Edgar Filing: International Coal Group, Inc.

Stock Price

November 21, 2005 through December 31, 2005

Form 10-K

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, 2005

¨	TRANSITION REPORT PURSUANT SECTION 13 OR 15(a) 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.)

2000 Ashland Drive

Ashland, Kentucky 41101

(Address of principal executive offices—zip code)

(606) 920-7400

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 ¨ No x

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. Yes x No ¨

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


Large accelerated filer ¨		Accelerated filer ¨		Non-accelerated filer x

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

Aggregate market value of common stock held by non-affiliates of the registrant as of December 31, 2005, the last business day of the registrant’s most recently completed fiscal year, at a closing price of $9.50 per share as reported by the New York Stock Exchange, was $1,032,625,566. Shares of common stock beneficially held by each executive officer and director and their respective spouses have been excluded since such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

Number of shares of common stock outstanding as of March 29, 2006 was 152,321,908.

DOCUMENTS INCORPORATED BY REFERENCE

Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2006 annual meeting of stockholders, which proxy statement will be filed no later than 120 days after close of the registrant’s fiscal year ended December 31, 2005.

INDEX TO ANNUAL REPORT

ON FORM 10-K

Table of Contents


PART I

Item 1.	BUSINESS	1

Item 1A.	RISK FACTORS	30

Item 1B.	UNRESOLVED STAFF COMMENTS	49

Item 2.	PROPERTIES	49

Item 3.	LEGAL PROCEEDINGS	55

Item 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	55

PART II
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	56

Item 6.	SELECTED FINANCIAL DATA	58

Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS	60

Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	78

Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	78

Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	78

Item 9A.	CONTROLS AND PROCEDURES	78

Item 9B.	OTHER INFORMATION	78

PART III
Item 10.*	DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY	79

Item 11.*	EXECUTIVE COMPENSATION	79

Item 12.*	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	79

Item 13.*	CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	79

Item 14.*	PRINCIPAL ACCOUNTANT FEES AND SERVICE	79

PART IV
Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	80

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 29, 2006.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-K contains forward-looking statements that are not statements of historical fact 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 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;

•

the ongoing integration of Anker and CoalQuest into our business;

•

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

•

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

•

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

•

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

•

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;

•

risks in coal mining;

•

unexpected maintenance and equipment failure;

•

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

•

competition;

•

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;

•

future legislation and changes in regulations or governmental policies or changes in interpretations thereof, including with respect to safety enhancements;

•

the impairment of the value of our goodwill;

•

the ongoing investigation into the Sago mine explosion; and

•

our liquidity, results of operations and financial condition.

You should keep in mind that any forward-looking statement made by us in this Form 10-K speaks only as of the date on which we make it. 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. 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.

iii

PART I

Introduction

This report is both our 2005 annual report to stockholders and our 2005 annual report on Form 10-K required under the federal securities laws.

In this annual report, the term “Horizon” refers to Horizon NR, LLC (the entity holding the operating subsidiaries of Horizon Natural Resources Company) and its consolidated subsidiaries, the term “Anker” refers to Anker Coal Group, Inc. and its consolidated subsidiaries, and the term “CoalQuest” refers to CoalQuest Development, LLC. References to the “Anker and CoalQuest acquisitions” refer to our acquisition, respectively, of each of Anker and CoalQuest, which occurred on November 18, 2005. Unless otherwise noted, all of our actual production and financial information includes the results of Anker and CoalQuest from November 19, 2005 through December 31, 2005. On November 18, 2005, we and our subsidiaries also underwent a corporate reorganization in which we became the parent holding company and ICG, Inc., the prior parent holding company, became our subsidiary. 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, after giving effect to the corporate reorganization and the Anker and CoalQuest acquisitions.

For purposes of all financial disclosures contained in this report, Horizon (together with its predecessor AEI Resources Holding, Inc. and its consolidated subsidiaries) is the predecessor to ICG.

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 do not qualify as a commercially viable coal reserve as prescribed by 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 Appalachian mining complexes, which include ten of our mining complexes, are located in West Virginia, Kentucky 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. Due to the decline in Appalachian coal production in recent years, these markets are currently characterized by strong demand with limited supply response and elevated spot and contract prices.

ICG, Inc. was formed by WL Ross & Co. LLC, or WLR, and other investors in May 2004 to acquire and operate competitive coal mining facilities. As of September 30, 2004, ICG, Inc. acquired certain key assets of Horizon through a bankruptcy auction. These assets are high quality reserves strategically located in Appalachia and the Illinois Basin, are union free, have limited reclamation liabilities and are substantially free of other legacy liabilities. Due to its initial capitalization, ICG, Inc. was able to complete the acquisition without incurring a significant level of indebtedness. Consistent with the WLR investor group’s strategy to consolidate attractive coal assets, we completed the corporate reorganization and acquired Anker and CoalQuest in November 2005, which further diversified our reserves.

As of December 31, 2005, based on an independent evaluation performed as of January 1, 2005 and management’s estimates, we owned or controlled approximately 314 million tons of metallurgical quality coal reserves and approximately 602 million tons of steam coal reserves. Further, we own or control approximately 707 million tons of non-reserve coal deposits.

Steam coal is primarily consumed by large electric utilities and industrial customers as fuel for electricity generation. Demand for low sulfur steam coal has grown significantly since the introduction of certain controls associated with the Clean Air Act and the decline in coal production in the eastern half of the United States. Metallurgical coal is primarily used to produce coke, a key raw material used in the steel making process. Generally, metallurgical coal sells at a premium to steam coal because of its higher quality and its importance and value in the steel making process.

For the year ended December 31, 2005, we sold 14.8 million tons of coal, of which 14.7 million tons were steam coal and 0.1 million tons were metallurgical coal. Our steam coal sales volume in 2005 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, 2005 were Georgia Power Company, Carolina Power & Light Company and Duke Power and we derived approximately 65% of our coal revenues from sales to our five largest customers. Revenues from sales to Georgia Power Company, Duke Power and Carolina Power & Light Company each accounted for more than 10% of coal revenues 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, as of and for the year ended December 31, 2005, and for the period May 13, 2004 to December 31, 2004 is included in Note 20 to our consolidated financial statements, and for the period January 1, 2004 to September 30, 2004 and the twelve months ended December 31, 2003, is included in Note 11 to the combined financial statements of Horizon, each included at the end of this report.

Recent Developments

On January 2, 2006, an explosion occurred at our Sago mine in Tallmansville, West Virginia. The Sago mine is operated by our subsidiary Wolf Run Mining Company (f/k/a Anker West Virginia Mining Company, Inc.). The explosion tragically resulted in twelve fatalities and the critical injury of another miner. We are fully cooperating with the state and federal investigations into the cause of the explosion. On March 14, 2006, we announced our initial findings from the investigation, including that the explosion was ignited by lightning and fueled by methane that naturally accumulated in an abandoned area of the mine that had been recently sealed. The precise route by which the lightning electrical charge traveled from a surface strike location to the sealed area remains under investigation, and the seals, constructed of Omega block under a plan approved by federal authorities and designed to withstand forces of 20 pounds per square inch, were essentially obliterated by the explosion. We will continue with data review and testing to verify the initial findings. Final results of the investigations will not be known until federal and state safety officials conclude their investigations and issue their reports. We resumed operations at the Sago mine on March 15, 2005, a week after federal and state safety officials provided approval.

On March 21, 2006, we entered into an amendment to our credit facility to provide us with an additional $100.0 million of commitments under our revolving credit facility. With these additional commitments, the maximum amount available under our revolving credit facility is $210.0 million, of which up to a maximum of $75.0 million may be utilized for letters of credit. See “Management’s Discussion and Analysis of Financial Conditions and Results of Operations—Credit Facility and Long-Term Debt Obligations.”

History

The Horizon Acquisition

On February 28, 2002, Horizon (at that time operating as AEI Resources Holdings, Inc.) filed a voluntary petition for Chapter 11 and its plan of reorganization became effective on May 8, 2002. However, Horizon’s profit margins and cash flows were negatively impacted in fiscal year 2002 by, among other things, the falling price of coal and continued increases in certain operating expenses. Due to capital and permit constraints, Horizon had to mine in areas which produced coal at greatly reduced profit margins thus severely reducing cash flow.

As a result of its continuing financial and operational difficulties, Horizon filed a second voluntary petition for relief under Chapter 11 on November 13, 2002. Horizon obtained a debtor-in-possession financing facility of up to $350.0 million and was effective in rationalizing its operations, selling non-core assets, paying down outstanding borrowings and generating substantial operating profit. With stabilized operations and a significantly improved coal market, Horizon filed a joint plan of reorganization and a joint plan of liquidation under Chapter 11.

ICG, Inc. was formed by WLR and other investors in May 2004. The Horizon assets were sold through a bankruptcy auction on August 17, 2004. Presented as a combined $290.0 million cash bid with A.T. Massey, ICG, Inc. agreed to pay $285.0 million in cash plus the assumption of up to $5.0 million of liabilities to be paid to contract counterparties to cure the pre-sale defaults under the leases and contracts assumed and assigned to ICG, Inc. to acquire the assets. ICG, Inc. also contributed a credit bid of second lien Horizon bonds, and A.T. Massey agreed to pay $5.0 million in cash to acquire a separate group of assets associated with two Horizon subsidiaries. The credit bid included the cancellation of $482.0 million of certain Horizon bonds in return for which those Horizon bondholders received the right to participate in a rights offering to purchase ICG common stock. Shares issued in connection with the rights offering are included in our outstanding stock. The former bondholders of Horizon that purchased shares of ICG, Inc. common stock in the rights offering were creditors of Horizon and received the shares in reliance on Section 1145 of the U.S. Bankruptcy Code, which in general provides for the limited exemption from the registration requirements of the Securities Act for securities issued in exchange for a claim against the debtor in bankruptcy.

In addition, Lexington Coal Company, LLC, a newly formed entity, was organized by the founding ICG, Inc. stockholders to assume certain reclamation liabilities and assets not otherwise being purchased by A.T. Massey or ICG, Inc. In order to provide support to Lexington Coal Company in consideration for assuming these liabilities, we agreed to provide a $10.0 million letter of credit to support reclamation obligations and to pay a 0.75% additional payment on the gross sales receipts for coal mined and sold from the assets we acquired from Horizon until the completion by Lexington Coal Company of all reclamation liabilities acquired from Horizon. The $10.0 million letter of credit was released in March 2006. Other than limited commonality of ownership of ICG and Lexington Coal Company, there is no relationship between the entities.

The bankruptcy court confirmed the sale on September 16, 2004 as part of the completion of the Horizon bankruptcy proceedings. At closing, we increased the purchase price by $6.25 million, primarily to satisfy increased administrative expenses, and the sale was completed as of September 30, 2004.

The acquisition was financed through equity investments and borrowings under our senior secured credit facility, which we entered into at the closing of the Horizon acquisition.

The Anker and CoalQuest Acquisitions

On March 31, 2005, ICG, Inc. entered into a business combination agreement with us, Anker and ICG Merger Sub, Inc., our indirect wholly owned subsidiary, and Anker Merger Sub, Inc., our indirect wholly owned subsidiary. Under the terms of the business combination agreement, on November 18, 2005, ICG Merger Sub merged with and into ICG, Inc. and Anker Merger Sub merged with and into Anker, with each of ICG, Inc. and

Anker surviving their respective mergers as our wholly owned subsidiaries and we became the new parent holding company. The stockholders of Anker, collectively, received 14,840,909 shares of our common stock.

On March 31, 2005, ICG, Inc. also entered into a business combination agreement with us, CoalQuest and CoalQuest Merger Sub LLC, our indirect wholly owned subsidiary, and the members of CoalQuest. Under the terms of the business combination agreement, on November 18, 2005, the members of CoalQuest contributed their interests in CoalQuest to us in exchange for shares of our common stock. As a result of this contribution, CoalQuest became our wholly owned subsidiary. The members of CoalQuest, collectively, received 9,250,000 shares of our common stock.

Our Reorganization and Public Offering

On November 18, 2005, International Coal Group, Inc. also completed a corporate reorganization. Prior to this reorganization, the top-tier parent holding company was ICG, Inc. Upon completion of this reorganization, International Coal Group, Inc. became the new top-tier parent holding company. In the corporate reorganization, the stockholders of ICG, Inc. received one share of International Coal Group, Inc. common stock for each share of ICG, Inc. common stock. On November 21, 2005, International Coal Group, Inc. common stock commenced trading on the New York Stock Exchange.

On December 12, 2005, we completed a public offering of 21 million shares of common stock. Net proceeds from the public offering were approximately $210.5 million. We used the proceeds to repay $188.7 million of our term loan debt and $21.2 million of borrowings under our revolving credit facility.

The Coal Industry

A major contributor to the world energy supply, coal represents over 23% 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 2004, coal-fired plants generated 50% 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 steel companies 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.”

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 by far the cheapest source of power fuel per million Btu, averaging less than one-third 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 techniques: room-and-pillar mining or longwall mining. In 2005, approximately 31% of our produced and processed coal volume came from underground mining operations generally using the room-and-pillar method with continuous mining equipment.

Room-and-Pillar Mining

In room-and-pillar mining, rooms are cut into the coalbed 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 generally 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 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. Productivity for continuous room-and-pillar mining in the United States averages 3.3 tons per employee per hour, according to the EIA.

Longwall Mining

The other underground mining method commonly used in the United States is the longwall mining method. We do not currently have any longwall mining operations, but we expect to use this mining method in the development of two of our undeveloped mining properties in 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 2005, approximately 69% 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, loading out the coal, replacing the overburden and topsoil after the coal has been excavated and reestablishing vegetation and plant life 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. Seam recovery for surface mining is typically between 80% and 90%. Productivity depends on equipment, geological composition and mining ratios and averages 4.2 tons per employee per hour in eastern regions of the United States, according to the EIA.

We use the following four types of surface mining methods.

Truck-and-Shovel/Loader Mining

Truck-and-shovel/loader mining is a surface mining method that uses large shovels or loaders to remove overburden which is used to backfill pits after coal removal. Shovels or loaders load coal into haul trucks for transportation to a preparation plant or unit train loadout facility. Seam recovery using the truck-and-shovel/loader mining method is typically 85% or more.

Dragline Mining

Dragline mining is a surface mining method that uses large capacity draglines to remove overburden to expose the coal seams. Shovels or loaders load coal in haul trucks for transportation to a preparation plant or unit train loadout facility. Seam recovery using the dragline method is typically 85% or more and productivity levels are similar to those for truck-and-shovel/loader mining.

Highwall Mining

Highwall mining is a surface mining method generally utilized in conjunction with truck-and-shovel/ loader surface mining. At the highwall exposed by the truck-and-shovel/loader 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.

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 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 reducing the cost of meeting the quality requirements of specific customer contracts, thereby optimizing contract revenue.

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 seam to 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.

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. By 2000, 90,000 megawatts of electric generation capacity utilized scrubbing technologies. According to the EIA, by 2025, an additional 27,000 megawatts of electric generation capacity will have installed scrubbers. 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, 2005, we operated a total of 12 surface and 11 underground coal mines located in Kentucky, Maryland, West Virginia and Illinois. Approximately 69% of our production has come from surface mines, and the remaining production has come from our underground mines. These mining facilities include seven preparations 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 mountain top removal, dragline, highwall 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 operation is scheduled to be replaced on an on-going basis with new, more efficient units during the next five years. Each year we endeavor to replace the oldest units, thereby maintaining productivity while minimizing capital expenditures. The following table provides summary information regarding our principal active operations as of December 31, 2005.


				Number and type of mines
Mining Complexes⁽¹⁾	Location	Preparation plant(s)		Under- ground	Surface	Total	Mining method⁽²⁾	Transportation	Tons produced in 2005
									(in thousands)
ICG Eastern, LLC	Cowen, WV	1		0	1	1	MTR-DL-TSL	Rail	2,766.4
ICG Hazard, LLC	Hazard, KY	0		0	5	5	R&P, HW, MTR, TSL	Rail, Truck	3,432.2
Flint Ridge	Hazard, KY	1		1	1	2	CTR, TSL, R&P, HW	Rail, Truck	906.2
ICG Knott County, LLC	Kite, KY	1		4	0	4	R&P	Rail	1,277.4
ICG East Kentucky, LLC	Pike Co., KY	0		0	1	1	MTR-TSL	Rail	1,441.2
ICG Illinois, LLC	Williamsville, IL	1		1	0	1	R&P	Truck	2,325.4
Vindex Energy Corporation*	Garrett Co., MD	1		1	2	3	CRM, CTR, R&P	Truck, Rail⁽³⁾	649.6
Patriot Mining Company*	Monongalia Co., WV	0		0	2	2	CTR	Barge, Rail, Truck	700.8	⁽⁴⁾
Buckhannon/Spruce Division*	Upshur Co., WV	1		1	0	1	R&P	Rail, Truck	757.5
Philippi Development Division*	Barbour Co., WV	1	⁽⁵⁾	1	0	1	R&P	Rail	122.3
Sycamore Group*	Harrison Co., WV	0		2	0	2	R&P	Truck	496.3	⁽⁶⁾⁽⁷⁾

*	Operated by Anker from January 1, 2005 to November 18, 2005 and by us from November 19, 2005 to December 31, 2005. Tons produced reflects all tons in 2005 for both operators.

(1)

Does not include two inactive mining complexes: ICG Beckley and Juliana.

(2)

CRM = Cross Ridge Mining; CTR = Contour Mining; R&P = Room-and-pillar; LW = Longwall; MTR = Mountain Top Removal; DL = Dragline; HW = Highwall; TSL = Truck and Shovel/Loader.

(3)

Utilizing third-party loadout.

(4)

Including waste-fuel.

(5)

Currently utilizing one circuit.

(6)

Mine permitted but undeveloped

(7)

Represents Wolf Run Mining Company’s (f/k/a Anker West Virginia Mining Company, Inc.) 50% share in The Sycamore Group LLC plus the Sycamore No. 2 mine, which began production in April 2005.

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


	2003				2004				2005
Mining complex	Tons Produced		Sales Realizations⁽¹⁾		Tons Produced		Sales Realizations⁽¹⁾		Tons Produced	Sales Realizations⁽¹⁾
ICG Eastern, LLC	2,657,537		$	26.16	2,712,067		$	34.12	2,766,365	$	42.75
ICG Hazard, LLC	4,116,115		$	26.46	3,978,038		$	32.69	3,432,153	$	44.49
Flint Ridge⁽²⁾	—			—	—			—	906,207	$	46.17
ICG Knott County, LLC	1,333,603		$	28.60	1,386,554		$	39.44	1,277,438	$	46.74
ICG East Kentucky, LLC	1,799,740		$	28.99	1,576,345		$	40.36	1,441,236	$	52.15
ICG Illinois, LLC	2,134,096		$	21.93	2,117,567		$	22.44	2,325,370	$	23.23
Vindex Energy Corporation⁽³⁾*	104,855		$	22.63	170,745		$	40.70	649,623	$	45.00
Patriot Mining Company*	425,638	⁽⁴⁾	$	19.28	423,448	⁽⁴⁾	$	20.46	700,762	$	24.26
Sycamore Group*	269,801		$	24.12	259,270		$	24.89	496,266	$	27.48
Buckhannon/Spruce Division*	1,353,896		$	30.98	1,213,851		$	34.18	757,518	$	37.05
Philippi Development Division*	299,167		$	27.37	255,439		$	45.36	122,343	$	51.62

	14,494,448				14,093,324				14,875,281

*	Operated by Anker during 2003, 2004 and through November 18, 2005 and by us from November 19, 2005 to December 31, 2005.

(1)

Excludes freight and handling revenue.

(2)

Flint Ridge began production in 2005.

(3)

Includes Vindex Division of Wolf Run (formerly referred to as the “Mt. Storm Division”).

(4)

Does not include Patriot’s waste fuel.

Northern and Central Appalachia Mining Operations

Below is a map showing the location and access to our coal properties in Northern and Central Appalachia:

LOGO

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

Our mines in Central Appalachia produced 9.8 million tons of coal in 2005 and our mines in Northern Appalachia produced 0.3 million tons of coal in 2005. The coal produced in 2005 from our Northern and Central Appalachian mining operations was, on average, 12,087 Btu/lb, 1.2% sulfur and 13.2% ash by content. Shipments to electric utilities, accounted for approximately 80% of the coal shipped by these mines in 2005, compared to 73% of shipments in 2004. 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 by the Norfolk Southern and CSX rail lines, although production may also be delivered by truck or barge, depending on the customer. ICG Natural Resources, LLC owns one river dock along the Kanawha River from which we could ship coal to our customers. We recently sold another idled river dock along the Kanawha River.

As of December 31, 2005, these mines had 1,547 employees.

ICG Eastern, LLC

ICG Eastern, LLC operates the Birch River surface mine, located 60 miles east of Charleston, near Cowen in Webster County, West Virginia. Birch River started operations in 1990 under Shell Mining Company, was purchased by Zeigler Coal Holding Company, or “Zeigler,” in 1992, and was subsequently acquired by AEI Resources, Inc. from Zeigler in 1998.

Birch River is extracting coal from five distinct coalbeds: (i) Freeport; (ii) Upper Kittanning; (iii) Middle Kittanning; (iv) Upper Clarion; and (v) Lower Clarion. We estimate that Birch River controls 20.9 million tons of coal reserves.

Approximately 73% of the coal reserves are leased, while approximately 27% are owned in fee. Most of the leased reserves are held by four lessors. The leases are retained by annual minimum payments and by tonnage-based royalty payments. All leases can be renewed until all mineable and merchantable coal has been exhausted.

Overburden is removed by a dragline, shovel, 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.

ICG Hazard, LLC

ICG Hazard, LLC is currently operating six surface mines and one underground mine, a unit train loadout (Kentucky River Loading) and other support facilities in eastern Kentucky, near Hazard. ICG Hazard, LLC is comprised of two mining complexes: (i) ICG Hazard and (ii) Flint Ridge. The coal reserves and operations were acquired in late-1997 and 1998 by AEI Resources.

ICG Hazard’s five surface mines include: (i) County Line; (ii) Vicco; (iii) Rowdy Gap; (iv) Tip Top; and (v) Thunder Ridge. The coal from these mines is being extracted from the Hazard 11, Hazard 10, Hazard 9, Hazard 8, Hazard 7 and Hazard 5A seams. Nearly all of the coal is marketed run-of-mine. We estimate that ICG Hazard controls 35.8 million tons of coal reserves, plus 0.2 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.

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

Overburden is removed by front-end loaders, end dumps, bulldozers and blast casting. Coal is transported from the mines to the Kentucky River Loading rail loadout by on-highway trucks. The loadout is served by CSX. Most of the coal is transported by rail, but some coal is direct shipped to the customer by truck from the mine pits.

Flint Ridge is currently operating one underground mine, one surface mine and one preparation plant. We estimate that Flint Ridge controls 32.2 million tons of coal reserves, plus 2.8 million tons classified as non-reserve coal deposits. The Flint Ridge underground operation is a room-and-pillar mine utilizing continuous miners and shuttle cars. The Flint Ridge surface/highwall mine utilizes front-end loaders, end dumps, bulldozers and blast casting for the overburden removal. Once the contour is established and the coal is removed, the highwall miner will then complete the coal extraction from the exposed highwall. Coal from the underground mine and the highwall miner is trucked to the preparation plant, processed, and hauled to the Kentucky River Loading rail loadout by on-highway trucks or directly to the customer. Coal from the contour mining operation is hauled directly to the Kentucky River Loading rail loadout.

Approximately 99.4% of Flint Ridge’s reserves are leased, while 0.6% are owned in fee. The leases are retained by annual minimum payments and by tonnage-based royalty payments. Most leases can be renewed until all mineable and merchantable coal has been exhausted.

An existing preparation plant structure was extensively upgraded in June 2005. Since July 2005, it has been processing coal from ICG Hazard and Flint Ridge mining complexes.

ICG Knott County, LLC

ICG Knott County, LLC operates four underground mines, the Supreme Energy preparation plant and rail loadout and other facilities necessary to support the mining operations in eastern Kentucky, near Kite. ICG Knott County was acquired by AEI Resources from Zeigler in 1998.

ICG Knott County is producing coal from the Hazard 4 and the Elkhorn 3 coalbeds. Three mines are operating in the Hazard 4 coalbed: Calvary, Clean Energy and Elk Hollow. The Classic mine is operating in the Elkhorn 3 coalbed. We estimate these properties contain 19.0 million tons of coal reserves, including the recently acquired Raven reserves. Most of the property has been extensively explored, but additional core drilling will be conducted within specified locations to better define the reserves.

Approximately 26% of ICG Knott County’s reserves are owned in fee, while approximately 74% are leased. The leases are retained by annual minimum payments and by tonnage-based royalty payments. The leases can be renewed until all mineable and merchantable coal has been exhausted.

ICG Knott County’s four underground mines are room-and-pillar operations, utilizing continuous miners and shuttle cars. Nearly all of the run-of-mine coal is processed at the Supreme Energy preparation plant; some of the Hazard 4 run-of-mine coal is blended with the washed coal. ICG Knott County intends to operate a new preparation plant to be constructed during 2006 in conjunction with Loadout, LLC, an affiliate of Penn Virginia Resources Partners, L.P.

Nearly all of ICG Knott County’s coal is transported by rail. The loadout is served by CSX.

ICG East Kentucky, LLC

ICG East Kentucky, LLC is a surface mining operation located in Pike County, Kentucky, near Phelps. ICG East Kentucky currently operates the Blackberry surface mine and the Phelps Loadout. ICG East Kentucky was acquired by AEI Resources in the second quarter of 1999.

Blackberry is an area surface mine that produces coal from three separate coalbeds: (i) Taylor; (ii) Fireclay; and (iii) Lower Fireclay. All of the coal is sold run-of-mine.

We estimate that the Blackberry mine controls 1.2 million tons of coal reserves; no additional exploration is required.

After Blackberry is depleted, ICG East Kentucky intends to begin mining the Mount Sterling property, which contains an additional 5.9 million tons of coal reserves. Mount Sterling is located in Martin and Pike Counties, Kentucky near the Tug Fork River. Although Mount Sterling is expected to be mined by ICG East Kentucky, the property is held by ICG Natural Resources, LLC. The leases are retained by annual minimum payments and by tonnage-based royalty payments. Most leases can be renewed until all mineable and merchantable coal has been exhausted.

Overburden at the Blackberry mine is removed by front end loaders, end dumps, bull dozers and blast casting. Coal from the pits is transported by truck to the Phelps Loadout.

Vindex Energy Corporation

Vindex Energy Corporation operates two surface mines, the Island mine and the Douglas mine and one underground mine, the Stony River mine, all located in the Potomac Basin in Garrett County, Maryland. The Stony River mine was idled in the first quarter of 2006 pending the results of drill exploration. In the first quarter of 2006, we commenced operations at a new surface mine, the Carlos Mine, also located in the Potomac Basin in Garrett County, Maryland. The reserves at Vindex are leased primarily from one major landowner. The lease expires in 2010 and is renewable on a year-by-year basis with a minimum annual holding cost. Vindex Energy is a cross-ridge mining operation extracting coal from the Upper Freeport, Bakerstown, Middle Kittanning and Upper Kittanning seams. All surface mines operated by Vindex Energy are truck-and-shovel/loader mining operations utilizing dozers, hydraulic excavators, loaders and trucks. Our underground mine uses the room-and-pillar mining method. Operations are conducted with relatively new equipment and exploration and development is conducted on a continual basis ahead of mining.

Vindex has been operating its mines at full production since the first quarter 2005. Approximately 20% of the raw coal production is screened at the Island Mine for sales directly to the customers. The remainder of the coal 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 using a third-party rail loading facility.

Patriot Mining Company

Patriot Mining Company consists of two active surface mines near Morgantown, West Virginia: Crown No. 2 and New Hill East located in Monongalia County, West Virginia. The majority of the coal and surface is leased under renewable contracts with small annual minimum holding costs. Patriot’s mines are extracting coal from the Waynesburg seam using contour mining methods with dozers, loaders and trucks. As mining progresses, reserves are being acquired and permitted for future operations. The coal is shipped to the customer by either rail, truck or barge using our barge loading facility.

Buckhannon/Spruce Division

The Buckhannon/Spruce Division currently consists of one active underground mine: The Sago mine located in Upshur County, West Virginia, near the town of Buckhannon. The Sago mine is extracting coal from the Middle Kittanning seam. Nearly all of the reserves in the Buckhannon/Spruce Division are owned by us. The Sago mine, which was originally opened in 1999 as a contract mine, closed in 2002, and then reopened as a captive operation in the first quarter of 2004. The Sago mine neared full production in the fourth quarter of 2005. All of the coal extracted from the Sago mine is processed through the nearby Sawmill Run preparation plant where coal is then primarily shipped by CSX rail with origination by the A&O railroad, a short-line operator, although some coal is trucked to local industrial customers. On January 2, 2006, an explosion occurred at the Sago mine resulting in the death of twelve miners and the critical injury of a thirteenth miner. As a result of the explosion, the Sago mine ceased active production during state and federal investigations into the cause of the explosion. The Sago mine resumed coal production on March 15, 2006.

The Imperial mine, scheduled for production in the second quarter of 2006, is a replacement for the Spruce No. 1 Mine. The reserves at Buckhannon/Spruce Division have characteristics that make it marketable to both steam and metallurgical coal customers.

Sycamore Group

Sycamore Group consists of The Sycamore Group LLC and the Harrison Division. The Sycamore Group LLC is a joint venture between ICG and Emily Gibson Coal Company. The joint venture, through an independent contract miner, operates one underground mine, the Sycamore No. 1 Mine (a/k/a the Fairfax No. 3 Mine), in Harrison County, West Virginia, approximately ten miles west of Clarksburg, where coal is extracted from the Pittsburgh seam by room-and-pillar mining method with continuous miners and shuttle cars for coal extraction.

The majority of the coal is leased with an annual minimum holding cost. It is anticipated that this reserve will be depleted and the mine closed during the first quarter of 2007. Operations are conducted utilizing the room-and-pillar mining method. Newly rebuilt mining equipment was recently installed to facilitate the complete extraction of the remaining reserves. All of The Sycamore Group LLC production is sold on a raw basis and shipped to Allegheny Power Service Corporation’s Harrison Power Station by truck.

The Harrison Division consists of the Sycamore No. 2 Mine, which is located in Harrison County, West Virginia, approximately ten miles west of Clarksburg. The Sycamore No. 2 Mine began producing coal from the Pittsburgh seam by room-and-pillar mining method with continuous miners and shuttle cars in the second quarter of 2005. The reserve is primarily leased from one major landowner with an annual minimum holding cost and an automatic renewal based on an annual minimum production of 250,000 tons.

The coal produced from the Sycamore No. 2 Mine will be sold on a raw basis and shipped to Allegheny Power Service Corporation’s Harrison Power Station by truck under a new life of mine, total production coal supply agreement.

Philippi Development Division

The Philippi Development Division operates the Sentinel mine, in Barbour County, West Virginia near the town of Philippi. The mine was acquired by Anker in 1990 and has been operating ever since. Historically, coal was extracted from the Lower Kittanning seam; however, mining is currently conducted in the Upper Kittanning seam by room-and-pillar mining method with a new low-seam continuous miner which was installed in the fourth quarter of 2004. The current operations are expected to be supplemented with a second continuous miner in the first quarter of 2007.

Coal is fed directly from the mine to our preparation plant and loadout facility served by the CSX railroad. The product can be shipped to steam or metallurgical markets.

New Appalachian Mine Developments

Hillman Property

The Hillman property, located in Northern Appalachia, includes approximately 194 million tons of deep coal reserves of both steam and metallurgical quality coal in the Lower Kittanning seam covering approximately 65,000-acres located predominantly in Taylor County, West Virginia, near Grafton. The reserve extends into parts of Barbour, Marion, and Harrison Counties as well. ICG owns the Hillman 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, we also own significant non-reserve coal deposits in the Kittanning, Freeport, Clarion and Mercer seams on the Hillman property.

The Hillman reserves are expected to be permitted for the development of two longwall mining operations. Production from the first complex is projected to begin in 2008.

Upshur Property

The Upshur Property, located in Northern Appalachia, contains approximately 93 million tons of non-reserve coal deposits owned or controlled by us in the Middle and Lower Kittanning seams. The non-reserve coal deposits are surface mineable at a ratio of slightly greater than 2 to 1. The low product heat content limits the distance over which the fuel can be transported and sold; however, the low mining cost makes Upshur an attractive location for an on-site power plant. Some preliminary research, including air quality monitoring, has been completed in association with the future construction of a circulating fluidized bed power plant at Upshur. We are working to identify a partner to establish a power plant at the site.

Big Creek Property

Our 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 27.5 million tons in the Jawbone, Greasy Creek and War Creek seams. The Big Creek reserve is all leased from Southern Regional Industrial Realty. Production from the permitted War Creek Mine is expected to begin in 2008 utilizing the room-and-pillar mining method with continuous haulage. The coalbed methane at Big Creek is currently leased to and being produced by Pocahontas Gas Partnership with an overriding royalty paid to us.

Beckley Property

The Beckley reserve (formerly referred to as the Bay Hill reserve), located in Central Appalachia, is a 29 million-ton deep reserve of high quality low-vol metallurgical coal in the Pocahontas No. 3 seam in Raleigh County west of Beckley, West Virginia. The southwest portion of the reserve underlies part of the recently closed BayBeck Mine in the Beckley seam. Most of the 16,800 acre Beckley reserve is leased from three land companies: Western Pocahontas Properties, Crab Orchard Coal Company and Beaver Coal Company. We have permitted a portion of the Beckley reserve for deep mine development and have begun development on shaft and slope facilities. We expect that site preparation for the mine portals will commence in the first quarter of 2006. We plan to market the coal produced from the Beckley reserve for export and to domestic steel producers.

Juliana Complex

Mining on the Juliana property, located in Central Appalachia, in Webster County, West Virginia, began in 1979 and was stopped in December 1999. Contour and mountain top removal stripping methods were utilized to produce coal from the Kittanning and Upper Freeport seams. In addition, a substantial amount of deep-mined coal was produced from the Middle Kittanning seam. A 500 TPH preparation facility with 100,000 tons of raw and clean coal storage and a unit-train loadout was used to process and load coal on the CSX railroad.

Currently at Juliana, there are two Kittanning deep mine permits and one surface mine permit in place. Permitted deep and surface non-reserve coal deposits are 1.2 million tons and 1.9 million tons, respectively. The ratio for the surface reserve is 17.3 to 1 bulk cubic yard per clean ton.

Jennie Creek Property

The Jennie Creek reserve, located in Mingo County, West Virginia, is a 44.9 million ton reserve of surface and deep mineable steam coal. Permitting is now in progress for a surface mine and preparation plant complex that is planned for production in 2007 on this Central Appalachian property. The development of the Jennie Creek reserve is subject to the resolution of certain disputes with lessors arising out of the Horizon bankruptcy proceedings. These disputes are the subject of pending litigation in the bankruptcy court. This property is expected to contain 14.7 million tons of surface mineable, low sulfur coal reserves. The coal will be produced by contouring, highwall mining, and area mining. A deep reserve in the high Btu, mid-sulfur Alma seam constitutes the largest block of coal at 30.2 million tons.

Illinois Basin Mining Operations

Below is a map showing the location and access to our coal operations in the Illinois Basin:

LOGO

ICG Illinois, LLC operates one large underground coal mine, the Viper mine, in central Illinois. Viper commenced mining operations in 1982 as a union free operation for Shell Oil Company. Viper was acquired by Ziegler in 1992 and subsequently acquired by AEI Resources in 1998.

The Viper Mine is mining the Illinois No. 5 Seam, also referred to as the Springfield Seam, with all raw coal production washed at Viper’s preparation plant. We estimate that Viper controls approximately 27.3 million tons of coal reserves, plus an additional 38.5 million tons of non-reserve coal deposits.

Approximately 61% of the coal reserves are leased, while 39% is owned in fee. The leases are retained by annual minimum payments and by tonnage-based royalty payments. The leases can be renewed until all mineable and merchantable coal has been exhausted.

The Viper mine is a room-and-pillar operation, utilizing continuous miners and shuttle cars. Management believes that ICG Illinois is one of the lowest cost and highest productivity mines in the Illinois Basin. All of the raw coal is processed at Viper’s preparation plant. The clean coal is transported to the customers by on-highway trucks. A major rail line is located a short distance from the plant, giving Viper the option of constructing a rail loadout.

ICG Illinois ships by independent trucking companies to utility and industrial customers located in North Central Illinois. Shipments to electric utilities account for approximately 70% of coal sales.

The underground equipment, infrastructure and preparation plant are well maintained. The majority of underground equipment will be replaced or rebuilt over the next five years.

Other Operations

Coal sales

In addition to the coal we mine, from time to time we also opportunistically secure coal purchase agreements with other coal producers to take advantage of differences in market prices.

ICG ADDCAR Systems, LLC

In our highwall mining business, we have six systems available for operations or lease using our patented ADDCAR highwall mining system and intend to build additional ADDCAR systems as required. ADDCAR^(TM) is the registered trademark of ICG. The ADDCAR highwall mining system is an innovative and efficient mining system. The system is often deployed at reserves that cannot be economically mined by other methods.

In a typical ADDCAR highwall mining system, there is 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 located at the rear of the launch vehicle. Our system utilizes a navigational package to provide horizontal guidance, which helps to control rib width and thus roof stability. Also, the system provides vertical guidance for control out of seam dilutions. The ADDCAR highwall mining system is also equipped with high-quality video monitors to provide the operator with visual displays of the mining process from inside each 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 depths 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 tractive effort provided by the crawler drive of the continuous miner the ADDCAR highwall mining system bolsters the cutting capability of the machine through an additional pumping force 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.

We currently have the exclusive North American distribution rights for the ADDCAR highwall mining system.

Coalbed methane

CoalQuest has entered into a joint operating agreement pursuant to which it will seek to produce coalbed methane, which is pipeline quality gas that resides in coal seams, from its properties in Barbour, Harrison and Taylor counties in West Virginia. Drilling at the first production well site for coalbed methane, in Barbour County, began in November 2005 and completion is expected by April 2006. We believe that initial marketable production of coalbed methane should occur in the second quarter of 2006. 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 anticipate recovering 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 will be 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.

Customers and Coal Contracts

Customers

Our primary customers are investment grade electric utility companies primarily in the eastern half of the United States. The majority of our customers purchase coal for terms of one year or longer, but we also supply coal on a spot basis for some of our customers. Our three largest customers for the year ended December 31, 2005 were Georgia Power Company, Duke Power and Carolina Power & Light Company and we derived approximately 65% of our coal revenues from sales to our five largest customers. Revenues from sales to Georgia Power Company, Duke Power and Carolina Power & Light Company each accounted for more than 10% of coal revenues in 2005.

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 provides us with greater predictability of sales volume and sales price. For the year ended December 31, 2005, approximately 77% of our 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 expire between 2006 and 2010 are expected to provide us a minimum of approximately 7.2 million tons of coal through the remaining lives of the contracts.

As a result of the Horizon bankruptcy process, we were able to renegotiate certain contracts at significantly higher prices that reflected the current pricing environment and not purchase unfavorable contracts. However, we do have certain contracts which are set below current market rates because Anker entered into these contracts before the recent rise in the 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.

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 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 many 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. These price reopener provisions have enabled us to negotiate higher selling prices in several contracts over the last several months.

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. Assuming steady or increasing coal prices over the near-term, we expect to renew many of our expiring sales contracts at significantly higher prices.

Transportation/Logistics

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 non-contract agreements with trucking companies throughout the year.

In 2005, approximately 94% of our coal (both produced and purchased) from our Central Appalachian operations was delivered to our customers by rail on either the Norfolk Southern or CSX rail lines, with the remaining 6% 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 2005, we spent more than $221 million to procure goods and services in support of our business activities, excluding capital expenditures. Principal commodities include maintenance and repair parts and services, electricity, 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.

Competition

The coal industry is intensely competitive. Our main competitors are Massey Energy Company and Alpha Natural Resources. As we develop additional reserves and expand our operations into Central and Northern West Virginia, we will face additional competition from Northern Appalachia coal producers, including Consol Energy and Foundation Coal Holdings. 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 will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry, which has accounted for approximately 92% of domestic coal consumption in recent years. These coal consumption patterns are influenced by factors beyond our control, including the demand for electricity which is significantly dependent upon economic activity and summer and winter temperatures in the United States, government regulation, technological developments and the location, availability, quality and price of competing sources of coal, alternative fuels such as natural gas, oil and nuclear and alternative energy sources such as hydroelectric power.

Employees

As of December 31, 2005, we had 2,023 employees of which 22% were salaried and 78% were hourly. We believe our relationship with our employees is good. 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 typically 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. These bonding companies, in turn, require that we backstop the surety bonds with cash and/or letters of credit. 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 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.

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. Applications for permits are subject to public comment and may be subject to litigation from environmental groups or other third parties seeking to deny issuance of a permit, which may also delay commencement or continuation of mining operations. 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 order to obtain mining permits and approvals from state regulatory authorities, mine operators must submit a reclamation plan for 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 several months before we plan to begin mining a new area. In our experience, mining permit approvals generally require 12 to 18 months after initial submission.

Surface Mining Control and Reclamation Act

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

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. An example is the proposed amendment to the Stream Buffer Rule issued by the OSM on January 7, 2004. This proposal seeks to further minimize the adverse environmental effects from construction of excess spoil fills and to clarify when excess spoil fills may be constructed within 100 feet of a perennial or intermittent stream. On June 16, 2005, the OSM asked for public comment on the preparation of an environmental impact statement with respect to this proposal, the period for public comment closed on September 1, 2005. A final rule will follow at some point in the future. Another example would be the early March 2006 National Academy of Sciences (NAS) study proposing that OSM develop new regulations to govern the use of coal combustion by-products, such as fly ash, when they are used in reclamation, particularly at surface mine sites. Such by-products are used to help minimize or prevent acid mine drainage developing from other rock and soil materials at the minesite. The NAS noted the many positive uses of such coal combustion by-products, in reclamation, but nevertheless recommended federal regulation to better ensure uniformity of requirements. Currently, utilization of such material is regulated by state authorities only.

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 it 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.

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 OSM’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 may take six months to two years 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.

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. This program is currently set to expire June 30, 2006, and Congress is considering various reauthorization proposals.

SMCRA stipulates compliance with many other major environmental statues, including: the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act, or RCRA, and the Comprehensive Environmental Response, Compensation and Liability Act, or either CERCLA or 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, federal and state workers’ compensation 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.

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 affect. 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. 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:

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. At this time, we

believe that implementation of Phase II has resulted in an upward pressure on the price of lower sulfur coals, as coal-fired power plants continue to comply with the more stringent restrictions of Title IV.

Fine Particulate Matter and Ozone

The Clean Air Act requires the EPA to set standards, referred to as National Ambient Air Quality Standards, or NAAQS, for certain pollutants. Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels. In 1997, the EPA revised the NAAQS for particulate matter and ozone; although previously subject to legal challenge, these revisions were subsequently upheld but implementation was delayed for several years.

For ozone, these changes include replacement of the existing one-hour average standard with a more stringent eight-hour average standard. On April 15, 2004, the EPA announced that counties in 32 states fail to meet the new eight-hour standard for ozone. The EPA is also considering whether to revise the ozone standard. States which fail to meet the new standard will have until June 2007 to develop plans for pollution control measures that allow them to come into compliance with the standards.

For particulates, the changes include retaining the existing standard for particulate matter with an aerodynamic diameter less than or equal to 10 microns, or PM10, and adding a new standard for fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns, or PM2.5. On December 17, 2004, the EPA announced that regions in 20 states and the District of Columbia did not achieve the fine particulate matter standard. 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. Under the Clean Air Act, individual states have up to twelve years from the date of designation to secure emissions reductions from sources contributing to the problem. In addition, on April 25, 2005, the EPA issued a finding that states have failed to submit State Implementation Plans that satisfy the requirements of the Clean Air Act with respect to the interstate transport of pollutants relative to the achievement of the 8-hour ozone and the PM2.5 standards. Because of this finding, the EPA must promulgate a Federal Implementation Plan for any state which does not submit its own plan. The EPA issued a proposed PM2.5 rule on September 8, 2005, and expects to issue a final rule by September 27, 2006. Meeting the new PM2.5 standard may require reductions of nitrogen oxide and sulfur dioxide emissions. Future regulation and enforcement of these new ozone and PM2.5 standards will affect many power plants, especially coal-fired plants and all plants in “nonattainment” areas.

Significant additional emissions control expenditures will be required at coal-fired power plants to meet the current NAAQS for ozone. Nitrogen oxides, which are a by-product of coal combustion, can lead to the creation of ozone. 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.

NOx SIP Call

The NOx SIP Call program was established by the EPA in October of 1998 to reduce the transport of ozone on prevailing winds from the Midwest and South to states in the Northeast, which said they could not meet federal air quality standards because of migrating pollution. Under Phase I of the program, the EPA is requiring 900,000 tons of nitrogen oxides reductions from power plants in 22 states east of the Mississippi River and the District of Columbia beginning in May 2004. Phase II of the rule requires a further reduction of about 100,000 tons of nitrogen oxides per year by May 1, 2007. Installation of additional control measures, such as selective catalytic reduction devices, required under the final rules will make it more costly to operate coal-fired electricity generating plants, thereby making coal a less attractive fuel.

Clear Skies Initiative

The Bush Administration has proposed new legislation, commonly referred to as the Clear Skies Initiative, that could require dramatic reductions in nitrous oxide, sulfur dioxide, and mercury emissions by power plants

through “cap-and-trade” programs similar to the existing acid rain regulations and current NOx budget programs. Congress has also considered several competing bills. It is not possible to predict with certainty what, if any, impact these potential changes could have on coal-buying decisions in the future.

Interstate Air Quality Rule

On March 10, 2005, the EPA adopted new rules for reducing emissions of sulfur dioxide and nitrogen oxides. This Clean Air Interstate Rule calls for power plants in 29 eastern states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrous oxide. The rule regulates these pollutants under a cap and trade program similar to the system now in effect for acid deposition control and to that proposed by the Clear Skies Initiative. The stringency of the cap may require many coal-fired sources to install additional pollution control equipment, such as wet scrubbers. This increased sulfur emission removal capability caused by the rule could result in decreased demand for low sulfur coal, potentially driving down prices for low sulfur coal. Emissions would be permanently capped and could not increase. The rule seeks to cut sulfur dioxide emissions by 45% in 2010, and by 57% in 2015. The rule is subject to judicial challenge, which makes it difficult to determine its precise impact. Many of the challengers seek to impose more stringent rules. On March 15, 2006, the EPA issued federal implementation plans for this rule.

Clean Air Mercury Rule

On March 15, 2005, the EPA issued the Clean Air Mercury Rule to control mercury emissions from power plants. The rule sets a mandatory, declining cap on the total mercury emissions allowed from coal-fired power plants nationwide. This approach, which allows emissions trading, seeks to reduce mercury emissions by nearly 70 percent from current levels once facilities reach a final mercury cap which takes effect in 2018. The rule is subject to judicial challenge, which makes it difficult to determine its precise impact. Many of the challengers seek to impose more stringent rules. In addition, there have been efforts in Congress to legislatively disapprove the rule. Also subject to judicial challenge is the EPA’s decision, which was announced concurrently with the rule, not to pursue regulation of mercury and other pollutants from coal-fired power plants under the Clean Air Act hazardous air pollutant program. The EPA recently stated that it is reconsidering this decision, but it declined to stay the implementation of the Clean Air Mercury Rule. On October 21, 2005, the EPA announced that it would seek additional public comments for 45 days on the Clean Air Mercury Rule and on portions of the decision not to regulate mercury and other pollutants emitted from power plants under the hazardous air pollutant program.

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.

Carbon Dioxide

In February 2003, a number of states notified the EPA that they planned to sue the agency to force it to set new source performance standards for utility emissions of carbon dioxide and to tighten existing standards for sulfur dioxide and particulate matter for utility emissions. In June 2003, three of these states sued the EPA seeking a court order requiring the EPA to designate carbon dioxide as a criteria pollutant and to issue a new NAAQS for carbon dioxide. If these lawsuits result in the issuance of a court order requiring the EPA to set emission limitations for carbon dioxide and/or lower emission limitations for sulfur dioxide and particulate matter, it could reduce the amount of coal our customers would purchase from us.

Regional Haze

The EPA has initiated a regional haze program designed to protect and to 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. On July 6, 2005, the EPA issued regulations revising its regional haze program.

Clean Water Act

The federal Clean Water Act, or CWA, and corresponding state laws, affect coal mining operations by imposing restrictions of the discharge of certain pollutants into water and on dredging and filling wetlands. The CWA establishes in-stream water quality standards and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System, or 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.

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, 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.

In particular, permits under Section 404 of the Clean Water Act are required for coal companies to conduct dredging or filling activities in jurisdictional waters for the purpose of creating slurry ponds, water impoundments, refuse areas, or valley fills or other mining activities. The Army Corps of Engineers, or ACOE, is empowered to issue “nationwide” permits for specific categories of filling activity that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404. Nationwide Permit 21 authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. On October 23, 2003, several citizens groups sued ACOE in the U.S. District Court for the Southern District of West Virginia seeking to invalidate “nationwide” permits utilized by ACOE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. Although the lower court enjoined the issuance of authorizations under Nationwide Permit 21, that decision was overturned by the Fourth Circuit Court of Appeals, which concluded that the ACOE complied with the Clean Water Act in promulgating Nationwide Permit 21. A similar lawsuit filed in the United States Court for the Eastern District of Kentucky by a number of environmental groups is still pending. This suit also seeks, among other things, an injunction preventing ACOE from authorizing pursuant to Nationwide Permit 21, “further discharges of mining rock, dirt or coal refuse into valley fills or surface impoundments” associated with certain specific mining permits, including permits issued to some of our mines in Kentucky. Granting of such relief would interfere with the further operation of these mines.

Total Maximum Daily Load, or TMDL, regulations established a process by which states designate these stream segments considered to be impaired (i.e., not meeting present water quality standards). Industrial dischargers, including coal mines, will be required to meet new TMDL effluent standards for these stream segments.

Under the Clean Water Act, states must conduct an anti-degradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality beyond prescribed limits. A state’s anti-degradation regulations prohibit the diminution of water quality in these streams. Several environmental groups and individuals recently challenged, and in part successfully, West Virginia’s anti-degradation policy. In general, waters discharged from coal mines to high quality streams will be required to meet or exceed new “high quality” standards. This could cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits, and could aversely affect our coal production.

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. All of 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. Additionally, in the aftermath of several fatal mining accidents in early 2006, including the Sago mine accident, West Virginia has enacted new mine safety legislation, and numerous other states (including most of the states in which we operate), as well as the federal, legislatures are considering similar legislation. The Mine Safety and Health Administration issued an emergency temporary standard addressing emergency mine evacuation, training and underground oxygen supplies on March 9, 2006, and expects to undertake additional rulemaking. 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 2005, we recorded $8.5 million of expense related to this excise tax.

Resource Conservation and Recovery Act

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

In May 2000, the EPA concluded that coal combustion by-products do not warrant regulation as hazardous waste under RCRA and that the hazardous waste exemption applied to these CCBs. However, the EPA has determined that national non-hazardous waste regulations under RCRA Subtitle D are needed for coal combustion by-products 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. As long as the exemption remains in effect, it is not anticipated that regulation of coal combustion by-product, will have any material effect on the amount of coal used by electricity generators. Most state hazardous waste laws also exempt coal combustion by-products, and instead treat them as either a solid waste or a special waste. Any costs associated with handling or disposal of coal combustion by-products would increase our customers’ operating costs and potentially reduce their coal purchases. In addition, contamination caused by the past disposal of ash can lead to material liability.

Due to the hazardous waste exemption for coal combustion by-products such as ash, some of the coal combustion by-products are currently put to beneficial use. For example, at certain mines the Company sometimes uses deposits ash from the combustion of coal as a beneficial use under its reclamation plan. The ash used for this purpose is mixed with lime and serves to help alleviate the potential for acid mine drainage.

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 Superfund, 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.

Climate change

Although the United States has refused to join the 1992 Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, future regulation of greenhouse gas could occur either pursuant to future U.S. treaty obligations or pursuant to statutory or regulatory changes under the Clean Air Act. The Bush Administration has proposed a package of voluntary emission reductions for greenhouse gases reduction targets which provide for certain incentives if targets are met. Some states, such as Massachusetts, have already issued regulations regulating greenhouse gas emissions from large power plants. Increased efforts to control greenhouse gas emissions, including the future joining of the Kyoto Protocol, could result in reduced demand for coal if electric power generators switch to lower carbon sources of fuel. If the United States were to ratify the Kyoto Protocol, our nation would be required to reduce greenhouse gas emissions to 93% of 1990 levels in a series of phased reductions from 2008 to 2012.

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. 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 $6.3 million at December 31, 2005.

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. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, 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.

Additional Information

We file annual, quarterly and current reports, and our amendments to those reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You may access and read our SEC filings without charge through our website, at www.intlcoal.com or the SEC’s website at 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 1–800–SEC–0330 for further information on the public reference room.

You may also request copies of our filings, at no cost, by telephone at (606) 920-7400 or by mail at: International Coal Group, Inc., 2000 Ashland Drive, Ashland, Kentucky 41101, Attention: Secretary.

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.

Base load. The lowest level of power production needs during a season or year.

Bituminous coal. A middle rank coal (between sub-bituminous and anthracite) formed by additional pressure and heat on lignite. The most common type of coal with moisture content less than 20% by weight and heating value of 10,500 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.

By-product. 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.

Clean coal burning technologies. A number of innovative, new technologies designed to use coal in a more efficient and cost-effective manner while enhancing environmental protection. Several promising technologies include fluidized-bed combustion, integrated gasification combined cycle, limestone injection multi-stage burner, enhanced flue gas desulfurization (or scrubbing), coal liquefaction, and coal gasification.

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. An underground coal mine.

Dragline. A large excavating machine used in the surface mining process to remove overburden (see “Overburden”). The dragline has a large bucket suspended from the end of a huge boom, which may be 275 feet long or larger. The bucket is suspended by cables and capable of scooping up vast amounts of overburden as it is pulled across the excavation area. The dragline, which can “walk” on huge pontoon-like “feet,” is one of the largest land-based machines in the world.

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.

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.

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 steel plow, or rotation drum, which is pulled mechanically back and forth across a face of coal that is usually several hundred 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: volatility, 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 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.

Reclamation. The process of restoring land and environmental values to a mining site after the coal or ore 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 Demonstrated Reserves. The recovery factor for underground mines is about 60.0%, and for surface mines about 80.0% to 90.0%. Using these percentages, there are about 275 billion tons of recoverable reserves in the United States.

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 about 6% to 7% of a power plant’s electrical output and thousands of gallons of water to operate.

Steam 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.

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 by-product of coal combustion.

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” tonne 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 shuttle car or conveyor to the surface. Most common in the coal industry, underground mines primarily are located east of the Mississippi River, and account for about 37.4% of total annual U.S. coal production.

ITEM 1A. RISK FACTORS

Risks Relating To Our Business

Because of our limited operating history, historical information regarding our company prior to October 1, 2004 is of little relevance in understanding our business as currently conducted.

We are subject to the risks, uncertainties, expenses and problems encountered by companies in the early stages of operations. We were incorporated in March 2005 as a holding company and ICG, Inc., was incorporated in May 2004 for the sole purpose of acquiring certain assets of Horizon. Until the completion of the Horizon asset acquisition, we had substantially no operations. As a result, historical information regarding our company prior to October 1, 2004, which do not include the historical financial information for Anker and CoalQuest, are of limited relevance in understanding our business as currently conducted. The financial statements for the Horizon predecessor periods have been prepared from the books and records of Horizon as if we had existed as a separate legal entity under common management for all periods presented (that is, on a “carve-out” basis). The financial statements for the Horizon predecessor periods include allocations of certain expenses, taxation charges, interest and cash balances relating to the predecessor based on management’s estimates. In light of these allocations and estimates, the Horizon predecessor financial information is not necessarily indicative of our consolidated financial position, results of operations and cash flows if we had operated during the Horizon predecessor period presented. See “Selected Financial Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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 charge 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. Declines in the prices we receive for our coal could adversely affect our operating results and our ability to generate the cash flows we require to improve our productivity and invest in our operations. The prices we receive for coal depend upon factors beyond our control, including:

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the supply of and demand for domestic and foreign coal;

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the demand for electricity;

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

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

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domestic and foreign governmental regulations and taxes;

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air emission standards for coal-fired power plants;

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regulatory, administrative and judicial decisions;

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

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the effect of worldwide energy conservation measures.

Our coal mining operations are subject to operating risks that could result in decreased coal production thereby reducing 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:

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the unavailability of qualified labor;

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

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

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failure of reserve estimates to prove correct;

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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;

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mining and processing equipment failures and unexpected maintenance problems;

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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;

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increased or unexpected reclamation costs;

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interruptions due to transportation delays;

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

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unexpected mine safety accidents, including fires and explosions from methane.

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.

Steam coal accounted for nearly all of our coal sales volume in 2005 and the majority of our sales of steam coal in 2005 were to electric power generators. Domestic electric power generation accounted for approximately 92% of all U.S. coal consumption in 2005, according to the EIA. The amount of coal consumed for U.S. electric power generation is affected primarily by the overall demand for electricity, the location, availability, quality and price of competing fuels for power such as natural gas, nuclear, fuel oil and alternative energy sources such as hydroelectric power, technological developments, and environmental and other governmental regulations.

Although we expect that many new power plants will be built to produce electricity during peak periods of demand, we also expect that many of these new power plants will be fired by natural gas because gas-fired plants are cheaper to construct than coal-fired plants and because natural gas is a cleaner burning fuel. Gas-fired generation from existing and newly constructed gas-fired facilities has the potential to displace coal-fired generation, particularly from older, less efficient coal-powered generators. In addition, the increasingly stringent requirements of the Clean Air Act may result in more electric power generators shifting from coal to natural gas-fired plants. 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.

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

Overall economic activity and the associated demands for power by industrial users can have significant effects on overall electricity demand. Robust economic activity can cause much heavier demands for power, particularly if such activity results in increased utilization of industrial assets during evening and nighttime periods. The economic slowdown experienced during the last several years significantly slowed the growth of

electrical demand and, in some locations, resulted in contraction of demand. Any downward pressure on coal prices, whether due to increased use of alternative energy sources, changes in weather patterns, decreases in overall demand or otherwise, would likely cause our profitability to decline.

Our profitability may be adversely affected by the status of our long-term coal supply agreements, changes in purchasing patterns in the coal industry and the loss of certain brokered coal contracts set to expire at the end of 2006, which could adversely affect the capability and profitability of our operations.

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, 2005, approximately 77% of our revenues were derived from coal sales that were made under long-term coal supply agreements. As of that date, we had 32 long-term sales agreements with a volume-weighted average term of approximately 4.7 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. In addition, we have brokered coal contracts that will expire at the end of 2006. These contracts were signed during a period of oversupply in the coal industry and contain pricing that, while acceptable to the sellers at that time, is significantly below today’s market levels and, management believes, will not be able to be renegotiated or replaced in today’s market. Assuming today’s market continues, we believe the loss of these contracts will have a significant impact on our earnings after 2006. For the year ended December 31, 2005, these contracts provided $33.4 million in pre-tax net income. For additional information relating to these contracts, see “Business—Customers and coal contracts—Long-term coal supply agreements.”

Furthermore, as electric utilities seek to adjust to requirements of the Clean Air Act, particularly the Acid Rain regulations, the Clean Air Mercury Rule and the Clean Air Interstate Rule, although these two rules are subject to administrative reconsideration and judicial challenge and the Clean Air Mercury Rule has been subject to legislative challenge in Congress, and the possible deregulation of their industry, 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.

Certain provisions in our long-term supply agreements may provide limited protection during adverse economic conditions or may result in economic penalties upon the failure to meet specifications.

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. Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, 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 with respect to long-term supply agreements, we may not achieve the revenue or profit we expect to achieve from these sales commitments. In addition, we may not be able to successfully convert these sales commitments into 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.

Most of our metallurgical coal reserves possess quality characteristics that enable us to mine, process and market them as high quality steam coal. 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 annually updated to reflect production of coal from the 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;

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

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

We depend heavily on a small number of large customers, the loss of any of which would adversely affect our operating results.

Our three largest customers for the year ended December 31, 2005 were Georgia Power, Carolina Power & Light and Duke Power and we derived approximately 65% of our coal revenues from sales to our five largest customers. At December 31, 2005, we had 10 coal supply agreements with these customers that expire at various times from 2006 to 2010. We typically discuss extension of existing agreements or entering into long-term agreements with our customers, however these negotiations may not be successful and these customers may not continue to purchase coal from us pursuant to long-term coal supply agreements. If a number of these customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially.

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. Decreased performance levels over longer periods of time could cause our customers to look elsewhere for their fuel needs, negatively affecting our revenues and profitability.

During 2005, we experienced brief periods of poor rail service, especially during the first half of the year. The service related issues resulted in missed shipments and adversely affected revenue. During the second half of the year and the first quarter of 2006, rail service steadily improved and did not significantly affect our shipment volumes. However, a return to the service related issues experienced in 2004 and early 2005 would affect our future operating results.

The states of West Virginia and Kentucky have recently increased enforcement of weight limits on coal trucks on its public roads. Additionally, West Virginia legislation, which raised coal truck weight limits in West Virginia, includes provisions supporting enhanced enforcement. The legislation went into effect on October 1, 2003 and implementation began on January 1, 2004. It is possible that other states in which our coal is transported by truck could conduct similar campaigns to increase enforcement of weight limits. Such stricter enforcement actions could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect revenues.

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.

On the other hand, 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.

Disruption in supplies of coal produced by third parties could temporarily impair our ability to fill our customers’ orders or increase our costs.

In addition to marketing coal that is produced from our controlled reserves, we purchase and resell coal produced by third parties from their controlled reserves to meet customer specifications. Disruption in our supply of third-party coal 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. Any increase in the prices we pay for third-party coal could increase our costs and therefore lower our earnings.

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 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, including the roof bolts required by the room-and-pillar method of mining described below. Scrap steel prices have risen significantly in recent months, and historically, the prices of scrap steel and petroleum have fluctuated. Recently we have been adversely impacted by margin compressions due to cost increases for various commodities and services influenced by the recent price acceleration of crude oil and natural gas — a trend that was greatly exacerbated by the Gulf hurricanes. Costs of diesel fuel, explosives (ANFO) and coal trucking have all escalated as a direct result of supply chain problems related to the Gulf hurricanes. There may be other acts of nature or 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.

The accident at the Sago mine could negatively impact our business.

On January 2, 2006, an explosion occurred at our Sago mine in West Virginia. The explosion tragically resulted in the deaths of twelve miners and the critical injury of another miner. We are fully cooperating with the state and federal investigations into the cause of the explosion. As a result of the accident, the federal and state investigations and related matters, our business may be negatively impacted by various factors such as the diversion of management’s attention from our day-to-day business, any negative perceptions about our safety

record affecting our ability to attract skilled labor, the impact of any litigation that may be commenced against us, any increased premiums for insurance or the outcome of the investigations into the cause of the explosion. We expect that there will be increased regulation of the mining industry as a whole, which may result in higher operating costs which would adversely affect our operating results.

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 sponsor both in-house and vocational coal mining programs at the local level in order to train additional skilled laborers. In the event the shortage of experienced labor continues or worsens 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 and therefore have a material adverse effect on our earnings.

We have a new management team, and if they are unable to work effectively together, our business may be harmed.

Most of our management team was hired in 2005, and the group has only been working together for a short period of time. Moreover, several other key employees were hired in 2005. Because many of our executive officers and key employees are new and we also expect to add additional key personnel in the near future, there is a risk that our management team will not be able to work together effectively. If our management team is unable to work together, our operations could be disrupted and our business harmed.

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

Our senior management team averages 24 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 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:

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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;

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

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

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

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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.

We may not be able to continue to effectively integrate Anker and CoalQuest into our operations or realize the expected benefits of those acquisitions.

Our future success will depend largely on our ability to continue to consolidate and effectively integrate Anker’s and CoalQuest’s operations into our operations. We may not be able to do so successfully without substantial costs, delays or other difficulties. We may face significant challenges in consolidating functions and integrating procedures, information technology systems, personnel and operating philosophies in a timely and efficient manner. The integration process is complex and time consuming and may pose a number of obstacles, such as:

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the loss of key employees or customers;

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the challenge of maintaining the quality of customer service;

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the need to coordinate geographically diverse operations;

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retooling and reprogramming of equipment and information technology systems; and

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the resulting diversion of management’s attention from our day-to-day business and the need to hire and integrate additional management personnel to manage our expanded operations.

If we are not successful in completing the integration of Anker and CoalQuest into our operations, if the integration takes longer or is more complex or expensive than anticipated, if we cannot operate the Anker and CoalQuest businesses as effectively as we anticipate, whether as a result of deficiency of the acquired business or otherwise, or if the integrated businesses fail to achieve market acceptance, our operating performance, margins, sales and reputation could be materially adversely affected.

Furthermore, we may not be able to realize the expected benefits of these acquisitions. For example, as a result of infrastructure weaknesses and short-term geologic issues at Anker, the transition period for implementation of various operational improvements has taken longer than originally anticipated. This extended transition resulted in, decreased coal production and increased production costs in the third and fourth quarters of 2005 and the first quarter of 2006.

If the value of our goodwill becomes impaired, the write-off of the impaired portion could materially reduce the value of our assets and reduce our net income for the year in which the write-off occurs.

When we acquire a business, we record an asset called “goodwill” if the amount we pay for the business, including liabilities assumed, is in excess of the fair value of the assets of the business we acquire. We recorded $340.7 million of goodwill on a preliminary basis in connection with the acquisitions of Horizon, Anker and CoalQuest. The Financial Accounting Standards Board’s (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets, requires that goodwill be tested at least annually (absent any impairment indicators). The testing includes comparing the fair value of each reporting unit with its carrying value. Fair value is determined using discounted cash flows, market multiples and market capitalization. Impairment adjustments, if any, are required to be recognized as operating expenses. We may have future impairment adjustments to our recorded goodwill. We will perform an impairment test of the assets acquired from Horizon, Anker and CoalQuest as of October 31, 2006. Any finding that the value of our goodwill has been impaired would require us to write-off the impaired portion, which could significantly reduce the value of our assets and reduce our net income for the year in which the write-off occurs.

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, federal and state workers’ compensation costs, coal leases and other obligations. 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:

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

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

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the 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, 2005, we had $59.9 million of letters of credit in place, of which $50.0 million serve as collateral for reclamation surety bonds and $9.9 million secure miscellaneous obligations. Included in the $50.0 million letters of credit securing collateral for reclamation surety bonds is a $10.0 million letter of credit related to Lexington Coal Company, LLC. The $10.0 million letter of credit was released in March 2006. Our credit facility currently provides for a $210.0 million revolving credit facility, of which up to $75.0 million may be used for letters of credit. If we do not maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our mining operations.

Our business requires substantial capital investment and maintenance expenditures, which we may be unable to provide.

Our business strategy will require additional substantial capital investment. We require capital 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 or obtain sufficient additional capital in the future, we could be forced to reduce or delay capital expenditures, sell assets or restructure or refinance our indebtedness.

Our level of indebtedness and other demands on our cash resources could materially adversely affect our ability to execute our business strategy and make us more vulnerable to economic downturns.

As of December 31, 2005, we had cash of approximately $9.2 million and total consolidated indebtedness, including current maturities and capital lease obligations, of approximately $49.6 million. During 2006, our anticipated principal repayments will be $0.1 million on the term loan. Subject to the limits contained in our

credit facilities, we may also incur additional debt in the future. In addition to the principal repayments on our outstanding debt, we have other demands on our cash resources, including, among others, capital expenditures and operating expenses.

Our credit facilities are secured by substantially all our assets. If we default under these facilities, the lenders could choose to declare all outstanding amounts immediately due and payable, and seek foreclosure of the assets we granted to them as collateral. If the amounts outstanding under the credit facilities were accelerated, we may not have sufficient resources to repay all outstanding amounts, and our assets may not be sufficient to repay all of our outstanding debt in full. Foreclosures on any of our material assets could disrupt our operations, and have a material adverse effect on our reputation, production volume, sales and earnings.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our annual debt service obligations to increase significantly.

Our borrowings under our credit facilities are at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on our variable rate indebtedness would increase even if the amount borrowed remained the same, resulting in a decrease in our net income. We have developed a hedging program to actively manage the risks associated with interest rate fluctuations but our program may not effectively eliminate all of the financial exposure associated with interest rate fluctuations. We currently have instruments in place that have the effect of fixing the interest rate on a portion of our outstanding debt for various time periods up to one year.

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 2003, however, the top ten coal producers’ share had increased to approximately 63% 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. 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 deregulation as utilities 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. In addition, 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.

We have contracts to supply coal to energy trading and brokering companies under which those companies sell coal to end users. During 2004 and 2005, the creditworthiness of the energy trading and brokering companies with which we do business declined, increasing the risk that we may not be able to collect payment for all coal sold and delivered to or on behalf of these energy trading and brokering companies.

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.

Our ability and the ability of some of our subsidiaries to engage in some business transactions or to pursue our business strategy may be limited by the terms of our debt.

Our credit facilities contain a number of financial covenants requiring us to meet financial ratios and financial condition tests, as well as covenants restricting our ability to:

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incur additional debt;

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pay dividends on, redeem or repurchase capital stock;

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allow our subsidiaries to issue new stock to any person other than us or any of our other subsidiaries;

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make investments;

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make acquisitions;

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incur or permit to exist liens;

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enter into transactions with affiliates;

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guarantee the debt of other entities, including joint ventures;

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merge or consolidate or otherwise combine with another company; and

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transfer or sell a material amount of our assets outside the ordinary course of business.

These covenants could adversely affect our ability to finance our future operations or capital needs or to execute preferred business strategies.

Our ability to borrow under our credit facilities will depend upon our ability to comply with these covenants and our borrowing base requirements. Our ability to meet these covenants and requirements may be affected by events beyond our control and we may not meet these obligations. Our failure to comply with these covenants and requirements could result in an event of default under our credit facilities that, if not cured or waived, could terminate our ability to borrow further, permit acceleration of the relevant debt and permit foreclosure on any collateral granted as security under our credit facilities. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we were able to obtain new financing, it may not be on commercially reasonable terms, on terms that are acceptable to us, or at all. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected.

We are also subject to limitations on capital expenditures under our revolving credit facility as set forth in the table below.


Period
January 1, 2006 - December 31, 2006	$	180,000,000
January 1, 2007 - December 31, 2007	$	255,000,000
January 1, 2008 - December 31, 2008	$	125,000,000
January 1, 2009 - December 31, 2009	$	75,000,000
January 1, 2010 - Final Maturity Date	$	85,000,000

Because of these limitations, we may not be able to pursue our business strategy to replace our aging equipment fleet, develop additional mines or pursue additional acquisitions without additional financing. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and Note 8 to our audited consolidated financial statements included elsewhere in this Form 10-K.

If our business does not generate sufficient cash for operations, we may not be able to repay our indebtedness.

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 indebtedness.

Our business may not generate sufficient cash flow from operations and future borrowings may not be available to us under our new credit facility or otherwise in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms, on terms acceptable to us or at all.

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:

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limitations on land use;

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employee health and safety;

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mandated benefits for retired coal miners;

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mine permitting and licensing requirements;

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reclamation and restoration of mining properties after mining is completed;

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air quality standards;

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water pollution;

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protection of human health, plantlife and wildlife;

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the discharge of materials into the environment;

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surface subsidence from underground mining; and

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the effects of mining on groundwater quality and availability.

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. In addition, state and federal regulations impose strict standards for particulate matter emissions which may restrict our ability to develop new mines or could require us to modify our existing operations and increase our costs of doing business.

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. New regulations that took effect in 2001 could significantly increase our costs with contesting and paying black lung claims. If new laws or regulations increase the number and award size of claims, it could substantially harm our business.

The costs, liabilities and requirements associated with these and other 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 “Environmental 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.

New government regulations are expected as a result of recent mining accidents which could increase our costs.

As a result of recent mining accidents, including at our Sago mine, we expect that new federal and state health and safety regulations will be adopted that would increase operating costs and affect our mining operations. The State of West Virginia has already adopted legislation which will, among other things, require mine operators to provide additional “self-rescue devices,” or oxygen equipment, inside mines, and require all miners to carry a wireless communication device. We also announced our intention to pursue new technology for worker safety. As a result of any new regulations, we expect to incur increased costs related to worker health and safety. Additionally, we could be subject to fines if we violate the new regulations.

Mining in Northern and Central Appalachia is more complex and involves more regulatory constraints than mining in the other areas, which could affect the mining operations 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, permitting, licensing and other environmental and regulatory requirements are more costly and time-consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and customers’ ability to use coal produced by, our mines in Northern and Central Appalachia.

Judicial rulings that restrict 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.

In our surface mining operations, we use mountaintop removal mining wherever feasible because it allows us to recover more tons of coal per acre and facilitates the permitting of larger projects, which allows mining to continue over a longer period of time than would be the case using other mining methods. To dispose of mining spoil material (including excess rock and overburden) generated by mountaintop removal operations, as well as other mining operations, we obtain permits to construct and operate valley fills and surface impoundments. Some of these permits are “nationwide” permits (as opposed to individual permits) issued by the Army Corps of Engineers, or ACOE, for dredging and filling in streams and wetlands. Several citizens groups sued the ACOE in West Virginia seeking to invalidate authorizations under Nationwide Permit 21. Although the lower court enjoined the issuance of future authorizations under Nationwide Permit 21, that decision was overturned by the Fourth Circuit Court of Appeals, which concluded that the ACOE complied with the Clean Water Act in promulgating Nationwide Permit 21. A similar lawsuit filed in federal court in Kentucky is still pending. We cannot predict the final outcome of this lawsuit. If mining methods at issue are limited or prohibited, it could significantly increase our operational 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 we charge for coal to cover higher production costs without reducing customer demand for our coal.

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, making our ability to comply with the applicable requirements more difficult or even impossible, thereby precluding continuing or future mining operations. Private individuals and the public have certain rights to comment upon and otherwise engage in the permitting process, including through court intervention. Accordingly, the permits we need may not be issued, maintained or renewed, or may not be issued or renewed in a timely fashion, or 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 flow, and profitability.

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

The Surface Mining Control and Reclamation Act of 1977, or SMCRA, establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is 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. We adopted SFAS No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. SFAS No. 143 requires that retirement obligations be recorded as a liability based on fair value, which is calculated as the present value of the estimated future cash flows. In 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 toxic torts, 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.

Mining operations can also impact flows and water quality in surface water bodies and remedial measures may be required, such as lining of stream beds, to prevent or minimize such impacts. We are currently involved with state environmental authorities concerning impacts or alleged impacts of our mining operations on water

flows in several surface streams. We are studying, or addressing, those impacts and we have not finally resolved those matters. Many of our mining operations take place in the vicinity of streams, and similar impacts could be asserted or identified at other streams in the future. The costs of our efforts at the streams we are currently addressing, and at any other streams that may be identified in the future, could be significant.

We maintain extensive coal slurry impoundments at a number of our mines. Such impoundments are subject to 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. We have commenced 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 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 higher 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 nitrogen oxide rules, new ozone and particulate matter standards, regional haze regulations, new source review, 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 reductions in emissions from coal-fired utilities. For example, under the Clean Air Interstate Rule issued in March 2005, the U.S. Environmental Protection Agency, or EPA, has further regulated sulfur dioxide and nitrogen oxides from coal-fired power plants. Among other things, in affected states, the rule mandates reductions in sulfur dioxide emissions by approximately 45% below 2003 levels by 2010, and by approximately 57% below 2003 levels by 2015. The stringency of this cap may require many coal-fired sources to install additional pollution control equipment, such as wet scrubbers. Installation of additional pollution control equipment required by this proposed rule could result in a decrease in the demand for low sulfur coal (because sulfur would be removed by the new equipment), potentially driving down prices for low sulfur coal. In March 2006, the EPA denied petitions to reconsider the Clean Air Interstate Rule and promulgated federal implementation plans for this rule, which are subject to judicial challenge. In March 2005, the EPA also adopted the Clean Air Mercury Rule to control mercury emissions from power plants, which could require coal-fired power plants to install new pollution controls or

comply with a mandatory, declining cap on the total mercury emissions allowed from coal-fired power plants nationwide. The Clean Air Mercury Rule is subject to administrative reconsideration and judicial challenge. This rule has also been subject to challenge in Congress. 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.

There have been several recent proposals in Congress, including the Clear Skies Initiative, 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.

One major by-product of burning coal is carbon dioxide, which is considered a greenhouse gas and is a major source of concern with respect to global warming. The Kyoto Protocol to the 1992 Framework Convention on Global Climate Change, which establishes a binding set of emission targets for greenhouse gases, became binding on ratifying countries on February 16, 2005. Four industrialized nations have refused to ratify the Kyoto Protocol—Australia, Liechtenstein, Monaco and the United States. Although the targets vary from country to country, if the United States were to ratify the Kyoto Protocol, our nation would be required to reduce greenhouse gas emissions to 93% of 1990 levels in a series of phased reductions from 2008 to 2012.

Future regulation of greenhouse gases in the United States could occur pursuant to future U.S. treaty obligations, statutory or regulatory changes under the Clean Air Act, or otherwise. The Bush Administration has proposed a package of voluntary emission reductions for greenhouse gases which provide for certain incentives if targets are met. Some states, such as Massachusetts, have already issued regulations regulating greenhouse gas emissions from large power plants. Further, in 2002, the Conference of New England Governors and Eastern Canadian Premiers adopted a Climate Change Action Plan, calling for reduction in regional greenhouse emissions to 1990 levels by 2010, and a further reduction of at least 10% below 1990 levels by 2020. Increased efforts to control greenhouse gas emissions, including the future ratification of the Kyoto Protocol by the United States, could result in reduced demand for our coal.

Risks Relating To Our Common Stock

We may be unable to provide the required financial information in a timely and reliable manner.

Our current operations consist primarily of the assets of our predecessor, Horizon, and the Anker and CoalQuest businesses that we have acquired, each of which had different historical operating, financial, accounting and other systems. Due to our rapid growth and limited history operating, our acquired operations as an integrated business, and our internal controls and procedures do not currently meet all the standards applicable to public companies, including those contemplated by Section 404 of the Sarbanes-Oxley Act of 2002, as well as rules and regulations enacted by the Securities and Exchange Commission. Areas of deficiency in our internal controls requiring improvement include documentation of controls and procedures, insufficient experience in public company accounting and periodic reporting matters among our financial and accounting staff.

Our management may not be able to effectively and timely implement controls and procedures that adequately respond to the increased regulatory compliance and reporting requirements that will be applicable to us as a public company. If we are not able to implement the requirements of Section 404 in a timely manner or with adequate compliance, our independent auditors may not be able to attest to the adequacy of our internal controls over financial reporting. This result may subject us to adverse regulatory consequences, and there could

also be a negative reaction in the financial markets due to a loss of confidence in the reliability of our financial statements. We could also suffer a loss of confidence in the reliability of our financial statements if our auditors report a material weakness in our internal controls. In addition, if we fail to develop and maintain effective controls and procedures, we may be unable to provide the required financial information in a timely and reliable manner or otherwise comply with the standards applicable to us as a public company. Any failure by us to timely provide the required financial information could materially and adversely impact our financial condition and the market value of our securities.

Our stock price may be extremely volatile.

There has been significant volatility in the market price and trading volume of equity securities, which is unrelated to the financial performance of the companies issuing the securities. These broad market fluctuations may negatively affect the market price of our common stock.

Some specific factors that may have a significant effect on our common stock market price include:

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actual or anticipated fluctuations in our operating results or future prospects;

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the public’s reaction to our press releases, our other public announcements and our filings with the SEC;

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strategic actions by us or our competitors, such as acquisitions or restructurings;

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new laws or regulations or new interpretations of existing laws or regulations applicable to our business;

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changes in accounting standards, policies, guidance, interpretations or principles;

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conditions of the coal industry as a result of changes in financial markets or general economic conditions, including those resulting from war, incidents of terrorism and responses to such events;

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sales of common stock by us or members of our management team; and

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changes in stock market analyst recommendations or earnings estimates regarding our common stock, other comparable companies or the coal industry generally.

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.

Funds sponsored by WLR own approximately 13.76% of our common stock. Circumstances may occur in which WLR 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 invoke risks to our other holders of common stock or adversely affect us or other investors.

We may from time to time engage in transactions with related parties and affiliates that include, among other things, business arrangements, lease arrangements for certain coal reserves and the payment of fees or commissions for the transfer of coal reserves by one operating company to another. These transactions, if any, may adversely affect our sales volumes, margins and earnings.

If our stockholders sell substantial amounts of our common stock , the market price of our common stock may decline.

As of December 31, 2005, we had 152,321,908 shares of common stock outstanding. The number of shares of common stock available for sale in the public market is limited by restrictions under federal securities law and under lock-up agreements that our directors, executive officers and certain holders of our common stock have entered into with the underwriters in the public offering and with us. Those lock-up agreements restrict these persons from selling, pledging or otherwise disposing of their shares of our common stock through and including June 5, 2006 without the prior written consent of UBS Securities LLC. However, UBS Securities LLC, may release all or any portion of the common stock from the restrictions of the lock-up agreements. These sales might make it difficult or impossible for us to sell additional securities if we need to raise capital. All of the shares sold in our recent public offering, as well as all of the shares issued by us in the corporate reorganization, are freely tradable without restrictions or further registration under the Securities Act of 1933, as amended, except for any shares held by our affiliates, as defined in Rule 144 of the Securities Act. The remaining shares of common stock outstanding, including those issued to former Anker stockholders and CoalQuest members, are available for sale into the public market at various times in the future. Additional shares of common stock underlying options granted or to be granted will become available for sale in the public market. We have also filed a registration statement on Form S-8 that registered 8,525,302 shares of common stock covering shares of restricted stock granted to our executives and the shares of common stock to be issued pursuant to the exercise of options we have granted or will grant under our employee stock option plan and a certain employment agreement.

In addition, under a registration rights agreement that we entered into with certain of our existing stockholders, certain of our stockholders have “demand” and “piggyback” registration rights in connection with future offerings of our common stock. “Demand” rights enable the holders to demand that their shares of common stock be registered and may require us to file a registration statement under the Securities Act at our expense. “Piggyback” rights require us to provide notice to the relevant holders of our stock if we propose to register any of our securities under the Securities Act and grant such holders the right to include their shares in our registration statement. We have also granted “piggyback” registration rights to the former Anker and CoalQuest holders who received shares of our common stock in the Anker and CoalQuest acquisitions. As restrictions on resale end on June 5, 2006, our stock price could drop significantly if the holders of these restricted shares sell them or the market perceives they intend to sell them. These sales may also make it more difficult for us to sell securities in the future at a time and at a price we deem appropriate.

The requirements of being a public company may strain our resources and distract management.

As a result of the reorganization, we became subject to the reporting requirements of the Securities Exchange Act of 1934 and the Sarbanes-Oxley Act. These requirements may place a strain on our people, systems and resources. The Exchange Act requires that we file annual, quarterly and current reports with respect to our business and financial condition. The Sarbanes-Oxley Act requires that we maintain effective disclosure

controls and procedures and internal controls over financial reporting. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal controls over financial reporting, significant resources and management oversight will be required. This may divert management’s attention from other business concerns. As a result of becoming a public company, our costs have also increased as a result of having to comply with the Exchange Act, the Sarbanes-Oxley Act and the New York Stock Exchange listing requirements, which require us, among other things, to establish an internal audit function.

We will incur incremental costs not reflected in our historical financial statements as a result of these increased regulatory compliance and reporting requirements, including increased auditing and legal fees. We also will need to hire additional accounting and administrative staff with experience managing public companies. Moreover, the standards that are applicable to us as a public company could make it more difficult and expensive for us to attract and retain qualified members of our board of directors and qualified executive officers. We also anticipate that the regulations related to the Sarbanes-Oxley Act will make it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage.

We may not pay dividends for the foreseeable future.

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 facilities limit 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 any dividends or make any distributions or payments with respect to our capital stock. Accordingly, investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize their investment.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable because we are not an accelerated filer.

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 260 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. ICG Natural Resources, LLC and CoalQuest own and lease all of our reserves that are not currently assigned to or associated with one of our mining operations. These reserves contain approximately 656 million tons of mid to high Btu, low and high sulfur coal located in Kentucky, West Virginia, Maryland, Illinois, Pennsylvania and Virginia. 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.

Our total coal reserves could support current production levels for more than 62 years. The following table provides the location of our mining operations and the type of coal produced at those operations as of December 31, 2005:


Mining operations	Assigned or Unassigned⁽¹⁾	Operating (O) or Development (D)	State	Mining method Surface (S) or Underground (UG)	Total proven and probable reserves⁽²⁾ (in million tons)	Owned proven and probable reserves (in million tons)	Leased proven and probable reserves (in million tons)	Steam proven and probable reserves (in million tons)	Metallurgical⁽³⁾⁽⁴⁾ proven and probable reserves (in million tons)
Northern Appalachia
Vindex Energy Corp.	Assigned	O	MD	S	9.79	0.00	9.79	7.28	2.51
	Unassigned	D	MD	S/UG	6.21	0.47	5.74	0.15	6.06

Total Vindex Energy Corp.					16.00	0.47	15.53	7.43	8.57

Patriot Mining Co.	Assigned	O	WV	S	0.15	0.15	0.00	0.15	0.00
	Unassigned	D	WV	S	0.20	0.19	0.01	0.20	0.00

Total Patriot Mining Co.					0.35	0.34	0.01	0.35	0.00

Buckhannon/Spruce Division	Assigned	O	WV	UG	2.90	2.90	0.00	0.00	2.90
	Unassigned	D	WV	UG	44.90	43.10	1.80	1.30	43.60

Total Buckhannon/Spruce Division					47.80	46.00	1.80	1.30	46.50

Sycamore Group	Assigned	O	WV	UG	18.22	0.38	17.84	18.22	0.00
Philippi Development Division	Assigned	O	WV	UG	35.91	32.28	3.63	0.00	35.91
	Unassigned	D	WV	UG	4.94	4.94	0.00	0.00	4.94

Total Phillipi Development Division					40.85	37.22	3.63	0.00	40.85

CoalQuest Development LLC	Unassigned	D	WV	UG	194.30	194.30	0.00	32.71	161.59
	(Hillman)

Northern Appalachia Total					317.52	278.71	38.81	60.01	257.51

Central Appalachia
ICG-Eastern	Assigned	O	WV	S	20.92	5.63	15.29	20.92	0.00

ICG-Hazard	Assigned	O	KY	S	15.64	0.00	15.64	15.64	0.00
	Unassigned	D	KY	S/UG	20.11	0.00	20.11	20.11	0.00

Total ICG-Hazard					35.75	0.00	35.75	35.75	0.00

Flint Ridge	Assigned	O	KY	S/UG	32.29	0.19	32.10	32.29	0.00
ICG-Knott County	Assigned	O	KY	UG	18.95	4.88	14.07	18.95	0.00
ICG-East Kentucky	Assigned	O	KY	S	1.18	0.00	1.18	1.18	0.00
ICG-Natural Resources	Unassigned	D	WV	S	30.00	0.00	30.00	30.00	0.00
	(Tioga)
ICG-Natural Resources	Unassigned	D	KY	S	5.91	4.36	1.55	5.91	0.00
	(Mt. Sterling)
ICG-Natural Resources	Unassigned	D	WV	S/UG	44.90	2.20	42.70	44.90	0.00
	(Jennie Creek)
ICG Beckley⁽³⁾	Unassigned	D	WV	UG	28.97	1.28	27.69	0.00	28.97
	(Beckley)
White Wolf Energy, Inc. (f/k/a Anker Virginia Mining Company, Inc.)⁽³⁾	Unassigned	D	V	UG	27.50	0.00	27.50	0.00	27.50
	(Big Creek)

Central Appalachia Total					246.37	18.54	227.83	189.90	56.47

Other
ICG-Illinois	Assigned (Viper)	O	IL	UG	27.30	10.66	16.64	27.30	0.00
ICG-Natural Resources	(Unassigned)	D	IL	UG	325.21	305.06	20.15	325.21	0.00

Total Other					352.51	315.72	36.79	352.51	0.00

Total Proven and Probable Reserves					916.40	612.97	303.43	602.42	313.98

(1)

The proven and probable reserves indicated for each mine are “Assigned.” Unassigned proven and probable reserves for each mining complex are shown separately. “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 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 investments 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)

ICG Beckley and White Wolf Energy meet historical metallurgical coal quality specifications.

(4)

Currently, we report selling coal with ash and sulfur contents as high as 10% and 1.5%, respectively into the current metallurgical market from the Vindex Energy, Buckhannon/Spruce and Phillipi Divisions. Similarly, we believe all production from Vindex Division and portions of Hillman could be sold on this metallurgical market when production begins.

The following table provides the “quality” (average moisture, ash, sulfur and Btu content, sulfur content and ash content per pound) of our coal reserves as of January 1, 2006:


		As received quality					Total reserves
Mining operations	Assigned or Unassigned⁽¹⁾	% Moisture	% Ash	% Sulfur	Btu/lb.	Lbs. SO(2) million Btu’s	<1.2 lbs. SO(2) compliance	>1.2 lbs SO(2) non-compliance
Northern Appalachia
Vindex Energy Corp.	Assigned	6.00	14.01	1.74	12,407	2.81	0.00	9.79
	Unassigned	6.00	9.47	0.86	13,193	1.31	0.00	6.21

Total Vindex Energy Corp.		6.00	12.25	1.40	12,712	2.24	0.00	16.00

Patriot Mining Co.	Assigned	6.00	19.06	2.13	11,240	3.85	0.00	0.00
	Unassigned	6.00	19.06	2.13	11,240	3.85	0.00	0.35

Total Patriot Mining Co.		6.00	19.06	2.13	11,240	3.85	0.00	.35

Buckhannon/Spruce Division	Assigned	6.00	8.81	1.24	13,078	1.89	0.00	2.90
	Unassigned	6.00	8.87	1.11	13,076	1.70	0.00	44.90

Total Buckhannon/Spruce Division		6.00	8.87	1.12	13,076	1.71	0.00	47.80

Sycamore Group	Assigned	6.00	7.19	3.05	13,099	4.65	0.00	18.22
Philippi Development Division	Assigned	6.00	8.17	1.32	13,299	1.98	0.00	35.91
	Unassigned	6.00	8.04	1.44	13,353	2.15	0.00	4.94

Total Phillipi Development Division		6.00	8.15	1.33	13,306	2.00	0.00	40.85

Coal CoalQuest Development LLC	Unassigned	6.00	9.21	1.15	13,179	1.74	0.00	194.30
	(Hillman)

Northern Appalachia Total							0.00	317.52

Central Appalachia
ICG-Eastern	Assigned	6.00	14.42	1.24	11,964	2.07	0.00	20.92
ICG-Hazard	Assigned	6.00	11.25	1.54	11,835	2.61	0.00	15.64
	Unassigned	6.00	12.98	1.63	12,047	2.72	0.00	20.11

Total ICG-Hazard		6.00	12.22	1.59	11,954	2.67	0.00	35.75

Flint Ridge	Assigned	6.00	8.15	1.39	12,768	2.17	0.00	32.29
ICG-Knott County	Assigned	6.00	7.71	1.22	12,927	1.88	2.59	16.36
ICG-East Kentucky	Assigned	4.50	11.59	1.36	12,680	2.14	0.00	1.18
ICG-Natural Resources	Unassigned (Tioga)	6.00	14.42	1.24	11,964	2.07	0.00	30.00
ICG-Natural Resources	Unassigned	6.00	9.18	0.83	12,430	1.33	0.00	5.91
	(Mt. Sterling)
ICG-Natural Resources	Unassigned	7.00	6.47	1.10	12,935	1.69	0.00	44.90
	(Jennie Creek)
ICG Beckley⁽²⁾	Unassigned	6.00	4.87	0.70	13,913	1.01	28.97	0.00
	(Beckley)
White Wolf Energy, Inc. (f/k/a Anker Virginia Mining Company, Inc.) ⁽²⁾	Unassigned	6.00	4.00	0.65	14,073	0.92	27.50	0.00
	(Big Creek)

Central Appalachia Total							59.06	187.31

Other
ICG-Illinois	Assigned (Viper)	16.00	8.80	2.86	10,692	5.35	0.00	27.30
ICG-Natural Resources	Unassigned	10.00	8.99	3.24	11,377	5.70	0.00	325.21

Total Other		10.50	8.98	3.21	11,320	5.67	0.00	352.51

Total Proven and Probable Reserves							59.06	857.34

(1)

The proven and probable reserves indicated for each mine are “Assigned.” Unassigned proven and probable reserves for each mining complex are shown separately. “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 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 investments before production can begin.

(2)

ICG Beckley and White Wolf Energy meet historical metallurgical coal quality specifications.

Our reserve estimate is 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 or sales of coal properties will also change the reserves. 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.”

Periodically, we retain outside experts to independently verify our coal reserves. The most recent review was completed during the first quarter of 2005 and covered all of our reserves. The results verified our reserve estimates, with very minor adjustments, and included an in-depth review of our procedures and controls. As of December 31, 2005, based on an independent evaluation performed on January 1, 2005 and on management’s current estimates, we controlled 916 million tons.

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 $1.76 per ton in 2005, representing approximately 4.20% (net of freight and handling) of our coal sales revenue in 2005. 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 warrants 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 either limited property control or geologic limitations, or both.

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, 2005:

Mining operations

Assigned or
Unassigned⁽¹⁾

Operating (O)
or Development (D)

State

Mining method
Surface (S) or
Underground (UG)

Total
non-reserve
coal deposits
(in million
tons)

Steam
non-reserve
coal deposits
(in million
tons)

Metallurgical⁽²⁾
non-reserve
coal deposits
(in million
tons)

Northern Appalachia

Patriot Mining Co

Assigned

0.13

0.00

Unassigned

1.77

0.00

Total Patriot Mining

1.89

0.00

Buckhannon/Spruce Division

Assigned

0.18

0.00

Unassigned

2.24

0.00

Total Buckhannon/Spruce Division

2.42

0.00

Sycamore Group

Assigned

1.28

0.00

Unassigned

0.00

Total Sycamore Group

1.28

0.00

Philippi Development Division

Assigned

1.64

0.00

Unassigned

0.76

0.00

Total Phillipi Development Division

2.40

0.00

CoalQuest Development LLC

Unassigned

37.04

0.00

(Hillman)

Upshur Property

Unassigned

92.96

0.00

(Upshur)

Northern Appalachia Total

137.99

0.00

Central Appalachia

ICG-Eastern

Assigned

0.02

0.00

ICG-Hazard

Assigned

0.16

0.00

Flint Ridge

Assigned

S/UG

2.84

0.00

ICG-Knott County

Assigned

0.00

ICG-East Kentucky

Assigned

0.00

(Blackberry)

ICG-Natural Resources

Unassigned

S/UG

35.60

0.00

(Mt. Sterling)

ICG-Natural Resources

Unassigned

20.64

0.00

(Jennie Creek)

Wolf Run Mining Company (f/k/a Anker West Virginia Mining Company, Inc.)

Unassigned)

S/UG

1.20

0.00

(Juliana)

ICG Beckley ⁽³⁾

Unassigned

1.88

0.00

1.88

(Beckley)

White Wolf Energy, Inc. (f/k/a Anker Virginia Mining Company, Inc.)⁽³⁾

Unassigned

2.57

0.00

(Big Creek)

Central Appalachia Total

64.91

63.03

1.88

Other

ICG-Illinois

Assigned

38.47

0.00

(Viper)

ICG-Natural Resources

Unassigned

263.07

0.00


Mining operations	Assigned or Unassigned⁽¹⁾	Operating (O) or Development (D)	State	Mining method Surface (S) or Underground (UG)	Total non-reserve coal deposits (in million tons)	Steam non-reserve coal deposits (in million tons)	Metallurgical⁽²⁾ non-reserve coal deposits (in million tons)
ICG-Natural Resources	(Illinois) Unassigned		AR	S	39.15	39.15	0.00
	(Arkansas)
	Unassigned		CA	UG	10.00	10.00	0.00
	(California)
	Unassigned		OH	UG	98.00	98.00	0.00
	(Ohio)
	Unassigned		MT	S	12.00	12.00	0.00
	(Montana)
	Unassigned		WA	S	43.08	43.08	0.00
	(Washington)

Total Other					503.77	503.77	0.00

Total Non-Reserve Coal Deposits					706.67	704.79	1.88

(1)

“Assigned non-reserve coal deposits” mean coal which has been committed by the company to operating mine shafts, mining equipment, and plant facilities, and all coal which has been leased by the 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)

Currently, ICG reports selling coal with ash and sulfur contents as high as 10% and 1.5%, respectively into the current metallurgical market from the Vindex Energy, Buckhannon/Spruce and Philippi Divisions. Similarly, we believe all production from Vindex Division and portions of Hillman can be sold on this metallurgical market.

(3)

ICG Beckley and White Wolf Energy meet historical metallurgical coal quality specifications.

The following table provides the “quality” (average moisture, ash, sulfur and Btu content per pound) of our non-reserve coal deposits as of December 31, 2005:


		As received quality
Mining operations	Assigned or Unassigned⁽¹⁾	% Moisture	% Ash	% Sulfur	Btu/ lb.	Lbs. SO(2)/ million Btu’s
Northern Appalachia
Patriot Mining Co	Assigned	N/A	N/A	N/A	N/A	N/A
	Unassigned	N/A	N/A	N/A	N/A	N/A
Buckhannon/Spruce Division	Assigned	6.00	9.00	1.20	13,000	1.85
	Unassigned	6.00	9.00	1.20	13,000	1.85
Sycamore Group	Assigned	6.00	7.21	3.05	13,097	4.66
	Unassigned	N/A	N/A	N/A	N/A	N/A
Philippi Development Division	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 (Upshur)	6.00	43.00	2.00	8,000	5.00
Central Appalachia
ICG-Eastern	Assigned	6.00	12.20	1.20	12,400	1.94
ICG-Hazard	Assigned	6.00	8.26	1.41	12,732	2.22
Flint Ridge	Assigned	6.00	8.15	1.39	12,768	2.18
ICG-Knott County	Assigned	N/A	N/A	N/A	N/A	N/A
ICG-East Kentucky	Assigned (Blackberry)	N/A	N/A	N/A	N/A	N/A
ICG-Natural Resources	Unassigned (Mt. Sterling)	6.00	11.63	1.93	11,774	3.28
ICG-Natural Resources	Unassigned (Jennie Creek)	6.00	12.50	1.10	12,000	1.83
Wolf Run Mining Company (f/k/a Anker West Virginia Mining Company, Inc.)	Unassigned (Juliana)	6.00	7.50	0.82	13,100	1.25
ICG Beckley ⁽²⁾	Unassigned (Beckley)	6.00	4.80	0.70	13,800	1.01
White Wolf Energy, Inc. (f/k/a Anker Virginia Mining Company, Inc.) ⁽²⁾	Unassigned (Big Creek)	6.00	7.40	0.60	13,500	0.89


		As received quality
Mining operations	Assigned or Unassigned⁽¹⁾	% Moisture	% Ash	% Sulfur	Btu/ lb.	Lbs. SO(2)/ million Btu’s
Other
ICG-Illinois	Assigned (Viper)	16.00	9.50	3.50	10,500	6.67
ICG-Natural Resources	Unassigned (Illinois)	13.00	9.00	3.00	11,000	5.45
ICG-Natural Resources		N/A	8.00	0.40	5,650	1.42
	(Arkansas)
	Unassigned	6.00	13.00	3.50	11,700	5.98
	(California)
	Unassigned	6.00	8.40	2.50	12,650	3.95
	(Ohio)
	Unassigned	N/A	8.00	0.30	8,900	0.67
	(Montana)
	Unassigned	N/A	8.00	0.50	7,025	1.42
	(Washington)

(1)

“Assigned non-reserve coal deposits” mean coal which has been committed by the company to operating mine shafts, mining equipment, and plant facilities, and all coal which has been leased by the 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)

ICG Beckley and White Wolf Energy meet historical metallurgical coal quality specifications.

ITEM 3. LEGAL PROCEEDINGS

From time to time, we are involved in legal proceedings arising in the ordinary course of business. We believe we have recorded adequate reserves for these liabilities and that there is no individual case or group of related cases pending that is likely to have a material adverse effect on our financial condition, results of operations or cash flows. With respect to any claims relating to Horizon which arose prior to November 12, 2002, such claims are subject to an automatic stay of the U.S. Bankruptcy Code. In limited circumstances, the Bankruptcy Court has lifted the stay but only to the extent of insurance coverage relating to Horizon. In any event, we believe all or substantially all of the claims will be resolved in accordance with Horizon’s plan of reorganization.

On November 18, 2005, we filed a lawsuit against Massey Coal Sales Company, Inc., a Massey Energy Company subsidiary, in the U.S. District Court for the Eastern District of Kentucky. In the complaint, we have alleged that Massey has breached an existing coal supply agreement. Pursuant to the terms of the coal supply agreement, Massey sells the coal to us and we in turn sell the coal to our customer, Carolina Power & Light. Any failure by Massey to perform under its coal supply agreement adversely affects our ability to perform under our agreement with Carolina Power & Light and could result in liability to our customer for such failure, although we would seek indemnification from Massey for any such liability. We are seeking damages for Massey’s past failure to perform, punitive damages and an injunction requiring contractual performance during the remaining term of the contract.

As a result of the explosion at our Sago mine on January 2, 2006, the Federal Mine Safety and Health Administration and the State of West Virginia have begun a joint investigation into the cause of the explosion. We are fully cooperating with the investigation by federal and state mine regulatory authorities to determine the cause of the explosion. See “Business — Recent Developments” for a summary of our initial findings from the investigation.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On October 24, 2005, the then sole stockholder of International Coal Group, Inc., ICG, Inc., by written consent, approved the adoption of our Second Amended and Restated Certificate of Incorporation.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Trading in our common stock commenced on the New York Stock Exchange on November 21, 2005 under the symbol “ICO.” The following table sets forth, for the periods indicated, the high and low sales prices per share at the end of the day of our common stock reported on the New York Stock Exchange.

As of March 16, 2006, there were approximately 109 holders of record of our common stock and an additional 10,738 stockholders whose shares were held for them in street name or nominee accounts.

The following table shows, for the quarterly periods indicated, the high and low quotes at the end of the day for the shares of the common stock of ICG, Inc. as reported on the Pink Sheets Electronic Quotation Service. Certain of the shares of ICG, Inc. were issued to former creditors of Horizon in a transaction exempt from the registration requirements of the Securities Act.


	Stock Price				Average Daily Volume⁽¹⁾
	High		Low		Average Daily Volume⁽¹⁾
January 1, 2005 through March 31, 2005	$	15.00	$	12.13	224,952
April 1, 2005 through June 30, 2005	$	15.00	$	12.00	99,629
July 1, 2005 through September 30, 2005	$	15.00	$	12.50	213,756
October 1, 2005 to November 18, 2005⁽²⁾	$	15.00	$	11.65	142,536

(1)

Does not include days on which there were no quotes for the shares of the ICG, Inc. common stock.

(2)

Quotes for the shares of ICG, Inc. common stock ceased being reported on the Pink Sheets Electronic Quotation Service at the close of business on November 18, 2005.

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. See “Risk Factors—Risks relating to our common stock —Our stock price may be extremely volatile.”

Recent Sales of Unregistered Securities

On March 31, 2005, in connection with our initial formation, we issued 100 shares of common stock to ICG, Inc. These shares were subsequently cancelled and reissued to ICG, LLC on April 19, 2005. On April 25, 2005, we issued an additional 9,999,900 shares of common stock to ICG, LLC. Both of these issuances were private placement made in accordance with Section 4(2) of the Securities Act. We did not receive any proceeds from such issuances of common stock.

On April 25, 2005, we granted 45,000 shares of restricted shares of common stock to William D. Campbell, our Vice President, Treasurer and Assistant Secretary, 40,000 shares of restricted shares of common stock to Phillip Michael Hardesty, our Senior Vice President, Sales and Marketing, 50,000 shares of restricted shares of common stock to Samuel R. Kitts, our Senior Vice President, West Virginia and Maryland Operations, 37,500 shares of restricted and 12,500 shares of unrestricted common stock to Roger L. Nicholson, our Senior Vice President, General Counsel and Secretary, and 50,000 shares of restricted shares of common stock to William Scott Perkins, our Senior Vice President, Kentucky and Illinois. On May 9, 2005, we granted 50,000 shares of restricted shares of common stock to Oren Eugene Kitts, our Senior Vice President Mining Operations, and on

June 29, 2005, we granted 40,000 shares of restricted shares of common stock to Charles G. Snavley, our Vice President, Planning and Acquisitions. Each of the forgoing grants was made pursuant to a restricted stock agreement that we entered into with each executive officer in accordance with our 2005 Equity and Performance Incentive Plan. The grants of the shares of restricted shares of common stock were exempt from registration under the Securities Act in reliance on Rule 701 under the Securities Act as an offer and sale of securities pursuant to certain compensatory benefit plans in compliance with Rule 701.

On November 18, 2005, as part of our reorganization, the 300,000 shares of ICG, Inc. stock held by Mr. Hatfield were exchanged for an equal number of shares of our common stock. The issuance by us of 300,000 shares of our common stock in exchange for the shares of ICG, Inc. common stock was made pursuant to Section 4(2) of the Securities Act as a private placement.

On November 18, 2005, we completed the acquisitions of Anker and CoalQuest pursuant to (i) the Anker Business Combination Agreement among ICG, Inc., us, Anker and the stockholders of Anker, dated as of March 31, 2005, as amended and (ii) the Business Combination Agreement among ICG, Inc., us, CoalQuest and the members of CoalQuest, dated as of March 31, 2005, as amended. In connection with these acquisitions, we issued an aggregate of 29,824,670 shares of common stock to an escrow agent for the benefit of the shareholders of Anker and the members of CoalQuest until the final determination of the number of shares issuable. The final aggregate number of shares issued to the former Anker shareholders was 14,840,909 shares, and the final aggregate number of shares issued to the former CoalQuest members was 9,250,000. The 5,733,761 shares deposited with the escrow agent were returned to our treasury. Each of these issuances were made pursuant to Section 4(2) of the Securities Act as private placements.

Use of Proceeds From the Registrant’s Public Offering

On December 12, 2005, we consummated a public offering of our common stock, par value $0.01 per share, pursuant to its registration statement on Form S-1 (File No. 333-124393), which was declared effective by the SEC on December 6, 2005. Pursuant to the offering, 21,000,000 shares of common stock were sold for an aggregate offering price of $231.0 million. The underwriters for the offering were UBS Securities LLC, Lehman Brothers Inc., Bear Stearns & Co. Inc., Goldman, Sachs & Co., J.P. Morgan Securities Inc. and Morgan Stanley & Co. Incorporated.

The net proceeds received by us in the offering were as follows:


	(in millions)
Aggregate offering proceeds to us	$	231.0
Underwriting discounts and commissions		15.6
Other fees and expenses		4.9

Total expenses		20.5

Net proceeds	$	210.5

We repaid $188.7 million of our term loan debt and $21.2 million of borrowings under our revolving credit facility and certain other expenses with the net proceeds of the public offering.

Summary of Equity Compensation Plans

Shown below is information concerning our equity compensation plan and individual compensation arrangements as of December 31, 2005.


	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⁾	325,000	$	11.00	7,362,500
Equity compensation plans not approved by stockholders⁽²⁾	319,052		10.97	—

	644,052		$10.99	7,362,500

(1)

We have one compensation plan, the 2005 Equity and Performance Incentive Plan approved by stockholders on October 24, 2005.

(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 12 to our audited consolidated financial statements included elsewhere in this report.

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 facilities limit 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.

IT EM 6. SELECTED FINANCIAL DATA

International Coal Group, Inc. was formed in March 2005 as wholly-owned subsidiary of ICG, Inc. in order to effect a corporate reorganization. On November 18, 2005, we completed the reorganization. Prior to this reorganization, ICG, Inc. was the top-tier holding company. Upon completion of the reorganization, International Coal Group, Inc. became the new top-tier parent holding company. International Coal Group, Inc. is a holding company which does not have any independent external operations, assets or liabilities, other than through its operating subsidiaries. Prior to the acquisition of certain assets of Horizon as of September 30, 2004, ICG, Inc. did not have any material assets, liabilities or results of operations. The selected historical consolidated financial data is derived from International Coal Group, Inc.’s audited consolidated financial statements as of and for the year ended December 31, 2005, as of and for the period from May 13, 2004 to December 31, 2004, and the predecessor consolidated financial data for the nine months ended September 30, 2004, and for the year ended December 31, 2003, which have been audited and are included elsewhere in this report. The selected historical consolidated financial data as of September 30, 2004 and December 31, 2003 and as of and for the period ended May 10, 2002 to December 31, 2002 have been derived from the consolidated financial statements of Horizon, our predecessor, which have been audited and are not included in this report. The selected historical consolidated financial data is derived from the statement of operations of AEI Resources, the predecessor of Horizon, for the period January 1, 2002 to May 9, 2002, which have been audited and are not included in the report. The selected historical consolidated financial data as of and for the year ended December 31, 2001 were derived from the audited consolidated financial statements of AEI Resources, the predecessor to Horizon and are not included in this report. In the opinion of management, the financial data reflect all adjustments,

consisting of all normal and recurring adjustments, necessary for a fair presentation of the results for those periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year or for any future period. The financial statements for the predecessor periods have been prepared on a “carve-out” basis to include our assets, liabilities and results of operations that were previously included in financial statements of Horizon. The financial statements for the predecessor periods include allocations of certain expenses, taxation charges, interest and cash balances relating to the predecessor based on management’s estimates. The predecessor financial information is not necessarily indicative of our consolidated financial position, results of operations and cash flows if we had operated during the predecessor periods presented.

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 report, including the consolidated financial statements of International Coal Group, Inc. and Horizon (and its predecessor) and the related notes thereto.


	AEI Resources (Predecessor to Horizon)						Horizon (Predecessor to International Coal Group, Inc.)									International Coal Group, Inc.
	Year ended December 31, 2001			Period from January 1, 2002 to May 9, 2002⁽²⁾			Period from May 10, 2002 to December 31, 2002⁽²⁾			Year ended December 31, 2003⁽²⁾			Period January 1, 2004 to September 30, 2004⁽²⁾			Period May 13, 2004 to December 31, 2004			Year ended December 31, 2005
							(dollars in thousands, except per share data)
Statement of Operations Data:
Revenues:
Coal sales revenues	$	500,829		$	136,040		$	264,235		$	441,291		$	346,981		$	130,463		$	619,038
Freight and handling revenues		14,728			2,947			6,032			8,008			3,700			880			8,601
Other revenues		34,835			21,183			27,397			31,771			22,702			4,766			20,074

Total revenues		550,392			160,170			297,664			481,070			373,383			136,109			647,713

Cost and expenses:
Freight and handling costs		14,728			2,947			6,032			8,008			3,700			880			8,601
Cost of coal sales and other revenues (exclusive of depreciation, depletion and amortization shown separately below)		379,333			114,767			251,361			400,652			306,429			113,707			510,834
Depreciation, depletion and amortization		92,602			32,316			40,033			52,254			27,547			7,943			43,195
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)		19,324			9,677			16,695			23,350			8,477			4,194			28,785
(Gain)/loss on sale of assets		189			(93	)		(39	)		(4,320	)		(226	)		(10	)		(502	)
Writedowns and special items		20,218			8,323			729,953			9,100			10,018			—			—

Total costs and expenses		526,394			167,937			1,044,035			489,044			355,945			126,714			590,913

Income (loss) from operations		23,998			(7,767	)		(746,371	)		(7,974	)		17,438			9,395			56,800

Other income (expense)
Interest expense		(138,655	)		(36,666	)		(80,405	)		(145,892	)		(114,211	)		(3,453	)		(14,394	)
Reorganization items		—			787,900			(4,075	)		(23,064	)		(12,471	)		—			—
Other, net		(2,941	)		499			1,256			187			1,581			898			6,080

Total interest and other income (expense)		(141,596	)		751,733			(83,224	)		(168,769	)		(125,101	)		(2,555	)		(8,314	)

Income (loss) before income taxes and minority interest		(117,598	)		743,966			(829,595	)		(176,743	)		(107,663	)		6,840			48,486
Income tax (expense) benefit		(4,155	)		—			—			—			—			(2,591	)		(16,676	)
Minority interest		—			—			—			—			—			—			15

Net income (loss)	$	(121,753	)	$	743,966		$	(829,595	)	$	(176,743	)	$	(107,663	)	$	4,249		$	31,825


	AEI Resources (Predecessor to Horizon)						Horizon (Predecessor to International Coal Group, Inc.)									International Coal Group, Inc.
	Year ended December 31, 2001			Period from January 1, 2002 to May 9, 2002			Period from May 10, 2002 to December 31, 2002			Year ended December 31, 2003⁽²⁾			Period January 1, 2004 to September 30, 2004⁽²⁾			Period May 13, 2004 to December 31, 2004			Year ended December 31, 2005
Earnings (loss) per share⁽¹⁾:
Basic		—			—			—			—			—		$	0.04		$	0.29
Diluted		—			—			—			—			—			0.04			0.29
Weighted-average common shares outstanding⁽¹⁾:
Basic		—			—			—			—			—			106,605,999			111,120,211
Diluted		—			—			—			—			—			106,605,999			111,161,287
Balance sheet data (at period end):
Cash and cash equivalents	$	64,592		$	87,278		$	114		$	859		$	—		$	23,967		$	9,187
Total assets		881,924			1,521,318			623,800			576,372			539,606			459,975			1,056,163
Long-term debt and capital leases		—			933,106			1,157			315			29			175,681			45,462
Total liabilities and minority interest		1,581,346			1,286,318			1,222,219			1,351,393			1,422,290			305,575			390,291
Total stockholders’ equity (members deficit)		(699,422	)		235,000			(598,419	)		(775,021	)		(882,684	)		154,400			665,872
Total liabilities and stockholders’ equity (members deficit)	$	881,924		$	1,521,318		$	623,800		$	576,372		$	539,606		$	459,975		$	1,056,163
Statement of cash flows data:
Net cash provided by (used in):
Operating activities	$	106,060		$	(353,592	)	$	76,378		$	20,030		$	28,085		$	30,264		$	77,319
Investing activities	$	(88,434	)	$	44,555		$	(12,805	)	$	(3,826	)	$	3,437		$	(329,168	)	$	(104,713	)
Financing activities	$	(8,547	)	$	259,011		$	(78,025	)	$	(15,459	)	$	(32,381	)	$	322,871		$	12,614
Capital expenditures	$	34,254		$	10,963		$	13,435		$	16,937		$	6,624		$	5,583			108,231

(1)

Earnings per share data and average shares outstanding are not presented for the year ended December 31, 2003 and the period from January 1, 2004 to September 30, 2004 because they were prepared on a carve-out basis. The financial statements prepared for predecessor periods are carve-out financial statements reflecting the operations and financial condition of the Horizon assets acquired by us as of September 30, 2004 (collectively, the “combined companies”). The predecessor financial statements were prepared from the separate accounts and records maintained by the combined companies. In addition, certain assets and expense items represent allocations from Horizon. The accounts allocated include vendor advances, reclamation deposits and selling, general and administrative expenses.

(2)

As restated. See Note 12 to the combined financial statements of Horizon included elsewhere in this report.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS 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 prospectus under “Special Note Regarding Forward-Looking Statements” and under “Risk Factors.” You should read the following discussion in conjunction with “Selected Financial Data” and audited and unaudited consolidated financial statements and notes of International Coal Group, Inc. and its subsidiaries and the audited and unaudited consolidated financial statements and notes of Horizon NR, LLC, each appearing elsewhere in this Form 10-K.

As discussed in Note 12 to Horizon NR, LLC’s combined financial statements, Horizon’s financial statements have been restated. The accompanying management discussion and analysis gives effect to that restatement.

Overview

ICG, Inc. was formed by WLR and other investors in May 2004 to acquire and operate competitive coal mining facilities. International Coal Group, Inc. was formed in March 2005 and became the parent holding company pursuant to a reorganization on November 18, 2005. Through the acquisition of key assets from the

Horizon bankruptcy estate, the WLR investor group was able to target properties strategically located in Appalachia and the Illinois Basin with high quality reserves that are union free, have limited reclamation liabilities and are substantially free of legacy liabilities. Due to our initial capitalization, we were able to complete the acquisition without significantly increasing our level of indebtedness. With the proceeds of our recently completed public offering, we retired substantially all of our debt. Consistent with the WLR investor group’s strategy to acquire attractive coal assets, the Anker and CoalQuest acquisitions further diversified our reserves.

We produce, process and sell steam coal from eleven regional mining complexes, which, as of December 31, 2005 were supported by eleven active underground mines, twelve active surface mines and seven preparation plants located throughout West Virginia, Kentucky 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 and the audited consolidated financial statements and notes of Horizon and its predecessors, each appearing elsewhere in this report. We also broker coal produced by others; the majority of which is shipped directly from the third party producer to the ultimate customer. Our sales of steam coal were made to large utilities and industrial customers in the Eastern region of the United States. In addition, we generate other revenues from the manufacture and operation of highwall mining systems, parts sales and shop services relating to those systems and coal handling and processing fees.

Our primary expenses are wages and benefits, repair and maintenance expenditures, diesel fuel purchases, blasting supplies, coal transportation costs, cost of purchased coal, royalties, freight and handling costs 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 current pricing environment for U.S. coal is strong. Any decrease in coal prices due to, among other reasons, the supply of domestic and foreign coal, the demand for electricity and the price and availability of alternative fuels for electricity generation could adversely affect our revenues and our ability to generate cash flows. In addition, our results of operations depend on the cost of coal production. We are experiencing increased operating costs for fuel and explosives, steel products, health care and contract labor. We expect to experience higher costs for surety bonds and letters of credit. In addition, historically low interest rates have had a negative impact on expenses related to our actuarially determined employee-related liabilities.

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. 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. Note 2 to our audited consolidated financial statements provides a description of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity.

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 at the time of shipment or delivery to the customer, at fixed or determinable prices, and the title 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, where coal is loaded to the rail, barge, truck or other transportation sources that deliver 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.

Other revenues consist of equipment and parts sales, equipment rebuild and maintenance services, coal handling and processing, royalties, commissions on coal trades, contract mining, and rental 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 apply the relevant accounting literature as appropriate, 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 as coal is shipped or rental income is earned.

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. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. We account for the costs of our reclamation activities in accordance with the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations. We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based upon third-party costs. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. In accordance with the provisions of SFAS No. 143, we determine the fair value of our asset retirement obligations. In order to determine fair value, we must also estimate a discount rate and third-party margin. Each is discussed further below:

•

Discount rate. SFAS No. 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of SFAS No. 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.

•

Third-party margin. SFAS No. 143 requires the measurement of an obligation to be based upon the amount a third-party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin was added to the estimated costs of these activities. This margin was estimated based upon our historical experience with contractors performing certain types of reclamation activities. The inclusion of this margin will result in a recorded obligation that is greater than our estimates of our cost to perform the reclamation activities. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is completed.

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, 2005, we had recorded asset retirement obligation liabilities of $84.4 million, including amounts reported as current

liabilities. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2005, we estimate that the aggregate undiscounted cost of final mine closure is approximately $131.8 million.

Depreciation, Depletion And Amortization

Property, plant and equipment, including coal lands and mine development costs, 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.

Coal land costs are depleted using the units-of-production method, based on estimated recoverable interest. The coal lands fair values are established by either using third party mining engineering consultants or market values as established when coal lands are purchased on the open market. These values are then evaluated as to the number of recoverable tons contained in a particular mining area. Once the coal land values are established, and the number of recoverable tons contained in a particular coal land area is determined, a “units of production” depletion rate can be calculated. This rate is then utilized to calculate depletion expense for each period mining is conducted on a particular coal lands area.

Any uncertainty surrounding the application of the depletion policy is directly related to the assumptions as to the number of recoverable tons contained in a particular coal land area. The amount of compensation paid for the coal lands is a set amount; however the “recoverable tons” contained in the coal land area are based on third party engineering estimates which can and often do change as the tons are mined. Any change in the number of “recoverable tons” contained in a coal land area will result in a change in the depletion rate and corresponding depletion expense. For the year ended December 31, 2005, we recorded $0.4 million of depletion expense. Assuming that “recoverable tons” are reduced by 10%, this would result in a decrease in pre-tax income of $0.04 million. This calculation would also be applied in the case of a coal land area containing more “recoverable tons” than the original estimate. This would result in increased pre-tax income.

Mine development costs are amortized using the units-of-production method, based on estimated recoverable interest in the same manner described above.

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

Asset Impairments

We follow SFAS No. 144, Accounting for the 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 the sum of projected cash flows is less than the carrying amount, impairment losses are recognized. In determining such impairment losses, discounted cash flows 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 closing obligations are accelerated and the mine closing 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. Our debt covenant ratios are based on “adjusted EBITDA” that excludes any non-cash items from the calculation, such as goodwill impairment. The minimum interest coverage ratio could be affected if the basis of goodwill (both book and tax) is impaired. A hypothetical impairment of $5.0 million to both the book and tax basis would result in additional annual federal taxes, over the amortization period of 15 years, of $0.1 million. We do not believe this would have a material impact on the ratio calculations.

Post-Retirement Medical Benefits

Some of our subsidiaries have long and short-term liabilities for post-retirement benefit cost obligations. Detailed information related to these liabilities is included in the notes to our consolidated financial statements included elsewhere in this report. Liabilities for post-retirement 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 post-retirement benefits. The discount rate assumption reflects the rates available on high quality fixed income debt instruments. The discount rate used to determine the net periodic benefit cost for post-retirement medical benefits was 5.50% for the year ended December 31, 2005. We make assumptions related to future trends for medical care costs in the estimates of retiree health care and work-related injury and illness obligations. The future health care cost trend rate represents the rate at which health care costs are expected to increase over the life of the plan. The health care cost trend rate assumptions are determined primarily based upon our historical rate of change in retiree health care costs. The post-retirement expense in the operating period ended December 31, 2005 was based on an assumed heath care inflationary rate of 10.0% in the operating period decreasing to 5.0% in 2015, which represents the ultimate health care cost trend rate for the remainder of the plan life. A one-percentage point increase in the assumed ultimate health care cost trend rate would increase the service and interest cost components of the post-retirement benefit expense for the year ended December 31, 2005 by $0.4 million and increase the accumulated post-retirement benefit obligation at December 31, 2005 by $1.6 million. A one-percentage point decrease in the assumed ultimate health care cost trend rate would decrease the service and interest cost components of the post-retirement benefit expense for the year ended December 31, 2005 by $0.3 million and decrease the accumulated post-retirement benefit obligation at December 31, 2005 by $1.2 million. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our requirement to satisfy these or additional obligations.

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 set of rules and regulations regarding compensation that is owed to an employee who is injured 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 actuarial studies.

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 a self- insurance program, in which we are a participant in a state run program, and an insurance policy. 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 actuarial studies. At December 31, 2005, we have recorded an accrual of $16.8 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 $6.3 million at December 31, 2005. Prior to the business combination with Anker, we did not have any liability under the Coal Act.

Income Taxes

We account for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes, 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. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, we take into account various factors including the expected level of future taxable income 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.

With regard to goodwill, a hypothetical write-off in the goodwill basis (both book and tax) of $5.0 million would result in additional annual federal taxes, as we would lose the tax deduction as a result of the write-off. The reduction of this tax asset, to be recognized over 15 years straight line under Section 197 of the Internal Revenue Code, would result in a decrease in taxable deductions of $0.3 million each year. This would increase annual taxable income by $0.3 million therefore creating an increase in income tax expense by the marginal effective federal income tax rate of 35%, or $0.1 million.

Goodwill

In our consolidated balance sheet as of December 31, 2005, we had $340.7 million in goodwill which represents the excess of costs over the fair value of the net assets acquired from Horizon, Anker and CoalQuest. The purchase price allocation for Anker and CoalQuest is preliminary and will not be finalized until all determinations of fair value are made, including third party appraisals. We tested for impairment of the Horizon assets as of October 31, 2005 and determined that impairment review supported the carrying value of goodwill. We will perform the next impairment test of the Horizon assets and our first impairment test for the net assets acquired from Anker and CoalQuest as of October 31, 2006. If the upcoming impairment review results in the application of impairment adjustments, we will be required to recognize these adjustments as operating expenses. As a result, we would have to write-off the impaired portion which could significantly reduce the value of our assets and reduce our net income for the year in which the write-off occurs.

Results Of Operations

Basis Of Presentation

Certain assets of Horizon and its subsidiaries were acquired by ICG, Inc. as of September 30, 2004. The remaining Horizon assets and all of its liabilities were transferred to A.T. Massey Coal Company, Inc. and Lexington Coal Company, LLC. Due to the change in ownership, and the resultant application of purchase accounting, the historical financial statements of Horizon and ICG included in this report have been prepared on different bases for the periods presented and are not comparable. In May 2002, Horizon, formerly operating as AEI Resources, was reorganized.

The following provides a description of the basis of presentation during all periods presented:

Successor—We were formed on March 31, 2005 as a wholly-owned subsidiary of ICG, Inc. in order to effect the corporate reorganization and the Anker and CoalQuest acquisitions all of which were consummated on November 18, 2005. Financial presentation represents the consolidated financial position of International Coal Group, Inc. as of December 31, 2005 and consolidated results of operations and cash flows for the period from

November 19 through December 31, 2005 combined with the consolidated results of operations and cash flows of ICG, Inc. for the period from January 1 through November 18, 2005, and the consolidated financial position of ICG, Inc. as of December 31, 2004 and its consolidated results of operations and cash flows for the period from May 13 (inception) through December 31, 2004. ICG, Inc. had no material assets, liabilities or results of operations until the acquisition of certain assets from Horizon as of September 30, 2004. ICG, Inc.’s consolidated financial position at December 31, 2004 and its consolidated results of operations for the period ended December 31, 2004 reflect the purchase price allocation partially based on appraisals prepared by independent valuation specialists and employee benefit valuations prepared by independent actuaries. The application of purchase accounting to the acquired assets of Horizon resulted in increases to coal inventories and the asset arising from recognition of asset retirement obligations. It also resulted in increases to plant and equipment, coal supply agreements and goodwill and a decrease in deferred taxes.

Predecessors—Represents the consolidated financial position and results of operations and cash flows for Horizon for the year ended December 31, 2003 and for the period January 1 through September 30, 2004. The Horizon accounts receivable, advance royalties, accounts payable and accrued expenses, intangibles, goodwill and other assets and long-term liabilities were estimates of management. An independent valuation specialist prepared appraisals of the Horizon property, plant and equipment, coal lands and accrued reclamation obligations while employee benefit valuations were prepared by independent actuaries; management allocated amounts of the purchase price to these assets and liabilities using these appraisals and valuations prepared by these specialists.

The financial statements for the predecessor periods of Horizon have been prepared on a “carve-out” basis to include our assets, liabilities and results of operations, that were previously included in the consolidated financial statements of Horizon. The financial statements for the Horizon predecessor periods include allocations of certain expenses, taxation charges, interest and cash balances relating to Horizon based on management’s estimates. The Horizon predecessor financial information is not necessarily indicative of our consolidated financial position, results of operations and cash flows if we had operated during the predecessor period presented.

Twelve Months Ended December 31, 2005 Compared to the Twelve Months Ended December 31, 2004 of International Coal Group, Inc. and Predecessor (“Combined”)

This discussion of the results of operations for the twelve months ended December 31, 2004 represents an addition of Horizon’s actual results for the nine months ended September 30, 2004 together with International Coal Group, Inc.’s actual results of operations for the three months ended December 31, 2004 (“Combined”).

Revenues

The following table reflects ICG’s revenues for the year ended December 31, 2005 and depicts ICG’s combined revenues for the year ended December 31, 2004 for the indicated categories:


	Year Ended December 31,				Actual
	Year Ended December 31,				Increase (Decrease)
	Combined 2004		2005		$			%
	(in thousands, except percentages and per ton data)
Coal revenues	$	477,444	$	619,038	$	141,594		30	%
Freight and handling revenues		4,580		8,601		4,021		88	%
Other revenues		27,468		20,074		(7,394	)	(27	)%

Total revenues	$	509,492	$	647,713	$	138,221		27	%

Tons sold		14,003		14,755		752		5	%

Coal revenue per ton	$	34.09	$	41.95	$	7.86		23	%

Coal revenues. Our coal revenue increased $141.6 million for the year ended December 31, 2005, or 30%, as compared to combined coal revenues for 2004. This increase was due to a $7.86 per ton increase in the average sales price of our coal and an increase in tons sold of 5% over the prior year. The increase in the average sales price of our coal was due to a general increase in coal prices during the year as well as a favorable renegotiation of coal sales contracts as a result of Horizon’s Chapter 11 bankruptcy. Our tons sold in 2005 increased by 0.8 million, or 5%, to 14.8 million, primarily due to the effect of our acquisitions of Anker and CoalQuest, which provided approximately 0.5 million additional tons compared to the prior year.

Freight and handling revenues. Freight and handling revenues increased $4.0 million to $8.6 million for year ended December 31, 2005 compared to 2004. The increase is due to an increase in shipments where we initially pay the freight and handling costs and are then reimbursed by the customer.

Other revenues. Other revenue decreased in 2005 by $7.4 million, or 27%, to $20.1 million, as compared to 2004. This decrease was due in a large part to our election to reclassify miscellaneous other revenue (such as royalty income, farming revenue, etc.) from the revenue section of the income statement to miscellaneous other income and expense for the period beginning October 1, 2004. Management believes that this reclassification improves the reporting of revenue by separating revenue pertaining primarily to mining activities from non-mining activities. The decrease was partially offset by other revenue derived from our highwall mining activities and shop services both performed by our subsidiary, ICG ADDCAR. Highwall mining and shop services increased to $20.1 million in 2005 compared to $19.8 million in 2004. In addition to these, other revenue for 2004 included $7.5 million that related primarily to non-mining activities.

Costs and expenses

The following table reflects ICG’s cost of operations for the year ended December 31, 2005 and depicts ICG’s combined cost of operations for the year ended December 31, 2004:


	Year Ended December 31,						Actual
	Year Ended December 31,						Increase (Decrease)
	Combined 2004			2005			$			%
	(in thousands, except percentages and per ton data)
Cost of coal sales and other revenues (exclusive of depreciation, depletion and amortization)	$	420,136		$	510,834		$	90,698		22	%
Cost of coal sales and other revenues as % of revenues		82	%		79	%
Freight and handling costs		4,580			8,601			4,021		88	%
Freight and handling costs as % of revenues		1	%		1	%
Depreciation, depletion and amortization		35,490			43,195			7,705		22	%
Depreciation, depletion and amortization as % of revenues		7	%		7	%
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization)		12,671			28,785			16,114		127	%
Selling, general and administrative expenses as % of revenues		3	%		4	%
Gain on sale of assets		(236	)		(502	)		(266	)	*
Writedowns and other items		10,018			—			(10,018	)	*

Total costs and expenses	$	482,659		$	590,913		$	108,254		22	%

Total costs and expenses as % of revenues		95	%		91	%
Total costs and expenses per ton sold⁽¹⁾	$	34.47		$	40.05		$	5.58		16	%

*	Not meaningful

(1)

Included in total costs and expenses per ton sold were costs for ICG ADDCAR, highwall mining activities and shop services of $2.08 and $1.74 in 2005 and 2004, respectively.

Cost of coal sales and other revenues. In 2005, our cost of coal sales increased $90.7 million, or 22.0%, to $510.8 million compared to $420.1 million in the prior year. The increase in cost of coal sales is primarily a result of increases in prices for steel-related mine supplies, increasing costs for roof control supplies of $1.7 million, increasing costs for conveyor belts and structure of $2.8 million, escalating diesel fuel costs, which were further heightened by Hurricane Katrina’s devastation in Mississippi and Louisiana of $12.0 million, increasing costs for repairs and maintenance of $6.3 million, increasing site preparation and maintenance of $1.1 million and increasing purchase coal costs of $5.6 million. Variable sales-related costs such as royalties and severance taxes increased $11.7 million due to increased sales realizations. Trucking costs increased $11.0 million due to both escalating diesel fuel costs and increased driver compensation costs. In addition, salary and hourly payroll expense increased $14.1 million due to a highly competitive labor market and the necessity to maintain a competitive compensation program. Approximately $22.3 million of the increase in the cost of coal sales was due to our acquisitions of Anker and CoalQuest. These increases were partially offset by decreases in equipment rental expense of $8.0 million due to the decision to purchase rather than lease to fulfill our equipment needs. The total costs and expenses per ton sold increased 16% from $34.47 per ton in 2004 to $40.05 per ton in 2005.

Total costs as percentage of revenues. Total costs and expenses as a percentage of coal revenues decreased to 91% in 2005 from 95% in 2004.

Freight and handling costs. Freight and handling costs increased $4.0 million to $8.6 million for the year ended December 31, 2005 compared to 2004. The increase is due to an increase in shipments where we initially pay the freight and handling costs and are then reimbursed by the customer.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased $7.7 million to $43.2 million in the 2005 compared to $35.5 million in 2004. Depreciation, depletion and amortization per ton increased from $2.53 per ton sold in 2004 to $2.93 per ton sold in 2005. The principal component of the increase was an increase in depreciation expense of $14.9 million in 2005 due to an increase in capital expenditures as well as shortened depreciable asset lives of the Horizon equipment purchased by ICG, Inc. in September 2004. The cost increase was offset by a decrease in depletion of $3.1 million as a result of a revaluation of mineral reserves in connection with the purchase of Horizon’s assets and amortization income on below market coal supply agreements of $1.0 million. Effective January 1, 2004, Horizon discontinued the accounting practice of capitalization of major repair costs in excess of $25,000 per occurrence. The decrease in amortization relating to this practice was $3.9 million.

Selling, general and administrative expenses. Selling, general and administrative expenses for 2005 were $28.8 million compared to $12.7 million for 2004. The increase of $16.1 million is primarily attributable to increases in stock compensation expense and related payroll taxes of $10.4 million, administrative fees of $1.6 million, miscellaneous bonuses of $1.3 million, and other costs of $2.8 million.

Gain on sale of assets. Gain on sale of assets increased $0.3 million from a gain of $0.2 million in 2004 to a gain of $0.5 million in 2005.

Writedowns and other items. The 2004 writedowns and other items were attributable to a loss of $13.3 million on the sale of coal lands, a gain of $7.7 million on a lease buyout, a loss on the retirement of highwall mining system of $6.2 million and other gains of $1.8 million. We did not record any writedowns in 2005.

Twelve Months Ended December 31, 2004 of International Coal Group, Inc. and Predecessor (“Combined”) compared to Twelve Months Ended December 31, 2003 of Horizon.

Revenues

The following table depicts International Coal Group, Inc.’s combined revenue for the twelve months ended December 31, 2004 and Horizon’s revenue for the twelve months ended December 31, 2003 for the indicated categories:


	Horizon		International Coal Group, Inc. (Combined)		Actual
	Twelve Months Ended December 31,				Actual
	Twelve Months Ended December 31,				Increase (Decrease)
	2003		2004		$			%
	(in thousands, except percentages and per ton data)
Coal revenues	$	441,291	$	477,444	$	36,153		8	%
Freight and handling revenues		8,008		4,580		(3,428	)	(43	%)
Other revenues		31,771		27,468		(4,303	)	(14	%)

Total revenues	$	481,070	$	509,492	$	28,422		6	%

Tons sold		16,656		14,003		(2,653	)	(16	%)
Coal revenue per ton	$	26.49	$	34.09	$	7.60		29	%

Coal revenues. International Coal Group, Inc.’s combined coal revenue increased $36.2 million for the year ended 2004, or 8%, to $477.4 million, as compared to Horizon’s for the same period in 2003. This increase was due to a $7.60 per ton (29%) increase in the average sales price, offset by a decrease in tons sold of 16% over the comparable period in the prior year. The increase in the average sales price of our coal was due to the general increase in coal prices during the period as well as the favorable renegotiations of coal sales contracts as a result of Horizon’s Chapter 11 bankruptcy.

Freight and handling revenues. International Coal Group, Inc.’s combined freight and handling revenues decreased $3.4 million for the twelve months ended December 31, 2004 compared to Horizon’s for the same period in 2003. The decrease is due to a decrease in shipments where we pay the freight and handling costs and are then reimbursed by the customer.

Other revenues. International Coal Group, Inc.’s combined other revenue decreased $4.3 million for the twelve months ended December 31, 2004 compared to Horizon’s for the same period in 2003. The decrease in other revenues was primarily a result of decreased participation in the Synfuel sales market in 2004. In addition, for the period beginning October 1, 2004, International Coal Group, Inc. elected to reclassify miscellaneous other revenue (such as royalty income, farming revenue, etc.) from the revenue section of the income statement to miscellaneous other income and expense. Management believes that this reclassification improves the reporting of revenue by separating revenue pertaining primarily to mining activities from non-mining activities. Other revenue for the last three months of 2004 included $0.5 million that related primarily to non-mining activities.

Costs and Expenses

The following table depicts International Coal Group, Inc.’s combined cost of operations for the twelve months ended December 31, 2004 and Horizon’s cost of operations for the twelve months ended December 31, 2003 for the indicated categories:


	Horizon			International Coal Group, Inc. (Combined)			Actual
	Twelve months ended December 31,						Actual
	Twelve months ended December 31,						Increase (Decrease)
	2003			2004			$			%
	(in thousands, except percentages and per ton data)
Cost of coal sales and other revenues (exclusive of depreciation, depletion and amortization)	$	400,652		$	420,136		$	19,484		5	%
Cost of coal sales and other revenues as % of revenues		83	%		82	%
Freight and handling costs		8,008			4,580			(3,428	)	(43	%)
Freight and handling costs as % of revenues		2	%		1	%
Depreciation, depletion and amortization		52,254			35,490			(16,764	)	(32	%)
Depreciation, depletion and amortization as % of revenues		11	%		7	%
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization)		23,350			12,671			(10,679	)	(46	%)
Selling, general and administrative expenses as % of revenues		5	%		3	%
Gain on sale of assets		(4,320	)		(236	)		4,084		(95	%)
Writedowns and other items		9,100			10,018			918		*

Total costs and expenses	$	489,044		$	482,659		$	(6,385	)	(1	%)

Total costs and expenses as % of revenues		102	%		95	%
Total costs and expenses per ton sold	$	29.36		$	34.47		$	5.11		17	%

*	Not meaningful

Cost of coal sales and other revenues. In the twelve month period ended December 31, 2004, International Coal Group, Inc.’s combined cost of coal sales increased $19.5 million, or 5% to $420.1 million compared to Horizon’s twelve month period ended December 31, 2003. The increase in cost of coal sales is primarily a result of increases in prices for steel-related mine supplies, increasing costs for roof control supplies of $4.3 million, escalating diesel fuel costs of $8.3 million, increasing costs for repairs and maintenance of $13.8 million. A portion of the increase ($7.6 million) in repair and maintenance expense results from a change in accounting practice adopted by Horizon on January 1, 2004. This change resulted in the elimination of capitalization of major repair items with a cost of $25,000 or more, the impact of this change equates to an increase in annual repair and maintenance cost. Variable sales-related costs such as royalties and severance taxes increased $6.8 million due to increased sales realizations. Trucking costs increased $5.6 million due to both escalating diesel fuel costs and increased driver compensation costs. In addition, salary and hourly payroll expense increased $8.0 million due to a highly competitive labor market and the necessity to maintain a competitive compensation program. Payroll taxes and other employee benefits increased $6.0 million due primarily to increases in workers’ compensation premiums, payroll taxes, employer 401(K) expense, and group insurance expense. These increases were partially offset by reduced pension fund costs. Purchased coal cost decreased $32.8 million between 2003 and 2004 due to reduced purchased coal volume. The total costs and expenses per ton sold increased 17% from $29.36 per ton for the twelve months ended December 31, 2003 to $34.47 per ton in the same period in 2004 (combined).

Total cost as percentage of revenues. Total costs and expenses as a percentage of coal revenues decreased to 95% for the twelve months ended December 31, 2004 compared to 102% in 2003.

Freight and handling costs. International Coal Group, Inc.’s combined freight and handling costs decreased $3.4 million for the year ended December 31, 2004 compared to Horizon’s for the same period in 2003. The decrease is due to a decrease in shipments where we pay the freight and handling costs and are then reimbursed by the customer.

Depreciation, depletion and amortization. International Coal Group, Inc.’s combined depreciation, depletion and amortization expense decreased $16.7 million to $35.5 million for the twelve months ended December 31, 2004 compared to Horizon’s for the same period in 2003. Depreciation, depletion and amortization decreased $0.61 per ton to $2.53 per ton for the twelve months ended December 31, 2004 as compared to the same period in 2003. The principal components of the decrease were a $9.6 million decrease in amortization related to an above market contract that expired at the end of 2003, a $2.2 million decrease in depletion due to lower depletion rates in the fourth quarter 2004 and higher production subject to depletion in 2003. Effective January 1, 2004, Horizon discontinued the accounting practice of capitalization of major repair costs in excess of $25,000 per occurrence. The amortization relating to this practice was $3.9 million for the twelve months ended December 31, 2004 as compared to $6.9 million for the same period in 2003. The remaining decrease for the combined twelve months ended December 31, 2004 as compared to the same period in 2003 was due primarily to assets being fully depreciated as well as reduced amortization of mine development costs.

Selling, general and administrative expenses. International Coal Group, Inc.’s combined selling, general and administrative expenses decreased $10.7 million to $12.7 for the twelve months ended December 31, 2004 compared to Horizon’s for the same period of 2003. The decrease of $10.7 million is primarily attributable to decreases in labor costs of $4.5 million, group insurance of $1.6 million, professional and consulting fees of $1.0 million, officers life insurance of $0.8 million, office rent of $0.7 million, taxes and licenses of $0.7 million and other insurance of $0.6 million.

Gain on sale of assets. International Coal Group, Inc.’s combined gain on sale of assets decreased $4.1 million, to $0.2 million for the twelve months ended December 31, 2004 compared to Horizon’s for the same period in 2003. The Horizon gain on sale of assets was due primarily to the sales of Cyrus Dock, Hannah Land and Blue Springs.

Writedowns and other items. International Coal Group, Inc.’s combined writedowns and other items increased $0.9 million, to $10.0 million in 2004 compared to Horizon’s for the same period in 2003. The 2004 writedowns and other items were attributable to a loss of $13.3 million on the sale of coal lands, a gain of $7.7 million on a lease buyout, a loss on the retirement of highwall mining system of $6.2 million and other gains of $1.8 million. The 2003 writedowns and other items were attributable to a writedown of assets of $6.4 million relating primarily to a closed operation (Blue Springs) and a writedown of parts inventory of $2.7 million.

Liquidity and Capital Resources

Our business is capital intensive and requires substantial capital expenditures for, among other things, purchasing, upgrading and maintaining equipment used in developing and mining our coal lands, as well as remaining in compliance with environmental laws and regulations. Our principal liquidity requirement is to finance our coal production, fund capital expenditures and to 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 flow from sales of our coal, other income and borrowings under our senior credit facility.

We believe the principal indicators of our liquidity are our cash position and remaining availability under our credit facility. As of December 31, 2005, our available liquidity was $38.0 million, including cash of $9.2 million and $28.8 million available under our credit facility. Total debt represented 6.9% of our total capitalization at December 31, 2005. Our total capitalization represents our current short- and long-term debt combined with our total stockholders’ equity.

We believe that a significant portion of our equipment needs to be upgraded in the near-term. Our capital expenditures were approximately $116.0 million for 2005 and we currently expect our capital expenditures will

be approximately $214.0 million in 2006, primarily for investments in new equipment and for mining development operations. We expect to fund these capital expenditures for the next year from our internal operations and borrowings under our credit facility. We intend to implement a new credit facility that will be sufficient to fund our expected capital expenditures through the peak spending years of 2006 and 2007. As a result of recent accidents in the mining industry, new legislation has been announced that will require additional capital expenditures to meet enhanced safety standards. We have included approximately $8.0 million for these increased amounts in our capital expenditure budget for 2006. As we take advantage of planned expansion opportunities from 2007 through 2009 principally as a result of the Anker and CoalQuest acquisitions, we expect to spend approximately $854.5 million on capital expenditures, which may require external financing. However, our capital expenditures may be different than currently anticipated depending upon the size and nature of new business opportunities and actual cash flows generated by our operations. In addition, as a result of infrastructure weaknesses and short term geologic issues at Anker, the transition period for implementation of various operational improvements has taken longer than originally anticipated. This extended transition resulted in decreased coal production and increased production costs in the third and fourth quarters of 2005. Recent performance has generally improved, indicating that operating issues are being appropriately addressed and suggesting that 2006 production rates and profit margins should be higher. In addition, as a result of the tragic explosion at the Sago mine, the federal and state investigations and related matters, our business has been negatively impacted. We do not expect that the temporary closure of the Sago mine will have any material negative effect on our long-term financial condition or results of operations. Operations at the Sago mine accounted for 0.4% of our consolidated revenues for 2005. However, we expect to incur increased operating and administrative expenses of approximately $15 million as a result of the accident and mine closure that will negatively impact 2006 earnings, approximately $10 million of which were incurred in the first quarter of 2006. We will continue to evaluate the financial impact of the Sago mine accident and may adjust the related reserve in our financial statements for the first quarter of 2006.

In our consolidated balance sheet as of December 31, 2005, we recorded $340.7 million in goodwill which represents the excess of costs over the fair value of the net assets acquired from Horizon, Anker and CoalQuest. The purchase price allocation for Anker and CoalQuest is preliminary and will not be finalized until all determinations of fair value are made, including third party appraisals. We tested for impairment of the Horizon assets as of October 31, 2005 and determined that impairment review supported the carrying value of goodwill. We will perform the next impairment test of the Horizon assets and for the net assets acquired from Anker and CoalQuest as of October 31, 2006. If the upcoming impairment review results in the application of impairment adjustments, we will be required to recognize these adjustments as operating expenses. As a result, we would have to write-off the impaired portion which could significantly reduce the value of our assets and reduce our net income for the year in which the write-off occurs. Our debt covenant ratios are based on “adjusted EBITDA” that excludes any non-cash items from the calculation, such as a goodwill write-off. The minimum interest coverage ratio could be affected if the basis of goodwill (both book and tax) is written off. A hypothetical write-off of $5.0 million to both the book and tax basis would result in additional annual federal taxes (as we would lose the tax deduction as a result of the write-off), over the amortization period of 15 years, of $0.1 million. This would not have a material impact on the ratio calculations.

Profitability in the third and fourth quarters of 2005 was negatively impacted by several factors, including non-cash costs associated with restricted stock issued to senior management, short term quality issues at the Knott County operations, a tight labor market in the Hazard area and permit delays related to the Hazard operations. ICG was adversely impacted by margin compressions due to cost increases for various commodities and services influenced by the recent price acceleration of crude oil and natural gas — a trend that was greatly exacerbated by the Gulf hurricanes. Costs of diesel fuel, explosives (ANFO), tires and coal trucking have all escalated as a direct result of supply chain problems related to the Gulf hurricanes. We presently expect that the margin compression experienced in the third and fourth quarters of 2005 will be substantially mitigated in late 2006 as these recent cost pressures abate and revenues are favorably impacted by sales contract price reopeners and general market improvement.

In addition, we have brokered coal contracts that will expire at the end of 2006. These contracts were signed during a period of oversupply in the coal industry and contain pricing that, while acceptable to the sellers at that

time, is significantly below today’s market levels and, management believes, will not be able to be renegotiated or replaced in today’s market. The loss of these contracts will have a significant impact on our earnings after 2006. For the year ended December 31, 2005, these contracts provided $33.4 million in pre-tax net income. However, the loss of this revenue is expected to be mitigated somewhat as additional owned and controlled mining complexes are brought into production in 2007.

Cash Flows

Net cash provided by operating activities was $77.3 million for the year ended December 31, 2005, an increase of $19.0 million from the same period in 2004. This increase is attributable to an increase in net income of $151.4 million after adjustment for non-cash charges. These increases were partially offset by the effects of a decrease in net operating assets and liabilities of $122.4 million and writedowns of $17.7 million. In the same period in 2004, there was a gain on a lease buyout option of $7.7 million related to our predecessor’s bankruptcy filing.

Net income increased in 2005 primarily as a result of higher realization due to the strengthening of the coal market during the period. The increase in realization was partially offset by higher operating costs most notably diesel fuel, trucking costs due to increased diesel costs and increased driver compensation and labor costs due to the highly competitive labor market. Higher interest expense for the predecessor company also impacted net income in 2004.

For the year ended December 31, 2005, net cash was used in investing activities of $104.7 million compared to cash used in investing activities of $325.7 million for the twelve months ended December 31, 2004. Cash used in investing activities for 2005 was $108.2 million in order to begin replacement of our aged mining equipment fleet compared to $12.2 million in 2004. Cash was returned from deposits of restricted cash used for collateral for reclamation and royalty bonds of $3.4 million in 2005 compared to cash deposited of $1.8 million in the same period of 2004. Proceeds of equipment sales were $0.6 million in 2005 compared to $4.1 million in the same period of 2004 and proceeds from lease buyouts of $7.7 million in 2004 had a positive impact on investing in 2004. Investment activities also includes cash paid (net of cash acquired) of $0.5 million related to the acquisition of Anker and CoalQuest in 2005 through the issuance of 24,090,909 million shares of common stock. In 2004, Horizon’s assets were purchased for $323.6 million.

Net cash provided by financing activities of $12.6 million for the year ended December 31, 2005 was primarily due to $210.5 million of net proceeds from the issuance and sale of 21 million shares of common stock in our public offering in December 2005. The net proceeds of the public offering were used to repay $188.7 million of term loan debt and $21.2 million of borrowings under our revolving credit facility. Prior to the public offering, we made term loan payments of $1.7 million and borrowed an additional $35.0 million to consummate the mergers with Anker and CoalQuest. Also impacting our financing activities was financing costs of $0.4 million, capital lease payments of $0.5 million and proceeds of $0.2 million related to issuance of common stock to employees. In addition, we borrowed $42.5 million on our revolving credit facility to satisfy short-term operational needs and made net repayments of $55.5 million and $7.5 million on our long-term and short-term debt, respectively. In 2004, cash provided in financing activities of $290.5 million primarily due to $150.2 million in capital provided by the original investors as well as borrowings under a $175 million term loan. We also incurred capital lease repayments of $0.8 million in 2004. Other changes in financing activities in 2004 resulted in a use of funds of $35.6 million primarily related to the repayment of Horizon’s DIP facility.

Net cash provided by operating activities was $58.3 million for the combined twelve months ended December 31, 2004, an increase of $38.3 million from the same period in 2003. This increase is attributable to an

increase of $73.3 million in net income primarily due to a strengthening coal market during the period. This increase was offset by a decrease in accrued expenses of $66.2 million primarily related to accrued interest charges in 2003. Other changes in operating activities resulted in a source of $31.2 million.

For the combined twelve months ended December 31, 2004 net cash used in investing activities was $325.7 million compared to a use of cash of $3.9 million for the same period in 2003. Cash used in 2004 was primarily related to the acquisition of the assets of Horizon.

Net cash provided by financing activities was $290.5 million for the combined twelve months ended December 31, 2004 as compared to a use of $15.5 million for the comparable period in 2003. The increase in cash provided by financing activities in 2004 was primarily due to $150.2 million in capital provided by the original investors, as well as the funding of a $175 million term loan. Other changes in financing activities resulted in a use of funds of $19.2 million primarily related to the repayment of Horizon’s DIP facility.

Credit Facility and Long-Term Debt Obligations

As of December 31, 2005, our total long-term indebtedness, including capital lease obligations, consisted of the following:


	As of December 31, 2005
	(in thousands)
Term loan due 2010	$	19,563
Revolving credit facility		21,280
Capital lease obligations		166
Other		4,453

Total long-term debt	$	45,462
Less current portion		1,646

Long-term debt, net of current portion	$	43,816

On November 5, 2004, we entered into an amended and restated credit facility with a group of lending institutions, for which UBS Securities LLC serves as Arranger, Bookmanager and Syndication Agent and subsequently have entered into four amendments. As amended, the credit facility provides for a term loan of $210.0 million and a revolving credit facility of up to $210.0 million with a letter of credit sub-limit of up to $75.0 million. As of December 31, 2005, we had $19.6 million term loan principal amount outstanding and letters of credit totaling $59.9 million and borrowings of $21.3 million outstanding under the revolving credit facility, leaving $28.8 million available for borrowing on the revolving credit facility. The interest rate on both the term loan and revolving credit facility bear interest at a variable rate based upon either the prime rate or a London Interbank Offered Rate (LIBOR), in each case plus a spread that is dependent on our leverage ratio. The interest rate applicable to our borrowings under the term loan was 7.13% as of December 31, 2005. The principal balance of the term loan is due on October 1, 2010 and the revolving credit facility expires on October 1, 2009. We and each of our subsidiaries have guaranteed the obligations under the credit facility which are secured by a lien on all of our assets of ICG and those of our subsidiaries. We must pay an annual commitment fee up to a maximum of ¹/2 of 1% of the unused portion of the commitment under the revolving credit facility. Our commitment fee expense in 2005 was $0.3 million. We also must pay an annual letter of credit participation fee up to 2¹/2% and a fronting fee of 0.2% on the average daily outstanding letter of credit balance. Our letter of credit fees were $1.43 million in 2005. We were in compliance with our debt covenants under the credit facility as of December 31, 2005.

The credit facility imposes certain restrictions on us, including restrictions on our ability to: incur debt, grant liens, enter into agreements with negative pledge clauses, provide guarantees in respect of obligations of any

other person, pay dividends and make other distributions, make loans, investments, advances and acquisitions, sell our assets, make redemptions and repurchases of capital stock, make capital expenditures, prepay, redeem or repurchase debt, liquidate or dissolve; engage in mergers or consolidations, engage in affiliate transactions, change our business, change our fiscal year, amend certain debt and other material agreements, issue and sell capital stock of subsidiaries, engage in sale and leaseback transactions, and restrict distributions from subsidiaries. In addition, the credit facility provides that we must comply with certain covenants, including certain interest coverage ratios.

Our credit facility, as amended, contains customary affirmative and negative covenants for senior credit facilities of this type, including, but not limited to, limitations on the incurrence of indebtedness, asset dispositions, acquisitions, investments, dividends and other restricted payments, liens and transactions with affiliates. Our credit facility, as amended, also currently contains the following financial covenants:

•

a maximum leverage ratio (consolidated indebtedness to consolidated EBITDA) set at 2.50 to 1.00 for the 2006 fiscal year and decreasing to 2.25 to 1.00 from January 1, 2007 through the final maturity date of the credit facility;

•

a minimum interest coverage ratio (consolidated EBITDA to consolidated interest expense) set at 4.00 to 1.00 for each of the four consecutive quarters then last ended; and

•

a limit on capital expenditures for the 2006 fiscal year of $180.0 million, for the 2007 fiscal year of $255.0 million, for the 2008 fiscal year of $125.0 million, for the 2009 fiscal year of $75.0 million and from January 1, 2010 through the final maturity date of the credit facility of $85.0 million.

At December 31, 2005, we had $59.9 million in letters of credit outstanding, all of which are supported by our current $75.0 million letter of credit sub-limit contained in our revolving credit facility. We paid $0.3 million in interest on our credit facility on October 10, 2004, the first scheduled interest payment date on the credit facility and additional interest payments of $12.8 million in 2005. We also made term loan amortization payments of $1.8 million in 2005. On December 12, 2005, we repaid $188.7 million of our term loan debt and $21.2 million of borrowings under our revolving credit facility with the net proceeds from the public offering of our common stock.

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 long-term liabilities relating to mine reclamation, end-of-mine closure costs, below market coal supply agreements, and “black lung” costs, and some of our operating and management-services 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. Based upon our current operations, the historical results of our predecessors, as well as those of Anker and CoalQuest, we believe that cash flow from operations, together with other available sources of funds, including additional borrowings under our credit facility, will be adequate for at least the next 12 months for making required payments of principal and interest on our indebtedness and for funding anticipated capital expenditures and working capital requirements. 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.

Contractual Obligations

The following is a summary of our significant future contractual obligations by year as of December 31, 2005:


	Payments due by period
	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
	(in thousands)
Long-term debt obligations and Capital leases	$	1,646	$	2,454	$	41,362	$	—	$	45,462
Operating leases		8,983		3,112		—		—		12,095
Coal purchase obligation⁽¹⁾		116,623		61,518		37,685		—		215,826
Advisory Services agreement⁽²⁾		2,000		4,000		4,000		1,500		11,500
Minimum royalties		3,891		10,564		10,329		23,842		48,626

Total⁽³⁾	$	133,143	$	81,648	$	93,376	$	25,342	$	333,509

(1)

Reflects estimates of obligations.

(2)

See “Certain relationships and related party transactions.”

(3)

Our contractual obligations exclude interest amounts due for the years shown above because it is at a variable rate. We are also a party to an employment agreement with each of our President and Chief Executive Officer and our Senior Vice President, General Counsel and Secretary.

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, federal and state workers’ compensation, 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 for us than the alternative of 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. ICG currently has a $75.0 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 us. 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, 2005, we had outstanding surety bonds with third parties for post-mining reclamation totaling $90.3 million plus $2.0 million for miscellaneous purposes. We maintained letters of credit as of December 31, 2005 totaling $59.9 million to secure reclamation surety bonds and other obligations, including $10.0 million related to Lexington Coal Company. These letters of credit are issued under our current $75.0 million bonding facility.

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 twelve months ended December 31, 2005, 2004 and 2003.

Recent Accounting Pronouncements

In January 2005, the FASB issued SFAS No. 123(R), Share Based Payments. SFAS No. 123(R) supersedes APB Opinion 25, Accounting for Stock Issued to Employees. This statement establishes standards of accounting

for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No. 123(R) is effective as of the beginning of the first fiscal year beginning after June 15, 2005.

The Company will adopt the provisions of SFAS No. 123(R) during the period beginning January 1, 2006, using the modified prospective method. Initial adoptions of SFAS No. 123(R) will not have a material impact on the Company’s consolidated financial position or results of operations. The total impact of adopting SFAS No. 123(R) on the Company in future periods cannot be predicted at this time because it will depend on the level of equity-based compensation granted in the future. Compensation expense for the year ending December 31, 2006, related to equity awards outstanding as of December 31, 2005, is estimated to be $1,944, net of income taxes.

Emerging Issues Task Force (“EITF”) Issue 04-02 addresses the issue of whether mineral rights are tangible or intangible assets. FASB SFAS No. 141, Business Combinations, requires the acquirer in a business combination to allocate the cost of the acquisition to the acquired assets and liabilities. At the March 17–18, 2004 meeting, the EITF reached a consensus that mineral rights (defined as the legal right to explore, extract and retain at least a portion of the benefits from mineral deposits) are tangible assets. As a result of the EITF’s consensus, the FASB issued FASB Staff Position (“FSP”) Nos. SFAS No. 141-a and SFAS No. 142-a, Interaction of FASB Statements No. 141, Business Combinations and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-02, Whether Mineral Rights Are Tangible or Intangible Assets, which amend SFAS Nos. 141 and 142 and results in the classification of mineral rights as tangible assets. We have recorded mineral rights as tangible assets.

On March 30, 2005, the FASB ratified the consensus reached by the EITF on Issue 04-6, Accounting for Stripping Costs in the Mining Industry. This issue applies to stripping costs incurred in the production phase of a mine for the removal of overburden or waste materials for the purpose of obtaining access to coal that will be extracted. Under the new rule, stripping costs incurred during the production phase of the mine are variable production costs that are included in the cost of inventory produced and extracted during the period the stripping costs are incurred. Historically, the coal industry has considered coal uncovered at a surface mining operation but not yet extracted to be coal inventory (pit inventory). This represents a change in accounting principle. The guidance in this EITF consensus is effective for fiscal years beginning after December 15, 2005 for which the cumulative effect of adoption should be recognized as an adjustment to the beginning balance of retained earnings during the period. Adoption of this EITF consensus is expected to result in an approximate $1.0 million decrease in our inventory and retained earnings during the first quarter of 2006.

In March 2005, the FASB issued FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143, Accounting for Asset Retirement Obligations. FIN 47 requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. This interpretation is effective for fiscal years ending after December 15, 2005. Adoption of this interpretation did not have a material impact on our consolidated financial position or results of operations.

In November 2004, the FASB issued SFAS No. 151, Inventory Costs, an amendment of ARB No. 43, Chapter 4. This statement amends the guidance in ARB No. 43, Chapter 4, Inventory Pricing, to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). This statement requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, this statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We do not expect this statement will have a material impact on our consolidated financial position or results of operations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity price risk. We manage our commodity price risk for coal sales through the use of long-term coal supply agreements rather than through the use of derivative instruments. As of December 31, 2005, we had sales commitments for 82% of our planned 2006 production. Some of the products used in our mining activities, such as diesel fuel, are subject to price volatility. Through our suppliers, we utilize forward contracts to manage the exposure related to this volatility. A hypothetical increase of $0.10 per gallon for diesel fuel would reduce pre-tax income for the year ended December 31, 2005 by $2.1 million. A hypothetical increase of 10% in steel prices would result in an increase in roof support costs. This would reduce pre-tax income for the year ended December 31, 2005 by $1.2 million.

Interest rate risk. Historically, we have had exposure to changes in interest rates on a portion of our existing level of indebtedness. This exposure had been hedged at 50% of the debt for a two year period using pay-fixed, receive-variable interest rate cap. As a result of the transactions, we anticipate exposure to changes in interest rates on a portion of our new level of indebtedness. A hypothetical increase or decrease in interest rates by 1% would have changed quarterly interest expense on our term loan facility by $0.05 million for the year ended December 31, 2005. We expect to use interest rate swaps or caps to manage this risk.

Market price risk. We are exposed to market price risk in the normal course of mining and selling coal. As of December 31, 2005, 82% of 2006 planned production committed for sale leaving approximately 18% uncommitted for sale. A hypothetical decrease of $1.00 per ton in the market price for coal would reduce pre-tax income by $3.8 million for 2005.

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 ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. As of the end of the period covered by this Report, an evaluation of the effectiveness of our disclosure controls and procedures was carried out under the supervision and with the participation of our management, including the Chief Executive Officer and Principal Financial Officer. Based on that evaluation, the Chief Executive Officer and Principal Financial Officer have concluded that our disclosure controls and procedures are effective.

There have been no changes in our internal control over financial reporting during the fourth quarter of fiscal 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

Part III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY

The information requested by Items 401, 405 and 406 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 26, 2006 (the “Definitive Proxy Statement”).

ITEM 11. EXECUTIVE COMPENSATION

The information requested by Item 402 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 57 of this Annual Report for information required by Item 201(d) of Regulation S-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The information requested by Item 404 of Regulation S-K is incorporated herein by reference to the Definitive Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICE

The information 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 are contained in the Definitive Proxy Statement and are incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)	Financial Statements:

(1)	The following financial statements are filed as part of this Annual Report 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, 2005 and December 31, 2004		F-2
Consolidated Statements of Operations for the year ended December 31, 2005 and for the period from May 13, 2004 (inception) to December 31, 2004		F-3
Consolidated Statements of Stockholders’ Equity for the year ended December 31, 2005 and for the period from May 13, 2004 (inception) to December 31, 2004		F-4
Consolidated Statements of Cash Flows for the year ended December 31, 2005 and for the period from May 13, 2004 (inception) to December 31, 2004		F-5
Notes to Consolidated Financial Statements for the for the year ended December 31, 2005 and for the period from May 13, 2004 (inception) to December 31, 2004		F-6

Horizon NR, LLC and Certain Subsidiaries (Predecessor to International Coal Group, Inc.)
Report of Independent Registered Public Accounting Firm		F-33
Combined Statements of Operations for the period January 1, 2004 to September 30, 2004 and the year ended December 31, 2003		F-35
Combined Statements of Members’ Deficit for the period January 1, 2004 to September 30, 2004 and the year ended December 31, 2003		F-36
Combined Statements of Cash Flows for the period January 1, 2004 to September 30, 2004 and the year ended December 31, 2003		F-37
Notes to Combined Financial Statements as of September 30, 2004, for the period January 1, 2004 to September 30, 2004 and the year ended December 31, 2003		F-38

(b)

Exhibits.

(i)

See the Exhibit Index.

(c)	Financial Statement Schedules.


		Page
(i)	Reports of Independent Registered Public Accounting Firm	F-51
(ii)	Schedule II – Valuation and Qualifying Accounts	F-53

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.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

International Coal Group, Inc.

We have audited the accompanying consolidated balance sheets of International Coal Group, Inc. and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2005 and the period from May 13, 2004 (inception) to December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, 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, 2005 and 2004, and the results of its operations and its cash flows for the year ended December 31, 2005 and the period from May 13, 2004 (inception) through December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Cincinnati, Ohio

March 30, 2006

F-1

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2005 and 2004

(Dollars in thousands, except per share data)


	December 31, 2005			December 31, 2004
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9,187		$	23,967
Accounts receivable		64,841			40,417
Inventories, net		20,667			13,943
Deferred income taxes		4,923			2,188
Prepaid insurance		7,055			7,142
Prepaid expenses and other		14,454			5,899

Total current assets		121,127			93,556
PROPERTY, PLANT AND EQUIPMENT, net		571,484			157,136
DEBT ISSUANCE COSTS, net		6,523			7,865
ADVANCE ROYALTIES		9,344			5,424
GOODWILL		340,736			183,946
DEFERRED INCOME TAXES, NON-CURRENT		—			7,741
OTHER NON-CURRENT ASSETS		6,949			4,307

Total assets	$	1,056,163		$	459,975

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	52,230		$	21,250
Short-term debt		4,113			3,787
Current portion of long-term debt and capital leases		1,646			2,235
Current portion of reclamation and mine closure costs		4,697			2,682
Current portion of employee benefits		1,524			—
Accrued income tax		—			2,232
Accrued expenses and other		43,444			33,854

Total current liabilities		107,654			66,040

LONG-TERM DEBT AND CAPITAL LEASES		43,816			173,446
RECLAMATION AND MINE CLOSURE COSTS		79,655			40,616
LONG-TERM EMPLOYEE BENEFITS		33,297			18,007
DEFERRED INCOME TAXES		43,198			—
BELOW-MARKET COAL SUPPLY AGREEMENTS		72,376			—
OTHER NON-CURRENT LIABILITIES		9,257			7,466

Total liabilities		389,253			305,575

MINORITY INTERESTS		1,038			—


COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY:
Preferred stock-par value $0.01 and $0.0001, respectively,
200,000,000 shares authorized, none issued
Common stock-par value $0.01 and $0.0001, respectively,
2,000,000,000 and 1,800,000,000 shares authorized, 152,321,908 and 106,605,999 shares issued and outstanding, respectively		1,523			11
Additional paid-in capital		632,897			150,140
Unearned compensation—restricted stock		(4,622	)		—
Retained earnings		36,074			4,249

Total stockholders’ equity		665,872			154,400

Total liabilities and stockholders’ equity	$	1,056,163		$	459,975

See notes to consolidated financial statements.

F-2

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

Year ended December 31, 2005

and the period May 13, 2004 (inception) to December 31, 2004

(Dollars in thousands, except per share data)


	Year Ended December 31, 2005			Period from May 13, 2004 (inception) to December 31, 2004
REVENUES:
Coal sales revenues	$	619,038		$	130,463
Freight and handling revenues		8,601			880
Other revenues		20,074			4,766

Total revenues		647,713			136,109

COSTS AND EXPENSES:
Freight and handling costs		8,601			880
Cost of coal sales and other revenues (exclusive of items shown separately below)		510,834			113,707
Depreciation, depletion and amortization		43,195			7,943
Selling, general and administrative (exclusive of depreciation and amortization shown separately above)		28,785			4,194
Gain on sale of assets		(502	)		(10	)

Total costs and expenses		590,913			126,714

Income from operations		56,800			9,395

INTEREST AND OTHER INCOME (EXPENSE):
Interest expense, net		(14,394	)		(3,453	)
Other, net		6,080			898

Total interest and other income (expense)		(8,314	)		(2,555	)

Income before income tax expense		48,486			6,840
INCOME TAX EXPENSE		(16,676	)		(2,591	)
MINORITY INTEREST		15			—

Net income	$	31,825		$	4,249

Earnings per share:
Basic	$	0.29		$	0.04
Diluted	$	0.29		$	0.04
Weighted average common shares outstanding:
Basic		111,120,211			106,605,999
Diluted		111,161,287			106,605,999

See notes to consolidated financial statements.

F-3

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Year ended December 31, 2005

and period May 13, 2004 (inception) to December 31, 2004

(Dollars in thousands)


	Common Stock			Additional Paid-in Capital			Unearned Compensation- restricted stock			Retained Earnings		Total
	Shares	Amount		Additional Paid-in Capital			Unearned Compensation- restricted stock			Retained Earnings		Total
Capital Contribution	106,605,999	$	11	$	150,140		$	—		$	—	$	150,151
Net income	—		—		—			—			4,249		4,249

Balance—December 31, 2004	106,605,999		11		150,140			—			4,249		154,400
Net income	—		—		—			—			31,825		31,825
Issuance of restricted stock and stock awards	600,000		—		8,090			(8,090	)		—		—
Issuance of shares of common stock pursuant to compensation agreement	25,000		—		372			—			—		372
Compensation expense-restricted stock and stock awards	—		—		—			3,468			—		3,468
Compensation expense-stock options	—		—		288			—			—		288
Corporate reorganization (Note 1)	—		1,061		(1,061	)		—			—		—
Issuance of shares in Anker/CoalQuest acquisition	24,090,909		241		264,759			—			—		265,000
Issuance of shares of common stock in connection with public offering	21,000,000		210		210,309			—			—		210,519

Balance—December 31, 2005	152,321,908	$	1,523	$	632,897		$	(4,622	)	$	36,074	$	665,872

See notes to consolidated financial statements.

F-4

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31, 2005

and period May 13, 2004 (inception) TO December 31, 2004

(Dollars in thousands)


	Year Ended December 31, 2005			Period from May 13, 2004 (inception) to December 31, 2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	31,825		$	4,249
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		43,195			7,943
Amortization of finance costs included in interest expense		1,785			266
Minority interest		(15	)		—
Compensation expense on restricted stock and options		3,928			—
Gain on sale of assets		(502	)		(10	)
Deferred income taxes		5,411			359
Changes in Assets and Liabilities:
Receivables		(11,904	)		19,713
Inventories		(1,470	)		6,140
Prepaid expenses		4,210			(2,030	)
Other assets		50			(1,306	)
Accounts payable		7,456			(3,815	)
Accrued expenses		(4,802	)		(1,527	)
Reclamation and mine closure costs		(1,178	)		(591	)
Other liabilities		(670	)		873

Net cash from operating activities		77,319			30,264

CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of assets		576			10
Additions to property, plant and equipment and mine development		(108,231	)		(5,583	)
Cash paid related to acquisitions, net		(458	)		(323,593	)
Withdrawals (deposits) of restricted cash		3,400			(2	)

Net cash from investing activities		(104,713	)		(329,168	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Capital contribution		—			150,151
Repayments on short-term debt		(7,461	)		(2,969	)
Borrowings on long-term debt		77,500			175,977
Repayments on long-term debt		(267,701	)		(235	)
Deferred finance costs		(443	)		(53	)
Proceeds from issuance of common stock		200			—
Proceeds from public offering, net		210,519			—

Net cash from financing activities		12,614			322,871

Net change in cash and cash equivalents		(14,780	)		23,967
Cash and cash equivalents, beginning of period		23,967			—

Cash and cash equivalents, end of period	$	9,187		$	23,967

Supplemental information:
Cash paid for interest (net of amount capitalized)	$	18,122		$	536

Cash paid for income taxes	$	17,277		$	—

Supplemental disclosure of non-cash items:
Acquisition of Horizon Natural Resources included in accrued expenses	$	—		$	2,191

Acquisition of Anker and CoalQuest through issuance of common stock	$	265,000		$	—

Purchases of property, plant and equipment through accounts payable	$	7,779		$	—

Issuance of restricted stock and stock awards	$	8,090		$	—

Corporate reorganization	$	1,061		$	—

See notes to consolidated financial statements.

F-5

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

1. ORGANIZATION

Entity Matters—ICG, Inc. was formed on May 13, 2004 by WL Ross & Co., LLC, (“WLR”), and other investors to acquire and operate competitive coal mining facilities. On September 30, 2004, ICG, Inc. acquired certain properties and assets, and assumed certain liabilities, of Horizon Natural Resources Company (“Horizon”) through Section 363 asset sales of the United States Bankruptcy Court (see Note 3). Prior to September 30, 2004, ICG, Inc. was raising capital and did not commence operations until October 1, 2004; and, as such, ICG, Inc. did not have any material assets, liabilities or results of operations.

International Coal Group, Inc. was formed in March 2005 as wholly-owned subsidiary of ICG, Inc. in order to effect a corporate reorganization. On November 18, 2005, the reorganization was completed. Prior to this reorganization, ICG, Inc. was the top-tier holding company. Upon completion of the reorganization, International Coal Group, Inc. became the new top-tier parent holding company. In the corporate reorganization, the stockholders of ICG, Inc. received one share of International Coal Group, Inc. common stock for each share of ICG, Inc. common stock. International Coal Group, Inc. and Subsidiaries are referred to as “ICG” or the “Company.”

In addition, the Company also completed acquisitions of Anker Coal Group, Inc. and CoalQuest Development, LLC, as of November 18, 2005 (see Note 3).

The accompanying consolidated financial statements include the results of operations of the properties and assets acquired since September 30, 2004. The Company has three reportable business segments: Central Appalachian, comprised of both surface and underground mines, Northern Appalachian, comprised of both surface and underground mines and Illinois Basin comprised of one underground mine located in the Illinois basin.

Public Offering of Common Stock—On December 12, 2005, the Company completed a public offering (“Offering”) of 21,000,000 shares of common stock. Net proceeds from the Offering, after deducting underwriting discounts and offering expenses, were approximately $210,519. The Company used the proceeds to repay $188,688 of term loan debt, $21,220 of borrowings under the revolving credit facility and $611 for other expenses.

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 minority ownership, by contract, lease or otherwise. In certain cases, ICG subsidiaries (i.e., Variable Interest Entities (“VIEs”) may also be consolidated based on a risks and rewards approach as required by the Financial Accounting Standards Board (FASB) revised Interpretation No. 46 (“FIN 46(R)”). See Note 13 to the consolidated financial statements for further discussion regarding the consolidation of VIEs. The consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States of America. Significant intercompany transactions and balances have been eliminated.

Cash and Cash Equivalents—The Company considers all highly liquid debt instruments with maturities of three months or less at the time of purchase to be cash equivalents.

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

F-6

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

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 collectibility and establishes or adjusts the allowance as necessary using the specific identification method. No allowance for doubtful accounts was considered necessary at December 31, 2005 and 2004.

Inventories—Inventories are stated at lower of average cost or market. Components of inventories consist of coal and parts and supplies, net of an allowance for obsolescence (see Note 4). Coal inventories represent coal contained in stockpiles and exposed in the pit, including those tons that have been uncovered or mined and hauled to our load out facilities but not yet shipped to customers. These inventories are stated on 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.

Derivative Financial Instruments—The Company’s hedging policies permit the use of interest rate swaps and caps to manage interest rate risk. The Company does not use derivative financial instruments for trading or speculative purposes. Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, establishes accounting and reporting standards for derivative instruments and hedging activities. To qualify for hedge accounting under SFAS No. 133, the effectiveness of each hedging relationship is assessed both at hedge inception and at each reporting period thereafter. Also, at the end of each reporting period, ineffectiveness in the hedging relationships is measured as the difference between the change in fair value of the derivative instruments and the change in fair value of either the hedged items (fair value hedges) or expected cash flows (cash flow hedges). Ineffectiveness, if any, is recorded in interest expense.

During 2004, the Company entered into an Interest Rate Cap Agreement (“Cap Agreement”), expiring December 15, 2006, and paid $184 to hedge its interest risk on $88,000 notional amount of term debt. The Cap Agreement is designed to offset the impact of changes in the LIBOR interest rate above the cap rate of 4.5%. However, the interest rate cap was determined to be ineffective under SFAS No. 133; therefore, changes in its fair value were recorded in income. The Cap Agreement, included in other current assets in the Company’s consolidated balance sheets, was adjusted to its fair value of approximately $230 and $164 as of December 31, 2005 and 2004, respectively. The adjustment resulted in a gain of approximately $66 in the year ended December 31, 2005 and loss of approximately $20 in the period ended December 31, 2004.

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. Unamortized deferred royalty costs are expensed when mining has ceased or a decision is made not to mine on such property. The Company has recorded advance royalties of $14,662 and $7,022 ($5,318 and $1,598 included in prepaid expense and other and $9,344 and $5,424 included in non-current assets) at December 31, 2005 and 2004, respectively.

Coal Supply Agreements—Purchase price allocated to coal supply agreements (sales contracts) are capitalized and amortized on the basis of coal to be shipped over the term of the contract. Value is allocated to

F-7

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

coal supply agreements based on discounted cash flows attributable to the difference between the above or below-market contract price and the then prevailing market price. The net book value of the Company’s above-market coal supply agreement was $4,051 at December 31, 2005. This amount is recorded in other assets in the accompanying consolidated balance sheets. The net book value of the below-market coal supply agreements was $72,376 at December 31, 2005. Amortization expense on all above-market coal supply agreements was $139 in 2005. Amortization income on the below-market coal supply agreements was $1,042 in 2005. There were no above or below-market coal supply agreements at December 31, 2004, nor any amortization for the period ended December 31, 2004. Based on expected shipments related to these contracts, the Company expects to record annual amortization expense on the above-market coal supply agreements and annual amortization income on the below-market coal supply agreements in each of the next five years as reflected in the table below.


	Above-market contract		Below-market contracts
2006	$	368	$	28,711
2007		368		15,879
2008		368		2,830
2009		368		1,929
2010		368		3,699

Property, Plant and Equipment—Property, plant and equipment, including coal lands and mine development costs are recorded at cost, which includes construction overhead and capitalized interest. Interest cost applicable to major asset additions are capitalized during the construction period, including $293 for the year ended December 31, 2005. Expenditures for major renewals and betterments are capitalized while expenditures for maintenance and repairs are expensed as incurred. Coal land costs are depleted using the units-of-production method, based on estimated recoverable interest. Mine development costs are amortized using the units-of-production method, based on estimated recoverable interest. Other property, plant and equipment is depreciated using the straight-line method with estimated useful lives substantially as follows:


		Years
Buildings		10 to 45
Mining and other equipment and related facilities		1 to 20
Land improvements		15
Transportation equipment		2 to 7
Furniture and fixtures		3 to 10

Depreciation, depletion and amortization expense, net of amortization income from coal supply agreements, for the year ended December 31, 2005 and for the period May 13, 2004 to December 31, 2004 was $43,195 and $7,943, respectively.

Goodwill—Goodwill represents the excess of costs over fair value of net assets of businesses acquired. Pursuant to SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”), goodwill and intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not amortized, but instead must be tested for impairment at least annually in accordance with the provisions of SFAS No. 142. The goodwill impairment test has two steps. The first identifies potential impairments by comparing the fair value of a reporting unit, based on discounted cash flows, with its book value, including goodwill. If the fair value of the reporting unit exceeds the carrying amount, goodwill is not impaired and the second step is not necessary. If the carrying value exceeds the fair value, the second step calculates the possible impairment loss by

F-8

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

comparing the implied fair value of goodwill with the carrying amount. If the implied goodwill is less than the carrying amount, a write-down is recorded. The Company performs its impairment test as of October 31 of each year. The impairment review of the assets acquired from Horizon supported the carrying value of goodwill, and as such, no write-down in the carrying value of goodwill was recorded.

Debt Issuance Costs—Debt issuance costs reflect fees incurred to obtain financing. Debt issuance costs are amortized (included in interest expense) using the straight line method, over the life of the related debt. Amortization expense for the year ended December 2005 was $1,785. Amortization expense for the period May 13, 2004 to December 31, 2004 was $266.

Restricted Cash—Restricted cash includes amounts required by various royalty and reclamation agreements. Restricted cash of $2,176 at December 31, 2005 and $4,243 at December 31, 2004 is included in other non-current assets ($2,171 and $3,744, respectively) and prepaid expenses and other ($5 and $499, respectively).

Coal Mine Reclamation and Mine Closure Costs—Future cost requirements for land reclamation are estimated where surface and deep mining operations have been conducted, based on the Company’s interpretation of the technical standards of regulations enacted by the U.S. Office of Surface Mining, as well as state regulations. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at deep mines. Other costs common to both types of mining are related to reclaiming refuse and slurry ponds as well as holding and related termination/exit costs.

The Company records these reclamation obligations under the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). SFAS No. 143 addresses asset retirement obligations that result from the acquisition, construction or normal operation of long-lived assets. It requires companies to recognize asset retirement obligations at fair value when the liability is incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The asset retirement costs are recorded in coal lands.

The Company expenses reclamation performed prior to final mine closure. The establishment of the end of mine reclamation and closure liability is based upon permit requirements and requires significant estimates and assumptions, principally associated with regulatory requirements, costs and recoverable coal lands. Annually, the end of mine reclamation and closure liability is reviewed and necessary adjustments are made, including adjustments due to mine plan and permit changes and revisions to cost and production levels to optimize mining and reclamation efficiency. The amount of such adjustments is reflected in the SFAS No. 143 year-end calculation.

Asset Impairments—The Company follows SFAS No. 144, Accounting for the 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 the sum of projected cash flows is less than the carrying amount, impairment losses are recognized. In determining such impairment losses, discounted cash flows 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 closing obligations are accelerated and the mine closing 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.

F-9

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

Income Tax Provision—The provision for income taxes includes federal, state and local income taxes currently payable and deferred taxes arising from temporary differences between the financial statement and tax basis of 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.

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 at the time of shipment or delivery to the customer, prices are fixed or determinable, and the title 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, where coal is loaded to the rail, barge, truck or other transportation source(s) 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.

Other revenues consist of equipment and parts sales, equipment rebuild and maintenance services, coal handling and processing, royalties, commissions on coal trades, contract mining, and rental income. With respect to other revenues recognized in situations unrelated to the shipment of coal, the Company carefully reviews the facts and circumstances of each transaction and applies the relevant accounting literature as appropriate, and does 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 the collectibility is reasonably assured. Advance payments received are deferred and recognized in revenue as coal is shipped or rentals are earned.

Postretirement Benefits Other Than Pensions—As prescribed by SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions (“SFAS No. 106”), accruals are made, based on annual outside actuarial valuations, for the expected costs of providing postretirement benefits other than pensions, which are primarily medical benefits, during an employee’s actual working career.

The Company accounts for health care and life insurance benefits provided for current and future retired employees and their dependents by accruing the cost of such benefits over the service lives of employees. Unrecognized actuarial gains and losses are amortized over the estimated average remaining service period for active employees utilizing the minimum amortization method prescribed by SFAS No. 106.

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 a large deductible insurance program, self-insurance and state workers’ compensation fund participation to secure on-going obligations depending on the location of the operation. For pneumoconiosis (black lung liabilities), provisions are made for estimated benefits based on annual evaluations prepared by independent actuaries. The Company follows SFAS No. 112, Employers’ Accounting for Postemployment Benefits for purposes of accounting for its black lung liabilities and assets.

Stock Based Compensation—The Company applies the provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations to account for

F-10

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

stock based awards issued under its equity and performance incentive plan. Based on the provisions of certain stock option awards, no compensation expense has been recognized for the options issued under the awards. Compensation expense for the remaining stock option awards is based on the intrinsic value of the options at the grant date, which is the measurement date, and is reflected in net earnings over the vesting period on a straight line basis. Compensation expense related to restricted stock awards is reflected in net earnings over the vesting period on a straight line basis. Compensation expense related to stock awards is reflected in net earnings of the vesting periods. If compensation expense associated with these awards was determined in accordance with SFAS No. 123, the Company’s net earnings and earnings per share would have been as follows:


	December 31, 2005
Net earnings, as reported	$	31,825
Add back compensation related to stock awards included in earnings, net of tax effects		2,479
Deduct effect of stock-based employee compensation, net of tax effects:
Stock option awards		(1,051	)
Restricted stock awards		(1,581	)
Stock awards		(707	)

Pro-forma net earnings	$	30,965

Earnings per share, as reported:
Basic	$	0.29

Diluted	$	0.29

Pro forma net earnings per share:
Basic	$	0.28

Diluted	$	0.28

The Black-Scholes option pricing model was used to calculate the estimated fair value of the options at the date of grant using the following assumptions: expected lives of 5 years, expected volatility of 41 and 48 percent and risk-free interest rates of 4.3 and 4.4 percent. The Company does not anticipate paying dividends on or forfeitures of options during the term of the options. The Company did not issue any stock based awards during the period May 13, 2004 through December 31, 2004.

Management’s Use of Estimates—The preparation of the consolidated financial statements in conformity with U.S. generally accepted accounting principles 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; inventories; coal lands; asset retirement obligations; employee benefit liabilities; future cash flows associated with assets; useful lives for depreciation, depletion and amortization; workers’ compensation claims; postretirement benefits other than pensions; 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 2005, the FASB issued SFAS No. 123(R), Share Based Payments (“SFAS No. 123(R)”). SFAS No. 123(R) supersedes APB Opinion 25, Accounting for Stock Issued to

F-11

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

Employees. This statement establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No.123(R) is effective as of the beginning of the first fiscal year beginning after June 15, 2005.

The Company will adopt the provisions of SFAS No. 123(R) during the period beginning January 1, 2006, using the modified prospective method. Initial adoptions of SFAS No. 123(R) will not have a material impact on the Company’s consolidated financial position or results of operations. The total impact of adopting SFAS 123(R) on the Company in future periods cannot be predicted at this time because it will depend on the level of equity-based compensation granted in the future. Compensation expense for the year ending December 31, 2006, related to equity awards outstanding as of December 31, 2005, is estimated to be $1,944, net of income taxes.

Emerging Issues Task Force (“EITF”) Issue 04-02 addresses the issue of whether mineral rights are tangible or intangible assets. SFAS No. 141, Business Combinations, requires the acquirer in a business combination to allocate the cost of the acquisition to the acquired assets and liabilities. At the March 17— 18, 2004 meeting, the EITF reached a consensus that mineral rights (defined as the legal right to explore, extract and retain at least a portion of the benefits from mineral deposits) are tangible assets. As a result of the EITF’s consensus, the FASB issued FASB Staff Position (“FSP”) Nos. SFAS No. 141-a and SFAS No. 142-a, Interaction of FASB Statements No. 141, Business Combinations and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-02, Whether Mineral Rights Are Tangible or Intangible Assets, which amend SFAS Nos. 141 and 142 and results in the classification of mineral rights as tangible assets. The Company has recorded mineral rights as tangible assets.

On March 30, 2005, the FASB ratified the consensus reached by the EITF on Issue 04-6, Accounting for Stripping Costs in the Mining Industry. This issue applies to stripping costs incurred in the production phase of a mine for the removal of overburden or waste materials for the purpose of obtaining access to coal that will be extracted. Under the new rule, stripping costs incurred during the production phase of the mine are variable production costs that are included in the cost of inventory produced and extracted during the period the stripping costs are incurred. Historically, the coal industry has considered coal uncovered at a surface mining operation but not yet extracted to be coal inventory (pit inventory). This represents a change in accounting principle. The guidance in this EITF consensus is effective for fiscal years beginning after December 15, 2005 for which the cumulative effect of adoption should be recognized as an adjustment to the beginning balance of retained earnings during the period. Adoption of this EITF consensus is expected to result in an approximate $1,000 decrease in the Company’s inventory and retained earnings during the first quarter of 2006.

In March 2005, the FASB issued FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143, Accounting for Asset Retirement Obligations (“FIN 47”). FIN 47 requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. This interpretation is effective for fiscal years ending after December 15, 2005. Adoption of this interpretation did not have a material impact on the Company’s consolidated financial position or results of operations.

In November 2004, the FASB issued SFAS No. 151, Inventory Costs an amendment of ARB No. 43, Chapter 4. This statement amends the guidance in ARB No. 43, Chapter 4, Inventory Pricing, to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage).

F-12

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

This statement requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, this statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company does not expect this statement to have a material impact on its consolidated financial position or results of operations.

3. ACQUISITIONS

Horizon Acquisition—The September 30, 2004 acquisition of certain Horizon properties, assets and liabilities was accounted for as a purchase business combination under the provisions of the FASB’s SFAS No. 141, Business Combinations. The aggregate purchase price of $325,784 was allocated to the assets acquired and liabilities assumed based on the respective fair values. The Horizon accounts receivable, advance royalties, accounts payable and accrued expenses, intangibles, goodwill and other assets and long-term liabilities were estimates of management. An independent valuation specialist prepared appraisals of the Horizon property, plant and equipment, coal reserves and accrued reclamation obligations while employee benefits valuations were prepared by independent actuaries. In connection with the acquisition, the Company is required to make certain payments to Lexington Coal Company (see Note 15), which will result in additional purchase price allocated to goodwill; all other allocations of the purchase price were finalized in 2005.

The following table summarizes the estimated fair values of assets acquired and liabilities assumed at the date of acquisition.

F-13

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)


	At September 30, 2004
Accounts receivable	$	60,130
Inventory		20,083
Prepaids and other		6,508
Property, plant, and equipment		159,496
Advance royalties		4,314
Debt issuance costs		8,078
Other assets		12,256
Goodwill		183,896
Accounts payable		(25,065	)
Accrued expenses		(35,422	)
Employee benefits		(17,127	)
Accrued reclamation		(43,889	)
Other long-term liabilities		(7,474	)

Net assets acquired	$	325,784


Funded by:
Capital contribution	$	150,151
Long-term debt		175,633

Total	$	325,784

Of the $183,896 allocated to goodwill above, approximately $166,000 will be deductible for federal income tax purposes.

The unaudited pro forma information shown below assumes that the certain properties and assets acquired and certain liabilities assumed as of September 30, 2004, occurred as of January 1, 2004 and January 1, 2003, and includes adjustments to decrease interest expense by approximately $101,000 in the nine months ended September 30, 2004 and approximately $131,000 in the twelve months ended December 31, 2003, to eliminate interest expense incurred in connection with Horizon’s Chapter 11 bankruptcy, and additional interest expense for ICG borrowings. This pro forma financial information is presented for informational purposes only and is not necessarily indicative of the results of future operations that would have been achieved had the assets been acquired and liabilities assumed at the beginning of 2003.


	Unaudited
	ICG		Horizon (Predecessor to ICG)
	Three months ended December 31, 2004		Nine months ended September 30, 2004			Twelve months ended December 31, 2003
Revenues	$	136,109	$	373,383		$	481,070
Net income (loss)	$	4,249	$	(6,292	)	$	(45,442	)
Basic and diluted earnings per share	$	0.04	$	(0.06	)	$	(0.43	)

Net income (loss) per share for the Horizon predecessor periods has been computed based on the average ICG shares outstanding for the three months ended December 31, 2004.

F-14

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

Anker and CoalQuest Acquisition—On March 31, 2005, the Company entered into a business combination agreement with each of Anker Coal Group, Inc. (“Anker”) and CoalQuest Development, LLC (“CoalQuest”) pursuant to which each of Anker and CoalQuest were to become the Company’s wholly owned subsidiaries. On November 18, 2005, the business combination was consummated and the stockholders of Anker received 14,840,909 shares of the Company’s common stock valued at $163,250 and the stockholders of CoalQuest received 9,250,000 shares of the Company’s common stock valued at $101,750. The results of operations of Anker and CoalQuest since November 18, 2005 are included in the consolidated results of operations of the Company for the period ended December 31, 2005.

The acquisition was a strategic business move to consolidate the coal assets of Anker and CoalQuest with the Company. This combination is expected to allow the Company to maintain current production levels for an extended period of time and also to further diversify its reserves.

The acquisition was accounted for using the purchase method of accounting whereby identifiable assets acquired and liabilities assumed were recorded at their fair market values as of the date of acquisition. The purchase price allocation is preliminary and will not be finalized until all determinations of fair value are made, including the completion of all independent third party appraisals. The Company expects completion of these appraisals in the third quarter of 2006. As a result, it is not practical to complete the assignment of goodwill to its reporting units as required by SFAS No. 142 as of December 31, 2005. The Company expects the final purchase price allocation to differ from the initial allocation presented below.

The following table summarizes the preliminary purchase price allocation based on fair values of the assets acquired and liabilities assumed at the date of acquisition:


	At November 18, 2005
Cash	$	7,379
Accounts receivable		12,520
Inventory		5,254
Prepaids and other		6,061
Property, plant and equipment		342,509
Advance royalties		6,324
Other assets		6,114
Goodwill		151,677
Accounts payable		(15,745	)
Accrued expenses		(14,392	)
Accrued reclamation		(42,232	)
Other long-term liabilities		(60,955	)
Below-market coal supply agreements		(73,418	)

Net assets acquired	$	331,096

Funded by:
Acquisition costs	$	4,944
Assumed debt		61,152
Issuance of 24,090,909 shares of common stock		265,000

	$	331,096

F-15

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

None of the $151,677 allocated to goodwill above is deductible for federal income tax purposes.

The following unaudited pro forma data reflect the consolidated results of operations of the Company as if the acquisition had taken place on January 1, 2005 and October 1, 2004, respectively. The unaudited pro forma information incorporates the accounting for the acquisition, including but not limited to, the application of purchase accounting for coal supply agreements and mineral reserves, employee benefit liabilities and property plant and equipment. The unaudited pro forma information may not be indicative of actual results.


	Unaudited
	Year ended December 31, 2005		For the period from May 13, 2004 (inception) to December 31, 2004
Revenues	$	779,821	$	177,829
Net income		23,100		5,558
Basic Earnings Per Share:
Net income	$	0.17	$	0.04
Basic common shares outstanding		132,307,011		130,696,908
Diluted Earnings Per Share:
Net income	$	0.17	$	0.04
Diluted common shares outstanding		132,348,087		130,696,908

Unaudited pro forma basic and diluted common shares outstanding include all shares issued in connection with the acquisition as if they were issued as of the beginning of each period presented.

Stock options totaling 325,000 were not included in the diluted earnings per share calculation since the strike price was less than the average market price of the shares during the periods presented.

4. INVENTORIES

As of December 31, inventories consisted of the following:


	2005		2004
Coal	$	9,960	$	4,443
Parts and supplies, net of a reserve for obsolescence of $311 for 2005 and $74 for 2004		10,707		9,500

Total	$	20,667	$	13,943

F-16

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

5. PROPERTY, PLANT AND EQUIPMENT

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


	2005			2004
Land and land improvements	$	18,633		$	16,798
Mining and other equipment and related facilities		181,283			72,590
Mine development and contract costs		36,449			16,012
Coal lands		342,673			53,031
Mine development in process		11,131			1,373
Construction work in process		35,607			5,275

		625,776			165,079
Less-accumulated depreciation, depletion and amortization		(54,292	)		(7,943	)

Net property, plant and equipment	$	571,484		$	157,136

Included in property, plant and equipment is $46,738 and $6,648, as of December 31, 2005 and 2004, respectively, related to development and construction projects for which depreciation, depletion and amortization have not yet commenced. Realization of these projects is reviewed on a periodic basis.

6. GOODWILL

The changes in the carrying amount of goodwill were as follows:


Balance as of September 30, 2004	$	183,896
Additional acquisition fees		50

Balance as of December 31, 2004		183,946
Adjustments to finalize purchase price allocation of Horizon		4,413
Bonding royalty (See Note 15)		700
Anker/CoalQuest acquisition (See Note 3)		151,677

Balance as of December 31, 2005	$	340,736

The adjustments to finalize purchase price allocation of Horizon were due to the excess of actual expenses related to the acquisition of the assets of Horizon Natural Resources over management’s original estimate to balance sheet accounts for items that were not available at the time of acquisition.

7. ACCRUED EXPENSES AND OTHER

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


	2005		2004
Payroll, bonus and vacation expense	$	22,373	$	16,163
Sales and use tax		181		143
Severance tax		2,472		1,355
Federal reclamation tax		1,081		918
Excise/black lung tax		710		344
Personal property tax		8,270		5,080
Franchise tax		751		58
Other		7,606		9,793

Total	$	43,444	$	33,854

F-17

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

8. DEBT

As of December 31, debt consisted of the following:


	2005		2004
Long-term debt
Term Notes	$	19,563	$	175,000
Revolving credit facility		21,280		—
Equipment notes		4,453		—
Capital leases (See Note 15)		166		681

Total		45,462		175,681
Less—current portion		1,646		2,235

Long-term debt and capital leases	$	43,816	$	173,446

Short-term debt
Insurance financing and other	$	4,113	$	3,787

Credit Facility and Other Long-Term Debt—At December 31, 2004 the Company had a credit facility consisting of a $110,000 revolving credit facility with a letter of credit sub-limit of up to $60,000 and a $175,000 term loan facility. On June 29, 2005 the credit facility was amended. As amended, the $320,000 credit facility provides for a $110,000 revolving credit facility with a letter of credit sub-limit of $75,000 and a $210,000 term loan facility. As part of the amendment, a $35,000 increase to the term loan was advanced upon the consummation of the business combination agreement with Anker and CoalQuest. In addition, the June 29, 2005 amendment allows for additional increases in the revolving credit facility of up to $190,000 and in the term loan facility of up to $50,000 without lender approval, upon completion of a public offering. On March 21, 2006, the Company obtained an increase of $100,000 in its revolving credit facility as permitted by the June 29, 2005 amendment.

The revolving credit facility has a five-year term and matures on October 1, 2009. Borrowings bear interest, at the Company’s option, at either LIBOR, plus a margin ranging from 2.00% to 2.50%, per annum or the prime rate plus a margin, ranging from 1.00% to 1.50%, per annum. As of December 31, 2005, ICG had $28,795 available on this revolving credit facility, net of $59,925 in letters of credit for insurance, workers’ compensation, land lease agreements and reclamation bonds. As of December 31, 2005 the facility bears interest from 6.87% to 6.88%.

The Company must pay a commitment fee ranging from 0.25% to 0.50%, per annum on the average daily unused portion of the commitment under the revolving credit facility. The Company recorded expense related to the commitment fee of $256 and $64 for the year ended December 31, 2005 and the period May 13, 2004 to December 31, 2004, respectively. The Company must also pay an annual letter of credit participation fee ranging from 2.00% to 2.50%, per annum and a letter of credit fronting fee of 0.20% on the average daily outstanding letter of credit balance under the revolving credit facility. The Company recorded expense related to the letter of credit participation fees and letter of credit fronting fees of $1,430 and $248 for the year ended December 31, 2005 and the period May 13, 2004 to December 31, 2004, respectively.

F-18

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

Borrowings under the Credit Facility are secured by substantially all of the Company’s and its subsidiaries assets, as well as by a pledge of 100% of the stock of all subsidiaries. In addition, the Company and each of its other non-borrower subsidiaries guarantee all of the indebtedness under the Credit Facility.

The Credit Facility requires certain mandatory prepayments upon the receipt of the proceeds from certain asset sales, casualty events, debt or equity offerings and in the event that there is excess cash flow as determined in accordance with the credit facility. The Credit Facility requires 50% of the proceeds of a public offering (net of any underwriting fees, discounts, commissions and other costs and expenses) to be applied as a prepayment of the Term Notes. The Term Loan Notes mature on October 1, 2010. $188,688 of net proceeds from the public offering were applied to the outstanding Term Loan Notes leaving a balance of $19,563. Due to this pre-payment the principal payments of $438 plus interest were reduced to $41 plus interest per quarter due from April 10, 2006 through October 10, 2009 and payments of $41,563 plus interest were reduced to $3,913 plus interest per quarter for three quarters and $7,207 plus interest for the final quarter. The Term Loan Notes bear interest, at the Company’s option, at either LIBOR plus 2.75% per annum or the prime rate plus 1.75% per annum. As of December 31, 2005 the Term Loan Notes bear interest at 7.13%.

The Credit Facility contains financial covenants including a maximum leverage ratio, a minimum interest coverage ratio, a minimum fixed charge coverage ratio and a limit on capital expenditures. The Credit Facility also contains certain other covenants, including, but not limited to, limitations on the incurrence of indebtedness, asset dispositions, acquisitions, investments, dividends and other restricted payments, liens and transactions with affiliates. At December 31, 2005, the Company was in compliance with all the above covenants.

The equipment notes have maturity dates extending to April 2010 and are collateralized by mining equipment. At December 31, 2005 the notes bear interest at fixed rates that range from 5.10% to 7.45%.

Future maturities of long-term debt and capital leases are as follows as of December 31, 2005:


Year ending December 31:
2006	$	1,646
2007		1,239
2008		1,215
2009		22,331
2010		19,031

Total	$	45,462

Short-Term Debt—The Company finances the majority of its annual insurance premiums. The current finance agreement requires an initial down payment of $2,371 and eight additional monthly principal and interest payments of $700. The note bears an interest rate of 5.35%.

F-19

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

9. ASSET RETIREMENT OBLIGATION

At December 31, 2005 and 2004, the asset retirement obligation accrual for reclamation and mine closure costs totaled $84,352 and $43,298, respectively.

The following schedule represents activity in the accrual for reclamation and mine closure cost obligation.


	2005			2004
Balance at beginning of period	$	43,298		$	—
Liabilities assumed in acquisitions		42,232			43,889
Expenditures		(4,546	)		(1,349	)
Accretion		3,368			758

Balance at December 31	$	84,352		$	43,298

The accrued reclamation and mine closure cost obligations are included in the accompanying consolidated balance sheets as follows:


	December 31, 2005		December 31, 2004
Current portion of reclamation and mine closure costs	$	4,697	$	2,682
Non-current reclamation and mine closure costs		79,655		40,616

Total	$	84,352	$	43,298

10. INCOME TAXES

The income tax provision for the year ended December 31, 2005 and the period May 13, 2004 to December 31, 2004 is comprised of the following:


	Year ended December 31, 2005		May 13, 2004 to December 31, 2004
Current:
Federal	$	9,954	$	1,901
State		1,311		331

		11,265		2,232
Deferred:
Federal		4,721		306
State		690		53

		5,411		359

Total	$	16,676	$	2,591

F-20

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

The following table presents the difference between the actual tax provision and the amounts obtained by applying the statutory U.S. federal income tax rate of 35% to income and losses before income taxes.


	Year ended December 31, 2005			May 13, 2004 to December 31, 2004
Federal provision computed at statutory rate	$	16,970		$	2,394
State income tax provision (net of federal tax benefits and apportionment factors) computed at statutory rate		1,301			219
Percentage depletion excess of tax basis at statutory rate		(1,701	)		—
Other		106			(22	)

Total	$	16,676		$	2,591

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


	2005			2004
Deferred Tax Assets:
Accrued employee benefits	$	13,388		$	6,932
Accrued reclamation and closure		32,363			16,670
Below-market contracts		26,305			—
NOL carryover		7,638			—
Other		7,757			3,720

		87,451			27,322

Deferred Tax Liabilities:
Property, coal lands and mine development costs		116,883			16,514
Other		8,843			879

		125,726			17,393

Net deferred tax asset (liability)	$	(38,275	)	$	9,929

Classified in balance sheet:
Deferred income taxes—current	$	4,923		$	2,188
Deferred income taxes—non-current		(43,198	)		7,741

Total	$	(38,275	)	$	9,929

The Company has a total net operating loss (NOL) carryover of $19,840, of which $2,707 expires in 2023 and $17,133 expires in 2024. The Company is subject to a limitation of approximately $6,900 on the amount of NOL it can utilize in any one year. The company also has an alternative minimum tax loss carryover of $20,580 of which $4,450 expires in 2023 and $16,130 expires in 2024.

F-21

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

11. EMPLOYEE BENEFITS

Employee benefits at December 31, are summarized as follows:


	2005		2004
Postretirement benefits	$	9,384	$	8,013
Black lung benefits		16,784		9,994
Workers’ compensation benefits		2,376		—
Coal Act benefits		6,277		—

Total		34,821		18,007
Less current portion		1,524		—

Long-term portion	$	33,297	$	18,007

Employees of the Company who complete ten years of service and certain employees who have completed eight years of service with the former Horizon companies and complete two years with ICG, will be eligible to receive postretirement benefits. Upon reaching the retirement age of 65, in order to receive a maximum medical life-time benefit of one hundred thousand dollars per family, 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, health care cost increases, etc.) that the Company uses in determining its postretirement obligations. Postretirement benefit expense for the Company totaled $1,371 and $330 for the year ended December 31, 2005 and the period May 13, 2004 to December 31, 2004, respectively.

Valuation Date—All actuarially determined benefits were determined as of December 31, 2005 and 2004.

Postretirement Benefits—The following postretirement benefit information was prepared for ICG for the year ended December 31, 2005 and period May 13, 2004 to December 31, 2004.


	Other Postretirement Benefits
	December 31, 2005			December 31, 2004
Changes in Benefit Obligations:
Benefit obligations at beginning of period	$	8,134		$	—
Benefit obligations assumed in the acquisition		—			7,683
Service costs		903			219
Interest cost		468			111
Actuarial loss		2,113			121

Benefit obligation at end of period	$	11,618		$	8,134

Fair value of plan assets at end of period	$	—		$	—

Funded Status of the Plan:
Accumulated obligations less plan assets	$	(11,618	)	$	(8,134	)
Unrecognized actuarial loss		2,234			121

Net liability recognized	$	(9,384	)	$	(8,013	)

F-22

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)


	Year ended December 31, 2005		May 13, 2004 to December 31, 2004
Net periodic benefit cost:
Service cost	$	903	$	219
Interest cost		468		111

Benefit cost	$	1,371	$	330

For measurement purposes, a 10% annual rate of increase in the per capita cost of covered health care benefits was assumed, gradually decreasing to 5% in 2015 and remaining level thereafter.

The expense and liability estimates can fluctuate by significant amounts based upon the assumptions used by the actuaries. As of December 31, 2005, a one-percentage-point change in assumed health care cost trend rates would have the following effects:


	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total of service and interest cost components	$	391	$	(295	)
Effect on postretirement benefit obligation		1,634		(1,235	)

Estimated future benefit payments reflecting expected future service for the fiscal years ending after December 31, 2005 are as follows:

Year ended December 31:


2006	$	65
2007		142
2008		392
2009		651
2010		1,089
2011 - 2015		10,560

Total	$	12,899

On December 8, 2003, the President of the United States signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”). The Act introduces a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

In May 2004, the FASB issued further guidance with the release of FASB Staff Position (“FSP”) No. FAS 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“FSP 106-2”). The effective date of FSP No. 106-2 is for the first interim or annual period beginning after June 15, 2004. As of December 31, 2005, the Company determined the effects of the Act

F-23

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

did not result in a material reduction of the Company’s postretirement benefit obligation or postretirement benefit expense.

Workers’ Compensation and Black Lung—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 fully insured by either a large deductible insurance program or state fund for workers’ compensation obligations and self-insured for black lung obligations.

The Company’s actuarially determined liability for self-insured black lung benefits is based on a 5.75% discount rate and various other assumptions including incidence of claims, benefits escalation, terminations and life expectancy. The annual black lung expense consists of actuarially determined amounts for self-insured obligations. The estimated amount of discounted obligations for self-insured black lung claims plus an estimate for incurred but not reported claims was $17,235 and $9,917 as of December 31, 2005 and 2004, respectively. The unrecognized projected black lung benefit obligations (difference between recorded accrual and projected obligations) at December 31, 2005 and 2004 was a loss of approximately $451 and a gain of approximately $77, respectively, and is being provided for over the future service period of current employees. The projected black lung obligations may vary in a given year based on the timing of claims filed and changes in actuarial assumptions. The Company recorded expenses related to black lung of $2,419 and $551 for the year ended December 31, 2005 and the period May 13, 2004 to December 31, 2004, respectively.

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 an independent actuarial valuation for the latest list of beneficiaries assigned to Anker, the Company estimates the amount of its obligation under the Coal Act to be approximately $6,277 as of December 31, 2005, discounted at 5.5%. The Company recorded interest expense related to the Coal Act of $37 for the year ended December 31, 2005. No amounts were recognized as of and for the period ended December 31, 2004.

Retirement Plan—Those employees formerly employed by Anker have a contributory defined contribution retirement plan covering all employees who meet certain eligibility requirements. The plan provides for employer contributions representing 5% of compensation. The Company’s contributions amounted to approximately $104 for the period from November 19 through December 31, 2005.

401(k) Plans—The Company sponsors a savings and retirement plan for substantially all employees. The Company matches voluntary contributions of participants, except for those previously employed by Anker, 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 $3,999 and $733 for the year ended December 31, 2005 and the period May 13, 2004 to December 31, 2004, respectively.

For those employees previously employed by Anker, and who meet eligibility requirements, the Company also has a 401(k) savings plan. The plan provides for either a 1% non-elective contribution, for those employees who choose not to contribute, or 100% match of the first 3% of employee contributions and 50% of the next 2% of employee contributions. Thus, the Company’s contribution could be as much as 4% of each participant’s compensation, subject to statutory limits. The expense under this plan for the Company was $78 for the period November 19 through December 31, 2005.

F-24

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

12. EMPLOYEE STOCK PLANS

The Company granted stock option, restricted stock and stock awards to certain executive officers during 2005. The restricted stock and stock option awards generally vest 25% in the year of grant and 25% in equal annual installments over the next three years.

Stock options to purchase 319,052 common shares at $10.97 with a fair value of $2,000 were granted in 2005. Total compensation expense based on the difference between the market price at the date of grant and its exercise price of $10.97 is $648; of this cost, $288 was recognized in earnings for the year ending December 31, 2005. Stock options to purchase 325,000 common shares with an estimated fair value of $1,693 were granted in 2005 and were priced at $11 per share which was the price of the shares of common stock sold in the Offering in December 2005. The options are exercisable upon vesting and expire 10 years from the date of grant.

Restricted stock awards of 518,750 shares with a fair value of $7,018, based on the market price of the stock at the date of grant, were made during 2005. The awards require no cash payment from the employee.

Stock awards of 81,250 shares with a fair value of $1,071, based on the market price of the stock at the date of grant, were made during 2005, without cash payment from the employee.

In September 2005, the Company’s president purchased 25,000 shares of common stock at $8 per share pursuant to his employment agreement. Total compensation expense of $172 was recognized in earnings for the year ending December 31, 2005.

For the year ended December 31, 2005, no options were exercised or forfeited.

13. VARIABLE INTEREST ENTITIES

The Company acquired a 50% interest in Sycamore Group, LLC (“Sycamore”) in conjunction with its acquisition of Anker (see Note 3). Sycamore was established as a joint venture with an unrelated third party to mine coal from the Sycamore No. 1 mine. It is anticipated that the reserve from Sycamore No. 1 will be 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 the provisions of FIN 46(R) and has consolidated the accounts of Sycamore as of December 31, 2005 and for the period November 19, 2005 through December 31, 2005. 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 December 31, 2005 and for the year then ended are as follows:


Assets	$	3,634
Liabilities		1,558
Revenue		1,098
Net Income		(33	)

14. EARNINGS PER SHARE

Basic earnings per share is computed by dividing net income 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

F-25

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

average number of common shares outstanding during the period and, when dilutive, potential common shares from the exercise of stock options and restricted common stock subject to continuing vesting requirements, pursuant to the treasury stock method.


	Year Ended December 31, 2005		Period from May 13, 2004 (inception) to December 31, 2004
Net income	$	31,825	$	4,249

Average common shares outstanding—Basic		111,120,211		106,605,999
Incremental shares arising from stock options		11,100		—
Incremental shares arising from restricted shares		29,976		—

Average common shares outstanding—Diluted		111,161,287		106,605,999

Earnings Per Share:
Basic	$	0.29	$	0.04

Diluted	$	0.29	$	0.04

Options outstanding to purchase 325,000 shares of common stock at $11.00 per share were not included in the computation because their exercise price was greater then the average market price of the common shares for the period from December 12, 2005 through December 31, 2005.

15. COMMITMENTS AND CONTINGENCIES

Guarantees and Financial Instruments with Off-balance Sheet Risk—In the normal course of business, the Company is a party to certain 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 the Company’s consolidated balance sheets. Management does not expect any material losses to result from these guarantees or off-balance sheet financial instruments. The Company has outstanding surety bonds with third parties of approximately $92,329 as of December 31, 2005 to secure reclamation and other performance commitments. In addition, as of December 31, 2005 the Company also has bank letters of credit outstanding of $59,925 under the revolving credit facility.

Coal Sales Contracts—As of December 31, 2005, the Company had commitments under 32 sales contracts to deliver annually scheduled base quantities of coal to 22 customers. The contracts expire from 2005 through 2020 with the Company contracted to supply a minimum of approximately 87.6 million tons of coal over the remaining lives of the contracts (maximum of approximately 17.0 million tons in 2006). The Company also has commitments to purchase certain amounts of coal to meet its sales commitments. The purchase coal contracts expire through 2010 and provide the Company a minimum of approximately 7.2 million tons of coal through the remaining lives of the contracts (maximum of 4.0 million tons in 2006). Certain of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

Employment Agreements—The Company has entered into employment agreements with the Chief Executive Officer and the Senior Vice President/General Counsel that expire on March 31, 2008. Under the employment agreements, the officers are guaranteed annual base compensation and annual bonuses totaling $760 and $604, respectively.

F-26

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

Leases—The Company leases various mining, transportation and other equipment under operating and capital leases. Lease expense for the year ended December 31, 2005 and the period May 13, 2004 to December 31, 2004 was $15,731 and $5,885, respectively. Property under capital leases included in property, plant and equipment in the consolidated balance sheets at December 31, 2005 and 2004 was approximately $548 and $975, respectively less accumulated depreciation of approximately $274 and $97, respectively. Depreciation of assets under capital leases is included in depreciation expense.

The Company also leases coal lands under agreements that call for royalties to be paid as the coal is mined. Total royalty expense for the year ended December 31, 2005 and the period May 13, 2004 to December 31, 2004 was approximately $26,027 and $5,119, 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. Approximate non-cancelable future minimum lease and royalty payments are as follows:


	Royalties		Operating Leases		Capital Leases
Year ended December 31,
2006	$	3,891	$	8,983	$	170
2007		5,332		3,090		—
2008		5,232		20		—
2009		5,263		2		—
2010		5,066		—		—
Thereafter		23,842		—		—

Total minimum lease payments	$	48,626	$	12,095		170

Less—amount representing interest						4

Present value of minimum lease payments (Note 8)						166
Less—current portion						166

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 is 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 (Additional Payment). On September 30, 2004, the Company prepaid $4,000 of such Additional Payments, accounting for the payment as additional purchase consideration. The prepayment was applied to actual Additional Payments through October 2005. In addition, Additional Payments of $700 were recorded in 2005 as additional purchase price (goodwill) (see Note 6).

Under the Bonding Royalty, ICG was required to pay an additional 0.75% on gross sales referred to above, to a fund controlled by one of its sureties until all letters of credit issued by such surety for both ICG and LCC were cash collateralized. During 2005, the surety released ICG of its obligation to maintain additional cash collateral and refunded all of the cash previously paid to collateralize the letters of credit. In March 2006, the $10,000 letter of credit to support reclamation obligations (Bonding Royalty) was also released.

F-27

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

Under the provisions of FIN 46 (R), ICG has determined it does not hold a significant variable interest in LCC and it is not the primary beneficiary of LCC.

Legal Matters—From time to time, the Company is involved in legal proceedings arising in the ordinary course of business. In the opinion of management the Company has recorded adequate reserves for these liabilities and there is no individual case or group of related cases pending that is likely to have a material adverse effect on the financial condition, results of operations or cash flows of the Company.

On November 18, 2005, the Company filed a lawsuit against Massey Coal Sales Company, Inc., a Massey Energy Company subsidiary, in the U.S. District Court for the Eastern District of Kentucky. In the complaint, the Company alleged that Massey has breached an existing coal supply agreement. Pursuant to the terms of the coal supply agreement, Massey sells the coal to the Company and the Company in turn sells the coal to the Company’s customer, Carolina Power & Light. Any failure by Massey to perform under its coal supply agreement adversely affects the Company’s ability to perform under the Company’s agreement with Carolina Power & Light and could result in liability to the Company’s customer for such failure, although the Company would seek indemnification from Massey for any such liability. The Company is seeking damages for Massey’s past failure to perform, punitive damages and an injunction requiring contractual performance during the remaining term of the contract.

As a result of the explosion at the Company’s Sago mine on January 2, 2006, the Federal Mine Safety and Health Administration and the State of West Virginia have begun a joint investigation into the cause of the explosion. The Company is fully cooperating with the investigation by federal and state mine regulatory authorities to determine the cause of the explosion (see Note 19).

Commissions—The Company has various sales and agency agreements with third parties, whereby the Company pays a $0.05 per ton commission on various coal sales agreements. The costs are expensed as the coal is delivered. The Company incurred commission expense of $36 and $1 for the year ended December 31, 2005 and the period May 13, 2004 to December 31, 2004.

Environmental Matters—Based upon current knowledge, the Company believes it is in material compliance with environmental laws and regulations as currently promulgated. However, 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 $92,329 as of December 31, 2005 to secure reclamation and other performance commitments. In addition, at December 31, 2005 the Company has $59,925 of letters of credit outstanding under the revolving credit facility, a portion of which ($50,000, including $10,000 to LCC— see Bonding Royalty and Additional Payment above) provides support to the third parties for their issuance of surety bonds. In addition, the Company has posted cash collateral of $2,176 and $4,243 to secure reclamation and other performance commitments as of December 31, 2005 and 2004, respectively. This cash collateral is included in other non-current assets and prepaid expense and other on the consolidated balance sheets.

Contract Mining Agreements—ICG’s subsidiary, ICG ADDCAR Systems, LLC (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

F-28

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

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 ranging from 2006 to 2008.

16. 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, 2005 and 2004, trade accounts receivable from electric utilities totaled approximately $45,498 and $35,060, respectively. The Company evaluates each customer’s creditworthiness prior to entering into transactions and constantly monitors the credit extended. Credit losses are provided for in the consolidated financial statements and historically have been minimal.

The Company had coal sales to the following major customers that equaled or exceeded 10% of revenues:


	December 31, 2005 Total Receivable Balance		December 31, 2005 Total Revenues		December 31, 2004 Total Receivable Balance		May 13, 2004 to December 31, 2004 Total Revenues
Customer A	$	8,210	$	95,832	$	2,563	$	17,720
Customer B		5,620		117,976		6,581		19,151
Customer C		5,138		68,202		5,751		19,759

17. 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.

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 and Interest Rate Cap: The carrying value of the term loan facility at December 31, 2005 and 2004 approximates fair value of the facility, as the interest rate is stated at LIBOR plus a margin. The carrying value of the Company’s capital lease obligations and other debt approximate fair value at December 31, 2005 and 2004. The fair value of the Company’s interest rate cap was $230 and $164 at December 31, 2005 and 2004, respectively.

18. RELATED-PARTY TRANSACTIONS AND BALANCES

Under an Advisory Services Agreement, dated as of October 1, 2004 between ICG and WLR, WLR has agreed to provide advisory services to ICG (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 ICG 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.

F-29

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

On October 1, 2004, ICG entered into an agreement with Insuratex, LTD, a wholly owned subsidiary of funds controlled by WLR, to administer and pay workers’ compensation claims incurred by ICG. ICG paid an initial $2,500 premium to fund such claims and continued to pay monthly installments of approximately $208 until a total premium of $5,000 was paid by ICG. This agreement was cancelled on September 30, 2005 and after deducting for actual claims paid, ICG received $4,295.

19. SUBSEQUENT EVENT

On January 2, 2006, an explosion occurred at the Company’s Sago mine in Tallmansville, West Virginia. The Sago mine is operated by the Company’s subsidiary Wolf Run Mining Company (f/k/a Anker West Virginia Mining Company, Inc.). The explosion tragically resulted in twelve fatalities and the critical injury of another miner. The Company is fully cooperating with the state and federal investigations into the cause of the explosion. On March 14, 2006 the Company announced its initial findings from the investigation, including that the explosion was ignited by lightning and fueled by methane that naturally accumulated in an abandoned area of the mine that had been recently sealed. The precise route by which the lightning electrical charge traveled from a surface strike location to the sealed area remains under investigation, and the seals, constructed of Omega block under a plan approved by federal authorities and designed to withstand forces of 20 pounds per square inch, were essentially obliterated by the explosion. The Company will continue with data review and testing to verify the findings. Final results of the investigations will not be known until federal and state safety officials conclude their investigations and issue their reports. The Company resumed operations at the Sago mine on March 15, 2005, a week after federal and state safety officials provided approval.

In the first quarter of 2006, ICG gave gifts totaling $2,000 to the families of the miners involved in the explosion in order to provide financial support. ICG recorded a preliminary estimate of $5,000, inclusive of the gifts to the families, related to the accident in January 2006.

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 three reportable business segments: Central Appalachian, Northern Appalachian and Illinois Basin. The Company’s operations in Central Appalachia are located in southern West Virginia and eastern Kentucky and include five underground mines and eight surface mines. The Company’s operations in Northern Appalachia are located in northern West Virginia, Pennsylvania and Maryland and include five underground mines and four surface mines. The Company’s operations in Illinois include one underground mine. The Company also has an Ancillary category which includes the Company’s brokered coal functions, corporate overhead, contract highwall mining services and land activities.

In 2005, the Company completed the allocation of the purchase price to the assets and liabilities acquired from Horizon. The difference between segment assets and consolidated assets in the following table is the elimination of intercompany transactions including inter-segment revenues and investment in subsidiaries

F-30

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

reflected in the elimination category. Reportable segment results for continuing operations for the year ending December 31, 2005 and segment assets as of December 31, 2005 were as follows:


	Central Appalachian		Northern Appalachian			Illinois Basin		Ancillary		Eliminations			Consolidated
Revenue	$	449,868	$	11,887		$	57,808	$	131,911	$	(3,761	)	$	647,713
EBITDA		100,383		(3,092	)		4,599		4,185		—			106,075
Depreciation, depletion and amortization		27,002		956			4,752		10,485		—			43,195
Capital expenditures		78,796		5,712			11,119		20,383		—			116,010
Total assets		383,104		100,128			37,625		2,043,798		(1,508,492	)		1,056,163
Goodwill		160,555		—			—		180,181		—			340,736

Revenue in the Ancillary category consists primarily of $108,102 relating to the Company’s brokered coal sales and $20,018 relating to contract highwall mining activities. Capital expenditures include non-cash amounts of $7,779. As discussed in Note 3, the preliminary allocation of the purchase price of Anker and CoalQuest results in goodwill of $151,677. This amount has been preliminarily included in the Ancillary segment above. The Company expects adjustments, which could be material, to its purchase price allocation between tangible and intangible assets, including goodwill. As a result, it is not practical to complete its assignment of its goodwill to its reporting units as required by SFAS No. 142 as of December 31, 2005.

Reportable segment results for continuing operations for the period from May 13, 2004 to December 31, 2004 and segment assets as of December 31, 2004 were as follows:


	Central Appalachian		Illinois Basin		Ancillary			Eliminations			Consolidated
Revenue	$	98,555	$	12,744	$	24,982		$	(172	)	$	136,109
EBITDA		14,581		1,383		2,272			—			18,236
Depreciation, depletion and amortization		4,468		1,048		2,427			—			7,943
Capital expenditures		4,858		732		(7	)		—			5,583
Total assets		304,280		27,426		554,324			(426,055	)		459,975
Goodwill		155,948		—		27,998			—			183,946

Revenue in the Ancillary category consists primarily of $20,213 relating to the Company’s brokered coal sales and $4,769 relating to contract highwall mining activities.

EBITDA represents net income before deducting interest expense, income taxes and depreciation, depletion and amortization. EBITDA is presented because it is an important supplemental measure of the Company’s performance used by the Company’s chief operating decision maker.

Reconciliation of net income to EBITDA is as follows:


	Year Ended December 31, 2005			Period from May 13, 2004 to December 31, 2004
Net income	$	31,825		$	4,249
Depreciation, depletion and amortization		43,195			7,943
Interest expense, net		14,394			3,453
Income tax expense		16,676			2,591
Minority interest		(15	)		—

EBITDA	$	106,075		$	18,236

F-31

INTERNATIONAL COAL GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2005 and for the

period May 13, 2004 to December 31, 2004

(Dollars in thousands, except per share data)

21. QUARTERLY DATA

The following is a summary of selected quarterly financial information (unaudited):


	2005
	Three months ended March 31		Three months ended June 30		Three months ended September 30		Three months ended December 31
Revenue	$	153,232	$	154,032	$	158,390	$	182,059
Income from operations		20,091		16,237		13,451		7,021
Net income		10,857		9,092		8,599		3,277
Basic Earnings per common share		0.10		0.09		0.08		0.03
Diluted Earnings per common share		0.10		0.09		0.08		0.03


	2004
	Three months ended December 31
Revenue	$	136,109
Income from operations		9,395
Net income		4,249
Basic Earnings per common share		0.04
Diluted Earnings per common share		0.04

ICG did not commence operations until October 1, 2004, and did not have any material results of operations prior to that date (see Note 1).

F-32

Horizon NR, LLC and Certain Subsidiaries (Predecessor to International Coal Group, Inc.)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Members

Horizon NR, LLC and Certain Subsidiaries:

We have audited the accompanying combined statements of operations, members’ deficit and cash flows of Horizon NR, LLC and Certain Subsidiaries (“Combined Companies”) (“Debtors-in-Possession”) for the Period January 1, 2004 to September 30, 2004 and for the year ended December 31, 2003. The Combined Companies are wholly owned subsidiaries of Horizon Natural Resources Company. These financial statements are the responsibility of the Combined Companies’ management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, such financial statements present fairly, in all material respects, the combined results of operations and combined cash flows of the Combined Companies for the period January 1, 2004 to September 30, 2004 and the year ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the combined financial statements, the accompanying combined financial statements have been prepared from the separate records maintained by the Combined Companies and are not necessarily indicative of the conditions that would have existed or the results of operations if the Combined Companies has been operated as unaffiliated entities. Portions of certain assets and expense items represent allocations made from items applicable to Horizon Natural Resources Company (Parent) and subsidiaries as a whole.

The accompanying combined financial statements have been prepared assuming that the Combined Companies will continue as a going concern, which contemplates continuity of the Combined Companies’ operations and realization of its assets and payments of its liabilities in the ordinary course of business. As discussed in Notes 1 and 2 of the combined financial statements, the Combined Companies have suffered recurring losses from operations. The Combined Companies also have significant debt obligations maturing in October 2004. Furthermore, during November 2002, the Combined Companies’ Parent and its other subsidiaries, inclusive of the Combined Companies, filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code. The accompanying combined financial statements do not purport to reflect or provide for the consequences of those bankruptcy proceedings. In particular, such combined financial statements do not purport to show (A) as to member accounts, the effect of any changes that may be made in the capitalization of the Combined Companies; or (B) as to operations, the effect of any changes that may be made in its business. In addition, as discussed in Note 2, the Combined Companies are in default of various covenants and provisions, including debt service payments, of their principal debt instruments (other than debtor-in-possession financing facility) which makes such obligations currently due. These matters raise substantial doubt about the Combined Companies’ ability to continue as a going concern. Management’s plans in regard to these matters are also discussed in Notes 1 and 2. The Combined Companies are currently operating their business as a debtor-in-possession under the jurisdiction of the United States Bankruptcy Court, and continuation of the Combined Companies as a going concern is contingent upon, among other things, the Combined Companies’ ability to comply with all debt covenants under the existing debtor-in-possession financing agreements, to

F-33

generate sufficient cash flow from operations, and to obtain financing sources to meet its future obligations. If no reorganization plan is approved or no refinancing of the October 2004 debt obligations is obtained, it is possible that the Combined Companies’ assets may be liquidated. The combined financial statements do not include any adjustments that might result should the Combined Companies be unable to continue as a going concern.

As discussed in Note 12, the accompanying combined financial statements have been restated.

/s/ Deloitte and Touche LLP

Louisville, Kentucky

March 25, 2005 (September 20, 2005 as to the effects of the restatements discussed in Note 12)

F-34

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

COMBINED STATEMENTS OF OPERATIONS

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)


	Period from January 1, 2004 to September 30, 2004 (1)			Year Ended December 31, 2003 (1)
REVENUES:
Coal Sales revenues	$	346,981		$	441,291
Freight and handling revenues		3,700			8,008
Other revenues		22,702			31,771

Total revenues		373,383			481,070

COSTS AND EXPENSES:
Freight and handling costs		3,700			8,008
Cost of coal sales and other revenues (exclusive of items shown separately below)		306,429			400,652
Depreciation, depletion and amortization		27,547			52,254
Selling, general and administrative (exclusive of depreciation and amortization shown separately above)		8,477			23,350
Gain on sale of assets		(226	)		(4,320	)
Writedowns and special items		10,018			9,100

Total costs and expenses		355,945			489,044

Income (loss) from operations		17,438			(7,974	)
INTEREST AND OTHER INCOME (EXPENSE):
Interest expense		(114,211	)		(145,892	)
Reorganization items		(12,471	)		(23,064	)
Other, net		1,581			187

Total interest and other income (expense)		(125,101	)		(168,769	)

NET LOSS	$	(107,663	)	$	(176,743	)

(1)	As restated. See Note 12.

See notes to combined financial statements.

F-35

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

COMBINED STATEMENTS OF MEMBERS’ DEFICIT

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)


	Members’ Investment		Additional Paid-in Capital		Accumulated Other Comprehensive Loss			Accumulated Deficit			Total
BALANCE—December 31, 2002 (1)	$	200	$	234,800	$	(3,824	)	$	(829,595	)	$	(598,419	)
Comprehensive loss:
January 1, 2003 to December 31, 2003, net loss (1)		—		—		—			(176,743	)		(176,743	)
Minimum pension liability adjustment		—		—		141			—			141

Total comprehensive loss												(176,602	)
Balance- December 31, 2003 (1)		200		234,800		(3,683	)		(1,006,338	)		(775,021	)
January 1, 2004 to September 30, 2004, net loss (1)		—		—		—			(107,663	)		(107,663	)

BALANCE—September 30, 2004 (1)	$	200	$	234,800	$	(3,683	)	$	(1,114,001	)	$	(882,684	)

(1)	As restated. See Note 12 to the combined financial statements.

See notes to combined financial statements.

F-36

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

COMBINED STATEMENTS OF CASH FLOWS

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)


	Period from January 1, 2004 to September 30, 2004 (1)			For the year ended December 31, 2003 (1)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(107,663	)	$	(176,743	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		27,547			52,254
Depreciation—Allocation from Affiliates		127			4,118
Amortization of finance costs included in interest expense		1,437			3,698
Gain on sale of assets		(226	)		(4,320	)
Gain on lease buyout		(7,736	)		—
Writedowns and special items		17,754			9,100
Provision for doubtful accounts		247			1,656
Changes in Assets and Liabilities:
(Increase) decrease in:
Receivables		(10,706	)		(11,104	)
Inventories		(4,242	)		(273	)
Prepaid expenses		7,971			19,374
Other Assets		477			(36	)
Increase (decrease) in:
Accounts payable		21,680			(10,344	)
Accrued expenses		85,520			150,144
Reclamation and mine closure costs		(4,007	)		(11,942	)
Other Liabilities		(95	)		(5,552	)

Total adjustments		135,748			196,773

Net cash provided by operating activities		28,085			20,030

CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of assets		4,089			15,388
Proceeds from lease buyout		7,736			—
Additions to property, plant and equipment and mine development		(6,624	)		(16,937	)
Deposits of restricted cash		(1,764	)		(2,277	)

Net cash provided by (used in) investing activities		3,437			(3,826	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments on long-term debt		(4,698	)		(13,729	)
Net borrowings/(repayments) on debtor-in-possession financing		(27,080	)		(737	)
Repayments on capital leases		(603	)		(993	)

Net cash used in financing activities		(32,381	)		(15,459	)

Net increase (decrease) in cash and cash equivalents		(859	)		745
Cash and cash equivalents, beginning of period		859			114

Cash and cash equivalents, end of period	$	—		$	859

(1)	As restated. See Note 12.

See notes to combined financial statements.

F-37

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

1. ORGANIZATION AND BASIS OF PRESENTATION

Horizon NR, LLC (“HNR”) is a wholly-owned subsidiary of Horizon Natural Resources Company. HNR has seventy-five direct and indirect wholly-owned subsidiaries. The accompanying combined financial statements include the financial statements of seventeen of the seventy-five subsidiaries and the assets and liabilities of HNR that were acquired by ICG (see below). HNR and the seventeen subsidiaries are referred to as the “Combined Companies” in the accompanying combined financial statements and related footnotes. The seventeen subsidiaries included are: Appalachian Realty Company, Ayrshire Land Company, Bluegrass Coal Development Company, Evergreen Mining Company, Fairview Land Company, LLC, Horizon Natural Resources Sales Company, Leslie Resources, Inc. (exclusive of Chaives Job), Leslie Resources Management, Inc., Sunny Ridge Enterprises, Inc., Sunny Ridge Mining Company, Inc. (exclusive of Job 10), Turris Coal Company, Ikerd-Bandy Co., Inc., Shipyard River Coal Terminal Company, Franklin Coal Sales Company, Kentucky Prince Mining Company, RP Terminal, LLC, and Mining Technologies, Inc.

Horizon formerly known as AEI Resources Holding, Inc. (“AEI”) operated a coal mining business through its subsidiaries in the United States. As discussed in Note 2, on November 13, 2002 and November 14, 2002, Horizon filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court (the “Bankruptcy Court”). Horizon completed its November 2002 bankruptcy proceedings on September 30, 2004 through the sale or transfer of certain properties, assets and liabilities to International Coal Group, Inc. (“ICG”) and others. Horizon had previously filed a voluntary petition for reorganization under the Bankruptcy Code accompanied by a prepackaged plan of reorganization on February 28, 2002. Horizon’s first bankruptcy Plan of Reorganization became effective May 9, 2002.

The combined financial statements for the period January 1, 2004 to September 30, 2004 and for the year ended December 31, 2003, are carve-out financial statements reflecting the operations and financial condition of the Horizon properties acquired by ICG on September 30, 2004.

These combined financial statements were prepared from the separate accounts and records maintained by the Combined Companies and are not necessarily indicative of the conditions that would have existed or the results of operations if the Combined Companies had been operated as unaffiliated entities. Certain assets and expense items represent allocations from Horizon. The accounts allocated, amount, and basis of allocation are:


	Horizon Amounts
	January 1, 2004 - September 30, 2004		January 1, 2003 - December 31, 2003
Selling, general, and administrative expenses	$	17,100	$	25,000

	Amounts allocated to Combined Companies				Basis of Allocation
	January 1, 2004 - September 30, 2004		January 1, 2003 - December 31, 2003
Selling, general, and administrative expenses	$	9,081	$	9,860	Estimated Hours Worked

Selling, general and administrative expenses were allocated to the Combined Companies using a formula based on the ratio of estimated hours worked for the Combined Companies compared to the estimated hours worked for Horizon.

F-38

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS—(CONTINUED)

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

The Combined Companies’ financial statements have been presented on the basis that they are a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The Combined Companies’ recurring losses from operations, the related bankruptcy filing, the maturity of their debt obligations in 2004 and the Combined Companies’ defaults under their various debt covenants raise substantial doubt about the Combined Companies’ ability to continue as a going concern. The combined financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should the Combined Companies be unable to continue as a going concern. Realization of the carrying amounts of the Combined Companies’ assets and satisfaction of their liabilities is dependent upon, among other things, the ability to comply with their debtor-in-possession financing agreement, the ability to refinance or extend the 2004 debt obligations and the ability to generate sufficient cash flows from operations to meet their obligations. The Combined Companies’ operating plan includes actions they believe will improve operating profits and cash flows. There can be no assurances that operating profits and cash flows will be realized in an amount sufficient to fund obligations or other liquidity needs.

Since filing for protection under the Bankruptcy Code on November 13, 2002 and November 14, 2002 (see Note 2), Horizon has operated its business as a debtor-in-possession subject to the jurisdiction of the Bankruptcy Court. Accordingly, the combined financial statements of the Combined Companies have been prepared in accordance with the American Institute of Certified Public Accountants Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code (“SOP 90-7”) and generally accepted accounting principles applicable to a going concern, which assume that assets will be realized and liabilities will be discharged in the normal course of business.

2. LIQUIDITY AND BANKRUPTCY PROCEEDINGS

Chapter 11 Reorganization—On November 13, 2002 and November 14, 2002, Horizon filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code. On September 30, 2004, in connection with the completion of Horizon’s bankruptcy proceedings, ICG acquired certain properties and assets, and assumed certain liabilities of Horizon through Section 363 asset sales of the United States Bankruptcy Court.

The Combined Companies reorganization and administrative expenses (primarily legal and consulting expenses) related to the Chapter 11 proceedings have been separately identified in the combined statements of operations as reorganization items.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Basis of Presentation and Principles of Combination—Significant intercompany transactions and balances have been eliminated in combination. Minority interests have not been recorded due to insignificance.

Company Risk Factors—The Combined Companies are exposed to risks associated with the bankruptcy proceedings and risks associated with a highly leveraged organization. Such risks include: increased vulnerability to adverse economic and industry conditions, limited ability to fund future working capital, capital expenditures, business acquisitions or other corporate requirements, and possible liquidity problems, as well as financing and credit constraints (see Note 2).

F-39

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS—(CONTINUED)

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

Bankruptcy Accounting—In preparing the accompanying combined financial statements, the Combined Companies applied the provisions of SOP 90-7, which does not significantly change the application of accounting principles generally accepted in the United States of America; however, it does require that the combined financial statements for periods including and subsequent to filing the Chapter 11 petition distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business.

Cash and Cash Equivalents—The Combined Companies consider all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.

In the accompanying combined statements of cash flows for the period January 1, 2004 through September 30, 2004, and for the year ended December 31, 2003, we reclassified changes in restricted cash balances to be consistent with our 2005 presentation, to present such changes as an investing activity, which resulted in a decrease of $1,764 and $2,277, respectively, in investing cash flows and a corresponding increase for the period January 1, 2004 through September 30, 2004, and for the year ended December 31, 2003, in operating cash flows from the amounts previously reported.

Advance Royalties—The Combined Companies 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.

Property, Plant and Equipment—Property, plant and equipment, including coal lands and mine development costs 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. Coal land costs are depleted using the units-of-production method, based on estimated recoverable interest. Mine development costs are amortized using the units-of-production method, based on estimated recoverable interest. Other property, plant and equipment is depreciated using the straight-line method with estimated useful lives substantially as follows:


		Years
Buildings		10 to 45
Mining and other equipment and related facilities		1 to 20
Land improvements		15
Transportation equipment		2 to 7
Furniture and fixtures		3 to 10

Depreciation, depletion and amortization expense for property, plant and equipment for the Combined Companies for the period January 1, 2004 to September 30, 2004, excluding depreciation allocated from affiliates, was $27,547 and year ended December 31, 2003 was $52,254.

Debt Issuance Costs—Debt issuance costs reflect fees incurred to obtain financing. Debt issuance costs are amortized (included in interest expense) using the effective interest method, over the life of the related debt.

F-40

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS—(CONTINUED)

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

Amortization expense for the nine months ended September 30, 2004 and the year ended December 31, 2003 was $1,437 and $3,698, respectively.

The Combined Companies file a consolidated federal income tax return that includes other subsidiaries of Horizon Natural Resources Company. Consolidated net operating losses are allocated to the various subsidiaries in accordance with IRS regulations and may not reflect actual losses incurred by the Combined Companies on a stand alone basis.

Revenue Recognition—Most revenues result from sales under long-term sales contracts with electric utilities, industrial companies or other coal-consuming organizations, primarily in the eastern United States. Revenues are recognized on coal sales in accordance with the terms of the sales agreement, which is usually when the coal is shipped to the customers and title has passed.

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

Other revenues generally consist of equipment and parts sales, equipment rebuild and maintenance services, coal handling and processing, royalties, commissions on coal trades, contract mining and rental income. These revenues are recognized in the period earned or when the service is completed. Advance payments received are deferred and recognized in revenue as coal is shipped or rentals are earned.

Management’s Use of Estimates—The preparation of the combined financial statements in conformity with U.S. generally accepted accounting principles 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 the allowance for doubtful accounts; inventories; coal lands; asset retirement obligations; employee benefit liabilities; future cash flows associated with assets; useful lives for depreciation, depletion and amortization; workers’ compensation claims; postretirement benefits other than pensions; income taxes; and fair value of financial instruments. Due to the subjective nature of these estimates, actual results could differ from those estimates.

Statements of Cash Flows—Supplemental disclosure:


	January 1, 2004 to September 30, 2004			Year ended December 31, 2003
Cash paid for interest	$	9,268		$	7,797
Income taxes paid (refunded)		(69	)		38

Non-cash transactions excluded from the December 31, 2003 Combined Statement of Cash Flows are comprised of a non-cash settlement involving the exchange of accrued expenses of $1,652 for accounts receivables of $1,652 and prepaid insurance financing through the issuance of current debt obligations of

F-41

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS—(CONTINUED)

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

$13,927. Non cash transactions excluded from the January 1, 2004 to September 30, 2004 and the December 31, 2003 Combined Statements of Cash Flows are comprised of $0 and $205, respectively, of additions to property, plant and equipment through the incurrence of capital lease obligations.

Comprehensive Income or Loss—Under generally accepted accounting principles other comprehensive income or loss can include, among other items, foreign currency items, minimum pension liability adjustments and unrealized gains and losses on certain investments in debt and equity securities. The Combined Companies recorded minimum pension liability adjustments of $0 and $141 in Other Comprehensive Income (Loss) in members’ deficit as of September 30, 2004 and December 31, 2003, respectively, to properly record the pension liability in accordance with actuarial calculations. The Combined Companies had no other items of Other Comprehensive Income (Loss).

4. DEBT

Debtor-In-Possession Facility—The Company has a Debtor-in-Possession (‘DIP”) facility that provides revolving loans and letters of credit (with a sub-limit on the issuance of letters of credit) comprised on Tranche A DIP Loans and Tranche B DIP Letters of Credit and Credit-Linked Deposits with $125,000 and $150,000 originally available, respectively. The DIP Facility could have been increased to $350,000 if certain requirements had been met: (1) an additional $25,000 draw down capacity under the DIP Facility if the lender approved Horizon’s, including the Combined Companies’, five-year business plan and (2) an additional $50,000 draw down capacity under the DIP Facility if the lender syndicated a portion of the DIP Facility. However, these requirements were not met, and the DIP Facility was not increased. The DIP Facility agreement was amended as of June 30 2004, and all defaults were waived. The maturity date is October 15, 2004. In addition, the maturity date may be extended to November 15, 2004, based on the sole discretion of the lender. The DIP Facility has been reduced by proceeds from asset sales, tax refunds and negotiations with the lender totaling $79,858. On August 18, 2004, the lender decreased the Combined Companies’ draw down capacity to $195,142.

Loans under the credit agreement bear interest, at the Combined Companies’ option, at either a market base rate plus 4.5% per year or at a market reserved adjusted Euro-dollar rate plus 5.5% per year. The DIP Facility is collateralized primarily by capital stock of most of Horizon’s subsidiaries, along with substantially all accounts receivable, inventory, property, plant and equipment, intangible assets, contract rights and other personal and real property of Horizon and most of its subsidiaries, including the Combined Companies. As of September 30, 2004 and December 31, 2003, the Combined Companies had $5,805 and $23,320 available on this revolving credit agreement, respectively, net of $159,851 and $155,688 in letters of credit, respectively.

As of September 30, 2004 and December 31, 2003 letters of credit outstanding consisted of the following:


	September 30, 2004		December 31, 2003
Letters of Credit:
Insurance/Workers’ compensation/Reclamation bonds	$	159,851	$	155,238
Coal lands/Royalties		—		450

Total	$	159,851	$	155,688

As of September 30, 2004 and December 31, 2003, borrowings under the DIP Facility bear interest at variable rates ranging from 4.625% to 9.5%.

F-42

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS—(CONTINUED)

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

The DIP Facility and senior secured term notes contain customary covenants including, without limitation, restrictions on Horizon’s, including the Combined Companies’, ability to (i) incur additional indebtedness, pay dividends and make other restricted payments and investments; (ii) acquire or dispose of assets; (iii) engage in transactions with affiliates; and (iv) merge, consolidate, or transfer substantially all of its assets.

Horizon, including the Combined Companies, is also required to maintain compliance with a minimum trailing consolidated adjusted EBITDA covenant. Beginning December 2002, Horizon, including the Combined Companies, was in violation of various provisions of the DIP Facility. Horizon negotiated a waiver of these events of default with the administrative agent as of June 30, 2004.

Senior Secured Notes—The senior secured term notes bear interest at a market base rate plus 4.25% per year and mature on May 8, 2008. Principal payments of $5,000 per quarter are due on these notes. As of September 30, 2004, the interest rate is 9% plus an additional 2.0% penalty as Horizon, including the Combined Companies, is in violation of certain covenants.

The senior secured notes bear interest at the rate of 11.75% per annum payable semi-annually on May 15 and November 15 of each year with a final maturity date of May 8, 2009. As of September 30, 2004 the interest rate is 11.75% plus an additional 2.0% penalty as Horizon, including the Combined Companies, is in violation of certain covenants.

The senior secured notes contain covenants similar to those of the DIP Facility. As of September 30, 2004, Horizon, including the Combined Companies, was in violation of various financial and other covenants regarding the senior secured term notes and senior secured notes including the non-payment of principal and interest payments due giving rise to an Event of Default. During the default period, Horizon, including the Combined Companies, must pay or accrue an additional interest of 2.0% per year to the holders of such notes.

5. INCOME TAXES

Because of the Combined Companies’ continuing losses, no provision (benefit) for income taxes has been recorded in any period presented.

The following table presents the difference between the actual tax provision (benefit) and the amounts obtained by applying the statutory U.S. federal income tax rate of 35% to income and losses before income taxes.


	January 1, 2004 to September 30, 2004 (1)			January 1, 2003 to December 31, 2003 (1)
Federal benefit computed at statutory rate	$	(37,682	)	$	(61,860	)
State income tax benefit (net of federal tax benefits and apportionment factors) computed at statutory rate		(4,630	)		(7,600	)
Valuation allowance		43,099			70,509
Other		(787	)		(1,049	)

	$	—		$	—

(1)	As restated. See Note 12.

F-43

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS—(CONTINUED)

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

Prior to October 1, 2004, the Combined Companies filed a consolidated federal income tax return that included other subsidiaries of Horizon Natural Resources Company. Consolidated net operating losses were allocated to the various subsidiaries in accordance with IRS regulations and may not reflect actual losses incurred by the Combined Companies on a stand alone basis.

Based on such allocations and the reductions discussed above, at December 31, 2003 the Combined Companies had NOLs and alternative minimum tax (AMT) NOLs. Upon the sale to ICG effective September 30, 2004, these NOLs are no longer available due to a change in control.

6. EMPLOYEE BENEFITS

Certain employees of the Combined Companies were eligible to participate in defined benefit pension plans sponsored by Horizon and receive other postretirement benefits. On December 2, 2003, the Board of Directors of Horizon approved the termination of the Horizon NR, LLC Employee Pension Plan (“Horizon Pension Plan”). Effective March 31, 2004, an employee who was not a participant in the Plan on March 31, 2004, could not become a participant in the Horizon Pension Plan. No employee should accrue any additional pension credited service or days of service for any period after March 31, 2004. Effective March 31, 2004 Horizon froze all future accrual of benefits under the Horizon pension plan. On June 25, 2004 the Pension Benefit Guaranty Corporation announced that it would assume responsibility for the pensions of more than 4,800 Horizon employees. Accordingly, pension and other postretirement benefit information as of September 30, 2004 and for the period January 1, 2004 to September 30, 2004 for these carve-out financial statements is not applicable.

Benefits under the plans were generally related to an employees’ length of service and salary. Horizon allocated pension expense and other postretirement benefit expense to the Combined Companies based on actuarially determined amounts. The amount of pension cost and other postretirement benefit cost allocated to the Combined Companies was impacted by various assumptions (discount rate, rate of return on plan assets, etc.) that Horizon used in determining its pension and other postretirement obligations. Pension expense allocated to the Combined Companies totaled $388 for the period January 1, 2004 to September 30, 2004 and $2,013 for the year ended December 31, 2003. Other postretirement benefit expense allocated to the Combined Companies totaled $1,450 for the period January 1, 2004 to September 30, 2004 and $1,513 for the year ended December 31, 2003.

Valuation Date—All actuarially determined benefits were determined as of December 31, 2003.

Pension and Other Postretirement Benefits—The following pension and other postretirement benefit information was prepared for Horizon and its seventy-six subsidiaries for the year ended December 31, 2003.

In conjunction with certain 1998 and 1999 acquisitions, Horizon acquired, or agreed to put in place, benefit plans providing pension benefits to certain employees and postretirement healthcare and life insurance to eligible employees, including union employees.

During 1998, Horizon acquired a non-contributory defined benefit pension plan covering all salaried and non-union employees of an acquired company. Effective January 1, 1999, Horizon amended and restated this plan to cover all salaried and non-union employees of Horizon, including the employees of the Combined

F-44

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS—(CONTINUED)

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

Companies. Benefits are generally based on the employee’s years of service and compensation during each year of employment. Horizon’s funding policy is to make the minimum payment required by the Employee Retirement Income Security Act of 1974 (“ERISA”).

Net periodic benefit costs of Horizon and all of its subsidiaries, including the Combined Companies were as follows:


	Pension Benefits
	January 1, 2003 to December 31, 2003
Net periodic benefit cost:
Service cost	$	2,999
Interest cost		6,098
Settlement charge		2,184
Expected return on assets		(5,468	)
Amortization of:
Prior service cost		(72	)
Actuarial loss		21

Benefit cost	$	5,762


	Other Postretirement Benefits
	January 1, 2003 to December 31, 2003
Net periodic benefit cost:
Service cost	$	6,251
Interest cost		42,278
Amortization of—Actuarial loss		897

Benefit cost	$	49,426

For measurement purposes, a 10% annual rate of increase in the per capita cost of covered health care benefits was assumed, gradually decreasing to 5% in 2010 and remaining level thereafter.

Net periodic benefit cost is determined using the assumptions as of the beginning of the year.

The expense estimates can fluctuate by significant amounts based upon the assumptions used by the actuaries. As of December 31, 2003, a one-percentage-point change in assumed health care cost trend rates would have the following effects on the amounts presented previously for the Horizon postretirement benefit plan:


	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total of service and interest cost components	$	6,300	$	(5,200	)

F-45

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS—(CONTINUED)

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

Workers’ Compensation and Black Lung—The operations of the Combined Companies are subject to 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 Combined Companies’ subsidiary operations are either fully insured or self-insured for their workers’ compensation and black lung obligations.

The Combined Companies recorded expenses related to self-insured workers’ compensation and black lung of $1,512 for the period January 1, 2004 to September 30, 2004 and $2,806 for the year ended December 31, 2003.

401(k) Plan—The Combined Companies sponsor savings and retirement plans for substantially all employees. The plans match voluntary contributions of participants up to a maximum contribution based upon a percentage of a participant’s salary with an additional matching contribution possible at the Combined Companies’ discretion. The expense under these plans for the Combined Companies was $2,488 and $1,897 for the period January 1, 2004 to September 30, 2004 and the year ended December 31, 2003, respectively.

7. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingency—As of September 30, 2004, the Combined Companies had commitments under eighteen sales contracts to deliver annually scheduled base quantities of coal to fifteen customers. The contracts expire from 2004 through 2020 with the Combined Companies contracted to supply a minimum of approximately 64 million tons of coal over the remaining lives of the contracts (maximum of approximately 16 million tons in 2004). The Combined Companies also has commitments to purchase certain amounts of coal to meet its sales commitments. The purchase coal contracts expire through 2006 and provide the Combined Companies a minimum of approximately 5.9 million tons of coal through the remaining lives of the contracts (approximately 2.6 million tons per year). Certain of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

Leases—The Combined Companies lease various mining, transportation and other equipment under operating and capital leases. Lease expense for the period January 1, 2004 to September 30, 2004 and the year ended December 31, 2003 was $17,711 and $23,302, respectively. Depreciation of assets under capital leases is included in depreciation expense.

The Combined Companies also lease coal lands under agreements that call for royalties to be paid as the coal is mined. Total royalty expense for the period January 1, 2004 through September 30, 2004 and the year ended December 31, 2003 was approximately $13,854 and $16,726, respectively.

Legal Matters—From time to time, the Combined Companies are involved in legal proceedings arising in the ordinary course of business. In the opinion of management the Combined Companies have recorded adequate reserves for these liabilities and there is no individual case or group of related cases pending that is likely to have a material adverse effect on the financial condition, results of operations or cash flows of the Combined Companies. With respect to any claims relating to Horizon which arose prior to November 12, 2002, such claims are subject to an automatic stay of the U.S. Bankruptcy Code. In limited circumstances, the Bankruptcy Court has lifted the stay but only to the extent of insurance coverage relating to Horizon.

Commissions—The Combined Companies have various sales and agency agreements with third parties, whereby they pay a $.10—$2.75 per ton commission on various coal sales agreements. The costs are expensed as

F-46

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS—(CONTINUED)

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

the coal is delivered. The Combined Companies incurred commission expense of $303 for the period January 1, 2004 to September 30, 2004 and $1,706 for the year ended December 31, 2003, respectively.

Environmental Matters—Based upon current knowledge, the Combined Companies believe they are in material compliance with environmental laws and regulations as currently promulgated. However, the exact nature of environmental control problems, if any, which the Combined Companies 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.

Contract Mining Agreements—The Combined Companies perform contract-mining services for various third parties and utilize contract miners on some of its operations. Terms of the agreements generally allow either party to terminate the agreements on a short-term basis.

In October 2002, Horizon NR, LLC’s subsidiary, Mining Technologies, Inc. (MTI), entered into a five year contract for work beginning in April 2003 to provide mining services for a period of five years or until all mineable coal is removed. MTI is expected to produce and deliver a minimum of 500,000 tons per year up to a maximum of 1,500,000 tons per year. The guaranteed monthly contract tonnage shall be mutually agreed upon. Failure to meet the guaranteed contract tonnage for three consecutive months may result in termination of the contract. All work under the contract must be completed no later than March 31, 2008.

In December 2003, MTI entered into a three year contract for work beginning in January 2004 to provide mining services for a period of three years or until all mineable coal is removed. MTI is expected to produce and deliver a minimum of 50,000 tons of coal per month that has an ash content of less than fifteen percent. Failure to meet the guaranteed contract tonnage and ash requirements for three consecutive months may result in termination of the contract. All work under the contract must be completed no later than January 15, 2007.

On February 1, 2004 MTI and Lauren Land agreed to the assumption and amendment of three highwall mining system lease agreements between them. The three leases ran for various remaining terms ranging from 2004 to 2009. Subject to Bankruptcy Court approval, the agreement called for MTI to assume and amend the leases by accepting prepayment of all rentals due or to become due during the current term, plus extensions, of the three leases, and to grant to Lauren an option to purchase any or all of the leased systems for the price of $200 each. As of February 1, 2004 Lauren’s lease payment obligations for all three leases totaled $9,500. Bankruptcy Court approval was received and the transaction closed on June 18, 2004.

8. MAJOR CUSTOMERS

The Company and Predecessor Companies have coal sales to the following major customers that in any period equaled or exceeded 10% of revenues:


	2004		2003
	January 1, 2004 to September 30, 2004 Total Revenues		January 1, 2003 to December 31, 2003 Total Revenues
Customer A	$	44,788	$	119,817
Customer B		58,712		89,459
Customer C		36,244		42,317

F-47

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS—(CONTINUED)

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

9. WRITEDOWNS AND OTHER ITEMS


	January 1, 2004 to September 30, 2004		Year Ended December 31, 2003
Sale of mineral rights, equipment and impairment of operating assets	$	10,018	$	6,416
Inventory writedown and other		—		2,684

Total	$	10,018	$	9,100

After the petition date, the Combined Companies identified certain non-core assets to be sold to generate cash flow. The decision was based on the relative value of these assets to the Combined Companies and the applicability of them to the long-term mine plan. During the period of January 1, 2004 to September 30, 2004 a $13,327 loss was recognized on the sale of coal lands, a $7,736 gain on lease buyout, a loss on retirement of highwall mining system of $6,168 and other gains of $1,741.

SFAS No. 144 addresses the applicable accounting when companies are unable to generate sufficient cash flows to recover the carrying amount of its fixed assets, coal lands, contract costs, development costs and long-term advance royalties. As a result of applying SFAS No. 144 for the year ending December 31, 2003, the Combined Companies wrote down assets aggregating $6,416. These losses resulted from deteriorating market conditions, poor mining conditions and a change in mine plans.

For the year ended December 31, 2003, the Combined Companies wrote down parts inventory of $2,677 as a result of the annual physical inventory at a subsidiary warehouse and incurred other writedowns of $7.

10. REORGANIZATION ITEMS


	January 1, 2004 to September 30, 2004			Year Ended December 31, 2003
Bankrupty related reorganization expenses, including professional services fees and labor costs	$	(12,471	)	$	(23,064	)

Total	$	(12,471	)	$	(23,064	)

11. 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 and Illinois basin regions. The Company has two reportable business segments: Central Appalachian (into which four operating segments, ICG Eastern, ICG East Kentucky, ICG Knott County and ICG Hazard have been aggregated), comprised of both surface and underground mines, and ICG Illinois, representing one underground mine located in the Illinois basin. The Ancillary category includes the Company’s brokered coal functions, corporate overhead, contract highwall mining services and land activities.

F-48

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS—(CONTINUED)

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

The difference between segment assets and consolidated assets in the following table is the elimination of intercompany transactions including inter-segment revenues and investment in subsidiaries reflected in the elimination category. Reportable segment results for operations and cash flows for the nine months ended September 30, 2004 were as follows:


	Central Appalachian		Illinois Basin		Ancillary		Eliminations			Consolidated
Revenue	$	252,669	$	38,306	$	83,693	$	(1,285	)	$	373,383
EBITDA		28,376		5,243		476		—			34,095
Depreciation, depletion and amortization		20,348		2,568		4,631		—			27,547
Capital expenditures		4,309		1,263		1,052		—			6,624

Revenue in the Ancillary category consists of $63,265 relating to the Company’s brokered coal sales, $15,971 relating to contract highwall mining activities and $4,457 primarily consisting of royalty and rental income.

Reportable segment results for operations and cash flows for the twelve months ended December 31, 2003 were as follows:


	Central Appalachian		Illinois Basin		Ancillary		Eliminations			Consolidated
Revenue	$	281,488	$	49,904	$	151,419	$	(1,741	)	$	481,070
EBITDA		2,915		7,438		11,050		—			21,403
Depreciation, depletion and amortization		29,239		3,954		19,061		—			52,254
Capital expenditures		11,252		784		4,901		—			16,937

Revenue in the Ancillary category consists primarily of $123,927 relating to the Company’s brokered coal sales, $13,702 relating to contract highwall mining activities and $13,790 primarily consisting of royalty and rental income.

Reconciliation of net loss to EBITDA is as follows:


	Nine months ended September 30, 2004			Twelve months ended December 31, 2003
Net loss	$	(107,663	)	$	(176,743	)
Depreciation, depletion and amortization		27,547			52,254
Interest expense		114,211			145,892

EBITDA	$	34,095		$	21,403

F-49

HORIZON NR, LLC AND CERTAIN SUBSIDIARIES (PREDECESSOR TO INTERNATIONAL COAL GROUP, INC.)

NOTES TO COMBINED FINANCIAL STATEMENTS—(CONTINUED)

For the period January 1, 2004 to September 30, 2004 and the year ended

December 31, 2003

(Dollars in thousands)

12. RESTATEMENTS

Subsequent to its issuance of the Company’s financial statements, the Company’s management determined that information about its reportable segments should be included in the notes to the financial statements. As a result the Company has now included such information in Note 11.

Additionally, subsequent to the issuance of the Company’s financial statements, the Company’s management determined that certain write-offs of amounts due from/due to other Horizon subsidiaries, recorded as reorganization items in connection with preparation of carve-out financial statements (see Note 1), should not have been recorded. The effects of correcting these write-offs are summarized below:


	Period from January 1, 2004 to September 30, 2004			Year Ended December 31, 2003
Reorganization items:
As reported	$	727		$	(52,784	)
Adjustment		(13,198	)		29,720

As restated	$	(12,471	)	$	(23,064	)

F-50

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of International Coal Group, Inc.

We have audited the consolidated financial statements of International Coal Group, Inc. and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and for the year ended December 31, 2005 and the period from May 13, 2004 (inception) to December 31, 2004, and have issued our report thereon dated March 30, 2006; such report is included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company listed in Item 15(c). This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audit. In our opinion, the financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Cincinnati, Ohio

March 30, 2006

F-51

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Horizon NR, LLC and Certain Subsidiaries

We have audited the combined statements of operations, members’ deficit and cash flows of Horizon NR, LLC and Certain Subsidiaries (“Horizon”) for the period January 1, 2004 to September 30, 2004 and for the year ended December 31, 2003, and have issued our report thereon dated March 25, 2005, (September 20, 2005 as to Note 12) (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the restatements discussed in Note 12); such report is included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of Horizon listed in Item 15(c). This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note A to the accompanying financial statement schedule, such schedule has been restated.

/s/ Deloitte & Touche LLP

Louisville, Kentucky

April 22, 2005 (June 8, 2005 as to the effect of the restatement discussed in Note A to the schedule)

F-52

Schedule II — Valuation and Qualifying Accounts (As Restated, See Note A)


Description	Balance at Beginning of Period		Charged to Revenue, Costs or Expenses			Other Additions (Deductions)			Balance at End of Period
Year ended December 31, 2005		(Dollars in thousands)
(International Coal Group, Inc.)
Reserve for inventory obsolescence	$	74	$	237		$	—		$	311
Period from May 13, 2004 to December 31, 2004
(International Coal Group, Inc.):
Reserve for inventory obsolescence				74						74
Period ended September 30, 2004
(Predecessor Horizon):
Allowance for doubtful accounts		7,798		1,590			(3,947	)(1)		5,441
Reserve for inventory obsolescence		2,803					(6	)(2)		2,797
Allowance for doubtful Notes		2,422		(442	)					1,980
Reserve for loss — Advance Royalties		1,000								1,000
Year ended December 31, 2003
(Predecessor Horizon):
Allowance for doubtful accounts		9,453		(1,115	)		(540	)(1)		7,798
Reserve for inventory obsolescence		2,485		(190	)		508	(2)		2,803
Allowance for doubtful Notes		2,451		(29	)					2,422
Reserve for loss — Advance Royalties		1,000								1,000

(1)

Reflects adjustment to allowance due to settlement of outstanding claims of predecessor.

(2)

Reflects adjustment of reserve based on annual physical inventory counts.

Note A—Amounts

for the period from May 13, 2004 to December 31, 2004 have been restated to correct the allocation of the purchase price. Certain amounts in other periods have been reclassified between amounts charged to revenues, costs or expenses, and other additions (deductions). A summary of the restatement is as follows:


	As Previously Reported			As Restated
	(Dollars in thousands)
Period from May 13, 2004 to December 31, 2004 (International Coal Group, Inc.):
Other additions (deductions):
Allowance for doubtful accounts	$	2,669		$	—
Reserve for inventory obsolescence		3,015			—
Reserve for loss — Advance Royalties		3,110			—
Charged to revenue, costs or expenses:
Reserve for loss — Advance Royalties		(8	)		—
Period ended September 30, 2004 (Predecessor Horizon):
Charged to revenue, costs or expenses:
Allowance for doubtful accounts		(2,357	)		1,590
Reserve for inventory obsolescence		(6	)		—
Other additions (deductions):
Allowance for doubtful accounts		—			(3,947	)
Reserve for inventory obsolescence		—			(6	)
Year ended December 31, 2003 (Predecessor Horizon):
Charged to revenue, costs or expenses:
Allowance for doubtful accounts		(1,655	)		(1,115	)
Reserve for inventory obsolescence		318			(190	)
Other additions (deductions):
Allowance for doubtful accounts		—			(540	)
Reserve for inventory obsolescence		—			508

F-53

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: March 30, 2006


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 Bennett K. Hatfield	President and Chief Executive Officer and Director (Principal Executive Officer)	March 30, 2006

/s/ William D. Campbell William D. Campbell	Vice President, Treasurer and Secretary (Principal Accounting and Principal Financial Officer)	March 30, 2006

* Wilbur L. Ross, Jr.	Non-Executive Chairman and Director	March 30, 2006

* Jon R. Bauer	Director	March 30, 2006

* Cynthia B. Bezik	Director	March 30, 2006

* William J. Catacosinos	Director	March 30, 2006

* Marcia L. Page	Director	March 30, 2006

* Wendy L. Teramoto	Director	March 30, 2006

*	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


	EXHIBIT INDEX

Exhibit No.	Description	Note

2.1	Business Combination Agreement among International Coal Group, Inc. (n/k/a ICG, Inc.), ICG Holdco, Inc. (n/k/a International Coal Group, Inc.), ICG Merger Sub, Inc., Anker Merger Sub, Inc. and Anker Coal Group, Inc., dated as of March 31, 2005	(B	)

2.2	First Amendment to the Business Combination Agreement among International Coal Group, Inc. (f/k/a ICG Holdco, Inc.), ICG, Inc. (f/k/a International Coal Group, Inc.), ICG Merger Sub, Inc., Anker Merger Sub, Inc. and Anker Coal Group, Inc., dated as of May 10, 2005	(B	)

2.3	Second Amendment to the Business Combination Agreement among International Coal Group, Inc. (f/k/a ICG Holdco, Inc.), ICG, Inc. (f/k/a International Coal Group, Inc.), ICG Merger Sub, Inc., Anker Merger Sub, Inc. and Anker Coal Group, Inc., effective as of June 29, 2005	(D	)

2.4	Business Combination Agreement among International Coal Group, Inc. (n/k/a ICG, Inc.), ICG Holdco, Inc. (n/k/a International Coal Group, Inc.), CoalQuest Merger Sub LLC, CoalQuest Development LLC and the members of CoalQuest Development LLC, dated as of March 31, 2005	(B	)

2.5	First Amendment to the Business Combination Agreement among International Coal Group, Inc. (f/k/a ICG Holdco, Inc.), ICG, Inc. (f/k/a International Coal Group, Inc.), CoalQuest Merger Sub LLC, CoalQuest Development LLC and the members of CoalQuest Development LLC, dated as of May 10, 2005	(B	)

2.6	Second Amendment to the Business Combination Agreement among International Coal Group, Inc. (f/k/a ICG Holdco, Inc.), ICG, Inc. (f/k/a International Coal Group, Inc.), CoalQuest Merger Sub LLC, CoalQuest Development LLC and the members of CoalQuest Development LLC, effective as of June 29, 2005	(D	)

3.1	Form of Second Amended and Restated Certificate of Incorporation of International Coal Group, Inc.	(H	)

3.2	Form of Second Amended and Restated By-laws of International Coal Group, Inc.	(I	)

4.1	Form of certificate of International Coal Group, Inc. common stock	(E	)

4.2	Registration Rights Agreement by and between International Coal Group, Inc., WLR Recovery Fund II, L.P., Contrarian Capital Management LLC, Värde Partners, Inc., Greenlight Capital, Inc., and Stark Trading, Shepherd International Coal Holdings Inc.	(B	)

4.3	Form of Registration Rights Agreement between International Coal Group, Inc. and certain former Anker stockholders and CoalQuest members	(D	)

10.1	Amended and Restated Credit Agreement dated as of November 5, 2004 among ICG, LLC, as Borrower, International Coal Group Inc. (n/k/a ICG, Inc.), the guarantors party thereto, UBS Securities LLC, as Arranger, Bookmanager and Syndication Agent, General Electric Capital Corporation, as Documentation Agent, UBS AG, Stamford Branch, as Issuing Bank, Administrative Agent and Collateral Agent, and UBS Loan Finance, LLC, as Swingline Lender	(A	)


Exhibit No.	Description	Note

10.2	First Amendment, dated as of November 30, 2004, to the Amended and Restated Credit Agreement dated as of November 5, 2004 among ICG, LLC, as Borrower, International Coal Group Inc., the guarantors party thereto, UBS Securities LLC, as Arranger, Bookmanager and Syndication Agent, General Electric Capital Corporation, as Documentation Agent, UBS AG, Stamford Branch, as Issuing Bank, Administrative Agent and Collateral Agent, and UBS Loan Finance, LLC, as Swingline Lender	(A	)

10.3	Security Agreement dated as of September 30, 2004 among ICG, LLC and the guarantors party thereto and UBS AG, Stamford Branch, as Collateral Agent	(A	)

10.4	Advisory Services Agreement effective as of October 1, 2004 between International Coal Group, LLC and W.L. Ross & Co. LLC	(A	)

10.5	Employment Agreement dated March 14, 2005 by and between Bennett K. Hatfield and International Coal Group, Inc.	(A	)

10.6	Employment Agreement dated April 25, 2005 by and between Roger L. Nicholson and International Coal Group, Inc.	(B	)

10.7	Fee Lease between Kentucky Union Company, lessor, and ICG Hazard, LLC (assigned from Leslie Resources, Inc.), lessee, of Flint Ridge Surface Mine, amended by: (a) Assignment of Real Property Agreements, dated September 30, 2004, assigning to ICG Hazard, LLC	(D	)

10.8	Fee Lease between Pocahontas Development Corp., lessor, and ICG East Kentucky, LLC (assigned from Sunny Ridge Enterprises, Inc.), lessee, of Blackberry Creek Surface Mine, amended by:	(D	)
	(a) Supplemental Lease and Agreement, dated May 26, 1998
	(b) Supplemental Lease and Agreement, dated October 27, 1998
	(c) Supplemental Lease and Agreement, dated November 22, 1999
	(d) Supplemental Lease and Agreement, dated May 30, 2001
	(e) Partial Lease and Amendment of Lease, dated August 21, 2003
	(f) Assignment of Real Property Agreements, dated September 30, 2004, assigning to ICG East Kentucky, LLC

10.9	Coal Lease between N&G Holdings Company, lessor, and ICG Hazard, LLC (assigned from Leslie Resources, Inc.), lessee, of Vicco Surface Mine, amended by:	(D	)
	(a) Assignment of Real Property Agreements, dated September 30, 2004, assigning to ICG Hazard, LLC

10.10	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:	(D	)
	(a) Partial Assignment of Lease, dated September 20, 1984, assigning to Twin River Coal Co.
	(b) General Conveyance, Assignment and Transfer, dated December 8, 1988, assigning to Island Creek Coal Co.
	(c) Assignment, dated December 12, 1990, assigning to Laurel Run Mining Co.
	(d) Consent Letter, dated as of October 25, 1995
	(e) Partial Assignment, dated October 30, 1995, assigning to East Kentucky Energy Corp.
	(f) Assignment, dated October 30, 1995, assigning to East Kentucky Energy Corp.
	(g) Assignment of Real Property Agreements, dated September 30, 2004, assigning to ICG Eastern, LLC


Exhibit No.	Description	Note

10.11	Surface 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:	(D	)
	(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

10.12	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:	(D	)

	(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

10.13	Fee Lease between M-B, LLC, lessor, and ICG Eastern, LLC (assigned from ANR Coal Development Company), lessee, of Birch River Mine, amended by:	(D	)

	(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 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:	(D	)

	(a) Assignment of Real Property Agreements, dated September 30, 2004, assigning to ICG Hazard, LLC

10.15	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:	(D	)
	(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

10.16	Fee Lease between Bach, et al., lessor, and ICG Hazard, LLC (assigned from Ark Land Company), lessee, of the Flint Ridge preparation plant site, amended by:	(D	)
	(a) Consent to Sublease, dated and effective October 28, 1982
	(b) Sublease Agreement, dated and effective October 28, 1982
	(c) Consent to Assignment of Lease, Estoppel Certificate and Amendment of Lease, dated October 26, 1998
	(d) Assignment of Lease, dated November 25, 1998, assigning to Leslie Resources, Inc.


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:	(D	)
	(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

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, Inc.), ICG Beckley (successor-in-interest to Winding Gulf Coals, Inc.), lessee, of Beckley Mine, including:	(D	)
	(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

10.19	Lease between Beaver Coal Corporation, lessor, and Wolf Run Mining Company (f/k/a Anker West Virginia Mining Company, Inc.), ICG Beckley (successor-in-interest to New River Company), lessee, of Beckley Mine, including:	(D	)
	(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:	(D	)
	(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

10.21	Lease between Southern Region Industrial Realty, Inc., lessor, and White Wolf Energy, Inc. (f/k/a Anker Virginia Mining Company, Inc. ) (successor-in-interest to Advantage Energy Corp.), lessee, of War Creek Mine, including:	(D	)
	(a) Letter Agreement, dated and effective September 9, 1997
	(b) Amendment, dated and effective August 1, 2002

10.22	Sublease between Reserve Coal Properties, sublessors, and Patriot Mining Company, sublessee, of Sycamore No. 2 Mine	(D	)

10.23	Intentionally left blank.


Exhibit No.		Description	Note

10.24	**	Agreement for Purchase and Sales of Coal, dated April 10, 2003 and effective January 1, 2004, between Georgia Power Company and ICG, LLC (assigned from Horizon Natural Resources Company)	(J	)

10.25		Second Amendment, dated as of June 29, 2005, to the Amended and Restated Credit Agreement dated as of November 5, 2004 among ICG, LLC, as Borrower, International Coal Group Inc., the guarantors party thereto, UBS Securities LLC, as Arranger, Bookmanager and Syndication Agent, General Electric Capital Corporation, as Documentation Agent, UBS AG, Stamford Branch, as Issuing Bank, Administrative Agent and Collateral Agent, and UBS Loan Finance, LLC, as Swingline Lender	(E	)

10.26		International Coal Group, Inc. 2005 Equity and Performance Incentive Plan	(E	)

10.27		International Coal Group, Inc. 2005 Equity and Performance Incentive Plan: Incentive Stock Option Agreement	(E	)

10.28		International Coal Group, Inc. 2005 Equity and Performance Incentive Plan: Non-Qualified Stock Option Agreement	(E	)

10.29		International Coal Group, Inc. 2005 Equity and Performance Incentive Plan: Restricted Share Agreement	(E	)

10.30		Form of Indemnification Agreement	(E	)

10.31		Third Amendment, dated as of February 22, 2006, to the Amended and Restated Credit Agreement dated as of November 5, 2004 among ICG, LLC, as Borrower, International Coal Group Inc., the guarantors party thereto, UBS Securities LLC, as Arranger, Bookmanager and Syndication Agent, General Electric Capital Corporation, as Documentation Agent, UBS AG, Stamford Branch, as Issuing Bank, Administrative Agent and Collateral Agent, and UBS Loan Finance, LLC, as Swingline Lender.	(F	)

10.32		Fourth Amendment, dated as of March 21, 2006, to the Amended and Restated Credit Agreement dated as of November 5, 2004 among ICG, LLC, as Borrower, International Coal Group Inc., the guarantors party thereto, UBS Securities LLC, as Arranger, Bookmanager and Syndication Agent, General Electric Capital Corporation, as Documentation Agent, UBS AG, Stamford Branch, as Issuing Bank, Administrative Agent and Collateral Agent, and UBS Loan Finance, LLC, as Swingline Lender.	(F	)

11.1		Statement Regarding Computation of Per Share Earnings	(F	)

21.1		List of Subsidiaries	(F	)

23.1		Consent of Deloitte & Touche, LLP	(F	)

23.2		Consent of Deloitte & Touche, LLP	(F	)

24.1		Power of Attorney	(F	)

31.1		Certification of the Chief Executive Officer	(F	)

31.2		Certification of the Principal Financial Officer	(F	)

32.1		Certification Pursuant to §906 of the Sabares Oxley Act of 2002	(F	)

(A)	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.

(B)	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.

(C)	Previously filed as an exhibit to International Coal Group, Inc.’s Registration Statement on Form S-4 (Reg. No. 333-126156), filed on June 27, 2005.

(D)	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.

(E)	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.

(F)	Filed herewith.

(G)	Previously filed as an exhibit to Amendment No. 1 to International Coal Group, Inc.’s Registration Statement of Form S-4 (Reg. No. 333-126156), filed on September 28, 2005.

(H)	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.

(I)	Previously filed as an exhibit to Amendment No. 5 to International Coal Group, Inc.’s Registration Statement on Form S-1 (Reg. No. 333-124393), filed on November 9, 2005.

(J)	Previously filed as an exhibit to Amendment No. 5 to International Coal Group, Inc.’s Registration Statement on Form S-1 (Reg. No. 333-124393), filed on November 14, 2005.

**	Confidential treatment requested as to certain portions that have been omitted and filed separately with the Securities and Exchange Commission.