UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
DC 20549





FORM
10-K/A


(Amendment
No. 1)


(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, 2008


OR





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





Commission
file number: 001-32679







International
Coal Group, Inc.


(Exact
Name of Registrant as Specified in Its Charter)





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





300
Corporate Centre Drive


Scott
Depot, WV 25560


(Address
of Principal Executive Offices—Zip Code)





(304)
760-2400


(Registrant’s
Telephone Number, Including Area Code)





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





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


None.





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





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





Indicate
by check mark whether the registrant: (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.  Yes  x      No   ̈





Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.      Yes  x      No   ̈





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





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





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





Aggregate
market value of common stock held by non-affiliates of the registrant as of
June 30, 2008, the last business day of the registrant’s most recently
completed second fiscal quarter, at a closing price of $13.05 per share as
reported by the New York Stock Exchange, was $1,392,427,588. 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 February 19, 2009 was
153,335,680.





DOCUMENTS
INCORPORATED BY REFERENCE





Part
III incorporates certain information by reference from the registrant’s
definitive proxy statement for the 2009 annual meeting of stockholders, which
proxy statement will be filed on or about April 15, 2009.











EXPLANATORY
NOTE





We
are filing this Form 10-K/A Amendment No. 1 (this “Amendment”) to amend and
restate certain information that was included in our original Annual Report on
Form 10-K for the year ended December 31, 2008 (the “2008 Form 10-K”) as
described below. For the convenience of the reader, this Amendment sets forth
the entire 2008 Form 10-K. However, this Amendment amends and restates only
Items 6, 7, 8 and 15 of Part II of the 2008 Form 10-K. The other Items are not
being amended. Except as described in this Explanatory Note, this Amendment does
not modify or update the disclosures in our 2008 Form 10-K. Therefore, this
Amendment does not reflect any other events that occurred after the original
February 27, 2009 filing date of the 2008 Form 10-K. Forward-looking statements
in this Amendment have also not been updated from the 2008 Form 10-K that we
filed on February 27, 2009. For updated information, please see the reports that
we have filed with the SEC for subsequent periods. In addition, in connection
with the filing of this Amendment and pursuant to Rules 12b-15 and 13a-14 under
the Exchange Act, we are including with this Amendment currently dated
certifications.





Subsequent to the issuance of our
consolidated financial statements for the year ended December 31, 2008, we
identified an error in the application of Statement of Financial Accounting
Standards No. 158,Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans—an
amendment of FASB Statements No. 87, 88, 106 and 132(R), on our employee benefits liability.
We had not previously recorded the unfunded status of our black lung obligation
as a liability in our statement of financial position or recognized changes in
the funded status of the obligation in the year in which the changes occurred
through comprehensive income. As a result of this error, as of December 31,
2008, we overstated our employee benefits liability by approximately $4.6
million and accumulated other comprehensive loss by approximately $2.9 million
and understated our deferred tax liability by approximately $1.7 million. As of
December 31, 2007, we overstated our employee benefits liability by
approximately $7.0 million and accumulated other comprehensive loss by
approximately $4.4 million and understated our deferred tax liability by
approximately $2.6 million. Additionally, comprehensive loss was understated by
approximately $1.5 million for the year ended December 31, 2008 and overstated
by approximately $2.3 million for the year ended December 31, 2007. We do not
believe these errors are material to the consolidated financial
statements. See Note 23
accompanying our consolidated financial statements for further information
regarding adjustment of the applicable financial statement line
items.





Additionally,
as disclosed in the 2008 Form 10-K, we adopted two new accounting standards
effective January 1, 2009 that require retrospective application. The revisions
relate to the retrospective adoption of: Accounting Standards Codification
(“ASC”) Subtopic 470-20-65-1,Transition Related to FASB Staff Position APB 14-1, Accounting for Convertible
Debt Instruments That May be Settled in Cash Upon Conversion (Including Partial
Cash Settlement)(“ASC 470-20-65-1”) (formerly FSP APB 14-1,Accounting for Convertible Debt
Instruments That May be Settled in Cash Upon Conversion (Including Partial Cash
Settlement)) and the provisions of ASC Subtopic 810-10-65-1,Transition Related to FASB
Statement No. 160, Noncontrolling Interests in Consolidated Financial
Statements–an amendment to ARB No. 51(“ASC 810-10-65-1”) (formerly SFAS
No. 160,Noncontrolling
Interests in Consolidated Financial Statements–an amendment to ARB No.
51). See Note 23 accompanying our consolidated financial statements for
further information regarding the impact of adoption of ASC 470-20-65-1 and ASC
810-10-65-1.











INDEX
TO ANNUAL REPORT


ON
FORM 10-K/A





Table
of Contents





Item 1.
            
            BUSINESS
            
            1Item 1A.
            
            RISK
      FACTORS
            
            32Item 1B.
            
            UNRESOLVED
      STAFF COMMENTS
            
            54Item 2.
            
            PROPERTIES
            
            55Item 3.
            
            LEGAL
      PROCEEDINGS
            
            61Item 4.
            
            SUBMISSION
      OF MATTERS TO A VOTE OF SECURITY HOLDERS
            
            63Item 5.
            
            MARKET
      FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
      PURCHASES OF EQUITY SECURITIES
            
            63Item 6.
            
            SELECTED
      FINANCIAL DATA
            
            65Item 7.
            
            MANAGEMENT’S
      DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
      OPERATIONS
            
            68Item 7A.
            
            QUANTITATIVE
      AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
            
            95Item 8.
            
            FINANCIAL
      STATEMENTS AND SUPPLEMENTARY DATA
            
            95Item 9.
            
            CHANGES
      IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
      DISCLOSURE
            
            95Item 9A.
            
            CONTROLS
      AND PROCEDURES
            
            96Item 9B.
            
            OTHER
      INFORMATION
            
            97Item 10.*
            
            DIRECTORS,
      EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
            
            97Item 11.*
            
            EXECUTIVE
      COMPENSATION
            
            97Item 12.*
            
            SECURITY
      OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
      STOCKHOLDER MATTERS
            
            97Item 13.*
            
            CERTAIN
      RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
      INDEPENDENCE
            
            97Item 14.*
            
            PRINCIPAL
      ACCOUNTANT FEES AND SERVICE
            
            97Item 15.
            
            EXHIBITS,
      FINANCIAL STATEMENT SCHEDULES
            
            98








*
            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 15, 2009.





i








SPECIAL
NOTE REGARDING FORWARD-LOOKING STATEMENTS





This
Annual Report on Form 10-K/A 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;•
            consummation
      of financing, acquisition or disposition transactions and the effect
      thereof on our business;•
            a
      significant number of conversions of our Convertible Senior Notes prior to
      maturity;•
            our
      plans and objectives for future operations and expansion or
      consolidation;•
            our
      relationships with, and other conditions affecting, our
      customers;•
            availability
      and costs of key supplies or commodities such as diesel fuel, steel,
      explosives and tires;•
            availability
      and costs of capital equipment;•
            prices
      of fuels which compete with or impact coal usage, such as oil and natural
      gas;•
            timing
      of reductions or increases in customer coal
inventories;•
            long-term
      coal supply arrangements;•
            risks
      in or related to coal mining operations, including risks relating to
      third-party suppliers and carriers operating at our mines or
      complexes;•
            unexpected
      maintenance and equipment failure;•
            environmental,
      safety and other laws and regulations, including those directly affecting
      our coal mining and production, and those affecting our customers’ coal
      usage;•
            ability
      to obtain and maintain all necessary governmental permits and
      authorizations;•
            competition
      among coal and other energy producers in the United States and
      internationally;•
            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;





ii







•
              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 or enforcement thereof, including with respect to
      safety enhancements and environmental initiatives relating to global
      warming;•
              impairment
      of the value of our long-lived and deferred tax assets;•
              our
      liquidity, including the ability to adhere to financial covenants related
      to our borrowing arrangements, results of operations and financial
      condition;•
              adequacy
      and sufficiency of our internal controls; and•
              legal
      and administrative proceedings, settlements, investigations and claims and
      the availability of related insurance coverage.






You should keep in
mind that any forward-looking statement made by us in this Annual Report on Form
10-K/A 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 2008 annual report to stockholders and our 2008 Annual Report
on Form 10-K/A 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 since
November 19, 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 12 of our mining complexes, are
located in West Virginia, Kentucky, Virginia and Maryland. We also have a
complementary mining complex of mid to high sulfur steam coal strategically
located in the Illinois Basin. We market our coal to a diverse customer
base of largely investment grade electric utilities, as well as domestic and
international industrial customers. The high quality of our coal and the
availability of multiple transportation options, including rail, truck and
barge, throughout the Appalachian region enable us to participate in both the
domestic and international coal markets. Appalachian coal markets exhibited
price volatility in 2008 that has continued into 2009.





ICG,
Inc. was formed by WL Ross & Co. LLC (“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 and are union free.
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 a corporate reorganization (described below) and acquired Anker and
CoalQuest in November 2005, which further diversified our coal
reserves.





1





As
of December 31, 2008, management estimates that we owned or controlled
approximately 328 million tons of metallurgical quality coal reserves and
approximately 689 million tons of steam coal reserves. Management’s estimates
were developed considering an initial evaluation, as well as subsequent
acquisitions, dispositions, depleted reserves, changes in available geological
or mining data and other factors. Further, we own or control approximately
521 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, 2008, we sold 18.9 million tons of coal, of which
approximately 17.9 million tons were produced from our mining activities and
approximately 1.0 million tons were purchased through brokered coal contracts
(coal purchased from third parties for resale), at an average sale price of
$53.22 and $45.10, respectively. Of the tons sold, 17.8 million tons were steam
coal and 1.1 million tons were metallurgical coal. Our steam coal sales volume
in 2008 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, 2008 were Progress Energy, Georgia
Power Company and Allegheny Energy Supply Company and we derived approximately
32% of our coal revenues from sales to our five largest customers. We did not
derive more than 10% of our coal sales revenues from any single customer in
2008.





We
have three reportable business segments, which are based on the coal regions in
which we operate: (i) Central Appalachian, comprised of both surface and
underground mines, (ii) Northern Appalachian, comprised of both surface and
underground mines and (iii) Illinois Basin, representing one underground
mine. Financial information concerning industry segments, as defined by
accounting principles generally accepted in the United States of America, as of
and for the years ended December 31, 2008, 2007 and 2006 is included in Note 20
to our consolidated financial statements included elsewhere in this
report.





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.





2





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.





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, among other things, 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. Other than the initial 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 21,000,000 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.





3





The
Coal Industry





A
major contributor to the world energy supply, coal represents over 26% 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 2008, coal-fired
plants generated approximately 49% 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 the most affordable source of power fuel per million Btu, averaging less
than one-quarter the price of both petroleum and natural gas.





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





Coal
Mining Methods





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





Underground
mining





Underground
mines in the United States are typically operated using one of two different
techniques: room-and-pillar mining or longwall mining. In 2008, approximately
43% of our produced and processed coal volume came from underground mining
operations 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.





4





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 our Hillman
property in Taylor County, West Virginia. In longwall mining, a rotating drum is
trammed mechanically across the face of coal and a hydraulic system supports the
roof of the mine while it advances through the coal. Chain conveyors then move
the loosened coal to an underground mine conveyor system for delivery to the
surface.





Surface
mining





Surface
mining is used when coal is found close to the surface. In 2008, approximately
57% 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.





We
use the following three 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 meeting the quality requirements of specific customer
contracts, while maximizing revenue through optimal use of coal
inventories.





5





Coal
Characteristics





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





Heat
Value





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





Bituminous
Coal





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





Sulfur
Content





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





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.





6





Operations





As
of December 31, 2008, we operated a total of 14 surface and 14 underground coal
mines located in Kentucky, Maryland, Virginia, West Virginia and Illinois.
Approximately 57% of our production has come from surface mines, and the
remaining production has come from our underground mines. These mining
facilities include 10 preparation plants, each of which receive, blend, process
and ship coal that is produced from one or more of our 28 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, highwall contour and cross ridge operations using
truck/loader equipment fleets along with large production tractors. A dragline
is employed as the prime earthmover at one of our surface mines. Most of our
preparation plants are modern heavy media plants that generally have both coarse
and fine coal cleaning circuits. We currently own most of the equipment utilized
in our mining operations. We employ preventive maintenance and rebuild programs
to ensure that our equipment is modern and well maintained. The mobile equipment
utilized at our mining operations is replaced on an on-going basis with new,
more efficient units based on equipment age and mechanical condition. Each year
we endeavor to replace the oldest units, thereby maintaining productivity while
minimizing capital expenditures.





The
following table provides summary information regarding our principal active
operations as of December 31, 2008:





Number
      and
              Type
      of MinesMining Complexes(1)
            
            Location
            
            Preparation
              Plants
            
            
            Under-
              ground
            
            Surface
            
            Total
            
            Mining
              Method
      (2)
            
            Transportation
            
            Tons
              Produced
      in
              2008(in thousands)Eastern
            
            Cowen,
      WV
            
            1
            
            
            —
            
            1
            
            1
            
            MTR, DL, TSL
            
            Rail
            
            3,234.5Hazard
            
            Hazard,
      KY
            
            —
            
            
            —
            
            7
            
            7
            
            HW,
      MTR,
              TSL
            
            Rail,
      Truck
            
            4,055.9Flint
      Ridge
            
            Hazard,
      KY
            
            1
            
            
            3
            
            —
            
            3
            
            R&P
            
            Rail,
      Truck
            
            1,056.0Knott County
            
            Kite,
      KY
            
            1
            
            
            3
            
            —
            
            3
            
            R&P
            
            Rail
            
            948.4Raven
            
            Raven,
      KY
            
            1
            
            
            2
            
            —
            
            2
            
            R&P
            
            Rail
            
            664.3East
      Kentucky
            
            Pike
      Co., KY
            
            —
            
            
            —
            
            2
            
            2
            
            MTR,
      TSL
            
            Rail
            
            1,058.1Beckley
            
            Eccles,
      WV
            
            1
            
            
            1
            
            —
            
            1
            
            R&P
            
            Rail
            
            531.8Vindex
      Energy Corporation
            
            Garrett
      Co., MD
            
            1
            
            
            —
            
            3
            
            3
            
            CRM, TSL
            
            Truck, Rail
            
            939.1Patriot
      Mining Company
            
            Monongalia Co., WV
            
            —
            
            
            —
            
            1
            
            1
            
            CTR,
      TSL
            
            Barge, Rail, Truck
            
            929.6Wolf
      Run Mining Buckhannon Division
            
            Upshur Co., WV
            
            1
            
            
            2
            
            —
            
            2
            
            R&P
            
            Rail,
      Truck
            
            993.8Sentinel
            
            Barbour
      Co., WV
            
            1
            (3)
            
            1
            
            —
            
            1
            
            R&P
            
            Rail
            
            1,007.4Powell Mountain
            
            St.
      Charles, VA
            
            1
            
            
            1
            
            —
            
            1
            
            R&P
            
            Rail
            
            100.3Illinois
            
            Williamsville,
      IL
            
            1
            
            
            1
            
            —
            
            1
            
            R&P
            
            Truck
            
            2,261.0








(1)
            Does
      not include Juliana, an inactive mining complex.(2)
            CRM
      = Cross Ridge Mining; CTR = Contour Mining; R&P = Room-and-pillar; MTR
      = Mountain Top Removal; DL = Dragline; HW = Highwall; TSL = Truck and
      Shovel/Loader.(3)
            A
      portion of the complex currently utilizes one
  circuit.








7








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





2008
            
            2007
            
            2006Mining Complexes(1)
            
            Tons
              Produced
            
            Sales
              Realizations
      (2)
            
            Tons
              Produced
            
            Sales
              Realizations
      (2)
            
            Tons
              Produced
            
            Sales
              Realizations
      (2)Eastern
            
            3,234,517
            
            $
            55.36
            
            3,268,000
            
            $
            42.15
            
            3,048,800
            
            $
            43.92Hazard
            
            4,055,874
            
            $
            54.56
            
            3,868,959
            
            $
            45.04
            
            3,709,924
            
            $
            50.05Flint
      Ridge
            
            1,055,996
            
            $
            55.05
            
            1,306,428
            
            $
            45.49
            
            1,718,300
            
            $
            50.81Knott County
            
            948,445
            
            $
            52.57
            
            1,039,714
            
            $
            46.41
            
            1,268,617
            
            $
            51.51Raven
            
            664,265
            
            $
            54.45
            
            608,068
            
            $
            48.30
            
            246,570
            
            $
            48.52East
      Kentucky
            
            1,058,092
            
            $
            58.39
            
            1,001,911
            
            $
            51.42
            
            1,255,522
            
            $
            53.28Beckley(3)
            
            531,842
            
            $
            106.66
            
            39,748
            
            $
            72.82
            
            —
            
            $
            —Vindex
      Energy Corporation
            
            939,141
            
            $
            54.43
            
            853,695
            
            $
            36.83
            
            1,062,925
            
            $
            36.62Patriot
      Mining Company
            
            929,645
            
            $
            40.56
            
            885,108
            
            $
            25.12
            
            888,265
            
            $
            23.52Wolf
      Run Mining Buckhannon Division
            
            993,807
            
            $
            56.48
            
            636,002
            
            $
            41.94
            
            820,688
            
            $
            42.46Sentinel
            
            1,007,425
            
            $
            60.73
            
            681,814
            
            $
            47.22
            
            58,403
            
            $
            41.25Sycamore
      Group
            
            —
            (4)
            $
            —
            
            82,904
            
            $
            30.14
            
            347,241
            
            $
            29.13Powell Mountain(5)
            
            100,322
            
            $
            132.17
            
            —
            
            $
            —
            
            —
            
            $
            —Illinois
            
            2,261,028
            
            $
            29.94
            
            2,085,495
            
            $
            29.84
            
            2,084,193
            
            $
            24.6817,780,399
            
            
            
            
            16,357,846
            
            
            
            
            16,509,448







(1)
            Does
      not include Juliana, an inactive mining complex.(2)
            Excludes
      freight and handling revenue.(3)
            Beckley
      was in development until the fall of 2008.(4)
            The
      Sycamore No. 1 mine was depleted and reclaimed in 2007.(5)
            Powell
      Mountain was acquired in 2008.







8








Northern
and Central Appalachia Mining Operations





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











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





Our
mines in Central Appalachia produced 11.6 million tons of coal in 2008 and
our mines in Northern Appalachia produced 3.9 million tons of coal in 2008.
The coal produced in 2008 from our Northern and Central Appalachian mining
operations was, on average, 12,214 Btu/lb., 1.3% sulfur and 12.6% ash by
content. Shipments bound for electric utilities accounted for approximately 91%
of the coal shipped by these mines in 2008 compared to 93% of shipments in 2007.
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.





As
of December 31, 2008, these mines had 2,166 employees.





9







Eastern





Eastern
operates the Birch River surface mine, located 60 miles east of Charleston,
near Cowen in Webster County, West Virginia. Birch River is extracting coal
from the Freeport, Upper Kittanning, Middle
Kittanning, Upper Clarion and Lower Clarion coalbeds. We estimate that
Birch River controls 5.0 million tons of coal reserves. Additional
potential reserves have been identified in the immediate vicinity of the
Birch River mine and exploration activities are currently being conducted
in order to add those potential reserves to the reserve base.





Approximately
36% of the coal reserves are leased, while approximately 64% 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. Most leases can
be renewed until all mineable and merchantable coal has been
exhausted.





Overburden
is removed by a dragline, excavator, front-end loaders, end dumps and
bulldozers. Approximately one-third of the total coal sales are
run-of-mine, while the other two-thirds are washed at Birch River’s
preparation plant. Coal is transported by conveyor belt from the preparation
plant to Birch River’s rail loadout, which is served by CSX via the A&O
Railroad, a short-line carrier that is partially owned by CSX.





Hazard





Hazard
currently operates seven surface mines, a unit train loadout (Kentucky River
Loading) and other support facilities in eastern Kentucky, near Hazard. The coal
reserves and operations were acquired in late-1997 and 1998 by AEI
Resources.





Hazard’s
seven surface mines include East Mac & Nellie, Vicco, Rowdy
Gap, County Line, Sam Campbell, Thunder Ridge and Middle Fork. The
coal from these mines is being extracted from the Hazard 10, Hazard 9, Hazard 8,
Hazard 7 and Hazard 5A seams. Nearly all of the coal is marketed as a blend of
run-of-mine product with the remainder being washed. Overburden is removed by
front-end loaders, end dumps, bulldozers and blast casting. East Mac &
Nellie also utilizes a large capacity hydraulic shovel. Coal is transported by
on-highway trucks from the mines to the Kentucky River Loading rail loadout,
which is served by CSX. Some coal is direct shipped to the customer by truck
from the mine pits.





We
estimate that Hazard controls 61.9 million tons of coal reserves, plus
6.4 million tons of coal that is classified as non-reserve coal deposits.
Most of the property has been adequately explored, but additional core drilling
will be conducted within specified locations to better define the
reserves.





Approximately
58% of Hazard’s reserves are leased. Most of the leased reserves are held by
seven lessors. In several cases, Hazard has multiple leases with each lessor.
The leases are retained by annual minimum payments and by tonnage-based royalty
payments. Most leases can be renewed until all mineable and merchantable coal
has been exhausted.





10





Flint
Ridge





As
of year end, Flint Ridge, located near Breathitt County, Kentucky, was currently
operating three underground mines and one preparation plant. Two underground
mines operate in the Hazard 8 seam, while the third underground mine operates in
the Hazard 5A seam.





Flint
Ridge’s three underground mines are room-and-pillar operations, utilizing
continuous miners and both battery powered ram cars and shuttle cars. All of the
run-of-mine coal is processed at the Flint Ridge preparation plant, which is an
existing preparation plant structure that was extensively upgraded in early
2005. Since July 2005, it has been processing coal from the Hazard and Flint
Ridge mining complexes.





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





We
estimate that Flint Ridge controls 24.2 million tons of coal reserves, plus
0.9 million tons of non-reserve coal deposits. Approximately 97% of Flint
Ridge’s reserves are leased, while 3% are owned in fee. The leases are retained
by annual minimum payments and by tonnage-based royalty payments. Most leases
can be renewed until all mineable and merchantable coal has been
exhausted.





Knott County





Knott County
operates three underground mines, the Supreme Energy preparation plant and rail
loadout and other facilities necessary to support the mining operations in
eastern Kentucky, near Kite. Knott County was acquired by AEI Resources
from Zeigler in 1998 with reserves acquired through a lease from Penn
Virginia.





Knott County
is producing coal from the Hazard 4 and Elkhorn 3 coalbeds. Two mines are
operating in the Hazard 4 coalbed: Calvary and Clean Energy. The Classic mine is
operating in the Elkhorn 3 coalbed. Three additional properties are in the
process of being permitted for underground mine development. We estimate this
property contains 15.2 million tons of coal reserves. A significant portion
of the property has been explored, but additional core drilling will be
conducted within specified locations to better define the reserves.





Approximately
25% of Knott County’s reserves are owned in fee, while approximately 75%
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.





Knott County’s
three 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. All of Knott County’s coal is transported by
rail from loadouts served by CSX.





11





Raven





Raven,
located in Knott County, Kentucky, operates two underground mines and the Raven
preparation plant. Raven’s two underground mines are producing coal from the
Elkhorn 2 coalbed. We estimate this property contains 12.2 million tons of
coal reserves. Most of the property has been extensively explored, but
additional core drilling will be conducted within specified locations to better
define the reserves.





Raven’s
reserves are 100% leased from one lessor. 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.





Raven’s
two underground mines are room-and-pillar operations, utilizing continuous
miners and battery powered ram cars. The coal is processed at the Raven
preparation plant. Operations at the Raven preparation plant began in 2006 in
conjunction with Loadout, LLC, an affiliate of Penn Virginia Resources Partners,
L.P. Nearly all of Raven’s coal is transported by rail via CSX.





East
Kentucky





East
Kentucky is a surface mining operation located in Martin and Pike Counties,
Kentucky, near the Tug Fork River. East Kentucky currently operates the Mt.
Sterling and Peelpoplar surface mines and the Sandlick loadout. The loadout is
serviced by Norfolk Southern railroad. East Kentucky was acquired by AEI
Resources in the second quarter of 1999.





Mt. Sterling
is an area surface mine that produces coal from the
Taylor, Coalburg, Winifrede, Buffalo and Stockton coalbeds. All
of the coal is sold run-of-mine. We estimate that the Mt. Sterling mine
controls 2.7 million tons of coal reserves, of which 88% are owned. No
additional exploration is required. Overburden at the Mt. Sterling mine is
removed by front-end loaders, end dumps, bulldozers and blast casting. Coal from
the pits is transported by truck to the Sandlick loadout.





Peelpoplar
is a surface mine that produces coal using contour mining from the Little
Fireclay and Whitesburg Middle coal seams that we estimate to control 0.2
million tons of coal reserves, none of which are owned. Mining is performed
using a front-end loader/truck spread and bulldozers. Coal produced is
transported by on-highway trucks to the Sandlick loadout. We plan to operate the
Peelpoplar mine though 2009.





Although
Mt. Sterling and Peelpoplar are mined by East Kentucky, the properties are held
by ICG Natural Resources. 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.





Beckley





The
Beckley Pocahontas Mine was placed into production in the fall of 2008. It is
located in Central Appalachia in Raleigh County, West Virginia. The Beckley
Pocahontas mine accesses a 32.0 million-ton deep reserve of high quality
low-volatile metallurgical coal in the Pocahontas No. 3 seam. Most of the
16,800 acre Beckley reserve is leased from three land companies: Western
Pocahontas Properties, Crab Orchard Coal Company and Beaver Coal
Company.





Construction
of the slope portal and a new preparation plant was completed in late 2007 with
remaining development completed in 2008. Underground production is by means of
the room-and-pillar method with continuous miners and battery haulers. We are
marketing the coal produced from the Beckley reserve to domestic steel producers
and for export. Additionally, we began marketing metallurgical coal produced
from reprocessing a nearby coal refuse pile located at Eccles, West
Virginia.





12





Vindex
Energy Corporation





Vindex
Energy Corporation operates three surface mines, the Carlos mine, the Island
mine and the Jackson Mountain mine, all located in Garrett and Allegany
Counties, Maryland. The reserves at Vindex are leased from multiple landowners
under leases that expire at varying times and are renewable with annual holding
costs. Vindex Energy is a cross-ridge mining operation extracting coal from the
Upper Freeport, Bakerstown, Middle Kittanning, Upper Kittanning, Pittsburgh and
Redstone seams. All surface mines operated by Vindex Energy are
truck-and-shovel/loader mining operations and are conducted with relatively new
equipment. Exploration and development is conducted on a continual basis ahead
of mining. In 2007, Vindex added the Cabin Run property to its reserve base. The
total reserves for the assigned surface operations at Vindex amount to
approximately 7.3 million tons.





Most
of the surface mine production is shipped directly to the customer as
run-of-mine product. Any coal that must be washed is processed at our
preparation plant located near Mount Storm, West Virginia, where the product is
shipped to the customer by either truck or rail.





Patriot
Mining Company





Patriot
Mining Company consists of the Guston Run surface mine, located near Morgantown
in Monongalia County, West Virginia. The Crown No. 4 surface mine was depleted
in the third quarter of 2007 and the Fort Grand surface mine was temporarily
idled in the fourth quarter of 2008. The majority of the coal and surface is
leased under renewable contracts with small annual minimum holding costs. Coal
is extracted from the Waynesburg seam using 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 rail,
truck or barge using our barge loading facility.





We
estimate that Patriot Mining Company currently controls approximately
6.2 million tons of coal reserves, of which 1% are owned.





Buckhannon
Division





Wolf
Run Mining Company’s Buckhannon Division currently consists of two active
underground mines: the Imperial mine located in Upshur County, West Virginia,
near the town of Buckhannon, and the Sycamore No. 2 mine located in
Harrison County, West Virginia, approximately ten miles west of Clarksburg.
Nearly all of the reserves in the Buckhannon Division are owned. The Buckhannon
Division also owns the Sago mine, which was idled in March 2007. The decision
was made in December 2008 to permanently close the Sago mine due to
deteriorating conditions and the high cost necessary to reactivate the
mine.





The
Imperial mine extracts coal from the Middle Kittanning seam. All of the coal
extracted from the Imperial mine is processed through the nearby Sawmill Run
preparation plant. This coal is 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. The reserves at the Buckhannon Division have
characteristics that make it marketable to both steam and export metallurgical
coal customers.





The
Sycamore No. 2 mine began producing coal from the Pittsburgh seam by the
room-and-pillar mining method with continuous miners and shuttle cars in the
fourth quarter of 2005. The reserve is primarily leased from one landowner with
an annual minimum holding costs and an automatic renewal based on an annual
minimum production of 250,000 tons. Unexpected adverse mining conditions forced
the idling of the Sycamore No. 2 mine during the third quarter of 2006;
however, an independent contractor resumed production at the mine in September
2007. The coal produced from the Sycamore No. 2 mine is sold on a raw basis
and shipped to Allegheny Power Service Corporation’s Harrison Power Station by
truck.





13





Powell
Mountain





Acquired
in 2008, Powell Mountain, located in Lee County, Virginia and Harlan County,
Kentucky, currently operates the Darby mine, a room-and-pillar mine operating
two sections with both shuttle cars and ram cars. The mine is operating in the
Darby seam with all coal being trucked to the Mayflower preparation plant for
processing. Coal is shipped by rail through the dual service rail loadout
facility with rail service provided by both the Norfolk Southern and CSX
railroads. Some purchased coal is brought into the facility for processing and
blending. We plan to begin operation of the new Middle Splint mine in
2010.





Sentinel





Wolf
Run Mining Company’s Sentinel mine, located in Barbour County, West Virginia,
was acquired by Anker in 1990 and has been operating ever since. Historically,
coal was extracted from the Upper and Lower Kittanning seams; however, the mine
was idled in the second quarter of 2006 to extend the slope and shafts to the
underlying Clarion seam. Developmental mining in the Clarion seam began in
November 2006 and the current operation now includes three continuous miner
sections using the room-and-pillar mining method. Clarion coalbed reserves at
the Sentinel mine amount to approximately 15.4 million tons, of which
approximately 12% is owned and 88% is leased.





Coal
is fed directly from the mine to a preparation plant and loadout facility served
by the CSX railroad with origination by the A&O Railroad, as short-line
operator. The product can be shipped to steam or metallurgical
markets.





New
Appalachian Mine Developments





Hillman
Property





The
Hillman property, located in Taylor County, West Virginia, near Grafton,
includes approximately 186.0 million tons of deep coal reserves of both
steam and metallurgical quality coal in the Lower Kittanning seam covering
approximately 65,000 acres. The reserve extends into parts of Barbour, Marion
and Harrison Counties as well. ICG owns the 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
West Virginia Department of Environmental Protection (“WVDEP”) issued a permit
on June 5, 2007 for the Tygart No. 1 underground longwall mine and
preparation plant complex located on the Hillman Property. On appeal, the WV
Surface Mine Board remanded the permit for additional modifications. The
modified permit application was approved in April 2008 and mine site development
commenced. A subsequent appeal to the WV Surface Mine Board resulted in the
suspension of the permit in October 2008 and cessation of construction activity.
A modified permit application is awaiting reissuance from WVDEP.





Construction
of our Tygart No. 1 mining complex is not expected to resume until market
conditions justify the additional production. We will continue to evaluate
timing of the development as market conditions evolve, but resumption of work is
not currently expected before 2011. At full production, we expect Tygart
No. 1 to produce 3.5 million tons annually of high quality coal that
is well suited to both the utility market and the high volatile metallurgical
market.





14





Upshur
Property





The
Upshur Property, located in Northern Appalachia, contains approximately
93.0 million tons of non-reserve coal deposits owned or controlled by us in
the Middle and Lower Kittanning seams. Due to unique geologic characteristics
and coal quality constraints, Upshur is a potential location for an on-site
power plant. Some preliminary research, including air quality monitoring, has
been completed as part of conceptual planning for the future construction of a
circulating fluidized bed power plant at Upshur.





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 25.9 million tons in the Jawbone, Greasy
Creek and War Creek seams. The Big Creek reserve is all leased from Southern
Regional Industrial Realty. The War Creek mine, which is permitted as a
room-and-pillar mining operation, is expected to be developed in the future as
market conditions warrant. We receive an overriding royalty on coalbed methane
production from this property.





Juliana
Complex





The
Juliana property, located in Webster County, West Virginia, was extensively
mined in the past by a predecessor of ICG. Contour and mountaintop removal
surface mining 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.





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.





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. This property
contains 14.7 million tons of surface mineable, low sulfur coal reserves. A deep
reserve in the high Btu, mid-sulfur Alma seam constitutes the largest block of
coal at 30.2 million tons. Permitting is now in progress for a surface mine on
this Central Appalachian property. Development of the entire Jennie Creek
reserve had been subject to the resolution of certain disputes with lessors
arising out of the Horizon bankruptcy proceedings. We resolved our litigation
with the lessors of the Jennie Creek coal reserves in 2007. Using the
results of an extensive core drilling project completed on the property in 2007
and 2008, the surface mine plan was updated and corresponding changes are being
made to the mining permits. The coal will be produced by contouring, highwall
mining and area mining.





15





Illinois Basin
Mining Operations





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











Illinois
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. We estimate that Viper controls approximately 42.6 million
tons of coal reserves, plus an additional 38.5 million tons of non-reserve coal
deposits.





Approximately
79% of the coal reserves are leased, while 21% are 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.





16





The
Viper mine is a room-and-pillar operation, utilizing continuous miners and
battery coal haulers. Management believes that 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
utility and industrial customers located in North Central Illinois by on-highway
trucks operated by independent trucking companies. A major rail line is located
a short distance from the plant, giving Viper the option of constructing a rail
loadout. Shipments to electric utilities account for approximately 64% of coal
sales.





The
underground equipment, infrastructure and preparation plant are well maintained.
Underground equipment is routinely replaced or rebuilt depending on the age and
mechanical condition of the equipment. Illinois plans to develop a new portal
facility that will allow it to eliminate the need to operate over five miles of
underground beltlines and to maintain the extensive previously mined
area.





Other
Operations





Brokered
coal sales





In
addition to the coal we mine, we purchase and resell coal produced by third
parties from their controlled reserves to meet our customers’
specifications.





ADDCAR
Systems





In
our highwall mining business, we have five systems in operation 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 often deployed at reserves that cannot be
economically mined by other methods.





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





A
five person crew operates the entire ADDCAR highwall mining system with control
of the continuous miner being performed remotely by one person from the
climate-controlled cab 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. In addition, the system provides
vertical guidance for avoiding or limiting out of seam dilutions. The ADDCAR
highwall mining system is equipped with high-quality video monitors to provide
the operator with visual displays of the mining process from inside 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 depth of up to 1,200 to 1,500 feet. After retraction, the
launch vehicle is moved to the next entry, leaving a support pillar of coal
between entries. This process recovers as much as 65% of the reserves while
keeping all personnel outside the coal seam in a safe working environment. A
wide range of seam heights can be mined with high production in seams as low as
3.5 feet and as high as 15 feet in a single pass. If the seam height is greater
than 15 feet, then multi-lifts can be mined to create an unlimited entry height.
The navigational features on the ADDCAR highwall mining system allow for
multi-lift mining while ensuring that the designed pillar width is
maintained.





17








During
the mining cycle, in addition to the tramming effort provided by the crawler
drive of the continuous miner, the ADDCAR highwall mining system increases the
cutting capability of the machine through additional forces provided by
hydraulic cylinders which transmit thrust to the back of the miner through
blocks mounted on the side of the conveyor cars. This additional energy allows
the continuous miner to achieve maximum cutting and loading rates as it moves
forward into the seam. The first ADDCAR narrow bench mining system was placed in
operation in 2007.





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





Coalbed
methane





CoalQuest
has entered into a lease and joint operating agreement pursuant to which it
leases coalbed methane, which is pipeline quality gas that resides in coal
seams, and participates in certain coalbed methane wells, from its properties in
Barbour, Harrison and Taylor counties in West Virginia. The first production
well owned in part by CoalQuest began commercial operations in June 2006 and ten
additional wells partially owned by CoalQuest were brought online by the end of
2007. During 2008, the counterparty to the lease and joint operating agreement
declared bankruptcy. As a result, we recorded a reserve against related
outstanding accounts receivable. The counterparty continues to operate the wells
under the protection of the bankruptcy court. Our coalbed methane lessee
developed other wells in which CoalQuest is not a partial owner. In the eastern
United States, conventional natural gas fields are typically located in various
sedimentary formations at depths ranging from 2,000 to 15,000 feet. Exploration
companies often put capital at risk by searching for gas in commercially
exploitable quantities at these depths. By contrast, the coal seams from which
we recover coalbed methane are typically less than 1,000 feet deep and are
usually better defined than deeper formations. We believe that this contributes
to lower exploration costs than those incurred by producers that operate in
deeper, less defined formations. We believe this project is part of the first
application of proprietary horizontal drilling technology for coalbed methane in
northern West Virginia coalfields. We have not filed reserve estimates with any
federal agency.





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





Customers
and Coal Contracts





Customers





Our
primary customers are investment grade electric utility companies 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, 2008 were Progress Energy, Georgia Power Company and Allegheny
Energy Supply Company and we derived approximately 32% of our coal revenues from
sales to our five largest customers. We did not derive more than 10% of our coal
sales revenues from any single customer in 2008.





Long-term
coal supply agreements





As
is customary in the coal industry, we enter into long-term supply contracts
(exceeding one year in duration) with many of our customers when market
conditions are appropriate. These contracts allow customers to secure a supply
for their future needs and provide us with greater predictability of sales
volume and sales price. For the year ended December 31, 2008, approximately 51%
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 2009 and 2010 and are expected to provide us a minimum of approximately
1.9 million tons of coal through the remaining lives of the
contracts.





18





We
have certain contracts which are below current market rates because they were
entered into during periods of suppressed 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 prevailing
market prices.





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





Price
reopener provisions are present in 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.





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





Transportation/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 agreements with transportation companies
throughout the year.





In
2008, approximately 98% of our coal (both produced and purchased) from our
Central Appalachian operations was delivered to our customers by rail generally
on either the Norfolk Southern or CSX rail lines, with the remaining 2%
delivered by truck. 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.





19





Suppliers





In
2008, we spent more than $375.6 million to procure goods and services in support
of our business activities, excluding capital expenditures. Principal
commodities include maintenance and repair parts and services, fuel, roof
control and support items, explosives, tires, conveyance structure, ventilation
supplies and lubricants. Our outside suppliers perform a significant portion of
our equipment rebuilds and repairs both on- and off-site, as well as
construction and reclamation activities.





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





Competition





The
coal industry is intensely competitive. Our main competitors are Massey Energy
Company, Arch Coal, Consol Energy, Alpha Natural Resources, Foundation Coal
Holdings, James River Coal Company, Patriot Coal Corporation and various other
smaller, independent producers. The most important factors on which we compete
are coal price at the mine, coal quality and characteristics, transportation
costs and the reliability of supply. Demand for coal and the prices that we are
able to obtain for our coal are closely linked to coal consumption patterns of
the domestic electric generation industry, which accounted for approximately 93%
of domestic coal consumption in 2007. 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, changes in international supply and demand, alternative fuels
such as natural gas, oil and nuclear and alternative energy sources, such as
hydroelectric power.





Employees





As
of December 31, 2008, we had 2,727 employees of which 22% were salaried and 78%
were hourly. We believe our relationship with our employees is positive. Our
entire workforce is union free.





Reclamation





Reclamation
expenses are a significant part of any coal mining operation. Prior to
commencing mining operations, a company is required to apply for numerous
permits in the state where the mining is to occur. Before a state will approve
and issue these permits, it 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.
Bonding companies also require posting of collateral, typically in the form of
letters of credit, to secure the surety bonds. As of December 31, 2008, the
Company had $61.1 million in letters of credit supporting its reclamation surety
bonds. While bonds are issued against reclamation liability for a particular
permit at a particular site, collateral posted in support of the bond is not
allocated to a specific bond, but instead is part of a collateral pool
supporting all bonds issued by that particular insurer. Bonds are released in
phases as reclamation is completed in a particular area.





20





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 and at our
operations.





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 for our planned mines promptly upon securing the necessary property
rights and required geologic and environmental data. In our experience, mining
permit approvals generally require 12 to 18 months after initial
submission.





Surface
Mining Control and Reclamation Act





The
Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is
administered by the Office of Surface Mining Reclamation and Enforcement
(“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 adopts a
regulatory program as comprehensive as the federal mining program under SMCRA,
the state becomes the regulatory authority. States in which we have active
mining operations have achieved primary control of enforcement through federal
approval of the state program.





21





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





The
mining permit application process is initiated by collecting baseline data to
adequately characterize the pre-mine environmental condition of the permit area.
This work includes surveys of cultural resources, soils, vegetation, wildlife,
assessment of surface and ground water hydrology, climatology and wetlands. In
conducting this work, we collect geologic data to define and model the soil and
rock structures and coal that 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 typically take 12 to 18 months, or even
longer, to be issued. Regulatory authorities have considerable discretion in the
timing of the permit issuance and the public has rights to comment on, and
otherwise engage in, the permitting process, including through intervention in
the courts.





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





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





Surety
Bonds





Federal
and state laws require us to obtain surety bonds to secure payment of certain
long-term obligations including mine closure or reclamation costs, 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. Bonding companies also require
posting of collateral, typically in the form of letters of credit, to secure the
surety bonds. As of December 31, 2008, the Company had $73.6 million in letters
of credit supporting its surety bonds, including reclamation bonds.





22








Clean
Air Act





The
federal Clean Air Act, and comparable state laws that regulate air emissions,
directly affect coal mining operations, but have a far greater indirect effect.
Direct impacts on coal mining and processing operations may occur through
permitting requirements and/or emission control requirements relating to
particulate matter, such as fugitive dust or fine particulate matter measuring
2.5 micrometers in diameter or smaller. The Clean Air Act indirectly affects
coal mining operations by extensively regulating the air emissions of sulfur
dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired
electricity generating plants and coke ovens. 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 U.S. Environmental Protection Agency (the “EPA”) to
set standards, referred to as National Ambient Air Quality Standards (“NAAQS”)
for certain pollutants. Areas that are not in compliance with these standards
(“non-attainment areas”) 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 failed 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 had until June 2007
to develop plans for pollution control measures that allow them to come into
compliance with the standards. On January 16, 2009, the EPA proposed additional
requirements for non-attainment areas that could impose new requirements on
power plants.





For
particulates, the changes include retaining the existing standard for
particulate matter with an aerodynamic diameter less than or equal to 10 microns
and adding a new standard for fine particulate matter with an aerodynamic
diameter less than or equal to 2.5 microns (“PM2.5”). 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 more stringent PM2.5
standard which became effective December 18, 2006. On December 22, 2008,
the EPA identified portions of 25 states as being in non-attainment with the
PM2.5 standard. 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 non-attainment areas.





23





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 requires
900,000 tons of nitrogen oxide 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 required a further reduction of about 100,000 tons of nitrogen
oxides per year by May 1, 2007. Installation of additional control measures
required under the final rules, such as selective catalytic reduction
devices, will make it more costly to operate coal-fired electricity generating
plants, thereby making coal a less attractive fuel.





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. 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 pursuant to this
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. On December 23, 2008, the United States Court of Appeals for the
District of Columbia remanded, without vacating, the Clean Air Interstate Rule
to the EPA for further proceedings consistent with the Court’s July 11, 2008
opinion which found numerous fatal flaws in the Rule. The EPA has not determined
how to respond to the Court’s decision.





Mercury





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





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. In addition, seven Northeastern states
have prepared and submitted to the EPA a Northeast Regional Mercury Total
Maximum Daily Load to reduce mercury in waterbodies by reducing air deposition
of mercury primarily from coal-fired power plants in the Midwest.





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.





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Regional
Haze





The EPA has initiated a regional haze program designed to protect and improve
visibility at and around national parks, national wilderness areas and
international parks. This program restricts the construction of new coal-fired
power plants whose operation may impair visibility at and around federally
protected areas. Moreover, this program may require certain existing coal-fired
power plants to install additional control measures designed to limit
haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile
organic chemicals and particulate matter. These limitations could affect the
future market for coal. On July 6, 2005, the EPA issued regulations
revising its regional haze program.





Clean
Water Act





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





Permits
under Section 404 of the CWA are required for coal companies to conduct
dredging or filling activities in jurisdictional waters for the purpose of
conducting any instream activities, including installing culverts, creating
water impoundments, constructing refuse areas, creating slurry ponds, placing
valley fills or performing other mining activities. Jurisdictional waters
typically include intermittent and perennial streams and may, in certain
instances, include man-made conveyances that have a hydrologic connection to a
stream or wetland. The Army Corps of Engineers (“ACOE”) authorizes in-stream
activities under either a general “nationwide” permit or under an individual
permit, based on the expected environmental impact. A nationwide permit may be
issued for specific categories of filling activity that are determined to have
minimal environmental adverse effects; however, the effective term of such
permits is limited to no longer than five years. Nationwide Permit 21 authorizes
the disposal of dredge-and-fill material from mining activities into the waters
of the United States. An individual permit typically requires a more
comprehensive application process, including public notice and comment, but an
individual permit can be issued for the project life. We have secured nationwide
permits and individual permits, depending on the expected duration and timing of
the proposed in-stream activity.





Judge
Robert C. Chambers of the U.S. District Court for the Southern District of West
Virginia ruled in March 2007 in a lawsuit filed by several citizen groups
against the ACOE that the ACOE failed to adequately assess the impacts of
surface mining on headwaters and approved mitigation that did not appropriately
compensate for stream losses. Judge Chambers in June 2007 found that sediment
ponds situated within a stream channel violated the prohibition against using
the waters of the U.S. for waste treatment and further decided that using the
reach of stream between a valley fill and the sediment pond to transport
sediment-laden runoff is prohibited by the Clean Water Act. In February 2009,
the Fourth Circuit Court of Appeals overturned these decisions and remanded the
case for further proceedings.





On
December 6, 2007, the Sierra Club and Kentucky Waterways Alliance sued the
ACOE in the U.S. District Court for the Western District of Kentucky alleging
that the ACOE Louisville District wrongfully issued a Section 404
authorization to ICG Hazard’s Thunder Ridge surface mine in Perry County,
Kentucky. The plaintiffs, who are represented by the same counsel as the
plaintiffs in the Chambers lawsuit, make essentially the same claims but add the
charge that the ACOE violated the National Environmental Policy Act requirement
that stream impacts first must be avoided or in the alternative minimized. On
December 26, 2007, the ACOE suspended the Section 404 permit to allow
it to review and supplement as needed the administrative record on which the
permit decision is based. We are cooperating with the ACOE in defending the
ACOE’s decision to issue the permit. Our Thunder Ridge surface mine continues to
operate on previously permitted areas and, in accordance with an agreement
reached among the parties, on certain portions of the newly permitted
area.





25





On
October 23, 2003, several citizens groups sued the ACOE in the U.S.
District Court for the Southern District of West Virginia seeking to invalidate
“nationwide” permits utilized by the 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. While
this case remained dormant since the appeals court decision, the judge asked the
parties to brief the court regarding the effects of the Chambers’ decision on
the Nationwide Permit 21 program. The requested briefs were filed in 2008 and
the case is pending decision or further directive by the court.





A
lawsuit making similar claims regarding the Nationwide Permit 21 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 the 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. The judge ordered a
briefing schedule for the parties in this litigation.





In
September 2008 the Sixth Circuit Court of Appeals partly affirmed and partly
rejected a federal district court’s decision that had upheld EPA’s approval of
Kentucky’s new anti-degradation regulations. Anti-degradation regulations
prohibit diminution of water quality in streams. The circuit court upheld
Kentucky’s methodology for designating high quality waters, even though
environmental groups claimed the methodology resulted in too few high quality
designations. The circuit court also affirmed Kentucky’s designation method on a
water body-by-water body approach and rejected environmentalist claims that such
designations must be conducted on a parameter by parameter basis. The court also
upheld Kentucky’s exclusion of “impaired” waters from anti-degradation review.
However, the circuit court struck down the district court’s approval of
Kentucky’s alternative anti-degradation implementation procedures for coal
mining. See “Legal Proceedings” contained in Item 3 of this Annual Report on
Form 10-K/A.





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. The federal Mine Improvement and New Emergency
Response Act of 2006 (the “MINER Act”) was signed into law on June 15, 2006
and implementation of the specific requirements of the MINER Act is currently
underway. The Mine Safety and Health Administration (“MSHA”) issued an emergency
temporary standard addressing sealing of abandoned areas in underground mines on
May 22, 2007 and on September 6, 2007, MSHA published a proposed rule
that would implement Section 4 of the MINER Act by addressing composition
and certification of mine rescue teams and improving their availability and
training. 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 2008, we recorded $11.8 million of expense
related to this excise tax.





26





Resource
Conservation and Recovery Act





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





Subtitle
C of the RCRA exempted fossil fuel combustion by-products (“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 CCBs do not warrant regulation as hazardous
waste under the RCRA and that the hazardous waste exemption applied to these
CCBs. However, the EPA has determined that national non-hazardous waste
regulations under the RCRA Subtitle D are needed for CCBs disposed in surface
impoundments and landfills and used as mine-fill. The agency also concluded
beneficial uses of these CCBs, other than for mine-filling, pose no significant
risk and no additional national regulations are needed. As long as the exemption
remains in effect, it is not anticipated that regulation of CCBs will have any
material effect on the amount of coal used by electricity generators. Most state
hazardous waste laws also exempt CCBs and instead treat them as either a solid
waste or a special waste. Efforts continue by environmental groups and others
for the adoption of more stringent disposal requirements for CCBs. Any increased
costs associated with handling or disposal of CCBs would increase our customers’
operating costs and potentially reduce their coal purchases. In addition,
contamination caused by the past disposal of ash can lead to material
liability.





Due
to the hazardous waste exemption for CCBs such as ash, some of the CCBs are
currently put to beneficial use. For example, at certain mines, the Company
sometimes uses ash deposits from the combustion of coal as a beneficial use
under its reclamation plan. The alkaline ash used for this purpose 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





Global
climate change has a potentially far-reaching impact upon our business. Concerns
over measurements, estimates and projections of global climate change,
particularly global warming, have resulted in widespread calls for the
reduction, by regulation and voluntary measures, of the emission greenhouse
gases, which include carbon dioxide and methane. These measures could impact the
market for our coal and coalbed methane, increase our own energy costs and
affect the value of our coal reserves. The United States has not ratified the
Framework Convention on Global Climate Change, commonly known as the Kyoto
Protocol, which would require our nation to reduce greenhouse gas emissions to
93% of 1990 levels by 2012. The United States is participating in international
discussions which are underway to develop a treaty to require additional
reductions in greenhouse gas emissions after 2012. The United States has yet to
adopt a federal program for controlling greenhouse gas emissions. However,
Congress is considering a variety of legislative proposals which would restrict
and/or tax the emission of carbon dioxide from the combustion of coal and other
fuels and which would mandate or encourage the generation of electricity by new
facilities that do not use coal. Even without new legislation, the emission of
greenhouse gases may be restricted by future regulation, as the U.S. Supreme
Court held in 2007 that the EPA has authority under the Clean Air Act to
regulate these gases. The EPA is considering the potential mechanisms for
regulating greenhouse gas emissions under the Clean Air Act, including whether
to impose restrictions on the emission of carbon dioxide. Federal regulation of
the emission of carbon dioxide from coal-fired electric generating stations
could adversely affect the demand for coal.





27





While
advocating for comprehensive federal legislation, many states have adopted
measures, sometimes as part of a regional collaboration, to reduce green house
gases generated within their own jurisdiction. These measures include emission
regulations, mandates for utilities to generate a portion of its electricity
without using coal and incentives or goals for generating electricity using
renewable resources. Some municipalities have also adopted similar measures.
Even in the absence of mandatory requirements, some entities are electing to
purchase electricity generated by renewable resources for a variety of reasons,
including participation in programs calling for voluntary reductions in
greenhouse gas emissions.





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





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 $1.3 million at December 31, 2008.





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.





Emergency
Planning and Community Right to Know Act





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





Other
Regulated Substances





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





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Additional
Information





We
file annual, quarterly and current reports, as well as 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, www.intlcoal.com, or the SEC’s website, www.sec.gov. You
may also read and copy any document we file at the SEC’s public reference room
located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please
call the SEC at 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
(304) 760-2400 or by mail at: International Coal Group, Inc., 300 Corporate
Centre Drive, Scott Depot, West Virginia 25560, 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. It is the most common type of coal with moisture
content less than 20% by weight and heating value of 10,000 to 14,000 Btus per
pound. It is dense and black and often has well-defined bands of bright and dull
material. It may be referred to as soft coal.





British thermal unit orBtu. 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” below). 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.





29





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





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





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





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





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





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





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





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





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





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





30





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





Recoverable reserve. The
amount of coal that can be recovered from the Reserves. The recovery factor for
underground mines is approximately 60% and for surface mines approximately 80%
to 90%. 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 approximately 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” ton is approximately 2,205 pounds. The short ton is the unit of
measure referred to in this report.





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





Underground mine. Also
known as a deep mine. Usually located several hundred feet below the earth’s
surface, an underground mine’s resource is removed mechanically and transferred
by conveyor to the surface. Most common in the coal industry, underground mines
primarily are located east of the Mississippi River and account for
approximately one-third of total annual U.S. coal production.





31














ITEM 1A.
            RISK
      FACTORS





Risks
Relating To Our Business





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





Our
results of operations are dependent upon the prices we receive for our coal, as
well as our ability to improve productivity and control costs. Any decreased
demand would cause spot prices to decline and require us to increase
productivity and decrease costs in order to maintain our margins. During the
first half of 2008, the spot market prices increased leading to a higher average
price per ton of coal. A decrease in those prices in 2009 could adversely affect
our operating results and our ability to generate the cash flows we require to
meet our bank loan requirements, improve our productivity and invest in our
operations. The prices we receive for coal depend upon factors beyond our
control, including:





•
            supply
      of and demand for domestic and foreign coal;•
            demand
      for electricity;•
            domestic
      and foreign demand for steel and the continued financial viability of the
      domestic and/or foreign steel industry;•
            proximity
      to, capacity of and cost of transportation facilities;•
            domestic
      and foreign governmental regulations and taxes;•
            air
      emission standards for coal-fired power plants;•
            regulatory,
      administrative and judicial decisions;•
            price
      and availability of alternative fuels, including the effects of
      technological developments; and•
            effect
      of worldwide energy conservation
measures.





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





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





•
            unavailability
      of qualified labor;•
            our
      inability to acquire, maintain or renew necessary permits or mining or
      surface rights in a timely manner, if at all;•
            unfavorable
      geologic conditions, such as the thickness of the coal deposits and the
      amount of rock embedded in or overlying the coal
  deposits;•
            failure
      of reserve estimates to prove correct;•
            changes
      in governmental regulation of the coal industry, including the imposition
      of additional taxes, fees or actions to suspend or revoke our permits or
      changes in the manner of enforcement of existing
    regulations;•
            mining
      and processing equipment failures and unexpected maintenance
      problems;•
            adverse
      weather and natural disasters, such as heavy rains and
      flooding;•
            increased
      water entering mining areas and increased or accidental mine water
      discharges;•
            increased
      or unexpected reclamation costs;•
            interruptions
      due to transportation delays;•
            unavailability
      of required equipment of the type and size needed to meet production
      expectations; and•
            unexpected
      mine safety accidents, including fires and
  explosions.





32





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. We were impacted during 2008 by a tightening labor market increasing our
compensation costs, as well as increases in costs for repairs and maintenance,
diesel fuel, blasting supplies, roof control supplies and contract labor, all of
which increased the cost of coal sales.





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 94% of all our coal sales volume in 2008 and the
majority of our sales of steam coal in 2008 were to electric power generators.
Domestic electric power generation accounted for approximately 93% of all U.S.
coal consumption in 2007, 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 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 and the potential regulation of greenhouse gas
emissions may result in more electric power generators shifting from coal to
natural gas-fired plants or alternative energy sources. Furthermore,
environmental activists have evidenced an intent to use regulatory and judicial
processes to block the construction of any new coal-fired power plants or
capacity expansions to existing plants due to climate change concerns, at least
until carbon dioxide emissions controls for such plants are imposed by federal
law. 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. An economic slowdown can significantly slow the growth of electrical
demand and, in some locations, result in contraction of demand. The economy
suffered a significant slowdown in the fourth quarter of 2008 that resulted in
lower demand. Any downward pressure on coal prices, whether due to increased use
of alternative energy sources, changes in weather patterns, decreases in overall
demand or otherwise, would likely cause our profitability to
decline.





33





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





We
sell a significant portion of our coal under long-term coal supply agreements,
which we define as contracts with a term greater than 12 months. For the year
ended December 31, 2008, approximately 51% of our revenues were derived from
coal sales that were made under long-term coal supply agreements. As of that
date, we had 49 long-term sales agreements with a volume-weighted average term
of approximately 3.8 years. The prices for coal shipped under these agreements
are typically fixed for at least the initial year of the contract, subject to
certain adjustments in later years and thus may be below the current market
price for similar type coal at any given time, depending on the timeframe of
contract execution or initiation. As a consequence of the substantial volume of
our sales that are subject to these long-term agreements, we have less coal
available with which to capitalize on higher coal prices, if and when they
arise. In addition, in some cases, our ability to realize the higher prices that
may be available in the spot market may be restricted when customers elect to
purchase higher volumes allowable under some contracts. When our current
contracts with customers expire or are otherwise renegotiated, our customers may
decide not to extend or enter into new long-term contracts or, in the absence of
long-term contracts, our customers may decide to purchase fewer tons of coal
than in the past or on different terms, including under different pricing
terms.





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





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





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





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





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





34








The duration or severity of the current global financial crisis are uncertain
and may have an impact on our business and financial conditions in ways that we
currently cannot predict.




The
continued credit crisis and related turmoil in the global financial system may
impact our business and our financial condition. In light of the current
economic condition in the financial markets, there can be no assurance the
lenders participating in our credit facility will fulfill their commitments in
accordance with their legal obligations under the credit facility. If one or
more of the lenders were to default on its obligation to fund its commitment,
the portion of the credit facility provided by such defaulting lender would not
be available to us. We also have access to a revolving credit facility to
purchase equipment from one of our vendors. The ability of the vendor to provide
this financing in the future may be negatively impacted by the current credit
crisis. Our ability to obtain alternate financing on acceptable terms (if at
all) may be severely restricted at a time when we would like, or need, to do so,
which could have an adverse impact on our ability to meet capital
commitments.





Additionally, while we have committed and priced the vast majority of our
planned shipments of coal production for next year, 26%, or approximately
434,000 tons, of our uncommitted tonnage for 2009 is metallurgical coal.
Visibility into the domestic and international metallurgical coal markets is
difficult because of recently announced price and production cuts by steel
producers in several countries, including the U.S. The depth and duration of
this imminent slowdown in the steel sector has yet to be defined and a reduction
in global steel production could adversely impact overall demand for, and/or
result in deferrals of or refusal to receive shipments of, our metallurgical
coal, which could have a negative effect on our revenues.





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





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





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





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





•
            geological
      and mining conditions which may not be fully identified by available
      exploration data or which may differ from experience in current
      operations;•
            historical
      production from the area compared with production from other similar
      producing areas; and•
            assumed
      effects of regulation and taxes by governmental agencies and assumptions
      concerning coal prices, operating costs, mining technology improvements,
      severance and excise taxes, development costs and reclamation
      costs.





35





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, 2008 were Progress
Energy, Georgia Power Company and Allegheny Energy Supply Company and we derived
approximately 32% of our coal revenues from sales to our five largest customers.
At December 31, 2008, we had coal supply agreements with these customers that
expire at various times from 2009 to 2011. 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 and related sales
revenues. Decreased performance levels over longer periods of time could cause
our customers to look elsewhere for their fuel needs, negatively affecting our
revenues and profitability.





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





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





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





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





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





36





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 or decreases in availability could significantly
impair our operating profitability.





Our
coal mining operations use significant amounts of steel, rubber, petroleum
products and other raw materials in various pieces of mining equipment, supplies
and materials, including the roof bolts required by the room-and-pillar method
of mining described previously. Scrap steel prices have risen significantly and,
historically, the prices of scrap steel and petroleum have fluctuated. In 2008,
we were adversely impacted by margin compressions due to cost increases for
various commodities and services such as diesel fuel, explosives (ANFO), roof
control supplies and coal trucking, influenced by the price variability of crude
oil and natural gas. There may be other acts of nature, terrorist attacks or
threats or other conditions that could also increase the costs of raw materials.
If the price of steel, rubber, petroleum products or other of these materials
increase, our operational expenses will increase, which could have a significant
negative impact on our profitability. Additionally, shortages in raw materials
used in the manufacturing of supplies and mining equipment could limit our
ability to obtain such items which could have an adverse effect on our ability
to carry out our business plan.





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,
which will be sealed and permanently closed in 2009. The explosion tragically
resulted in the deaths of twelve miners and the critical injury of another
miner. As a result of the accident, the federal and state investigations and
related matters and civil litigation arising out of the accident, our business
may be negatively impacted by various factors including the diversion of
management’s attention from our day-to-day business, further negative media
attention, any negative perceptions about our safety record affecting our
ability to attract skilled labor, the impact of litigation commenced against us,
any increased premiums for insurance and any claims that may be asserted against
us that are not covered, in whole or in part, by our insurance
policies.





37








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. Labor and benefit costs have
increased in 2008 due to a tightening labor market resulting in the need to
offer more competitive compensation packages. Contract labor costs also
increased over prior year. In 2008, $12.68 and $1.60 of our cost of coal sales
per ton were attributable to labor and benefits and contract labor,
respectively, compared to $10.60 and $1.11 for 2007. 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.





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





•
            uncertainties
      in assessing the value, strengths and potential profitability of, and
      identifying the extent of all weaknesses, risks, contingent and other
      liabilities (including environmental or mine safety liabilities) of,
      acquisition candidates;•
            potential
      loss of key customers, management and employees of an acquired
      business;•
            ability
      to achieve identified operating and financial synergies anticipated to
      result from an acquisition;•
            discrepancies
      between the estimated and actual reserves of the acquired
      business;•
            problems
      that could arise from the integration of the acquired business;
      and•
            unanticipated
      changes in business, industry or general economic conditions that affect
      the assumptions underlying our rationale for pursuing the
      acquisition.





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





38





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





Our
mining operations are subject to conditions that can impact the safety of our
workforce or delay coal deliveries or increase the cost of mining at particular
mines for varying lengths of time. These conditions include fires and explosions
from methane gas or coal dust; accidental minewater discharges; weather,
flooding and natural disasters; unexpected maintenance problems; key equipment
failures; variations in coal seam thickness; variations in the amount of rock
and soil overlying the coal deposit; variations in rock and other natural
materials and variations in geologic conditions. We maintain insurance policies
that provide limited coverage for some of these risks, although there can be no
assurance that these risks would be fully covered by our insurance policies.
Despite our efforts, significant mine accidents could occur and have a
substantial impact. See “– The accident at the Sago mine could negatively impact
our business.”





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





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





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





As
a result of our acquisition of Anker and of historical financial results, we
have recorded deferred tax assets. If we fail to generate profits in the
foreseeable future, our deferred tax assets may not be fully utilized. We
evaluate our ability to utilize our net operating loss (“NOL”) and tax credit
carryforwards each period and, in compliance with SFAS No. 109,Accounting for Income Taxes
(“SFAS 109”), record
any resulting adjustments that may be required to deferred income tax expense.
In addition, we will reduce the deferred income tax asset for the benefits of
NOL and tax credit carryforwards used in future periods and will recognize and
record federal and state income tax expense at statutory rates in future
periods. If, in the future, we determine that it is more likely than not that we
will not realize all or a portion of the deferred tax assets, we will record a
valuation allowance against deferred tax assets which would result in a charge
to income tax expense.





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





39








•
            lack
      of availability, higher expense or unfavorable market terms of new
      bonds;•
            restrictions
      on availability of collateral for current and future third-party surety
      bond issuers under the terms of our amended and restated credit facility;
      and•
            exercise
      by third-party surety bond issuers of their right to refuse to renew the
      surety.





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





At
December 31, 2008, we had $73.6 million of letters of credit in place, of which
$61.1 million serves as collateral for reclamation surety bonds and $12.5
million secures miscellaneous obligations. Our amended and restated credit
facility provides for a revolving credit facility of $100.0 million, of which up
to $80.0 million may be used for letters of credit. If we do not maintain
sufficient borrowing capacity under our amended and restated credit facility for
additional letters of credit, we may be unable to obtain or renew surety bonds
required for our mining operations.





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





Our
business strategy may require continued 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, particularly in
current market conditions, or if available, may not be on satisfactory terms.
Future debt financings, if available, may result in increased interest and
amortization expense, increased leverage and decreased income available to fund
further acquisitions and expansion. In addition, future debt financings may
limit our ability to withstand competitive pressures and render us more
vulnerable to economic downturns. If we fail to generate sufficient earnings or
to obtain sufficient additional capital in the future or fail to manage our
capital investments effectively, we could be forced to reduce or delay capital
expenditures, sell assets or restructure or refinance our
indebtedness.





In
addition, the credit agreement governing our amended and restated credit
facility contains customary affirmative and negative covenants for 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.
The credit agreement requires us to meet certain financial tests, including a
maximum leverage ratio, a minimum interest coverage ratio, and a limit on
capital expenditures. If we fail to comply with any affirmative or negative
covenant, or to meet any financial test, in our credit agreement, we may be
unable to obtain or renew surety bonds required for our mining
operations.





The credit agreement also contains customary events of default, including, but
not limited to, failure to pay principal or interest, breach of covenants or
representations and warranties, cross-default to other indebtedness, judgment
default and insolvency. If an event of default occurs under the credit
agreement, the lenders under the credit agreement will be entitled to take
various actions, including demanding payment for all amounts outstanding
thereunder and foreclosing on any collateral. If the lenders were to do so, our
other debt obligations including the senior notes and the convertible notes,
would also have the right to accelerate those obligations which the Company
would be unable to satisfy. See “– 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 existing debt” and “– The duration
or severity of the current global financial crisis are uncertain and may have an
impact on our business and financial conditions in ways that we currently cannot
predict.”





40





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 2007, however, the top
ten coal producers’ share had increased to approximately 65% 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, a recent slowdown
in the global steel sector has resulted in announced price and production cuts
by steel producers in several countries, which could impact the ability of our
metallurgical coal customers to settle outstanding amounts due to us. Further,
competition with other coal suppliers could force us to extend credit to
customers and on terms that could increase the risk we bear on payment
default.





We
have contracts to supply coal to energy trading and brokering companies under
which those companies sell coal to end users. In recent years, 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.





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





41





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





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





In
order to obtain leases or mining contracts to conduct our mining operations on
property where these defects exist, we may in the future have to incur
unanticipated costs. In addition, we may not be able to successfully negotiate
new leases or mining contracts for properties containing additional reserves, or
maintain our leasehold interests in properties where we have not commenced
mining operations during the term of the lease. Some leases have minimum
production requirements. Failure to meet those requirements could result in
losses of prepaid royalties and, in some rare cases, could result in a loss of
the lease itself.





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





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





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





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





42





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





We
are parties to a number of legal proceedings incidental to normal business
activities, including several complaints related to the accident at our Sago
mine, a breach of contract complaint by one of our customers related to the
idling of our Sycamore No. 2 mine and class action lawsuits that allege
that the registration statements filed in connection with our initial public
offering contained false and misleading statements, and that investors relied
upon those securities filings and suffered damages as a result. Some actions
brought against us from time to time may have merit. There is always the
potential that an individual matter or the aggregation of many matters could
have an adverse effect on our financial condition, results of operations or cash
flows. See “Legal Proceedings” contained in Item 3 of this Annual Report on
Form 10-K/A.





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
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 does not include the historical
financial information for Anker and CoalQuest, is 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.”





Risks
Relating To Government Regulation





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





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





•
            limitations
      on land use;•
            employee
      health and safety;•
            mandated
      benefits for retired coal miners;•
            mine
      permitting and licensing requirements;•
            reclamation
      and restoration of mining properties after mining is
      completed;•
            air
      quality standards;•
            water
      pollution;•
            construction
      and permitting of facilities required for mining operations, including
      valley fills and other structures, including those constructed in
      waterbodies and wetlands;•
            protection
      of human health, plantlife and wildlife;•
            discharge
      of materials into the environment;•
            surface
      subsidence from underground mining; and•
            effects
      of mining on groundwater quality and
  availability.





43





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





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





Under
federal law, each coal mine operator must secure payment of federal black lung
benefits to claimants who are current and former employees and contribute to a
trust fund for the payment of benefits and medical expenses to claimants who
last worked in the coal industry before July 1973. The trust fund is funded by
an excise tax on coal production. If this tax increases, or if we could no
longer pass it on to the purchaser of our coal under many of our long-term sales
contracts, it could increase our operating costs and harm our results. New
regulations that took effect in 2001 could significantly increase our costs
related to 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, Safety and Other Regulatory
Matters.”





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





44





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.





Mining
in the mountainous terrain of Appalachia typically requires the use of valley
fills for the disposal of excess spoil (rock and soil material) generated by
construction and mining activities. In our surface mining operations, we 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. Mountaintop removal mining, along with other
methods of surface mining, depends on valley fills to dispose of mining spoil
material. Construction of roads, underground mine portal sites, coal processing
and handling facilities and coal refuse embankments or impoundments also require
the development of valley fills. We obtain permits to construct and operate
valley fills and surface impoundments from the Army Corps of Engineers (the
“ACOE”) under the auspices of Section 404 of the federal Clean Water Act.
Lawsuits challenging the ACOE’s authority to authorize surface mining activities
under Nationwide Permit 21 or under more comprehensive individual permits have
been instituted by environmental groups, which also advocate for changes in
federal and state laws that would prevent or further restrict the issuance of
such permits. The Fourth Circuit Court of Appeals in 2005 vacated and remanded
one such suit that was originally filed in West Virginia, concluding that the
ACOE complied with the Clean Water Act when it promulgated the 2002 version of
Nationwide Permit 21. Final disposition of that case is pending before Judge
Joseph R. Goodwin of the U.S. District Court for the Southern District of West
Virginia. A similar lawsuit filed in federal court in Kentucky is still pending.
Both of those cases had additional briefing by the parties in 2008 and are
awaiting decision or further direction from the courts.





In
a March 2007 decision pertaining originally to certain Section 404 permits
issued to Massey Energy Company, Judge Robert C. Chambers of the U.S. District
Court for the Southern District of West Virginia ruled that the ACOE failed to
adequately assess the impacts of surface mining on headwaters and approved
mitigation that did not appropriately compensate for stream losses. Judge
Chambers in June 2007 found that sediment ponds situated within a stream channel
violated the prohibition against using the waters of the U.S. for waste
treatment and further decided that using the reach of stream between a valley
fill and the sediment pond to transport sediment-laden runoff is prohibited by
the Clean Water Act. The ACOE along with several intervenors appealed Judge
Chambers’ decisions to the Fourth Circuit Court of Appeals, which heard oral
arguments in September 2008. A three judge panel of the Fourth Circuit on
February 13, 2009 reversed, vacated and remanded Judge Chambers’ March 2007 and
June 2007 decisions in their entirety, ruling that the ACOE properly exercised
its discretion in the permit review and approval process. The appellees have not
publicly stated their intentions with respect to further appeals.





A
similar challenge to the ACOE Section 404 permit process was launched by
environmental groups in Kentucky in December 2007 when a lawsuit was filed in
federal court against the ACOE alleging that it wrongfully issued a
Section 404 authorization for the expansion of ICG Hazard’s Thunder Ridge
surface mine. That permit was suspended on December 26, 2007 to allow the
ACOE to review the documentation on which the permit decision was based.
Subsequently, the AOCE requested supplemental information from ICG Hazard, which
has been provided. All court proceedings are on hold in this case while the ACOE
considers its decision. The Company currently has two subsidiaries in that
jurisdiction of Kentucky that will require Section 404 permits within the
next two years. If permitting requirements are substantially increased or if
mining methods at issue are limited or prohibited, it could greatly lengthen the
time needed to permit new reserves, 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. See “Legal Proceedings” contained in Item 3 of this Annual Report on Form
10-K/A.





45





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





Both
the federal and state governments impose stringent health and safety standards
on the mining industry. Regulations are comprehensive and affect nearly every
aspect of mining operations, including training of mine personnel, mining
procedures, blasting, the equipment used in mining operations and other matters.
As a result of past mining accidents, additional federal and state health and
safety regulations have been adopted that have increased operating costs and
affect our mining operations. State and federal legislation has been adopted
that, among other things, requires additional oxygen supplies, communication and
tracking devices, refuge chambers, stronger seal construction and monitoring
standards and mine rescue teams. The legislation also raised the maximum civil
penalty for certain violations of federal mine safety regulations to $220,000
from $60,000. We expect that new regulations or stricter enforcement of existing
regulations will increase our costs related to worker health and safety.
Additionally, we could be subject to civil penalties and other penalties if we
violate mining regulations.





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





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





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





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





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. The public has
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 flows and
profitability.





46







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





The
SMCRA establishes operational, reclamation and closure standards for all aspects
of surface mining, as well as the surface effects of deep mining. Estimates of
our total reclamation and mine-closing liabilities are based upon permit
requirements, engineering studies 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 (“SFAS No. 143”), effective January 1, 2003. SFAS
No. 143 requires that asset retirement obligations be recorded as a
liability based on fair value, which is calculated as the present value of the
estimated future cash flows. In 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.





We
use, and in the past have used, alkaline CCBs during the reclamation process at
certain of our mines to aid in preventing the formation of acid mine drainage.
Use of CCBs on a mined area is subject to regulatory approval and is allowed
only after it is proved to be a beneficial use. If in the future CCBs were to be
classified as a hazardous waste or if more stringent disposal requirements were
to be otherwise established for these wastes, we may be required to cease using
CCBs and find a replacement alkaline material for this purpose, which may add to
the cost of mine reclamation.





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.





47





Extensive
environmental regulations affect our customers and could reduce the demand for
coal as a fuel source and cause our sales to decline.





The
Clean Air Act and similar state and local laws extensively regulate the amount
of sulfur dioxide, particulate matter, nitrogen oxides and other compounds
emitted into the air from coke ovens and electric power plants, which are the
largest end-users of our coal. Such regulations will require significant
emissions control expenditures for many coal-fired power plants to comply with
applicable ambient air quality standards. As a result, these generators may
switch to other fuels that generate less of these emissions, possibly reducing
future demand for coal and the construction of coal-fired power
plants.





The
Federal Clean Air Act, including the Clean Air Act Amendments of 1990, and
corresponding state laws that regulate emissions of materials into the air
affect coal mining operations both directly and indirectly. Measures intended to
improve air quality that reduce coal’s share of the capacity for power
generation could diminish our revenues and harm our business, financial
condition and results of operations. The price of lower sulfur coal may decrease
as more coal-fired utility power plants install additional pollution control
equipment to comply with stricter sulfur dioxide emission limits, which may
reduce our revenues and harm our results. In addition, regulatory initiatives
including the 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. The EPA is reconsidering the March 2005
Clean Air Interstate Rule pursuant to a court order which remanded, but did not
vacate, that rule, which 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. The EPA has announced that
it intends to initiate a rulemaking to adopt technology-based standards for
mercury emissions form coal-fired power plants in response to a court order
which vacated and remanded its 2005 Clean Air Mercury Rule. The EPA has not
determined how to respond to the Court’s decision. In February 2008, the Court
ruled that the EPA’s 2005 Clean Air Mercury Rule violates the Clean Air Act and
gave the agency two years to develop mercury emissions standards. Some states,
including Georgia and North Carolina, are adopting or proposing to adopt more
stringent restrictions on mercury emissions than those contained in the remanded
Clean Air Mercury Rule. 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 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.





48





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





Greenhouse
gas emissions have increasingly become the subject of a large amount of
international, national, state and local attention. Although the United States
did not 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. 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, the United States would be required to reduce greenhouse gas emissions
to 93% of 1990 levels in a series of phased reductions from 2008 to
2012.





Coal-fired
power plants can generate large amounts of carbon emissions, and, as a result,
have become subject to challenge, including the opposition to any new coal-fired
power plants or capacity expansions of existing plants, by environmental groups
seeking to curb the environmental effects of emissions of greenhouse gases.
Various legislation has been and will continue to be introduced in Congress
which reflects a wide variety of strategies for reducing greenhouse gas
emissions in the United States. These strategies include mandating decreases in
carbon dioxide emissions from coal-fired power plants, instituting a carbon tax
on emissions of carbon dioxide, banning the construction of new coal-fired power
plants that are not equipped with technology to capture and sequester carbon
dioxide, encouraging the growth of renewable energy sources (such as wind or
solar power) or nuclear for electricity production, financing the development of
advanced coal burning plants which have greatly reduced carbon dioxide
emissions. Most states in the United States have taken steps to regulate
greenhouse gas emissions. In addition, in Massachusetts v. Environmental
Protection Agency, a U.S. Supreme Court decision in April 2007, the U.S. Supreme
Court ruled in favor of twelve states and several cities of the United States
against the EPA, and held that carbon dioxide and other greenhouse gases can
qualify as pollutants under the Clean Air Act. As a result, the EPA may issue
regulations related to greenhouse gas emissions.





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





Risks
Relating To Our Common Stock





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





Our
total consolidated long-term debt as of December 31, 2008 was approximately
$417.6 million and represented approximately 45% of our total capitalization,
excluding current indebtedness of approximately $20.1 million, as of that
date.





49





Our
level of indebtedness could have important consequences on our future
operations, including:





•
            making
      it more difficult for us to meet our payment and other obligations under
      our outstanding senior and convertible notes and our other outstanding
      debt;•
            resulting
      in an event of default if we fail to comply with the financial and other
      restrictive covenants contained in our debt agreements, which could result
      in all of our debt becoming immediately due and
payable;•
            subjecting
      us to the risk of increased sensitivity to interest rate increases on our
      indebtedness with variable interest rates, including borrowings under our
      senior credit facility;•
            reducing
      the availability of our cash flow to fund working capital, capital
      expenditures, acquisitions and other general corporate purposes, and
      limiting our ability to obtain additional financing for these
      purposes;•
            limiting
      our flexibility in planning for, or reacting to, and increasing our
      vulnerability to, changes in our business, the industry in which we
      operate and the general economy; and•
            placing
      us at a competitive disadvantage compared to our competitors that have
      less debt or are less leveraged.





If
new debt is added to our and our subsidiaries’ current debt levels, the related
risks that we and they now face could intensify. 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
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, including our outstanding senior
and convertible notes.





Our
business may not generate sufficient cash flow from operations and future
borrowings may not be available to us under our senior credit facility or
otherwise in an amount sufficient to enable us to pay our indebtedness including
anticipated interest on the notes, 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.





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 existing debt.





Our
credit facility contains a number of financial covenants requiring us to meet
financial ratios and financial condition tests. The indenture governing our
outstanding senior notes and our senior credit facility also restrict our and
our subsidiaries’ ability to:





50











•
            incur
      additional debt or issue guarantees;•
            pay
      dividends on, redeem or repurchase capital stock;•
            allow
      our subsidiaries to issue new stock to any person other than us or any of
      our other subsidiaries;•
            make
      certain investments;•
            make
      acquisitions;•
            incur,
      or permit to exist, liens;•
            enter
      into transactions with affiliates;•
            guarantee
      the debt of other entities, including joint ventures;•
            merge
      or consolidate or otherwise combine with another company;
    and•
            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 facility 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. From time to time, we have
amended or revised our financial covenants, and have also received waivers of
covenant compliance under our senior credit facility. However, we may not
continue to receive waivers from our lenders or be permitted to amend the
financial covenants. Our failure to comply with these covenants and requirements
could result in an event of default under the indenture governing our
outstanding senior notes that, if not cured or waived, could permit acceleration
of our outstanding convertible and senior notes and permit foreclosure on any
collateral granted as security under our senior credit facility. If our
indebtedness is accelerated, we may not be able to repay the notes or borrow
sufficient funds to refinance the notes. 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 subject to limitations on capital expenditures under our senior credit
facility. Because of these limitations, we may not be able to pursue our
business strategy to replace our equipment fleet as it ages, develop additional
mines or pursue additional acquisitions without additional
financing.





51







We may not be able to repurchase our Convertible Senior Notes if noteholders
convert prior to maturity.


Upon the occurrence of specific events, our Convertible Senior Notes may become
convertible, requiring us to settle in cash the principal amount of the note,
and any excess conversion value may be settled in cash or in shares of our
common stock, at our option, as provided by the terms of the indenture governing
the Convertible Senior Notes. The Convertible Senior Notes are convertible at an
initial conversion price, subject to adjustment, of $6.10 per share
(approximately 163.8136 shares per $1,000 principal amount of the Convertible
Senior Notes). If we elect to settle any excess conversion value of the
Convertible Senior Notes in cash, the holder will receive, for each $1,000
principal amount, the conversion rate multiplied by a 20-day average closing
price of the common stock as set forth in the indenture beginning on the third
trading day after the Convertible Senior Notes are surrendered. We have $225.0
million of principal amount of Convertible Senior Notes outstanding. In the
event that a holder elects to convert its Convertible Senior Note, we would need
to seek a waiver or amendment from our lenders to fund any cash settlement of
any such conversion from working capital and/or borrowings under our amended
credit facility in excess of $25.0 million per year. There is no assurance we
will have sufficient cash on hand or available to fund the $225.0 million or
that we would receive a waiver or amendment, especially in light of the current
credit environment. In addition, if a significant number of noteholders were to
convert their notes prior to maturity, we may not have enough available funds at
any particular time to make the required repayments. Our failure to repurchase
converted notes at a time when noteholders have the right to convert would
constitute a default under the indenture. This default would, in turn,
constitute an event of default under our amended and restated credit facility
and could constitute an event of default under our Senior Notes, any of which
could cause repayment of the related debt to be accelerated after any applicable
notice or grace periods. If debt repayment were to be accelerated, we may not
have sufficient funds to repurchase the Convertible Senior Notes or repay the
debt. Alternatively, upon conversion, we may issue additional stock to satisfy
the payment obligation related to any excess conversion value which could lead
to immediate and potentially substantial dilution in net tangible book value per
share.





Changes
in the accounting treatment of certain of our existing securities could decrease
our earnings per share.





There
may be, in the future, potentially new or different accounting pronouncements or
regulatory rulings, which could impact the way we are required to account for
our securities, and which may have an adverse impact on our future financial
condition and results of operations. With respect to our convertible notes, we
are required under accounting principles generally accepted in the United States
of America (“GAAP”) as presently in effect to include in outstanding shares for
purposes of computing diluted earnings per share only a number of shares
underlying the notes that, at the end of a given quarter, have a value in excess
of the outstanding principal amount of the notes. This is because of the “net
share settlement” feature of the notes, under which we are required to pay the
principal amount of the notes in cash. The accounting method for net share
settled convertible securities was recently considered by the FASB, which issued
FASB Staff Position (“FSP”) APB 14-1,Accounting for Convertible Debt
Instruments That May be Settled in Cash Upon Conversion (Including Partial Cash
Settlement) (“FSP APB 14-1”). FSP APB 14-1, which has been
retrospectively applied in this Annual Report on Form 10-K/A, requires
that the liability and equity components of convertible debt instruments
that may be settled in cash upon conversion be accounted for separately.
Adoption of FSP APB 14-1 resulted in us recognizing additional interest expense.
See Note 23 accompanying the consolidated financial statements included
elsewhere in this Annual Report on Form 10-K/A.





The
conditional conversion feature of the notes could result in a holder receiving
less than the value of the common stock into which a note would otherwise be
convertible.





At
certain times, the notes are convertible into cash and, if applicable, shares of
our common stock only if specified conditions are met. If these conditions are
not met, a holder will not be able to convert the notes at that time, and, upon
a later conversion, a holder may not be able to receive the value of the common
stock into which the convertible notes would otherwise have been convertible had
such conditions been met.





52





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





We
currently have a portion of our assets invested in a money market fund. This
investment is subject to investment market risk and our income from this
investment could be adversely affected by a decline in value. In the case of
money market accounts and other fixed income investment products, which invest
in high-quality short-term money market instruments, as well as other fixed
income securities, the value of the assets may decline as a result of changes in
interest rates, an issuer’s actual or perceived creditworthiness or an issuer’s
ability to meet its obligations. A significant decrease in the net asset value
of the securities underlying the money market fund could cause a material
decline in our net income and cash flows.





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





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





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





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





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





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





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





As
of December 31, 2008, funds sponsored by WLR own approximately 16% 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.





53





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 effect our sales volumes, margins and earnings.





If
we do not meet the New York Stock Exchange continued listing requirements, our
common stock may be delisted, and we may be required to repurchase or refinance
our 9.00% Convertible Senior Notes Due 2012.





In
order to maintain our listing on the New York Stock Exchange (“NYSE”), we must
continue to meet the NYSE minimum share price listing rule, the minimum market
capitalization rule and other continued listing criteria. If our common stock
were delisted, it could (i) reduce the liquidity and market price of our
common stock; (ii) negatively impact our ability to raise equity financing
and access the public capital markets; and (iii) materially adversely
impact our results of operations and financial condition. In addition, if our
common stock is not listed on the NYSE or another national exchange, holders of
our 9.00% senior convertible notes due 2012 will be entitled to require us to
repurchase their convertible notes. Our credit facility and senior notes provide
that the occurrence of this repurchase right constitutes a default pursuant to
their respective agreements.





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





As
of December 31, 2008, we had 153,322,245 shares of common stock outstanding. The
number of shares of common stock available for resale in the public market is
limited in certain circumstances by restrictions under federal securities. All
of the shares sold in our 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.
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. 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.





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





None.





54








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 291 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 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 726 million tons of mid to high Btu, low and high sulfur coal
located in Kentucky, West Virginia, Maryland, Illinois 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.





55







Our total coal reserves could support current production levels for more than 58
years. The following table provides the location of our mining operations and
the type of coal produced at those operations as of January 1,
2009:





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)
            
            Owned
              Proven
              and
              Probable
              Reserves
            
            Leased
              Proven
              and
              Probable
              Reserves
            
            Steam
              Proven
              and
              Probable
              Reserves
            
            Metallurgical(3)(4)
              Proven
      and
              Probable
              Reserves(in
      million tons)Northern
      AppalachiaVindex
      Energy Corp.
            
            Assigned
            
            O
            
            MD
            
            S
            
            7.27
            
            0.00
            
            7.27
            
            7.27
            
            0.00Unassigned
            
            D
            
            MD
            
            S/UG
            
            52.83
            
            0.35
            
            52.48
            
            32.58
            
            20.25Total
      Vindex Energy Corp.
            
            
            
            
            
            
            
            
            
            60.10
            
            0.35
            
            59.75
            
            39.85
            
            20.25Patriot
      Mining Co.
            
            Assigned
            
            O
            
            WV
            
            S
            
            6.18
            
            0.05
            
            6.13
            
            6.18
            
            0.00Unassigned
            
            D
            
            WV
            
            S
            
            0.00
            
            0.00
            
            0.00
            
            0.00
            
            0.00Total
      Patriot Mining Co.
            
            
            
            
            
            
            
            
            
            6.18
            
            0.05
            
            6.13
            
            6.18
            
            0.00Wolf
      Run Mining Buckhannon Division
            
            Assigned
            
            O
            
            WV
            
            UG
            
            28.50
            
            13.16
            
            15.34
            
            14.86
            
            13.64Unassigned
            
            D
            
            WV
            
            UG
            
            30.55
            
            28.81
            
            1.74
            
            0.00
            
            30.55Total
      Wolf Run Mining Buckhannon Division
            
            
            
            
            
            
            
            
            
            59.05
            
            41.97
            
            17.08
            
            14.86
            
            44.19Sentinel
            
            Assigned
            
            O
            
            WV
            
            UG
            
            47.33
            
            30.41
            
            16.92
            
            0.00
            
            47.33Unassigned
            
            D
            
            WV
            
            UG
            
            4.94
            
            4.94
            
            0.00
            
            0.00
            
            4.94Total
      Sentinel
            
            
            
            
            
            
            
            
            
            52.27
            
            35.35
            
            16.92
            
            0.00
            
            52.27CoalQuest
      Development LLC
            
            Unassigned
            
            D
            
            WV
            
            UG
            
            186.09
            
            186.09
            
            0.00
            
            32.71
            
            153.38(Hillman)Northern
      Appalachia Total
            
            
            
            
            
            
            
            
            
            363.69
            
            263.81
            
            99.88
            
            93.60
            
            270.09Central
      AppalachiaEastern
            
            Assigned
            
            O
            
            WV
            
            S
            
            4.95
            
            3.15
            
            1.80
            
            4.95
            
            0.00Unassigned
            
            D
            
            WV
            
            S
            
            6.70
            
            0.00
            
            6.70
            
            6.70
            
            0.00Total
      Eastern
            
            
            
            
            
            
            
            
            
            11.65
            
            3.15
            
            8.50
            
            11.65
            
            0.00Hazard
            
            Assigned
            
            O
            
            KY
            
            S
            
            61.94
            
            26.12
            
            35.82
            
            61.94
            
            0.00Unassigned
            
            D
            
            KY
            
            S
            
            0.00
            
            0.00
            
            0.00
            
            0.00
            
            0.00Total
      Hazard
            
            
            
            
            
            
            
            
            
            61.94
            
            26.12
            
            35.82
            
            61.94
            
            0.00Flint
      Ridge
            
            Assigned
            
            O
            
            KY
            
            UG
            
            24.18
            
            0.63
            
            23.55
            
            24.18
            
            0.00Knott County
            
            Assigned
            
            O
            
            KY
            
            UG
            
            3.42
            
            2.93
            
            0.49
            
            3.42
            
            0.00Unassigned
            
            D
            
            KY
            
            UG
            
            11.78
            
            0.93
            
            10.85
            
            11.78
            
            0.00Total Knott County
            
            
            
            
            
            
            
            
            
            15.20
            
            3.86
            
            11.34
            
            15.20
            
            0.00Raven
            
            Assigned
            
            O
            
            KY
            
            UG
            
            10.03
            
            0.00
            
            10.03
            
            10.03
            
            0.00Unassigned
            
            D
            
            KY
            
            UG
            
            2.20
            
            0.00
            
            2.20
            
            2.20
            
            0.00Total
      Raven
            
            
            
            
            
            
            
            
            
            12.23
            
            0.00
            
            12.23
            
            12.23
            
            0.00East
      Kentucky
            
            Assigned
            
            O
            
            KY
            
            S
            
            2.94
            
            2.39
            
            0.55
            
            2.94
            
            0.00ICG
      Natural Resources
            
            Assigned
            
            D
            
            WV
            
            S
            
            14.70
            
            0.00
            
            14.70
            
            14.70
            
            0.00Unassigned
            
            D
            
            WV
            
            UG
            
            30.20
            
            2.21
            
            27.99
            
            30.20
            
            0.00(Jennie Creek)Total ICG
      Natural Resources
            
            
            
            
            
            
            
            
            
            44.90
            
            2.21
            
            42.69
            
            44.90
            
            0.00Powell Mountain
            
            Assigned
            
            O
            
            VA
            
            UG
            
            5.05
            
            0.00
            
            5.05
            
            5.05
            
            0.00Unassigned
            
            D
            
            VA
            
            S/UG
            
            22.02
            
            0.00
            
            22.02
            
            22.02
            
            0.00Total Powell Mountain
            
            
            
            
            
            
            
            
            
            27.07
            
            0.00
            
            27.07
            
            27.07
            
            0.00Beckley
            
            Assigned
            
            O
            
            WV
            
            UG
            
            32.03
            
            1.28
            
            30.75
            
            0.00
            
            32.03White
      Wolf Energy, Inc.
            
            Unassigned
            
            D
            
            VA
            
            UG
            
            25.91
            
            0.00
            
            25.91
            
            0.00
            
            25.91(Big Creek)Central
      Appalachia Total
            
            
            
            
            
            
            
            
            
            258.05
            
            39.64
            
            218.41
            
            200.11
            
            57.94OtherIllinois
            
            Assigned
            
            O
            
            IL
            
            UG
            
            42.58
            
            8.93
            
            33.65
            
            42.58
            
            0.00(Viper)ICG
      Natural Resources
            
            Unassigned
            
            D
            
            IL
            
            UG
            
            352.88
            
            352.88
            
            0.00
            
            352.88
            
            0.00Total
      Other
            
            
            
            
            
            
            
            
            
            395.46
            
            361.81
            
            33.65
            
            395.46
            
            0.00Total Proven and Probable Reserves
            
            
            
            
            
            
            
            
            
            1,017.20
            
            665.26
            
            351.94
            
            689.17
            
            328.03








(1)
            “Assigned
      reserves” means coal which has been committed by the coal company to
      operating mine shafts, mining equipment and plant facilities, and all coal
      which has been leased by the coal company to others. “Unassigned reserves”
      represent coal which has not been committed, and which would require new
      mineshafts, mining equipment or plant facilities before operations could
      begin in the property. The primary reason for this distinction is to
      inform investors which coal reserves will require substantial capital
      investment before production can begin.(2)
            The
      proven and probable reserves are reported as recoverable reserves, which
      is that part of a coal deposit which could be economically and legally
      extracted or produced at the time of the reserve determination, taking
      into account mining recovery and preparation plant yield.(3)
            Beckley
      and White Wolf Energy, Inc. meet historical metallurgical coal quality
      specifications.(4)
            We
      sold coal with ash and sulfur contents as high as 10% and 1.5%,
      respectively, into the metallurgical market from Vindex Energy, Buckhannon
      and Sentinel in 2008. Similarly, we believe all production from
      Vindex Energy and portions of Hillman could be sold on this
      metallurgical market when production begins.





56








The
following table provides the “quality” (average moisture, ash and sulfur
contents and Btu per pound) of our coal reserves as of January 1,
2009:





As
      Received Quality
            
            Total
      ReservesMining
      Operations
            
            Assigned
      or
              Unassigned
      (1)
            
            %
              Moisture
            
            %
              Ash
            
            %
              Sulfur
            
            Btu/lb.
            
            Lbs.
      SO2/
              million Btu’s
            
            <1.2 lbs.
              SO2
              Compliance
            
            >1.2 lbs
              SO2
              Non-ComplianceNorthern
      AppalachiaVindex
      Energy Corp.(3)
            
            Assigned
            
            4.66
            
            19.27
            
            1.80
            
            11,702
            
            3.07
            
            0.00
            
            7.27Unassigned
            
            6.00
            
            13.10
            
            1.75
            
            12,613
            
            2.78
            
            0.00
            
            52.83Total
      Vindex Energy Corp.
            
            
            
            5.84
            
            13.85
            
            1.76
            
            12,503
            
            2.81
            
            0.00
            
            60.10Patriot
      Mining Co.
            
            Assigned
            
            6.00
            
            14.96
            
            2.67
            
            11,830
            
            4.52
            
            0.00
            
            6.18Unassigned
            
            6.00
            
            19.06
            
            2.13
            
            11,240
            
            3.79
            
            0.00
            
            0.00Total
      Patriot Mining Co.
            
            
            
            6.00
            
            14.96
            
            2.67
            
            11,830
            
            4.52
            
            0.00
            
            6.18Wolf
      Run Mining Buckhannon Division(3)
            
            Assigned
            
            6.00
            
            8.07
            
            2.21
            
            13,070
            
            3.39
            
            0.00
            
            28.50Unassigned
            
            6.00
            
            8.92
            
            0.99
            
            13,069
            
            1.52
            
            0.00
            
            30.55Total Wolf Run Mining Buckhannon Division
            
            
            
            6.00
            
            8.51
            
            1.58
            
            13,069
            
            2.42
            
            0.00
            
            59.05Sentinel(3)
            
            Assigned
            
            6.00
            
            8.38
            
            1.48
            
            13,184
            
            2.25
            
            0.00
            
            47.33Unassigned
            
            6.00
            
            8.04
            
            1.44
            
            13,353
            
            2.15
            
            0.00
            
            4.94Total
      Sentinel
            
            
            
            6.00
            
            8.35
            
            1.48
            
            13,200
            
            2.24
            
            0.00
            
            52.27CoalQuest
      Development LLC(3)
            
            Unassigned
            
            6.00
            
            9.25
            
            1.15
            
            13,145
            
            1.76
            
            0.00
            
            186.09(Hillman)Northern
      Appalachia Total
            
            
            
            
            
            
            
            
            
            
            
            
            
            0.00
            
            363.69Central
      AppalachiaEastern
            
            Assigned
            
            6.00
            
            14.42
            
            1.24
            
            11,964
            
            2.07
            
            0.00
            
            4.95Unassigned
            
            6.00
            
            14.42
            
            1.24
            
            11,964
            
            2.07
            
            0.00
            
            6.70Total
      Eastern
            
            
            
            6.00
            
            14.42
            
            1.24
            
            11,964
            
            2.07
            
            0.00
            
            11.65Hazard
            
            Assigned
            
            6.00
            
            12.59
            
            1.38
            
            12,070
            
            2.28
            
            0.00
            
            61.94Flint
      Ridge
            
            Assigned
            
            6.00
            
            8.15
            
            1.39
            
            12,768
            
            2.17
            
            1.36
            
            22.82Knott County
            
            Assigned
            
            6.09
            
            8.73
            
            1.78
            
            12,799
            
            2.78
            
            0.31
            
            3.11Unassigned
            
            6.00
            
            6.90
            
            1.58
            
            13,051
            
            2.42
            
            0.00
            
            11.78Total Knott County
            
            
            
            6.02
            
            7.31
            
            1.62
            
            12,994
            
            2.50
            
            0.31
            
            14.89Raven
            
            Assigned
            
            6.00
            
            8.00
            
            1.18
            
            12,787
            
            1.85
            
            0.00
            
            10.03Unassigned
            
            6.00
            
            4.10
            
            2.07
            
            13,477
            
            3.07
            
            0.00
            
            2.20Total
      Raven
            
            
            
            6.00
            
            7.30
            
            1.34
            
            12,911
            
            2.08
            
            0.00
            
            12.23East
      Kentucky
            
            Assigned
            
            5.88
            
            9.37
            
            0.87
            
            12,450
            
            1.40
            
            0.00
            
            2.94ICG
      Natural Resources
            
            Assigned
            
            7.00
            
            9.65
            
            0.75
            
            12,281
            
            1.22
            
            9.59
            
            5.11Unassigned
            
            7.00
            
            4.92
            
            1.27
            
            13,254
            
            1.92
            
            0.00
            
            30.20(Jennie Creek)Total
      ICG Natural Resources
            
            
            
            7.00
            
            6.47
            
            1.10
            
            12,935
            
            1.70
            
            9.59
            
            35.31Powell Mountain
            
            Assigned
            
            6.00
            
            3.92
            
            0.62
            
            14,428
            
            0.86
            
            5.05
            
            0.00Unassigned
            
            6.00
            
            8.38
            
            2.01
            
            13,194
            
            3.04
            
            6.46
            
            15.56Total Powell Mountain
            
            
            
            6.00
            
            6.81
            
            1.75
            
            13,476
            
            2.60
            
            11.51
            
            15.56Beckley(2)
            
            Assigned
            
            6.00
            
            4.87
            
            0.70
            
            13,913
            
            1.01
            
            32.03
            
            0.00(Beckley)White
      Wolf Energy, Inc.(2)
            
            Unassigned
            
            6.00
            
            4.09
            
            0.63
            
            14,150
            
            0.89
            
            25.91
            
            0.00(Big Creek)Central
      Appalachia Total
            
            
            
            
            
            
            
            
            
            
            
            
            
            80.71
            
            177.34OtherIllinois
            
            Assigned
      (Viper)
            
            16.00
            
            8.80
            
            2.86
            
            10,692
            
            5.35
            
            0.00
            
            42.58ICG
      Natural Resources
            
            Unassigned
            
            12.53
            
            9.32
            
            2.93
            
            10,986
            
            5.33
            
            0.00
            
            352.88Total
      Other
            
            
            
            12.90
            
            9.27
            
            2.92
            
            10,954
            
            5.33
            
            0.00
            
            395.46Total
      Proven and Probable Reserves
            
            
            
            
            
            
            
            
            
            
            
            
            
            80.71
            
            936.49








(1)
            “Assigned
      reserves” means coal which has been committed by the coal company to
      operating mine shafts, mining equipment and plant facilities, and all coal
      which has been leased by the coal company to others. “Unassigned reserves”
      represent coal which has not been committed, and which would require new
      mine shafts, mining equipment or plant facilities before operations could
      begin in the property. The primary reason for this distinction is to
      inform investors which coal reserves will require substantial capital
      investment before production can begin.(2)
            Beckley
      and White Wolf Energy, Inc. meet historical metallurgical coal quality
      specifications.(3)
            We
      sold coal with ash and sulfur contents as high as 10% and 1.5%,
      respectively, into the metallurgical market from Vindex Energy, Buckhannon
      and Sentinel in 2008. Similarly, we believe all production from
      Vindex Energy and portions of Hillman could be sold on this
      metallurgical market when production
begins.





57








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, sales or dispositions of coal properties will also
change the reserves. We estimate that we controlled 1,017 million tons of
reserves at December 31, 2008. Changes in mining methods may increase or
decrease the recovery basis for a coal seam, as will plant processing efficiency
tests. We maintain reserve information in secure computerized databases, as well
as in hard copy. The ability to update and/or modify the reserves is restricted
to a few individuals and the modifications are documented.





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





We
currently own approximately 65% 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
$2.94 per ton in 2008, representing approximately 5.2% (net of freight and
handling) of our coal sales revenue in 2008. Consistent with industry practice,
we conduct only limited investigations of title to our coal properties prior to
leasing. Title to lands and reserves of the lessors or grantors and the
boundaries of our leased priorities are not completely verified until we prepare
to mine those reserves.





Non-Reserve
Coal Deposits





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




58








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 January 1,
2009:





Mining
      Operations
            
            Assigned
      or
              Unassigned
      (1)
            
            Operating (O)
      or
              Development (D)
            
            State
            
            Mining Method
              Surface
      (S) or
              Underground
              (UG)
            
            Total
              Non-Reserve
              Coal
              Deposits
            
            Steam
              Non-Reserve
              Coal
              Deposits
            
            Metallurgical(2)(3)
              Non-Reserve
              Coal
      Deposits(in
      million tons)Northern
      AppalachiaVindex
      Energy Corp.
            
            Unassigned
            
            D
            
            MD
            
            S
            
            0.44
            
            0.00
            
            0.44Wolf
      Run Mining Buckhannon Division
            
            Assigned
            
            O
            
            WV
            
            UG
            
            1.46
            
            1.46
            
            0.00Unassigned
            
            D
            
            WV
            
            UG
            
            2.24
            
            2.24
            
            0.00Total
      Wolf Run Mining Buckhannon Division
            
            
            
            
            
            
            
            
            
            3.70
            
            3.70
            
            0.00Sentinel
            
            Assigned
            
            O
            
            WV
            
            UG
            
            1.64
            
            1.64
            
            0.00Unassigned
            
            D
            
            WV
            
            UG
            
            0.76
            
            0.76
            
            0.00Total
      Sentinel
            
            
            
            
            
            
            
            
            
            2.40
            
            2.40
            
            0.00CoalQuest
      Development LLC
            
            Unassigned
            
            D
            
            WV
            
            UG
            
            38.14
            
            38.14
            
            0.00(Hillman)Upshur
      Property
            
            Unassigned
            
            
            
            WV
            
            S
            
            92.96
            
            92.96
            
            0.00(Upshur)Northern
      Appalachia Total
            
            
            
            
            
            
            
            
            
            137.64
            
            137.20
            
            0.44Central
      AppalachiaEastern
            
            Assigned
            
            O
            
            WV
            
            S
            
            0.02
            
            0.02
            
            0.00Hazard
            
            Assigned
            
            O
            
            KY
            
            S
            
            6.39
            
            6.39
            
            0.00Flint
      Ridge
            
            Assigned
            
            O
            
            KY
            
            UG
            
            0.94
            
            0.94
            
            0.00Knott County
            
            Assigned
            
            O
            
            KY
            
            UG
            
            0.00
            
            0.00
            
            0.00East
      Kentucky
            
            Assigned
            
            O
            
            KY
            
            S
            
            0.00
            
            0.00
            
            0.00(Mount Sterling)ICG
      Natural Resources
            
            Assigned
            
            D
            
            WV
            
            S
            
            0.22
            
            0.22
            
            0.00(Jennie
      Creek)ICG
      Natural Resources
            
            Unassigned
            
            D
            
            KY
            
            S/UG
            
            35.59
            
            35.59
            
            0.00(Martin Co.,
              Muhlenberg Co.)ICG
      Natural Resources
            
            Unassigned
            
            
            
            WV
            
            UG
            
            21.62
            
            21.62
            
            0.00(Mobil)Powell Mountain
            
            Unassigned
            
            O
            
            VA
            
            UG
            
            46.07
            
            46.07
            
            0.00Beckley
            
            Unassigned
            
            O
            
            WV
            
            UG
            
            1.88
            
            0.00
            
            1.88Juliana
      Mining Co., Inc.
            
            Unassigned
            
            D
            
            WV
            
            S/UG
            
            3.10
            
            3.10
            
            0.00White
      Wolf Energy, Inc.
            
            Unassigned
            
            D
            
            VA
            
            UG
            
            2.58
            
            2.58
            
            0.00(Big
      Creek)Central
      Appalachia Total
            
            
            
            
            
            
            
            
            
            118.41
            
            116.53
            
            1.88OtherIllinois
            
            Assigned
            
            O
            
            IL
            
            UG
            
            38.47
            
            38.47
            
            0.00(Viper)ICG
      Natural Resources
            
            Unassigned
            
            
            
            IL
            
            UG
            
            57.92
            
            57.92
            
            0.00(Illinois)








59








Mining
      Operations
            
            Assigned
      or
              Unassigned(1)
            
            Operating (O) or
              Development (D)
            
            State
            
            Mining Method
              Surface
      (S) or
              Underground
              (UG)
            
            Total
              Non-Reserve
              Coal Deposits
            
            Steam
              Non-Reserve
              Coal Deposits
            
            Metallurgical(2)(3)
              Non-Reserve
              Coal
      Deposits(in
      million tons)ICG
      Natural Resources
            
            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
            
            9.86
            
            9.86
            
            0.00(Washington)Total
      Other
            
            
            
            
            
            
            
            
            
            265.40
            
            265.40
            
            0.00Total
      Non-Reserve Coal Deposits
            
            
            
            
            
            
            
            521.45
            
            519.13
            
            2.32








(1)
            “Assigned
      non-reserve coal deposits” mean coal which has been committed by the coal
      company to operating mine shafts, mining equipment and plant facilities,
      and all coal which has been leased by the coal company to others.
      “Unassigned non-reserve coal deposits” represent coal which has not been
      committed, and which would require new mine shafts, mining equipment or
      plant facilities before operations could begin in the
      property.(2)
            Beckley
      and White Wolf Energy, Inc. meet historical metallurgical coal quality
      specifications.(3)
            We
      sold coal with ash and sulfur contents as high as 10% and 1.5%,
      respectively, into the metallurgical market from Vindex Energy, Buckhannon
      and Sentinel in 2008. Similarly, we believe all production from
      Vindex Energy and portions of Hillman can be sold on this
      metallurgical market.





The
following table provides the “quality” (average moisture, ash and sulfur
contents and Btu per pound) of our non-reserve coal deposits as of
January 1, 2009:





As
      Received QualityMining
      Operations
            
            Assigned
      or
              Unassigned
      (1)
            
            %
              Moisture
            
            %
              Ash
            
            %
              Sulfur
            
            Btu/
      lb.
            
            Lbs. SO2/
              million Btu’sNorthern
      AppalachiaVindex
      Energy Corp.(3)
            
            Unassigned
            
            6.00
            
            14.15
            
            1.49
            
            12,409
            
            2.40Wolf
      Run Mining Buckhannon Division(3)
            
            Assigned
            
            6.00
            
            7.43
            
            2.83
            
            13,086
            
            4.32Unassigned
            
            6.00
            
            9.00
            
            1.20
            
            13,000
            
            1.85Sentinel(3)
            
            Assigned
            
            6.00
            
            8.30
            
            1.40
            
            13,100
            
            2.14Unassigned
            
            6.00
            
            8.30
            
            1.40
            
            13,100
            
            2.14Upshur
      Property
            
            Unassigned
            
            6.00
            
            43.00
            
            2.00
            
            8,000
            
            5.00Central
      AppalachiaEastern
            
            Assigned
            
            6.00
            
            12.20
            
            1.20
            
            12,400
            
            1.94Hazard
            
            Assigned
            
            6.00
            
            13.51
            
            1.07
            
            11,880
            
            1.79Flint
      Ridge
            
            Assigned
            
            6.00
            
            8.15
            
            1.39
            
            12,768
            
            2.18Knott County
            
            Assigned
            
            N/A
            
            N/A
            
            N/A
            
            N/A
            
            N/AEast
      Kentucky
            
            Assigned
            
            N/A
            
            N/A
            
            N/A
            
            N/A
            
            N/A(Mt. Sterling)ICG
      Natural Resources
            
            Assigned
            
            7.00
            
            7.78
            
            0.63
            
            12,609
            
            1.01(Jennie Creek)ICG
      Natural Resources
            
            Unassigned
            
            6.00
            
            11.47
            
            1.91
            
            11,780
            
            3.24(Martin Co.,
              Muhlenberg Co.)ICG
      Natural Resources
            
            Unassigned
              (Mobil)
            
            6.00
            
            12.50
            
            1.10
            
            12,000
            
            1.83Powell Mountain
            
            Unassigned
            
            6.00
            
            5.78
            
            1.21
            
            13,348
            
            1.81Beckley(2)
            
            Unassigned
            
            6.00
            
            4.80
            
            0.70
            
            13,800
            
            1.01Juliana
      Mining Co., Inc.
            
            Unassigned
            
            6.00
            
            7.50
            
            0.82
            
            13,100
            
            1.25White
      Wolf Energy, Inc.(2)
            
            Unassigned
            
            6.00
            
            7.40
            
            0.60
            
            13,500
            
            0.89(Big Creek)








60











As
      received qualityMining
      operations
            
            Assigned
      or
              Unassigned
      (1)
            
            %
              Moisture
            
            %
              Ash
            
            %
              Sulfur
            
            Btu/
      lb.
            
            Lbs. SO2/
              million Btu’sOtherIllinois
            
            Assigned
            
            16.00
            
            9.50
            
            3.50
            
            10,500
            
            6.67(Viper)ICG
      Natural Resources
            
            Unassigned
            
            13.00
            
            9.00
            
            3.00
            
            11,000
            
            5.45(Illinois)ICG
      Natural Resources
            
            Unassigned
            
            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 coal
      company to operating mine shafts, mining equipment and plant facilities,
      and all coal which has been leased by the coal company to others.
      “Unassigned non-reserve coal deposits” represent coal which has not been
      committed, and which would require new mineshafts, mining equipment or
      plant facilities before operations could begin in the
      property.(2)
            Beckley
      and White Wolf Energy, Inc. meet historical metallurgical coal quality
      specifications.(3)
            We
      sold coal with ash and sulfur contents as high as 10% and 1.5%,
      respectively, into the metallurgical market from Vindex Energy, Buckhannon
      and Sentinel 2008. Similarly, we believe all production from
      Vindex Energy and portions of Hillman can be sold on this
      metallurgical market.





ITEM 3.
            LEGAL
      PROCEEDINGS





On
August 23, 2006, a survivor of the Sago mine accident, Randal McCloy, filed
a complaint in the Kanawha Circuit Court in Kanawha County, West Virginia. The
claims brought by Randal McCloy and his family against us and certain of our
subsidiaries, and against W.L. Ross & Co., and Wilbur L. Ross, Jr.,
individually, were dismissed on February 14, 2008, after the parties
reached a confidential settlement. Sixteen other complaints have been filed in
Kanawha Circuit Court by the representatives of many of the miners who died in
the Sago mine accident, and several of these plaintiffs have filed amended
complaints to expand the group of defendants in the cases. The complaints allege
various causes of action against us and our subsidiary, Wolf Run Mining Company,
one of our shareholders, W.L. Ross & Co., and Wilbur L. Ross Jr.,
individually, related to the accident and seek compensatory and punitive
damages. In addition, the plaintiffs also allege causes of action against other
third parties, including claims against the manufacturer of Omega block seals
used to seal the area where the explosion occurred and against the manufacturer
of self-contained self-rescuer (“SCSR”) devices worn by the miners at the Sago
mine. Some of these third parties have been dismissed from the actions upon
settlement. The amended complaints add other of our subsidiaries to the cases,
including ICG, Inc., ICG, LLC and Hunter Ridge Coal Company, unnamed parent,
subsidiary and affiliate companies of us, W.L. Ross & Co., and Wilbur
L. Ross Jr., and other third parties, including a provider of electrical
services and a supplier of components used in the SCSR devices. We believe that
we are appropriately insured for these and other potential claims, and we have
fully paid our deductible applicable to our insurance policies. In addition to
the dismissal of the McCloy claim, we have settled and dismissed five other
actions. These settlements required the release of us, our subsidiaries, W. L.
Ross & Co., and Wilbur L. Ross, Jr. Some of the plaintiffs involved in
one of the dismissed actions have sought permission from the Supreme Court of
Appeals of West Virginia to appeal the settlement, alleging that the settlement
negotiated by the decedent’s estate should not have been approved by the trial
court. The trial court overruled those plaintiffs’ objections to the settlement,
and, although the West Virginia Supreme Court of Appeals refused to stay the
effectiveness of the settlement, the plaintiffs’ petition for appeal to the West
Virginia Supreme Court of Appeals was recently presented to the court. The court
has not yet ruled whether it will accept the petition for appeal or decline to
hear the appeal. We will vigorously defend ourselves against the remaining
complaints and any appeal of any prior settlements.





61





Allegheny
Energy Supply (“Allegheny”), the sole customer of coal produced at our
subsidiary Wolf Run Mining Company’s (“Wolf Run”) Sycamore No. 2 mine,
filed a lawsuit against Wolf Run, Hunter Ridge Holdings, Inc. (“Hunter Ridge”),
and us in state court in Allegheny County, Pennsylvania on December 28,
2006, and amended its complaint on April 23, 2007. Allegheny claims that we
breached a coal supply contract when we declared force majeure under the
contract upon idling the Sycamore No. 2 in the third quarter of 2006. The
Sycamore No. 2 mine was idled after encountering adverse geologic
conditions and abandoned gas wells that were previously unidentified and
unmapped. The amended complaint also alleges that the production stoppages
constitute a breach of the guarantee agreement by Hunter Ridge and breach of
certain representations made upon entering into the contract in early 2005, a
claim that Allegheny has since voluntarily dropped. Allegheny claims that it
will incur costs in excess of $100.0 million to purchase replacement coal over
the life of the contract. We, Wolf Run and Hunter Ridge answered the amended
complaint on August 13, 2007, disputing all of the remaining claims. On November
3, 2008, we, Wolf Run and Hunter Ridge filed an amended answer and
counterclaim against the plaintiffs seeking to void the coal supply agreement
due to, among other things, fraudulent inducement and conspiracy. The
counterclaim alleges further that Allegheny breached a confidentiality agreement
with Hunter Ridge, which prohibited the solicitation of its employees. After the
coal supply agreement was executed, Allegheny hired the then-president of Anker
Coal Group, Inc. (now Hunter Ridge) who engaged in negotiations on behalf of
Wolf Run and Hunter Ridge. In addition to seeking a declaratory judgment that
the coal supply agreement and guaranty be deemed void and unenforceable and
rescission of the contracts, the counterclaim also seeks compensatory and
punitive damages.





On
December 6, 2007, the Kentucky Waterways Alliance, Inc., and The Sierra
Club sued the U.S. Army Corps of Engineers (the “ACOE”) in the United States
District Court for the Western District of Kentucky, Louisville Division (the
“Court”), asserting that a permit to construct five valley fills was issued
unlawfully to our Hazard subsidiary for its Thunder Ridge Surface mine. The suit
alleges that the ACOE failed to comply with the requirements of both
Section 404 of the Clean Water Act and the National Environmental Policy
Act. Hazard has intervened in the suit to protect our interests. The ACOE
suspended the Section 404 permit on December 26, 2007 in order to
evaluate the issues raised by the plaintiffs. That evaluation is now in
progress. If the ACOE reinstates the permit and the Court subsequently finds
that the permit is unlawful, production could be materially affected at the
Thunder Ridge Surface mine and the process of obtaining ACOE permits for coal
mining activities in Kentucky could become more difficult.





On
January 7, 2008, Saratoga Advantage Trust filed a class action lawsuit in
the U.S. District Court for the Southern District of West Virginia against us
and certain of our officers and directors. The complaint asserts claims under
Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule
10b-5 promulgated thereunder, based on alleged false and misleading statements
in the registration statements filed in connection with our November 2005
reorganization and December 2005 public offering of common stock. In addition,
the complaint challenges other of our public statements regarding our operating
condition and safety record. We intend to vigorously defend the
action.





On
July 3, 2007, Taylor Environmental Advocacy Membership, Inc. (“T.E.A.M.”) filed
a petition to appeal the issuance of ICG Tygart Valley, LLC’s (“Tygart Valley”)
Surface Mine Permit U-2004-06 against the West Virginia Department of
Environmental Protection (the “WVDEP”) in an action before the West Virginia
Surface Mine Board (the “Board”). On December 10, 2007, the Board remanded the
permit to the WVDEP for revision to certain provisions related to pre-mining
water monitoring and cumulative hydrologic impacts. The WVDEP issued a
modification on April 1, 2008 addressing those issues. T.E.A.M. filed an appeal
of the WVDEP’s approval of the permit modification on April 30, 2008. On October
7, 2008, the Board issued an order remanding the permit to the WVDEP requiring
Tygart Valley to address a technical issue related to projected post-mining
water quality. Tygart Valley has prepared and submitted a permit modification to
alleviate the board’s concerns. All site development will be suspended until the
WVDEP has approved the permit modification. If the WVDEP issues the permit
as modified, there will be additional opportunity for appeal by T.E.A.M.





62





In
addition, from time to time, we are involved in legal proceedings arising in the
ordinary course of business. These proceedings include assessments of penalties
for citations and orders asserted by MSHA and other regulatory agencies, none of
which are expected by management to, individually or in the aggregate, have a
material adverse effect on us. In the opinion of management, we have recorded
adequate reserves for liabilities arising in the ordinary course and it is
management’s belief there is no individual case or group of related cases
pending that is likely to have a material adverse effect on our financial
condition, results of operations or cash flows.





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





No
matters were submitted to a vote of security holders during the quarter ended
December 31, 2008.








PART
II





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





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





Stock
      PriceHigh
            
            Low2007January 1,
      2007 through March 31, 2007
            
            $
            5.61
            
            
            $
            4.70April 1,
      2007 through June 30, 2007
            
            
            6.48
            
            
            
            5.24July 1,
      2007 through September 30, 2007
            
            
            6.12
            
            
            
            3.85October 1,
      2007 through December 31, 2007
            
            
            5.57
            
            
            
            4.452008January 1,
      2008 through March 31, 2008
            
            $
            6.98
            
            
            $
            5.28April 1,
      2008 through June 30, 2008
            
            
            13.28
            
            
            
            6.01July 1,
      2008 through September 30, 2008
            
            
            13.11
            
            
            
            5.61October 1,
      2008 through December 31, 2008
            
            
            5.98
            
            
            
            1.50





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





As
of February 19, 2009, there were approximately 243 holders of record of our
common stock and an additional 48,402 stockholders whose shares were held for
them in street name or nominee accounts.





63








Summary
of Equity Compensation Plans





Shown
below is information concerning our equity compensation plans and individual
compensation arrangements as of December 31, 2008.





Equity
      Compensation Plan InformationPlan
      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
      PlansEquity
      compensation plans approved by stockholders(1)
            
            2,512,140
            
            $
            7.49
            
            5,175,023Equity
      compensation plans not approved by stockholders(2)
            
            319,052
            
            
            10.97
            
            —2,831,192
            
            $
            7.88
            
            5,175,023








(1)
            We
      have two compensation plans: the 2005 Equity and Performance Incentive
      Plan, which was approved by stockholders on October 24, 2005, and the
      Director Compensation Plan.(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 13 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 facility and indenture governing the senior
notes limits us from paying cash dividends or other payments or distributions
with respect to our capital stock in excess of certain limitations. In addition,
the terms of any future credit agreement may contain similar restrictions on our
ability to pay dividends or make payments or distributions with respect to our
capital stock.





64










ITEM 6.
            SELECTED
      FINANCIAL DATA





International
Coal Group, Inc. was formed in March 2005 as a 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 December 31, 2008 and 2007 and for the years ended December 31,
2008, 2007 and 2006 which is included elsewhere in this report. The selected
historical consolidated financial data of International Coal Group, Inc. as of
December 31, 2006, 2005 and 2004, the year ended December 31, 2005 and for
the period May 13, 2004 (inception) to December 31, 2004 is derived
from audited consolidated financial statements which are not included in this
report. The selected historical consolidated financial data as of and for the
nine months ended September 30, 2004 is derived from the consolidated
financial statements of Horizon, our predecessor, which has been audited and is
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.





During
the years ended December 31, 2008 and 2007, we recorded impairment losses of
$37.4 million and $170.4 million, respectively. For 2008, $30.2 million of the
loss related to impairment of goodwill at our ADDCAR subsidiary and $7.2 million
related to impairment of long-lived assets. For 2007, the impairment loss
related to impairment of goodwill at various of our business units. See Notes 4
and 5 to our consolidated financial statements for further discussion of the
impairment losses.





On
November 18, 2005, we consummated a business combination with each of Anker and
CoalQuest. The results of operations of Anker and CoalQuest are included in our
consolidated results of operations since that date.





65











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 the
related notes thereto. Amounts shown are in thousands, except per share
data.




International
      Coal Group, Inc.
              
              
              Horizon
                (Predecessor
      to International Coal Group, Inc.)Year
      ended
                December 31,
                2008(2)
              
              
              Year
      ended
                December 31,
                2007(2)
              
              
              Year
      ended
                December 31,
                2006(2)
              
              
              Year
      ended
                December 31,
                2005(2)
              
              
              Period
      from
                May 13,
                2004
      to
                December 31,
                2004
              
              
              Period
      from
                January 1,
                2004
      to
                September 30,
                2004Statement
      of Operations Data:Coal
      sales revenues
              
              $
              998,245
              
              
              $
              770,663
              
              
              $
              833,998
              
              
              $
              619,038
              
              
              $
              130,463
              
              
              $
              346,981Freight
      and handling revenues
              
              
              45,231
              
              
              
              29,594
              
              
              
              18,890
              
              
              
              8,601
              
              
              
              880
              
              
              
              3,700Other
      revenues
              
              
              53,260
              
              
              
              48,898
              
              
              
              38,706
              
              
              
              22,852
              
              
              
              5,648
              
              
              
              22,841Total
      revenues
              
              
              1,096,736
              
              
              
              849,155
              
              
              
              891,594
              
              
              
              650,491
              
              
              
              136,991
              
              
              
              373,522Costs
      and Expenses:Cost
      of coal sales and other revenues
              
              
              918,655
              
              
              
              766,158
              
              
              
              769,332
              
              
              
              510,097
              
              
              
              113,527
              
              
              
              306,429Freight
      and handling costs
              
              
              45,231
              
              
              
              29,594
              
              
              
              18,890
              
              
              
              8,601
              
              
              
              880
              
              
              
              3,700Depreciation,
      depletion and amortization
              
              
              96,047
              
              
              
              86,517
              
              
              
              72,218
              
              
              
              43,076
              
              
              
              7,932
              
              
              
              27,547Selling,
      general and administrative
              
              
              38,147
              
              
              
              33,325
              
              
              
              34,578
              
              
              
              28,828
              
              
              
              4,205
              
              
              
              8,477Gain
      on sale of assets
              
              
              (32,518
              )
              
              
              (38,656
              )
              
              
              (1,125
              )
              
              
              (502
              )
              
              
              (10
              )
              
              
              (226
              )Impairment
      loss
              
              
              37,428
              
              
              
              170,402
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —Writedowns
      and special items
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              10,018Total
      costs and expenses
              
              
              1,102,990
              
              
              
              1,047,340
              
              
              
              893,893
              
              
              
              590,100
              
              
              
              126,534
              
              
              
              355,945Income
      (loss) from operations
              
              
              (6,254
              )
              
              
              (198,185
              )
              
              
              (2,299
              )
              
              
              60,391
              
              
              
              10,457
              
              
              
              17,577Interest
      and Other Income (Expense):Interest
      expense, net
              
              
              (43,643
              )
              
              
              (35,989
              )
              
              
              (18,091
              )
              
              
              (14,394
              )
              
              
              (3,453
              )
              
              
              (114,211Reorganization
      items
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              
              (12,471
              )Other,
      net
              
              
              —
              
              
              
              319
              
              
              
              2,113
              
              
              
              3,302
              
              
              
              16
              
              
              
              1,442Total
      interest and other income (expense)
              
              
              (43,643
              )
              
              
              (35,670
              )
              
              
              (15,978
              )
              
              
              (11,092
              )
              
              
              (3,437
              )
              
              
              (125,240
              )Income
      (loss) before income taxes
              
              
              (49,897
              )
              
              
              (233,855
              )
              
              
              (18,277
              )
              
              
              49,299
              
              
              
              7,020
              
              
              
              (107,663
              )Income
      tax (expense) benefit
              
              
              23,670
              
              
              
              85,944
              
              
              
              9,015
              
              
              
              (16,986
              )
              
              
              (2,660
              )
              
              
              —Net
      income (loss)
              
              
              (26,227
              )
              
              
              (147,911
              )
              
              
              (9,262
              )
              
              
              32,313
              
              
              
              4,360
              
              
              
              (107,663
              )Net
      (income) loss attributable to noncontrolling interest
              
              
              —
              
              
              
              349
              
              
              
              (58
              )
              
              
              15
              
              
              
              —
              
              
              
              —Net
      income (loss) attributable to International Coal Group,
    Inc.
              
              $
              (26,227
              )
              
              $
              (147,562
              )
              
              $
              (9,320
              )
              
              $
              32,328
              
              
              $
              4,360
              
              
              $
              (107,663
              )







66








International
      Coal Group, Inc.
            
            
            Horizon
              (Predecessor
      to International Coal Group, Inc.)Year
      ended
              December 31,
              2008(2)
            
            
            Year
      ended
              December 31,
              2007(2)
            
            
            Year
      ended
              December 31,
              2006(2)
            
            
            Year
      ended
              December 31,
              2005(2)
            
            
            Period
      from
              May 13,
              2004
      to
              December 31,
              2004
            
            
            Period
      from
              January 1,
              2004
      to
              September 30,
              2004Earnings
      Per Share(1):Basic
            
            $
            (0.17
            )
            
            $
            (0.97
            )
            
            $
            (0.06
            )
            
            $
            0.29
            
            
            $
            0.04
            
            
            $
            —Diluted
            
            
            (0.17
            )
            
            
            (0.97
            )
            
            
            (0.06
            )
            
            
            0.29
            
            
            
            0.04
            
            
            
            —Weighted-Average
      Common Shares Outstanding(1)
      :Basic
            
            
            152,632,586
            
            
            
            152,304,461
            
            
            
            152,028,165
            
            
            
            111,120,211
            
            
            
            106,605,999
            
            
            
            —Diluted
            
            
            152,632,586
            
            
            
            152,304,461
            
            
            
            152,028,165
            
            
            
            111,161,287
            
            
            
            106,605,999
            
            
            
            —Balance
      Sheet Data (at period end):Cash
      and cash equivalents
            
            $
            63,930
            
            
            $
            107,150
            
            
            $
            18,742
            
            
            $
            9,187
            
            
            $
            23,967
            
            
            $
            —Total
      assets
            
            
            1,350,647
            
            
            
            1,303,363
            
            
            
            1,316,891
            
            
            
            1,051,403
            
            
            
            457,045
            
            
            
            539,606Long-term
      debt and capital leases
            
            
            432,870
            
            
            
            391,248
            
            
            
            180,035
            
            
            
            45,462
            
            
            
            175,681
            
            
            
            29Total
      liabilities
            
            
            841,530
            
            
            
            771,595
            
            
            
            655,326
            
            
            
            383,879
            
            
            
            302,534
            
            
            
            1,422,290Total
      stockholders’ equity (members’ deficit)
            
            
            509,117
            
            
            
            531,768
            
            
            
            661,565
            
            
            
            667,524
            
            
            
            154,511
            
            
            
            (882,684
            )Total
      liabilities and stockholders’ equity (members’ deficit)
            
            
            1,350,647
            
            
            
            1,303,363
            
            
            
            1,316,891
            
            
            
            1,051,403
            
            
            
            457,045
            
            
            
            539,606Statement
      of Cash Flows Data:Net
      cash from:Operating
      activities
            
            $
            78,729
            
            
            $
            22,471
            
            
            $
            55,591
            
            
            $
            77,319
            
            
            $
            30,264
            
            
            $
            28,085Investing
      activities
            
            
            (124,040
            )
            
            
            (126,907
            )
            
            
            (160,769
            )
            
            
            (104,713
            )
            
            
            (329,168
            )
            
            
            3,437Financing
      activities
            
            
            2,091
            
            
            
            192,844
            
            
            
            114,733
            
            
            
            12,614
            
            
            
            322,871
            
            
            
            (32,381
            )Capital
      expenditures
            
            
            132,800
            
            
            
            160,807
            
            
            
            165,658
            
            
            
            108,231
            
            
            
            5,583
            
            
            
            6,624








(1)
            Earnings
      per share data and average shares outstanding are not presented 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 23 to the consolidated financial statements included
      elsewhere in this Annual Report on Form
10-K/A.





67








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





The
following discussion contains forward-looking statements that include numerous
risks and uncertainties. Actual results could differ materially from those
discussed in the forward-looking statements as a result of these risks and
uncertainties, including those set forth in this Annual Report on Form 10-K/A
under “Special Note Regarding Forward-Looking Statements” and under “Risk
Factors.” You should read the following discussion in conjunction with “Selected
Financial Data” and the audited and unaudited consolidated financial statements
and notes thereto of International Coal Group, Inc. and its subsidiaries
appearing elsewhere in this Annual Report on Form 10-K/A. Effective January 1,
2009, we adopted two accounting pronouncements that required retrospective
application. The following discussion incorporates the retrospective application
of FSP APB 14-1,Accounting
for Convertible Debt Instruments That May be Settled in Cash Upon Conversion
(Including Partial Cash Settlement), and SFAS No. 160,Noncontrolling Interests in
Consolidated Financial Statements–an amendment to ARB No.
51.





Overview





We
produce, process and sell steam coal from 13 regional mining complexes, which,
as of December 31, 2008 were supported by 14 active underground mines, 14 active
surface mines and 10 preparation plants located throughout West Virginia,
Kentucky, Virginia, Maryland and Illinois. We have three reportable business
segments, which are based on the coal regions in which we operate:
(i) Central Appalachian, comprised of both surface and underground mines,
(ii) Northern Appalachian, also comprised of both surface and underground
mines and (iii) Illinois Basin, representing one underground mine. For more
information about our reportable business segments, please see our audited
consolidated financial statements and the notes thereto 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
steam coal sales are primarily 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.





ICG,
Inc. was formed by WL Ross & Co. LLC (“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. With
the proceeds of our December 2005 public offering, we retired substantially all
of our then outstanding debt. Consistent with the WLR investor group’s strategy
to acquire attractive coal assets, the Anker and CoalQuest acquisitions further
diversified our reserves in November 2005.





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 pricing
environment for domestic steam and metallurgical coal during the first three
quarters of 2008 was relatively strong. In the fourth quarter of 2008, coal
prices dropped drastically due to decreased demand for metallurgical coal caused
by the global economic crisis and decreased demand for steam coal caused by high
inventory levels at utilities. We have experienced increased operating costs for
fuel and explosives, steel products, tires, healthcare and labor. While prices
of labor and commodities increased over prior year, we expect that current
economic conditions will reduce the inflationary pressures that drove up such
costs in 2008. However, we expect to experience higher costs for surety bonds
and letters of credit.





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.





68





Critical
Accounting Policies and Estimates





Our
financial statements are prepared in accordance with accounting principles that
are generally accepted in the United States of America. The preparation of these
financial statements requires management to make estimates and judgments that
affect the reported amount of assets, liabilities, revenues and expenses, as
well as the disclosure of contingent assets and liabilities. Management
evaluates its estimates on an on-going basis. Management bases its estimates and
judgments on historical experience and other factors that are believed to be
reasonable under the circumstances. Actual results may differ from the estimates
used. Our actual results have generally not differed materially from our
estimates. However, we monitor such differences and, in the event that actual
results are significantly different from those estimated, we disclose any
related impact on our results of operations, financial position and cash flows.
Note 2 to our audited consolidated financial statements provides a description
of significant accounting policies. We believe that of these significant
accounting policies, the following 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 or risk of loss has passed in accordance with
the terms of the sales agreement. Under the typical terms of these agreements,
risk of loss transfers to the customers at the mine or port, where coal is
loaded to the rail, barge, truck or other transportation sources that deliver
coal to its destination.





Coal
sales revenues also result from the sale of brokered coal produced by others.
Revenue is recognized and recorded at the time of shipment or delivery to the
customer, prices are fixed or determinable and the title or risk of loss has
passed in accordance with the terms of the sale agreement. The revenues related
to brokered coal sales are included in coal sales revenues on a gross basis and
the corresponding cost of the coal from the supplier is recorded in cost of coal
sales in accordance with Emerging Issues Task Force (“EITF”) 99-19,Reporting Revenue Gross as a
Principal versus Net as an Agent.





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





Other
revenues primarily consist of contract mining income, coalbed methane sales, ash
disposal services, equipment and parts sales, equipment rebuild and maintenance
services, royalties and coal handling and processing income. With respect to
other revenues recognized in situations unrelated to the shipment of coal, we
carefully review the facts and circumstances of each transaction and 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 related income is
earned.





Accounts
Receivable and Allowance for Doubtful Accounts





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





69





Reclamation





Our
asset retirement obligations arise from the Federal Surface Mining Control and
Reclamation Act of 1977 and similar state statutes, which require that mine
property be restored in accordance with specified standards and an approved
reclamation plan. We record these reclamation obligations according to the
provisions of SFAS No. 143. SFAS No. 143 requires the fair
value of a liability for an asset retirement obligation to be recognized in the
period in which the legal obligation associated with the retirement of the
long-lived asset is incurred. Fair value of reclamation liabilities is
determined based on the present value of the estimated future expenditures. When
the liability is initially recorded, the offset is capitalized by increasing the
carrying amount of the related long-lived asset. Over time, the liability is
accreted to its present value, and the capitalized cost is depreciated over the
useful life of the related asset. If the assumptions used to estimate the
liability do not materialize as expected or regulatory changes were to occur,
reclamation costs or obligations to perform reclamation and mine closing
activities could be materially different than currently estimated. To settle the
liability, the obligation is paid, and to the extent there is a difference
between the liability and the amount of cash paid, a gain or loss upon
settlement is recorded. 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, 2008, we had recorded asset retirement
obligation liabilities of $79.2 million, including amounts reported as current
liabilities. While the precise amount of these future costs cannot be determined
with certainty, as of December 31, 2008, we estimate that the aggregate
undiscounted cost of final mine closure is approximately $149.5
million.





Advance
Royalties





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





Inventories





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





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





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





70





Depreciation,
Depletion and Amortization





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





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 lands and mineral rights area. The amount of compensation paid
for the coal lands and mineral rights is a set amount; however, the “recoverable
tons” contained in the coal lands and mineral rights area are based on
engineering estimates which can, and often do, change as the tons are mined. Any
change in the number of “recoverable tons” contained in a coal lands and mineral
rights area will result in a change in the depletion rate and corresponding
depletion expense. For the year ended December 31, 2008, we recorded $2.0
million of depletion expense.





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





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





Coal
Reserves





There
are numerous uncertainties inherent in estimating quantities of economically
recoverable coal reserves, many of which are beyond our control. As a result,
estimates of economically recoverable coal reserves are by their nature
uncertain. Information about our reserves consists of estimates based on
engineering, economic and geological data assembled by our internal engineers
and geologists. Reserve estimates are periodically updated to reflect past coal
production, new drilling information and other geologic or mining data.
Acquisitions, sales or dispositions of coal properties will also change the
reserves. Some of the factors and assumptions that impact economically
recoverable reserve estimates include: (i) geological conditions; (ii)
historical production from the area compared with production from other
producing areas; (iii) the assumed effects of regulations and taxes by
governmental agencies; (iv) assumptions governing future prices; and (v)
future operating costs.





Each
of these factors may in fact vary considerably from the assumptions used in
estimating reserves. For these reasons, estimates of the economically
recoverable quantities of coal attributable to a particular group of properties,
and classifications of these reserves based on risk of recovery and estimates of
future net cash flows, may vary substantially. Actual production, revenues and
expenditures with respect to reserves will likely vary from estimates, and these
variances may be material. At December 31, 2008, we had 1.0 billion tons of coal
reserves.





71





Goodwill





As
a result of a prior acquisition, we had assigned goodwill to our ADDCAR
reporting unit based upon its estimated fair value. Pursuant to SFAS
No. 142, goodwill and intangible assets that are determined to have an
indefinite useful life are not amortized, but instead must be tested for
impairment at least annually, and more frequently if a triggering event occurs.
We perform our impairment test as of October 31 each year. The goodwill
impairment test consists of two steps. The first identifies potential impairment
by comparing the fair value of a reporting unit with its carrying amount,
including goodwill. Fair value of a reporting unit is estimated using present
value techniques, such as discounted cash flows of projected future operations
developed by management or a weighting of income and market approaches. If the
fair value of the reporting unit exceeds the carrying amount, goodwill is not
considered impaired and the second step is not necessary. If the carrying value
of the reporting unit exceeds the fair value, the second step is necessary to
measure the amount of impairment loss by comparing the implied fair value of
goodwill with its carrying amount. Implied fair value of goodwill is determined
as the amount that the fair value of the assets of a business unit exceeds their
carrying value, excluding goodwill. Impairment loss is measured as the amount of
the carrying value of goodwill that exceeds its implied fair value. We performed
an impairment test of goodwill related to our ADDCAR subsidiary as of
October 31, 2008. The results of the 2008 annual impairment test indicated
that its estimated fair value was less than the carrying amount of the
respective business unit assets, including goodwill, and, therefore, was
impaired. As a result, we recorded a $30.2 million non-cash impairment charge to
reduce the carrying amount of these assets to their estimated fair value.
Subsequent to this impairment charge, we have no goodwill remaining as of
December 31, 2008.





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 impairment indicators
are present. When the sum of projected cash flows is less than the carrying
amount, impairment losses are indicated. If the fair value of the assets is less
than the carrying amount of the assets, an impairment loss is recognized. In
determining such impairment losses, discounted cash flows or asset appraisals
are utilized to determine the fair value of the assets being evaluated. Also, in
certain situations, expected mine lives are shortened because of changes to
planned operations. When that occurs and it is determined that the mine’s
underlying costs are not recoverable in the future, reclamation and mine 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. Recognition of an impairment will decrease asset values, increase
operating expenses and decrease net income. In December 2008, we made the
decision to permanently close our Sago mine during the first quarter of 2009.
Upon making this decision, we performed an impairment test of related mine
development costs, which resulted in a $7.2 million non-cash impairment charge
to reduce the carrying amount of these assets to their estimated fair value.
There were no other impairment charges related to long-lived assets recognized
in 2008 as a result of our impairment tests.





Derivative
Financial Instruments





We
use derivative financial instruments to manage interest rate risk. We do 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 (“SFAS No. 133”),
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. We have not designated our derivatives as hedging instruments
and we recognize changes in the fair value of our derivatives in earnings in the
period of change.





72





We
enter into coal supply contracts with many of our customers. Certain of these
agreements meet the definition of a derivative under SFAS No. 133. We
analyze these agreements for qualification for the normal purchase, normal sale
exception under the standard. We enter into the contracts with the intent
to supply the related coal and do not trade the contracts. If we change our
intentions with respect to delivery on or operation of these contracts, the
accounting for the contracts could change.





Coal
Supply Agreements





We
have allocated purchase price to below-market coal supply agreements acquired in
acquisitions accounted for as business combinations. In accordance with
SFAS No. 141,Business Combinations, value was allocated to coal supply agreements
based on discounted cash flows attributable to the difference between the
below-market contract price and the prevailing market price at the date of
acquisition and was capitalized and is being amortized on the basis of coal to
be shipped over the term of the contracts. Determination of fair value requires
management’s judgment and often involves the use of significant estimates and
assumptions.





Stock-Based
Compensation





We
account for our stock-based awards in accordance with SFAS No. 123(R),Share Based Payment (“SFAS
No. 123(R)”). Under SFAS No. 123(R), stock-based compensation
expense is generally measured at the grant date and recognized as expense over
the vesting period of the award. We utilize restricted stock and stock options
as part of our stock-based compensation program. Determining fair value requires
us to make a number of assumptions, including expected term, risk-free rate and
expected volatility. The assumptions used in calculating the fair value of
stock-based awards represent our best estimates, but these estimates involve
inherent uncertainties and the application of management judgment. Although we
believe the assumptions and estimates we have made are reasonable and
appropriate, changes in assumptions could materially impact our reported
financial results.





Debt
Issuance Costs





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





Income
Taxes





We
account for income taxes in accordance with SFAS No. 109, 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 timing of the realization of deferred tax liabilities,
the expected level of future taxable income and available tax planning
strategies. If future taxable income is lower than expected or if expected tax
planning strategies are not available as anticipated, we may record a change to
the valuation allowance through income tax expense in the period the
determination is made.





73





Postretirement
Medical Benefits





Some
of our subsidiaries have long- and short-term liabilities for postretirement
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 postretirement benefits are not
funded. The liability is actuarially determined and we use various actuarial
assumptions, including the discount rate and future cost trends, to estimate the
costs and obligations for postretirement benefits. The discount rate assumption
reflects the rates available on a hypothetical portfolio of high-quality fixed
income debt instruments whose cash flows match the timing and amount of expected
benefit payments. The discount rate used to determine the net periodic benefit
cost for postretirement medical benefits was 6.25% for the year ended December
31, 2008. We make assumptions related to future trends for medical care costs in
the estimates of retiree healthcare and work-related injury and illness
obligations. The future healthcare cost trend rate represents the rate at which
healthcare costs are expected to increase over the life of the plan. The
healthcare cost trend rate assumptions are determined primarily based upon our,
and our predecessor’s, historical rate of change in retiree healthcare costs.
The postretirement expense in the operating period ended December 31, 2008 was
based on an assumed heath care inflationary rate of 8.3% in the operating period
decreasing to 5.0% in 2015, which represents the ultimate healthcare cost trend
rate for the remainder of the plan life. A one-percentage point increase in the
assumed ultimate healthcare cost trend rate would increase the service and
interest cost components of the postretirement benefit expense for the year
ended December 31, 2008 by $0.4 million and increase the accumulated
postretirement benefit obligation at December 31, 2008 by $1.8 million. A
one-percentage point decrease in the assumed ultimate healthcare cost trend rate
would decrease the service and interest cost components of the postretirement
benefit expense for the year ended December 31, 2008 by $0.4 million and
decrease the accumulated postretirement benefit obligation at December 31, 2008
by $1.7 million. If our assumptions do not materialize as expected or if
regulatory changes were to occur, actual cash expenditures and costs that we
incur could differ materially from our current estimates.





Workers’
Compensation





Workers’
compensation is a system by which individuals who sustain personal injuries due
to job-related accidents are compensated for their disabilities, medical costs
and, on some occasions, for the costs of their rehabilitation, and by which the
survivors of workers who suffer fatal injuries receive compensation for lost
financial support. The workers’ compensation laws are administered by state
agencies with each state having its own rules and regulations regarding
compensation that is owed to an employee who is injured in the course of
employment or the beneficiary of an employee that suffers fatal injuries in the
course of employment. Our operations are covered through a combination of
participation in a state run program and insurance policies. Our estimates of
these costs are adjusted based upon actuarially determined amounts using a
discount rate of 5.50% as of December 31, 2008. The discount rate assumption
reflects the rates available on a hypothetical portfolio of high-quality fixed
income debt instruments whose cash flows match the timing and amount of expected
benefit payments. If we were to decrease our estimate of the discount rate to
4.5%, the present value of our workers’ compensation liability would increase by
approximately $0.4 million. If we were to increase our estimate of the discount
rate to 6.5%, the present value of our workers’ compensation liability would
decrease by approximately $0.2 million. At December 31, 2008, we have recorded
an accrual of $7.8 million for workers’ compensation benefits. Actual losses may
differ from these estimates, which could increase or decrease our
costs.





74





Coal
Workers’ Pneumoconiosis





We
are responsible under various federal statutes, and various states’ statutes,
for the payment of medical and disability benefits to eligible employees
resulting from occurrences of coal workers’ pneumoconiosis disease (black lung).
Our operations are covered through a combination of participation in a state run
program and insurance policies. We accrue for any self-insured liability by
recognizing costs when it is probable that a covered liability has been incurred
and the cost can be reasonably estimated. Our estimates of these costs are
adjusted based upon actuarially determined amounts using a discount rate of
5.75% as of December 31, 2008. The discount rate assumption reflects the
rates available on a hypothetical portfolio of high-quality fixed income debt
instruments whose cash flows match the timing and amount of expected benefit
payments. If we were to decrease our estimate of the discount rate to 4.75%, the
present value of our black lung benefit liability would increase by
approximately $13.7 million. If we were to increase our estimate of the discount
rate to 6.75%, the present value of our black lung benefit liability would
decrease by approximately $10.1 million. At December 31, 2008, we have recorded
an accrual of $22.8 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 $1.3 million at December 31, 2008. Actual losses may differ
from these estimates, which could increase or decrease our costs. Our estimates
of these costs are adjusted based upon actuarially determined amounts using a
discount rate of 6.25% as of December 31, 2008. The discount rate assumption
reflects the rates available on a hypothetical portfolio of high-quality fixed
income debt instruments whose cash flows match the timing and amount of expected
benefit payments. If we were to decrease our estimate of the discount rate to
5.25%, the present value of our Coal Act liability would increase by
approximately $0.9 million. If we were to increase our estimate of the discount
rate to 7.25%, the present value of our Coal Act liability would decrease by
approximately $0.8 million. Prior to the business combination with Anker, we did
not have any liability under the Coal Act.





75








Results
of Operations





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





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





The
following table depicts revenues for the years ended December 31, 2008 and 2007
for the indicated categories:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2008
            
            
            2007
            
            $
      or Tons
            
            %(in thousands, except percentages
      and per ton data)Coal
      sales revenues
            
            $
            998,245
            
            
            $
            770,663
            
            $
            227,582
            
            30
            %Freight
      and handling revenues
            
            
            45,231
            
            
            
            29,594
            
            
            15,637
            
            53
            %Other
      revenues
            
            
            53,260
            
            
            
            48,898
            
            
            4,362
            
            9
            %Total
      revenues
            
            $
            1,096,736
            
            
            $
            849,155
            
            $
            247,581
            
            29
            %Tons
      sold
            
            
            18,914
            
            
            
            18,343
            
            
            571
            
            3
            %Coal
      sales revenue per ton
            
            $
            52.78
            
            
            $
            42.01
            
            $
            10.77
            
            26
            %





The
following table depicts coal sales revenues by operating segment for years ended
December 31, 2008 and 2007:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2008
            
            
            2007
            
            $
            
            %(in thousands, except percentages)Central
      Appalachian
            
            $
            672,077
            
            
            $
            512,352
            
            $
            159,725
            
            31
            %Northern
      Appalachian
            
            
            209,932
            
            
            
            121,200
            
            
            88,732
            
            73
            %Illinois Basin
            
            
            69,796
            
            
            
            60,368
            
            
            9,428
            
            16
            %Ancillary
            
            
            46,440
            
            
            
            76,743
            
            
            (30,303
            )
            (39
            )%Total
      coal sales revenues
            
            $
            998,245
            
            
            $
            770,663
            
            $
            227,582
            
            30
            %





The
following table depicts tons sold by operating segment for the years ended
December 31, 2008 and 2007:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2008
            
            
            2007
            
            Tons
            
            %(in thousands, except percentages)Central
      Appalachian
            
            
            11,617
            
            
            
            11,323
            
            
            294
            
            3
            %Northern
      Appalachian
            
            
            3,937
            
            
            
            3,291
            
            
            646
            
            20
            %Illinois Basin
            
            
            2,331
            
            
            
            2,025
            
            
            306
            
            15
            %Ancillary
            
            
            1,029
            
            
            
            1,704
            
            
            (675
            )
            (40
            )%Total
      tons sold
            
            
            18,914
            
            
            
            18,343
            
            
            571
            
            3
            %





Coal sales
revenues—Coal sales revenues are derived from sales of produced coal and
brokered coal contracts. Coal sales revenues increased for the year ended
December 31, 2008 compared to the year ended December 31, 2007 due to a 26%
increase in sales realization per ton resulting from increased spot
market and short-term contract sales entered into in order to capitalize on
favorable market conditions during the first three quarters of 2008. Further
impacting the increase in coal sales revenue was a 3% increase in tons sold
compared to the same period of 2007. Partially offsetting the impact of improved
realization per ton and the increase in tons sold was a decrease in coal sales
revenues attributable to the expiration of certain brokered coal
contracts.





Central Appalachian. Coal
sales revenues from our Central Appalachian segment for the year ended December
31, 2008 increased over the same period in 2007 primarily due to an increase of
$12.61 per ton, which was driven by higher average prices of our coal sold
pursuant to short-term supply agreements and on the spot market, including
increased sales of metallurgical coal, primarily from increased production at
our new Beckley operation.





76








Northern Appalachian. For the
year ended December 31, 2008, our Northern Appalachian coal sales revenues
increased due to an increase of $16.50 per ton resulting from higher average
prices of coal sold pursuant to coal supply agreements and from an increase in
sales of metallurgical coal, particularly on the spot market which provided
advantageous pricing throughout much of 2008. Additionally, we experienced an
increase in tons sold at certain of our complexes. The increase in tons sold was
mainly attributable to our Sentinel complex continuing to increase production
output to target levels, the ramp up of production at the formerly idled
Harrison operation during 2008 and increased production resulting from
investments in capital improvements made during the year.





Illinois Basin. The
increase in coal sales revenues from our Illinois Basin segment was due to
a 15% increase in tons sold resulting from increased short-term contract
sales.





Ancillary. Our Ancillary
segment’s coal sales revenues are comprised of coal sold under brokered coal
contracts. We experienced a decrease in tons sold due to the expiration of
certain brokered coal contracts.





Freight and
handling revenues—Freight and handling revenues represent reimbursement
of freight and handling costs for certain shipments for which we initially pay
the costs and are then reimbursed by the customer. Freight and handling revenues
and costs increased for the year ended December 31, 2008 compared to the same
period in 2007 primarily due to increased fuel surcharges and transportation
rates. Additionally, we have entered into new sales contracts during 2008 that
have increased freight and handling revenues and costs.





Other
revenues—The increase in other revenues for the year ended December 31,
2008 compared to the year ended December 31, 2007 was due to additional ash
disposal income, royalty income, sales of scrap materials, contract mining
revenues and an increase in revenue generated from coalbed methane wells owned
jointly by our subsidiary, CoalQuest, and CDX. The increases were partially
offset by a decrease in revenue from our ADDCAR subsidiary, primarily related to
the sale of a narrow bench highwall mining system in 2007.





Costs
and expenses





The
following table depicts cost of operations for the years ended December 31, 2008
and 2007 for the indicated categories:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2008
            
            
            2007
            
            $
            
            %(in thousands, except percentages
      and per ton data)Cost
      of coal sales
            
            $
            882,983
            
            
            $
            732,112
            
            $
            150,871
            
            21
            %Freight
      and handling costs
            
            
            45,231
            
            
            
            29,594
            
            
            15,637
            
            53
            %Cost
      of other revenues
            
            
            35,672
            
            
            
            34,046
            
            
            1,626
            
            5
            %Depreciation,
      depletion and amortization
            
            
            96,047
            
            
            
            86,517
            
            
            9,530
            
            11
            %Selling,
      general and administrative expenses
            
            
            38,147
            
            
            
            33,325
            
            
            4,822
            
            14
            %Gain
      on sale of assets
            
            
            (32,518
            )
            
            
            (38,656
            )
            
            6,138
            
            16
            %Impairment
      loss
            
            
            37,428
            
            
            
            170,402
            
            
            (132,974
            )
            (78
            )%Total
      costs and expenses
            
            $
            1,102,990
            
            
            $
            1,047,340
            
            $
            55,650
            
            5
            %Cost
      of coal sales per ton
            
            $
            46.68
            
            
            $
            39.91
            
            $
            6.77
            
            17
            %








77








The
following table depicts cost of coal sales by operating segment for the years
ended December 31, 2008 and 2007:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2008
            
            
            2007
            
            $
            
            %(in thousands, except percentages)Central
      Appalachian
            
            $
            595,683
            
            
            $
            468,958
            
            $
            126,725
            
            27
            %Northern
      Appalachian
            
            
            193,389
            
            
            
            147,745
            
            
            45,644
            
            31
            %Illinois Basin
            
            
            57,424
            
            
            
            46,701
            
            
            10,723
            
            23
            %Ancillary
            
            
            36,487
            
            
            
            68,708
            
            
            (32,221
            )
            (47
            )%Cost
      of coal sales
            
            $
            882,983
            
            
            $
            732,112
            
            $
            150,871
            
            21
            %





Cost of coal
sales—For the year ended December 31, 2008, our cost of coal sales
increased compared to the year ended December 31, 2007 primarily as a result of
a 17% increase in cost per ton, as well as a 3% increase in tons sold as
described above.





Central Appalachian. Cost of
coal sales from our Central Appalachian segment increased to $51.28 per ton for
the year ended December 31, 2008 from $41.42 per ton for the year ended December
31, 2007 primarily as a result of increased labor and diesel fuel costs. Labor
and benefit costs increased due to a tightening labor market resulting in the
need to offer more competitive compensation packages. Diesel fuel costs
increased over prior period as a result of higher per gallon fuel costs and
additional gallons used. Further impacting the increase in cost of coal sales
were increases in repairs and maintenance costs, contract labor costs,
royalties, severance taxes and reclamation costs.





Northern Appalachian. Our
Northern Appalachian segment cost of coal sales per ton increased to $49.13 for
the year ended December 31, 2008 from $44.89 for the year ended December 31,
2007 due to increased labor, diesel fuel and repairs and maintenance costs
resulting from certain high-dollar repairs performed during 2008. Additionally,
royalties, severance taxes and trucking costs increased at our Northern
Appalachian segment primarily due to increased coal sales. Partially offsetting
these increases was a decrease in purchased coal costs due to increased
production at our Vindex and Sentinel complexes.





Illinois Basin. For the
year ended December 31, 2008, our Illinois Basin cost of coal sales
increased by $1.57 per ton primarily due to increased labor, roof control
supplies and repairs and maintenance costs. Labor increased as demand for
skilled miners increased over 2007. Roof control supplies increased as prices
for steel were escalated for much of 2008. Additionally, repairs and maintenance
costs have increased due to several repairs on underground mining equipment
during 2008. Partially offsetting the aforementioned increases was a decrease in
royalty expense resulting from increased mining of owned reserves rather than
leased reserves as compared to 2007.





Ancillary. Cost of coal sales
from our Ancillary segment decreased for the year ended December 31, 2008
primarily due to a decrease in purchased coal costs related to the expiration of
certain brokered coal contracts.





Cost of other
revenues—For the year ended December 31, 2008, cost of other revenues
increased primarily due to increases in labor and benefits, ash disposal
transportation costs, gathering fees related to coalbed methane wells owned
jointly by our subsidiary, CoalQuest, and CDX and highwall miner expenses.
Partially offsetting the increases were the sale of a narrow bench highwall
mining system by our subsidiary ADDCAR in 2007 with no comparable sale in 2008
and decreased water treatment costs at a non-producing
property.





78








Depreciation,
depletion and amortization—The principal component of the increase in
depreciation, depletion and amortization expense was a decrease in amortization
income on below-market coal agreements. Additionally, there were increases in
depletion expense and depreciation expense due to significant additions to
property, plant, equipment and mine development during 2008. These increases
were partially offset by a decrease in amortization of coalbed methane well
development costs.





Selling, general
and administrative expenses—Selling, general and administrative expenses
for the year ended December 31, 2008 increased primarily due to increases in bad
debt expense, labor and benefit costs, sales tax expense and legal settlements.
Partially offsetting these increases were decreases in taxes and licenses
and legal and professional fees.





Gain on sale of
assets—Gain on sale of assets for 2008 related primarily to exchanges of
property, the sale of a used highwall mining system and the disposition of other
assets. The gain recognized in 2007 was primarily attributable to the sale of
the Denmark property.





Impairment
loss—The impairment loss reflects the write-off of goodwill in 2008
associated with our ADDCAR subsidiary, as a result of the negative impact of
several contributing factors which resulted in a reduction in the forecasted
cash flows used to estimate fair value. During 2007, all goodwill associated
with our Hazard, Knott County, East Kentucky and Eastern subsidiaries was
deemed to be impaired and written-off. Additionally, as a result of making the
decision to close the Sago mine, related development costs were deemed to be
impaired and were written-off during 2008. No comparable impairment occurred
during the prior year.





Adjusted
EBITDA by Operating Segment





Adjusted
EBITDA represents net income before deducting interest expense, income taxes,
depreciation, depletion, amortization, impairment charges and noncontrolling
interest. Adjusted EBITDA is presented because it is an important supplemental
measure of our performance used by our chief operating decision maker in such
areas as capital investment and allocation of resources. It is considered
“adjusted” as we adjust EBITDA for impairment charges and noncontrolling
interest. Other companies in our industry may calculate Adjusted EBITDA
differently than we do, limiting its usefulness as a comparative measure.
Adjusted EBITDA is reconciled to its most comparable GAAP measure on page 81 of
this Annual Report on Form 10-K/A and in Note 20 to our consolidated financial
statements for the year ended December 31, 2008.





The
following table depicts operating segment Adjusted EBITDA for the years ended
December 31, 2008 and 2007:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2008
            
            2007
            
            $
            
            %(in thousands, except percentages)Central
      Appalachian
            
            $
            107,186
            
            $
            47,442
            
            $
            59,744
            
            126
            %Northern
      Appalachian
            
            
            23,687
            
            
            (22,215
            )
            
            45,902
            
            207
            %Illinois Basin
            
            
            14,784
            
            
            15,463
            
            
            (679
            )
            (4
            )%Ancillary
            
            
            (18,436
            )
            
            18,363
            
            
            (36,799
            )
            (200
            )%Total
      Adjusted EBITDA
            
            $
            127,221
            
            $
            59,053
            
            $
            68,168
            
            115
            %





Adjusted
EBITDA from our Central Appalachian segment for the year ended December 31, 2008
increased compared to the year ended December 31, 2007 primarily due to a $24.6
million pre-tax gain on an exchange of coal reserves. The increase was further
impacted by an increase of approximately 294,000 tons sold and an increase in
profit margins of $2.74 per ton over prior year.





79











The
increase in Adjusted EBITDA from our Northern Appalachian segment was due to a
combination of an increase in sales realizations of $16.50 per ton, resulting in
increased profit margins of $12.27 per ton, as well as an increase of
approximately 646,000 tons sold.





Adjusted
EBITDA from our Illinois Basin segment decreased during the year ended
December 31, 2008 related to increases in operating costs with a less
significant corresponding increase in sales realizations. The increased costs
resulted in a decrease in profit margins of $1.44 per ton compared to the year
ended December 31, 2007.





The
decrease in Adjusted EBITDA from our Ancillary segment was primarily due to the
gain on the sale of the Denmark property that occurred during 2007. Also, there
was a decrease of approximately 675,000 tons sold related to the expiration of
brokered coal contracts, partially offset by increased profit margins of $4.95
per ton.





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





The
following tables reconcile Adjusted EBITDA to net income (loss) by operating
segment for the years ended December 31, 2008 and 2007:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2008
            
            
            2007
            
            $
            
            %(in thousands, except percentages)Central
      AppalachianNet
      income (loss) attributable to International Coal Group,
    Inc.
            
            $
            47,244
            
            
            $
            (184,372
            )
            $
            231,616
            
            126
            %Depreciation,
      depletion and amortization
            
            
            64,132
            
            
            
            60,015
            
            
            4,117
            
            7
            %Interest
      expense, net
            
            
            2,145
            
            
            
            1,397
            
            
            748
            
            54
            %Income
      tax benefit
            
            
            (6,335
            )
            
            
            —
            
            
            (6,335
            )
            (100
            )%Impairment
      loss
            
            
            —
            
            
            
            170,402
            
            
            (170,402
            )
            (100
            )%Adjusted
      EBITDA
            
            $
            107,186
            
            
            $
            47,442
            
            $
            59,744
            
            126
            %





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2008
            
            
            2007
            
            $
            
            %(in thousands, except percentages)Northern
      AppalachianNet
      income (loss) attributable to International Coal Group,
    Inc.
            
            $
            3,217
            
            
            $
            (31,790
            )
            $
            35,007
            
            110
            %Depreciation,
      depletion and amortization
            
            
            17,884
            
            
            
            9,467
            
            
            8,417
            
            89
            %Interest
      expense, net
            
            
            717
            
            
            
            457
            
            
            260
            
            57
            %Income
      tax benefit
            
            
            (5,322
            )
            
            
            —
            
            
            (5,322
            )
            (100
            )%Impairment
      loss
            
            
            7,191
            
            
            
            —
            
            
            7,191
            
            100
            %Noncontrolling
      interest
            
            
            —
            
            
            
            (349
            )
            
            349
            
            100
            %Adjusted
      EBITDA
            
            $
            23,687
            
            
            $
            (22,215
            )
            $
            45,902
            
            207
            %





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2008
            
            
            2007
            
            $
            
            %(in thousands, except percentages)Illinois BasinNet
      income attributable to International Coal Group, Inc.
            
            $
            6,959
            
            
            $
            8,714
            
            $
            (1,755
            )
            (20
            )%Depreciation,
      depletion and amortization
            
            
            7,342
            
            
            
            6,527
            
            
            815
            
            12
            %Interest
      expense, net
            
            
            327
            
            
            
            222
            
            
            105
            
            47
            %Income
      tax expense
            
            
            156
            
            
            
            —
            
            
            156
            
            100
            %Adjusted
      EBITDA
            
            $
            14,784
            
            
            $
            15,463
            
            $
            (679
            )
            (4
            )%





80








Year
      ended
              December
      31,
            
            Increase
              (Decrease)2008
            
            
            2007
            
            $
            
            %(in thousands, except percentages)AncillaryNet
      income (loss) attributable to International Coal Group,
    Inc.
            
            $
            (83,647
            )
            
            $
            59,886
            
            $
            (143,533
            )
            (240
            )%Depreciation,
      depletion and amortization
            
            
            6,689
            
            
            
            10,508
            
            
            (3,819
            )
            (36
            )%Interest
      expense, net
            
            
            40,454
            
            
            
            33,913
            
            
            6,541
            
            19
            %Income
      tax benefit
            
            
            (12,169
            )
            
            
            (85,944
            )
            
            73,775
            
            86
            %Impairment
      loss
            
            
            30,237
            
            
            
            —
            
            
            30,237
            
            100
            %Adjusted
      EBITDA
            
            $
            (18,436
            )
            
            $
            18,363
            
            $
            (36,799
            )
            (200
            )%





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2008
            
            
            2007
            
            $
            
            %(in thousands, except percentages)ConsolidatedNet
      loss attributable to International Coal Group, Inc.
            
            $
            (26,227
            )
            
            $
            (147,562
            )
            $
            121,335
            
            82
            %Depreciation,
      depletion and amortization
            
            
            96,047
            
            
            
            86,517
            
            
            9,530
            
            11
            %Interest
      expense, net
            
            
            43,643
            
            
            
            35,989
            
            
            7,654
            
            21
            %Income
      tax benefit
            
            
            (23,670
            )
            
            
            (85,944
            )
            
            62,274
            
            72
            %Impairment
      loss
            
            
            37,428
            
            
            
            170,402
            
            
            (132,974
            )
            (78
            )%Noncontrolling
      interest
            
            
            —
            
            
            
            (349
            )
            
            349
            
            100
            %Adjusted
      EBITDA
            
            $
            127,221
            
            
            $
            59,053
            
            $
            68,168
            
            115
            %





81




















Year
Ended December 31, 2007 Compared to the Year Ended December 31,
2006





Revenues





The
following table depicts revenues for the years ended December 31, 2007 and
2006 for the indicated categories:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2007
            
            
            2006
            
            $
      or Tons
            
            %(in thousands, except percentages
      and per ton data)Coal
      sales revenues
            
            $
            770,663
            
            
            $
            833,998
            
            $
            (63,335
            )
            (8
            )%Freight
      and handling revenues
            
            
            29,594
            
            
            
            18,890
            
            
            10,704
            
            57
            %Other
      revenues
            
            
            48,898
            
            
            
            38,706
            
            
            10,192
            
            26
            %Total
      revenues
            
            $
            849,155
            
            
            $
            891,594
            
            $
            (42,439
            )
            (5
            )%Tons
      sold
            
            
            18,343
            
            
            
            19,371
            
            
            (1,028
            )
            (5
            )%Coal
      sales revenue per ton
            
            $
            42.01
            
            
            $
            43.05
            
            $
            (1.04
            )
            (2
            )%





Coal sales
revenues. Coal sales revenues are derived from sales of produced
coal and brokered coal contracts. Coal sales revenues decreased $63.3 million
for the year ended December 31, 2007, or 8%, compared to 2006. This
decrease was due to a 5% decrease in tons sold in 2007 compared to 2006 that
resulted from a decrease of approximately 4.7 million tons sold related to
the idling, closure or cutback of production at mines in 2007 as discussed below
and the expiration of certain brokered coal contracts, as well as geologic
issues at several other mines. The decrease in coal sales revenue from decreased
sales tons was further impacted by a $1.04 per ton reduction in sales
realization of our coal primarily sold pursuant to coal supply agreements. These
decreases were partially offset by a 3.4 million ton increase in tons sold
from new mines that commenced full production in 2007 and from mines that
experienced a full year of production in 2007.





Freight and handling
revenues. Freight and handling revenues represent dollar-for-dollar
reimbursement for shipments from certain of our operations for which we
initially pay the freight and handling costs and are then reimbursed by the
customer. Freight and handling revenues and costs increased $10.7 million to
$29.6 million for the year ended December 31, 2007 compared to 2006 due to
an increase in shipments from locations operating under such agreements, as well
as increased transportation rates and fuel surcharges.





Other revenues. Other
revenues increased $10.2 million for the year ended December 31, 2007
compared to 2006. The increase was due to $6.8 million of revenue generated from
coalbed methane wells owned jointly by our subsidiary, CoalQuest, and CDX, as
well as increased revenue of $3.7 million from our highwall mining activities
and shop services and $7.2 million from the sale of a narrow bench highwall
mining system by ADDCAR. Partially offsetting these increases was a decrease in
plant processing revenue of $1.1 million. Additionally, we recognized a $7.0
million gain in 2006 related to the termination of a contractual coal delivery
obligation. No comparable gain was recognized in 2007.





82





Coal
sales revenues and tons sold by segment





The
following table depicts coal sales revenues by operating segment for the years
ended December 31, 2007 and 2006:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2007
            
            
            2006
            
            $
            
            %(in thousands, except percentages)Central
      Appalachian
            
            $
            512,352
            
            
            $
            534,429
            
            $
            (22,077
            )
            (4
            )%Northern
      Appalachian
            
            
            121,200
            
            
            
            109,184
            
            
            12,016
            
            11
            %Illinois Basin
            
            
            60,368
            
            
            
            49,842
            
            
            10,526
            
            21
            %Ancillary
            
            
            76,743
            
            
            
            140,543
            
            
            (63,800
            )
            (45
            )%Total
      coal sales revenues
            
            $
            770,663
            
            
            $
            833,998
            
            $
            (63,335
            )
            (8
            )%





The
following table depicts tons sold by operating segment for the years ended
December 31, 2007 and 2006:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2007
            
            
            2006
            
            Tons
            
            %(in thousands, except percentages)Central
      Appalachian
            
            
            11,323
            
            
            
            10,904
            
            
            419
            
            4
            %Northern
      Appalachian
            
            
            3,291
            
            
            
            3,281
            
            
            10
            
            *
            %Illinois Basin
            
            
            2,025
            
            
            
            2,020
            
            
            5
            
            *
            %Ancillary
            
            
            1,704
            
            
            
            3,166
            
            
            (1,462
            )
            (46
            )%Total
      tons sold
            
            
            18,343
            
            
            
            19,371
            
            
            (1,028
            )
            (5
            )%





*
Not meaningful





Coal
sales revenues from our Central Appalachian segment decreased approximately
$22.1 million, or 4%, for the year ended December 31, 2007 as compared to
the year ended December 31, 2006. This decrease was primarily attributable
to a decrease of $3.76 per ton in the average sales price of our coal primarily
sold pursuant to coal supply agreements. The decrease in sales realization was
partially offset by an increase in tons sold of approximately 0.4 million,
or 4%, over 2006 due to various mines, principally at our Eastern and Raven
locations, significantly increasing or reaching full production in
2007.





For
the year ended December 31, 2007, our Northern Appalachian coal sales
revenues increased approximately $12.0 million, or 11%, as compared to 2006 due
to an increase in sales realization of $3.55 per ton as segment operations
benefited from favorable pricing from its coal supply agreements, as well as an
increase in sales of metallurgical coal at prevailing market prices. Tons sold
from our Northern Appalachian operations remained constant as compared to the
prior year.





Coal
sales revenues from our Illinois Basin segment increased approximately
$10.5 million, or 21%, as compared to 2006 due to an increase in coal sales
revenue of $5.12 per ton resulting from more favorable terms on its coal supply
agreements.





Our
Ancillary segment’s coal sales revenues are comprised of coal sold under
brokered coal contracts. We experienced a decrease of $63.8 million, or 45%, due
to a decrease of 1.5 million tons primarily resulting from the expiration
of brokered coal contracts.





83





Costs
and expenses





The
following table depicts cost of operations for the years ended December 31,
2007 and 2006 for the indicated categories:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2007
            
            
            2006
            
            $
            
            %(in thousands, except percentages
      and per ton data)Cost
      of coal sales
            
            $
            732,112
            
            
            $
            739,914
            
            $
            (7,802
            )
            (1
            )%Freight
      and handling costs
            
            
            29,594
            
            
            
            18,890
            
            
            10,704
            
            57
            %Cost
      of other revenues
            
            
            34,046
            
            
            
            29,418
            
            
            4,628
            
            16
            %Depreciation,
      depletion and amortization
            
            
            86,517
            
            
            
            72,218
            
            
            14,299
            
            20
            %Selling,
      general and administrative expenses
            
            
            33,325
            
            
            
            34,578
            
            
            (1,253
            )
            (4
            )%Net
      gain on sale of assets
            
            
            (38,656
            )
            
            
            (1,125
            )
            
            (37,531
            )
            *
            %Goodwill
      impairment loss
            
            
            170,402
            
            
            
            —
            
            
            170,402
            
            100
            %Total
      costs and expenses
            
            $
            1,047,340
            
            
            $
            893,893
            
            $
            153,447
            
            17
            %Cost
      of coal sales per ton
            
            $
            39.91
            
            
            $
            38.20
            
            $
            1.71
            
            4
            %





*
Not meaningful





Cost of coal sales. For
the year ended December 31, 2007, our total cost of coal sales decreased
$7.8 million, or 1%, to $732.1 million compared to $739.9 million for the year
ended December 31, 2006. The decrease in cost of coal sales was primarily
the result of a 5% decrease in tons sold as described above which was partially
offset by a 4% increase in cost per ton.





Mining
operations that significantly increased or reached full production in 2007 at
our East Mac and Nellie, Flint Ridge Deep, Raven, Mt. Sterling, Guston Run,
Crown Surface, Imperial, Sentinel, County Line and Middle Fork mines increased
cost of coal sales by $144.0 million. Increased costs from new mining operations
were partially offset by a decrease in costs of $111.9 million resulting from
the closure or cutback of production at our higher cost Flint Ridge Surface,
Rowdy Gap, Flint Ridge Highwall, Blackberry Creek, New Hill, Sago, Crown East
II, Sycamore No. 1, Island, Tip Top and Elk Hollow mines. Cost of coal
sales at existing mines, as well as from brokered coal contracts, decreased
$40.5 million, primarily as a result of a 1.1 million ton decrease in
coal sales.





Cost
of coal sales per ton increased to $39.91 for the year ended December 31,
2007 compared to $38.20 in 2006, an increase of $1.71. The increase was mainly
due to a $1.34 per ton increase in the average cost of produced coal sold. The
increase in cost per ton of produced coal was caused by increases of: $0.46 per
ton in labor and benefit costs; $0.27 per ton in contract labor; $0.44 per ton
insurance and worker’s compensation costs; $0.18 per ton in fuel, oil and
lubricants; $0.26 per ton in blending material; $0.10 per ton in insurance; and
$0.20 per ton in roof control supplies. The increases were partially offset by
decreases of: $0.52 per ton in equipment and vehicle lease costs. Purchased coal
increased $3.87 per ton, resulting in an increase of $0.38 per ton in the
average cost of coal sold.





Cost of other
revenues. For the year ended December 31, 2007, cost of other
revenues increased $4.6 million, or 16%, to $34.0 million compared to $29.4
million for the year ended December 31, 2006. Of the increase,
approximately $4.7 million was due to costs related to ADDCAR’s sales of mining
equipment during the year and exploration and development of coalbed methane
resulted in an additional increase of $1.8 million.





84








Depreciation, depletion and
amortization. Depreciation, depletion and amortization expense
increased $14.3 million, or 20%, to $86.5 million for the year ended
December 31, 2007 compared to $72.2 million in 2006. The principal
component of the increase was an increase in depreciation and amortization
expense of $14.5 million for the year ended December 31, 2007 related to
increased property and equipment purchased to improve efficiency at existing
operations and to equip new mine developments. Additional increases in
depreciation and amortization expense were due to coalbed methane well
development costs of $5.5 million. The increases were partially offset by an
increase in amortization income on below-market coal supply agreements of $5.7
million during the year ended December 31, 2007.





Selling, general and administrative
expenses. Selling, general and administrative expenses for the year
ended December 31, 2007 were $33.3 million compared to $34.6 million for
the year ended December 31, 2006. The decrease of $1.3 million was
primarily attributable to gifts aggregating $2.0 million made in 2006 to the
families of the thirteen miners involved in the Sago mine accident, partially
offset by an increase of $1.3 million in professional and legal
fees.





Net gain on sale of
assets. Net gain on sale of assets increased $37.5 million for the
year ended December 31, 2007 from 2006, primarily due to a gain of
approximately $36.8 million related to the sale of our Denmark property in the
third quarter of 2007.





Goodwill impairment loss. The
goodwill impairment loss reflects the negative impact of several contributing
factors which resulted in a reduction in the forecasted cash flows used to
estimate fair value. These factors include, but are not limited to, a
significant decrease in the sales price of coal through our annual measurement
date, increases in the cost of diesel fuel, explosives, tires, roofbolts and
other materials used in mining coal, increased labor costs due to tightening
labor markets, significant investments in the areas of safety and compliance and
increased interest rates contributing to a higher discount rate. Furthermore,
the business, regulatory and marketplace environments in which we currently
operate differs significantly from the historical environments that drove the
business cases used to value and record the acquisition of these business units.
Accordingly, we have been unable to attain the forecasted projections that were
used to initially value the business units at the date of acquisition. The
goodwill impairment losses were at the following business units: $32.9 million
at Hazard, $58.5 million at Eastern, $43.0 million at East Kentucky and $36.0
million at Knott County.





Adjusted
EBITDA by Segment





Adjusted
EBITDA represents net income before deducting interest expense, income taxes,
depreciation, depletion, amortization, impairment charges and noncontrolling
interest. Adjusted EBITDA is presented because it is an important supplemental
measure of our performance used by our chief operating decision maker in such
areas as capital investment and allocation of resources. It is considered
“adjusted” as we adjust EBITDA for impairment charges and noncontrolling
interest. Adjusted EBITDA is calculated differently than the prior year in that
it includes an adjustment for impairment charges. No impairment charges were
incurred in the prior year. Other companies in our industry may calculate
Adjusted EBITDA differently than we do, limiting its usefulness as a comparative
measure. Adjusted EBITDA is reconciled to its most comparable GAAP measure on
page 87 of this Annual Report on Form 10-K/A and in Note 20 to our consolidated
financial statements for the year ended December 31, 2007.





The
following table depicts segment Adjusted EBITDA for the years ended
December 31, 2007 and 2006:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2007
            
            
            2006
            
            $
            
            %(in thousands, except percentages)Central
      Appalachian
            
            $
            47,442
            
            
            $
            108,598
            
            $
            (61,156
            )
            (56
            )%Northern
      Appalachian
            
            
            (22,215
            )
            
            
            (36,586
            )
            
            14,371
            
            39
            %Illinois Basin
            
            
            15,463
            
            
            
            4,476
            
            
            10,987
            
            245
            %Ancillary
            
            
            18,363
            
            
            
            (4,456
            )
            
            22,819
            
            512
            %Total
      Adjusted EBITDA
            
            $
            59,053
            
            
            $
            72,032
            
            $
            (12,979
            )
            (18
            )%





85








Adjusted
EBITDA from our Central Appalachian segment decreased $61.2 million, or 56%, for
the year ended December 31, 2007 as compared to the year ended
December 31, 2006. The decrease was primarily due to the decreased
realization per ton as discussed above. Also impacting the decrease were
inflated operating costs per ton primarily resulting from regulatory issues and
short-term mine constraints. The reduced realizations and increased costs
resulted in a decrease in profit margins of $5.99 per ton. Additionally,
activities incidental to our coal producing activities decreased by $1.5 million
in 2007 further contributing to the decrease in Adjusted EBITDA.





The
increase in Adjusted EBITDA from our Northern Appalachian segment of $14.4
million for the year ended December 31, 2007 was primarily due to an
increase in coal sales revenue as of $3.55 per ton and decreased costs of $1.02
per ton resulting in increased profit margins of $4.57 per ton.





Adjusted
EBITDA from our Illinois Basin segment increased $11.0 million during the
year ended December 31, 2007 due to a $5.12 per ton increase in sales
realization over 2006 with cost per ton remaining constant with prior
year.





The
increase in Adjusted EBITDA from our Ancillary segment of $22.8 million was
primarily due to the sale of the Denmark property in September 2007, which
resulted in a gain of $36.8 million, as well as from increased contributions to
income from our investment in coalbed methane wells and from our ADDCAR
subsidiary as discussed above. These increases were partially offset by a
decrease in Adjusted EBITDA resulting from the expiration of brokered coal
contracts.





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





The
following tables reconcile Adjusted EBITDA to net income (loss) by segment for
the years ended December 31, 2007 and 2006:





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2007
            
            
            2006
            
            $
            
            %(in thousands, except percentages)Central
      AppalachianNet
      income (loss) attributable to International Coal Group,
    Inc.
            
            $
            (184,372
            )
            
            $
            59,620
            
            $
            (243,992
            )
            (409
            )%Depreciation,
      depletion and amortization
            
            
            60,015
            
            
            
            48,050
            
            
            11,965
            
            25
            %Interest
      expense, net
            
            
            1,397
            
            
            
            928
            
            
            469
            
            51
            %Impairment
      loss
            
            
            170,402
            
            
            
            —
            
            
            170,402
            
            100
            %Adjusted
      EBITDA
            
            $
            47,442
            
            
            $
            108,598
            
            $
            (61,156
            )
            (56
            )%





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2007
            
            
            2006
            
            $
            
            %(in thousands, except percentages)Northern
      AppalachianNet
      loss attributable to International Coal Group, Inc.
            
            $
            (31,790
            )
            
            $
            (47,907
            )
            $
            16,117
            
            34
            %Depreciation,
      depletion and amortization
            
            
            9,467
            
            
            
            10,822
            
            
            (1,355
            )
            (13
            )%Interest
      expense, net
            
            
            457
            
            
            
            441
            
            
            16
            
            4
            %Noncontrolling
      interest
            
            
            (349
            )
            
            
            58
            
            
            (407
            )
            (702
            )%Adjusted
      EBITDA
            
            $
            (22,215
            )
            
            $
            (36,586
            )
            $
            14,371
            
            39
            %





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2007
            
            
            2006
            
            $
            
            %(in thousands, except percentages)Illinois BasinNet
      income (loss) attributable to International Coal Group,
    Inc.
            
            $
            8,714
            
            
            $
            (1,978
            )
            $
            10,692
            
            541
            %Depreciation,
      depletion and amortization
            
            
            6,527
            
            
            
            6,287
            
            
            240
            
            4
            %Interest
      expense, net
            
            
            222
            
            
            
            167
            
            
            55
            
            33
            %Adjusted
      EBITDA
            
            $
            15,463
            
            
            $
            4,476
            
            $
            10,987
            
            245
            %





86








Year
      ended
              December
      31,
            
            Increase
              (Decrease)2007
            
            
            2006
            
            $
            
            %(in thousands, except percentages)AncillaryNet
      income (loss) attributable to International Coal Group,
    Inc.
            
            $
            59,886
            
            
            $
            (19,055
            )
            $
            78,941
            
            414
            %Depreciation,
      depletion and amortization
            
            
            10,508
            
            
            
            7,059
            
            
            3,449
            
            49
            %Interest
      expense, net
            
            
            33,913
            
            
            
            16,555
            
            
            17,358
            
            105
            %Income
      tax benefit
            
            
            (85,944
            )
            
            
            (9,015
            )
            
            (76,929
            )
            (853
            )%Adjusted
      EBITDA
            
            $
            18,363
            
            
            $
            (4,456
            )
            $
            22,819
            
            512
            %





Year
      ended
              December
      31,
            
            Increase
              (Decrease)2007
            
            
            2006
            
            $
            
            %(in thousands, except percentages)ConsolidatedNet
      loss attributable to International Coal Group, Inc.
            
            $
            (147,562
            )
            
            $
            (9,320
            )
            $
            (138,242
            )
            *
            %Depreciation,
      depletion and amortization
            
            
            86,517
            
            
            
            72,218
            
            
            14,299
            
            20
            %Interest
      expense, net
            
            
            35,989
            
            
            
            18,091
            
            
            17,898
            
            99
            %Income
      tax benefit
            
            
            (85,944
            )
            
            
            (9,015
            )
            
            (76,929
            )
            (853
            )%Impairment
      loss
            
            
            170,402
            
            
            
            —
            
            
            170,402
            
            100
            %Noncontrolling
      interest
            
            
            (349
            )
            
            
            58
            
            
            (407
            )
            (702
            )%Adjusted
      EBITDA
            
            $
            59,053
            
            
            $
            72,032
            
            $
            (12,979
            )
            (18
            )%





*
Not meaningful





Liquidity
and Capital Resources





Our
business is capital intensive and requires substantial capital expenditures for,
among other things, purchasing and upgrading equipment used in developing and
mining our coal lands, as well as remaining in compliance with environmental
laws and regulations. Our principal liquidity requirements are to finance our
coal production, fund capital expenditures and service our debt and reclamation
obligations. We may also engage in acquisitions from time to time. Our primary
sources of liquidity to meet these needs are cash flows from sales of our coal,
other income, borrowings under our senior credit facility, the proceeds of our
convertible notes offering and capital equipment financing
arrangements.





We
believe the principal indicators of our liquidity are our cash position and
remaining availability under our credit facility. As of December 31, 2008, our
available liquidity was $90.3 million, including cash of $63.9 million and $26.4
million available for borrowing under our $100.0 million senior credit facility.
Total debt represented 48% of our total capitalization at December 31, 2008. Our
total capitalization represents our current and long-term debt combined with our
total stockholders’ equity.





In
February 2009, we executed an amendment to our $100.0 million credit facility
that affected certain 2009 debt covenants. The amendment modified the maximum
permitted leverage and minimum interest coverage ratios. The amendment also
decreased the maximum capital spending and added a minimum liquidity
requirement. Debt covenants for years subsequent to 2009 were not affected by
the amendment.





The
recent and unprecedented disruption in the current credit markets has had a
significant adverse impact on a number of financial institutions. At this time,
our liquidity has not been materially impacted by the current credit environment
and we do not expect that it will be materially impacted in the
near-future. We will continue to closely monitor our liquidity and the
credit markets. However, we cannot predict with any certainty the impact to us
of any further disruption in the credit environment. See “Risk Factors – The
duration or severity of the current global financial crisis are uncertain and
may have an impact on our business and financial conditions in ways that we
currently cannot predict.”





87








Our
Convertible Senior Notes (the “Convertible Notes”) became convertible at the
option of holders beginning July 1, 2008. The conversion period expired on
September 30, 2008 pursuant to the terms of the governing indenture with no
holders exercising their conversion rights. The Convertible Notes may become
convertible again in the future under certain conditions. Accordingly, we will
reassess the convertibility on a quarterly basis.





We
currently expect our total capital expenditures will be approximately $100.0
million in 2009, substantially all of which will be for equipment and
infrastructure at our existing operations. Cash paid for capital expenditures
was approximately $132.8 million for the year ended December 31, 2008. We have
funded and will continue to fund these capital expenditures from our internal
operations and with proceeds from our convertible notes offering in 2007. We
believe that these sources of capital and our $50.0 million equipment revolving
credit facility with Caterpillar Financial Services Corporation will be
sufficient to fund our anticipated capital expenditures under our current budget
plan through the end of 2009. Although we expect to experience some periods of
tightening liquidity availability, we expect to be able to manage through such
periods. To the extent necessary, management believes it has flexibility in
the timing of the cash requirements by managing the pace of capital spending. In
addition, management may from time to time raise additional capital through the
disposition of non-core assets or engaging in sale-leaseback transactions. The
need and timing of seeking additional capital in the future will be subject to
market conditions.





Approximately
$86.1 million of 2008 cash paid for capital expenditures was attributable to
Central Appalachian operations. This amount represents investments of
approximately $44.7 million in our Beckley mining complex, as well as additional
investments of $41.4 million for upgrades at the remaining Central Appalachian
operations. We paid approximately $31.0 million at our Northern Appalachian
operations in the year ended December 31, 2008, approximately $20.8 million of
which was for development of our Sentinel and Tygart properties. Expenditures of
approximately $4.9 million for our Illinois Basin operations were for
ongoing operations improvements. Approximately $10.8 million of cash paid for
capital expenditures for the year ended December 31, 2008 was within our
Ancillary segment for safety equipment, as well as for upgrades at various other
subsidiaries.





As
a result of recent accidents in the mining industry, additional regulatory
requirements were promulgated that will require additional capital expenditures
to meet enhanced safety standards. For the year ended December 31, 2008, we
spent $4.2 million to meet these standards and anticipate spending an additional
$4.3 million in 2009.





Cash
Flows





Net
cash provided by operating activities was $78.7 million for the year ended
December 31, 2008, an increase of $56.3 million from the same period in 2007.
This increase is attributable to a decrease in net loss of $62.9 million after
adjustment for non-cash charges offset by a decrease in net operating assets and
liabilities of $6.7 million.





For
the year ended December 31, 2008, net cash used in investing activities was
$124.0 million compared to $126.9 million for the year ended December 31, 2007.
For the year ended December 31, 2008, $132.8 million of cash was used for
development and acquisition of new mining complexes and to support existing
mining operations compared to $169.7 million in the same period 2007.
Additionally, we collected proceeds from asset sales of $8.8 million during the
year ended December 31, 2008 versus $46.5 million during the comparable period
of 2007.





Net
cash provided by financing activities of $2.1 million for the year ended
December 31, 2008 was due to repayments on our short-term and long-term debt of
$7.9 million. These amounts were offset by borrowings of $9.8 million provided
by long-term and short-term notes entered into during the year and proceeds from
stock options exercised of $0.1 million.





Net
cash provided by operating activities was $22.5 million for the year ended
December 31, 2007, a decrease of $33.1 million from 2006. This decrease is
attributable to an increase in net operating assets and liabilities of $42.9
million offset by a decrease in net loss of $76.0 million after adjustment for
non-cash charges.





88








For
the year ended December 31, 2007, net cash used in investing activities was
$126.9 million compared to $160.8 million for the year ended December 31,
2006. For 2007, $169.7 million of cash was used to support existing mining
operations and for development of new mining complexes compared to $165.7
million in 2006. Investing activities for 2007 also included cash paid of $3.8
million representing contingency payments related to the Horizon acquisition as
compared to $4.7 million in 2006. Additionally, we collected proceeds from asset
sales of $46.5 million during the year ended December 31, 2007 versus $3.8
million during 2006.





Net
cash provided by financing activities of $192.8 million for the year ended
December 31, 2007 was primarily due to proceeds of $225.0 million from our
convertible senior notes offering. Additionally, we had borrowings of $65.0
million on our credit facility and an additional $26.1 million was provided by
short-term notes entered into during the year. These borrowings were offset by
repayments on our short-term and long-term debt and capital leases of $45.4
million and $68.6 million, respectively. Also impacting financing activities for
the year ended December 31, 2007 was additional finance costs of $9.3
million related to the issuance of our convertible notes and amending our credit
facility.





Credit
Facility and Long-Term Debt Obligations





As
of December 31, 2008, our total long-term indebtedness, including capital lease
obligations, consisted of the following (in thousands):








20089.00%
      Convertible Senior Notes, due 2012, net of debt discount
      of  $17,369
            
            $
            207,63110.25%
      Senior Notes, due 2014
            
            
            175,000Equipment
      notes
            
            
            43,378Capital
      leases and other
            
            
            6,861Total
            
            
            432,870Less
      current portion
            
            
            (15,319
            )Long-term
      debt and capital leases
            
            $
            417,551





Convertible senior
notes. In 2007, we completed a private offering of $225.0 million
aggregate principal amount of 9.00% Convertible Senior Notes (the “Convertible
Notes”) due 2012. The Convertible Notes are our senior unsecured obligations and
are guaranteed on a senior unsecured basis by our material future and current
domestic subsidiaries. The Convertible Notes and the related guarantees rank
equal in right of payment to all of our and the guarantors’ respective existing
and future unsecured senior indebtedness. Interest is payable semi-annually in
arrears on February 1 and August 1 of each year.





The
Convertible Notes became convertible at the option of holders beginning
July 1, 2008. The conversion period expired on September 30, 2008 pursuant
to the terms of the governing indenture with no holders exercising their
conversion rights. The Convertible Notes may become convertible again in the
future under certain conditions. Accordingly, we will reassess the
convertibility on a quarterly basis.





89











The
principal amount of the Convertible Notes is payable in cash and amounts above
the principal amount, if any, will be convertible into shares of our common
stock or, at our option, cash. The Convertible Notes are convertible at an
initial conversion price, subject to adjustment, of $6.10 per share
(approximating 163.8136 shares per one thousand dollar principal amount of the
Convertible Notes). The volume weighted-average price of our stock subsequent to
the expiration date of the conversion period was below $6.10 per share.
Accordingly, there were no potentially convertible shares at December 31, 2008.
The Convertible Notes are convertible upon the occurrence of certain events,
including (i) prior to February 12, 2012 during any calendar quarter
after September 30, 2007, if the closing sale price per share of our common
stock for each of 20 or more trading days in a period of 30 consecutive trading
days ending on the last trading day of the immediately preceding calendar
quarter exceeds 130% of the conversion price in effect on the last trading day
of the immediately preceding calendar quarter; (ii) prior to
February 12, 2012 during the five consecutive business days immediately
after any five consecutive trading day period in which the average trading price
for the notes on each day during such five trading-day period was equal to or
less than 97% of the closing sale price of our common stock on such day
multiplied by the then current conversion rate; (iii) upon the occurrence
of specified corporate transactions; and (iv) at any time from, and
including February 1, 2012 until the close of business on the second
business day immediately preceding August 1, 2012. In addition, upon events
defined as a “fundamental change” under the Convertible Notes indenture, we may
be required to repurchase the Convertible Notes at a repurchase price in cash
equal to 100% of the principal amount of the notes to be repurchased, plus any
accrued and unpaid interest to, but excluding, the fundamental change repurchase
date. As such, in the event of a fundamental change or the aforementioned
average pricing thresholds are met, we would be required to classify the entire
amount outstanding of the Convertible Notes as a current liability in the
following quarter. In the event that a significant number of the holders of the
Convertible Notes were to convert their notes prior to maturity, we may not have
enough available funds at any particular time to make the required repayments.
Under these circumstances, we would look to WLR, our banking group and other
potential lenders to obtain short-term funding until such time that we could
secure necessary financing on a long-term basis. The availability of any such
financing would depend upon the circumstances at the time, including the terms
of any such financing, and other factors. In addition, if conversion occurs in
connection with certain changes in control, we may be required to deliver
additional shares of our common stock (a “make whole” premium) by increasing the
conversion rate with respect to such notes.





Senior notes. In 2006,
we sold $175.0 million aggregate principal amount of our 10.25% Senior Notes
(the “Notes”) due July 15, 2014. Interest on the Notes is payable
semi-annually in arrears on July 15 and January 15 of each year. The
Notes are senior unsecured obligations and are guaranteed on a senior unsecured
basis by all of our current and future domestic subsidiaries that are material
or that guarantee our amended and restated credit facility. The Notes and the
guarantees rank equally with all of our and the guarantors’ existing and future
senior unsecured indebtedness, but are effectively subordinated to all of our
and the guarantors existing and future senior secured indebtedness to the extent
of the value of the assets securing that indebtedness and to all liabilities of
our subsidiaries that are not guarantors. We have the option to redeem
all or a portion of the Notes at 100% of the aggregate principal amount at
maturity at any time on or after July 15, 2012. At any time on or after July 15,
2010 and prior to July 15, 2012, we may also redeem all or a portion of the
Notes at a redemption price equal to 100% of the aggregate principal amount of
the Notes plus an applicable premium as of, and accrued and unpaid interest and
additional interest, if any, to, but not including the date of
redemption. At any time before July 15, 2009, we may also redeem up
to 35% of the aggregate principal amount of the Notes at a redemption price of
110.25% of the principal amount, plus accrued and unpaid interest, if any, to
the date of redemption, with the proceeds of certain equity offerings. Upon a
change of control, we may be required to offer to purchase the Notes at a
purchase price equal to 101% of the principal amount, plus accrued and unpaid
interest.





The
indenture governing the Notes contains covenants that limit our ability to,
among other things, incur additional indebtedness, issue preferred stock, pay
dividends, repurchase, repay or redeem our capital stock, make certain
investments, sell assets and incur liens. As of December 31, 2008, we were
in compliance with our covenants under the indenture.





90











Credit facility. In
2006, we entered into a second amended and restated credit agreement (the
“Amended Credit Facility”) consisting of a revolving credit facility which
matures on June 23, 2011. In July 2007, concurrent with the issuance of the
convertible notes, we further amended the Amended Credit Facility to reduce the
commitments thereunder to $100.0 million, of which a maximum of $80.0 million
may be used for letters of credit. The amendment, among other things, modified
the maximum permitted leverage ratio, the minimum interest coverage ratio and
the maximum amount of capital expenditures permitted. Further, the amendment
revised certain interest rate thresholds and unused commitment fee levels under
the Amended Credit Facility. In February 2009, we executed a further amendment
to the Amended Credit Facility that affected certain 2009 debt covenants. The
amendment modified the maximum permitted leverage and minimum interest coverage
ratios. The amendment also decreased the maximum capital spending and added a
minimum liquidity requirement. Debt covenants for years subsequent to 2009 were
not affected by the amendment. As of December 31, 2008, we had no
borrowings outstanding and letters of credit totaling $73.6 million outstanding,
leaving $26.4 million available for future borrowing capacity. Interest on the
borrowings under the Amended Credit Facility is payable, at our option, at
either the base rate plus an applicable margin based on our leverage ratio of
1.25% to 2.00% as of December 31, 2008 or LIBOR plus an applicable margin
based on our leverage ratio of 2.25% to 3.00% as of December 31, 2008. As
of December 31, 2008, we were in compliance with our financial covenants under
the Amended Credit Facility.





Equipment notes and other.
The equipment notes, having various maturity dates extending to January 2014,
are collateralized by mining equipment. As of December 31, 2008, we had amounts
outstanding for 36-month through 60-month terms with a weighted-average interest
rate of 6.42%. At December 31, 2008, additional funds are available under our
revolving equipment credit facility for terms ranging from 36 to 60 months with
a current interest rate of 8.75%. Additionally, we finance certain of our annual
insurance premiums at a current interest rate of 5.42%.





Other





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





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





Our
ability to meet our long-term debt obligations will depend upon our future
performance, which, in turn, will depend upon general economic, financial and
business conditions, along with competition, legislation and regulation—factors
that are largely beyond our control. Based upon our current operations, we
believe that cash flow from operations, together with other available sources of
funds will be adequate for at least through the end of 2009 for making required
payments of principal and interest on our indebtedness and for funding
anticipated capital expenditures and working capital requirements. Although we
expect to experience some periods of tightening liquidity availability, we
expect to be able to manage through such periods. To the extent necessary,
management believes it has flexibility in the timing of the cash requirements by
managing the pace of capital spending. In addition, management may from time to
time raise additional capital through the disposition of non-core assets or
engaging in sale-leaseback transactions. 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.





91











Contractual
Obligations





The
following is a summary of our significant future contractual obligations by year
as of December 31, 2008 (in thousands):





Payments
      due by periodLess than
              1
      year
            
            
            1-3
      years
            
            
            3-5
      years
            
            
            More than
              5
      years
            
            
            TotalLong-term
      debt, capital lease and other obligations (1)
            
            $
            57,990
            
            
            $
            101,104
            
            
            $
            286,703
            
            
            $
            184,785
            
            
            $
            630,582Operating
      leases
            
            
            87
            
            
            
            82
            
            
            
            —
            
            
            
            —
            
            
            
            169Coal
      purchase obligations(2)
            
            
            22,926
            
            
            
            14,377
            
            
            
            —
            
            
            
            —
            
            
            
            37,303Diesel
      fuel purchase obligations(2)
            
            
            73,753
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            73,753Advisory
      Services Agreement(3)
            
            
            2,000
            
            
            
            3,500
            
            
            
            —
            
            
            
            —
            
            
            
            5,500Minimum
      royalties
            
            
            10,111
            
            
            
            19,640
            
            
            
            16,636
            
            
            
            37,004
            
            
            
            83,391Postretirement
      medical benefits
            
            
            523
            
            
            
            2,505
            
            
            
            5,068
            
            
            
            170,230
            
            
            
            178,326Total
            
            $
            167,390
            
            
            $
            141,208
            
            
            $
            308,407
            
            
            $
            392,019
            
            
            $
            1,009,024








(1)
            Amounts
      are inclusive of interest assuming interest rates of 10.25% for our senior
      notes, 9.0% for our convertible notes and ranging from 5.10% to 8.75% on
      our equipment notes.(2)
            Reflects
      estimates of obligations.(3)
            See
      “Certain relationships and related party transactions.”





We
have excluded from the table above uncertain tax liabilities as defined in FASB
Interpretation No. 48, “Accounting for Uncertainty in Income
Taxes,” due to the immateriality of such amounts.





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 than posting an all cash bond or a bank
letter of credit, either of which would require a greater use of our credit
facility. We then use bank letters of credit to secure our surety bonding
obligations as a lower cost alternative than securing those bonds with cash. We
currently have a $130.4 million committed bonding facility pursuant to which we
are required to provide bank letters of credit in an amount up to 50% of the
aggregate bond liability. Recently, surety bond costs have increased, while the
market terms of surety bonds have generally become less favorable. To the extent
that surety bonds become unavailable, we would seek to secure our reclamation
obligations with letters of credit, cash deposits or other suitable forms of
collateral.





As
of December 31, 2008, we had outstanding surety bonds with third parties for
post-mining reclamation totaling $111.0 million, plus $4.7 million for
miscellaneous purposes. As of December 31, 2008, we maintained letters of credit
totaling $73.6 million to secure reclamation surety bonds and other
obligations.





92








Inflation





Inflation
in the United States has been relatively low in recent years and did not have a
material impact on results of operations for the years ended December 31, 2008,
2007 and 2006. However, commodities prices have increased at a rate greater than
that of the general economy, specifically prices for fuel and explosives, steel
products, tires, healthcare and labor.





Recent
Accounting Pronouncements





Fair Value Measurements. In
September 2006, the FASB issued SFAS No. 157,Fair Value Measurements
(“SFAS No. 157”). SFAS No. 157 clarifies the definition of fair value,
establishes a framework for measuring fair value and expands the disclosures on
fair value measurements. SFAS No. 157 is effective for fiscal years
beginning after November 15, 2007. Adoption of SFAS No. 157 did not
have a material impact on our financial position, results of operations or cash
flows; however, adoption did result in additional information being included in
the footnotes accompanying our consolidated financial statements.





In
February 2008, the FASB issued FSP 157-2,Effective Date of FASB Statement
No. 157 (“FSP 157-2”). FSP 157-2 permits delayed adoption of SFAS No. 157
for certain non-financial assets and liabilities, which are not recognized at
fair value on a recurring basis, until fiscal years, and interim periods within
those fiscal years, beginning after November 15, 2008. Adoption of FSP
157-2 did not have a material impact on our financial position, results of
operations or cash flows.





Fair Value Option. In
February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial
Assets and Financial Liabilities—Including an amendment of FASB Statement
No. 115 (“SFAS No. 159”). SFAS No. 159 provides entities
with an option to report selected financial assets and liabilities at fair value
and establishes presentation and disclosure requirements designed to facilitate
comparisons between entities that choose different measurement attributes for
similar types of assets and liabilities. SFAS No. 159 is effective as of
the beginning of the first fiscal year that begins after November 15, 2007.
Adoption of SFAS No. 159 did not have a material impact on our financial
position, results of operations or cash flows.





Financial Assets.In October 2008, the
FASB issued FSP 157-3,Determining Fair Value of a Financial Asset in a Market That Is Not
Active (“FSP 157-3”). FSP 157-3 clarified the application of SFAS No. 157
in an inactive market. It demonstrated how the fair value of a financial asset
is determined when the market for that financial asset is inactive. FSP 157-3
was effective upon issuance, including prior periods for which financial
statements had not been issued. Adoption of FSP 157-3 did not have a material
impact on our financial position, results of operations or cash
flows.





Convertible Debt. In May
2008, the FASB issued FSP APB 14-1,Accounting for Convertible Debt
Instruments That May be Settled in Cash Upon Conversion (Including Partial Cash
Settlement) (“FSP APB 14-1”). FSP APB 14-1 requires the liability and
equity components of convertible debt instruments that may be settled in cash
upon conversion to be separately accounted for in a manner that reflects the
issuer’s nonconvertible debt borrowing rate. To allocate the proceeds from a
convertible debt offering in this manner, a company would first need to
determine the carrying amount of the liability component, which would be based
on the fair value of a similar liability (excluding any embedded conversion
options). The resulting debt discount would be amortized over the period during
which the debt is expected to be outstanding as additional non-cash interest
expense. FSP APB 14-1 is effective for financial statements for fiscal years
beginning after December 15, 2008, and interim periods within those fiscal
years, and would be applied retrospectively for all periods presented. We have
determined our non-convertible borrowing rate would have been 11.7% at issuance
of our convertible debt. See Note 23 accompanying our consolidated financial
statements included in this Annual Report on Form 10-K/A for information
regarding the effect of adoption of FSP APB 14-1.





93





Business Combinations. In
December 2007, the FASB issued SFAS No. 141 (Revised 2007),Business Combinations (“SFAS
No. 141(R)”). SFAS No. 141(R) will significantly change the accounting
for business combinations. Under SFAS No. 141(R), an acquiring entity will
be required to recognize all the assets acquired and liabilities assumed in a
transaction at the acquisition-date fair value with limited exceptions. SFAS
No. 141(R) will change the accounting treatment for certain specific
acquisition-related items including: (i) expensing acquisition-related
costs as incurred, (ii) valuing noncontrolling interests at fair value at
the acquisition date and (iii) expensing restructuring costs associated
with an acquired business. SFAS No. 141(R) also includes a substantial
number of new disclosure requirements. SFAS No. 141(R) is to be applied to
any business combination for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after
December 15, 2008. Upon adoption, SFAS No. 141(R) will impact the
accounting for our future business combinations.





Noncontrolling Interests. In
December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in
Consolidated Financial Statements–an amendment to ARB No. 51 (“SFAS
No. 160”). SFAS No. 160 establishes new accounting and reporting
standards for the noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in
a subsidiary (minority interest) is an ownership interest in the consolidated
entity that should be reported as equity in the consolidated financial
statements and separate from the parent company’s equity. Among other
requirements, this statement requires consolidated net income to be reported at
amounts that include the amounts attributable to both the parent and the
noncontrolling interest. It also requires disclosure, on the face of the
consolidated statement of operations, of the amounts of consolidated net income
attributable to the parent and to the noncontrolling interest. The provisions of
SFAS No. 160 are effective for fiscal years, and interim periods within
those fiscal years, beginning on or after December 15, 2008. Adoption of
this new accounting requirement impacted the presentation of the noncontrolling
interest in our balance sheets and statements of operations and cash flows. The
impact of the changes in presentation was not material.





Derivative Instruments. In
March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative
Instruments and Hedging Activities – an amendment of FASB Statement
No. 133 (“SFAS No. 161”). SFAS No. 161 requires additional
disclosures for derivative instruments and hedging activities that include how
and why an entity uses derivatives, how these instruments and the related hedged
items are accounted for under FASB Statement No. 133,Accounting for Derivative
Instruments and Hedging Activities, and related interpretations and how
derivative instruments and related hedged items affect the entity’s financial
position, results of operations and cash flows. SFAS No. 161 is effective
for fiscal years, and interim periods within those fiscal years, beginning after
November 15, 2008. Adoption of SFAS No. 161 did not impact the
footnotes accompanying our consolidated financial statements.





GAAP Hierarchy. In
May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted
Accounting Principles (“SFAS No. 162”). SFAS No. 162 identifies the
sources of accounting principles and the framework for selecting the principles
to be used in the preparation of financial statements of nongovernmental
entities that are presented in conformity with generally accepted accounting
principles. SFAS No. 162 directs the hierarchy to the entity, rather than
the independent auditors, as the entity is responsible for selecting accounting
principles for financial statements that are presented in conformity with
generally accepted accounting principles. SFAS No. 162 is effective for fiscal
years, and interim periods within those fiscal years, beginning on or after
December 31, 2008. Adoption of SFAS No. 162 did not have a material impact
on our financial position, results of operations or cash flows.








94





Share-Based Payments.In June 2008, the FASB
issued EITF 03-6-1,
Determining Whether Instruments Granted in Share-Based Payment Transactions Are
Participating Securities (“EITF 03-6-1”). EITF 03-6-1 clarifies that all
outstanding unvested share-based payment awards that contain rights to
nonforfeitable dividends participate in undistributed earnings with common
shareholders. Awards of this nature are considered participating securities and
the two-class method of computing basic and diluted earnings per share must be
applied. EITF 03-6-1 is effective for fiscal years beginning after December 15,
2008. Adoption of EITF 03-6-1 did not have a material impact on our financial
position, results of operations or cash flows.





Financial Instruments. In
June 2008, the FASB ratified EITF 07-5,Determining Whether an Instrument
(or an Embedded Feature) Is Indexed to an Entity’s Own Stock (“EITF
07-5”). EITF 07-5 provides that an entity should use a two step approach to
evaluate whether an equity-linked financial instrument (or embedded feature) is
indexed to its own stock, including evaluating the instrument’s contingent
exercise and settlement provisions. It also clarifies the impact of foreign
currency denominated strike prices and market-based employee stock option
valuation instruments on the evaluation. EITF 07-5 is effective for fiscal years
beginning after December 15, 2008. Adoption of EITF 07-5 did not have a material
impact on our financial position, results of operations or cash
flows.





ITEM 7A.
            QUANTITATIVE
      AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK





Interest rate risk. In
May 2006, we entered into an Interest Rate Collar Agreement, which became
effective on March 31, 2007 and expires March 31, 2009, to hedge our
interest risk on $200.0 million notional amount of revolving debt. The interest
rate collar is designed as a cash flow hedge to offset the impact of changes in
the LIBOR interest rate above 5.92% and below 4.80%. This agreement was entered
into in conjunction with our amended and restated credit facility dated
June 23, 2006. We recognize the change in the fair value of this agreement
in the income statement in the period of change. For the year ended December 31,
2008, we recorded a loss of $2.0 million related to changes in fair market
value.





Market price risk. We
are exposed to market price risk in the normal course of mining and selling
coal. As of December 31, 2008, 92% of 2009 planned production is committed for
sale, leaving approximately 8% uncommitted for sale. A hypothetical decrease of
$1.00 per ton in the market price for coal would reduce pre-tax income by
approximately $1.5 million for 2009.





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.








95








ITEM 9A.
            CONTROLS
      AND PROCEDURES





We
maintain a set of disclosure controls and procedures designed to provide
reasonable assurance that information required to be disclosed by us in reports
that we file or submit under the Securities Exchange Act of 1934 (the “Exchange
Act”) is recorded, processed, summarized and reported within the time periods
specified in Securities and Exchange Commission rules and forms. Our disclosure
controls and procedures are also designed to provide reasonable assurance that
information required to be disclosed in the reports that we file or submit under
the Exchange Act is accumulated and communicated to our management, including
the Chief Executive Officer and Chief Financial Officer, to allow timely
decisions regarding required disclosure. Periodically, we review the design and
effectiveness of our disclosure controls and controls over financial reporting
to ensure they remain effective. If such reviews identify a need, we will make
modifications to improve the design and effectiveness of our control
structure.





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





Management’s Report on Internal
Control Over Financial Reporting





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





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





Under
the supervision and with the participation of our management, including our
Chief Executive Officer and Chief Financial Officer, we conducted an evaluation
of our controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)
under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) using
the criteria set by the Committee of Sponsoring Organizations of the Treadway
Commission (“COSO”) inInternal Control—Integrated Framework. Based on this evaluation, our
Chief Executive Officer and Chief Financial Officer have concluded that our
controls and procedures were effective as of December 31,
2008.





Our
Independent Registered Public Accounting Firm, Deloitte & Touche LLP,
has audited the effectiveness of our internal control over financial reporting,
as stated in their attestation report included on page F-1 of Item
15.





Changes
in Internal Control Over Financial Reporting





There
have been no changes in our internal controls over financial reporting during
the fourth quarter of fiscal year 2008 that would have materially affected, or
would be reasonably likely to materially affect, our internal control over
financial reporting.





96








ITEM 9B.
            OTHER
      INFORMATION





None.





Part
III





ITEM 10.
            DIRECTORS,
      EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE





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 20, 2009 (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 63
of this Annual Report on Form 10-K/A for information required by
Item 201(d) of Regulation S-K.





ITEM 13.
            CERTAIN
      RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
      INDEPENDENCE





The
information requested by 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 will be incorporated herein by
reference.





97








PART
IV





ITEM 15.
            EXHIBITS,
      FINANCIAL STATEMENT SCHEDULES





(a)
            Financial
      Statements:





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





PageInternational
      Coal Group, Inc. and SubsidiariesReports
      of Independent Registered Public Accounting Firm
            
            F-1Consolidated
      Balance Sheets as of December 31, 2008 and 2007
            
            F-3Consolidated
      Statements of Operations for the years ended December 31, 2008, 2007 and
      2006
            
            F-4Consolidated
      Statements of Stockholders’ Equity for the years ended December 31, 2008,
      2007 and 2006
            
            F-5Consolidated
      Statements of Cash Flows for the years ended December 31, 2008, 2007 and
      2006
            
            F-6Notes
      to Consolidated Financial Statements for the years ended December 31,
      2008, 2007 and 2006
            
            F-7(b)    Exhibits.(i)     See
      the Exhibit Index.(c)    Financial
      Statement Schedules.PageSchedule I—Condensed
      Financial Information of the Registrant
            
            F-45Schedule II—Valuation
      and Qualifying Accounts
            
            F-49





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.





98







REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





To
the Board of Directors and Stockholders of


International
Coal Group, Inc.


Scott
Depot, West Virginia





We
have audited the internal control over financial reporting of International Coal
Group, Inc. and subsidiaries (the “Company”) as of December 31, 2008, based on
criteria established inInternal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. The Company’s management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s Report on Internal Control
Over Financial Reporting. Our responsibility is to express an opinion on the
Company’s internal control over financial reporting based on our
audit.





We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing
and evaluating the design and operating effectiveness of internal control based
on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.





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





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





In
our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2008, based on the
criteria established inInternal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission.





We
have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated financial
statements and financial statement schedules as of and for the year ended
December 31, 2008 of the Company and our report dated February 27, 2009
(December 18, 2009 as to Note 23) expressed an unqualified opinion on those
financial statements and financial statement schedules and included an
explanatory paragraph regarding the retrospective adoption of FASB Staff
Position APB 14-1, Accounting
for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion
(Including Partial Cash Settlement).





/s/ Deloitte &
      Touche LLPCincinnati,
      OhioFebruary
      27, 2009





F-1





REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





To
the Board of Directors and Stockholders of


International
Coal Group, Inc.


Scott
Depot, West Virginia





We
have audited the accompanying consolidated balance sheets of International Coal
Group, Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007,
and the related consolidated statements of operations, stockholders’ equity, and
cash flows for each of the three years in the period ended December 31, 2008.
Our audits also included the financial statement schedules listed in the Index
at Item 15. These financial statements and financial statement schedules
are the responsibility of the Company’s management. Our responsibility is to
express an opinion on these financial statements and financial statement
schedules based on our audits.





We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.





In
our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company as of December 31, 2008
and 2007, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2008 in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such financial statement schedules, when considered in relation
to the basic consolidated financial statements taken as a whole, present fairly,
in all material respects, the information set forth therein.





As
discussed in Note 23 to the consolidated financial statements, the accompanying
2008 and 2007 consolidated financial statements have been retrospectively
adjusted for the adoption of FASB Staff Position APB 14-1, Accounting for Convertible Debt
Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash
Settlement).





We
have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the Company’s internal control over
financial reporting as of December 31, 2008, based on the criteria established
inInternal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 27, 2009 expressed an
unqualified opinion on the Company’s internal control over financial
reporting.








/s/
      Deloitte & Touche LLPCincinnati,
      OhioFebruary
      27, 2009 (December 18, 2009 as to Note
23)





F-2







INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





CONSOLIDATED
BALANCE SHEETS


December
31, 2008 and 2007


(Dollars
in thousands, except per share amounts)








December
      31,
              2008
            
            
            December 31,
              2007ASSETSCURRENT
      ASSETS:Cash
      and cash equivalents
            
            $
            63,930
            
            
            $
            107,150Accounts
      receivable, net of allowances of $1,516 and $539
            
            
            75,321
            
            
            
            83,765Inventories,
      net
            
            
            58,788
            
            
            
            40,679Deferred
      income taxes
            
            
            17,649
            
            
            
            5,000Prepaid
      insurance
            
            
            13,380
            
            
            
            10,618Income
      taxes receivable
            
            
            8,030
            
            
            
            8,854Prepaid
      expenses and other
            
            
            10,893
            
            
            
            9,138Total
      current assets
            
            
            247,991
            
            
            
            265,204PROPERTY,
      PLANT, EQUIPMENT AND MINE DEVELOPMENT, net
            
            
            1,069,297
            
            
            
            974,710DEBT
      ISSUANCE COSTS, net
            
            
            10,462
            
            
            
            12,890ADVANCE
      ROYALTIES, net
            
            
            17,462
            
            
            
            14,661GOODWILL
            
            
            —
            
            
            
            30,237OTHER
      NON-CURRENT ASSETS
            
            
            5,435
            
            
            
            5,661Total
      assets
            
            $
            1,350,647
            
            
            $
            1,303,363LIABILITIES
      AND STOCKHOLDERS’ EQUITYCURRENT
      LIABILITIES:Accounts
      payable
            
            $
            75,810
            
            
            $
            70,042Short-term
      debt
            
            
            4,741
            
            
            
            —Current
      portion of long-term debt and capital leases
            
            
            15,319
            
            
            
            4,234Current
      portion of reclamation and mine closure costs
            
            
            11,139
            
            
            
            7,333Current
      portion of employee benefits
            
            
            3,359
            
            
            
            2,925Accrued
      expenses and other
            
            
            87,704
            
            
            
            62,723Total
      current liabilities
            
            
            198,072
            
            
            
            147,257LONG-TERM
      DEBT AND CAPITAL LEASES
            
            
            417,551
            
            
            
            387,014RECLAMATION
      AND MINE CLOSURE COSTS
            
            
            68,107
            
            
            
            78,587EMPLOYEE
      BENEFITS
            
            
            56,563
            
            
            
            48,102DEFERRED
      INCOME TAXES
            
            
            51,154
            
            
            
            62,905BELOW-MARKET
      COAL SUPPLY AGREEMENTS
            
            
            43,888
            
            
            
            39,668OTHER
      NON-CURRENT LIABILITIES
            
            
            6,195
            
            
            
            8,062Total
      liabilities
            
            
            841,530
            
            
            
            771,595COMMITMENTS
      AND CONTINGENCIES
            
            
            —
            
            
            
            —STOCKHOLDERS’
      EQUITY:Preferred
      stock – par value $0.01, 200,000,000 shares authorized, none
      issued
            
            
            —
            
            
            
            —Common
      stock – par value $0.01, 2,000,000,000 shares authorized, 153,322,245 and
      152,992,109 shares, respectively, issued and
    outstanding
            
            
            1,533
            
            
            
            1,530Additional
      paid-in capital
            
            
            656,997
            
            
            
            652,677Accumulated
      other comprehensive loss
            
            
            (2,277
            )
            
            
            (1,530
            )Retained
      deficit
            
            
            (147,171
            )
            
            
            (120,944
            )Total
      International Coal Group, Inc. stockholders’ equity
            
            
            509,082
            
            
            
            531,733Noncontrolling
      interest
            
            
            35
            
            
            
            35Total
      stockholders’ equity
            
            
            509,117
            
            
            
            531,768Total
      liabilities and stockholders’ equity
            
            $
            1,350,647
            
            
            $
            1,303,363





See
notes to consolidated financial statements.


F-3








INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





CONSOLIDATED
STATEMENTS OF OPERATIONS


Years
ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Year
      Ended December 31,2008
            
            
            2007
            
            
            2006REVENUES:Coal
      sales revenues
            
            $
            998,245
            
            
            $
            770,663
            
            
            $
            833,998Freight
      and handling revenues
            
            
            45,231
            
            
            
            29,594
            
            
            
            18,890Other
      revenues
            
            
            53,260
            
            
            
            48,898
            
            
            
            38,706Total
      revenues
            
            
            1,096,736
            
            
            
            849,155
            
            
            
            891,594COSTS
      AND EXPENSES:Cost
      of coal sales
            
            
            882,983
            
            
            
            732,112
            
            
            
            739,914Freight
      and handling costs
            
            
            45,231
            
            
            
            29,594
            
            
            
            18,890Cost
      of other revenues
            
            
            35,672
            
            
            
            34,046
            
            
            
            29,418Depreciation,
      depletion and amortization
            
            
            96,047
            
            
            
            86,517
            
            
            
            72,218Selling,
      general and administrative
            
            
            38,147
            
            
            
            33,325
            
            
            
            34,578Gain
      on sale of assets
            
            
            (32,518
            )
            
            
            (38,656
            )
            
            
            (1,125
            )Goodwill
      impairment loss
            
            
            30,237
            
            
            
            170,402
            
            
            
            —Long-lived
      asset impairment loss
            
            
            7,191
            
            
            
            —
            
            
            
            —Total
      costs and expenses
            
            
            1,102,990
            
            
            
            1,047,340
            
            
            
            893,893Loss
      from operations
            
            
            (6,254
            )
            
            
            (198,185
            )
            
            
            (2,299
            )INTEREST
      AND OTHER INCOME (EXPENSE):Interest
      expense, net
            
            
            (43,643
            )
            
            
            (35,989
            )
            
            
            (18,091
            )Other,
      net
            
            
            —
            
            
            
            319
            
            
            
            2,113Total
      interest and other income (expense)
            
            
            (43,643
            )
            
            
            (35,670
            )
            
            
            (15,978
            )Loss
      before income taxes
            
            
            (49,897
            )
            
            
            (233,855
            )
            
            
            (18,277
            )INCOME
      TAX BENEFIT
            
            
            23,670
            
            
            
            85,944
            
            
            
            9,015Net
      loss
            
            
            (26,227
            )
            
            
            (147,911
            )
            
            
            (9,262
            )Net
      (income) loss attributable to noncontrolling interest
            
            
            —
            
            
            
            349
            
            
            
            (58
            )Net
      loss attributable to International Coal Group, Inc.
            
            $
            (26,227
            )
            
            $
            (147,562
            )
            
            $
            (9,320
            )Earnings
      per share:Basic
      and diluted
            
            $
            (0.17
            )
            
            $
            (0.97
            )
            
            $
            (0.06
            )Weighted-average
      common shares outstanding:Basic
      and diluted
            
            
            152,632,586
            
            
            
            152,304,461
            
            
            
            152,028,165





See
notes to consolidated financial statements.





F-4







INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY


Years
ended December 31, 2008, 2007 and 2006


(Dollars
in thousands)







Common
      StockShares
              
              
              Amount
              
              
              Additional Paid-in
      Capital
              
              
              Unearned
      Compensation RestrictedStock
              
              
              Accumulated
      Other
      Comprehensive Loss
              
              
              Retained
      Earnings (Deficit)
              
              
              Total
      International Coal Group, Inc. Stockholder’s’ Equity
              
              
              Non-controlling
      Interest
              
              
              Total
      Stockholders’ EquityBalance—December
      31, 2005
              
              
              152,321,908
              
              
              $
              1,523
              
              
              $
              632,897
              
              
              $
              (4,622
              )
              
              $
              —
              
              
              $
              36,688
              
              
              $
              666,486
              
              
              $
              1,038
              
              
              $
              667,524Net
      income (loss)
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (9,320
              )
              
              
              (9,320
              )
              
              
              58
              
              
              
              (9,262
              )Comprehensive
      loss
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (9,262
              )Effect
      of adoption of SFAS No. 158- postretirement benefit obligations, net
      of tax of $3,079
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (3,846
              )
              
              
              —
              
              
              
              (3,846
              )
              
              
              —
              
              
              
              (3,846
              )Effect
      of adoption of SFAS No. 158- black lung benefit obligations, net of
      tax of $1,312
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              2,119
              
              
              
              —
              
              
              
              2,119
              
              
              
              —
              
              
              
              2,119Effect
      of adoption of EITF 04-6, net of tax of $400
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (638
              )
              
              
              (638
              )
              
              
              —
              
              
              
              (638
              )Effect
      of adoption of SFAS No. 123(R)
              
              
              —
              
              
              
              —
              
              
              
              (4,622
              )
              
              
              4,622
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —Issuance
      of restricted stock and stock awards, net of forfeitures
              
              
              584,580
              
              
              
              6
              
              
              
              (6
              )
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —Compensation
      expense on share-based awards
              
              
              —
              
              
              
              —
              
              
              
              5,668
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              5,668
              
              
              
              —
              
              
              
              5,668Balance—December
      31, 2006
              
              
              152,906,488
              
              
              
              1,529
              
              
              
              633,937
              
              
              
              —
              
              
              
              (1,727
              )
              
              
              26,730
              
              
              
              660,469
              
              
              
              1,096
              
              
              
              661,565Net
      loss
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (147,562
              )
              
              
              (147,562
              )
              
              
              (349
              )
              
              
              (147,911
              )Postretirement
      benefit obligation adjustments, net of tax of $1,362
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (2,231
              )
              
              
              —
              
              
              
              (2,231
              )
              
              
              —
              
              
              
              (2,231
              )Amortization
      of accumulated postretirement benefit obligation, net of tax of
      $109
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              174
              
              
              
              —
              
              
              
              174
              
              
              
              —
              
              
              
              174Black
      lung benefit obligation adjustments, net of tax of $1,460
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              2,441
              
              
              
              —
              
              
              
              2,441
              
              
              
              —
              
              
              
              2,441Amortization
      of black lung benefit obligation, net of tax of $115
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (187
              )
              
              
              —
              
              
              
              (187
              )
              
              
              —
              
              
              
              (187
              )Comprehensive
      loss
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (147,714
              )Distributions
      to noncontrolling interest
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (712
              )
              
              
              (712
              )Effect
      of adoption of FIN 48
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (112
              )
              
              
              (112
              )
              
              
              —
              
              
              
              (112
              )Issuance
      of restricted stock and stock awards, net of forfeitures
              
              
              85,621
              
              
              
              1
              
              
              
              (1
              )
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —Compensation
      expense on share-based awards
              
              
              —
              
              
              
              —
              
              
              
              5,224
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              5,224
              
              
              
              —
              
              
              
              5,224Equity
      component of Convertible Senior Notes, due 2012
              
              
              —
              
              
              
              —
              
              
              
              13,517
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              13,517
              
              
              
              —
              
              
              
              13,517Balance—December
      31, 2007
              
              
              152,992,109
              
              
              
              1,530
              
              
              
              652,677
              
              
              
              —
              
              
              
              (1,530
              )
              
              
              (120,944
              )
              
              
              531,733
              
              
              
              35
              
              
              
              531,768Net
      loss
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (26,227
              )
              
              
              (26,227
              )
              
              
              —
              
              
              
              (26,227
              )Postretirement
      benefit obligation adjustments, net of tax of $727
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              530
              
              
              
              —
              
              
              
              530
              
              
              
              —
              
              
              
              530Amortization
      of accumulated postretirement benefit obligation, net of tax of
      $214
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              216
              
              
              
              —
              
              
              
              216
              
              
              
              —
              
              
              
              216Black
      lung benefit obligation adjustments, net of tax of $548
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (903
              )
              
              
              —
              
              
              
              (903
              )
              
              
              —
              
              
              
              (903
              )Amortization
      of black lung benefit obligation, net of tax of $358
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (590
              )
              
              
              —
              
              
              
              (590
              )
              
              
              —
              
              
              
              (590
              )Comprehensive
      loss
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (26,974
              )Issuance
      of restricted stock and stock awards, net of forfeitures
              
              
              312,436
              
              
              
              3
              
              
              
              (3
              )
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              —Stock
      options exercised
              
              
              17,700
              
              
              
              —
              
              
              
              149
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              149
              
              
              
              —
              
              
              
              149Compensation
      expense on share-based awards
              
              
              —
              
              
              
              —
              
              
              
              4,174
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              4,174
              
              
              
              —
              
              
              
              4,174Balance—December
      31, 2008
              
              
              153,322,245
              
              
              $
              1,533
              
              
              $
              656,997
              
              
              $
              —
              
              
              $
              (2,277
              )
              
              $
              (147,171
              )
              
              $
              509,082
              
              
              $
              35
              
              
              $
              509,117




See notes to consolidated
financial statements.


F-5





INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





CONSOLIDATED
STATEMENTS OF CASH FLOWS


Years
ended December 31, 2008, 2007 and 2006


(Dollars
in thousands)








Year
      Ended December 31,2008
            
            
            2007
            
            
            2006CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      loss
            
            $
            (26,227
            )
            
            $
            (147,911
            )
            
            $
            (9,262
            )Adjustments
      to reconcile net loss to net cash from operating
    activities:Depreciation,
      depletion and amortization
            
            
            96,047
            
            
            
            86,517
            
            
            
            72,218Impairment
      loss
            
            
            37,428
            
            
            
            170,402
            
            
            
            —Write-off
      and amortization of deferred finance costs and debt
    discount
            
            
            6,141
            
            
            
            9,516
            
            
            
            3,418Amortization
      of accumulated employee benefit obligations
            
            
            (518
            )
            
            
            (19
            )
            
            
            —Compensation
      expense on share-based awards
            
            
            4,174
            
            
            
            5,224
            
            
            
            5,668Gain
      on sale of assets, net
            
            
            (32,518
            )
            
            
            (38,656
            )
            
            
            (1,125
            )Provision
      for bad debt
            
            
            994
            
            
            
            503
            
            
            
            —Deferred
      income taxes
            
            
            (24,434
            )
            
            
            (87,399
            )
            
            
            3,239Changes
      in Assets and Liabilities:Accounts
      receivable
            
            
            7,918
            
            
            
            (13,606
            )
            
            
            (5,885
            )Inventories
            
            
            (17,333
            )
            
            
            (92
            )
            
            
            (20,958
            )Prepaid
      expenses and other
            
            
            (3,545
            )
            
            
            3,202
            
            
            
            (10,201
            )Other
      non-current assets
            
            
            (2,744
            )
            
            
            (457
            )
            
            
            (2,553
            )Accounts
      payable
            
            
            7,116
            
            
            
            12,588
            
            
            
            (1,832
            )Accrued
      expenses and other
            
            
            24,677
            
            
            
            11,648
            
            
            
            12,268Reclamation
      and mine closure costs
            
            
            (5,281
            )
            
            
            5,509
            
            
            
            5,014Other
      liabilities
            
            
            6,834
            
            
            
            5,502
            
            
            
            5,582Net
      cash from operating activities
            
            
            78,729
            
            
            
            22,471
            
            
            
            55,591CASH
      FLOWS FROM INVESTING ACTIVITIES:Proceeds
      from the sale of assets
            
            
            8,786
            
            
            
            46,524
            
            
            
            3,782Net
      proceeds from sale-leaseback
            
            
            —
            
            
            
            —
            
            
            
            5,413Additions
      to property, plant, equipment and mine development
            
            
            (132,197
            )
            
            
            (160,807
            )
            
            
            (165,658
            )Cash
      paid related to acquisitions, net
            
            
            (603
            )
            
            
            (12,717
            )
            
            
            (4,721
            )Withdrawals
      (deposits) of restricted cash
            
            
            (26
            )
            
            
            193
            
            
            
            415Distribution
      to joint venture
            
            
            —
            
            
            
            (100
            )
            
            
            —Net
      cash from investing activities
            
            
            (124,040
            )
            
            
            (126,907
            )
            
            
            (160,769
            )CASH
      FLOWS FROM FINANCING ACTIVITIES:Borrowings
      on short-term debt
            
            
            6,310
            
            
            
            26,082
            
            
            
            10,375Repayments
      on short-term debt
            
            
            (1,569
            )
            
            
            (45,368
            )
            
            
            (20,400
            )Borrowings
      on long-term debt
            
            
            3,496
            
            
            
            65,000
            
            
            
            71,543Repayments
      on long-term debt and capital leases
            
            
            (6,295
            )
            
            
            (68,585
            )
            
            
            (112,418
            )Debt
      issuance costs
            
            
            —
            
            
            
            (9,285
            )
            
            
            (9,367
            )Proceeds
      from stock options exercised
            
            
            149
            
            
            
            —
            
            
            
            —Proceeds
      from senior notes offering
            
            
            —
            
            
            
            —
            
            
            
            175,000Proceeds
      from convertible notes offering
            
            
            —
            
            
            
            225,000
            
            
            
            —Net
      cash from financing activities
            
            
            2,091
            
            
            
            192,844
            
            
            
            114,733NET
      CHANGE IN CASH AND CASH EQUIVALENTS
            
            
            (43,220
            )
            
            
            88,408
            
            
            
            9,555CASH
      AND CASH EQUIVALENTS, BEGINNING OF PERIOD
            
            
            107,150
            
            
            
            18,742
            
            
            
            9,187CASH
      AND CASH EQUIVALENTS, END OF PERIOD
            
            $
            63,930
            
            
            $
            107,150
            
            
            $
            18,742Supplemental
      information:Cash
      paid for interest (net of amount capitalized)
            
            $
            36,193
            
            
            $
            20,113
            
            
            $
            4,898Cash
      (paid) received for income taxes
            
            $
            —
            
            
            $
            2,971
            
            
            $
            (150
            )Supplemental
      disclosure of non-cash items:Purchases
      of property, plant, equipment and mine development through accounts
      payable
            
            $
            12,942
            
            
            $
            547
            
            
            $
            5,145Purchases
      of property, plant, equipment and mine development through financing
      arrangements
            
            $
            40,708
            
            
            $
            10,971
            
            
            $
            26,175Assets
      acquired through the assumption of liabilities
            
            $
            17,464
            
            
            $
            2,016
            
            
            $
            —Assets
      acquired through the exchange of property
            
            $
            22,608
            
            
            $
            —
            
            
            $
            —





See
notes to consolidated financial statements


F-6











INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








1.
            ORGANIZATION





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





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.





International
Coal Group, Inc. was formed in March 2005, as a 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. In addition, the Company completed acquisitions of Anker Coal
Group, Inc. (“Anker”) and CoalQuest Development, LLC (“CoalQuest”), on
November 18, 2005.





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 14 to the
consolidated financial statements for further discussion regarding the
consolidation of VIEs. The Company accounts for its undivided interest in
coalbed methane wells (see Note 7) using the proportionate consolidation method,
whereby its share of assets, liabilities, revenues and expenses are included in
the appropriate classification in the financial statements. The consolidated
financial statements are presented in accordance with accounting principles
generally accepted in the United States of America. Significant intercompany
transactions and balances have been eliminated.





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





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





F-7





INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Inventories—Components
of inventories consist of coal and parts and supplies (see Note 3).





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




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





Derivative
Financial Instruments—The Company uses interest rate swaps 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
(“SFAS No. 133”), establishes accounting and reporting standards for
derivative instruments and hedging activities.





In
May 2006, the Company entered into an Interest Rate Collar Agreement (the
“Collar Agreement”), which became effective as of March 31, 2007 and will
expire on March 31, 2009. The Company uses the Collar Agreement to hedge
its interest rate risk on $200,000 notional amount of revolving debt. The
interest rate collar is designed as a cash flow hedge to offset the impact of
changes in the LIBOR interest rate above 5.92% and below 4.80%. The Company has
not designated its derivatives as hedging instruments and recognizes the change
in the fair value of its derivatives in its consolidated statement of operations
in the period of change. The derivative liability, resulting from adjusting the
Collar Agreement to its fair value of approximately $1,665, including the
Company’s initial net investment of $300, is included in accrued expenses and
other in the Company’s consolidated balance sheet at December 31, 2008. Such
adjustment resulted in losses of approximately $1,993, $1,649 and $939 for years
ended December 31, 2008, 2007 and 2006, respectively, and is included in
interest expense.





Pursuant
to FSP APB 14-1, the Company’s convertible notes are accounted for as
convertible debt in the accompanying consolidated balance sheet and the embedded
conversion option in the convertible notes has been accounted for as a component
of equity.





Advance
Royalties—The Company is required, under certain royalty lease
agreements, to make minimum royalty payments whether or not mining activity is
being performed on the leased property. These minimum payments may be recoupable
once mining begins on the leased property. The recoupable minimum royalty
payments are capitalized and amortized based on the units-of-production method
at a rate defined in the lease agreement once mining activities begin. The
Company has recorded net advance royalties of $22,573 and $20,188, the current
portion of $5,111 and $5,528 is included in prepaid expense at December 31, 2008
and 2007, respectively. Unamortized deferred royalty costs are expensed when
mining has ceased or a decision is made not to mine on such property. At
December 31, 2008 and 2007, the Company has recorded allowances for such
circumstances totaling $3,909 and $3,771, respectively.





F-8








INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Coal Supply
Agreements—Purchase price allocated to the Company’s below-market coal
supply agreements (sales contracts) acquired in acquisitions accounted for as
business combinations were capitalized and are being amortized on the basis of
coal to be shipped over the term of the contracts. Purchase price allocated to
the Company’s above-market coal supply agreement was capitalized and is being
reduced as related cash payments are received. Value was allocated to coal
supply agreements based on discounted cash flows attributable to the difference
between the above- or below-market contract price and the prevailing market
price at the date of acquisition. The net book value of the Company’s
above-market coal supply agreement was $3,447 and $3,713 at December 31, 2008
and 2007, respectively. This amount is recorded in other assets in the Company’s
consolidated balance sheets. The net book value of the below-market coal supply
agreements was $43,888 and $39,668 at December 31, 2008 and 2007, respectively.
Amortization income on the below-market coal supply agreements was $9,590,
$19,214 and $13,494 in 2008, 2007 and 2006, respectively. Amortization income is
included in depreciation, depletion and amortization expense. Based on expected
shipments related to these contracts, the Company expects to record annual
amortization income on the below-market coal supply agreements in each of the
next five years as reflected in the table below.





Below-market
              contracts2009
            
            $
            10,0912010
            
            
            7,8812011
            
            
            3,1862012
            
            
            3,1862013
            
            
            3,186





Property, Plant,
Equipment and Mine Development—Property, plant, equipment and mine
development costs, including coal lands and mineral rights, are recorded at
cost, which includes construction overhead and capitalized interest. Interest
cost applicable to major asset additions is capitalized during the construction
period and totaled $6,721 and $5,433 for the years ended December 31, 2008 and
2007, respectively. Expenditures for major renewals and betterments are
capitalized, while expenditures for maintenance and repairs are expensed as
incurred. Coal lands and mineral rights costs are depleted using the
units-of-production method, based on estimated recoverable 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 as
follows:





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





F-9








INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








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 that are
determined to have an indefinite useful life are not amortized, but instead must
be tested for impairment at least annually. The goodwill impairment test
consists of two steps. The first identifies potential impairment by comparing
the fair value of a reporting unit with its carrying amount, including goodwill.
Fair value of a reporting unit is estimated using present value techniques, such
as discounted cash flows of projected future operations developed by management,
or a weighting of income and market approaches. If the fair value of the
reporting unit exceeds the carrying amount, goodwill is not considered impaired
and the second step is not necessary. If the carrying value of the reporting
unit exceeds the fair value, the second step is necessary to measure the amount
of impairment loss by comparing the implied fair value of goodwill with its
carrying amount. Implied fair value of goodwill is determined as the amount that
the fair value of the assets of a business unit exceeds their carrying value,
excluding goodwill. Impairment loss is measured as the amount of the carrying
value of goodwill that exceeds its implied fair value. The Company performs its
impairment test as of October 31st of
each year. See Note 5.





Debt Issuance
Costs—Debt issuance costs reflect fees incurred to obtain financing. Debt
issuance costs related to the Company’s outstanding debt are amortized over the
life of the related debt. Amortization expense for the years ended December 31,
2008, 2007 and 2006 was $2,428, $8,082 and $3,418, respectively, and is included
in interest expense. Amortization expense for 2008, 2007 and 2006 includes $0,
$5,348 and $1,369, respectively, representing deferred financing fees
written-off as a result of amending and restating the Company’s prior credit
agreements.





Restricted
Cash—Restricted cash includes amounts required by various royalty and
reclamation agreements. Restricted cash of $1,589 and $1,563 at December 31,
2008 and 2007, respectively, is included in other non-current
assets.





Coal Mine
Reclamation and Mine Closure Costs—The Company’s asset retirement
obligations arise from the Federal Surface Mining Control and Reclamation Act of
1977 and similar state statutes, which require that mine property be restored in
accordance with specified standards and an approved reclamation plan. The
Company records these reclamation obligations according to the provisions of
SFAS No. 143,Accounting for Asset Retirement Obligations (“SFAS No. 143”).
SFAS No. 143 requires the fair value of a liability for an asset
retirement obligation to be recognized in the period in which the legal
obligation associated with the retirement of the long-lived asset is incurred.
Fair value of reclamation liabilities is determined based on the present value
of the estimated future expenditures. When the liability is initially recorded,
the offset is capitalized by increasing the carrying amount of the related
long-lived asset. Over time, the liability is accreted to its present value and
the capitalized cost is depreciated over the useful life of the related asset.
To settle the liability, the obligation is paid, and to the extent there is a
difference between the liability and the amount of cash paid, a gain or loss
upon settlement is recorded. On at least an annual basis, the Company reviews
its entire reclamation liability and makes necessary adjustments for permit
changes as granted by state authorities, additional costs resulting from
accelerated mine closures and revisions to cost estimates and productivity
assumptions.





F-10







INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








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 impairment indicators are present. When the sum of
projected cash flows is less than the carrying amount, impairment losses are
indicated. If the fair value of the assets is less than the carrying amount of
the assets, an impairment loss is recognized. In determining such impairment
losses, discounted cash flows or asset appraisals are utilized to determine the
fair value of the assets being evaluated. Also, in certain situations, expected
mine lives are shortened because of changes to planned operations. When that
occurs and it is determined that the mine’s underlying costs are not recoverable
in the future, reclamation and mine 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. During the year ended December 31,
2008, the Company recognized an impairment loss of $7,191 in accordance with
SFAS No. 144. See Note 4.





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.





The
Company recognizes interest expense and penalties related to unrecognized tax
benefits as interest expense and other expense, respectively, in its
consolidated statement of operations.





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





Coal
sales revenues also result from the sale of brokered coal produced by others.
Revenue is recognized and recorded at the time of shipment or delivery to the
customer, prices are fixed or determinable and the title or risk of loss has
passed in accordance with the terms of the sale agreement. The revenues related
to brokered coal sales are included in coal sales revenues on a gross basis and
the corresponding cost of the coal from the supplier is recorded in cost of coal
sales in accordance with Emerging Issues Task Force (“EITF”) 99-19,Reporting Revenue Gross as a
Principal versus Net as an Agent.





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





Other
revenues primarily consist of contract mining income, coalbed methane sales, ash
disposal services, equipment and parts sales, equipment rebuild and maintenance
services, royalties and coal handling and processing income. With respect to
other revenues recognized in situations unrelated to the shipment of coal, we
carefully review the facts and circumstances of each transaction and 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 related income is
earned.





F-11







INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








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 actuarially determined estimates, for the expected
costs of providing postretirement benefits other than pensions for current and
future retired employees and their dependents, which are primarily healthcare
and life insurance benefits, during an employee’s actual working career.
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. The Company’s liability is reduced by the
amount of Medicare prescription drug reimbursement that it expects to receive
under the Drug Improvement and Modernization Act of 2003. See Note
12.





As
prescribed by SFAS No. 158,Employers’ Accounting for Defined
Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements
No. 87, 88, 106 and 132(R)(“SFAS No. 158”), changes in the funded
status of the postretirement benefit plan are recognized through other
comprehensive income.





Workers’
Compensation and Black Lung Benefits—The Company is liable under federal
and state laws to pay workers’ compensation and pneumoconiosis (black lung)
benefits to eligible employees. The Company utilizes a combination of
participation in a state run program and insurance policies. For black lung
liabilities, provisions are made for actuarially determined estimated benefits.
The Company follows SFAS No. 112,Employers’ Accounting for
Postemployment Benefits and SFAS No. 158 for purposes of accounting for
and presentation of its black lung liabilities.





As
prescribed by SFAS No. 158, changes in the funded status of the black lung
obligation are recognized through other comprehensive income.





Stock-Based
Compensation—The Company accounts for its stock-based awards in
accordance with SFAS No. 123(R),Share Based Payment (“SFAS
No. 123(R)”). SFAS No. 123(R) 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. Under the fair value recognition provisions of SFAS
No. 123(R), the Company measures stock-based compensation cost based upon
the grant date fair value of the award, which is recognized as expense on a
straight-line basis over the corresponding vesting period. The Company uses the
Black-Scholes option valuation model to determine the estimated fair value of
its stock options at the date of grant. Determining the fair value of
share-based awards at the grant date requires several assumptions. These
assumptions include the expected life of the option, the risk-free interest
rate, volatility of the price of the Company’s common stock and expected
dividend yield on the Company’s common stock. See Note 13.





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





F-12







INTERNATIONAL COAL GROUP, INC. AND
SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Recent Accounting
Pronouncements—In September 2006, the Financial Accounting Standards
Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”)
No. 157,Fair Value
Measurements (“SFAS No. 157”). SFAS No. 157 clarifies the
definition of fair value, establishes a framework for measuring fair value and
expands the disclosures on fair value measurements. SFAS No. 157 is
effective for fiscal years beginning after November 15, 2007. Adoption of
SFAS No. 157 did not have a material impact on the Company’s financial
position, results of operations or cash flows; however, adoption did result in
additional information being included in the footnotes accompanying the
Company’s consolidated financial statements. See Note 18.





In
February 2008, the FASB issued FASB Staff Position (“FSP”) 157-2,Effective Date of FASB Statement
No. 157 (“FSP 157-2”). FSP 157-2 permits delayed adoption of SFAS 157 for
certain non-financial assets and liabilities, which are not recognized at fair
value on a recurring basis, until fiscal years, and interim periods within those
fiscal years, beginning after November 15, 2008. Adoption of FSP 157-2 did
not have a material impact on the Company’s financial position, results of
operations or cash flows.





In
February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial
Assets and Financial Liabilities – Including an amendment of FASB Statement
No. 115 (“SFAS No. 159”). SFAS No. 159 provides entities
with an option to report selected financial assets and liabilities at fair value
and establishes presentation and disclosure requirements designed to facilitate
comparisons between entities that choose different measurement attributes for
similar types of assets and liabilities. SFAS No. 159 is effective as of
the beginning of the first fiscal year that begins after November 15, 2007.
Adoption of SFAS No. 159 did not have a material impact on the Company’s
financial position, results of operations or cash flows.





In
October 2008, the FASB issued FSP 157-3,Determining Fair Value of a
Financial Asset in a Market That Is Not Active (“FSP 157-3”). FSP 157-3
clarified the application of SFAS No. 157 in an inactive market. It demonstrated
how the fair value of a financial asset is determined when the market for that
financial asset is inactive. FSP 157-3 was effective upon issuance, including
prior periods for which financial statements had not been issued. Adoption of
FSP 157-3 did not have a material impact on the Company’s financial position,
results of operations or cash flows.





In
May 2008, the FASB issued FSP APB 14-1,Accounting for Convertible Debt
Instruments That May be Settled in Cash Upon Conversion (Including Partial Cash
Settlement) (“FSP APB 14-1”). FSP APB 14-1 requires the liability and
equity components of convertible debt instruments that may be settled in cash
upon conversion to be separately accounted for in a manner that reflects the
issuer’s nonconvertible debt borrowing rate. To allocate the proceeds from a
convertible debt offering in this manner, a company would first need to
determine the carrying amount of the liability component, which would be based
on the fair value of a similar liability, excluding any embedded conversion
options. The resulting debt discount would be amortized over the period during
which the debt is expected to be outstanding as additional non-cash interest
expense. FSP APB 14-1 is effective for financial statements for fiscal years
beginning after December 15, 2008, and interim periods within those fiscal
years, and would be applied retrospectively for all periods presented. See Note
23.





F-13





INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








In
December 2007, the FASB issued SFAS No. 141 (Revised 2007),Business Combinations (“SFAS
No. 141(R)”). SFAS No. 141(R) will significantly change the accounting
for business combinations. Under SFAS No. 141(R), an acquiring entity will
be required to recognize all the assets acquired and liabilities assumed in a
transaction at the acquisition-date fair value with limited exceptions. SFAS
No. 141(R) will change the accounting treatment for certain specific
acquisition-related items including: (i) expensing acquisition-related
costs as incurred, (ii) valuing noncontrolling interests at fair value at
the acquisition date and (iii) expensing restructuring costs associated
with an acquired business. SFAS No. 141(R) also includes a substantial
number of new disclosure requirements. SFAS No. 141(R) is to be applied to
any business combination for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after
December 15, 2008. Upon adoption, SFAS No. 141(R) will impact the
accounting for the Company’s future business combinations.





In
December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in
Consolidated Financial Statements–an amendment to ARB No. 51 (“SFAS
No. 160”). SFAS No. 160 establishes new accounting and reporting
standards for the noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in
a subsidiary (minority interest) is an ownership interest in the consolidated
entity that should be reported as equity in the consolidated financial
statements and separate from the parent company’s equity. Among other
requirements, this statement requires consolidated net income to be reported at
amounts that include the amounts attributable to both the parent and the
noncontrolling interest. It also requires disclosure, on the face of the
consolidated statement of operations, of the amounts of consolidated net income
attributable to the parent and to the noncontrolling interest. The provisions of
SFAS No. 160 are effective for fiscal years, and interim periods within
those fiscal years, beginning on or after December 15, 2008. See Note
23.





In
March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative
Instruments and Hedging Activities – an amendment of FASB Statement
No. 133 (“SFAS No. 161”). SFAS No. 161 requires additional
disclosures for derivative instruments and hedging activities that include how
and why an entity uses derivatives, how these instruments and the related hedged
items are accounted for under FASB Statement No. 133,Accounting for Derivative
Instruments and Hedging Activities, and related interpretations and how
derivative instruments and related hedged items affect the entity’s financial
position, results of operations and cash flows. SFAS No. 161 is effective
for fiscal years, and interim periods within those fiscal years, beginning after
November 15, 2008. Adoption of SFAS No. 161 did not impact the
footnotes accompanying the Company’s consolidated financial
statements.





In
May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted
Accounting Principles (“SFAS No. 162”). SFAS No. 162 identifies the
sources of accounting principles and the framework for selecting the principles
to be used in the preparation of financial statements of nongovernmental
entities that are presented in conformity with generally accepted accounting
principles. SFAS No. 162 directs the hierarchy to the entity, rather than
the independent auditors, as the entity is responsible for selecting accounting
principles for financial statements that are presented in conformity with
generally accepted accounting principles. SFAS No. 162 is effective for fiscal
years, and interim periods within those fiscal years, beginning on or after
December 15, 2008. Adoption of SFAS No. 162 did not have a material impact
on the Company’s financial position, results of operations or cash
flows.





F-14







INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








In
June 2008, the FASB issued EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities
(“EITF 03-6-1”). EITF 03-6-1 clarifies that all outstanding unvested share-based
payment awards that contain rights to nonforfeitable dividends participate in
undistributed earnings with common shareholders. Awards of this nature are
considered participating securities and the two-class method of computing basic
and diluted earnings per share must be applied. EITF 03-6-1 is effective for
fiscal years beginning after December 15, 2008. Adoption of EITF 03-6-1 did not
have a material impact on the Company’s financial position, results of
operations or cash flows.





In
June 2008, the FASB ratified EITF 07-5,Determining Whether an Instrument
(or an Embedded Feature) Is Indexed to an Entity’s Own Stock (“EITF
07-5”). EITF 07-5 provides that an entity should use a two step approach to
evaluate whether an equity-linked financial instrument (or embedded feature) is
indexed to its own stock, including evaluating the instrument’s contingent
exercise and settlement provisions. It also clarifies the impact of foreign
currency denominated strike prices and market-based employee stock option
valuation instruments on the evaluation. EITF 07-5 is effective for fiscal years
beginning after December 15, 2008. Adoption of EITF 07-5 did not have a material
impact on the Company’s financial position, results of operations or cash
flows.





3.
            INVENTORIES





As
of December 31, 2008 and 2007, inventories consisted of the
following:





2008
            
            
            2007Coal
            
            $
            28,436
            
            
            $
            19,855Parts
      and supplies
            
            
            32,159
            
            
            
            21,602Reserve
      for obsolescence, parts and supplies
            
            
            (1,807
            )
            
            
            (778
            )Total
            
            $
            58,788
            
            
            $
            40,679








F-15







INTERNATIONAL COAL GROUP, INC. AND
SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








4.
            PROPERTY,
      PLANT, EQUIPMENT AND MINE
DEVELOPMENT





As
of December 31, 2008 and 2007, property, plant, equipment and mine development
are summarized by major classification as follows:





2008
            
            
            2007Coal
      lands and mineral rights
            
            $
            586,512
            
            
            $
            594,034Plant
      and equipment
            
            
            571,083
            
            
            
            442,530Mine
      development
            
            
            181,876
            
            
            
            133,557Land
      and land improvements
            
            
            24,119
            
            
            
            20,889Coalbed
      methane well development costs
            
            
            14,889
            
            
            
            14,2761,378,479
            
            
            
            1,205,286Less
      accumulated depreciation, depletion and amortization
            
            
            (309,182
            )
            
            
            (230,576
            )Net
      property, plant and equipment
            
            $
            1,069,297
            
            
            $
            974,710





Depreciation,
depletion and amortization expense related to property, plant, equipment and
mine development for the years ended December 31, 2008, 2007 and 2006 was
$105,637, $105,726 and $85,344, respectively.





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





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





In
September 2007, the Company sold its Denmark reserve in Southern Illinois for
$39,000 in cash. As a result, the Company recognized a gain of $36,782 which is
included in gain on sale of assets in its statement of operations for the year
ended December 31, 2007. Under terms of the transaction, the purchaser is also
obligated to pay the Company an overriding royalty totaling $4,000 on certain
future production that will be recognized as the reserves are
mined.





F-16







INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








5.
            GOODWILL





The
Company recorded goodwill related to its acquisition of certain assets and
assumption of certain liabilities of Horizon and Anker/CoalQuest. The Company
assigned the goodwill to certain of the acquired reporting units based on their
estimated fair values. In accordance with SFAS No. 142, the Company tests
goodwill for impairment on an annual basis, at a minimum, and more frequently if
a triggering event occurs. The 2008 goodwill testing identified impairment of
goodwill at the Company’s ADDCAR Systems, LLC (“ADDCAR”) subsidiary resulting in
a $30,237 impairment loss. The loss reflects the negative impact of several
contributing factors which resulted in a reduction in the forecasted cash flows
to estimate fair value. These factors include but are not limited to less than
anticipated demand for and increased costs of contract mining services, an
increased reliance on lower-margin mining equipment sales and the need for
capital investment to replace aging equipment. Furthermore, the business,
regulatory and marketplace environment in which the Company currently operates
differs significantly from the historical environment that drove the business
case used to value and record the acquisition of this business unit.
Accordingly, the Company has been unable to attain the forecasted projections
that were used to initially value the business unit at the date of
acquisition.





The
goodwill testing performed in 2007 identified impairment of goodwill at the
following business units: $32,914 at Hazard, $58,511 at Eastern, $42,941 at East
Kentucky and $36,036 at Knott County.





In
2006, goodwill and certain assets acquired and liabilities assumed were adjusted
to fair value as a result of the finalization of the purchase price allocation
associated with the Anker/CoalQuest acquisitions. Goodwill was primarily
allocated to property, plant, equipment and mine development. The adjustments to
the purchase price allocation of Horizon represents allocation of additional
purchase price due to excess actual expenses related to the acquisition over
management’s original estimates and reallocation of purchase price to assets and
liabilities for which fair values were not available at the time of the
acquisition. The adjustments to the purchase price allocation of Horizon
recorded during 2006 were due to a refund of legal fees held in escrow. Bonding
royalties represent payments made on the gross sales receipts for coal mined and
sold by the former Horizon companies that ICG acquired (see Note 16). At
December 31, 2006, the entire goodwill balance related to the Horizon
acquisition.





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





Balance
      as of December 31, 2005
            
            $
            344,394Adjustments
      to purchase price allocation of Horizon
            
            
            (812
            )Bonding
      royalty
            
            
            3,975Adjustments
      to purchase price allocation of Anker/CoalQuest
            
            
            (150,800
            )Balance
      as of December 31, 2006
            
            
            196,757Bonding
      royalty
            
            
            3,882Impairment
      loss
            
            
            (170,402
            )Balance
      as of December 31, 2007
            
            
            30,237Impairment
      loss
            
            
            (30,237
            )Balance
      as of December 31, 2008
            
            $
            —





F-17







INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES




NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








6.
            ACCRUED
      EXPENSES AND OTHER





As
of December 31, 2008 and 2007, accrued expenses and other consisted of the
following:





2008
            
            
            2007Compensation
      and related expenses
            
            $
            38,076
            
            
            $
            25,147Interest
            
            
            17,776
            
            
            
            17,330Royalties
            
            
            5,826
            
            
            
            4,282Sales
      and production related taxes
            
            
            5,574
            
            
            
            5,098Deferred
      revenue
            
            
            5,506
            
            
            
            —Personal
      property, land and mineral taxes
            
            
            3,719
            
            
            
            3,582Transportation
            
            
            3,453
            
            
            
            2,655Other
            
            
            7,774
            
            
            
            4,629Total
            
            $
            87,704
            
            
            $
            62,723





7.
            INVESTMENT
      IN JOINT OPERATING AGREEMENT





In
July 2005, CoalQuest entered into an agreement with CDX Gas, LLC (“CDX”)
for the purpose of exploration and development of coalbed methane under a joint
operating agreement, whereby CoalQuest has the right to obtain up to a 50%
undivided working interest in each well drilled on property owned by the
Company. The Company accounts for this joint operation using the proportionate
consolidation method, whereby its share of assets, liabilities, revenues and
expenses are included in the appropriate classification in the Company’s
financial statements. As of December 31, 2008 and 2007, the Company recorded
assets of $2,356 and $5,891 net of accumulated depletion of $12,533 and $8,385,
respectively, related to the operating agreement. This amount is included in net
property, plant, equipment and mine development in the consolidated balance
sheet. For the years ended December 31, 2008, 2007 and 2006, the Company
recorded $8,597, $7,741 and $1,949 and $2,935, $983 and $313, respectively, of
coalbed methane revenue and royalty income, respectively, related to the
operating agreement which is included in other revenues in the consolidated
statement of operations. During 2008, CDX declared bankruptcy. As a result, the
Company recorded a reserve against outstanding accounts receivable due from CDX
totaling $1,282.





8.
            ACQUISITION





In
May 2008, the Company entered into an agreement to purchase the membership
interests of Powdul Acquisition LLC. The purchase resulted in the Company
acquiring the idle Powell Mountain underground mining operation and related
assets. The cost of the acquired entity totaled $18,067 which included cash paid
of $450, other related acquisition costs of $153 and total liabilities of
$17,464. Total liabilities include current liabilities of $132, asset retirement
obligations of $3,522 and a below-market contract valued at $13,810. As a result
of the purchase price allocation, the Company recorded current assets of $1,335,
mineral interests of $10,998, development costs of $1,922 and property, plant
and equipment of $3,812. The acquisition would not have had a material impact on
the Company’s results of operations had it taken place on January 1,
2008.





F-18





INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








9.
            DEBT





Long-Term
Debt and Capital Leases





As
of December 31, 2008 and 2007, long-term debt and capital leases consisted of
the following:





2008
            
            
            20079.00%
      Convertible Senior Notes, due 2012, net of debt discount of $17,369and $21,082,
      respectively
            
            $
            207,631
            
            
            $
            203,91810.25%
      Senior Notes, due 2014
            
            
            175,000
            
            
            
            175,000Equipment
      notes
            
            
            43,378
            
            
            
            12,330Capital
      leases and other
            
            
            6,861
            
            
            
            —Total
            
            
            432,870
            
            
            
            391,248Less
      current portion
            
            
            (15,319
            )
            
            
            (4,234
            )Long-term
      debt
            
            $
            417,551
            
            
            $
            387,014





Convertible
senior notes—In 2007, the Company completed a private offering of
$225,000 aggregate principal amount of 9.00% Convertible Senior Notes (the
“Convertible Notes”) due 2012. The Convertible Notes are the Company’s senior
unsecured obligations and are guaranteed on a senior unsecured basis by the
Company’s material future and current domestic subsidiaries. The Convertible
Notes and the related guarantees rank equal in right of payment to all of the
Company’s and the guarantors’ respective existing and future unsecured senior
indebtedness. Interest is payable semi-annually in arrears on February 1
and August 1 of each year.





The
Convertible Notes became convertible at the option of holders beginning
July 1, 2008. The conversion period expired on September 30, 2008 pursuant
to the terms of the governing indenture with no holders exercising their
conversion rights. The Convertible Notes may become convertible again in the
future under certain conditions. Accordingly, the Company will reassess the
convertibility on a quarterly basis.





F-19





INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








The
principal amount of the Convertible Notes is payable in cash and amounts above
the principal amount, if any, will be convertible into shares of the Company’s
common stock or, at the Company’s option, cash. The Convertible Notes are
convertible at an initial conversion price, subject to adjustment, of $6.10 per
share (approximating 163.8136 shares per one thousand dollar principal amount of
the Convertible Notes). The volume weighted-average price of the Company’s stock
subsequent to the expiration date of the conversion period was below $6.10 per
share. Accordingly, there were no potentially convertible shares at December 31,
2008. The Convertible Notes are convertible upon the occurrence of certain
events, including (i) prior to February 12, 2012 during any calendar
quarter after September 30, 2007, if the closing sale price per share of
the Company’s common stock for each of 20 or more trading days in a period of 30
consecutive trading days ending on the last trading day of the immediately
preceding calendar quarter exceeds 130% of the conversion price in effect on the
last trading day of the immediately preceding calendar quarter; (ii) prior
to February 12, 2012 during the five consecutive business days immediately
after any five consecutive trading day period in which the average trading price
for the notes on each day during such five trading-day period was equal to or
less than 97% of the closing sale price of the Company’s common stock on such
day multiplied by the then current conversion rate; (iii) upon the
occurrence of specified corporate transactions; and (iv) at any time from,
and including February 1, 2012 until the close of business on the second
business day immediately preceding August 1, 2012. In addition, upon events
defined as a “fundamental change” under the Convertible Notes indenture, the
Company may be required to repurchase the Convertible Notes at a repurchase
price in cash equal to 100% of the principal amount of the notes to be
repurchased, plus any accrued and unpaid interest to, but excluding, the
fundamental change repurchase date. As such, in the event of a fundamental
change or the aforementioned average pricing thresholds are met, the Company
would be required to classify the entire amount outstanding of the Convertible
Notes as a current liability in the following quarter. In the event that a
significant number of the holders of the Convertible Notes were to convert their
notes prior to maturity, the Company may not have enough available funds at any
particular time to make the required repayments. Under these circumstances, the
Company would look to WLR, its banking group and other potential lenders to
obtain short-term funding until such time that it could secure necessary
financing on a long-term basis. The availability of any such financing would
depend upon the circumstances at the time, including the terms of any such
financing, and other factors. In addition, if conversion occurs in connection
with certain changes in control, the Company may be required to deliver
additional shares of the Company’s common stock (a “make whole” premium) by
increasing the conversion rate with respect to such notes. For a discussion
of the effects of the Convertible Notes on earnings per share, see Note
15.





F-20


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Senior
notes—In 2006, the Company sold $175,000 aggregate principal amount of
the Company’s 10.25% Senior Notes (the “Notes”) due July 15, 2014. Interest
on the Notes is payable semi-annually in arrears on July 15 and
January 15 of each year. The Notes are senior unsecured obligations and are
guaranteed on a senior unsecured basis by all of the Company’s current and
future domestic subsidiaries that are material or that guarantee the Company’s
amended and restated credit facility. The Notes and the guarantees rank equally
with all of the Company’s and the guarantors’ existing and future senior
unsecured indebtedness, but are effectively subordinated to all of the Company’s
and the guarantors existing and future senior secured indebtedness to the extent
of the value of the assets securing that indebtedness and to all liabilities of
the Company’s subsidiaries that are not guarantors. The Company has the option to
redeem all or a portion of the Notes at 100% of the aggregate principal amount
at maturity at any time on or after July 15, 2012. At any time on or after July
15, 2010 and prior to July 15, 2012, we may also redeem all or a portion of the
Notes at a redemption price equal to 100% of the aggregate principal amount of
the Notes plus an applicable premium as of, and accrued and unpaid interest and
additional interest, if any, to, but not including the date of
redemption. At any time before July 15, 2009, the Company may also
redeem up to 35% of the aggregate principal amount of the Notes at a redemption
price of 110.25% of the principal amount, plus accrued and unpaid interest, if
any, to the date of redemption, with the proceeds of certain equity offerings.
Upon a change of control, the Company may be required to offer to purchase the
Notes at a purchase price equal to 101% of the principal amount, plus accrued
and unpaid interest.





The
indenture governing the Notes contains covenants that limit the Company’s
ability to, among other things, incur additional indebtedness, issue preferred
stock, pay dividends, repurchase, repay or redeem the Company’s capital stock,
make certain investments, sell assets and incur liens. As of December 31,
2008, the Company was in compliance with its covenants under the
indenture.





Credit
facility—In 2006, the Company entered into a second amended and restated
credit agreement (the “Amended Credit Facility”) consisting of a revolving
credit facility which matures on June 23, 2011. In July 2007, concurrent
with the issuance of the Convertible Notes, the Company again amended the
Amended Credit Facility to reduce the commitments thereunder to $100,000 of
which a maximum of $80,000 may be used for letters of credit. The amendment,
among other things, modified the maximum permitted leverage ratio, the minimum
interest coverage ratio and the maximum amount of capital expenditures
permitted. Further, the amendment revised certain interest rate thresholds and
unused commitment fee levels under the Amended Credit Facility. In February
2009, the Company executed a further amendment to the Amended Credit Facility
that affected certain 2009 debt covenants. The amendment modified the maximum
permitted leverage and minimum interest coverage ratios. The amendment also
decreased the maximum capital spending and added a minimum liquidity
requirement. Debt covenants for years subsequent to 2009 were not affected by
the amendment. As of December 31, 2008, the Company had no borrowings
outstanding and letters of credit totaling $73,551 outstanding, leaving $26,449
available for future borrowing capacity. Interest on the borrowings under the
Amended Credit Facility is payable, at the Company’s option, at either the base
rate plus an applicable margin based on the Company’s leverage ratio of 1.25% to
2.00% as of December 31, 2008 or LIBOR plus an applicable margin based on
the Company’s leverage ratio of 2.25% to 3.00% as of December 31, 2008. As
of December 31, 2008, the Company was in compliance with its financial covenants
under the Amended Credit Facility.





Equipment notes
and other—The equipment notes, having various maturity dates extending to
January 2014, are collateralized by mining equipment. As of December 31, 2008,
the Company had amounts outstanding for 36-month through 60-month terms with a
weighted-average interest rate of 6.42%. At December 31, 2008, additional funds
are available under the Company’s revolving equipment credit facility for terms
ranging from 36 to 60 months with a current interest rate of 8.75%.
Additionally, the Company finances certain of its annual insurance premiums at a
current interest rate of 5.42%.





F-21







INTERNATIONAL COAL GROUP, INC. AND
SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Future
maturities of long-term debt and capital leases are as follows as of December
31, 2008:





Year
      ending December 31:2009
            
            $
            15,3192010
            
            
            11,7712011
            
            
            9,8392012
            
            
            232,9362013
            
            
            5,306Thereafter
            
            
            175,068Total
            
            
            450,239Less
      debt discount
            
            
            (17,369
            )Total
            
            $
            432,870





Short-Term
Debt





The
Company finances the majority of its annual insurance premiums, a portion of
which is included in short-term debt. The weighted-average interest rate
applicable to the notes was 4.65%. As of December 31, 2008 and 2007, the Company
had $4,741 and $0, respectively, outstanding related to insurance
financing.





10.
            ASSET
      RETIREMENT OBLIGATION





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





The
Company estimates its ultimate reclamation liability based upon detailed
engineering calculations of the amount and timing of the future cash flows to
perform the required work. The Company considers the estimated current cost of
reclamation and applies inflation rates and third-party profit. The third-party
profit is an estimate of the approximate markup that would be charged by
contractors for work performed on the Company’s behalf. The discount rate
applied is based on the rates of treasury bonds with maturities similar to the
estimated future cash flow, adjusted for the Company’s credit
standing.





At
December 31, 2008 and 2007, the asset retirement obligation accrual for
reclamation and mine closure costs totaled $79,246 and $85,920, respectively.
The assets that give rise to the obligation are primarily related to mine
development, preparation plants and loadouts.





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





2008
            
            
            2007Balance
      at beginning of year
            
            $
            85,920
            
            
            $
            92,670Revisions
      of estimated cash flows
            
            
            (5,896
            )
            
            
            (12,620
            )Liabilities
      incurred (net of disposals) or assumed in acquisitions
            
            
            1,438
            
            
            
            7,295Expenditures
            
            
            (9,594
            )
            
            
            (8,237
            )Accretion
            
            
            7,378
            
            
            
            6,812Balance
      at end of year
            
            $
            79,246
            
            
            $
            85,920





F-22







INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








At
December 31, 2008 and 2007, the accrued reclamation and mine closure costs are
included in the accompanying consolidated balance sheets as
follows:





2008
            
            
            2007Current
      portion of reclamation and mine closure costs
            
            $
            11,139
            
            
            $
            7,333Non-current
      portion of Reclamation and mine closure costs
(non-current)
            
            
            68,107
            
            
            
            78,587Total
            
            $
            79,246
            
            
            $
            85,920





11.
            INCOME
      TAXES





The
income tax benefit for the years ended December 31, 2008, 2007 and 2006 are
comprised of the following:





2008
            
            
            2007
            
            
            2006Current:Federal
            
            $
            374
            
            
            $
            1,046
            
            
            $
            (11,487
            )State
            
            
            390
            
            
            
            409
            
            
            
            (767
            )764
            
            
            
            1,455
            
            
            
            (12,254
            )Deferred:Federal
            
            
            (21,877
            )
            
            
            (75,684
            )
            
            
            2,637State
            
            
            (2,557
            )
            
            
            (11,715
            )
            
            
            602(24,434
            )
            
            
            (87,399
            )
            
            
            3,239Income
      tax benefit
            
            $
            (23,670
            )
            
            $
            (85,944
            )
            
            $
            (9,015
            )





The
following table presents the difference between the income tax benefit in the
accompanying statements of operations and the amounts obtained by applying the
statutory U.S. federal income tax rate of 35% to income and losses before income
taxes for the years ended December 31, 2008, 2007 and 2006:








2008
            
            
            2007
            
            
            2006Federal
      income tax benefit computed at statutory rate
            
            $
            (17,464
            )
            
            $
            (81,727
            )
            
            $
            (6,397
            )State
      income tax expense (net of federal tax benefits) computed at statutory
      rate
            
            
            (1,414
            )
            
            
            (7,345
            )
            
            
            (108
            )Percentage
      depletion in excess of tax basis at statutory rate
            
            
            (6,477
            )
            
            
            (1,784
            )
            
            
            (3,084
            )Penalties
            
            
            1,869
            
            
            
            —
            
            
            
            —Goodwill
      impairment
            
            
            (490
            )
            
            
            4,046
            
            
            
            —Other
            
            
            306
            
            
            
            866
            
            
            
            574Income
      tax benefit
            
            $
            (23,670
            )
            
            $
            (85,944
            )
            
            $
            (9,015
            )








F-23





INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








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





2008
            
            
            2007Deferred
      tax assets:Accrued
      employee benefits
            
            $
            22,772
            
            
            $
            20,695Accrued
      reclamation and closure
            
            
            30,274
            
            
            
            31,271Below-market
      contracts
            
            
            15,691
            
            
            
            16,777NOL
      carryover
            
            
            68,909
            
            
            
            48,637Goodwill
            
            
            53,960
            
            
            
            40,501Other
            
            
            19,705
            
            
            
            11,100211,311
            
            
            
            168,981Deferred
      tax liabilities:Property,
      coal lands and mine development costs
            
            
            (232,937
            )
            
            
            (212,474
            )Other
            
            
            (11,879
            )
            
            
            (14,412
            )(244,816
            )
            
            
            (226,886
            )Net
      deferred tax liability
            
            $
            (33,505
            )
            
            $
            (57,905
            )Classified
      in balance sheet:Deferred
      income taxes—current
            
            $
            17,649
            
            
            $
            5,000Deferred
      income taxes—non-current
            
            
            (51,154
            )
            
            
            (62,905
            )Total
            
            $
            (33,505
            )
            
            $
            (57,905
            )





The
Company has a total net operating loss (“NOL”) carryover of $186,441, of which
$2,707 expires in 2024, $17,154 expires in 2025, $5,331 expires in 2026, $99,748
expires in 2027 and $61,501 expires in 2028. The Company is subject to a
limitation of approximately $6,900 per year on $19,861 of the NOLs attributable
to certain acquired entities. However, due to the cumulative nature of the
limitation, the Company has full utilization of NOLs starting in 2008. The
Company also has an alternative minimum tax (“AMT”) loss in the amount of
$35,392, of which $4,451 expires in 2024, $16,796 expires in 2025, and $14,145
expires in 2028. The AMT NOL attributable to certain acquired entities of
$21,247 is subject to the same annual limitation specified above for the regular
NOL. The NOLs reflect $582 of excess tax deductions, which reduce the NOL
carryforward portion of the deferred tax asset. The Company will recognize the
excess tax deduction at such time that the deduction will reduce taxes payable.
Adjustments have been made to certain regular and AMT NOL carryovers as a result
of current Internal Revenue Service audits of 2006 and 2007.





Internal
Revenue Code (“IRC”) Section 382 imposes significant limitations on the annual
utilization of NOL carryforwards if a “change in ownership” is deemed to occur.
Generally, an ownership change is deemed to occur if the Company experiences a
cumulative change in ownership of greater than 50% within a three-year testing
period. The Company completed an IRC Section 382 study and determined that an
ownership change had occurred. Although the IRC Sec 382 ownership change result
in an annual limitation of the Company’s NOL carryforwards, all NOLs are
expected to be fully utilized within the remaining NOL carryforward
period.





The
Company recorded valuation allowances of $2,396 and $1,588 at December 31, 2008
and 2007, respectively, against certain state NOL carryforwards that, more
likely than not, are expected to expire without being utilized.





The
Company files income tax returns in the U.S. and various states. Generally, the
Company is no longer subject to U.S. federal, state and local income tax
examinations by tax authorities for years before 2005. The Company is currently
under examination by the Internal Revenue Service and the state of West Virginia
for certain tax years pertaining to income taxes.





F-24





INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








12.
            EMPLOYEE
      BENEFITS





Employee
benefits at December 31, 2008 and 2007 are summarized as follows:





2008
            
            
            2007Postretirement
      benefits
            
            $
            27,974
            
            
            $
            25,024Black
      lung benefits
            
            
            22,824
            
            
            
            17,758Workers’
      compensation benefits
            
            
            7,847
            
            
            
            6,781Coal
      Act benefits
            
            
            1,277
            
            
            
            1,464Total
            
            
            59,922
            
            
            
            51,027Less
      current portion
            
            
            3,359
            
            
            
            2,925Employee
      benefits—non-current
            
            $
            56,563
            
            
            $
            48,102





Valuation
Date—All actuarially determined benefits were determined as of December
31, 2008 and 2007.





Postretirement
Benefits—Employees of the Company who complete ten years of service, and
certain employees who have completed eight years of service with the former
Horizon companies and complete two years with ICG, will be eligible to receive
postretirement benefits, which consists of healthcare 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, healthcare cost increases, etc.) that the Company uses in
determining its postretirement obligations. The Company assumed discount rates
of 6.25% and 6.50% for the years ended December 31, 2008 and 2007, respectively.
Postretirement benefit expense for the Company totaled $4,664, $3,394 and $2,021
for the years ended December 31, 2008, 2007 and 2006, respectively.





Postretirement
benefit information for the years ended December 31, 2008 and 2007 is as
follows:





2008
            
            
            2007Changes
      in Benefit Obligations:Accumulated
      benefit obligations at beginning of period
            
            $
            25,024
            
            
            $
            18,331Service
      cost
            
            
            2,607
            
            
            
            2,057Interest
      cost
            
            
            1,627
            
            
            
            1,054Actuarial
      (gain) loss
            
            
            (1,257
            )
            
            
            3,593Benefits
      paid
            
            
            (27
            )
            
            
            (11
            )Accumulated
      benefit obligation at end of period
            
            
            27,974
            
            
            
            25,024Fair
      value of plan assets at end of period
            
            
            —
            
            
            
            —Net
      liability
            
            $
            27,974
            
            
            $
            25,024





The
changes in the actuarial loss that are included in accumulated other
comprehensive income were as follows:





2008
            
            
            2007Balance
      at beginning of year
            
            $
            10,235
            
            
            $
            6,925Actuarial
      (gain) loss
            
            
            (1,257
            )
            
            
            3,593Amortization
      of actuarial loss
            
            
            (430
            )
            
            
            (283
            )Balance
      at end of year
            
            $
            8,548
            
            
            $
            10,235





F-25








INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








The
Company expects to recognize $288 of the net actuarial loss as a component of
the net periodic benefit cost during 2009. Components of net periodic benefit
cost for the years ended December 31, 2008, 2007 and 2006 are as
follows:





2008
            
            
            2007
            
            
            2006Net
      periodic benefit cost:Service
      cost
            
            $
            2,607
            
            
            $
            2,057
            
            
            $
            1,297Interest
      cost
            
            
            1,627
            
            
            
            1,054
            
            
            
            668Amortization
      of actuarial loss
            
            
            430
            
            
            
            283
            
            
            
            56Benefit
      cost
            
            $
            4,664
            
            
            $
            3,394
            
            
            $
            2,021





For
measurement purposes, an 8.33% annual rate of increase in the per capita cost of
covered healthcare benefits was assumed, gradually decreasing to 5.00% in 2015
and remaining level thereafter.





The
expense and liability estimates can fluctuate by significant amounts based upon
the assumptions used. As of December 31, 2008, a one-percentage-point increase
in assumed healthcare cost trend rates would increase total service and interest
cost components and the postretirement benefit obligation by $410 and $1,793,
respectively. Conversely, a one-percentage-point decrease would reduce total
service and interest cost components and the postretirement benefit obligation
by $378 and $1,713, respectively.





Estimated
future benefit payments for the years indicated ending after December 31, 2008
are as follows:





2009
            
            
            $
            5232010
            
            
            
            9252011
            
            
            
            1,5802012
            
            
            
            2,1342013
            
            
            
            2,9342014
      – 2018
            
            
            
            25,652Total
            
            
            $
            33,748





The
Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the
“Act”) provides for a prescription drug benefit under Medicare (“Medicare Part
D”), as well as a federal subsidy to sponsors of retiree healthcare benefit
plans that provide a benefit that is at least actuarially equivalent to Medicare
Part D. The Company accounts for the subsidy as prescribed by FSP FAS
106-2,Accounting and
Disclosure Requirements related to the Medicare Prescription Drug, Improvement
and Modernization Act of 2003 (“FSP 106-2”). As of December 31,
2008, the Company determined the effects of the Act resulted in a $426 reduction
of its postretirement benefit obligation. The Act is expected to result in a
$113 reduction of the Company’s postretirement benefit cost for the year ended
December 31, 2009. The effect on the Company’s postretirement benefit cost
components includes reductions of $65, $27 and $21 to the service cost, interest
cost and amortization of accumulated postretirement benefit obligation,
respectively.





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 insured by a
combination of participation in a state run program and insurance policies. The
Company’s workers’ compensation liability is discounted at 5.50%.





F-26







INTERNATIONAL COAL GROUP, INC. AND
SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








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.





Black
lung benefit information for the years ended December 31, 2008 and 2007 is as
follows:





2008
            
            
            2007Changes
      in Benefit Obligations:Accumulated
      benefit obligations at beginning of period
            
            $
            17,758
            
            
            $
            17,598Service
      cost
            
            
            2,045
            
            
            
            2,799Interest
      cost
            
            
            1,611
            
            
            
            1,262Actuarial
      (gain) loss
            
            
            1,451
            
            
            
            (3,901
            )Benefits
      paid
            
            
            (41
            )
            
            
            —Accumulated
      benefit obligation at end of period
            
            
            22,824
            
            
            
            17,758Fair
      value of plan assets at end of period
            
            
            —
            
            
            
            —Net
      liability
            
            $
            22,824
            
            
            $
            17,758





The
changes in the actuarial gain that are included in accumulated other
comprehensive income were as follows:





2008
            
            
            2007Balance
      at beginning of year
            
            $
            (7,030
            )
            
            $
            (3,431
            )Actuarial
      (gain) loss
            
            
            1,451
            
            
            
            (3,901
            )Amortization
      of actuarial gain
            
            
            948
            
            
            
            302Balance
      at end of year
            
            $
            (4,631
            )
            
            $
            (7,030
            )





The
Company expects to recognize $390 of the net actuarial gain as a component of
the net periodic benefit cost during 2009. Components of net periodic benefit
cost for the years ended December 31, 2008, 2007 and 2006 are as
follows:





2008
            
            
            2007
            
            
            2006Net
      periodic benefit cost:Service
      cost
            
            $
            2,045
            
            
            $
            2,799
            
            
            $
            3,032Interest
      cost
            
            
            1,611
            
            
            
            1,262
            
            
            
            1,052Amortization
      of actuarial (gain) loss
            
            
            (948
            )
            
            
            (302
            )
            
            
            160Benefit
      cost
            
            $
            2,708
            
            
            $
            3,759
            
            
            $
            4,244








F-27







INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Estimated
future benefit payments for the years indicated ending after December 31, 2008
are as follows:





2009
            
            
            $
            2302010
            
            
            
            3962011
            
            
            
            4082012
            
            
            
            5702013
            
            
            
            9242014
      – 2018
            
            
            
            8,610Total
            
            
            $
            11,138





UMWA Combined
Benefit Fund (Coal Act)—The Coal Industry Retiree Health Benefit Act of
1992 (the “Coal Act”) provides for the funding of medical and death benefits for
certain retired members of the UMWA. It provides for the assignment of
beneficiaries to their former employers and any unassigned beneficiaries to
employers based on a formula. Based upon actuarially determined amounts for the
latest list of beneficiaries assigned to Anker, the Company estimates the amount
of its obligation under the Coal Act to be approximately $1,277 and $1,464 as of
December 31, 2008 and 2007, discounted at 6.25% and 6.00%, respectively. The
Company recorded interest expense related to the Coal Act of $80, $302 and $345
for the years ended December 31, 2008, 2007 and 2006, respectively.





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
$6,971, $4,293 and $5,182 for the years ended December 31, 2008, 2007 and 2006,
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
a 100% match of the first 3% of employee contributions and 50% of the next 2% of
employee contributions. The Company also contributes an additional 5%
non-elective contribution for every employee eligible to participate in the
program. The expense under this plan for the Company was $1,956, $1,776 and
$1,736 for the years ended December 31, 2008, 2007 and 2006,
respectively.





F-28





INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








13.
            EMPLOYEE
      STOCK AWARDS





The
Company’s 2005 Equity and Performance Incentive Plan (the “Plan”) permits the
granting of stock options, restricted shares, stock appreciation rights,
restricted share units, performance shares or performance units to its employees
for up to 8,000,000 shares of common stock. Option awards are generally granted
with an exercise price equal to the market price of the Company’s stock at the
date of grant and have 10-year contractual terms. The option and restricted
stock awards generally vest in equal annual installments of 25% over a four-year
period. The Company recognizes expense related to the awards on a straight-line
basis over the vesting period. The Company issues new shares upon the exercise
of option awards.





The
Black-Scholes option pricing model was used to calculate the estimated fair
value of the options granted. The estimated grant date fair value of the options
granted in 2008, 2007 and 2006 was calculated using the following
assumptions:





2008
            
            
            2007
            
            
            2006Expected
      term (in years)
            
            
            5
            
            
            
            5
            
            
            
            5Expected
      volatility
            
            
            43.0%
      - 48.2
            %
            
            
            43.0%
      - 48.1
            %
            
            
            48.1
            %Weighted-average
      volatility
            
            
            43.5
            %
            
            
            43.2
            %
            
            
            48.1
            %Risk-free
      rate
            
            
            1.7%
      - 3.7
            %
            
            
            4.0%
      - 5.1
            %
            
            
            4.6%
      - 5.2
            %Expected
      dividends
            
            
            —
            
            
            
            —
            
            
            
            —





The
Company estimated a forfeiture rate of 4.50%, 3.25% and 1.00% for 2008, 2007 and
2006, respectively.





Due
to the Company’s limited operating history, the expected lives and volatility
are estimated based on other companies in the coal industry. The risk-free
interest rates are based on the rates of zero coupon U.S. Treasury bonds with
similar maturities on the date of grant. The forfeiture rate was determined
based on estimates of future turnover of the Company’s employees eligible under
the plan.





Stock-based
employee compensation expense of $2,596, $3,134 and $3,501, net of tax of
$1,578, $2,090 and $2,167, related to the issuance of all stock awards
outstanding was included in earnings for the years ended December 31, 2008, 2007
and 2006, respectively.




F-29







INTERNATIONAL COAL GROUP, INC. AND
SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








A
summary of the Company’s outstanding options as of December 31, 2008, and
changes during the year ended December 31, 2008, is as follows:





Options
            
            Shares
            
            
            Weighted-
              Average
              Exercise
              Price
            
            
            Weighted-
              Average
              Remaining
              Contractual
              Term
              (years)
            
            
            Aggregate
              Intrinsic
              ValueOutstanding
      at January 1, 2008
            
            
            2,012,342
            
            
            $
            8.76Granted
            
            
            1,055,160
            
            
            
            6.35Exercised
            
            
            (17,700
            )
            
            
            8.39Forfeited
      and expired
            
            
            (218,610
            )
            
            
            8.44Outstanding
      at December 31, 2008
            
            
            2,831,192
            
            
            
            7.88
            
            
            
            7.9
            
            
            $
            (15,811
            )Vested or expected to vest at December
      31, 2008
            
            
            2,725,556
            
            
            
            7.93
            
            
            
            7.9
            
            
            $
            (15,338
            )Exercisable
      at December 31, 2008
            
            
            1,329,907
            
            
            
            9.28
            
            
            
            7.0
            
            
            $
            (9,280
            )





The
weighted-average grant-date fair value of options granted during the years ended
December 31, 2008, 2007 and 2006 was $2.64, $2.65 and $3.93, respectively. The
total intrinsic value of options exercised during the year ended December 31,
2008 was $47. There were no options exercised in 2007 or 2006.





A
summary of the status of the Company’s nonvested restricted stock awards as of
December 31, 2008 and changes during the year ended December 31, 2008 is as
follows:





Nonvested
      Shares
            
            Shares
            
            
            Weighted-
              Average Grant-Date
              Fair
      ValueNonvested
      at January 1, 2008
            
            
            574,190
            
            
            $
            9.15Granted
            
            
            349,194
            
            
            
            6.74Vested
            
            
            (323,020
            )
            
            
            10.40Forfeited
            
            
            (44,020
            )
            
            
            8.00Nonvested
      at December 31, 2008
            
            
            556,344
            
            
            
            7.00





The
weighted-average grant-date fair value of restricted stock granted during the
years ended December 31, 2008, 2007 and 2006 was $6.74, $5.87 and $8.50,
respectively. The total fair value of restricted stock vested during the years
ended December 31, 2008, 2007 and 2006 was $3,361, $3,221 and $2,933,
respectively.





As
of December 31, 2008, there was $6,237 of unrecognized compensation cost related
to non-vested stock-based awards that is expected to be recognized over a
weighted-average period of 2.6 years.





F-30







INTERNATIONAL COAL GROUP, INC. AND
SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








14.
            VARIABLE
      INTEREST ENTITIES





The
Company acquired a 50% interest in Sycamore Group, LLC (“Sycamore”) in
conjunction with its acquisition of Anker. Sycamore was established as a joint
venture with an unrelated third-party to mine coal from the Sycamore No. 1
mine. The reserve from Sycamore No. 1 was depleted and the mine closed
during the first quarter of 2007. The Company considers itself to be the primary
beneficiary of Sycamore, based on an evaluation of its involvement with Sycamore
and the provisions of FIN 46(R), and has consolidated the accounts of Sycamore
as of December 31, 2008 and 2007, as well as the results of operations for the
year ended December 31, 2008, 2007 and 2006. The creditors of Sycamore have no
recourse to the general credit of ICG. Amounts related to Sycamore that are
included in the consolidated financial statements of ICG as of and for the years
ending December 31, 2008, 2007 and 2006, are as follows:





2008
            
            
            2007
            
            
            2006Assets
            
            $
            213
            
            
            $
            257
            
            
            $
            3,342Liabilities
            
            
            138
            
            
            
            187
            
            
            
            1,097Revenue
            
            
            —
            
            
            
            1,808
            
            
            
            10,343Net
      income (loss)
            
            
            —
            
            
            
            (403
            )
            
            
            130





15.
            EARNINGS
      PER SHARE





Reconciliations
of the weighted-average shares used to compute basic and diluted earnings per
share for the years ended December 31, 2008, 2007 and 2006 are as
follows:





2008
            
            
            2007
            
            
            2006Net
      loss attributable to International Coal Group, Inc.
            
            $
            (26,227
            )
            
            $
            (147,562
            )
            
            $
            (9,320
            )Average
      common shares outstanding—Basic
            
            
            152,632,586
            
            
            
            152,304,461
            
            
            
            152,028,165Incremental
      shares arising from stock options
            
            
            —
            
            
            
            —
            
            
            
            —Incremental
      shares arising from restricted shares
            
            
            —
            
            
            
            —
            
            
            
            —Incremental
      shares arising from convertible notes
            
            
            —
            
            
            
            —
            
            
            
            —Average
      common shares outstanding—Diluted
            
            
            152,632,586
            
            
            
            152,304,461
            
            
            
            152,028,165Earnings
      Per Share:Basic
      and Diluted
            
            $
            (0.17
            )
            
            $
            (0.97
            )
            
            $
            (0.06
            )





Options
to purchase 2,831,192 shares of common stock and 556,344 shares of restricted
common stock outstanding at December 31, 2008 have been excluded from the
computation of diluted net loss per share for the year ended December 31, 2008
because their effect would have been anti-dilutive. Options to purchase
2,012,342 shares of common stock and 574,190 shares of restricted common stock
outstanding at December 31, 2007 have been excluded from the computation of
diluted net loss per share for the year ended December 31, 2007 because their
effect would have been anti-dilutive. Options to purchase 1,814,302 shares of
common stock and 787,540 shares of restricted common stock outstanding at
December 31, 2006 have been excluded from the computation of diluted net loss
per share for the year ended December 31, 2006 because their effect would have
been anti-dilutive.





In July 2007, the Company completed the offering of its Convertible Notes. The
principal amount of the Convertible Notes is payable in cash and amounts above
the principal amount, if any, will be convertible into shares of the Company’s
common stock or, at the Company’s option, cash. The volume weighted-average
price of the Company’s stock during the applicable measurement period was below
$6.10 per share. Accordingly, there were no potentially dilutive shares at
December 31, 2008.





F-31





INTERNATIONAL COAL GROUP, INC. AND
SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








16.
            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.





Coal Sales
Contracts—As of December 31, 2008, the Company had commitments under 49
sales contracts to deliver annually scheduled base quantities of coal to 34
customers. The contracts expire from 2009 through 2020 with the Company
contracted to supply a minimum of approximately 63.5 million tons of coal
over the remaining lives of the contracts (maximum of approximately
16.9 million tons in 2009).





Diesel Fuel
Purchase Contracts—As of December 31, 2008, the Company had commitments
to purchase $73,753 of diesel fuel during 2009. The Company did not have
material diesel fuel purchase contacts in place for the purchase of diesel fuel
during the years ended December 31, 2008, 2007 or 2006.





Coal Purchase
Contracts—As of December 31, 2008, the Company had commitments to
purchase coal to meet its sales commitments. Certain of the contracts have sales
price adjustment provisions, subject to certain limitations and adjustments,
based on a variety of factors and indices. The following is a summary of the
Company’s future contractual purchase obligations by year as of December 31,
2008:





Year
      ending December 31:2009
            
            $
            22,9262010
            
            
            14,377Total
            
            $
            37,303





The
Company incurred purchased coal expense of approximately $23,363, $13,892 and
$41,874 for the years ended December 31, 2008, 2007 and 2006 related to these
coal purchase contracts.





Leases—The
Company leases various mining, transportation and other equipment under
operating and capital leases. Lease expense for the years ended December 31,
2008, 2007 and 2006 was $4,970, $6,254 and $15,194, respectively. Property under
capital lease included in property, plant, equipment and mine development in the
consolidated balance sheet at December 31, 2008 was approximately $3,816,
less accumulated depreciation of approximately $0. There were no capital leases
at December 31, 2007. At December 31, 2008, the Company imputed interest on
its capital lease using a rate of 10% in order to reduce the net minimum lease
payments to present value. Depreciation expense related to assets under capital
leases is included in depreciation, depletion and amortization in the Company’s
consolidated statement of operations.





The
Company also leases coal lands and mineral rights under agreements that call for
royalties to be paid as the coal is mined. Total royalty expense for the years
ended December 31, 2008, 2007 and 2006 was approximately $52,232, $37,680 and
$38,458, 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.





F-32







INTERNATIONAL COAL GROUP, INC. AND
SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Non-cancelable
future minimum royalty and lease payments as of December 31, 2008 are as
follows:





Royalties
            
            
            Operating
      Leases
            
            
            Capital
      LeasesYear
      ended December 31,2009
            
            $
            10,111
            
            
            $
            87
            
            
            $
            1,7262010
            
            
            9,925
            
            
            
            63
            
            
            
            1,7262011
            
            
            9,715
            
            
            
            19
            
            
            
            8632012
            
            
            8,408
            
            
            
            —
            
            
            
            —2013
            
            
            8,228
            
            
            
            —
            
            
            
            —Thereafter
            
            
            37,004
            
            
            
            —
            
            
            
            —Total
      minimum lease payments
            
            $
            83,391
            
            
            $
            169
            
            
            $
            4,315Less—amount
      representing interest
            
            
            
            
            
            
            
            
            
            
            499Present
      value of minimum lease payments
            
            
            
            
            
            
            
            
            
            
            3,816Less—current
      portion
            
            
            
            
            
            
            
            
            
            
            1,430Total
      long-term portion of capital leases
            
            
            
            
            
            
            
            
            
            $
            2,386





Bonding Royalty
and Additional Payment—Lexington Coal Company, LLC (“LCC”) was organized
in part by the founding ICG stockholders in conjunction with the acquisition of
the former Horizon companies. LCC was organized to assume certain reclamation
liabilities and assets of Horizon not otherwise being acquired by ICG or others.
There was initially a limited commonality of ownership of LCC and ICG. In order
to provide support to LCC, ICG provided a $10,000 letter of credit to support
reclamation obligations (Bonding Royalty) and in addition agreed to pay a 0.75%
payment on the gross sales receipts for coal mined and sold by the former
Horizon companies that ICG acquired from Horizon until the completion by LCC of
all reclamation liabilities that LCC assumed from Horizon (“Additional
Payments”). The Company made payments totaling $4,457, $3,883 and $3,975 for the
years ended December 31, 2008, 2007 and 2006, respectively.





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. 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.





F-33







INTERNATIONAL COAL GROUP, INC. AND
SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Legal
Matters—On August 23, 2006, a survivor of the Sago mine accident,
Randal McCloy, filed a complaint in the Kanawha Circuit Court in Kanawha County,
West Virginia. The claims brought by Randal McCloy and his family against the
Company and certain of its subsidiaries, and against W.L. Ross & Co.,
and Wilbur L. Ross, Jr., individually, were dismissed on February 14, 2008,
after the parties reached a confidential settlement. Sixteen other complaints
have been filed in Kanawha Circuit Court by the representatives of many of the
miners who died in the Sago mine accident, and several of these plaintiffs have
filed amended complaints to expand the group of defendants in the cases. The
complaints allege various causes of action against the Company and its
subsidiary, Wolf Run Mining Company, one of the Company’s shareholders, W.L.
Ross & Co., and Wilbur L. Ross Jr., individually, related to the
accident and seek compensatory and punitive damages. In addition, the plaintiffs
also allege causes of action against other third parties, including claims
against the manufacturer of Omega block seals used to seal the area where the
explosion occurred and against the manufacturer of self-contained self-rescuer
(“SCSR”) devices worn by the miners at the Sago mine. Some of these third
parties have been dismissed from the actions upon settlement. The amended
complaints add other of the Company’s subsidiaries to the cases, including ICG,
Inc., ICG, LLC and Hunter Ridge Coal Company, unnamed parent, subsidiary and
affiliate companies of the Company, W.L. Ross & Co., and Wilbur L. Ross
Jr., and other third parties, including a provider of electrical services and a
supplier of components used in the SCSR devices. The Company believes that it is
appropriately insured for these and other potential claims, and it has fully
paid its deductible applicable to its insurance policies. In addition to the
dismissal of the McCloy claim, the Company has settled and dismissed five other
actions. These settlements required the release of the Company, the Company’s
subsidiaries, W. L. Ross & Co., and Wilbur L. Ross, Jr. Some of the
plaintiffs involved in one of the dismissed actions have sought permission from
the Supreme Court of Appeals of West Virginia to appeal the settlement, alleging
that the settlement negotiated by the decedent’s estate should not have been
approved by the trial court. The trial court overruled those plaintiffs’
objections to the settlement, and, although the West Virginia Supreme Court of
Appeals refused to stay the effectiveness of the settlement, the plaintiffs’
petition for appeal to the West Virginia Supreme Court of Appeals was recently
presented to the court. The court has not yet ruled whether it will accept the
petition for appeal or decline to hear the appeal. The Company will vigorously
defend itself against the remaining complaints and any appeal of any prior
settlements.





Allegheny
Energy Supply (“Allegheny”), the sole customer of coal produced at the Company’s
subsidiary Wolf Run Mining Company’s (“Wolf Run”) Sycamore No. 2 mine,
filed a lawsuit against Wolf Run, Hunter Ridge Holdings, Inc. (“Hunter Ridge”),
and the Company in state court in Allegheny County, Pennsylvania on
December 28, 2006, and amended its complaint on April 23, 2007.
Allegheny claims that the Company breached a coal supply contract when it
declared force majeure under the contract upon idling the Sycamore No. 2 in
the third quarter of 2006. The Sycamore No. 2 mine was idled after
encountering adverse geologic conditions and abandoned gas wells that were
previously unidentified and unmapped. The amended complaint also alleges that
the production stoppages constitute a breach of the guarantee agreement by
Hunter Ridge and breach of certain representations made upon entering into the
contract in early 2005, a claim that Allegheny has since voluntarily dropped.
Allegheny claims that it will incur costs in excess of $100,000 to purchase
replacement coal over the life of the contract. The Company, Wolf Run and Hunter
Ridge answered the amended complaint on August 13, 2007, disputing all of the
remaining claims. On November 3, 2008, the Company, Wolf Run and Hunter Ridge
filed an amended answer and counterclaim against the plaintiffs seeking to void
the coal supply agreement due to, among other things, fraudulent inducement and
conspiracy. The counterclaim alleges further that Allegheny breached a
confidentiality agreement with Hunter Ridge, which prohibited the solicitation
of its employees. After the coal supply agreement was executed, Allegheny hired
the then-president of Anker Coal Group, Inc. (now Hunter Ridge) who engaged in
negotiations on behalf of Wolf Run and Hunter Ridge. In addition to seeking a
declaratory judgment that the coal supply agreement and guaranty be deemed void
and unenforceable and rescission of the contracts, the counterclaim also seeks
compensatory and punitive damages.





F-34







INTERNATIONAL COAL GROUP, INC. AND
SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








On
December 6, 2007, the Kentucky Waterways Alliance, Inc., and The Sierra
Club sued the U.S. Army Corps of Engineers (the “ACOE”) in the United States
District Court for the Western District of Kentucky, Louisville Division (the
“Court”), asserting that a permit to construct five valley fills was issued
unlawfully to the Company’s Hazard subsidiary for its Thunder Ridge Surface
mine. The suit alleges that the ACOE failed to comply with the requirements of
both Section 404 of the Clean Water Act and the National Environmental
Policy Act. Hazard has intervened in the suit to protect the Company’s
interests. The ACOE suspended the Section 404 permit on December 26,
2007 in order to evaluate the issues raised by the plaintiffs. That evaluation
is now in progress. If the ACOE reinstates the permit and the Court subsequently
finds that the permit is unlawful, production could be materially affected at
the Thunder Ridge Surface mine and the process of obtaining ACOE permits for
coal mining activities in Kentucky could become more difficult.





On
January 7, 2008, Saratoga Advantage Trust filed a class action lawsuit in
the U.S. District Court for the Southern District of West Virginia against the
Company and certain of its officers and directors. The complaint asserts claims
under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and
Rule 10b-5 promulgated thereunder, based on alleged false and misleading
statements in the registration statements filed in connection with the Company’s
November 2005 reorganization and December 2005 public offering of common stock.
In addition, the complaint challenges other of the Company’s public statements
regarding the Company’s operating condition and safety record. The Company
intends to vigorously defend the action.





On
July 3, 2007, Taylor Environmental Advocacy Membership, Inc. (“T.E.A.M.”) filed
a petition to appeal the issuance of ICG Tygart Valley, LLC’s (“Tygart Valley”)
Surface Mine Permit U-2004-06 against the West Virginia Department of
Environmental Protection (the “WVDEP”) in an action before the West Virginia
Surface Mine Board (the “Board”). On December 10, 2007, the Board remanded the
permit to the WVDEP for revision to certain provisions related to pre-mining
water monitoring and cumulative hydrologic impacts. The WVDEP issued a
modification on April 1, 2008 addressing those issues. T.E.A.M. filed an appeal
of the WVDEP’s approval of the permit modification on April 30, 2008. On October
7, 2008, the Board issued an order remanding the permit to the WVDEP requiring
Tygart Valley to address a technical issue related to projected post-mining
water quality. Tygart Valley has prepared and submitted a permit modification to
alleviate the board’s concerns. All site development will be suspended until the
WVDEP has approved the permit modification. If the WVDEP issues the permit
as modified, there will be additional opportunity for appeal by
T.E.A.M.





From
time to time, the Company is involved in legal proceedings arising in the
ordinary course of business. These proceedings include assessments of penalties
for citations and orders asserted by the Mine Safety and Health Administration,
and other regulatory agencies none of which are expected by management to
individually or in the aggregate have a material adverse effect on the Company.
In the opinion of management, the Company has recorded adequate reserves for
liabilities arising in the ordinary course and it is management’s belief there
is no individual case or group of related cases pending that is likely to have a
material adverse effect on the financial condition, results of operations or
cash flows of the Company.





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.





F-35







INTERNATIONAL COAL GROUP, INC. AND
SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Performance
Bonds—The Company has outstanding surety bonds with third parties of
approximately $115,667 as of December 31, 2008 to secure reclamation and other
performance commitments. In addition, at December 31, 2008 the Company has
$73,551 of letters of credit outstanding under the revolving credit facility, a
portion of which $61,126 provides support to the third parties for their
issuance of surety bonds. In addition, the Company has posted cash collateral of
$1,589 and $1,563 to secure reclamation and other performance commitments as of
December 31, 2008 and 2007, respectively. This cash collateral is included in
other non-current assets on the consolidated balance sheets.





Contract Mining
Agreements—ICG’s subsidiary, ADDCAR, performs contract mining services
for various third parties and utilizes contract miners on some of its
operations. Terms of the agreements generally allow either party to terminate
the agreements on a short-term basis. The guaranteed monthly contract tonnage is
mutually agreed upon and failure to meet the guaranteed contract tonnage may
result in termination of the contract. Completion dates for work under these
contracts vary in dates ranging from 2009 to 2010.





17.
            CONCENTRATION
      OF CREDIT RISK AND MAJOR CUSTOMERS





The
Company markets its coal principally to electric utilities in the United States,
the majority of which have investment grade credit ratings. As of December 31,
2008 and 2007, trade accounts receivable from electric utilities totaled
approximately $49,059 and $57,029, respectively. The Company evaluates each
customer’s creditworthiness prior to entering into transactions and constantly
monitors the credit extended, but does not require its customers to provide
collateral. Credit losses are provided for in the consolidated financial
statements and historically have been minimal.





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





December
      31, 2008
              Total
      Receivable
              Balance
            
            
            Year
      Ended
              December
      31, 2008
              Total
      Revenues
            
            
            December
      31, 2007
              Total
      Receivable
              Balance
            
            
            Year
      Ended
              December
      31, 2007
              Total
      Revenues
            
            
            December
      31, 2006
              Total
      Receivable
              Balance
            
            
            Year
      Ended
              December
      31, 2006
              Total
      RevenuesCustomer
      A
            
            $
            —
            
            
            $
            —
            
            
            $
            2,886
            
            
            $
            97,389
            
            
            $
            4,893
            
            
            $
            135,025Customer
      B
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            6,397
            
            
            
            117,249Customer
      C
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            6,041
            
            
            
            94,935





Deposits
held with banks may exceed the amount of insurance provided on such deposits.
Generally, these deposits may be redeemed upon demand and are maintained with
financial institutions of reputable credit and, therefore, bear minimal
risk.





F-36





INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








18.
            FAIR
      VALUE OF FINANCIAL INSTRUMENTS





The
estimated fair values of the Company’s financial instruments are determined
based on relevant market information. These estimates involve uncertainty and
cannot be determined with precision. The following methods and assumptions were
used to estimate the fair value of each class of financial
instrument.





Effective
January 1, 2008, the Company adopted SFAS No. 157, which clarifies the
definition of fair value, establishes a framework for measuring fair value and
expands the disclosures on fair value measurements. SFAS No. 157 applies
whenever other statements require or permit assets or liabilities to be measured
at fair value. SFAS No. 157 requirements for certain non-financial assets
and liabilities have been deferred until the first quarter of 2009 in accordance
with FASB Staff Position 157-2,Effective Date of FASB Statement
No. 157. SFAS No. 157 establishes the following fair value
hierarchy that prioritizes the inputs used to measure fair value:





•
            Level
      1 –
            Unadjusted
      quoted prices for identical assets or liabilities in active
      markets.•
            Level
      2 –
            Inputs
      other than Level 1 that are based on observable market data, either
      directly or indirectly. These include quoted prices for similar assets or
      liabilities in active markets, quoted prices for identical assets or
      liabilities in inactive markets, inputs that are observable that are not
      prices and inputs that are derived from or corroborated by observable
      markets.•
            Level
      3 –
            Developed
      from unobservable data, reflecting an entity’s own
      assumptions.





The
Company entered into an Interest Rate Collar Agreement (the “Collar”) that
expires on March 31, 2009. The interest rate collar was designed as a cash
flow hedge to offset the impact of changes in the LIBOR interest rate above
5.92% and below 4.80%. At December 31, 2008, a liability for the fair value of
the Collar was included in accrued expenses and other on the Company’s
consolidated balance sheet. The value of the interest rate collar is based on a
forward LIBOR curve, which is observable at commonly quoted intervals for the
full term of the agreement. The Company recognizes the change in the fair value
of this agreement in the period of change. For the years ended December 31,
2008, 2007 and 2006, the Company recorded losses of $1,993, $1,649 and $939
respectively, related to the change in fair value. The losses are included in
interest expense in the Company’s consolidated statement of
operations.





F-37







INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








The
following table presents the fair value hierarchy for financial liabilities
measured at fair value on a recurring basis:





Fair Value Measurements Using:Description
            
            December
      31,
              2008
            
            
            Quoted Prices
              in
      Active
              Markets
      for
              Identical
              Assets
              (Level 1)
            
            
            Significant
              Other
              Observable
              Inputs
              (Level 2)
            
            
            Significant
              Unobservable
              Inputs
              (Level 3)Interest
      Rate Collar Agreement
            
            $
            1,665
            
            
            $
            —
            
            
            $
            1,665
            
            
            $
            —





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—At December 31, 2008 and 2007, the Company had $225,000
aggregate principal amount of its 9.0% Convertible Notes outstanding. The fair
value of the Convertible Notes was approximately $114,683 and $266,445 as of
December 31, 2008 and 2007, respectively. At December 31, 2008 and
2007, the Company had $175,000 aggregate principal amount of its 10.25% Senior
Notes outstanding. The fair value of the Senior Notes was approximately $131,250
and $167,125 as of December 31, 2008 and 2007, respectively.





The
carrying value of the Company’s capital lease obligations and other debt
approximate fair value at December 31, 2008 and 2007.





19.
            RELATED
      PARTY TRANSACTIONS AND BALANCES





Under
an Advisory Services Agreement dated as of October 1, 2004 between the
Company and WLR, WLR has agreed to provide advisory services to the Company
(consisting of consulting and advisory services in connection with strategic and
financial planning, investment management and administration and other matters
relating to the business and operation of the Company of a type customarily
provided by sponsors of U.S. private equity firms to companies in which they
have substantial investments, including any consulting or advisory services
which the Board of Directors reasonably requests). WLR is paid a quarterly fee
of $500 and reimbursed for any reasonable out-of-pocket expenses (including
expenses of third-party advisors retained by WLR). The agreement is for a period
of seven years; however, it may be terminated upon the occurrence of certain
events.





The
Company has paid legal fees relating to the representation of WLR and the
Company’s Chairman, Mr. Wilbur L. Ross, Jr., by counsel in connection
with various litigation matters pending against the Company, WLR and
Mr. Wilbur L. Ross, Jr. related to the Sago mine accident. The Company
did not record any expense in 2008 relating to these matters. During the year
ended December 31, 2007 the Company recorded expenses totaling approximately
$739 relating to these matters.





F-38







INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








20.
            SEGMENT
      INFORMATION





The
Company extracts, processes and markets steam and metallurgical coal from deep
and surface mines for sale to electric utilities and industrial customers,
primarily in the eastern United States. The Company operates only in the United
States with mines in the Central Appalachian, Northern Appalachian and
Illinois Basin regions. The Company has three reportable business segments:
Central Appalachian, Northern Appalachian and Illinois Basin. The Company’s
Central Appalachian operations are located in southern West Virginia, eastern
Kentucky and western Virginia and include eight mining complexes. The Company’s
Northern Appalachian operations are located in northern West Virginia and
Maryland and include four mining complexes. The Company’s Illinois Basin
operations include one mining complex. The Company also has an Ancillary
category, which includes the Company’s brokered coal functions, corporate
overhead, contract highwall mining services and land activities.





Reportable
segment results for continuing operations for the year ended December 31, 2008
and segment assets as of December 31, 2008 were as follows:





Central
              Appalachian
            
            
            Northern
              Appalachian
            
            
            Illinois
              Basin
            
            
            Ancillary
            
            
            ConsolidatedRevenue
            
            $
            702,958
            
            
            $
            230,660
            
            
            $
            79,682
            
            
            $
            83,436
            
            
            $
            1,096,736Adjusted
      EBITDA
            
            
            107,186
            
            
            
            23,687
            
            
            
            14,784
            
            
            
            (18,436
            )
            
            
            127,221Depreciation,
      depletion and amortization
            
            
            64,132
            
            
            
            17,884
            
            
            
            7,342
            
            
            
            6,689
            
            
            
            96,047Impairment
      losses
            
            
            —
            
            
            
            7,191
            
            
            
            —
            
            
            
            30,237
            
            
            
            37,428Capital
      expenditures
            
            
            112,617
            
            
            
            41,760
            
            
            
            7,148
            
            
            
            11,070
            
            
            
            172,595Total
      assets
            
            
            751,986
            
            
            
            184,846
            
            
            
            40,850
            
            
            
            372,965
            
            
            
            1,350,647





Revenue
in the Ancillary category consists primarily of $46,720 relating to the
Company’s brokered coal sales and $19,862 relating to contract highwall mining
activities. Capital expenditures include non-cash amounts of $53,650 for the
year ended December 31, 2008. Capital expenditures do not include $14,290 paid
during the year ended December 31, 2008 related to capital expenditures
accrued in prior periods.





Reportable
segment results for continuing operations for the year ended December 31, 2007
and segment assets as of December 31, 2007 were as follows:





Central
              Appalachian
            
            
            Northern
              Appalachian
            
            
            Illinois
              Basin
            
            
            Ancillary
            
            
            ConsolidatedRevenue
            
            $
            530,255
            
            
            $
            133,284
            
            
            $
            68,440
            
            
            $
            117,176
            
            
            $
            849,155Adjusted
      EBITDA
            
            
            47,442
            
            
            
            (22,215
            )
            
            
            15,463
            
            
            
            18,363
            
            
            
            59,053Depreciation,
      depletion and amortization
            
            
            60,015
            
            
            
            9,467
            
            
            
            6,527
            
            
            
            10,508
            
            
            
            86,517Impairment
      losses
            
            
            170,402
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            170,402Capital
      expenditures
            
            
            129,353
            
            
            
            37,940
            
            
            
            2,639
            
            
            
            11,695
            
            
            
            181,627Total
      assets
            
            
            653,620
            
            
            
            161,350
            
            
            
            37,861
            
            
            
            450,532
            
            
            
            1,303,363Goodwill
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            30,237
            
            
            
            30,237





Revenue
in the Ancillary category consists primarily of $76,802 relating to the
Company’s brokered coal sales and $18,994 relating to contract highwall mining
activities. Capital expenditures include non-cash amounts of
$11,518.





F-39








INTERNATIONAL COAL GROUP, INC. AND
SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Reportable
segment results for continuing operations for the year ending December 31, 2006
and segment assets as of December 31, 2006 were as follows:





Central
              Appalachian
            
            
            Northern
              Appalachian
            
            
            Illinois
              Basin
            
            
            Ancillary
            
            
            ConsolidatedRevenue
            
            $
            541,844
            
            
            $
            122,041
            
            
            $
            56,606
            
            
            $
            171,103
            
            
            $
            891,594Adjusted
      EBITDA
            
            
            108,598
            
            
            
            (36,586
            )
            
            
            4,476
            
            
            
            (4,456
            )
            
            
            72,032Depreciation,
      depletion and amortization
            
            
            48,050
            
            
            
            10,822
            
            
            
            6,287
            
            
            
            7,059
            
            
            
            72,218Capital
      expenditures
            
            
            95,033
            
            
            
            73,173
            
            
            
            7,950
            
            
            
            20,822
            
            
            
            196,978Total
      assets
            
            
            752,200
            
            
            
            147,285
            
            
            
            41,103
            
            
            
            376,303
            
            
            
            1,316,891Goodwill
            
            
            167,105
            
            
            
            —
            
            
            
            —
            
            
            
            29,652
            
            
            
            196,757





Revenue
in the Ancillary category consists primarily of $141,919 relating to the
Company’s brokered coal sales and $25,249 relating to contract highwall mining
activities. Capital expenditures include non-cash amounts of
$31,320.





Adjusted
EBITDA represents net income before deducting interest expense, income taxes,
depreciation, depletion, amortization, impairment charges and noncontrolling
interest. Adjusted 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 loss to Adjusted EBITDA is as follows:





Year
      Ended December 31,2008
            
            
            2007
            
            
            2006Net
      loss attributable to International Coal Group, Inc.
            
            $
            (26,227
            )
            
            $
            (147,562
            )
            
            $
            (9,320
            )Depreciation,
      depletion and amortization
            
            
            96,047
            
            
            
            86,517
            
            
            
            72,218Interest
      expense, net
            
            
            43,643
            
            
            
            35,989
            
            
            
            18,091Income
      tax benefit
            
            
            (23,670
            )
            
            
            (85,944
            )
            
            
            (9,015
            )Impairment
      loss
            
            
            37,428
            
            
            
            170,402
            
            
            
            —Noncontrolling
      interest
            
            
            —
            
            
            
            (349
            )
            
            
            58Adjusted
      EBITDA
            
            $
            127,221
            
            
            $
            59,053
            
            
            $
            72,032






21.
            SUPPLEMENTARY
      GUARANTOR INFORMATION





International
Coal Group, Inc. (the “Parent Company”) issued $175,000 of Senior Notes due 2014
(the “Notes”) in June 2006 and $225,000 of Convertible Senior Notes due 2012
(the “Convertible Notes”) in July 2007. The Parent Company has no independent
assets or operations other than those related to the issuance, administration
and repayment of the Notes and the Convertible Notes. All subsidiaries of the
Parent Company (the “Guarantors”), except for a minor non-guarantor joint
venture, have fully and unconditionally guaranteed the Notes and the Convertible
Notes on a joint and several basis. The Guarantors are 100% owned, directly or
indirectly, by the Parent Company. Accordingly, condensed consolidating
financial information for the Parent Company and the Guarantors are not
presented.





F-40










INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








The
Notes and the Convertible Notes are senior obligations of the Parent Company and
are guaranteed on a senior basis by the Guarantors and rank senior in right of
payment to the Parent Company’s and Guarantors’ future subordinated
indebtedness. Amounts borrowed under the Amended Credit Facility are secured by
substantially all of the assets of the Parent Company and the Guarantors on a
priority basis, so the Notes and Convertible Notes are effectively subordinated
to amounts borrowed under the Amended Credit Facility. Other than for corporate
related purposes or interest payments required by the Notes or Convertible
Notes, the Amended Credit Facility restricts the Guarantors’ abilities to make
loans or pay dividends to the Parent Company in excess of $25,000 per year (or
at all upon an event of default) and restricts the ability of the Parent Company
to pay dividends. Therefore, all but $25,000 of the subsidiaries’ assets are
restricted assets.





The
Parent Company and Guarantors are subject to certain covenants under the
indenture for the Notes. Under these covenants, the Parent Company and
Guarantors are subject to limitations on the incurrence of additional
indebtedness, payment of dividends and the incurrence of liens, however, the
indenture contains no restrictions on the ability of the Guarantors to pay
dividends or make payments to the Parent Company.





The
obligations of the Guarantors are limited to the maximum amount permitted under
bankruptcy law, the Uniform Fraudulent Conveyance Act, the Uniform Fraudulent
Transfer Act or any similar Federal or state law respecting fraudulent
conveyance or fraudulent transfer.





22.
            QUARTERLY
      DATA





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





2008Three months
              ended
              March 31
            
            
            Three months
              ended
              June 30
            
            
            Three months
              ended
              September 30
            
            
            Three months
              ended
              December 31Revenue
            
            $
            251,925
            
            
            $
            277,885
            
            
            $
            309,199
            
            
            $
            257,727Income
      (loss) from operations
            
            
            (7,369
            )
            
            
            30,461
            
            
            
            20,726
            
            
            
            (50,072
            )Net
      income (loss) attributable to International Coal Group,
    Inc.
            
            
            (11,913
            )
            
            
            13,770
            
            
            
            9,324
            
            
            
            (37,408
            )(1)Basic
      earnings per common share
            
            $
            (0.08
            )
            
            $
            0.09
            
            
            $
            0.06
            
            
            $
            (0.24
            )Diluted
      earnings per common share
            
            $
            (0.08
            )
            
            $
            0.08
            
            
            $
            0.06
            
            
            $
            (0.24
            )





2007Three months
              ended
              March 31
            
            
            Three months
              ended
              June 30
            
            
            Three months
              ended
              September 30
            
            Three months
              ended
              December 31Revenue
            
            $
            228,314
            
            
            $
            208,050
            
            
            $
            207,829
            
            $
            204,962Income
      (loss) from operations
            
            
            (8,815
            )
            
            
            (10,850
            )
            
            
            10,230
            
            
            (188,750
            )Net
      loss attributable to International Coal Group, Inc.
            
            
            (8,068
            )
            
            
            (10,234
            )
            
            
            (1,513
            )(1)
            
            (127,747
            )(1)Basic
      earnings per common share
            
            $
            (0.05
            )
            
            $
            (0.07
            )
            
            $
            (0.01
            )
            $
            (0.84
            )Diluted
      earnings per common share
            
            $
            (0.05
            )
            
            $
            (0.07
            )
            
            $
            (0.01
            )
            $
            (0.84
            )





(1)
              Net
      loss attributable to International Coal Group, Inc. for the three months
      ended December 31, 2008, September 30, 2007 and December 31, 2007
      increased $458, $230 and $298, respectively, due to the Company’s
      retrospective adoption of FSP APB 14-1. See Note 23.





F-41





INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Included
in the three months ended December 31, 2008 and 2007 are impairment losses of
$37,428 and $170,402, respectively. For 2008, $30,237 of the loss related to
impairment of goodwill at the Company’s ADDCAR subsidiary and $7,191 related to
impairment of long-lived assets. For 2007, the impairment loss related to
impairment of goodwill at various of the Company’s business units. See Notes 4
and 5 to the Company’s consolidated financial statements for further discussion
of the impairment losses.





23.
            RESTATEMENT
      OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS AND EFFECT OF ADOPTION OF
      ACCOUNTING PRONOUNCEMENTS





Subsequent
to the issuance of its consolidated financial statements for the year ended
December 31, 2008, the Company identified an error in the application of SFAS
No. 158 on its employee benefits liability. The Company had not previously
recorded the unfunded status of its black lung obligation as a liability in its
statement of financial position or recognized changes in the funded status of
the obligation in the year in which the changes occurred through comprehensive
income. This error resulted in an overstatement of the employee benefits
liability and accumulated other comprehensive loss and an understatement of the
deferred tax liability as of December 31, 2008 and 2007. Additionally,
comprehensive loss was understated by $1,493 for the year ended December 31,
2008 and overstated by $2,254 for the year ended December 31, 2007. The Company
does not believe these errors are material to the consolidated financial
statements.





Additionally,
effective January 1, 2009, the Company adopted FSP APB 14-1. FSP APB 14-1
requires the liability and equity components of convertible debt instruments
that may be settled in cash upon conversion to be separately accounted for in a
manner that reflects the issuer’s nonconvertible debt borrowing rate. To
allocate the proceeds from a convertible debt offering in this manner, a company
would first need to determine the carrying amount of the liability component,
which would be based on the fair value of a similar liability, excluding any
embedded conversion options. The resulting debt discount would be amortized over
the period during which the debt is expected to be outstanding as additional
non-cash interest expense. The Company retrospectively adjusted its consolidated
financial statements for the years ended December 31, 2008 and 2007 to reflect
the adoption of FSP APB 14-1. The Company has determined its non-convertible
borrowing rate would have been 11.7% at issuance of its convertible
debt.





The
effect of correcting for the application of SFAS No. 158 and the adoption of FSP
APB 14-1 was as follows:





Consolidated
      Balance Sheets
            
            As
              Originally
              Filed
            
            
            Correction
      for Application of SFAS No. 158
            
            
            Adjustment
      for Adoption of FSP APB 14-1
            
            
            As
      RestatedDecember
      31, 2008Property,
      plant, equipment and mine development
            
            $
            1,068,146
            
            
            $
            —
            
            
            $
            1,151
            
            
            $
            1,069,297Debt
      issuance costs, net
            
            
            10,635
            
            
            
            —
            
            
            
            (173
            )
            
            
            10,462Total
      assets
            
            
            1,349,669
            
            
            
            —
            
            
            
            978
            
            
            
            1,350,647Long-term
      debt and capital lease
            
            
            434,920
            
            
            
            —
            
            
            
            (17,369
            )
            
            
            417,551Employee
      benefits
            
            
            61,194
            
            
            
            (4,631
            )
            
            
            —
            
            
            
            56,563Deferred
      tax liability
            
            
            42,468
            
            
            
            1,751
            
            
            
            6,935
            
            
            
            51,154Total
      liabilities
            
            
            854,844
            
            
            
            (2,880
            )
            
            
            (10,434
            )
            
            
            841,530Additional
      paid-in capital
            
            
            643,480
            
            
            
            —
            
            
            
            13,517
            
            
            
            656,997Accumulated
      other comprehensive loss
            
            
            (5,157
            )
            
            
            2,880
            
            
            
            —
            
            
            
            (2,277
            )Retained
      deficit
            
            
            (145,066
            )
            
            
            —
            
            
            
            (2,105
            )
            
            
            (147,171
            )Total
      International Coal Group, Inc. stockholders’ equity
            
            
            494,790
            
            
            
            2,880
            
            
            
            11,412
            
            
            
            509,082Total
      liabilities and stockholders’ equity
            
            
            1,349,669
            
            
            
            —
            
            
            
            978
            
            
            
            1,350,647





F-42





INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Consolidated
      Balance Sheets
            
            As
              Originally
              Filed
            
            
            Correction
      for Application of SFAS No. 158
            
            
            Adjustment
      for Adoption of FSP APB 14-1
            
            
            As
      RestatedDecember
      31, 2007Property,
      plant, equipment and mine development
            
            $
            974,334
            
            
            $
            —
            
            
            $
            376
            
            
            $
            974,710Debt
      issuance costs, net
            
            
            13,466
            
            
            
            —
            
            
            
            (576
            )
            
            
            12,890Total
      assets
            
            
            1,303,563
            
            
            
            —
            
            
            
            (200
            )
            
            
            1,303,363Long-term
      debt and capital lease
            
            
            408,096
            
            
            
            —
            
            
            
            (21,082
            )
            
            
            387,014Employee
      benefits
            
            
            55,132
            
            
            
            (7,030
            )
            
            
            —
            
            
            
            48,102Deferred
      tax liability
            
            
            52,355
            
            
            
            2,657
            
            
            
            7,893
            
            
            
            62,905Total
      liabilities
            
            
            789,157
            
            
            
            (4,373
            )
            
            
            (13,189
            )
            
            
            771,595Additional
      paid-in capital
            
            
            639,160
            
            
            
            —
            
            
            
            13,517
            
            
            
            652,677Accumulated
      other comprehensive loss
            
            
            (5,903
            )
            
            
            4,373
            
            
            
            —
            
            
            
            (1,530
            )Retained
      deficit
            
            
            (120,416
            )
            
            
            —
            
            
            
            (528
            )
            
            
            (120,944
            )Total
      International Coal Group, Inc. stockholders’ equity
            
            
            514,371
            
            
            
            4,373
            
            
            
            12,989
            
            
            
            531,733Total
      liabilities and stockholders’ equity
            
            $
            1,303,563
            
            
            $
            —
            
            
            $
            (200
            )
            
            $
            1,303,363








Consolidated
      Statements of Operations
            
            As
              Originally
              Filed
            
            
            Correction
      for Application of SFAS No. 158
            
            
            Adjustment
      for Adoption of FSP APB 14-1
            
            
            As
      RestatedYear
      Ended December 31, 2008Interest expense,
      net
            
            $
            (41,107
            )
            
            $
            —
            
            
            $
            (2,536
            )
            
            $
            (43,643
            )Income
      tax benefit
            
            
            22,711
            
            
            
            —
            
            
            
            959
            
            
            
            23,670Net
      loss attributable to International Coal Group, Inc.
            
            
            (24,650
            )
            
            
            —
            
            
            
            (1,577
            )
            
            
            (26,227
            )Earnings
      per share:Basic
      and diluted
            
            $
            (0.16
            )
            
            $
            —
            
            
            $
            (0.01
            )
            
            $
            (0.17
            )Year
      Ended December 31, 2007Interest expense,
      net
            
            $
            (35,140
            )
            
            $
            —
            
            
            $
            (849
            )
            
            $
            (35,989
            )Income
      tax benefit
            
            
            85,623
            
            
            
            —
            
            
            
            321
            
            
            
            85,944Net
      loss attributable to International Coal Group, Inc.
            
            
            (147,034
            )
            
            
            —
            
            
            
            (528
            )
            
            
            (147,562
            )Earnings
      per share:Basic
      and diluted
            
            $
            (0.97
            )
            
            $
            —
            
            
            $
            —
            
            
            $
            (0.97
            )





F-43





INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


For
the years ended December 31, 2008, 2007 and 2006


(Dollars
in thousands, except per share amounts)








Consolidated
      Statements of Cash Flows
            
            As
              Originally
              Filed
            
            Correction
      for Application of SFAS No. 158
            
            
            Adjustment
      for Adoption of FSP APB 14-1
            
            
            As
      RestatedYear
      Ended December 31, 2008Net loss
            
            $
            (24,650
            )
            $
            —
            
            
            $
            (1,577
            )
            
            $
            (26,227
            )Amortization
      of finance costs and debt discount included in interest
      expense
            
            
            2,831
            
            
            —
            
            
            
            3,310
            
            
            
            6,141Amortization
      of accumulated postretirement benefit obligation
            
            
            430
            
            
            (948
            )
            
            
            —
            
            
            
            (518
            )Deferred
      income taxes
            
            
            (23,477
            )
            
            —
            
            
            
            (957
            )
            
            
            (24,434
            )Other
      liabilities
            
            
            5,886
            
            
            948
            
            
            
            —
            
            
            
            6,834Additions
      to property, plant, equipment and mine development
            
            
            (131,421
            )
            
            —
            
            
            
            (776
            )
            
            
            (132,197
            )Year
      Ended December 31, 2007Net loss
            
            $
            (147,383
            )(1)
            $
            —
            
            
            $
            (528
            )
            
            $
            (147,911
            )Amortization
      of finance costs and debt discount included in interest
      expense
            
            
            8,291
            
            
            —
            
            
            
            1,225
            
            
            
            9,516Amortization
      of accumulated postretirement benefit obligation
            
            
            283
            
            
            (302
            )
            
            
            —
            
            
            
            (19
            )Deferred
      income taxes
            
            
            (87,078
            )
            
            —
            
            
            
            (321
            )
            
            
            (87,399
            )Other
      liabilities
            
            
            5,200
            
            
            302
            
            
            
            —
            
            
            
            5,502Additions
      to property, plant, equipment and mine development
            
            
            (160,431
            )
            
            —
            
            
            
            (376
            )
            
            
            (160,807
            )





(1)  Amount reflects an immaterial adjustment of $349 related to the
Company’s retrospective adoption of SFAS No. 160.





Effective
January 1, 2009, the Company adopted SFAS No. 160. SFAS No. 160
establishes new accounting and reporting standards for the noncontrolling
interest in a subsidiary and for the deconsolidation of a subsidiary. It
clarifies that a noncontrolling interest in a subsidiary (minority interest) is
an ownership interest in the consolidated entity that should be reported as
equity in the consolidated financial statements and separate from the parent
company’s equity. Among other requirements, this statement requires consolidated
net income to be reported at amounts that include the amounts attributable to
both the parent and the noncontrolling interest. It also requires disclosure, on
the face of the consolidated statement of operations, of the amounts of
consolidated net income attributable to the parent and to the noncontrolling
interest. The Company retrospectively adjusted its consolidated financial
statements for the years ended December 31, 2008, 2007 and 2006 to reflect the
adoption of SFAS No. 160. Adoption impacted the presentation of the
noncontrolling interest in the Company’s consolidated balance sheets and
consolidated statements of operations and cash flows. The impact of the changes
in presentation was not material.





F-44








Schedule
I—Condensed Financial Information of the Registrant





International
Coal Group, Inc.





Parent
Company Balance Sheets


(Dollars
in thousands, except per share amounts)





December
      31,
              2008(1)
            
            
            December 31,
              2007(1)ASSETSDEBT
      ISSUANCE COSTS, net
            
            $
            8,851
            
            
            $
            10,630DEFERRED
      INCOME TAXES
            
            
            18,806
            
            
            
            2,589INVESTMENT
      IN SUBSIDIARIES
            
            
            877,885
            
            
            
            909,847Total
      assets
            
            $
            905,542
            
            
            $
            923,066LIABILITIES
      AND STOCKHOLDERS’ EQUITYCURRENT
      LIABILITIES:Accrued
      expenses and other
            
            $
            16,709
            
            
            $
            16,788Total
      current liabilities
            
            
            16,709
            
            
            
            16,788LONG-TERM
      DEBT AND CAPITAL LEASES
            
            
            382,631
            
            
            
            378,918Total
      liabilities
            
            
            399,340
            
            
            
            395,706COMMITMENTS
      AND CONTINGENCIES
            
            
            —
            
            
            
            —STOCKHOLDERS’
      EQUITY:Preferred
      stock – par value $0.01, 200,000,000 shares authorized, none
      issued
            
            
            —
            
            
            
            —Common
      stock – par value $0.01, 2,000,000,000 shares authorized, 153,322,245 and
      152,992,109 shares, respectively, issued and
    outstanding
            
            
            1,533
            
            
            
            1,530Additional
      paid-in capital
            
            
            656,997
            
            
            
            652,677Accumulated
      other comprehensive loss
            
            
            (5,157
            )
            
            
            (5,903
            )Retained
      deficit
            
            
            (147,171
            )
            
            
            (120,944
            )Total
      stockholders’ equity
            
            
            506,202
            
            
            
            527,360Total
      liabilities and stockholders’ equity
            
            $
            905,542
            
            
            $
            923,066





(1)  Amounts
have been adjusted due to the Company’s retrospective adoption of FSP APB 14-1.
See Note 23 accompanying the Company’s consolidated financial statements
included elsewhere in this Annual Report on Form 10-K/A.





F-45











International
Coal Group, Inc.





Parent
Company Statements of Operations


(Dollars
in thousands, except per share amounts)





Year
      Ended December 31,2008(1)
            
            
            2007(1)
            
            
            2006(1)INCOME
      FROM OPERATIONS
            
            $
            —
            
            
            $
            —
            
            
            $
            —INTEREST
      AND OTHER INCOME (EXPENSE):Interest
      expense, net
            
            
            (42,905
            )
            
            
            (28,579
            )
            
            
            (9,684
            )Loss
      before income taxes
            
            
            (42,905
            )
            
            
            (28,579
            )
            
            
            (9,684
            )INCOME
      TAX (EXPENSE) BENEFIT
            
            
            16,218
            
            
            
            10,803
            
            
            
            3,702EQUITY
      IN NET INCOME (LOSS) OF SUBSIDIARIES
            
            
            460
            
            
            
            (129,786
            )
            
            
            (3,338
            )Net
      loss
            
            $
            (26,227
            )
            
            $
            (147,562
            )
            
            $
            (9,320
            )Earnings
      per share:Basic
      and diluted
            
            $
            (0.17
            )
            
            $
            (0.97
            )
            
            $
            (0.06
            )Weighted-average
      common shares outstanding:Basic
      and diluted
            
            
            152,632,586
            
            
            
            152,304,461
            
            
            
            152,028,165





(1)  Amounts
have been adjusted due to the Company’s retrospective adoption of FSP APB 14-1.
See Note 23 accompanying the Company’s consolidated financial statements
included elsewhere in this Annual Report on Form 10-K/A.





F-46





International
Coal Group, Inc.





Parent
Company Statements of Cash Flows


(Dollars
in thousands)








Year
      Ended December 31,2008(1)
            
            
            2007(1)
            
            
            2006(1)NET
      CASH FROM OPERATING ACTIVITIES
            
            $
            (38,266
            )
            
            $
            (19,036
            )
            
            $
            —CASH
      FLOWS FROM INVESTING ACTIVITIES:Investment
      in subsidiaries
            
            
            38,266
            
            
            
            (198,121
            )
            
            
            (170,047
            )Net
      cash from investing activities
            
            
            38,266
            
            
            
            (198,121
            )
            
            
            (170,047
            )CASH
      FLOWS FROM FINANCING ACTIVITIES:Proceeds
      from senior notes offering
            
            
            —
            
            
            
            —
            
            
            
            175,000Proceeds
      from convertible notes offering
            
            
            —
            
            
            
            225,000Debt
      issuance costs
            
            
            —
            
            
            
            (7,843
            )
            
            
            (4,953
            )Net
      cash from financing activities
            
            
            —
            
            
            
            217,157
            
            
            
            170,047NET
      CHANGE IN CASH AND CASH EQUIVALENTS
            
            
            —
            
            
            
            —
            
            
            
            —CASH
      AND CASH EQUIVALENTS, BEGINNING OF PERIOD
            
            
            —
            
            
            
            —
            
            
            
            —CASH
      AND CASH EQUIVALENTS, END OF PERIOD
            
            $
            —
            
            
            $
            —
            
            
            $
            —





(1)  Amounts
have been adjusted due to the Company’s retrospective adoption of FSP APB 14-1.
See Note 23 accompanying the Company’s consolidated financial statements
included elsewhere in this Annual Report on Form 10-K/A.





F-47








LONG-TERM
      DEBT





As
of December 31, 2008 and 2007, long-term debt consisted of the following (in
thousands):





2008
            
            
            20079.00%
      Convertible Senior Notes, due 2012, net of debt discount of $17,369and $21,082,
      respectively
            
            $
            207,631
            
            
            $
            203,91810.25%
      Senior Notes, due 2014
            
            
            175,000
            
            
            
            175,000Long-term
      debt
            
            $
            382,631
            
            
            $
            378,918








Convertible
senior notes—In 2007, the Company completed a private offering of
$225,000 aggregate principal amount of 9.00% Convertible Senior Notes (the
“Convertible Notes”) due 2012. The Convertible Notes are the Company’s senior
unsecured obligations and are guaranteed on a senior unsecured basis by the
Company’s material future and current domestic subsidiaries. The Convertible
Notes and the related guarantees rank equal in right of payment to all of the
Company’s and the guarantors’ respective existing and future unsecured senior
indebtedness. Interest is payable semi-annually in arrears on February 1
and August 1 of each year.





Senior
notes—In 2006, the Company sold $175,000 aggregate principal amount of
the Company’s 10.25% Senior Notes (the “Notes”) due July 15, 2014. Interest
on the Notes is payable semi-annually in arrears on July 15 and
January 15 of each year. The Notes are senior unsecured obligations and are
guaranteed on a senior unsecured basis by all of the Company’s current and
future domestic subsidiaries that are material or that guarantee the Company’s
amended and restated credit facility.





The
indenture governing the Notes contains covenants that limit the Company’s
ability to, among other things, incur additional indebtedness, issue preferred
stock, pay dividends, repurchase, repay or redeem the Company’s capital stock,
make certain investments, sell assets and incur liens. As of December 31,
2008, the Company was in compliance with its covenants under the
indenture.





See
Note 9 to the consolidated financial statements included elsewhere in the Annual
Report on Form 10-K/A for further discussion of the Convertible Notes and
Notes.





Future
maturities of long-term debt are as follows as of December 31, 2008 (in
thousands):





Year
      ending December 31:2009
            
            $
            —2010
            
            
            —2011
            
            
            —2012
            
            
            225,0002013
            
            
            —Thereafter
            
            
            175,000Total
            
            
            400,000Less
      debt discount
            
            
            (17,369
            )Total
            
            $
            382,631








F-48





Schedule
II—Valuation and Qualifying Accounts





Description
            
            Balance at
              Beginning
              of
      Period
            
            
            Charged to
              Revenue,
              Costs
      or
              Expenses
            
            
            Other
              Additions
              (Deductions)
            
            
            Balance at
              End
      of
              Period(in
      thousands)Year
      ended December 31, 2008Allowance
      for doubtful accounts
            
            $
            539
            
            
            $
            994
            
            
            $
            (17
            )
            
            $
            1,516Reserve
      for inventory obsolescence
            
            
            778
            
            
            
            1,029
            
            
            
            —
            
            
            
            1,807Reserve
      for loss—advance royalties
            
            
            3,771
            
            
            
            630
            
            
            
            (492
            )
            
            
            3,909Year
      ended December 31, 2007Allowance
      for doubtful accounts
            
            $
            36
            
            
            $
            503
            
            
            $
            —
            
            
            $
            539Reserve
      for inventory obsolescence
            
            
            576
            
            
            
            (82
            )
            
            
            284
            
            
            
            778Reserve
      for loss—advance royalties
            
            
            638
            
            
            
            3,414
            
            
            
            (281
            )
            
            
            3,771Year
      ended December 31, 2006Allowance
      for doubtful accounts
            
            $
            —
            
            
            $
            36
            
            
            $
            —
            
            
            $
            36Reserve
      for inventory obsolescence
            
            
            311
            
            
            
            265
            
            
            
            —
            
            
            
            576Reserve
      for loss—advance royalties
            
            
            —
            
            
            
            (412
            )
            
            
            1,050
            
            
            
            638








F-49










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.





INTERNATIONAL
      COAL GROUP, INC.By:
            /s/
      Bennett K. HatfieldBennett
      K. Hatfield
              President
      and Chief Executive Officer


Date:
December 18, 2009























Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and the
capabilities and on the dates indicated.





Signature
            
            Title
            
            Date/s/
      Bennett K. Hatfield
            
            President,
      Chief Executive Officer and Director
            
            December
      18, 2009Bennett
      K. Hatfield
            
            (Principal
      Executive Officer)/s/
      Bradley W. Harris
            
            Senior
      Vice President and Chief Financial Officer
            
            December
      18, 2009Bradley
      W. Harris
            
            (Principal
      Accounting and Principal Financial Officer)*
            
            Non-Executive
      Chairman and Director
            
            December
      18, 2009Wilbur L. Ross,
      Jr.*
            
            Director
            
            December
      18, 2009Maurice
      E. Carino, Jr.*
            
            Director
            
            December
      18, 2009Cynthia
      B. Bezik*
            
            Director
            
            December
      18, 2009William
      J. Catacosinos*
            
            Director
            
            December
      18, 2009Stanley
      N. Gaines*
            
            Director
            
            December
      18, 2009Samuel
      A. Mitchell*
            
            Director
            
            December
      18, 2009Wendy
      L. Teramoto





*
            The
      undersigned, by signing his name hereto, does sign and execute this Annual
      Report on Form 10-K/A 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. HatfieldBennett
      K. Hatfield, Attorney-in-Fact

















EXHIBIT
INDEX





Exhibit No.
            
            Description
            
            Note2.1
            
            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
            
            (C
            )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
            
            (C
            )3.1
            
            Form
      of Second Amended and Restated Certificate of Incorporation of
      International Coal Group, Inc.
            
            (E
            )3.2
            
            Form
      of Second Amended and Restated By-laws of International Coal Group,
      Inc.
            
            (F
            )4.1
            
            Form
      of certificate of International Coal Group, Inc. common
    stock
            
            (D
            )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
            
            (C
            )4.4
            
            Indenture,
      dated June 23, 2006, by and among ICG, the guarantors party thereto and
      The Bank of New York Trust Company, N.A., as trustee relating to
      International Coal Group, Inc.’s 10.25% senior notes
            
            (H
            )4.5
            
            Form
      of 10.25% senior note (included in Exhibit 4.1)
            
            (H
            )4.6
            
            Form
      of guarantee relating to International Coal Group, Inc.’s 10.25% senior
      notes (included in Exhibit 4.1)
            
            (H
            )4.7
            
            Indenture,
      dated as of July 31, 2007, among International Coal Group, Inc., and the
      guarantors party thereto and The Bank of New York Trust Company, N.A. as
      Trustee, relating to International Coal Group, Inc.’s 9.00% Convertible
      Notes.
            
            (J
            )4.8
            
            Form
      of 9.00% Senior Convertible Note (included in Exhibit 4.7)
            
            (J
            )4.9
            
            Form
      of Guarantee relating to International Coal Group, Inc.’s 9.00%
      Convertible Notes
            
            (J
            )4.10
            
            Registration
      Rights Agreement, dated as of July 31, 2007, among International Coal
      Group, Inc., and the guarantors party thereto and UBS Securities LLC as
      purchaser.
            
            (J
            )10.1
            
            Second
      Amended and Restated Credit Agreement, dated June 23, 2006, by and among
      ICG, LLC, as borrower, the guarantors party thereto, the lenders party
      thereto, J.P. Morgan Securities Inc. and UBS Securities LLC, as joint lead
      arrangers and joint bookrunners, JPMorgan Chase Bank, N.A. and CIT Capital
      Securities LLC, as co-syndication agents, Bank of America, N.A. and
      Wachovia Bank, N.A. as co-documentation agents, JPMorgan Chase Bank, N.A.
      and Bank of America, N.A. as issuing banks, UBS Loan Finance LLC, as
      swingline lender, and UBS AG, Stamford Branch, as an issuing bank,
      administrative agent and collateral agent
            
            (H
            )














Exhibit No.
            
            Description
            
            Note10.2
            
            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
            )10.3
            
            Advisory
      Services Agreement effective as of October 1, 2004 between International
      Coal Group, LLC and W.L. Ross & Co. LLC
            
            (A
            )10.4
            
            Employment
      Agreement dated March 14, 2005 by and between Bennett K. Hatfield and
      International Coal Group, Inc.
            
            (A
            )10.5
            
            Employment
      Agreement dated April 25, 2005 by and between Roger L. Nicholson and
      International Coal Group, Inc.
            
            (B
            )10.6
            
            International
      Coal Group, Inc. 2005 Equity and Performance Incentive
Plan
            
            (D
            )10.7
            
            International
      Coal Group, Inc. 2005 Equity and Performance Incentive Plan: Incentive
      Stock Option Agreement
            
            (D
            )10.8
            
            International
      Coal Group, Inc. 2005 Equity and Performance Incentive Plan: Non-Qualified
      Stock Option Agreement
            
            (D
            )10.9
            
            International
      Coal Group, Inc. 2005 Equity and Performance Incentive Plan: Restricted
      Share Agreement
            
            (D
            )10.10
            
            Form
      of Indemnification Agreement
            
            (D
            )10.11
            
            Fee
      Lease between Kentucky Union Company, lessor, and ICG Hazard, LLC
      (assigned from Leslie Resources, Inc.), lessee, of Flint Ridge Surface
      Mine, amended by:
            
            (C
            )(a) Assignment
      of Real Property Agreements, dated September 30, 2004, assigning to
      ICG Hazard, LLC10.14
            
            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:
            
            (C
            )(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, LLC10.15
            
            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:
            
            (C
            )(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, LLC10.17
            
            Fee
      Lease between M-B, LLC, lessor, and ICG Eastern, LLC (assigned from ANR
      Coal Development Company), lessee, of Birch River Mine, amended
      by:
            
            (C
            )(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, LLC10.18
            
            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:
            
            (C
            )(a) Assignment
      of Real Property Agreements, dated September 30, 2004, assigning to
      ICG Hazard, LLC













Exhibit No.
            
            Description
            
            Note10.19
            
            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:
            
            (C
            )(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, LLC10.20
            
            Lease
      between Allegany Coal and Land Company, lessor, and Patriot Mining
      Company, Inc., lessee, of Allegany County, Maryland Mine,
      including:
            
            (C
            )(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, 200210.21
            
            Lease
      between The Crab Orchard Coal and Land Company, lessor, and Wolf Run
      Mining Company (f/k/a Anker West Virginia Mining Company), ICG Beckley,
      LLC (successor-in-interest to Winding Gulf Coals, Inc.), lessee, of
      Beckley Mine, including:
            
            (C
            )(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, 199410.22
            
            Lease
      between Beaver Coal Corporation, lessor, and Wolf Run Mining Company
      (f/k/a Anker West Virginia Mining Company), ICG Beckley, LLC
      (successor-in-interest to New River Company), lessee, of Beckley Mine,
      including:
            
            (C
            )(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, 199510.23
            
            Lease
      between Douglas Coal Company, lessor, and Vindex Energy Corp. (assigned
      from Patriot Mining Company, Inc.), lessee, of Island and Douglas Mine,
      including:
            
            (C
            )(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, 2006












Exhibit No.
              
              Description
              
              Note10.25
              
              Sublease
      between Reserve Coal Properties, sublessors, and Patriot Mining Company,
      sublessee, of Sycamore No. 2 Mine
              
              (C
              )10.27
              
              Contract
      for Sale and Purchase of Coal dated July 1, 1980, between City of
      Springfield, Illinois and, ICG Illinois, LLC (assigned from Turis Coal
      Company), amended by:
              
              (B
              )(a) Amendment
      dated March 4, 1986, effective January 1, 1986(b) Second
      Amendment dated April 22, 1986, effective January 1, 1986(c) Modification
      dated and effective June 8, 1987(d) Modification
      dated and effective November 4, 1988(e) Amendment
      dated and effective January 1, 1989(f) Amendment
      dated March 20, 1992, effective January 1, 1992(g) Amendment
      dated March 21, 1995, effective January 1, 1995(h) Amendment
      dated May 10, 1996, effective May 1, 1996(i) Amendment
      dated August 20, 1998, effective January 1, 1998(j) Amendment
      dated May 30, 2001, effective January 1, 2001(k) Letter
      dated October 8, 2004 assigning to ICG Illinois, LLC10.28‡
              
              Coal
      Supply Agreement, dated as of April 1, 1992, between Hunter Ridge
      Coal Company (f/k/a Anker Energy Corporation) and Logan Generating Company
      (formerly Keystone Energy Service Company, L.P.), amended
    by:
              
              (G
              )(a) First
      Amendment, effective as of September 1, 1995(b) Second
      Amendment, effective as of March 15, 2002(c) Third
      Amendment, effective as of October 31, 2004(d) Coal
      Price Adjustment Agreement, effective as of October 31,
    200410.29‡
              
              Coal
      Sales Agreement, dated as of February 17, 2006, between Wolf Run
      Mining Company (f/k/a Anker West Virginia Mining Company, Inc.) and
      Allegheny Energy Supply Company, LLC and Monongahela Power
      Company
              
              (G
              )10.30
              
              Amendment
      No. 1 to the Second Amended and Restated Credit Agreement, dated as of
      January 31, 2007, among ICG, LLC, as borrower, International Coal Group,
      Inc. and certain of its subsidiaries as guarantors, the lenders party
      thereto, J.P. Morgan Chase Securities Inc. and UBS Securities LLC, as
      joint lead arrangers and joint bookrunners, JPMorgan Chase Bank, N.A. and
      CIT Capital USA Inc., as co-syndication agents, Bank of America, N.A. and
      Wachovia Bank, N.A., as co-documentation agents, JPMorgan Chase Bank and
      Bank of America, N.A., as issuing banks, UBS Loan Finance LLC, as
      swingline lender, and UBS AG, Stamford Branch, as issuing bank, as
      administrative agent and as collateral agent for the
    lenders
              
              (I
              )












Exhibit No.
            
            Description
            
            Note10.31
            
            Amendment
      No. 3 to the Second Amended and Restated Credit Agreement, dated as of
      February 20, 2009, among ICG, LLC, as borrower, International Coal Group,
      Inc. and certain of its subsidiaries as guarantors, the lenders party
      thereto, J.P. Morgan Chase Securities Inc. and UBS Securities LLC, as
      joint lead arrangers and joint bookrunners, JPMorgan Chase Bank, N.A. and
      CIT Capital USA Inc., as co-syndication agents, Bank of America, N.A. and
      Wachovia Bank, N.A., as co-documentation agents, JPMorgan Chase Bank and
      Bank of America, N.A., as issuing banks, UBS Loan Finance LLC, as
      swingline lender, and UBS AG, Stamford Branch, as issuing bank, as
      administrative agent and as collateral agent for the
    lenders
            
            (N
            )10.32
            
            International
      Coal Group, Inc. Executive Severance Plan
            
            (I
            )10.33
            
            International
      Coal Group Inc. Director Compensation Plan
            
            (I
            )10.34‡
            
            Coal
      Lease Agreement Between Tygart Resources, Inc. and Pittsburgh Ligionier,
      Inc., Lessors and Rocking Chair Energy Company, LLC, Lessees, including
      (a) Assignment and Consent Agreement dated March 28, 2007 by and
      between Tygart Resources, Inc. and Pittsburgh Ligionier, Inc, Rocking
      Chair Energy Company, LLC, and Wolf Run Mining Company (b) Amendment
      No. 1 to Lease Agreement made effective as of April 1, 2007 by and between
      Tygart Resources, Inc. and Pittsburgh Ligionier, Inc., Lessors and Rocking
      Chair Energy Company, LLC and Wolf Run Mining Company (c) Corporate
      Guaranty of International Coal Group, Inc. dated as of April 1,
      2007
            
            (I
            )10.35‡
            
            Lease
      and Sublease Agreement between Penn Virginia Operating Co., LLC, lessor,
      and ICG Knott County, LLC (assigned from Greymont Mining Corp.), lessee,
      as amended by First Amendment to Lease and Sublease Agreement, dated
      November 11, 2005 and letter agreement dated February 12,
      2007.
            
            (L
            )10.36‡
            
            Coal
      Facility Lease and Operating Agreement, dated July 7, 2005, between
      Loadout LLC, lessor, and ICG Knott County, LLC (assigned from Elk Ridge,
      Inc.), lessee, as amended by First Amendment to Coal Facility Lease and
      Operating Agreement, dated November 11, 2005.
            
            (L
            )10.37
            
            International
      Coal Group, Inc. Director Compensation Plan (as amended
    2007)
            
            (K
            )10.38
            
            Second
      Amendment and Limited Waiver to the Second Amended and Restated Credit
      Agreement, dated as of July 31, 2007, among ICG, LLC, as borrower,
      International Coal Group, Inc. and certain of its subsidiaries as
      guarantors, the lenders party thereto, J.P. Morgan Chase Securities Inc.
      and UBS Securities LLC, as joint lead arrangers and joint bookrunners,
      JPMorgan Chase Bank, N.A. and CIT Capital USA Inc., as co-syndication
      agents, Bank of America, N.A. and Wachovia Bank, N.A., as co-documentation
      agents, JPMorgan Chase Bank and Bank of America, N.A. as issuing banks,
      UBS Loan Finance LLC, as swingline lender, and UBS AG, Stamford Branch, as
      issuing bank, as administrative agent and as collateral agent for the
      lenders
            
            (J
            )10.39‡
            
            Amended
      and Restated Coal Lease dated as of May 27, 2008 by and between Dulcet
      Acquisition LLC, as lessor, and Powdul Acquisition LLC, as
      lessee
            
            (M
            )10.40
            
            Form
      of Non-Employee Director Restricted Share Unit Agreement
            
            (O
            )11.1
            
            Statement
      regarding Computation of Earnings Per Share
            
            (P
            )21.1
            
            List
      of Subsidiaries
            
            (O
            )23.1
            
            Consent
      of Deloitte & Touche, LLP
            
            (P
            )24.1
            
            Power
      of attorney, dated February 27, 2009
            
            (O
            )31.1
            
            Certification
      of the Chief Executive Officer
            
            (P
            )31.2
            
            Certification
      of the Principal Financial Officer
            
            (P
            )32.1
            
            Certification
      Pursuant to § 906 of the Sarbanes-Oxley Act of 2002
            
            (P
            )














(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 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.(D)
            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.(E)
            Previously
      filed as an exhibit to Amendment No. 4 to International Coal Group,
      Inc.’s Registration Statement on Form S-1 (Reg. No. 333-124393),
      filed on October 24, 2005 and incorporated herein by
      reference.(F)
            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 and incorporated herein by
      reference.(G)
            Previously
      filed as an exhibit to Amendment No. 6 to International Coal Group,
      Inc.’s Registration Statement on Form S-1 (Reg. No. 333-124393),
      filed on November 14, 2005 and incorporated herein by
      reference.(H)
            Previously
      filed as an exhibit to International Coal Group, Inc.’s Current Report on
      Form 8-K, filed on June 26, 2006 and incorporated herein by
      reference.(I)
            Previously
      filed as an exhibit to International Coal Group, Inc.’s Annual Report on
      Form 10-K for the year ended December 31, 2006, filed on
      March 1, 2007, and incorporated herein by
  reference.(J)
            Previously
      filed as an exhibit to International Coal Group, Inc.’s Current Report on
      Form 8-K, filed on July 31, 2007, and incorporated herein by
      reference.(K)
            Previously
      filed as an exhibit to International Coal Group, Inc.’s Quarterly Report
      on Form 10-Q for the quarter ended March 31, 2007, filed on
      May 8, 2007, and incorporated herein by reference.(L)
            Previously
      filed as an exhibit to International Coal Group, Inc.’s Annual Report on
      Form 10-K for the year ended December 31, 2007, filed on February 29, 2008
      and incorporated herein by reference.(M)
            Previously
      filed as an exhibit to International Coal Group Inc.’s Quarterly Report on
      Form 10-Q for the quarter ended June 30, 2008, filed on August 8, 2008,
      and incorporated herein by reference.(N)
            Previously
      filed as an exhibit to International Coal Group Inc.’s Current Report on
      Form 8-K, filed on February 23, 2009, and incorporated herein by
      reference.(O)
            Previously
      filed as an exhibit to International Coal Group, Inc.’s Annual Report on
      Form 10-K, filed on February 27, 2009 and incorporated herein by
      reference.(P)
            Filed
      herewith.‡
            Confidential
      treatment requested as to certain portions that have been omitted and
      filed separately with the Securities and Exchange
    Commission.