equipment and infrastructure at our existing operations, as well as for development at our Tygart Valley, Illinois and Vindex complexes. Cash paid for capital expenditures was approximately $102.9 million for the year ended December 31, 2010. We have funded and expect to continue to fund these capital expenditures from cash on hand, internal operations and equipment financing arrangements, such as our $50.0 million equipment revolving credit facility with Caterpillar Financial Services Corporation. We believe that these sources of capital will be sufficient to fund our anticipated capital expenditures through 2011, including initial development of our Tygart Valley complex. To the extent necessary, management believes it has flexibility on the timing of these cash requirements by managing the pace of capital spending. In addition, management may from time to time raise additional capital through the disposition of non-core assets, engaging in sale-leaseback transactions or utilizing our shelf registration statement. The need and timing of seeking additional capital in the future will be subject to market conditions.

Approximately $39.9 million of cash paid for capital expenditures for the year ended December 31, 2010 was attributable to our Central Appalachian operations. This amount represents investments of approximately $11.7 million in our Beckley mining complex, $9.7 million at Knott County and $9.8 million at our Raven division. We paid approximately $37.8 million at our Northern Appalachian operations in the year ended December 31, 2010. This amount represents investments of approximately $16.3 million at our Vindex complex, $7.5 million at Tygart Valley and $6.5 million at our Sentinel complex. Expenditures of approximately $21.5 million for our Illinois Basin operations were for development of a new mine portal and ongoing operations improvements. Approximately $3.7 million of cash paid for capital expenditures for the year ended December 31, 2010 was within our Ancillary segment.

More stringent regulatory requirements imposed upon the mining industry demand substantial capital expenditures to meet safety standards. For the year ended December 31, 2010, we spent $7.3 million to meet these standards and anticipate spending an additional $3.7 million in 2011. As a result of a recent explosion at a competitor’s mine, additional safety requirements may increase our capital and operating costs. See Item 1A — “Risk Factors”.

In addition, in March 2010, the Patient Protection and Affordable Care Act (“PPACA”) and the Health Care and Education Reconciliation Act (“HCERA” or, collectively with PPACA, the “Health Care Reform Act”) were enacted into law. As a result, we recorded a one-time, non-cash income tax charge of $0.8 million during the year ended December 31, 2010 to reflect the impact of this change. The Health Care Reform Act also includes a provision to remove lifetime caps on medical plans. Our retiree medical plan has such a cap and, as a result of removing this cap, our postretirement benefit obligation was increased by $13.0 million. The prior service cost associated with the plan change will be amortized over the average remaining working life of the related employees. We incurred additional expense of $1.3 million for the year ended December 31, 2010 related to the remeasurement. The Health Care Reform Act also amended previous legislation related to coal workers’ pneumoconiosis (black lung), providing an automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims. These new provisions of the Health Care Reform Act may increase the number of future claims that are awarded benefits. We do not have sufficient claims experience since the Health Care Reform Act was passed to estimate the impact on our December 31, 2010 black lung liability of the potential increase in the number of future claims that are awarded benefits. An increase in benefits awarded could have a material impact on our financial position, results of operations or cash flows.

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Cash Flows

Net cash provided by operating activities was $187.4 million for the year ended December 31, 2010, an increase of $71.7 million from the same period in 2009. This increase is attributable to an increase in net operating assets and liabilities of $58.3 million and an increase in net income of $13.4 million, after adjustment for non-cash charges.

For the year ended December 31, 2010, net cash used in investing activities was $89.3 million compared to $73.2 million for the year ended December 31, 2009. For the year ended December 31, 2010, $102.9 million of cash was paid for capital expenditures at existing mining and ancillary operations compared to $66.3 million in the same period of 2009. Additionally, cash flows from investing activities for the year ended December 31, 2010 included $8.9 million due to the withdrawal of restricted cash previously pledged as collateral.

Net cash provided by financing activities was $24.5 million for the year ended December 31, 2010. We received proceeds from our 2017 Convertible Notes, 2018 Senior Notes and Common Stock offerings of $416.0 million. We used $358.4 million of these proceeds to repurchase a portion of our 2014 Senior Notes and 2012 Convertible Notes. Additionally, we made payments of $23.5 million on our short- and long-term debt obligations. We also incurred additional finance costs of $14.7 million for the year ended December 31, 2010 related to the debt offerings and our asset-based loan facility.

Net cash provided by operating activities was $115.7 million for the year ended December 31, 2009, an increase of $37.0 million from the same period in 2008. This increase is attributable to an increase in net income of $93.3 million, after adjustment for non-cash charges, offset by a decrease in net operating assets and liabilities of $56.3 million.

For the year ended December 31, 2009, net cash used in investing activities was $73.2 million compared to $124.0 million for the year ended December 31, 2008. For the year ended December 31, 2009, $66.3 million of cash was used for development of new mining complexes and to support existing mining operations compared to $132.8 million in 2008. Additionally, we collected proceeds from asset sales of $3.7 million during the year ended December 31, 2009 versus $8.8 million during the comparable period of 2008.

Net cash used by financing activities of $13.9 million for the year ended December 31, 2009 was due to repayments on our short-term and long-term debt of $24.3 million and finance costs incurred of $1.3 million. These amounts were partially offset by borrowings of $11.7 million provided by long-term and short-term notes entered into during the year.

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Credit Facility and Long-Term Debt Obligations

As of December 31, 2010, our total long-term indebtedness, including capital lease obligations, consisted of the following (in thousands):

	December 31, 2010
9.125% Senior Notes, due 2018, net of debt discount of $1,308	$	198,692
4.00% Convertible Senior Notes, due 2017, net of debt discount of $31,882		83,118
9.00% Convertible Senior Notes, due 2012, net of debt discount of $28		703
Equipment notes		42,730
Capital lease and other		1,107
Total		326,350
Less current portion		(17,928	)
Long-term debt and capital lease	$	308,422

9.125% Senior notes due 2018. On March 22, 2010, we completed a public offering of $200.0 million aggregate principal amount of our 2018 Senior Notes, with net proceeds of $193.6 million to us after deducting discounts and underwriting fees of $6.4 million. Interest on the 2018 Senior Notes is payable semi-annually in arrears on April 1st and October 1st of each year, commencing October 1, 2010. The obligations under the 2018 Senior Notes are fully and unconditionally guaranteed, jointly and severally, by all of our wholly-owned domestic subsidiaries other than subsidiaries that are designated as unrestricted subsidiaries. The 2018 Senior Notes and the guarantees are secured by a second-priority lien on, and security interest in, substantially all of our and the guarantors’ assets, junior to first-priority liens that secure our ABL Loan Facility and certain other permitted liens under the indenture that governs the notes. Prior to April 1, 2014, we may redeem all or a part of the 2018 Senior Notes at a price equal to 100% of the principal amount plus an applicable “make-whole” premium and accrued and unpaid interest to the redemption date. We may redeem the 2018 Senior Notes, in whole or in part, beginning on April 1, 2014. The initial redemption price will be 104.563% of their aggregate principal amount, plus accrued and unpaid interest. The redemption price declines to 102.281% and 100.000% of their aggregate principal amount, plus accrued and unpaid interest, on April 1, 2015 and April 1, 2016 and thereafter, respectively. In addition, at any time and from time to time prior to April 1, 2013, we may redeem up to 35% of the 2018 Senior Notes at a redemption price equal to 109.125% of its principal amount plus accrued and unpaid interest using proceeds from sales of certain kinds of our capital stock. Upon the occurrence of a change of control or the sale of our assets, it may be required to repurchase some or all of the notes.

The indenture governing the 2018 Senior Notes contains covenants that limit our ability to, among other things, incur additional indebtedness, issue preferred stock, pay dividends, repurchase, repay or redeem its capital stock, make certain investments, sell assets and incur liens. As of December 31, 2010, we were in compliance with its covenants under the indenture.

4.00% Convertible senior notes due 2017. On March 16, 2010, we completed a public offering of $115.0 million aggregate principal amount of our 2017 Convertible Notes. Net proceeds from the offering were $111.6 million, after deducting underwriting fees of $3.4 million. The 2017 Convertible Notes are our senior unsecured obligations and are guaranteed jointly and severally on a senior unsecured basis by all of our material future and current domestic subsidiaries or that guarantee the ABL Loan Facility on a senior basis. The 2017 Convertible Notes and the related guarantees rank equal in right of payment to all of our and the guarantors’ respective existing and future unsecured senior indebtedness. Interest is payable semi-annually in arrears on April 1st and October 1st of each year, commencing October 1, 2010. We assess the convertibility of the 2017 Convertible Notes on an ongoing basis. The 2017 Convertible Notes were not convertible as of December 31, 2010.

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The 2017 Convertible Notes are convertible into our common stock, under certain circumstances, at an initial conversion price, subject to adjustment, of $5.81 per share (approximating 172.0874 shares per one thousand dollar principal amount of the 2017 Convertible Notes). Holders may convert their notes at their option prior to January 1, 2017 only under the following circumstances: (i) during any calendar quarter after the calendar quarter ending September 30, 2010 (and only during that quarter), if the closing sale price of our common stock for each of 20 or more trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the conversion price of such notes in effect on the last trading day of the immediately preceding calendar quarter; (ii) during the five consecutive business days immediately after any five consecutive trading day period, or the note measurement period, in which the trading price per note for each trading day of that note measurement period was equal to or less than 97% of the product of the closing sale price of shares of our common stock and the applicable conversion rate for such trading day; and (iii) upon the occurrence of specified corporate transactions. In addition, the notes will be convertible irrespective of the foregoing circumstances from, and including, January 1, 2017 to, and including, the business day immediately preceding April 1, 2017. Upon conversion, we will have the right to deliver cash, shares of our common stock or a combination thereof, at our election. At any time on or prior to the 23rd business day immediately preceding the maturity date, we may irrevocably elect to deliver solely shares of our common stock in respect of our conversion obligation or pay cash up to the aggregate principal amount of the notes to be converted and deliver shares of its common stock, cash or a combination thereof in respect of the remainder, if any, of the conversion obligation. It is our current intention to settle the principal amount of any notes converted in cash. The conversion rate, and thus the conversion price, will be subject to adjustment. A holder that surrenders notes for conversion in connection with a “make-whole fundamental change” that occurs before the maturity date may in certain circumstances be entitled to an increased conversion rate. In the event the 2017 Convertible Notes become convertible, we would be required to classify the entire amount outstanding of the 2017 Convertible Notes as a current liability.

9.00% Convertible senior notes due 2012. In December 2009, we entered into a series of privately negotiated agreements to exchange shares for our outstanding 2012 Convertible Notes. In connection with such agreements, we issued a total of 18,660,550 shares of our common stock in exchange for $63.5 million aggregate principal amount of our 2012 Convertible Notes during December 2009. One of the exchange agreements, as amended, provided for closing of additional exchanges on each of January 11, 2010 and January 19, 2010 for exchange transactions occurring in 2010. Subsequent to December 31, 2009, the noteholder exchanged $22,000 aggregate principal amount of 2012 Convertible Notes for 6,198,668 shares of our common stock. During 2010, we used the net proceeds from our Common Stock and 2017 Convertible Notes offerings to finance the repurchase of $138.8 million aggregate principal amount of 2012 Convertible Notes.

The 2012 Convertible Notes are our senior unsecured obligations and are guaranteed on a senior unsecured basis by our material current and future domestic subsidiaries. The 2012 Convertible Notes and the related guarantees rank equal in right of payment to all of our and the guarantors’ respective existing and future unsecured senior indebtedness. Interest is payable semi-annually in arrears on February 1st and August 1st of each year. We assess the convertibility of the 2012 Convertible Notes on an ongoing basis. The 2012 Convertible Notes were not convertible as of December 31, 2010.

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The principal amount of the 2012 Convertible Notes is payable in cash and amounts above the principal amount, if any, will be convertible into shares of our common stock or, at our option, cash. The 2012 Convertible Notes are convertible into shares of our common stock, under certain circumstances, at an initial conversion price, subject to adjustment, of $6.10 per share (approximating 163.8136 shares per one thousand dollar principal amount of the 2012 Convertible Notes). The 2012 Convertible Notes are convertible upon the occurrence of certain events, including (i) prior to February 12, 2012 during any calendar quarter after September 30, 2007, if the closing sale price per share of our common stock for each of 20 or more trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the conversion price in effect on the last trading day of the immediately preceding calendar quarter; (ii) prior to February 12, 2012 during the five consecutive business days immediately after any five consecutive trading day period in which the average trading price for the notes on each day during such five trading day period was equal to or less than 97% of the closing sale price of our common stock on such day multiplied by the then current conversion rate; (iii) upon the occurrence of specified corporate transactions; and (iv) at any time from, and including February 1, 2012 until the close of business on the second business day immediately preceding August 1, 2012. In addition, upon events defined as a “fundamental change” under the 2012 Convertible Notes indenture, we may be required to repurchase the 2012 Convertible Notes at a repurchase price in cash equal to 100% of the principal amount of the notes to be repurchased, plus any accrued and unpaid interest to, but excluding, the fundamental change repurchase date. In the event the 2012 Convertible Notes become convertible, we would be required to classify the entire amount outstanding of the 2012 Convertible Notes as a current liability. In addition, if conversion occurs in connection with certain changes in control, we may be required to deliver additional shares of our common stock (a “make-whole” premium) by increasing the conversion rate with respect to such notes.

Asset-based loan facility. On February 22, 2010, we entered into an ABL Loan Facility which replaced our prior senior secured credit facility. The ABL Loan Facility is a $125.0 million senior secured facility with a four-year term, all of which is available for loans or the issuance of letters of credit. Subject to certain conditions, at any time prior to maturity, we will be able to elect to increase the size of the ABL Loan Facility, up to a maximum of $200.0 million. Availability under the ABL Loan Facility is determined using a borrowing base calculation. The ABL Loan Facility is guaranteed by all of our current and future wholly-owned subsidiaries and secured by a first priority security interest on all of our and each of our guarantors’ existing and after-acquired real and personal property, including all outstanding equity interests of our wholly-owned subsidiaries. The ABL Loan Facility has a maturity date of February 22, 2014. The ABL Loan Facility has an early acceleration provision if more than $20.0 million aggregate principal amount of 2012 Convertible Notes were to have remained outstanding as of January 31, 2012. With the repurchases of the 2012 Convertible Notes that occurred during the year ended December 31, 2010, this provision has been satisfied. As of December 31, 2010, we had a borrowing capacity of $105.9 million under the ABL Loan Facility with no borrowings outstanding, letters of credit totaling $86.3 million outstanding and $19.6 million available for future borrowing, and were in compliance with our financial covenants under the ABL Loan Facility. The ABL Loan Facility was amended on May 6, 2010 for minor technical corrections.

Equipment notes. The equipment notes, having various maturity dates extending to April 2015, are collateralized by mining equipment. As of December 31, 2010, we had amounts outstanding with terms ranging from 36 to 60 months and a weighted-average interest rate of 7.38%. As of December 31, 2010, we had a borrowing capacity of $19.4 million available under our revolving equipment credit facility for terms from 36 to 60 months at an interest rate of 6.25%.

Capital lease and other. We lease certain mining equipment under a capital lease. We imputed interest on our capital lease using a rate of 10.44%.

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Other

As a regular part of our business, we review opportunities for, and engage in discussions and negotiations concerning, the acquisition of coal mining assets and interests in coal mining companies, and acquisitions of, or combinations with, coal mining companies. When we believe that these opportunities are consistent with our growth plans and our acquisition criteria, we will make bids or proposals and/or enter into letters of intent and other similar agreements, which may be binding or nonbinding, that are customarily subject to a variety of conditions and usually permit us to terminate the discussions and any related agreement if, among other things, we are not satisfied with the results of our due diligence investigation. Any acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. There can be no assurance that additional financing will be available on terms acceptable to us, or at all.

Additionally, we have other long-term liabilities, including, but not limited to, mine reclamation and closure costs, below-market coal supply agreements and “black lung” costs, and some of our subsidiaries have long-term liabilities relating to retiree health and other employee benefits.

Our ability to meet our long-term debt obligations will depend upon our future performance, which in turn, will depend upon general economic, financial and business conditions, along with competition, legislation and regulation — factors that are largely beyond our control. We believe that cash flow from operations, together with other available sources of funds, including additional borrowings under the ABL Loan Facility and equipment credit facility, will be adequate at least through 2011 for making required payments of principal and interest on our indebtedness and for funding anticipated capital expenditures and working capital requirements. To the extent necessary, management believes it has some flexibility to manage its cash requirements by controlling the pace and timing of capital spending, utilizing availability under its credit facilities, reducing certain costs and idling low-margin operations. In addition, management may from time to time raise additional capital through the disposition of non-core assets, engaging in sale-leaseback transactions or utilizing our shelf registration statement. However, we cannot assure you that our operating results, cash flow and capital resources will be sufficient for repayment of our debt obligations in the future.

Our 2012 Convertible Notes and 2017 Convertible Notes were not convertible as of December 31, 2010. In the event that the 2012 Convertible Notes or 2017 Convertible Notes were to become convertible and holders were to convert their notes prior to maturity, we will use a combination of cash on hand and shares of our common stock.

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Contractual Obligations

The following is a summary of our significant future contractual obligations by year as of December 31, 2010 (in thousands):

	Payments Due by Period
	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Long-term debt and capital lease(1)	$	43,424	$	72,784	$	46,988	$	361,813	$	525,009
Postretirement medical benefits		626		2,513		3,793		381,570		388,502
Minimum royalties		10,814		17,565		15,343		27,207		70,929
Diesel fuel purchase obligations(2)		31,398		—		—		—		31,398
Explosives purchase obligations(2)		13,154		—		—		—		13,154
Advisory Services Agreement(3)		1,500		—		—		—		1,500
Operating leases		131		83		6		—		220
Total	$	101,047	$	92,945	$	66,130	$	770,590	$	1,030,712

(1)	Amounts are inclusive of interest assuming interest rates of 9.125% for our 2018 Senior Notes, 4.0% for our 2017 Convertible Notes, 9.0% for our 2012 Convertible Notes and ranging from 5.46% to 10.09% on our equipment notes.
(2)	Reflects estimates of obligations.
(3)	See “Certain Relationships and Related Transactions, and Director Independence.”

We have excluded $3,133 of uncertain tax liabilities as defined in ASC Topic 740, Income Taxes, from the table above due to the uncertainty of timing of future cash flows.

As of December 31, 2010, the Company had fulfilled all of its contractual coal purchase obligations.

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Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheets and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

Federal and state laws require us to secure payment of certain long-term obligations, such as mine closure and reclamation costs, coal leases and other obligations. We typically secure these payment obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive than posting an all cash bond or a bank letter of credit, either of which would require a greater use of our credit facility. We then use bank letters of credit to secure our surety bonding obligations as a lower cost alternative than securing those bonds with cash. We currently have a $124.6 million committed bonding facility pursuant to which we are required to provide bank letters of credit in an amount up to 50% of the aggregate bond liability. 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 our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.

As of December 31, 2010, we had outstanding surety bonds with third parties for post-mining reclamation totaling $121.1 million, plus $3.5 million for miscellaneous purposes. As of December 31, 2010, we maintained letters of credit totaling $86.3 million to secure reclamation surety bonds and other obligations.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the years ended December 31, 2010, 2009 and 2008. Although the impact of inflation has been insignificant in recent years, it is still a factor in the global economy and may increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and commodities.

Recent Accounting Pronouncements

See Note 2–Summary of Significant Policies and General–Recent Accounting Pronouncements to the audited consolidated financial statements included in Item 15 of this Annual Report on Form 10-K related to recently issued accounting pronouncements, which information is incorporated herein by reference.

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ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market price risk. We are exposed to market price risk in the normal course of mining and selling coal. We manage this risk through the use of coal supply agreements, rather than through the use of derivative instruments. As of December 31, 2010, 78% of our 2011 projected sales are committed and priced. Any committed and unpriced projected sales are subject to future market price volatility. Additionally, the prices of coal shipped under supply agreements may be below the current market prices for similar types of coal at any given time. As a result of the substantial volume of sales that are subject to these agreements, we have less coal available with which to capitalize on stronger coal prices if and when they arise.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our financial statements and supplementary data are included at the end of this report beginning on page F-1.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

There have been no changes in, or disagreements with, accountants on accounting and financial disclosure.

ITEM 9A.

CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. Our disclosure controls and procedures are also designed to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. Periodically, we review the design and effectiveness of our disclosure controls and controls over financial reporting to ensure they remain effective. If such reviews identify a need, we will make modifications to improve the design and effectiveness of our control structure. We conducted an evaluation of our controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our controls and procedures were effective as of December 31, 2010.

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Control systems, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that control objectives are met. Because of inherent limitations in all control systems, no evaluation of controls can provide assurance that all control issues and instances of fraud, if any, within a company will be detected. Additionally, controls can be circumvented by individuals, by collusion of two or more people, or by management override. Over time, controls can become inadequate because of changes in conditions or the degree of compliance may deteriorate. Further, the design of any system of controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any design will succeed in achieving its stated goals under all future conditions. Because of the inherent limitations in any cost-effective control system, misstatements due to errors or fraud may occur and not be detected.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for maintaining and establishing adequate internal control over financial reporting. Our internal control framework and processes were designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

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

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of our controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Exchange Act using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our controls and procedures were effective as of December 31, 2010.

Our Independent Registered Public Accounting Firm, Deloitte & Touche LLP, has audited the effectiveness of our internal control over financial reporting, as stated in their attestation report included in Item 9A of this Annual Report on Form 10-K.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal controls over financial reporting during the fourth quarter of fiscal year 2010 that would have materially affected, or would be reasonably likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

International Coal Group, Inc.

Scott Depot, West Virginia

We have audited the internal control over financial reporting of International Coal Group, Inc. and subsidiaries (the “Company”) as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2010 of the Company and our report dated February 17, 2011, expressed an unqualified opinion on those financial statements and financial statement schedules.

/s/ Deloitte & Touche LLP

Cincinnati, Ohio

February 17, 2011

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ITEM 9B.

OTHER INFORMATION

Mine Safety and Health Administration Data

We believe that every employee should enjoy a safe workplace and we want each employee to return home healthy and safely every day. Our safety culture relies on involving all employees in the safety process through programs, such as the Employee Involvement Group, which obtain individual commitments to making our workplaces safe and to doing the job right the first time. We believe that involving our employees in problem-solving solutions and the design of our improvement processes creates a stronger team approach. Our safety processes include training programs for accident prevention, hazard recognition and safe work procedures to improve the individual skills of each employee. We implemented our Continuous Safety Improvement process, which creates individual Safety Improvement Plans for each business unit that are designed to improve overall safety performance, as well as regulatory compliance performance.

These safety programs empower all of our employees to champion the safety process. Every person is challenged to identify hazards and initiate corrective actions. We encourage our employees to report any safety concerns to management immediately, but we also provide the ability for employees to report concerns anonymously, in either event allowing hazards to be dealt with in a timely manner. All levels of the organization are expected to be proactive and commit to continuous improvement, implementing new safety processes, when appropriate, that promote a safe and healthy work environment. As a result of these efforts, many of our mining operations have been recognized with state and national awards over the years for outstanding safety performance. During the year ended December 31, 2010, 28 individual safety awards were presented to our operations.

Our subsidiaries operate multiple mining complexes in five states and are regulated by both MSHA and state regulatory agencies. As described in more detail in the “Environmental, Safety and Other Regulatory Matters” section of this Annual Report on Form 10-K, the Federal Mine Safety and Health Act of 1977, as amended (the “Mine Act”) and state regulatory agencies, among other regulations, imposes stringent safety and health standards on all aspects of mining operations. Regulatory inspections are mandated by these agencies with thousands of inspection shifts at our properties each year. Citations and compliance metrics at each of our 13 affiliated mining properties vary, due to the size and type of the operation. We endeavor to conduct our mining and other operations in compliance with all applicable federal, state and local laws and regulations. However, violations occur from time to time. None of the violations identified or the monetary penalties assessed upon us set forth in the tables below have been material.

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For reporting purposes of The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, we include the following table that sets forth the following information for the three months and year ended December 31, 2010: Section 104 Citations: The total number of violations received from MSHA under section 104 of the Mine Act, which includes citations for health or safety standards that could significantly and substantially contribute to a serious injury if left unabated; Section 104(b) Orders: The total number of orders issued by MSHA under section 104(b) of the Mine Act, which represents a failure to abate a citation under section 104(a) within the period of time prescribed by MSHA. This results in an order of immediate withdrawal from the area of the mine affected by the condition until MSHA determines that the violation has been abated; Section 104(d) Citations and Orders: The total number of citations and orders issued by MSHA under section 104(d) of the Mine Act for unwarrantable failure to comply with mandatory health or safety standards; Section 107(a) Orders: The total number of orders issued by MSHA under section 107(a) of the Mine Act for situations in which MSHA determined an imminent danger existed; and Section 110(b)(2) Violations: The total number of flagrant violations issued by MSHA under section 110(b)(2) of the Mine Act. The Company has the right to contest through legal proceedings a citation, order or penalty assessment, which the Company does, from time to time, when it deems appropriate.

Three months ended December 31, 2010

MSHA Mine ID	Mine Operator	Section 104 Significant and Substantial Citations	Section 104(b) Withdrawal Orders	Section 104(d) Unwarrantable Failure Citation/ Orders	Section 107(a) Imminent Danger Orders	Section 110(b)(2) Flagrant Violations
4801645	ICG ADDCAR Systems, LLC	—	—	—	—	—
1202351	ICG ADDCAR Systems, LLC	—	—	—	—	—
1202416	ICG ADDCAR Systems, LLC	—	—	—	—	—
1202356	ICG ADDCAR Systems, LLC	—	—	—	—	—
4608799	ICG ADDCAR Systems, LLC	—	—	—	—	—
1517110	ICG Knott County, LLC	—	—	—	—	—
1518393	ICG Knott County, LLC	—	—	—	—	—
1518522	ICG Knott County, LLC	19	1	1	—	—
1516567	ICG Knott County, LLC	—	—	—	—	—
1519447	ICG Knott County, LLC	8	—	1	—	—
1519240	ICG Knott County, LLC	—	—	—	—	—
1518949	ICG Knott County, LLC	2	—	—	—	—
1518710	ICG Knott County, LLC	—	—	—	—	—
1517724	ICG Knott County, LLC	—	—	—	—	—
1519497	ICG Knott County, LLC	6	—	—	—	—
1519323	ICG Knott County, LLC	1	—	—	—	—
1518048	ICG Hazard, LLC	—	—	—	—	—
1518613	ICG Hazard, LLC	—	—	—	—	—
1518181	ICG Hazard, LLC	—	—	—	—	—
1517746	ICG Hazard, LLC	3	—	—	—	—
1513495	ICG Hazard, LLC	—	—	—	—	—
1519391	ICG Hazard, LLC	—	—	—	—	—
1518966	ICG Hazard, LLC	—	—	—	—	—
1519236	ICG Hazard, LLC	—	—	—	—	—
1519416	ICG Hazard, LLC	—	—	—	—	—
1515506	ICG Hazard, LLC	2	—	—	—	—
1511991	ICG Hazard, LLC	2	—	—	—	—
1518850	ICG Hazard, LLC	—	—	—	—	—
1518991	ICG Hazard, LLC	17	—	—	—	—
1519281	ICG Hazard, LLC	—	—	—	—	—

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MSHA Mine ID	Mine Operator	Section 104 Significant and Substantial Citations	Section 104(b) Withdrawal Orders	Section 104(d) Unwarrantable Failure Citation/ Orders	Section 107(a) Imminent Danger Orders	Section 110(b)(2) Flagrant Violations
1517960	ICG East Kentucky, LLC	—	—	—	—	—
1519382	ICG East Kentucky, LLC	1	—	—	—	—
1518193	ICG East Kentucky, LLC	—	—	—	—	—
1519070	ICG East Kentucky, LLC	—	—	—	—	—
1516290	ICG East Kentucky, LLC	—	—	—	—	—
4407060	Powell Mountain Energy, LLC	—	—	—	—	—
4407207	Powell Mountain Energy, LLC	—	—	—	—	—
4405605	Powell Mountain Energy, LLC	—	—	—	—	—
1518734	Powell Mountain Energy, LLC	17	—	—	—	—
4609115	Wolf Run Mining Company	38	—	1	—	—
4608791	Wolf Run Mining Company	—	—	—	—	—
4605544	Wolf Run Mining Company	5	—	—	—	—
4608364	Wolf Run Mining Company	—	—	—	—	—
4605823	Upshur Property, Inc.	—	—	—	—	—
4604168	Wolf Run Mining Company	63	—	1	—	—
4608777	Wolf Run Mining Company	—	—	—	—	—
4607945	ICG Eastern, LLC	—	—	—	—	—
4608390	ICG Eastern, LLC	—	—	—	—	—
4609220	ICG Eastern, LLC	1	—	—	—	—
4605252	ICG Beckley, LLC	32	—	2	—	—
4609216	ICG Beckley, LLC	—	—	—	—	—
1800749	Vindex Energy Corporation	1	—	—	—	—
1800769	Vindex Energy Corporation	2	—	1	—	—
1800170	Vindex Energy Corporation	—	—	—	—	—
4602151	Vindex Energy Corporation	—	—	—	—	—
4607837	Vindex Energy Corporation	—	—	—	—	—
4609369	Vindex Energy Corporation	13	—	—	1	—
1800709	Vindex Energy Corporation	1	—	1	—	—
1102664	ICG Illinois, LLC	43	1	1	—	—
4607654	Patriot Mining Company, Inc.	—	—	—	—	—
4607555	Patriot Mining Company, Inc.	1	—	—	—	—

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Year ended December 31, 2010

MSHA Mine ID	Mine Operator	Section 104 Significant and Substantial Citations	Section 104(b) Withdrawal Orders	Section 104(d) Unwarrantable Failure Citation/ Orders	Section 107(a) Imminent Danger Orders	Section 110(b)(2) Flagrant Violations
4801645	ICG ADDCAR Systems, LLC	—	—	—	—	—
1202351	ICG ADDCAR Systems, LLC	—	—	—	—	—
1202416	ICG ADDCAR Systems, LLC	2	—	—	—	—
1202356	ICG ADDCAR Systems, LLC	1	—	—	—	—
4608799	ICG ADDCAR Systems, LLC	—	—	—	—	—
1517110	ICG Knott County, LLC	6	—	—	—	—
1518393	ICG Knott County, LLC	—	—	—	—	—
1518522	ICG Knott County, LLC	60	1	4	—	—
1516567	ICG Knott County, LLC	1	—	—	—	—
1519447	ICG Knott County, LLC	25	—	1	—	—
1519240	ICG Knott County, LLC	—	—	—	—	—
1518949	ICG Knott County, LLC	27	—	1	—	—
1518710	ICG Knott County, LLC	—	—	—	—	—
1517724	ICG Knott County, LLC	6	—	—	—	—
1519497	ICG Knott County, LLC	9	—	—	—	—
1519323	ICG Knott County, LLC	16	—	—	—	—
1518048	ICG Hazard, LLC	11	—	—	—	—
1518613	ICG Hazard, LLC	5	—	—	—	—
1518181	ICG Hazard, LLC	—	—	—	—	—
1517746	ICG Hazard, LLC	28	—	—	—	—
1513495	ICG Hazard, LLC	1	—	—	—	—
1519391	ICG Hazard, LLC	1	—	—	—	—
1518966	ICG Hazard, LLC	17	—	—	—	—
1519236	ICG Hazard, LLC	—	—	—	—	—
1519416	ICG Hazard, LLC	4	—	—	—	—
1515506	ICG Hazard, LLC	2	—	—	—	—
1511991	ICG Hazard, LLC	12	—	—	—	—
1518850	ICG Hazard, LLC	—	—	—	—	—
1518991	ICG Hazard, LLC	65	—	—	—	—
1519281	ICG Hazard, LLC	—	—	—	—	—

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MSHA Mine ID	Mine Operator	Section 104 Significant and Substantial Citations	Section 104(b) Withdrawal Orders	Section 104(d) Unwarrantable Failure Citation/ Orders	Section 107(a) Imminent Danger Orders	Section 110(b)(2) Flagrant Violations
1517960	ICG East Kentucky, LLC	9	—	—	—	—
1519382	ICG East Kentucky, LLC	1	—	—	—	—
1518193	ICG East Kentucky, LLC	—	—	—	—	—
1519070	ICG East Kentucky, LLC	4	—	—	—	—
1516290	ICG East Kentucky, LLC	—	—	—	—	—
4407060	Powell Mountain Energy, LLC	—	—	—	—	—
4407207	Powell Mountain Energy, LLC	—	—	—	—	—
4405605	Powell Mountain Energy, LLC	6	—	—	—	—
1518734	Powell Mountain Energy, LLC	119	1	13	—	—
4609115	Wolf Run Mining Company	80	—	2	—	—
4608791	Wolf Run Mining Company	—	—	—	—	—
4605544	Wolf Run Mining Company	5	—	—	—	—
4608364	Wolf Run Mining Company	—	—	—	—	—
4605823	Upshur Property, Inc.	3	—	—	—	—
4604168	Wolf Run Mining Company	189	—	9	—	—
4608777	Wolf Run Mining Company	—	—	—	—	—
4607945	ICG Eastern, LLC	3	—	—	—	—
4608390	ICG Eastern, LLC	2	—	—	—	—
4609220	ICG Eastern, LLC	1	—	—	—	—
4605252	ICG Beckley, LLC	117	—	2	—	—
4609216	ICG Beckley, LLC	1	—	—	—	—
1800749	Vindex Energy Corporation	7	—	—	—	—
1800769	Vindex Energy Corporation	4	—	1	—	—
1800170	Vindex Energy Corporation	2	—	—	—	—
4602151	Vindex Energy Corporation	—	—	—	—	—
4607837	Vindex Energy Corporation	3	—	2	—	—
4609369	Vindex Energy Corporation	16	—	—	1	—
1800709	Vindex Energy Corporation	2	—	1	—	—
1102664	ICG Illinois, LLC	138	1	7	—	—
4607654	Patriot Mining Company, Inc.	2	—	—	—	—
4607555	Patriot Mining Company, Inc.	1	—	—	—	—

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The following table that sets forth for the three months and year ended December 31, 2010: the total dollar value of proposed assessments from MSHA; the total number of mining-related fatalities; the total number of written notices of pattern of violations; the total number of written notices of the potential to have a pattern of violations; and the total number of pending legal actions before the Federal Mine Safety and Health Review Commission for each of our subsidiaries that is a coal mine operator, by individual mine.

All of the legal actions below were initiated by us to contest citations, orders or proposed assessments issued by MSHA, and if we are successful, may result in a reduction or dismissal of those citations, orders or assessments.

Three months ended December 31, 2010

MSHA Mine ID	Mine Operator		Total Dollar Value of Proposed MSHA Assessments (in thousands)	Number of Mining-Related Fatalities	Number of Written Notices of Pattern of Violations	Number of Notices of the Potential to Have a Pattern of Violations	Legal Actions pending before the Federal Mine Safety and Health Review Commission
4801645	ICG ADDCAR Systems, LLC	$	—	—	—	—	—
1202351	ICG ADDCAR Systems, LLC		—	—	—	—	1
1202416	ICG ADDCAR Systems, LLC		—	—	—	—	—
1202356	ICG ADDCAR Systems, LLC		—	—	—	—	—
4608799	ICG ADDCAR Systems, LLC		—	—	—	—	3
1517110	ICG Knott County, LLC		—	—	—	—	6
1518393	ICG Knott County, LLC		—	—	—	—	1
1518522	ICG Knott County, LLC		128	—	—	—	5
1516567	ICG Knott County, LLC		—	—	—	—	—
1519447	ICG Knott County, LLC		8	—	—	—	1
1519240	ICG Knott County, LLC		—	—	—	—	1
1518949	ICG Knott County, LLC		9	—	—	—	8
1518710	ICG Knott County, LLC		—	—	—	—	1
1517724	ICG Knott County, LLC		1	—	—	—	—
1519497	ICG Knott County, LLC		1	—	—	—	—
1519323	ICG Knott County, LLC		2	—	—	—	—
1518048	ICG Hazard, LLC		—	—	—	—	1
1518613	ICG Hazard, LLC		9	—	—	—	—
1518181	ICG Hazard, LLC		—	—	—	—	—
1517746	ICG Hazard, LLC		8	—	—	—	2
1513495	ICG Hazard, LLC		—	—	—	—	1
1519391	ICG Hazard, LLC		—	—	—	—	—
1518966	ICG Hazard, LLC		—	—	—	—	—
1519236	ICG Hazard, LLC		—	—	—	—	—
1519416	ICG Hazard, LLC		—	—	—	—	—
1515506	ICG Hazard, LLC		1	—	—	—	1
1511991	ICG Hazard, LLC		1	—	—	—	—
1518850	ICG Hazard, LLC		—	—	—	—	3
1518991	ICG Hazard, LLC		55	—	—	—	22
1519281	ICG Hazard, LLC		—	—	—	—	2

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MSHA Mine ID	Mine Operator		Total Dollar Value of Proposed MSHA Assessments (in thousands)	Number of Mining-Related Fatalities	Number of Written Notices of Pattern of Violations	Number of Notices of the Potential to Have a Pattern of Violations	Legal Actions pending before the Federal Mine Safety and Health Review Commission
1517960	ICG East Kentucky, LLC	$	—	—	—	—	—
1519382	ICG East Kentucky, LLC		—	—	—	—	—
1518193	ICG East Kentucky, LLC		—	—	—	—	—
1519070	ICG East Kentucky, LLC		4	—	—	—	—
1516290	ICG East Kentucky, LLC		—	—	—	—	—
4407060	Powell Mountain Energy, LLC		—	—	—	—	—
4407207	Powell Mountain Energy, LLC		—	—	—	—	—
4405605	Powell Mountain Energy, LLC		1	—	—	—	1
1518734	Powell Mountain Energy, LLC		39	—	—	—	19
4609115	Wolf Run Mining Company		18	—	—	—	7
4608791	Wolf Run Mining Company		—	—	—	—	3
4605544	Wolf Run Mining Company		—	—	—	—	—
4608364	Wolf Run Mining Company		—	—	—	—	—
4605823	Upshur Property, Inc.		—	—	—	—	1
4604168	Wolf Run Mining Company		190	—	—	—	32
4608777	Wolf Run Mining Company		—	—	—	—	—
4607945	ICG Eastern, LLC		—	—	—	—	—
4608390	ICG Eastern, LLC		—	—	—	—	—
4609220	ICG Eastern, LLC		—	—	—	—	—
4605252	ICG Beckley, LLC		29	—	—	—	9
4609216	ICG Beckley, LLC		—	—	—	—	—
1800749	Vindex Energy Corporation		—	—	—	—	1
1800769	Vindex Energy Corporation		—	—	—	—	—
1800170	Vindex Energy Corporation		1	—	—	—	—
4602151	Vindex Energy Corporation		—	—	—	—	1
4607837	Vindex Energy Corporation		—	—	—	—	—
4609369	Vindex Energy Corporation		4	—	—	—	—
1800709	Vindex Energy Corporation		—	—	—	—	—
1102664	ICG Illinois, LLC		189	—	—	—	27
4607654	Patriot Mining Company, Inc.		—	—	—	—	—
4607555	Patriot Mining Company, Inc.		—	—	—	—	—

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Year ended December 31, 2010

SHA Mine ID	Mine Operator		Total Dollar Value of Proposed MSHA Assessments (in thousands)	Number of Mining-Related Fatalities	Number of Written Notices of Pattern of Violations	Number of Notices of the Potential to Have a Pattern of Violations	Legal Actions pending before the Federal Mine Safety and Health Review Commission
4801645	ICG ADDCAR Systems, LLC	$	—	—	—	—	—
1202351	ICG ADDCAR Systems, LLC		—	—	—	—	1
1202416	ICG ADDCAR Systems, LLC		1	—	—	—	—
1202356	ICG ADDCAR Systems, LLC		1	—	—	—	—
4608799	ICG ADDCAR Systems, LLC		1	—	—	—	3
1517110	ICG Knott County, LLC		46	—	—	—	6
1518393	ICG Knott County, LLC		1	—	—	—	1
1518522	ICG Knott County, LLC		192	—	—	—	5
1516567	ICG Knott County, LLC		1	—	—	—	—
1519447	ICG Knott County, LLC		10	—	—	—	—
1519240	ICG Knott County, LLC		—	—	—	—	1
1518949	ICG Knott County, LLC		182	—	—	—	8
1518710	ICG Knott County, LLC		—	—	—	—	1
1517724	ICG Knott County, LLC		2	—	—	—	—
1519497	ICG Knott County, LLC		1	—	—	—	—
1519323	ICG Knott County, LLC		23	—	—	—	—
1518048	ICG Hazard, LLC		29	—	—	—	1
1518613	ICG Hazard, LLC		14	—	—	—	—
1518181	ICG Hazard, LLC		—	—	—	—	—
1517746	ICG Hazard, LLC		94	—	—	—	2
1513495	ICG Hazard, LLC		—	—	—	—	1
1519391	ICG Hazard, LLC		—	—	—	—	—
1518966	ICG Hazard, LLC		34	—	—	—	1
1519236	ICG Hazard, LLC		—	—	—	—	—
1519416	ICG Hazard, LLC		2	—	—	—	—
1515506	ICG Hazard, LLC		2	—	—	—	1
1511991	ICG Hazard, LLC		7	—	—	—	—
1518850	ICG Hazard, LLC		—	—	—	—	3
1518991	ICG Hazard, LLC		331	—	—	—	27
1519281	ICG Hazard, LLC		—	—	—	—	2

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MSHA Mine ID	Mine Operator		Total Dollar Value of Proposed MSHA Assessments (in thousands)	Number of Mining-Related Fatalities	Number of Written Notices of Pattern of Violations	Number of Notices of the Potential to Have a Pattern of Violations	Legal Actions pending before the Federal Mine Safety and Health Review Commission
1517960	ICG East Kentucky, LLC	$	3	—	—	—	—
1519382	ICG East Kentucky, LLC		—	—	—	—	—
1518193	ICG East Kentucky, LLC		—	—	—	—	—
1519070	ICG East Kentucky, LLC		4	—	—	—	—
1516290	ICG East Kentucky, LLC		1	—	—	—	—
4407060	Powell Mountain Energy, LLC		—	—	—	—	—
4407207	Powell Mountain Energy, LLC		—	—	—	—	—
4405605	Powell Mountain Energy, LLC		3	—	—	—	1
1518734	Powell Mountain Energy, LLC		399	—	—	—	20
4609115	Wolf Run Mining Company		70	—	—	—	12
4608791	Wolf Run Mining Company		—	—	—	—	4
4605544	Wolf Run Mining Company		—	—	—	—	—
4608364	Wolf Run Mining Company		—	—	—	—	—
4605823	Upshur Property, Inc.		2	—	—	—	1
4604168	Wolf Run Mining Company		603	—	—	—	42
4608777	Wolf Run Mining Company		—	—	—	—	—
4607945	ICG Eastern, LLC		4	—	—	—	—
4608390	ICG Eastern, LLC		1	—	—	—	—
4609220	ICG Eastern, LLC		—	—	—	—	—
4605252	ICG Beckley, LLC		135	1	—	—	9
4609216	ICG Beckley, LLC		—	—	—	—	—
1800749	Vindex Energy Corporation		4	—	—	—	4
1800769	Vindex Energy Corporation		1	—	—	—	1
1800170	Vindex Energy Corporation		1	—	—	—	1
4602151	Vindex Energy Corporation		—	—	—	—	1
4607837	Vindex Energy Corporation		1	—	—	—	—
4609369	Vindex Energy Corporation		4	—	—	—	—
1800709	Vindex Energy Corporation		—	—	—	—	—
1102664	ICG Illinois, LLC		566	—	—	—	30
4607654	Patriot Mining Company, Inc.		1	—	—	—	—
4607555	Patriot Mining Company, Inc.		—	—	—	—	—

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Part III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information requested by Items 401, 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is incorporated herein by reference to the definitive Proxy Statement used in connection with the solicitation of proxies for our Annual Meeting of Stockholders to be held on May 18, 2011 (the “Definitive Proxy Statement”).

ITEM 11.

EXECUTIVE COMPENSATION

The information requested by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K is incorporated herein by reference to the Definitive Proxy Statement.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information requested by Item 403 of Regulation S-K is incorporated herein by reference to the Definitive Proxy Statement.

See “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Summary of Equity Compensation Plans” on page 64 of this Annual Report on Form 10-K for information required by Item 201(d) of Regulation S-K.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information requested by Items 404 and 407(a) of Regulation S-K is incorporated herein by reference to the Definitive Proxy Statement.

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

The information requested by Item 9(e) of Schedule 14A with respect to the fees and services related to our independent registered public accounting firm, Deloitte & Touche LLP, and the disclosure of the Audit Committee’s pre-approval policies and procedures is incorporated herein by reference to the Definitive Proxy Statement.

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PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)	Financial Statements:

The following financial statements are filed as part of this Annual Report on Form 10-K under Item 8:

		Page
International Coal Group, Inc. and Subsidiaries

Report of Independent Registered Public Accounting Firm		F-1

Consolidated Balance Sheets as of December 31, 2010 and 2009		F-2

Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008		F-3

Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the years ended December 31, 2010, 2009 and 2008		F-4

Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008		F-5

Notes to Consolidated Financial Statements for the years ended December 31, 2010, 2009 and 2008		F-6

(b) Exhibits.

(i) See the Exhibit Index.

(c) Financial Statement Schedules.

		Page
Schedule I—Condensed Financial Information of the Registrant		F-47

Schedule II—Valuation and Qualifying Accounts		F-52

Schedules other than that noted above are omitted because of an absence of conditions under which they are required or because the information to be disclosed is presented in the financial statements or notes thereto.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

International Coal Group, Inc.

Scott Depot, West Virginia

We have audited the accompanying consolidated balance sheets of International Coal Group, Inc. and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules 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 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, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 17, 2011, expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Cincinnati, Ohio

February 17, 2011

F-1

Table of Contents

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2010 and 2009

(Dollars in thousands, except per share amounts)

	December 31, 2010			December 31, 2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	215,276		$	92,641
Accounts receivable, net of allowances of $1,005 and $222		82,557			80,291
Inventories, net		70,029			82,037
Deferred income taxes		13,563			15,906
Prepaid insurance		8,500			6,351
Income taxes receivable		129			1,423
Prepaid expenses and other		10,543			9,960
Total current assets		400,597			288,609

PROPERTY, PLANT, EQUIPMENT AND MINE DEVELOPMENT, net		1,040,118			1,038,200
DEBT ISSUANCE COSTS, net		11,998			7,634
ADVANCE ROYALTIES, net		16,037			18,025
OTHER NON-CURRENT ASSETS		10,947			15,492
Total assets	$	1,479,697		$	1,367,960

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	78,899		$	63,582
Short-term debt		2,797			2,166
Current portion of long-term debt and capital leases		17,928			17,794
Current portion of reclamation and mine closure costs		8,414			9,390
Current portion of employee benefits		3,831			3,973
Accrued expenses and other		61,092			74,803
Total current liabilities		172,961			171,708

LONG-TERM DEBT AND CAPITAL LEASES		308,422			366,515
RECLAMATION AND MINE CLOSURE COSTS		70,730			65,601
EMPLOYEE BENEFITS		81,868			63,767
DEFERRED INCOME TAXES		60,452			57,399
BELOW-MARKET COAL SUPPLY AGREEMENTS		26,823			29,939
OTHER NON-CURRENT LIABILITIES		4,176			3,797
Total liabilities		725,432			758,726

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY:
Preferred stock–par value $0.01, 200,000,000 shares authorized, none issued		—			—
Common stock–par value $0.01, 2,000,000,000 shares authorized, 203,870,564 and 203,824,372 shares issued and outstanding, respectively, as of December 31, 2010 and 172,820,047 and 172,812,726 shares issued and outstanding, respectively, as of December 31, 2009		2,038			1,728
Treasury stock		(216	)		(14	)
Additional paid-in capital		851,440			732,124
Accumulated other comprehensive income (loss)		(3,459	)		1,048
Retained deficit		(95,602	)		(125,713	)
Total International Coal Group, Inc. stockholders’ equity		754,201			609,173
Noncontrolling interest		64			61
Total stockholders’ equity		754,265			609,234
Total liabilities and stockholders’ equity	$	1,479,697		$	1,367,960

See notes to consolidated financial statements.

F-2

Table of Contents

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

Years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

	Year Ended December 31,
	2010			2009			2008
REVENUES:
Coal sales revenues	$	1,078,246		$	1,006,606		$	998,245
Freight and handling revenues		35,411			26,279			45,231
Other revenues		52,814			92,464			53,260
Total revenues		1,166,471			1,125,349			1,096,736

COSTS AND EXPENSES:
Cost of coal sales		850,328			832,214			882,983
Freight and handling costs		35,411			26,279			45,231
Cost of other revenues		48,331			36,089			35,672
Depreciation, depletion and amortization		104,566			106,084			96,047
Selling, general and administrative		35,569			32,749			38,147
Gain on sale of assets		(4,243	)		(3,659	)		(32,518	)
Goodwill impairment loss		—			—			30,237
Long-lived asset impairment loss		—			—			7,191
Total costs and expenses		1,069,962			1,029,756			1,102,990
Income (loss) from operations		96,509			95,593			(6,254	)
INTEREST AND OTHER EXPENSE:
Loss on extinguishment of debt		(29,409	)		(13,293	)		—
Interest expense, net		(40,736	)		(53,044	)		(43,643	)
Total interest and other expense		(70,145	)		(66,337	)		(43,643	)
Income (loss) before income taxes		26,364			29,256			(49,897	)
INCOME TAX BENEFIT (EXPENSE) BENEFIT		3,750			(7,732	)		23,670
Net income (loss)		30,114			21,524			(26,227	)
Net income attributable to noncontrolling interest		(3	)		(66	)		—
Net income (loss) attributable to International Coal Group, Inc.	$	30,111		$	21,458		$	(26,227	)

Earnings per share:
Basic	$	0.15		$	0.14		$	(0.17	)
Diluted		0.15			0.14			(0.17	)
Weighted-average common shares outstanding:
Basic		197,366,978			153,630,446			152,632,586
Diluted		205,283,999			155,386,263			152,632,586

See notes to consolidated financial statements.

F-3

Table of Contents

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

Years ended December 31, 2010, 2009 and 2008

(Dollars in thousands)

	Common Stock				Treasury Stock			Additional Paid-in Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings (Deficit)			Total International Coal Group, Inc. Stockholders’ Equity			Noncontrolling Interest			Total Stockholders’ Equity
	Shares		Amount		Treasury Stock			Additional Paid-in Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings (Deficit)			Total International Coal Group, Inc. Stockholders’ Equity			Noncontrolling Interest			Total Stockholders’ Equity
Balance—December 31, 2007	152,992,109		$	1,530	$	—		$	652,677		$	(1,530	)	$	(120,944	)	$	531,733		$	35		$	531,768
Net loss	—			—		—			—			—			(26,227	)		(26,227	)		—			(26,227	)
Postretirement benefit obligation adjustments, net of tax of $727	—			—		—			—			530			—			530			—			530
Amortization of postretirement benefit net loss, net of tax of $214	—			—		—			—			216			—			216			—			216
Black lung benefit obligation adjustments, net of tax of $548	—			—		—			—			(903	)		—			(903	)		—			(903	)
Amortization of black lung benefit net gain, net of tax of $358	—			—		—			—			(590	)		—			(590	)		—			(590	)
Comprehensive loss	—			—		—			—			—			—			—			—			(26,974	)
Issuance of restricted stock and stock awards, net of forfeitures	312,436			3		—			(3	)		—			—			—			—			—
Stock options exercised	17,700			—		—			149			—			—			149			—			149
Compensation expense on share based awards	—			—		—			4,174			—			—			4,174			—			4,174
Balance—December 31, 2008	153,322,245			1,533		—			656,997			(2,277	)		(147,171	)		509,082			35			509,117
Net income	—			—		—			—			—			21,458			21,458			66			21,524
Postretirement benefit obligation adjustments, net of tax of $323	—			—		—			—			2,663			—			2,663			—			2,663
Amortization of postretirement benefit net loss, net of tax of $117	—			—		—			—			171			—			171			—			171
Black lung benefit obligation adjustments, net of tax of $416	—			—		—			—			735			—			735			—			735
Amortization of black lung benefit net gain, net of tax of $146	—			—		—			—			(244	)		—			(244	)		—			(244	)
Comprehensive income	—			—		—			—			—			—			—			—			24,849
Purchases of treasury stock	(7,321	)		—		(14	)		—			—			—			(14	)		—			(14	)
Distributions to noncontrolling interest	—			—		—			—			—			—			—			(40	)		(40	)
Issuance of common stock in exchange for convertible notes	18,660,550			187		—			71,430			—			—			71,617			—			71,617
Issuance of restricted stock and stock awards, net of forfeitures	837,252			8		—			(8	)		—			—			—			—			—
Compensation expense on share based awards	—			—		—			3,705			—			—			3,705			—			3,705
Balance—December 31, 2009	172,812,726			1,728		(14	)		732,124			1,048			(125,713	)		609,173			61			609,234
Net income	—			—		—			—			—			30,111			30,111			3			30,114
Postretirement benefit obligation adjustments, net of tax of $4,353	—			—		—			—			(7,134	)		—			(7,134	)		—			(7,134	)
Amortization of postretirement benefit net loss, net of tax of $295	—			—		—			—			485			—			485			—			485
Black lung benefit obligation adjustments, net of tax of $1,351	—			—		—			—			2,229			—			2,229			—			2,229
Amortization of black lung benefit net gain, net of tax of $54	—			—		—			—			(87	)		—			(87	)		—			(87	)
Comprehensive income	—			—		—			—			—			—			—			—			25,607
Issuance of common stock from public offering	24,444,365			245		—			102,208			—			—			102,453			—			102,453
Issuance of convertible notes from public offering	—			—		—			20,800			—			—			20,800			—			20,800
Issuance of common stock in exchange for convertible notes	6,198,668			62		—			25,650			—			—			25,712			—			25,712
Repurchase of convertible notes	—			—		—			(32,676	)		—			—			(32,676	)					(32,676	)
Issuance of restricted stock and stock awards, net of forfeitures	365,734			3		—			(3	)		—			—			—			—			—
Purchases of treasury stock	(38,871	)		—		(202	)		—			—			—			(202	)		—			(202	)
Stock options exercised	41,750			—		—			114			—			—			114			—			114
Compensation expense on share based awards	—			—		—			3,223			—			—			3,223			—			3,223
Balance—December 31, 2010	203,824,372		$	2,038	$	(216	)	$	851,440		$	(3,459	)	$	(95,602	)	$	754,201		$	64		$	754,265

See notes to consolidated financial statements.

F-4

Table of Contents

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended December 31, 2010, 2009 and 2008

(Dollars in thousands)

	Year Ended December 31,
	2010			2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	30,114		$	21,524		$	(26,227	)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Depreciation, depletion and amortization		104,566			106,084			96,047
Loss on extinguishment of debt		29,409			13,293			—
Impairment loss		—			—			37,428
Amortization and write-off of deferred finance costs and debt discount		7,798			7,001			6,141
Amortization of accumulated employee benefit obligations		639			(102	)		(518	)
Compensation expense on share based awards		3,223			3,705			4,174
Gain on sale of assets, net		(4,243	)		(3,659	)		(32,518	)
Provision for bad debt		783			(1,294	)		994
Deferred income taxes		(4,533	)		7,859			(24,434	)
Changes in Assets and Liabilities:
Accounts receivable		(3,049	)		(3,676	)		7,918
Inventories		11,988			(23,249	)		(17,333	)
Prepaid expenses and other		(1,438	)		14,569			(3,545	)
Other non-current assets		(2,191	)		399			(2,744	)
Accounts payable		16,852			(16,814	)		7,116
Accrued expenses and other		(13,888	)		(13,089	)		24,677
Reclamation and mine closure costs		2,178			1,341			(5,281	)
Other liabilities		9,223			1,862			6,834
Net cash from operating activities		187,431			115,754			78,729
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of assets		4,764			3,695			8,786
Additions to property, plant, equipment and mine development		(102,912	)		(66,345	)		(132,197	)
Cash paid related to acquisitions, net		—			—			(603	)
Withdrawals (deposits) of restricted cash		8,807			(10,468	)		(26	)
Contribution to joint venture		—			(40	)		—
Net cash from investing activities		(89,341	)		(73,158	)		(124,040	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on short-term debt		5,191			2,611			6,310
Repayments on short-term debt		(4,560	)		(5,186	)		(1,569	)
Borrowings on long-term debt		—			9,086			3,496
Repayments on long-term debt and capital lease		(18,899	)		(19,104	)		(6,295	)
Proceeds from convertible notes offering		115,000			—			—
Proceeds from senior notes offering		198,596			—			—
Proceeds from common stock offering		102,453			—			—
Repurchases of senior notes		(188,960	)		—			—
Repurchases of convertible notes		(169,458	)		—			—
Purchases of treasury stock		(202	)		(14	)		—
Proceeds from stock options exercised		114			—			149
Debt issuance costs		(14,730	)		(1,278	)		—
Net cash from financing activities		24,545			(13,885	)		2,091
NET CHANGE IN CASH AND CASH EQUIVALENTS		122,635			28,711			(43,220	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		92,641			63,930			107,150
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	215,276		$	92,641		$	63,930

Supplemental information:
Cash paid for interest (net of amount capitalized)	$	40,807		$	47,327		$	36,193
Cash received for income taxes	$	187		$	7,006		$	—

Supplemental disclosure of non-cash items:
Issuance of common stock in exchange for convertible notes	$	25,712		$	71,617		$	—
Purchases of property, plant, equipment and mine development through accounts payable	$	15,881		$	17,416		$	12,942
Purchases of property, plant, equipment and mine development through financing arrangements	$	5,447		$	17,066		$	40,708
Assets acquired through the assumption of liabilities	$	—		$	—		$	17,464
Assets acquired through the exchange of property	$	1,277		$	—		$	22,608

See notes to consolidated financial statements.

F-5

Table of Contents

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

1.	ORGANIZATION

Entity Matters—International Coal Group, Inc. (“ICG” or the “Company”) is a leading producer of coal in Northern and Central Appalachia and also has operations and reserves in the Illinois Basin. The Company’s customers are primarily investment grade electric utilities, as well as domestic industrial and steel customers that demand a variety of coal products. The Company’s ability to produce a comprehensive range of high-Btu steam and metallurgical quality coal allows it to blend coal, which enables it to market differentiated coal products to a variety of customers with different coal quality demands.

2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Principles of Consolidation—The consolidated financial statements include the accounts of ICG, whose subsidiaries are generally controlled through a majority voting interest, but may be controlled by means of a significant noncontrolling ownership, by contract, lease or otherwise. In certain cases, ICG subsidiaries (i.e., Variable Interest Entities (“VIEs”)) may also be consolidated as required by the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 810, Consolidation (“ASC 810”). See Note 12 to the consolidated financial statements for further discussion regarding the consolidation of VIEs. The Company accounts for its undivided interest in coalbed methane wells (see Note 14) using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in the appropriate classification in the financial statements. The consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States of America. Intercompany transactions and balances have been eliminated.

Cash and Cash Equivalents—The Company considers all highly-liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. Cash equivalents consist of money market funds. Because of the short maturity of these investments, the carrying amounts approximate fair value.

Accounts Receivable and Allowance for Doubtful Accounts—Accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company establishes provisions for losses on accounts receivable when it is probable that all or part of the outstanding balance will not be collected. The Company regularly reviews collectability and establishes or adjusts the allowance as necessary.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Inventories—Components of inventories consist of coal and parts and supplies (see Note 4).

Coal inventories are stated at lower of average cost or market and represent coal contained in stockpiles, including those tons that have been mined and hauled to our loadout facilities, but not yet shipped to customers. These inventories are stated in clean coal equivalent tons and take into account any loss that may occur during the processing stage. Coal must be of a quality that can be sold on existing sales orders to be carried as coal inventory. The majority of the Company’s coal inventory does not require extensive processing prior to shipment. In most cases, processing consists of crushing or sizing the coal prior to loading into the truck or rail car for shipment to the customer.

Parts and supplies inventories are valued at average cost, less an allowance for obsolescence. The Company establishes provisions for losses in parts and supplies inventory values through analysis of turnover of inventory items and adjusts the allowance as necessary.

Financial Instruments—Pursuant to ASC Subtopic 470-20, Debt with Conversion and Other Options, the Company’s convertible notes are accounted for as convertible debt in the accompanying consolidated balance sheet and the embedded conversion option in the convertible notes has been accounted for as a component of equity.

Advance Royalties—The Company is required, under certain royalty lease agreements, to make minimum royalty payments whether or not mining activity is being performed on the leased property. These minimum payments may be recoupable once mining begins on the leased property. The recoupable minimum royalty payments are capitalized and amortized based on the units-of-production method at a rate defined in the lease agreement once mining activities begin. The Company has recorded net advance royalties of $22,166 and $23,790; the current portion of $6,128 and $5,765 is included in prepaid expense at December 31, 2010 and 2009, respectively. Unamortized deferred royalty costs are expensed when mining has ceased or a decision is made not to mine on such property. At December 31, 2010 and 2009, the Company has recorded allowances for such circumstances totaling $4,593 and $4,206, respectively and recognized losses of $1,576, $1,438 and $630 for the years ended December 31, 2010, 2009 and 2008, respectively.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Coal Supply Agreements—The Company’s below-market coal supply agreements (sales contracts) represent coal supply agreements acquired through acquisitions accounted for as business combinations for which the prevailing market price for coal specified in the contract was in excess of the contract price. The liability recorded related to these coal supply agreements was based on discounted cash flows resulting from the difference between the below-market contract price and the prevailing market price at the date of acquisition. The below-market coal supply agreements are amortized on the basis of tons shipped over the term of the respective contract. The net book value of the Company’s below-market coal supply agreements was $26,823 and $29,939 at December 31, 2010 and 2009, respectively. Amortization income on the below-market coal supply agreements was $3,116, $6,228 and $9,590 for the years ended December 31, 2010, 2009 and 2008, respectively. Amortization income is included in depreciation, depletion and amortization expense. Based on the expected shipments related to the remaining below-market contracts, the Company expects to record annual amortization income in each of the next five years as reflected in the table below.

	Below-market contracts
2011	$	3,591
2012		3,561
2013		3,561
2014		3,454
2015		2,467

During 2009, the Company terminated a below-market coal supply agreement and realized a $7,721 pre-tax non-cash gain. The gain is included in other revenues for the year ended December 31, 2009.

During 2009, three of the Company’s customers requested early termination of certain coal supply agreements. The Company received $34,880 in payments for the early termination of these agreements and the lost margin on pre-termination shipments. The income is included in other revenues for the year ended December 31, 2009.

Property, Plant, Equipment and Mine Development—Property, plant, equipment and mine development costs, including coal lands and mineral rights, are recorded at cost, which includes construction overhead and capitalized interest. Interest cost applicable to major asset additions is capitalized during the construction period and totaled $2,626, $325 and $6,721 for the years ended December 31, 2010, 2009 and 2008, respectively. Expenditures for major renewals and betterments are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Coal lands and mineral rights costs are depleted using the units-of-production method, based on estimated recoverable reserves. Mine development costs are amortized using the units-of-production method, based on estimated recoverable reserves. Other property, plant and equipment is depreciated using the straight-line method with estimated useful lives as follows:

	Years
Buildings	10 to 20
Mining and other equipment and related facilities	1 to 20
Land improvements		15
Transportation equipment	2 to 10
Furniture and fixtures	3 to 10

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Debt Issuance Costs—Debt issuance costs reflect fees incurred to obtain financing. Debt issuance costs related to the Company’s outstanding debt are amortized over the life of the related debt. Amortization expense for the years ended December 31, 2010, 2009 and 2008 was $2,166, $2,884 and $2,428, respectively, and is included in interest expense. Loss on extinguishment of debt for the year ended December 31, 2010 includes $5,279 representing deferred financing fees written-off as a result of the Company repurchasing its 2012 Convertible Notes and 2014 Senior Notes, as well as exchanging a portion of its 2012 Convertible Notes for shares of its common stock. Additionally, deferred financing fees of $1,700 were written-off as interest expense during the year ended December 31, 2010 related to the Company’s prior credit facility. Loss on extinguishment of debt for the year ended December 31, 2009 includes $1,182 representing deferred financing fees written-off as a result of the Company exchanging a portion of its 2012 Convertible Notes for shares of its common stock. See Note 6. There were no deferred financing fees written-off in 2008.

Restricted Cash—Restricted cash includes amounts required by various casualty insurance and reclamation agreements. Restricted cash of $3,250 and $12,057 at December 31, 2010 and 2009, respectively, is included in other non-current assets.

Coal Mine Reclamation and Mine Closure Costs—The Company’s asset retirement obligations arise from the Federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The Company records these reclamation obligations according to the provisions of ASC Topic 410, Asset Retirement and Environmental Obligations (“ASC 410”). ASC 410 requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which the legal obligation associated with the retirement of the long-lived asset is incurred. Fair value of reclamation liabilities is determined based on the present value of the estimated future expenditures. 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 future value and the capitalized cost is depreciated over the useful life of the related asset. To settle the liability, the mine property is reclaimed, and to the extent there is a difference between the liability and the amount of cash paid to perform the reclamation, a gain or loss upon settlement is recognized. On at least an annual basis, the Company reviews its entire reclamation liability and makes necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures and revisions to cost estimates and productivity assumptions.

Asset Impairments—The Company follows ASC Subtopic 360-10-45, Impairment or Disposal of Long-Lived Assets (“ASC 360-10-45”) which requires that projected future cash flows from use and disposition of long-lived assets be compared with the carrying amounts of those assets when impairment indicators are present. When the sum of projected cash flows is less than the carrying amount, impairment losses are indicated. If the fair value of the assets is less than the carrying amount of the assets, an impairment loss is recognized. In determining such impairment losses, discounted cash flows or asset appraisals are utilized to determine the fair value of the assets being evaluated. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine’s underlying costs are not recoverable in the future, reclamation and mine closure obligations are accelerated and the mine closure accrual is increased accordingly. To the extent it is determined asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized. During the year ended December 31, 2008, the Company recognized an impairment loss of $7,191 in accordance with ASC 360. No such losses were incurred in 2010 or 2009. See Note 5.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Income Tax Provision—The provision for income taxes includes federal, state and local income taxes currently payable and a portion related to deferred tax assets and liabilities. Income taxes are recorded under the liability method. Under this method, deferred income taxes are recognized for the estimated future tax effects of differences between the tax basis of assets and liabilities and their financial reporting amounts, as well as net operating loss carryforwards and tax credits based on enacted tax laws. Valuation allowances are established when necessary to reduce deferred tax assets to the amount expected to be realized.

A tax position is initially recognized in the financial statements when it is more likely than not the position will be sustained upon examination by applicable taxing authorities. Such tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with the taxing authority assuming full knowledge of the position and all relevant facts. The Company recognizes interest expense and penalties related to unrecognized tax benefits as interest expense and other expense, respectively, in its consolidated statement of operations.

Revenue Recognition—Coal revenues result from sales contracts (long-term coal contracts or purchase orders) with electric utilities, industrial companies or other coal-related organizations, primarily in the eastern United States. Revenue is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable and the title or risk of loss has passed in accordance with the terms of the sales agreement. Under the typical terms of these agreements, risk of loss transfers to the customers at the mine or port, when the coal is loaded on the rail, barge, truck or other transportation source that delivers coal to its destination.

Freight and handling costs paid to third-party carriers and invoiced to coal customers are recorded as freight and handling costs and freight and handling revenues, respectively.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Postretirement Benefits Other Than Pensions—As prescribed by ASC Topic 715, Compensation–Retirement Benefits (“ASC 715”), accruals are made during an employee’s actual working career, based on actuarially determined estimates, for the expected costs of providing postretirement benefits other than pensions for current and future retired employees and their dependents, which are primarily healthcare benefits. Actuarial gains and losses are amortized over the estimated average remaining service period for active employees utilizing the minimum amortization method prescribed by ASC 715. The Company’s liability is reduced by the amount of Medicare prescription drug reimbursement that it expects to receive under the Drug Improvement and Modernization Act of 2003. See Note 10. Changes in the funded status of the plan when the obligation is remeasured, are recognized through comprehensive income.

Workers’ Compensation and Black Lung Benefits—The Company is liable under federal and state laws to pay workers’ compensation and pneumoconiosis (black lung) benefits to eligible employees. The Company utilizes a combination of participation in a state run program and insurance policies. For black lung liabilities, provisions are made for actuarially determined estimated benefits. The Company follows ASC Topic 712, Compensation–Nonretirement Postemployment Benefits (“ASC 712”) for purposes of accounting for its workers’ compensation and black lung liabilities. Changes in the funded status of the black lung obligation when the obligation is remeasured are recognized through comprehensive income.

Share Based Compensation—The Company accounts for its share based awards in accordance with ASC Topic 718, Compensation–Stock Compensation (“ASC 718”), which establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. The Company measures share based compensation cost based upon the grant date fair value of the award, which is recognized as expense on a straight-line basis over the corresponding vesting period. The Company uses the Black-Scholes option valuation model to determine the estimated fair value of its stock options at the date of grant. Determining the fair value of share based awards at the grant date requires several assumptions. These assumptions include the expected life of the option, the risk-free interest rate, expected volatility of the price of the Company’s common stock and expected dividend yield on the Company’s common stock. See Note 11.

Cost of Other Revenues—Cost of other revenues includes costs of contract mining, coalbed methane activities, ash disposal services, equipment and parts sales, equipment rebuild and maintenance services, royalties and coal handling and processing income, as well as costs incurred associated with other non-coal producing transactions. For the year ended December 31, 2010, cost of other revenues includes a $10,000 payment made in the second quarter of 2010 related to the early termination of a coal supply agreement.

Corporate Vacation Policy—In June 2009, the Company changed its policy related to when employees are credited with vacation time. Under the original policy, employees earned their vacation in the year prior to vesting, and were vested with 100% of their annual vacation time on January 1st of each year. Under the revised policy, employees are vested in their vacation time ratably throughout the year as it is earned. Accordingly, the Company did not record accruals in 2009 for vacation time to be vested in 2010. If the Company continued to account for vacation under the old policy, it would have recognized additional cost of coal sales, cost of other revenues and selling, general and administrative expenses of $7,001, $433 and $511, respectively, for the year ended December 31, 2009.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Management’s Use of Estimates—The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant items subject to such estimates and assumptions include, but are not limited to: the allowance for doubtful accounts; coal inventories; parts and supplies inventory reserves; coal lands and mineral rights; advance royalty reserves; asset retirement obligations; share-based compensation; employee benefit liabilities; future cash flows associated with assets; useful lives for depreciation, depletion and amortization; income taxes; and fair value of financial instruments. Due to the subjective nature of these estimates, actual results could differ from those estimates.

Recent Accounting Pronouncements—In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements (“ASU 2010-06”). This amendment to ASC Topic 820, Fair Value Measurements and Disclosures, requires additional disclosures about fair value measurements. ASU 2010-06 is effective for interim and annual periods beginning after December 15, 2009, except for disclosures about purchases, sales, issuance and settlements in the roll forward of activity in Level III fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Adoption of ASU 2010-06 did not have a material effect on the Company’s financial position, results of operations or cash flows.

In June 2009, the FASB issued updates to ASC Topic 810, Consolidation (“ASC 810”) to improve financial reporting by enterprises involved with variable interest entities. ASC 810 is effective as of the first fiscal year beginning after November 15, 2009. Adoption of ASC 810 did not have a material impact on the Company’s financial position, results of operations or cash flows.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

3.	CAPITAL RESTRUCTURING

In March 2010, the Company completed public offerings of 24,444,365 shares of its common stock, par value $0.01 per share (the “Common Stock”), at a public offering price of $4.47 per share, $115,000 aggregate principal amount of 4.00% Convertible Senior Notes due 2017 (the “2017 Convertible Notes”) and $200,000 aggregate principal amount of 9.125% Senior Secured Second-Priority Notes due 2018 (the “2018 Senior Notes”) pursuant to a shelf registration statement deemed effective by the Securities and Exchange Commission on January 15, 2010.

During 2010, the Company used $169,458 of the net proceeds from the Common Stock and 2017 Convertible Notes offerings to finance the repurchase of $138,771 aggregate principal amount of its 9.00% Convertible Senior Notes due 2012 (the “2012 Convertible Notes”). The Company used $188,960 of the net proceeds from the 2018 Senior Notes offering to finance the repurchase of $175,000 aggregate principal amount of its 10.25% Senior Notes due 2014 (the “2014 Senior Notes”). The remaining proceeds were used for general corporate purposes. Additionally, the Company entered into a series of agreements to exchange a portion of its outstanding 2012 Convertible Notes for shares of common stock in December 2009. One exchange agreement, as amended, provided for closing of additional exchanges in January 2010 (see Note 6). The Company recorded loss on extinguishment of debt of $29,409 related to these debt repurchases and exchanges.

The Company secured a new four-year $125,000 asset-based loan facility (the “ABL Loan Facility”) to replace its prior revolving credit facility which was set to expire in June 2011. The ABL Loan Facility provides the potential for $25,000 in additional borrowing capacity, contains minimal financial covenants and matures in February 2014. The ABL Loan Facility has been used primarily for issuing letters of credit that collateralize the Company’s reclamation bonds.

4.	INVENTORIES

As of December 31, 2010 and 2009, inventories consisted of the following:

	2010			2009
Coal	$	37,126		$	49,120
Parts and supplies		35,288			35,065
Reserve for obsolescence, parts and supplies		(2,385	)		(2,148	)
Total	$	70,029		$	82,037

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

5.	PROPERTY, PLANT, EQUIPMENT AND MINE DEVELOPMENT

As of December 31, 2010 and 2009, property, plant, equipment and mine development are summarized by major classification as follows:

	2010			2009
Coal lands and mineral rights	$	586,618		$	586,706
Plant and equipment		655,014			620,451
Mine development		242,699			195,756
Land and land improvements		24,781			26,351
Coalbed methane well development costs		14,697			14,889
		1,523,809			1,444,153
Less accumulated depreciation, depletion and amortization		(483,691	)		(405,953	)
Net property, plant and equipment	$	1,040,118		$	1,038,200

Depreciation, depletion and amortization expense related to property, plant, equipment and mine development for the years ended December 31, 2010, 2009 and 2008 was $107,538, $112,267 and $105,637, respectively.

In June 2008, the Company exchanged certain coal reserves with a third-party. In addition to reserves, the Company received $3,000 in cash. As a result, the Company recognized a pre-tax gain of $24,633 based upon the fair value of the underlying assets received in the exchange, which is included in gain on sale of assets in its statement of operations for the year ended December 31, 2008. Additionally, in September 2008, the Company exchanged certain property resulting in the recognition of a $975 pre-tax gain based upon the fair value of the underlying assets given up in the exchange. The gain is included in gain on sale of assets in the Company’s statement of operations for the year ended December 31, 2008.

In December 2008, the Company made the decision to permanently close its Sago mine during the first quarter of 2009. As a result of this decision, the Company recognized a $7,191 impairment charge. The assets of the Sago mine had been included in the Company’s Northern Appalachian business segment.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

DEBT

Long-Term Debt and Capital Lease

As of December 31, 2010 and 2009, long-term debt and capital lease consisted of the following:

	2010			2009
9.125% Senior Notes, due 2018, net of debt discount of $1,308	$	198,692		$	—
4.00% Convertible Senior Notes, due 2017, net of debt discount of $31,882		83,118			—
9.00% Convertible Senior Notes, due 2012, net of debt discount of $28 and $9,480, respectively		703			152,022
10.25% Senior Notes, due 2014		—			175,000
Equipment notes		42,730			54,417
Capital lease and other		1,107			2,870
Total		326,350			384,309
Less current portion		(17,928	)		(17,794	)
Long-term debt and capital lease	$	308,422		$	366,515

9.125% Senior notes due 2018—On March 22, 2010, the Company completed a public offering of $200,000 aggregate principal amount of its 2018 Senior Notes, with net proceeds of $193,596 to the Company after deducting discounts and underwriting fees of $6,404. Interest on the 2018 Senior Notes is payable semi-annually in arrears on April 1st and October 1st of each year, commencing October 1, 2010. The obligations under the 2018 Senior Notes are fully and unconditionally guaranteed, jointly and severally, by all of the Company’s wholly-owned domestic subsidiaries other than subsidiaries that are designated as unrestricted subsidiaries. The 2018 Senior Notes and the guarantees are secured by a second-priority lien on, and security interest in, substantially all of the Company’s and the guarantors’ assets, junior to first-priority liens that secure the Company’s ABL Loan Facility and certain other permitted liens under the indenture that governs the notes. Prior to April 1, 2014, the Company may redeem all or a part of the 2018 Senior Notes at a price equal to 100% of the principal amount plus an applicable “make-whole” premium and accrued and unpaid interest to the redemption date. The Company may redeem the 2018 Senior Notes, in whole or in part, beginning on April 1, 2014. The initial redemption price will be 104.563% of their aggregate principal amount, plus accrued and unpaid interest. The redemption price declines to 102.281% and 100.000% of their aggregate principal amount, plus accrued and unpaid interest, on April 1, 2015 and April 1, 2016 and thereafter, respectively. In addition, at any time and from time to time prior to April 1, 2013, the Company may redeem up to 35% of the 2018 Senior Notes at a redemption price equal to 109.125% of its principal amount plus accrued and unpaid interest using proceeds from sales of certain kinds of the Company’s capital stock. Upon the occurrence of a change of control or the sale of the Company’s assets, it may be required to repurchase some or all of the notes.

The indenture governing the 2018 Senior Notes contains covenants that limit the Company’s ability to, among other things, incur additional indebtedness, issue preferred stock, pay dividends, repurchase, repay or redeem its capital stock, make certain investments, sell assets and incur liens. As of December 31, 2010, the Company was in compliance with its covenants under the indenture.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

4.00% Convertible senior notes due 2017—On March 16, 2010, the Company completed a public offering of $115,000 aggregate principal amount of its 2017 Convertible Notes. Net proceeds from the offering were $111,550, after deducting underwriting fees of $3,450. The 2017 Convertible Notes are the Company’s senior unsecured obligations and are guaranteed jointly and severally on a senior unsecured basis by all of the Company’s material future and current domestic subsidiaries or that guarantee the ABL Loan Facility on a senior basis. The 2017 Convertible Notes and the related guarantees rank equal in right of payment to all of the Company’s and the guarantors’ respective existing and future unsecured senior indebtedness. Interest is payable semi-annually in arrears on April 1st and October 1st of each year, commencing October 1, 2010. The Company assesses the convertibility of the 2017 Convertible Notes on an ongoing basis. The 2017 Convertible Notes were not convertible as of December 31, 2010.

The 2017 Convertible Notes are convertible into the Company’s common stock at an initial conversion price, subject to adjustment, of $5.81 per share (approximating 172.0874 shares per one thousand dollar principal amount of the 2017 Convertible Notes). Holders may convert their notes at their option prior to January 1, 2017 only under the following circumstances: (i) during any calendar quarter after the calendar quarter ending September 30, 2010 (and only during that quarter), if the closing sale price of the Company’s common stock for each of 20 or more trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the conversion price of such notes in effect on the last trading day of the immediately preceding calendar quarter; (ii) during the five consecutive business days immediately after any five consecutive trading day period, or the note measurement period, in which the trading price per note for each trading day of that note measurement period was equal to or less than 97% of the product of the closing sale price of shares of the Company’s common stock and the applicable conversion rate for such trading day; and (iii) upon the occurrence of specified corporate transactions. In addition, the notes will be convertible irrespective of the foregoing circumstances from, and including, January 1, 2017 to, and including, the business day immediately preceding April 1, 2017. Upon conversion, the Company will have the right to deliver cash, shares of its common stock or a combination thereof, at the Company’s election. At any time on or prior to the 23rd business day immediately preceding the maturity date, the Company may irrevocably elect to deliver solely shares of its common stock in respect of the Company’s conversion obligation or pay cash up to the aggregate principal amount of the notes to be converted and deliver shares of its common stock, cash or a combination thereof in respect of the remainder, if any, of the conversion obligation. It is the Company’s current intention to settle the principal amount of any notes converted in cash. The conversion rate, and thus the conversion price, will be subject to adjustment. A holder that surrenders notes for conversion in connection with a “make-whole fundamental change” that occurs before the maturity date may in certain circumstances be entitled to an increased conversion rate. In the event the 2017 Convertible Notes become convertible, the Company would be required to classify the entire amount outstanding of the 2017 Convertible Notes as a current liability. For a discussion of the effects of the 2017 Convertible Notes on earnings per share, see Note 15.

As of December 31, 2010, the equity component of the 2017 Convertible Notes was $20,786 and is included in additional paid-in capital. Interest expense resulting from amortization of the debt discount was $2,829 for the year ended December 31, 2010. Interest expense on the principal amount of the 2017 Convertible Notes was $3,642 for the year ended December 31, 2010. The Company has determined its non-convertible borrowing rate would have been 10.1% at issuance.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

9.00% Convertible senior notes due 2012—In December 2009, the Company entered into a series of privately negotiated agreements to exchange shares for its outstanding 2012 Convertible Notes. In connection with such agreements, the Company issued a total of 18,660,550 shares of its common stock in exchange for $63,498 aggregate principal amount of its 2012 Convertible Notes during December 2009. One of the exchange agreements, as amended, provided for closing of additional exchanges on each of January 11, 2010 and January 19, 2010 for exchange transactions occurring in 2010. Subsequent to December 31, 2009, the noteholder exchanged $22,000 aggregate principal amount of 2012 Convertible Notes for 6,198,668 shares of the Company’s common stock. As a result of the exchanges settled in January 2010, the Company recognized a loss on extinguishment of the related debt totaling $5,397 during the year ended December 31, 2010. During 2010, the Company used the net proceeds from its Common Stock and 2017 Convertible Notes offerings (see Note 3) to finance the repurchase of $138,771 aggregate principal amount of 2012 Convertible Notes.

The 2012 Convertible Notes are the Company’s senior unsecured obligations and are guaranteed on a senior unsecured basis by the Company’s material current and future domestic subsidiaries. The 2012 Convertible Notes and the related guarantees rank equal in right of payment to all of the Company’s and the guarantors’ respective existing and future unsecured senior indebtedness. Interest is payable semi-annually in arrears on February 1st and August 1st of each year. The Company assesses the convertibility of the 2012 Convertible Notes on an ongoing basis. The 2012 Convertible Notes were not convertible as of December 31, 2010.

The principal amount of the 2012 Convertible Notes is payable in cash and amounts above the principal amount, if any, will be convertible into shares of the Company’s common stock or, at the Company’s option, cash. The 2012 Convertible Notes are convertible at an initial conversion price, subject to adjustment, of $6.10 per share (approximating 163.8136 shares per one thousand dollar principal amount of the 2012 Convertible Notes). The 2012 Convertible Notes are convertible upon the occurrence of certain events, including (i) prior to February 12, 2012 during any calendar quarter after September 30, 2007, if the closing sale price per share of the Company’s common stock for each of 20 or more trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the conversion price in effect on the last trading day of the immediately preceding calendar quarter; (ii) prior to February 12, 2012 during the five consecutive business days immediately after any five consecutive trading day period in which the average trading price for the notes on each day during such five trading day period was equal to or less than 97% of the closing sale price of the Company’s common stock on such day multiplied by the then current conversion rate; (iii) upon the occurrence of specified corporate transactions; and (iv) at any time from, and including February 1, 2012 until the close of business on the second business day immediately preceding August 1, 2012. In addition, upon events defined as a “fundamental change” under the 2012 Convertible Notes indenture, the Company may be required to repurchase the 2012 Convertible Notes at a repurchase price in cash equal to 100% of the principal amount of the notes to be repurchased, plus any accrued and unpaid interest to, but excluding, the fundamental change repurchase date. In the event the 2012 Convertible Notes become convertible, the Company would be required to classify the entire amount outstanding of the 2012 Convertible Notes as a current liability. In addition, if conversion occurs in connection with certain changes in control, the Company may be required to deliver additional shares of the Company’s common stock (a “make-whole” premium) by increasing the conversion rate with respect to such notes. For a discussion of the effects of the 2012 Convertible Notes on earnings per share, see Note 15.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

As of December 31, 2010 and 2009, the equity component of the 2012 Convertible Notes was $44 and $9,702, respectively, and is included in additional paid-in capital. Interest expense resulting from amortization of the debt discount was $1,006, $4,117 and $3,714 for the years ended December 31, 2010, 2009 and 2008, respectively. Interest expense on the principal amount of the 2012 Convertible Notes was $4,512, $20,042 and $20,250 for the years ended December 31, 2010, 2009 and 2008, respectively. The Company has determined its non-convertible borrowing rate would have been 11.7% at issuance.

10.25% Senior notes due 2014—The Company used the net proceeds from its 2017 Senior Notes offering (see Note 3) to finance the repurchase of $175,000 aggregate principal amount of its 2014 Senior Notes. There were no 2014 Senior Notes outstanding as of July 15, 2010.

Asset-based loan facility—On February 22, 2010, the Company entered into an ABL Loan Facility which replaced its prior senior secured credit facility. The ABL Loan Facility is a $125,000 senior secured facility with a four-year term, all of which is available for loans or the issuance of letters of credit. Subject to certain conditions, at any time prior to maturity, the Company will be able to elect to increase the size of the ABL Loan Facility, up to a maximum of $200,000. Availability under the ABL Loan Facility is determined using a borrowing base calculation. The ABL Loan Facility is guaranteed by all of the Company’s current and future wholly-owned subsidiaries and secured by a first priority security interest on all of the Company’s and each of the Company’s guarantors’ existing and after-acquired real and personal property, including all outstanding equity interests of the Company’s wholly-owned subsidiaries. The ABL Loan Facility has a maturity date of February 22, 2014. As of December 31, 2010, the Company had a borrowing capacity of $105,977 under the ABL Loan Facility with no borrowings outstanding, letters of credit totaling $86,337 outstanding and $19,640 available for future borrowing, and was in compliance with its financial covenants under the ABL Loan Facility. The ABL Loan Facility was amended on May 6, 2010 for minor technical corrections.

Equipment notes—The equipment notes, having various maturity dates extending to April 2015, are collateralized by mining equipment. As of December 31, 2010, the Company had amounts outstanding with terms ranging from 36 to 60 months and a weighted-average interest rate of 7.38%. As of December 31, 2010, the Company had a borrowing capacity of $19,413 available under its revolving equipment credit facility for terms from 36 to 60 months at an interest rate of 6.25%.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Capital lease and other—The Company leases certain mining equipment under a capital lease. The Company imputed interest on its capital lease using a rate of 10.44%.

Future maturities of long-term debt and capital lease are as follows as of December 31, 2010:

Year ending December 31:
2011	$	17,928
2012		16,357
2013		9,029
2014		1,149
2015		105
Thereafter		315,000
Total		359,568
Less debt discount		(33,218	)
Total	$	326,350

Short-Term Debt

The Company finances the majority of its annual insurance premiums with the related obligation included in short-term debt. The weighted-average interest rate applicable to the notes was 2.04% at December 31, 2010. As of December 31, 2010 and 2009, the Company had $2,797 and $2,166, respectively, outstanding related to insurance financing.

7.	ACCRUED EXPENSES AND OTHER

As of December 31, 2010 and 2009, accrued expenses and other consisted of the following:

	2010		2009
Compensation and related expenses	$	28,860	$	33,414
Interest		6,370		15,690
Royalties		6,452		6,177
Sales and production related taxes		4,842		5,395
Deferred revenue		846		454
Personal property, land and mineral taxes		5,566		4,717
Transportation		2,208		1,946
Other		5,948		7,010
Total	$	61,092	$	74,803

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

8.	ASSET RETIREMENT OBLIGATION

The Company’s reclamation liabilities primarily consist of spending estimates related to reclaiming surface land and support facilities at both surface and underground mines in accordance with federal and state reclamation laws as defined by each mine permit. The obligation and corresponding asset are recognized in the period in which the liability is incurred.

The Company estimates its ultimate reclamation liability based upon detailed engineering calculations of the amount and timing of the future cash flows to perform the required work. These estimates are reviewed on an annual basis and revised as a result of changes in mine plans, changes in the estimated amount of work necessary to complete the reclamation, changes in the timing of performing the work and changes in the estimated costs to complete the reclamation work. The Company considers the estimated current cost of reclamation and applies inflation rates and third-party profit margins. The third-party profit margins are estimates of the approximate markup that would be charged by contractors for work performed on the Company’s behalf. The discount rate applied is based on the rates of treasury bonds with maturities similar to the estimated future cash flows, adjusted for the Company’s credit standing. The assets that give rise to the obligation are primarily related to mine development, preparation plants and loadouts.

The following schedule represents activity in the accrual for reclamation and mine closure costs for the years ended December 31, 2010 and 2009:

	2010			2009
Balance at beginning of year	$	74,991		$	79,246
Revisions of estimated cash flows		1,144			(3,574	)
Liabilities incurred (net of disposals)		973			(546	)
Expenditures		(5,310	)		(7,566	)
Accretion		7,346			7,431
Balance at end of year	$	79,144		$	74,991

At December 31, 2010 and 2009, the accrued reclamation and mine closure costs are included in the accompanying consolidated balance sheets as follows:

	2010		2009
Current portion of reclamation and mine closure costs	$	8,414	$	9,390
Non-current portion of reclamation and mine closure costs		70,730		65,601
Total	$	79,144	$	74,991

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

9.	INCOME TAXES

The income tax (benefit) expense for the years ended December 31, 2010, 2009 and 2008 is comprised of the following:

	2010			2009			2008
Current:
Federal	$	—		$	(1,249	)	$	374
State		783			1,122			390
		783			(127	)		764
Deferred:
Federal		(2,296	)		5,582			(21,877	)
State		(2,237	)		2,277			(2,557	)
		(4,533	)		7,859			(24,434	)
Income tax (benefit) expense	$	(3,750	)	$	7,732		$	(23,670	)

The following table presents the difference between the income tax expense (benefit) in the accompanying statements of operations and the amounts obtained by applying the statutory U.S. federal income tax rate of 35% to income and losses before income taxes for the years ended December 31, 2010, 2009 and 2008:

	2010			2009			2008
Federal income tax expense (benefit) computed at statutory rate	$	9,227		$	10,298		$	(17,464	)
State income tax expense (benefit), net of federal tax effect, computed at statutory rate		(945	)		2,235			(1,414	)
Percentage depletion in excess of tax basis at statutory rate		(14,276	)		(9,204	)		(6,477	)
Penalties		1,211			1,007			1,869
Goodwill impairment		—			—			(490	)
Loss on extinguishment of debt		266			2,841			—
Medicare Part D Subsidy		732			—			—
Other		35			555			306
Income tax (benefit) expense	$	(3,750	)	$	7,732		$	(23,670	)

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2010 and 2009 are summarized as follows:

	2010			2009
Deferred tax assets:
Accrued employee benefits	$	32,497		$	26,526
Accrued reclamation and closure		31,598			30,810
Below-market contracts		8,992			10,124
NOL carryover		86,305			79,510
Goodwill		46,622			50,528
Other		14,167			16,502
Total deferred tax assets		220,181			214,000
Valuation allowance for deferred tax assets		(2,428	)		(2,561	)
Total deferred tax assets, net of valuation allowance		217,753			211,439

Deferred tax liabilities:
Property, coal lands and mine development costs		(251,720	)		(246,579	)
Other		(12,922	)		(6,353	)
Total deferred tax liabilities		(264,642	)		(252,932	)
Net deferred tax liability	$	(46,889	)	$	(41,493	)

Classified in balance sheet:
Deferred income taxes—current	$	13,563		$	15,906
Deferred income taxes—non-current		(60,452	)		(57,399	)
Total	$	(46,889	)	$	(41,493	)

The Company has a total net operating loss (“NOL”) carryover of $226,840, of which $2,707 expires in 2024, $17,154 expires in 2025, $4,818 expires in 2026, $99,792 expires in 2027, $58,514 expires in 2028, $23,608 expires in 2029, and $20,247 expires in 2030. The Company is subject to a limitation of approximately $6,900 per year on $19,861 of NOLs attributable to certain acquired entities. However, due to the cumulative nature of the limitation, as of 2008 the Company was no longer impacted by this limitation. The Company also has an alternative minimum tax (“AMT”) loss carryover in the amount of $24,450, of which $14,325 expires in 2025, $6,900 expires in 2028 and $3,225 expires in 2029. The AMT NOL attributable to certain acquired entities of $14,325 is subject to the same annual limitation specified above for the regular NOL attributable to these entities. The NOLs reflect $2,388 of excess tax deductions, which reduce the NOL carryforward portion of the deferred tax asset. The Company will recognize the excess tax deduction at such time that the Company is in a tax paying position.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Internal Revenue Code (“IRC”) Section 382 imposes significant limitations on the annual utilization of NOL carryforwards if a “change in ownership” is deemed to occur. Generally, an ownership change is deemed to occur if the Company experiences a cumulative change in ownership of greater than 50% within a three-year testing period. The Company completed an IRC Section 382 study and determined that no ownership change had occurred in 2010.

The Company recorded valuation allowances against certain state NOL carryforwards that, more likely than not, are expected to expire without being utilized. The valuation allowance decreased $133 during the year ended December 31, 2010 and increased $165 and $808 during the years ended December 31, 2009 and 2008, respectively.

The Company files income tax returns in the U.S. and various states. Generally, the Company is no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years before 2007.

A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits at December 31, 2010, 2009 and 2008 is as follows:

	2010		2009			2008
Balance at beginning of year	$	135	$	205		$	971
Increase in unrecognized tax benefits resulting from tax positions taken during prior period		2,998		—			—
Reduction in unrecognized tax benefits as a result of the lapse of the applicable statute of limitations		—		(70	)		(127	)
Reduction in unrecognized tax benefits as a result of a settlement with taxing authorities		—		—			(639	)
Balance at end of year	$	3,133	$	135		$	205

If recognized, $147 of the gross unrecognized tax benefits at December 31, 2010 would affect the effective tax rate.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

10.	EMPLOYEE BENEFITS

Employee benefits at December 31, 2010 and 2009 are summarized as follows:

	2010			2009
Postretirement benefits	$	47,095		$	30,048
Black lung benefits		26,291			25,936
Workers’ compensation benefits		10,362			10,307
Coal Act benefits		1,393			1,449
Postemployment benefits		558			—
Total		85,699			67,740
Less current portion		(3,831	)		(3,973	)
Employee benefits—non-current	$	81,868		$	63,767

Valuation Date—All actuarially determined benefits were determined as of December 31, 2010 and 2009.

Postretirement Benefits—Employees of the Company who complete ten years of service, and certain employees who have completed eight years of service with the former Horizon Natural Resources Company and complete two years with the Company, will be eligible to receive postretirement healthcare benefits. Eligible retired employees must pay two hundred and fifty dollars per month per family. The Company accrues postretirement benefit expense based on actuarially determined amounts. The amount of postretirement benefit cost accrued is impacted by various assumptions (discount rate, healthcare cost increases, etc.) that the Company uses in determining its postretirement obligations.

In March 2010, the Patient Protection and Affordable Care Act (“PPACA”) and the Health Care and Education Reconciliation Act (“HCERA” or, collectively with PPACA, the “Health Care Reform Act”) were enacted into law. The Health Care Reform Act is a comprehensive health care reform bill that includes a provision to remove lifetime caps on medical plans. The Company’s retiree medical plan has such a cap and, as a result removing this cap, its postretirement benefit obligation was increased by $13,009. The prior service cost associated with the plan change will be amortized over the average remaining working life of the related employees. The Company incurred additional expense of $1,266 during the year ended December 31, 2010 related to the remeasurement.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

The Company assumed discount rates of 5.50% and 5.75% to determine the postretirement benefit liability as of December 31, 2010 and 2009, respectively, and 5.75% for the three months ended March 31, 2010, 6.25% for the nine months ended December 31, 2010 and 6.25% and 6.50% to determine the net periodic benefit costs for the years ended December 31, 2009 and 2008.

Postretirement benefit information for the years ended December 31, 2010 and 2009 is as follows:

	2010			2009
Changes in Benefit Obligations:
Accumulated benefit obligations at beginning of period	$	30,048		$	27,974
Plan change-prior service cost		13,009			—
Service cost		3,598			3,335
Interest cost		2,054			1,748
Actuarial gain		(1,522	)		(2,986	)
Benefits paid		(92	)		(23	)
Accumulated benefit obligation at end of period		47,095			30,048
Fair value of plan assets at end of period		—			—
Net liability recognized	$	47,095		$	30,048

The changes in the actuarial loss that are included in accumulated other comprehensive income were as follows:

	2010			2009			2008
Balance at beginning of year	$	5,274		$	8,548		$	10,235
Plan change-prior service cost		13,009			—			—
Actuarial gain		(1,522	)		(2,986	)		(1,257	)
Amortization of actuarial loss and prior service cost		(780	)		(288	)		(430	)
Balance at end of year	$	15,981		$	5,274		$	8,548

The Company expects to recognize $1,001 of the net actuarial loss as a component of the net periodic benefit cost during 2011. Components of net periodic benefit cost for the years ended December 31, 2010, 2009 and 2008 are as follows:

	2010		2009		2008
Net periodic benefit cost:
Service cost	$	3,598	$	3,335	$	2,607
Interest cost		2,054		1,748		1,627
Amortization of actuarial loss and prior service cost		780		288		430
Benefit cost	$	6,432	$	5,371	$	4,664

For measurement purposes at December 31, 2010, a 7.10% annual rate of increase in the per capita cost of covered healthcare benefits was assumed, gradually decreasing to 4.70% in 2081 and remaining level thereafter.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

The expense and liability estimates can fluctuate by significant amounts based upon the assumptions used. As of December 31, 2010, a one-percentage-point increase in assumed healthcare cost trend rates would increase total service and interest cost components and the postretirement benefit obligation by $1,568 and $9,362, respectively. Conversely, a one-percentage-point decrease would reduce total service and interest cost components and the postretirement benefit obligation by $1,251 and $7,629, respectively.

Estimated future benefit payments for the years indicated ending after December 31, 2010 are as follows:

2011	$	626
2012		1,035
2013		1,478
2014		1,757
2015		2,036
2016 – 2020		15,975
Total	$	22,907

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) provides for a prescription drug benefit under Medicare (“Medicare Part D”), as well as a federal subsidy to sponsors of retiree healthcare benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. As of December 31, 2010, the Company determined the effects of the Medicare Act resulted in a $7,219 reduction of its postretirement benefit obligation. The Medicare Act is expected to result in a $1,484 reduction of the Company’s postretirement benefit cost for the year ended December 31, 2011. The effect on the Company’s postretirement benefit cost components for 2011 includes reductions of $644, $397 and $443 to the service cost, interest cost and amortization of accumulated postretirement benefit obligation, respectively.

Under the Health Care Reform Act, the Company will no longer receive a federal income tax deduction for the expenses incurred in connection with providing the subsidized coverage to the extent of the subsidy received. Because future anticipated retiree prescription drug plan liabilities and related subsidies are already reflected in the Company’s financial statements, this change required it to reduce the value of the related tax benefits recognized in its financial statements in the period during which the Health Care Reform Act was enacted. As a result, the Company recorded a one-time, non-cash income tax charge of $829 during the year ended December 31, 2010 to reflect the impact of this change.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Black Lung—The Company’s actuarially determined liability for self-insured black lung benefits at December 31, 2010 and 2009 was based on discount rates of 5.50% and 6.00%, respectively, and various other assumptions, including incidence of claims, benefits escalation, terminations and life expectancy. The Company determined net periodic benefit costs using discount rates of 6.00%, 5.75% and 6.50% for the years ended December 31, 2010, 2009 and 2008, respectively.

The annual black lung expense consists of actuarially determined amounts for self-insured obligations.

Black lung benefit information for the years ended December 31, 2010 and 2009 is as follows:

	2010			2009
Changes in Benefit Obligations:
Accumulated benefit obligations at beginning of period	$	25,936		$	22,824
Service cost		2,443			2,771
Interest cost		1,556			1,579
Actuarial gain		(3,580	)		(1,151	)
Benefits paid		(64	)		(87	)
Accumulated benefit obligation at end of period		26,291			25,936
Fair value of plan assets at end of period		—			—
Net liability	$	26,291		$	25,936

The changes in the actuarial gain that are included in accumulated other comprehensive income were as follows:

	2010			2009			2008
Balance at beginning of year	$	(5,392	)	$	(4,631	)	$	(7,030	)
Actuarial (gain) loss		(3,580	)		(1,151	)		1,451
Amortization of actuarial gain		141			390			948
Balance at end of year	$	(8,831	)	$	(5,392	)	$	(4,631	)

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

The Company expects to recognize $310 of the net actuarial gain as a component of the net periodic benefit cost during 2010. Components of net periodic benefit cost for the years ended December 31, 2010, 2009 and 2008 are as follows:

	2010			2009			2008
Net periodic benefit cost:
Service cost	$	2,443		$	2,771		$	2,045
Interest cost		1,556			1,579			1,611
Amortization of actuarial gain		(141	)		(390	)		(948	)
Benefit cost	$	3,858		$	3,960		$	2,708

The expense and liability estimates can fluctuate by significant amounts based upon the assumptions used. As of December 31, 2010, a one-percentage-point increase or decrease in assumed medical escalation rates would not have had a material impact on the expense or related liability.

Estimated future benefit payments for the years indicated ending after December 31, 2010 are as follows:

2011	$	596
2012		836
2013		830
2014		846
2015		1,159
2016 – 2020		9,462
Total	$	13,729

The plan is unfunded; therefore, no contributions were made by the Company for the years ended December 31, 2010 and 2009.

The Health Care Reform Act also amended previous legislation related to coal workers’ pneumoconiosis (black lung), providing an automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims. These new provisions of the Health Care Reform Act may increase the number of future claims that are awarded benefits. The Company does not have sufficient claims experience since the Health Care Reform Act was passed to estimate the impact on its December 31, 2010 black lung liability of the potential increase in the number of future claims that are awarded benefits. An increase in benefits awarded could have a material impact on the Company’s financial position, results of operations or cash flows.

Workers’ Compensation—The operations of the Company are subject to the federal and state workers’ compensation laws. These laws provide for the payment of benefits to disabled workers and their dependents, including lifetime benefits for black lung. The Company’s subsidiary operations are insured by a combination of participation in a state run program and insurance policies. Based upon actuarially determined information, the Company estimates its workers’ compensation liability to be approximately $10,362 and $10,307 at December 31, 2010 and 2009, discounted at 4.50% and 4.75%, respectively.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

UMWA Combined Benefit Fund (Coal Act)—The Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”) provides for the funding of medical and death benefits for certain retired members of the UMWA. It provides for the assignment of beneficiaries to their former employers and any unassigned beneficiaries to employers based on a formula. Based upon actuarially determined amounts for the latest list of beneficiaries assigned to the Company’s Hunter Ridge Holdings, Inc. (“Hunter Ridge”) subsidiary, the Company estimates the amount of its obligation under the Coal Act to be approximately $1,393 and $1,449 as of December 31, 2010 and 2009, discounted at 4.75% and 5.50%, respectively. The Company recognized interest expense related to the Coal Act of $76, $74 and $80 for the years ended December 31, 2010, 2009 and 2008, respectively.

Postemployment Benefits—During 2010, a subsidiary of the Company implemented a new postemployment benefit for fulltime employees that were hired prior to December 31, 2009, and meet minimum eligibility requirements of age 55 and 10 years of service. Eligible employees can receive a post employment benefit of up to 280 hours of regular pay, depending on hire date and years of service, upon voluntary separation from the Company. The Company accrues for this post employment benefit over an employee’s estimated remaining eligibility period based on actuarially determined amounts. The Company estimates the amount of its obligation to be approximately $558 as of December 31, 2010 using a discount rate of 4.75%.

401(k) Plans—The Company sponsors a 401(k) savings and retirement plan for all employees, except those employed by its Hunter Ridge subsidiary. Under the plan, the Company matches voluntary contributions of participants up to a maximum contribution of 3% of a participant’s salary. The Company also contributes an additional 3% non-elective contribution for every employee eligible to participate in the program. The expense under this plan for the Company was $7,030, $7,153 and $6,971 for the years ended December 31, 2010, 2009 and 2008, respectively.

For those employees employed by Hunter Ridge, the Company also has a separate 401(k) savings plan. The plan provides for a 100% match of the first 3% of employee contributions and 50% of the next 2% of employee contributions. The Company also contributes an additional 5% non-elective contribution for every employee who meets certain eligibility requirements. The expense under this plan for the Company was $2,915, $2,537 and $1,956 for the years ended December 31, 2010, 2009 and 2008, respectively.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

11.	EMPLOYEE STOCK AWARDS

The Company’s Amended and Restated 2005 Equity and Performance Incentive Plan (the “Plan”) permits the granting of stock options, restricted shares, stock appreciation rights, restricted share units, performance shares or performance units to its employees for up to 18,000,000 shares of common stock. Option awards are generally granted with an exercise price equal to the market price of the Company’s stock at the date of grant and have 10-year contractual terms. The option and restricted stock awards generally vest in equal annual installments of 25% over a four-year period. The Company recognizes expense related to the awards on a straight-line basis over the vesting period of each separately vesting portion of the awards as if the awards were, in substance, multiple awards. The Company issues new shares upon the exercise of option awards.

The Black-Scholes option pricing model was used to calculate the estimated fair value of the options granted. The estimated grant-date fair value of the options granted in 2010, 2009 and 2008 was calculated using the following assumptions:

	2010			2009			2008
Expected term (in years)		5 - 7.5			5			5
Expected volatility		50.8% - 67.4	%		48.2% - 50.8	%		43.0% - 48.2	%
Weighted-average volatility		67.4	%		50.8	%		43.5	%
Risk-free rate		1.2% - 3.1	%		1.4% - 2.8	%		1.7% - 3.7	%
Expected dividends		—			—			—

The Company estimated forfeiture rates of 5.50%, 4.50% and 4.50% for 2010, 2009 and 2008, respectively.

The Company estimates volatility using both historical and market data. The expected option term is based on historical data and exercise behavior. The risk-free interest rates are based on the rates of zero coupon U.S. Treasury bonds with similar maturities on the date of grant. The estimated forfeiture rates were determined based on historical turnover of the Company’s employees eligible under the plan.

Share based employee compensation expense of $2,005, $2,304 and $2,596, net of tax of $1,218, $1,401 and $1,578, related to stock awards outstanding was included in earnings for the years ended December 31, 2010, 2009 and 2008, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

A summary of the Company’s outstanding options as of December 31, 2010, and changes during the year ended December 31, 2010, is as follows:

Options	Shares			Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (years)		Aggregate Intrinsic Value
Outstanding at January 1, 2010		5,034,610		$	5.00
Granted		881,085			4.18
Exercised		(41,750	)		2.71
Forfeited		(99,674	)		3.23
Expired		(34,688	)		7.09
Outstanding at December 31, 2010		5,739,583			4.91		7.26	$	19,038
Vested or expected to vest at December 31, 2010		5,445,277			5.01		7.20		17,647
Exercisable at December 31, 2010		2,766,566			6.92		6.13		4,964

The weighted-average grant-date fair value of options granted during the years ended December 31, 2010, 2009 and 2008 was $2.61, $0.70 and $2.64, respectively. The total intrinsic value of options exercised during the year ended December 31, 2010 and 2008 was $131 and $47, respectively. There were no options exercised in 2009.

A summary of the status of the Company’s nonvested restricted stock awards as of December 31, 2010, and changes during the year ended December 31, 2010, is as follows:

Nonvested Shares	Shares			Weighted- Average Grant-Date Fair Value
Nonvested at January 1, 2010		1,148,479		$	2.97
Granted		396,885			4.25
Vested		(357,637	)		3.69
Forfeited		(42,721	)		3.47
Nonvested at December 31, 2010		1,145,006			3.17

The weighted-average grant-date fair value of restricted stock granted during the years ended December 31, 2010, 2009 and 2008 was $4.25, $1.56 and $6.74, respectively. The total fair value of restricted stock vested during the years ended December 31, 2010, 2009 and 2008 was $1,320, $1,649 and $3,361, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

A summary of the Company’s nonvested restricted share unit awards as of December 31, 2010, and changes during the year ended December 31, 2010, is as follows:

Restricted Share Units	Shares			Weighted- Average Grant-Date Fair Value
Nonvested at January 1, 2010		—		$	—
Granted		85,155			4.11
Vested		(85,155	)		4.11
Forfeited		—			—
Nonvested at December 31, 2010		—			—

The weighted-average grant-date fair value of restricted share units granted during the years ended December 31, 2010 and 2009 was $4.11 and $1.52, respectively. The total fair value of restricted share units vested during both of the years ended December 31, 2010 and 2009 was $350.

As of December 31, 2010, there was $5,789 of unrecognized compensation cost related to non-vested share based awards that is expected to be recognized over a weighted-average period of 2.6 years.

The Plan provides recipients the ability to satisfy tax obligations upon vesting of shares of restricted stock by having the Company withhold a portion of the shares otherwise deliverable to the recipients. During the year ended December 31, 2010, the Company withheld 38,871 shares of common stock from employees in connection with tax withholding obligations. The value of the common stock that was withheld was based upon the closing price of the common stock on the applicable vesting dates. Such shares were included in treasury stock in the Company’s consolidated balance sheet at December 31, 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

12.	VARIABLE INTEREST ENTITIES

The Company acquired a 50% interest in Sycamore Group, LLC (“Sycamore”) in conjunction with its acquisition of Anker. Sycamore was established as a joint venture with an unrelated third-party to mine coal from the Sycamore No. 1 mine. The reserve from Sycamore No. 1 was depleted and the mine closed during the first quarter of 2007. The Company considers itself to be the primary beneficiary of Sycamore, based on an evaluation of its involvement with Sycamore and has consolidated the accounts of Sycamore as of December 31, 2010 and 2009, as well as the results of operations for the years ended December 31, 2010, 2009 and 2008. The creditors of Sycamore have no recourse to the general credit of ICG. Amounts related to Sycamore that are included in the consolidated financial statements of ICG as of and for the years ending December 31, 2010, 2009 and 2008 are as follows:

	2010		2009		2008
Assets	$	289	$	188	$	213
Liabilities		160		65		138
Revenue		—		—		—
Net income		3		66		—

13.

GOODWILL

The Company recorded goodwill related to its acquisition of certain assets and assumption of certain liabilities of Horizon Natural Resources Company (“Horizon”) and Anker Coal Group, Inc. (“Anker”)/CoalQuest Development, LLC (“CoalQuest”). The Company assigned the goodwill to certain of the acquired reporting units based on their estimated fair values. The Company tested goodwill for impairment on an annual basis, at a minimum, and more frequently if a triggering event occurred. The 2008 goodwill testing identified impairment of goodwill at the Company’s ADDCAR Systems, LLC (“ADDCAR”) subsidiary resulting in a $30,237 impairment loss.

14.	INVESTMENT IN JOINT OPERATING AGREEMENT

One of the Company’s subsidiaries, CoalQuest, entered into an agreement with CDX Gas, LLC (“CDX”) for the purpose of exploration and development of coalbed methane under a joint operating agreement, whereby CoalQuest has the right to obtain up to a 50% undivided working interest in each well drilled on property owned by the Company. The Company accounts for this joint operation using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in the appropriate classification in the Company’s financial statements. As of December 31, 2010 and 2009, the Company recorded property, plant and equipment of $189 and $1,095, net of accumulated amortization of $14,507 and $13,794, respectively, related to the operating agreement. This amount is included in property, plant, equipment and mine development in the consolidated balance sheet. For the years ended December 31, 2010, 2009 and 2008, the Company recognized $2,077, $2,972 and $11,532, respectively, of coalbed methane revenue and royalty income related to the operating agreement which is included in other revenues in the consolidated statement of operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

15.	EARNINGS PER SHARE

Basic earnings per share is computed by dividing net income or 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, restricted common stock subject to continuing vesting requirements, restricted stock units and convertible debt, pursuant to the treasury stock method.

Reconciliations of the weighted-average shares used to compute basic and diluted earnings per share for the years ended December 31, 2010, 2009 and 2008 are as follows:

	2010		2009		2008
Net income (loss) attributable to International Coal Group, Inc.	$	30,111	$	21,458	$	(26,227	)

Average common shares outstanding—basic		197,366,978		153,630,446		152,632,586
Incremental shares arising from:
Stock options		881,383		290,019		—
Restricted shares		391,038		1,367,577		—
Restricted share units		169,512		98,221		—
Convertible senior notes		6,475,088		—		—
Average common shares outstanding—diluted		205,283,999		155,386,263		152,632,586

Earnings Per Share:
Basic	$	0.15	$	0.14	$	(0.17	)
Diluted		0.15		0.14		(0.17	)

Options to purchase 2,642,322 shares of common stock outstanding at December 31, 2010 have been excluded from the computation of diluted earnings per share for the year ended December 31, 2010 because their effect would have been anti-dilutive. Options to purchase 2,748,672 shares of common stock outstanding at December 31, 2009 and 3,384,443 shares of potentially issuable common stock related to an agreement to exchange Convertible Notes subsequent to December 31, 2009 have been excluded from the computation of diluted earnings per share for the year ended December 31, 2009 because their effect would have been anti-dilutive. Options to purchase 2,831,192 shares of common stock and 556,344 shares of restricted common stock outstanding at December 31, 2008 have been excluded from the computation of diluted earnings per share for the year ended December 31, 2008 because their effect would have been anti-dilutive.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

The Company currently intends to settle the principal amount of the 2017 Convertible Notes in cash, and amounts above the principal amount, if any, will be settled with shares of the Company’s common stock or, at the Company’s option, cash. The principal amount of the 2012 Convertible Notes is payable in cash and amounts above the principal amount, if any, will be settled with shares of the Company’s common stock or, at the Company’s option, cash. The volume weighted-average price of the Company’s common stock for the applicable cash settlement averaging periods of the 2012 Convertible Notes related to 2009 and 2008 was below the initial conversion price of $6.10 per share. Accordingly, there were no potentially dilutive shares related to the 2012 Convertible Notes at December 31, 2009 and 2008.

16.	COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts—As of December 31, 2010, the Company had commitments under 25 sales contracts to deliver annually scheduled base quantities of coal to 21 customers. The contracts expire from 2011 through 2020 with the Company contracted to supply approximately 44.2 million tons of coal over the remaining lives of the contracts (approximately 10.0 million tons in 2011).

Diesel Fuel Purchase Contracts—As of December 31, 2010 and 2009, the Company had commitments to purchase $31,398 and $39,859, respectively, of diesel fuel during 2010 and 2009, respectively.

Explosives Purchase Contracts—As of December 31, 2010 and 2009, the Company had commitments to purchase $13,154 and $11,842, respectively, of ammonia-based explosives during 2010 and 2009, respectively.

Coal Purchase Contracts—As of December 31, 2010, the Company had fulfilled all of its contractual purchase obligations to purchase coal. The Company incurred purchased coal expense of approximately $16,618, $23,448 and $23,363 for the years ended December 31, 2010, 2009 and 2008 related to these coal purchase contracts.

Leases—The Company leases various mining, transportation and other equipment under operating and capital leases. Lease expense for the years ended December 31, 2010, 2009 and 2008 was $3,409, $4,138 and $4,970, respectively. Property under capital lease included in property, plant, equipment and mine development in the consolidated balance sheet at December 31, 2010 and 2009 was approximately $2,967 and $3,430, net of accumulated depreciation of approximately $849 and $386, respectively. Depreciation expense related to the asset under capital lease for the year ended December 31, 2010 and 2009 was $463 and $386, respectively, and is included in depreciation, depletion and amortization in the Company’s consolidated statement of operations. The Company entered into its only capital lease on December 31, 2008 and, accordingly, did not record depreciation expense related to the asset for the year ended December 31, 2008. The Company imputed interest on its capital lease using a rate of 10.44% in order to reduce the net minimum lease payments to present value.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

The Company also leases coal lands and mineral rights under agreements that call for royalties and wheelage to be paid as the coal is mined or transported across leased property. Total royalty expense for the years ended December 31, 2010, 2009 and 2008 was approximately $60,832, $57,448 and $54,536, respectively. Certain agreements require minimum annual royalties to be paid regardless of the amount of coal mined during the year. Certain agreements may be cancelable at the Company’s discretion.

Non-cancelable future minimum royalty and lease payments as of December 31, 2010 are as follows:

	Royalties		Operating Leases		Capital Leases
Year ended December 31,
2011	$	10,814	$	131	$	1,151
2012		9,281		58		—
2013		8,284		25		—
2014		7,961		6		—
2015		7,382		—		—
Thereafter		27,207		—		—
Total minimum lease payments	$	70,929	$	220	$	1,151
Less—amount representing interest						(44	)
Present value of minimum lease payments						1,107
Less—current portion						(1,107	)
Total long-term portion of capital leases					$	—

Bonding Royalty and Additional Payment—Lexington Coal Company, LLC (“LCC”) was organized in part by the founding ICG stockholders in conjunction with the acquisition of the former Horizon companies. LCC was organized to assume certain reclamation liabilities and assets of Horizon not otherwise being acquired by ICG or others. There was initially a limited commonality of ownership of LCC and ICG. In order to provide support to LCC, ICG provided a $10,000 letter of credit to support reclamation obligations (bonding royalty) and in addition agreed to pay a 0.75% payment on the gross sales receipts for coal mined and sold by the former Horizon companies that ICG acquired from Horizon until the completion by LCC of all reclamation liabilities that LCC assumed from Horizon. The Company made payments totaling $3,516, $4,053 and $4,457 for the years ended December 31, 2010, 2009 and 2008, respectively. ICG has determined it does not hold a significant variable interest in LCC and it is not the primary beneficiary of LCC.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Legal Matters— On August 23, 2006, a survivor of the Sago mine accident, Randal McCloy, filed a complaint in the Kanawha Circuit Court in Kanawha County, West Virginia. The claims brought by Randal McCloy and his family against the Company and certain of its subsidiaries, and against W.L. Ross & Co., and Wilbur L. Ross, Jr., individually, were dismissed on February 14, 2008, after the parties reached a confidential settlement. Sixteen other complaints have been filed in Kanawha Circuit Court by the representatives of many of the miners who died in the Sago mine accident, and several of these plaintiffs have filed amended complaints to expand the group of defendants in the cases. The complaints allege various causes of action against the Company and its subsidiary, Wolf Run Mining Company, one of its shareholders, W.L. Ross & Co., and Wilbur L. Ross, Jr., individually, related to the accident and seek compensatory and punitive damages. In addition, the plaintiffs also allege causes of action against other third parties, including claims against the manufacturer of Omega block seals used to seal the area where the explosion occurred and against the manufacturer of self-contained self-rescuer (“SCSR”) devices worn by the miners at the Sago mine. Some of these third parties have been dismissed from the actions upon settlement. The amended complaints add other of the Company’s subsidiaries to the cases, including ICG, Inc., ICG, LLC and Hunter Ridge Coal Company, unnamed parent, subsidiary and affiliate companies of the Company, W.L. Ross & Co., and Wilbur L. Ross, Jr., and other third parties, including a provider of electrical services and a supplier of components used in the SCSR devices. The Company has not accrued any liability for the remaining claims pending because it believes that it has good factual and legal defenses to the asserted claims and that, while it is possible that liability may be determined against the Company, it is not reasonably probable, and an estimate of damages, if the Company were to be found liable, cannot be made at this time. The Company believes that it is appropriately insured for these and other potential claims, and has fully paid its deductible applicable to its insurance policies. In addition to the dismissal of the McCloy claim, the Company has settled and dismissed five other actions. These settlements required the release of the Company, its subsidiaries, W.L. Ross & Co., and Wilbur L. Ross, Jr. The Company intends to vigorously defend itself against the remaining complaints.

Allegheny Energy Supply (“Allegheny”), the sole customer of coal produced at the Company’s subsidiary Wolf Run Mining Company’s (“Wolf Run”) Sycamore No. 2 mine, filed a lawsuit against Wolf Run, Hunter Ridge Holdings, Inc. (“Hunter Ridge”), and the Company in state court in Allegheny County, Pennsylvania on December 28, 2006, and amended its complaint on April 23, 2007. Allegheny claims that Wolf Run breached a coal supply contract when it declared force majeure under the contract upon idling the Sycamore No. 2 mine in the third quarter of 2006, and that Wolf Run continues to breach the contract by failing to ship in volumes referenced in the contract. The Sycamore No. 2 mine was idled after encountering adverse geologic conditions and abandoned gas wells that were previously unidentified and unmapped. After extensive searching for gas wells and rehabilitation of the mine, it was re-opened in 2007, but with notice to Allegheny that it would necessarily operate at reduced volumes in order to safely and effectively avoid the many gas wells within the reserve. The amended complaint also alleges that the production stoppages constitute a breach of the guarantee agreement by Hunter Ridge and breach of certain representations made upon entering into the contract in early 2005, a claim that Allegheny has since voluntarily dropped. Allegheny claims that it will incur costs in excess of $100,000 to purchase replacement coal over the life of the contract. The Company, Wolf Run and Hunter Ridge answered the amended complaint on August 13, 2007, disputing all of the remaining claims. On November 3, 2008, the Company, Wolf Run and Hunter Ridge filed an amended answer and counterclaim against the plaintiffs seeking to void the coal supply agreement due to, among other things, fraudulent inducement and conspiracy. The counterclaim alleges further that Allegheny breached a confidentiality agreement with Hunter Ridge, which prohibited the solicitation of its employees. After the coal supply agreement was executed, Allegheny hired the then-president of Anker Coal Group, Inc. (now Hunter Ridge) who engaged in negotiations on behalf of Wolf Run and Hunter Ridge. In addition to seeking a declaratory judgment that the coal supply

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

agreement and guaranty be deemed void and unenforceable and rescission of the contracts, the counterclaim also seeks compensatory and punitive damages. On September 23, 2009, Allegheny filed a second amended complaint alleging several alternative theories of liability in its effort to extend contractual liability to the Company, which was not a party to the original contract and did not exist at the time Wolf Run and Allegheny entered into the contract. No new substantive claims were asserted. The Company answered the second amended complaint on October 13, 2009, denying all of the new claims. The Company’s counterclaim was dismissed on motion for summary judgment entered on May 11, 2010. Allegheny’s claims against International Coal Group, Inc. were also dismissed by summary judgment, but the claims against Wolf Run and Hunter Ridge remain pending. The court conducted a non-jury trial of this matter beginning on January 10, 2011 and concluding on February 1, 2011. The court did not render a verdict at the close of the trial, but has scheduled further briefing of legal matters, and is expected to render its decision in mid-March 2011. At the trial, Allegheny presented its evidence for breach of contract and claimed that it is entitled to past and future damages in the aggregate of between $228,000 and $377,000. Wolf Run and Hunter Ridge presented their defense of the claims, including evidence with respect to the existence of force majeure conditions and excuse under the contract and applicable law. Because the court required evidence on both the issues of liability and damages, Wolf Run and Hunter Ridge presented evidence concerning damages available to Allegheny in the event the court determines that they are liable for breach of the contract, even though the Company believes that it has presented evidence that excuses it from liability. Wolf Run and Hunter Ridge presented significant evidence that Allegheny’s damages calculations significantly inflated its damages claims because Allegheny did not seek to determine cover as of the time of the breach and in some instances artificially assumed future non-delivery or did not take into account the requirement to supply coal in the future. Because the contract is for the life of the Sycamore No. 2 reserve and because Allegheny is the sole customer, the Company presented evidence that future supply of coal from the mine, as well as appropriate calculation of cover for past shortfalls, would result in a damages calculation of between zero and $6,606. The Company has not accrued any liability for the claims pending because it believes that it has good factual and legal defenses to the asserted claims.

On January 7, 2008, Saratoga Advantage Trust (“Saratoga”) filed a class action lawsuit in the U.S. District Court for the Southern District of West Virginia against the Company and certain of its officers and directors seeking unspecified damages. The complaint asserts claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder, based on alleged false and misleading statements in the registration statements filed in connection with the Company’s November 2005 reorganization and December 2005 public offering of common stock. In addition, the complaint challenges other of the Company’s public statements regarding its operating condition and safety record. On July 6, 2009, Saratoga filed an amended complaint asserting essentially the same claims but seeking to add an individual co-plaintiff. The Company has filed a motion to dismiss the amended complaint. The Company has not accrued any liability for the claims pending because it believes that it has good factual and legal defenses to the asserted claims and that an estimate of damages, if the Company were to be found liable, cannot be made at this time. The Company intends to vigorously defend the action.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

On June 11, 2010, the West Virginia Department of Environmental Protection (“WVDEP”) filed suit against ICG Eastern, LLC (“ICG Eastern”) alleging violations of the West Virginia Water Pollution Control/National Pollutant Discharge Elimination System (“WVNPDES”) and Surface Mine Permits for ICG Eastern’s Birch River surface mine. The WVDEP alleges that ICG Eastern has failed to fully comply with the effluent limits for aluminum, manganese, pH, iron and selenium contained in its WVNPDES permit. The complaint further alleges that violations of the WVNPDES permit effluent limits have caused violations of water quality standards for the same parameters in the streams receiving the discharges from this mine. The WVDEP also alleges that violations of the effluent limits in the WVNPDES permits are also violations of the regulations governing surface mining in West Virginia. ICG Eastern and the WVDEP executed a settlement agreement that will require ICG Eastern to pay a monetary penalty of $229 and accept the imposition of a compliance schedule related to selenium and other water quality parameters. The settlement agreement was submitted to the Webster County Circuit Court on December 30, 2010 where it is now pending the Court’s approval. The Company has fully reserved the expected liability.

The Sierra Club, on December 3, 2010, filed a Notice of Intent (“NOI”) to sue ICG Hazard, LLC (“Hazard”) alleging violations of the Clean Water Act and the Surface Mining Control and Reclamation Act of 1977 at Hazard’s Thunder Ridge surface mine. The NOI claims that Hazard is discharging selenium and contributing to conductivity levels in the receiving streams in violation of state and federal regulations. The Company disputes that allegation and intends to vigorously defend against any lawsuit that may result.

On December 3, 2010, the Kentucky Energy and Environment Cabinet (“Cabinet”) filed suit against ICG Hazard, LLC, ICG Knott County, LLC, ICG East Kentucky, LLC and Powell Mountain Energy, LLC (collectively, “KY Operations”) alleging that the KY Operations failed to comply with the terms and conditions of the Kentucky Pollutant Discharge Elimination System (“KPDES”) permits issued by the Cabinet’s Division of Water to the KY Operations. Among the claims lodged by the Cabinet were allegations that contract water monitoring laboratories retained by the KY Operations did not adhere to the practices and procedures required for conducting KPDES monitoring, the contract laboratories failed to properly document and maintain records of the monitoring, and the KY Operations submitted quarterly Discharge Monitoring Reports that sometimes contained inaccurate, incomplete and erroneous information. The KY Operations and the Cabinet entered a proposed Consent Judgment contemporaneously with the filing of the complaint that, if approved by the Franklin County (KY) Circuit Court, will require the KY Operations to pay a monetary penalty of $350, to prepare and implement a Corrective Action Plan that corrects the deficiencies in the respective KPDES monitoring programs, to identify the responsible corporate officers for each KPDES permit, and to provide specific detailed information in support of the Discharge Monitoring Reports to be filed for the fourth quarter 2010 and first quarter 2011. Final resolution of this matter is pending approval by the Court. On February 11, 2011, the Court entered an order allowing certain anti-mining groups to intervene in the action to contest the validity of the Consent Judgment. The hearing on the entry of the Consent Judgment is scheduled to be held on June 14, 2011. The Company has fully reserved the proposed penalty.

In addition, from time to time, the Company is involved in legal proceedings arising in the ordinary course of business. These proceedings include assessments of penalties for citations and orders asserted by the Mine Safety and Health Administration and other regulatory agencies, none of which are expected by management to, individually or in the aggregate, have a material adverse effect on the Company. In the opinion of management, the Company has recorded adequate reserves for liabilities arising in the ordinary course and it is management’s belief there is no individual case or group of related cases pending that is likely to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Environmental Matters—The exact nature of environmental control problems, if any, which the Company may encounter in the future cannot be predicted, primarily because of the increasing number, complexity and changing character of environmental requirements that may be enacted by federal and state authorities.

Performance Bonds—The Company has outstanding surety bonds with third parties of approximately $124,652 as of December 31, 2010 to secure reclamation and other performance commitments. In addition, at December 31, 2010 the Company has $86,337 of letters of credit outstanding under the revolving credit facility, $65,812 of which provides support to the third parties for their issuance of reclamation surety bonds. In addition, the Company has posted cash collateral of $3,250 and $12,057 to secure reclamation and other performance commitments as of December 31, 2010 and 2009, respectively. This cash collateral is included in other non-current assets on the consolidated balance sheets.

Contract Mining Agreements—ICG’s subsidiary, ADDCAR, performs contract mining services for various third parties and utilizes contract miners on some of its operations. Terms of the agreements generally allow either party to terminate the agreements on a short-term basis. The guaranteed monthly contract tonnage is mutually agreed upon and failure to meet the guaranteed contract tonnage may result in termination of the contract. Completion dates for work under these contracts vary in dates through 2011 or, in some cases, until all coal reserves are exhausted.

17.	CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

The Company markets its coal principally to electric utilities in the United States, the majority of which have investment grade credit ratings. As of December 31, 2010 and 2009, trade accounts receivable from electric utilities totaled approximately $36,157 and $56,222, respectively. The Company evaluates each customer’s creditworthiness prior to entering into transactions and constantly monitors the credit extended, but does not require its customers to provide collateral. Credit losses are provided for in the consolidated financial statements and historically have been minimal.

The Company did not derive 10% or more of its revenues from any single customer for the years ended December 31, 2010, 2009 and 2008.

Deposits held with banks may exceed the amount of insurance provided on such deposits. Generally, these deposits may be redeemed upon demand and are maintained with financial institutions of reputable credit and, therefore, bear minimal risk.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

18.	FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of the Company’s financial instruments are determined based on relevant market information. These estimates involve uncertainty and cannot be determined with precision. The following methods and assumptions were used to estimate the fair value of each class of financial instrument.

The Company entered into an Interest Rate Collar Agreement (the “Collar”) that expired and was settled on March 31, 2009. The interest rate collar was designed as a cash flow hedge to offset the impact of changes in the LIBOR interest rate above 5.92% and below 4.80%. The fair value of the Collar was $1,665 as of December 31, 2008 based on a forward LIBOR curve, which was observable at commonly quoted intervals for the full term of the agreement (Level 2). The Company recognized the change in the fair value of this agreement in the period of change. For the years ended December 31, 2010, 2009 and 2008, the Company recognized losses of $0, $6 and $1,993, respectively, related to the change in fair value. The losses are included in interest expense in the Company’s consolidated statements of operations.

Cash and Cash Equivalents, Accounts Receivable, Accounts Payable, Short-Term Debt and Other Current Liabilities—The carrying amounts approximate the fair value due to the short maturity of these instruments.

Long-term Debt—The fair value of the convertible notes and senior notes were based upon their respective values in active markets or the Company’s best estimate using market information. The fair value of the aggregate principal amounts outstanding as of December 31, 2010 and 2009 are as follows:

	2010				2009
	Principal Outstanding		Fair Value		Principal Outstanding		Fair Value
9.125% Senior Notes, due 2018	$	200,000	$	216,000	$	—	$	—
4.00% Convertible Senior Notes, due 2017		115,000		175,168		—		—
9.00% Convertible Senior Notes, due 2012		731		987		161,502		177,458
10.25% Senior Notes, due 2014		—		—		175,000		168,219

The carrying value of the Company’s other debt approximates fair value at December 31, 2010 and 2009.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

19.	RELATED PARTY TRANSACTIONS AND BALANCES

On December 13, 2010, pursuant to the terms of two separate registration rights agreements, the Company filed a registration statement and a preliminary prospectus supplement to permit affiliates of WL Ross & Co., LLC (“WLR”) and Fairfax Financial Holdings Limited (“Fairfax”) to resell shares of its common stock in an underwritten public offering. In connection with the offering, the Company, affiliates of WLR, affiliates of Fairfax and Merrill Lynch, Pierce, Fenner & Smith Incorporated entered into an underwriting agreement, dated as of December 14, 2010, relating to the sale of 12,268,700 and 22,577,800 shares of the Company’s common stock by affiliates of WLR and Fairfax, respectively. The offering closed on December 17, 2010. Pursuant to the terms of the two separate registration rights agreements, the Company collectively reimbursed affiliates of WLR and Fairfax $100 for fees and expenses for their counsel.

Under an Advisory Services Agreement dated as of October 1, 2004 between the Company and WLR, WLR has agreed to provide advisory services to the Company (consisting of consulting and advisory services in connection with strategic and financial planning, investment management and administration and other matters relating to the business and operation of the Company of a type customarily provided by sponsors of U.S. private equity firms to companies in which they have substantial investments, including any consulting or advisory services which the Board of Directors reasonably requests). WLR is paid a quarterly fee of $500 and reimbursed for any reasonable out-of-pocket expenses (including expenses of third-party advisors retained by WLR). The agreement is for a period of seven years; however, it may be terminated upon the occurrence of certain events.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

20.	SEGMENT INFORMATION

The Company extracts, processes and markets steam and metallurgical coal from deep and surface mines for sale to electric utilities and industrial customers, primarily in the eastern United States. The Company operates only in the United States with mines in the Central Appalachian, Northern Appalachian and Illinois Basin regions. The Company has fourteen operating locations, thirteen of which are aggregated into three reportable business segments: Central Appalachian, Northern Appalachian and Illinois Basin. The Company’s Central Appalachian operations are located in southern West Virginia, eastern Kentucky and western Virginia and include eight mining complexes. The Company’s Northern Appalachian operations are located in northern West Virginia and Maryland and include four mining complexes. The Company’s Illinois Basin operations include one mining complex. The Company also has an Ancillary category, which includes the Company’s brokered coal functions, corporate overhead, contract highwall mining services and land activities.

Reportable segment results for continuing operations for the year ended December 31, 2010 and segment assets as of December 31, 2010 were as follows:

	Central Appalachian		Northern Appalachian		Illinois Basin		Ancillary			Consolidated
Revenue	$	701,639	$	305,436	$	95,115	$	64,281		$	1,166,471
Adjusted EBITDA		146,700		58,622		23,736		(27,983	)		201,075
Depreciation, depletion and amortization		70,045		20,491		9,131		4,899			104,566
Capital expenditures		37,725		42,033		23,386		3,737			106,881
Total assets		676,076		218,115		68,467		517,039			1,479,697

Revenue in the Ancillary category consists primarily of $27,721 relating to the Company’s brokered coal sales, $18,064 relating to equipment and parts sales and $14,728 relating to contract highwall mining activities for the year ended December 31, 2010. Capital expenditures include non-cash amounts of $21,328 for the year ended December 31, 2010. Capital expenditures do not include $17,416 paid during the year ended December 31, 2010, related to capital expenditures accrued in prior periods.

Reportable segment results for continuing operations for the year ended December 31, 2009 and segment assets as of December 31, 2009 were as follows:

	Central Appalachian		Northern Appalachian		Illinois Basin		Ancillary			Consolidated
Revenue	$	734,687	$	223,486	$	83,908	$	83,268		$	1,125,349
Adjusted EBITDA		169,842		31,005		14,405		(13,575	)		201,677
Depreciation, depletion and amortization		71,298		20,991		7,957		5,838			106,084
Capital expenditures		44,289		21,159		17,573		4,864			87,885
Total assets		723,818		184,626		55,311		404,205			1,367,960

Revenue in the Ancillary category consists primarily of $41,678 relating to the Company’s brokered coal sales, $18,737 relating to contract highwall mining activities and $9,644 relating to equipment and parts sales. Capital expenditures include non-cash amounts of $34,482 for the year ended December 31, 2009. Capital expenditures do not include $12,942 paid during the year ended December 31, 2009 related to capital expenditures accrued in prior periods.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

Reportable segment results for continuing operations for the year ended December 31, 2008 and segment assets as of December 31, 2008 were as follows:

	Central Appalachian		Northern Appalachian		Illinois Basin		Ancillary			Consolidated
Revenue	$	702,958	$	230,660	$	79,682	$	83,436		$	1,096,736
Adjusted EBITDA		107,186		23,687		14,784		(18,436	)		127,221
Depreciation, depletion and amortization		64,132		17,884		7,342		6,689			96,047
Impairment losses		—		7,191		—		30,237			37,428
Capital expenditures		112,617		41,760		7,148		11,070			172,595
Total assets		751,986		184,846		40,850		372,965			1,350,647

Revenue in the Ancillary category consists primarily of $46,720 relating to the Company’s brokered coal sales and $19,862 relating to contract highwall mining activities. Capital expenditures include non-cash amounts of $53,650 for the year ended December 31, 2008. Capital expenditures do not include $14,290 paid during the year ended December 31, 2008 related to capital expenditures accrued in prior periods.

Reconciliation of net income (loss) to Adjusted EBITDA is as follows:

	Year Ended December 31,
	2010			2009		2008
Net income (loss) attributable to International Coal Group, Inc.	$	30,111		$	21,458	$	(26,227	)
Depreciation, depletion and amortization		104,566			106,084		96,047
Interest expense, net		40,736			53,044		43,643
Income tax expense (benefit)		(3,750	)		7,732		(23,670	)
Loss on extinguishment of debt		29,409			13,293		—
Impairment loss		—			—		37,428
Noncontrolling interest		3			66		—
Adjusted EBITDA	$	201,075		$	201,677	$	127,221

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

21.	SUPPLEMENTARY GUARANTOR INFORMATION

International Coal Group, Inc. (the “Parent Company”) issued its 2014 Senior Notes in June 2006, 2012 Convertible Notes in July 2007, 2018 Senior Notes and 2017 Convertible Notes (together with the 2014 Senior Notes, the 2012 Convertible Notes and the 2018 Senior Notes, the “Notes”) in March 2010.

The Parent Company has no independent assets or operations other than those related to the issuance, administration and repayment of the Notes. All subsidiaries of the Parent Company (the “Guarantors”), except for a minor non-guarantor joint venture, have fully and unconditionally guaranteed the Notes on a joint and several basis. The Guarantors are 100% owned, directly or indirectly, by the Parent Company. Accordingly, condensed consolidating financial information for the Parent Company and the Guarantors is not presented.

The Notes are senior obligations of the Parent Company and are guaranteed on a senior basis by the Guarantors and rank senior in right of payment to the Parent Company’s and Guarantors’ future subordinated indebtedness. Obligations under the ABL Loan Facility are secured on a first-priority basis and obligations under the 2018 Senior Notes are secured on a second-priority basis by substantially all of the assets of the Parent Company and the Guarantors. As a result, the 2014 Senior Notes, 2012 Convertible Notes and 2017 Convertible Notes are effectively subordinated to amounts borrowed under the ABL Loan Facility and the 2018 Senior Notes. Other than for corporate-related purposes or interest payments required by the Notes, the ABL Loan Facility restricts the Guarantors’ abilities to make loans or pay dividends to the Parent Company in excess of $25,000 per year (or at all upon an event of default) and restricts the ability of the Parent Company to pay dividends. Therefore, all but $25,000 of the Parent Company’s subsidiaries’ assets are restricted assets.

The Parent Company and Guarantors are subject to certain covenants under the indenture for the 2018 Senior Notes. Under these covenants, the Parent Company and Guarantors are, among other things, subject to limitations on the incurrence of additional indebtedness, payment of dividends and the incurrence of liens; however, the indenture contains no restrictions on the ability of the Guarantors to pay dividends or make payments to the Parent Company.

The obligations of the Guarantors are limited to the maximum amount permitted under bankruptcy law, the Uniform Fraudulent Conveyance Act, the Uniform Fraudulent Transfer Act or any similar federal or state law respecting fraudulent conveyance or fraudulent transfer.

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INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2010, 2009 and 2008

(Dollars in thousands, except per share amounts)

22.	QUARTERLY DATA (UNAUDITED)

The following is a summary of selected quarterly financial information:

	2010
	Three months ended March 31			Three months ended June 30		Three months ended September 30		Three months ended December 31
Revenue	$	288,594		$	300,440	$	313,064	$	264,373
Income from operations		20,470			18,671		35,740		21,628
Net income (loss) attributable to International Coal Group, Inc.		(8,852	)		4,482		24,850		9,631
Basic earnings per common share	$	(0.05	)	$	0.02	$	0.12	$	0.05
Diluted earnings per common share	$	(0.05	)	$	0.02	$	0.12	$	0.05

	2009
	Three months ended March 31		Three months ended June 30		Three months ended September 30		Three months ended December 31
Revenue	$	304,966	$	277,797	$	296,622	$	245,964
Income from operations		18,235		26,205		37,689		13,464
Net income (loss) attributable to International Coal Group, Inc.		3,693		10,382		18,716		(11,333	)
Basic earnings per common share	$	0.02	$	0.07	$	0.12	$	(0.07	)
Diluted earnings per common share	$	0.02	$	0.07	$	0.12	$	(0.07	)

Included in net income (loss) attributable to International Coal Group, Inc. for the three months ended December 31, 2009 are losses on extinguishment of debt totaling $13,293 related to the Company entering into a series of privately negotiated agreements pursuant to which it issued a total of 18,660,550 shares of its common stock in exchange for $63,498 aggregate principal amount of its Convertible Notes.

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Schedule I—Condensed Financial Information of the Registrant

International Coal Group, Inc.

Parent Company Balance Sheets

(Dollars in thousands, except per share amounts)

	December 31, 2010			December 31, 2009
ASSETS
CURRENT ASSETS:
Prepaid expenses and other	$	—		$	391
DEBT ISSUANCE COSTS, net		8,476			5,822
DEFERRED INCOME TAXES		48,019			37,877
INVESTMENT IN SUBSIDIARIES		985,959			906,952
Total assets	$	1,042,454		$	951,042

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	—		$	451
Accrued expenses and other		5,740			14,396
Total current liabilities		5,740			14,847

LONG-TERM DEBT		282,513			327,022
Total liabilities		288,253			341,869

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY:
Preferred stock–par value $0.01, 200,000,000 shares authorized, none issued		—			—
Common stock–par value $0.01, 2,000,000,000 shares authorized, 203,870,564 and 203,824,372 shares issued and outstanding, respectively, as of December 31, 2010 and 172,820,047 and 172,812,726 shares issued and outstanding, respectively, as of December 31, 2009		2,038			1,728
Treasury stock		(216	)		(14	)
Additional paid-in capital		851,440			732,124
Accumulated other comprehensive income (loss)		(3,459	)		1,048
Retained deficit		(95,602	)		(125,713	)
Total stockholders’ equity		754,201			609,173
Total liabilities and stockholders’ equity	$	1,042,454		$	951,042

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International Coal Group, Inc.

Parent Company Statements of Operations

(Dollars in thousands, except per share amounts)

	Year Ended December 31,
	2010			2009			2008
INCOME FROM OPERATIONS	$	—		$	—		$	—
INTEREST AND OTHER INCOME (EXPENSE):
Loss on extinguishment of debt		(29,409	)		(13,293	)		—
Interest expense, net		(31,591	)		(44,002	)		(42,905	)
Loss before income taxes		(61,000	)		(57,295	)		(42,905	)
INCOME TAX BENEFIT		22,832			19,071			16,218
EQUITY IN NET INCOME (LOSS) OF SUBSIDIARIES		68,279			59,682			460
Net income (loss)	$	30,111		$	21,458		$	(26,227	)

Earnings per share:
Basic	$	0.15		$	0.14		$	(0.17	)
Diluted		0.15			0.14			(0.17	)
Weighted-average common shares outstanding:
Basic		197,366,978			153,630,446			152,632,586
Diluted		205,283,999			155,386,263			152,632,586

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International Coal Group, Inc.

Parent Company Statements of Cash Flows

(Dollars in thousands)

	Year Ended December 31,
	2010			2009			2008
NET CASH FROM OPERATING ACTIVITIES	$	(35,240	)	$	(40,453	)	$	(38,266	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in subsidiaries		(11,898	)		40,511			38,266
Net cash from investing activities		(11,898	)		40,511			38,266
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from convertible notes offering		115,000			—			—
Proceeds from senior notes offering		198,596			—			—
Proceeds from common stock offering		102,453			—			—
Repurchases of senior notes		(188,960	)		—			—
Repurchases of convertible notes		(169,458	)		—			—
Purchases of treasury stock		(202	)		—			—
Debt issuance costs		(10,291	)		(58	)		—
Net cash from financing activities		47,138			(58	)		—
NET CHANGE IN CASH AND CASH EQUIVALENTS		—			—			—
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		—			—			—
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	—		$	—		$	—

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LONG-TERM DEBT

As of December 31, 2010 and 2009, long-term debt consisted of the following (in thousands):

	2010		2009
9.125% Senior Notes, due 2018, net of debt discount of $1,308	$	198,692	$	—
4.00% Convertible Senior Notes, due 2017, net of debt discount of $31,882		83,118		—
9.00% Convertible Senior Notes, due 2012, net of debt discount of $28 and $9,480, respectively		703		152,022
10.25% Senior Notes, due 2014		—		175,000
Long-term debt	$	282,513	$	327,022

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9.00% Convertible senior notes due 2012—In December 2009, the Company entered into a series of privately negotiated agreements in order to induce conversions of its outstanding 2012 Convertible Notes. In connection with such agreements, the Company issued a total of 18,660,550 shares of its common stock in exchange for $63,498 aggregate principal amount of its 2012 Convertible Notes during December 2009. One of the exchange agreements, as amended, provided for closing of additional exchanges on each of January 11, 2010 and January 19, 2010 for exchange transactions occurring in 2010. Subsequent to December 31, 2009, the noteholder exchanged $22,000 aggregate principal amount of 2012 Convertible Notes for 6,198,668 shares of the Company’s common stock. During 2010, the Company used the net proceeds from its Common Stock and 2017 Convertible Notes offerings (see Note 3) to finance the repurchase of $138,771 aggregate principal amount of 2012 Convertible Notes.

See Note 6 to the audited consolidated financial statements included in Item 15 of this Annual Report on Form 10-K for further discussion of the Company’s convertible and senior notes.

Future maturities of long-term debt are as follows as of December 31, 2010 (in thousands):

Year ending December 31:
2011	$	—
2012		731
2013		—
2014		—
2015		—
Thereafter		315,000
Total		315,731
Less debt discount		(33,218	)
Total	$	282,513

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Schedule II—Valuation and Qualifying Accounts

Description	Balance at Beginning of Period		Charged to Revenue, Costs or Expenses			Other Additions (Deductions)			Balance at End of Period
	(in thousands)
Year ended December 31, 2010
Allowance for doubtful accounts	$	222	$	783		$	—		$	1,005
Reserve for inventory obsolescence		2,148		237			—			2,385
Reserve for loss—advance royalties		4,206		1,576			(1,189	)		4,593
Year ended December 31, 2009
Allowance for doubtful accounts	$	1,516	$	(1,294	)	$	—		$	222
Reserve for inventory obsolescence		1,807		341			—			2,148
Reserve for loss—advance royalties		3,909		1,438			(1,141	)		4,206
Year ended December 31, 2008
Allowance for doubtful accounts	$	539	$	994		$	(17	)	$	1,516
Reserve for inventory obsolescence		778		1,029			—			1,807
Reserve for loss—advance royalties		3,771		630			(492	)		3,909

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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.

Date: February 17, 2011

INTERNATIONAL COAL GROUP, INC.

By:	/s/ Bennett K. Hatfield
	Bennett K. Hatfield President and Chief 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 and the capabilities and on the dates indicated.

Signature	Title	Date

/s/ Bennett K. Hatfield	President, Chief Executive Officer and Director	February 17, 2011
Bennett K. Hatfield	(Principal Executive Officer)

/s/ Bradley W. Harris	Senior Vice President, Chief Financial Officer and Treasurer	February 17, 2011
Bradley W. Harris	(Principal Accounting and Principal Financial Officer)

*	Non-Executive Chairman and Director	February 17, 2011
Wilbur L. Ross, Jr.

*	Director	February 17, 2011
Maurice E. Carino, Jr.

*	Director	February 17, 2011
Cynthia B. Bezik

*	Director	February 17, 2011
William J. Catacosinos

*	Director	February 17, 2011
Stanley N. Gaines

*	Director	February 17, 2011
Samuel A. Mitchell

*	Director	February 17, 2011
Wendy L. Teramoto

*	The undersigned, by signing his name hereto, does sign and execute this Annual Report on Form 10-K pursuant to the Powers of Attorney executed by the above-named officers and Directors of the Company and filed with the Securities and Exchange Commission on behalf of such officers and Directors.

INTERNATIONAL COAL GROUP, INC.

By:	/s/ Bennett K. Hatfield
	Bennett K. Hatfield, Attorney-in-Fact

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EXHIBIT INDEX

Exhibit No.	Description	Note
3.1	Second Amended and Restated Certificate of Incorporation of International Coal Group, Inc.	(A)

3.2	Third Amended and Restated By-Laws of International Coal Group, Inc., effective as of November 17, 2010	(B)

4.1	Form of Certificate of International Coal Group, Inc. Common Stock	(C)

4.2	Registration Rights Agreement, dated as of April 2005, by and among International Coal Group, Inc., ICG Holdco, Inc., WLR Recovery Fund II, L.P., Contrarian Capital Management LLC, Greenlight Capital Qualified, LP, Stark Trading, Shepherd International Coal Holdings Inc. and Varde Coal, Inc.	(D)

4.3	Registration Rights Agreement, dated as of May 16, 2008, by and between International Coal Group, Inc. and Fairfax Financial Holdings Limited	(E)

4.4	Indenture, dated as of July 31, 2007, among International Coal Group, Inc., the guarantors party thereto and The Bank of New York Trust Company, N.A., as Trustee, relating to International Coal Group, Inc.’s 9.00% Convertible Senior Notes due 2012	(F)

4.5	Form of 9.00% Convertible Senior Note due 2012 (included in Exhibit 4.4)	(F)

4.6	Form of Guarantee relating to International Coal Group, Inc.’s 9.00% Convertible Senior Notes due 2012 (included in Exhibit 4.4)	(F)

4.7	First Supplemental Indenture, dated December 3, 2009, among International Coal Group, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to International Coal Group, Inc.’s 9.00% Convertible Senior Notes due 2012	(G)

4.8	Indenture, dated as of March 16, 2010, among International Coal Group, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A.	(H)

4.9	First Supplemental Indenture, dated as of March 16, 2010, among International Coal Group, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A, relating to International Coal Group, Inc.’s 4.00% Convertible Senior Notes due 2017	(H)

4.10	Form of 4.00% Convertible Senior Notes due 2017	(H)

4.11	Second Supplemental Indenture, dated as of March 22, 2010, among International Coal Group, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to International Coal Group, Inc.’s 9.125% Senior Secured Second-Priority Notes due 2018	(I)

4.12	Form of 9.125% Senior Secured Second-Priority Notes due 2018.	(I)

4.13	Security Agreement, dated as of March 22, 2010, among International Coal Group, Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A.	(I)

4.14	Intercreditor Agreement, dated as of March 22, 2010, among International Coal Group, Inc., The Bank of New York Mellon Trust Company, N.A., General Electric Capital Corporation and UBS AG, Stamford Branch	(I)

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Exhibit No.	Description	Note
10.1	Advisory Services Agreement, effective as of October 1, 2004, between International Coal Group, LLC and W.L. Ross & Co. LLC	(J)

10.2	Amended and Restated Employment Agreement, dated as of December 31, 2009, by and between Bennett K. Hatfield and International Coal Group, Inc.	(G)

10.3	International Coal Group, Inc. Amended and Restated 2005 Equity and Performance Incentive Plan	(K)

10.4	International Coal Group, Inc. Amended and Restated 2005 Equity and Performance Incentive Plan: Incentive Stock Option Agreement	(L)

10.5	International Coal Group, Inc. Amended and Restated 2005 Equity and Performance Incentive Plan: Non-Qualified Stock Option Agreement	(L)

10.6	International Coal Group, Inc. Amended and Restated 2005 Equity and Performance Incentive Plan: Restricted Share Agreement	(L)

10.7	Form of Indemnification Agreement	(C)

10.8	International Coal Group, Inc. 2005 Amended and Restated Equity and Performance Incentive Plan: Non-Employee Director Restricted Share Unit Agreement	(L)

10.9	International Coal Group, Inc. Executive Severance Plan	(L)

10.10	International Coal Group, Inc. Director Compensation Plan	(S)

10.11	Fee Lease between Kentucky Union Company, lessor, and ICG Hazard, LLC (assigned from Leslie Resources, Inc.), lessee, of Flint Ridge Surface Mine, amended by:	(M)

	(a) Assignment of Real Property Agreements, dated September 30, 2004, assigning to ICG Hazard, LLC

	(b) Amendment, dated and effective October 23, 2007

10.12	Coal Lease between Knight-Ink Heirs, lessor, and ICG Eastern, LLC (assigned from Cherry River Coal and Coke Company), lessee, of Birch River Mine, amended by:	(M)

	(a) Amendment, dated effective October 1, 1977

	(b) Partial Assignment of Lease, dated September 20, 1984, assigning to Twin River Coal Co.

	(c) General Conveyance, Assignment and Transfer, dated December 8, 1988, assigning to Island Creek Coal Co.

	(d) Assignment, dated December 18, 1990, assigning to Laurel Run Mining Co.

	(e) Amendment and Supplement, dated and effective March 10, 1995

	(f) Assignment, dated October 9, 1995, assigning to Black Eagle Holdings, Inc.

	(g) Assignment, dated October 19, 1995, assigning to Gauley Eagle Holdings, Inc.

	(h) Consent Letter, dated as of October 25, 1995

	(i) Partial Assignment, dated October 30, 1995, assigning to East Kentucky Energy Corp.

	(j) Assignment, dated October 30, 1995, assigning to East Kentucky Energy Corp.

	(k) Assignment of Real Property Agreements, dated September 30, 2004, assigning to ICG Eastern, LLC

	(l) Amendment, dated and effective July 31, 2009

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Exhibit No.	Description	Note
10.13	Coal Lease between NGHD Lands, et. al., lessor, and ICG Eastern, LLC (assigned from Coastal Coal-West Virginia, LLC), lessee, of Birch River Mine, amended by:	(M)

	(a) Lease and Sublease Agreement, dated March 14, 2001

	(b) Memorandum of Lease and Sublease Agreement, dated June 1, 2001

	(c) Assignment of Real Property Agreements, dated September 30, 2004, assigning to ICG Eastern, LLC

10.14	Fee Lease between M-B, LLC, lessor, and ICG Eastern, LLC (assigned from ANR Coal Development Company), lessee, of Birch River Mine, amended by:	(M)

	(a) Lease and Sublease Agreement, dated March 14, 2001

	(b) Memorandum of Lease and Sublease Agreement, dated June 1, 2001

	(c) Assignment of Real Property Agreements, dated September 30, 2004, assigning to ICG Eastern, LLC

10.15	Fee Lease between ACIN (successor-in-interest to CSTL, LLC), lessor, and ICG Hazard, LLC (assigned from Leslie Resources, Inc.), lessee, of County Line and Rowdy Gap Mines, amended by:	(M)

	(a) Amendment, dated and effective December 4, 1998

	(b) Amendment, dated and effective March 17, 1999

	(c) Amendment, dated and effective August 17, 1999

	(d) Amendment, dated October 7, 1999 and effective October 24, 1999

	(e) Amendment, dated April 20, 2000 and effective April 24, 2000

	(f) Partial Surrender Agreement, dated and effective March 19, 2001

	(g) Assignment of Real Property Agreements, dated September 30, 2004, assigning to ICG Hazard, LLC

	(h) Partial Surrender Agreement, dated and effective December 1, 2005

	(i) Amendment, dated and effective November 13, 2006

10.16	Fee Lease between Kentucky River Properties, LLC, lessor, and ICG Hazard, LLC (assigned from Shamrock Coal Company), lessee, of Rowdy Gap and Thunder Ridge Mines, amended by:	(M)

	(a) Agreement of Assignment, dated July 8, 1992, assigning to Ray Coal Company, Inc.

	(b) Assignment and Assumption Agreement, dated June 30, 1994, assigning to Ikerd-Bandy, Co.

	(c) Assignment of Real Property Agreements, dated September 30, 2004, assigning to ICG Hazard, LLC

Table of Contents

Exhibit No.	Description	Note
10.17	Lease between Allegany Coal and Land Company, lessor, and Patriot Mining Company, Inc., lessee, of Allegany County, Maryland Mine, including:	(M)

	(a) Amendment 1, dated and effective June 7, 1999

	(b) Amendment 2, dated and effective August 31, 1999

	(c) Amendment 3, dated and effective June 1, 2000

	(d) Amendment 4, dated and effective June 1, 2001

	(e) Default Letter, dated and effective May 6, 2002

	(f) Letter Agreement, dated and effective May 8, 2002

	(g) Amendment 5, dated and effective May 19, 2005

10.18	Lease between The Crab Orchard Coal and Land Company, lessor, and Wolf Run Mining Company (f/k/a Anker West Virginia Mining Company), ICG Beckley, LLC (successor-in-interest to Winding Gulf Coals, Inc.), lessee, of Beckley Mine, including:	(M)

	(a) Modification and Amendment, dated and effective December 28, 1970

	(b) Second Modification and Amendment, dated and effective August 22, 1974

	(c) Agreement and Partial Surrender and Release, dated and effective October 13, 1980

	(d) Amendment, dated and effective January 1, 1983

	(e) Amendment, dated and effective January 1, 1986

	(f) Amendment, dated and effective January 1, 1991

	(g) Agreement of Consent, dated and effective October 27, 1994

	(h) Acceptance by Pine Valley Coal Company, Inc., dated and effective October 31, 1994

	(i) Instrument of Assignment, dated October 28, 1994, effective October 31, 1994

	(j) Amendment, dated and effective October 31, 1994

Table of Contents

Exhibit No.	Description	Note
10.19	Lease between Beaver Coal Corporation, lessor, and Wolf Run Mining Company (f/k/a Anker West Virginia Mining Company), ICG Beckley, LLC (successor-in-interest to New River Company), lessee, of Beckley Mine, including:	(M)

	(a) Amendment, dated and effective August 1, 1975

	(b) Amendment, dated and effective August 1, 1986

	(c) Amendment, dated and effective August 1, 1991

	(d) Acceptance by Pine Valley Coal Company, Inc., dated and effective October 31, 1994

	(e) Agreement of Consent, dated and effective October 28, 1994

	(f) Instrument of Assignment, dated October 28, 1994 and effective October 31, 1994

	(g) Option to Lease, dated April 1, 1995

10.20	Lease between Douglas Coal Company, lessor, and Vindex Energy Corp. (assigned from Patriot Mining Company, Inc.), lessee, of Island and Douglas Mine, including:	(M)

	(a) Option to Lease, dated May 27, 1994

	(b) Guarantee, dated and effective May 1994

	(c) Memorandum of Lease, dated and effective September 21, 1995

	(d) Assignment, dated June 17, 2005, assigning to Vindex Energy Corp.	(G)

	(e) Notification of Extension, dated June 8, 2010

10.21	Contract for Sale and Purchase of Coal dated July 1, 1980, between City of Springfield, Illinois and ICG Illinois, LLC (assigned from Turis Coal Company), amended by:	(D)

	(a) Amendment dated March 4, 1986, effective January 1, 1986

	(b) Second Amendment dated April 22, 1986, effective January 1, 1986

	(c) Modification dated and effective June 8, 1987

	(d) Modification dated and effective November 4, 1988

	(e) Amendment dated and effective January 1, 1989

	(f) Amendment dated March 20, 1992, effective January 1, 1992

	(g) Amendment dated March 21, 1995, effective January 1, 1995

	(h) Amendment dated May 10, 1996, effective May 1, 1996

	(i) Amendment dated August 20, 1998, effective January 1, 1998

	(j) Amendment dated May 30, 2001, effective January 1, 2001

	(k) Letter dated October 8, 2004 assigning to ICG Illinois, LLC

Table of Contents

Exhibit No.	Description	Note
10.22‡	Coal Lease Agreement Between Tygart Resources, Inc. and Pittsburgh Ligionier, Inc., Lessors and Rocking Chair Energy Company, LLC, Lessees, including (a) Assignment and Consent Agreement dated March 28, 2007 by and between Tygart Resources, Inc. and Pittsburgh Ligionier, Inc., Rocking Chair Energy Company, LLC, and Wolf Run Mining Company (b) Amendment No. 1 to Lease Agreement made effective as of April 1, 2007 by and between Tygart Resources, Inc. and Pittsburgh Ligionier, Inc., Lessors and Rocking Chair Energy Company, LLC and Wolf Run Mining Company (c) Corporate Guaranty of International Coal Group, Inc. dated as of April 1, 2007	(O)

10.23‡	Lease and Sublease Agreement between Penn Virginia Operating Co., LLC, lessor, and ICG Knott County, LLC (assigned from Greymont Mining Corp.), lessee, as amended by First Amendment to Lease and Sublease Agreement, dated November 11, 2005 and letter agreement dated February 12, 2007	(P)

10.24‡	Coal Facility Lease and Operating Agreement, dated July 7, 2005, between Loadout LLC, lessor, and ICG Knott County, LLC (assigned from Elk Ridge, Inc.), lessee, as amended by First Amendment to Coal Facility Lease and Operating Agreement, dated November 11, 2005	(P)

10.25‡	Amended and Restated Coal Lease dated as of May 27, 2008 by and between Dulcet Acquisition LLC, as lessor, and Powdul Acquisition LLC, as lessee, amended by:	(Q)

	(a) Amendment 1, dated and effective April 29, 2009

	(b) Amendment 2, dated and effective November 6, 2009

10.26	Third Amended and Restated Credit Agreement, dated as of February 22, 2010, by and among ICG, LLC, as borrower, International Coal Group, Inc. and certain of its subsidiaries, as guarantors, General Electric Capital Corporation, as administrative agent and as a collateral agent, UBS AG, Stamford Branch, as a collateral agent, and certain other revolving lenders.	(R)

10.27	Amendment No. 1 to the Third Amended and Restated Credit Agreement, dated as of May 6, 2010, among ICG, LLC, as borrower, International Coal Group, Inc. and certain of its subsidiaries, as guarantors, General Electric Capital Corporation, administrative and as a collateral agent, UBS AG, Stamford Branch, as a collateral agent, and certain other revolving lenders.	(L)

10.28	Amended and Restated Security Agreement, dated as of February 22, 2010, among ICG, LLC, the guarantors party thereto, General Electric Capital Corporation, collateral agent and UBS AG, Stamford Branch, as collateral agent.	(R)

11.1	Statement regarding Computation of Earnings Per Share	(T)

12.1	Statement regarding Computation of Ratio of Earnings to Fixed Charges	(T)

21.1	List of Subsidiaries	(T)

23.1	Consent of Deloitte & Touche, LLP	(T)

24.1	Power of attorney, dated February 10, 2011	(T)

31.1	Certification of the Chief Executive Officer	(T)

31.2	Certification of the Principal Financial Officer	(T)

32.1	Certification Pursuant to § 906 of the Sarbanes-Oxley Act of 2002	(T)

Table of Contents

(A)	Previously filed as an exhibit to Amendment No. 4 to International Coal Group, Inc.’s Registration Statement on Form S-1 (Reg. No. 333-124393), filed on October 24, 2005 and incorporated herein by reference.

(B)	Previously filed as an exhibit to International Coal Group, Inc.’s Current Report on Form 8-K, filed on November 19, 2010, and incorporated herein by reference.

(C)	Previously filed as an exhibit to Amendment No. 3 to International Coal Group, Inc.’s Registration Statement on Form S-1 (Reg. No. 333-124393), filed on September 28, 2005 and incorporated herein by reference.

(D)	Previously filed as an exhibit to Amendment No. 1 to International Coal Group, Inc.’s Registration Statement on Form S-1 (Reg. No. 333-124393), filed on June 15, 2005, and incorporated herein by reference.

(E)	Previously filed as Exhibit 1.2 to Amendment No. 1 to Schedule 13D of Fairfax Financial Holdings Limited, filed on May 29, 2008, and incorporated herein by reference.

(F)	Previously filed as an exhibit to International Coal Group, Inc.’s Current Report on Form 8-K, filed on July 31, 2007, and incorporated herein by reference.

(G)	Previously filed as an exhibit to International Coal Group, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009, filed on January 29, 2010, and incorporated herein by reference.

(H)	Previously filed as an exhibit to International Coal Group, Inc.’s Current Report on Form 8-K, filed on March 16, 2010, and incorporated herein by reference.

(I)	Previously filed as an exhibit to International Coal Group, Inc.’s Current Report on Form 8-K, filed on March 23, 2010, and incorporated herein by reference.

(J)	Previously filed as an exhibit to International Coal Group, Inc.’s Registration Statement on Form S-1 (Reg. No. 333-124393), filed on April 28, 2005, and incorporated herein by reference.

(K)	Previously filed as Annex A to International Coal Group Inc.’s Definitive Proxy Statement on Schedule 14A (File No. 001-32679), filed on April 15, 2009, and incorporated herein by reference.

(L)	Previously filed as an exhibit to International Coal Group Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, filed on May 6, 2010, and incorporated herein by reference.

(M)	Previously filed as an exhibit to Amendment No. 2 to International Coal Group, Inc.’s Registration Statement on Form S-1 (Reg. No. 333-124393), filed on June 30, 2005, and incorporated herein by reference.

(N)	Previously filed as an exhibit to Amendment No. 6 to International Coal Group, Inc.’s Registration Statement on Form S-1 (Reg. No. 333-124393), filed on November 14, 2005 and incorporated herein by reference.

(O)	Previously filed as an exhibit to International Coal Group, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2006, filed on March 1, 2007, and incorporated herein by reference.

(P)	Previously filed as an exhibit to International Coal Group, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2007, filed on February 29, 2008, and incorporated herein by reference.

(Q)	Previously filed as an exhibit to International Coal Group Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, filed on August 8, 2008, and incorporated herein by reference.

(R)	Previously filed as an exhibit to International Coal Group Inc.’s Current Report on Form 8-K/A, filed on March 8, 2010, and incorporated herein by reference.

(S)	Previously filed as an exhibit to International Coal Group Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, filed on May 8, 2007, and incorporated herein by reference.

(T)	Filed herewith.

‡	Confidential treatment requested as to certain portions that have been omitted and filed separately with the Securities and Exchange Commission.