UNITED
STATES
 SECURITIES
AND EXCHANGE COMMISSION
 Washington,
DC 20549
 
 FORM
10-K
 (Mark
One)
 x
              ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
      1934
 
 For
the fiscal year ended December 31, 2009
 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   ̈    No  x
 
 Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Exchange Act.  Yes   ̈    No  x
 
 Indicate
by check mark whether the registrant: (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.  Yes  x      No   ̈
 
 Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.      Yes  x      No   ̈
 
 Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, 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   ̈    Accelerated
filer  x     Non-accelerated
filer   ̈    Smaller
reporting company   ̈
 
 Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act).  Yes   ̈    No  x
 
 Aggregate
market value of common stock held by non-affiliates of the registrant as of
June 30, 2009, the last business day of the registrant’s most recently
completed second fiscal quarter, at a closing price of $2.86 per share as
reported by the New York Stock Exchange, was $262,328,609. 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 January 20, 2010 was
179,014,632.
 
 DOCUMENTS
INCORPORATED BY REFERENCE
 
 Part
III incorporates certain information by reference from the registrant’s
definitive proxy statement for the 2010 annual meeting of stockholders, which
proxy statement will be filed on or about April 1, 2010.
  
  INDEX
TO ANNUAL REPORT
 ON
FORM 10-K
 
 Table of Contents
 
 Item 1.
              
              BUSINESS
              
              1Item 1A.
              
              RISK FACTORS
              
              31Item 1B.
              
              UNRESOLVED STAFF COMMENTS
              
              54Item 2.
              
              PROPERTIES
              
              54Item 3.
              
              LEGAL PROCEEDINGS
              
              60Item 4.
              
              SUBMISSION OF MATTERS TO A VOTE OF SECURITY
      HOLDERS
              
              60Item 5.
              
              MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
      MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
              
              61Item 6.
              
              SELECTED FINANCIAL DATA
              
              63Item 7.
              
              MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
      AND RESULTS OF OPERATIONS
              
              65Item 7A.
              
              QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK
              
              92Item 8.
              
              FINANCIAL STATEMENTS AND SUPPLEMENTARY
    DATA
              
              92Item 9.
              
              CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
      AND FINANCIAL DISCLOSURE
              
              92Item 9A.
              
              CONTROLS AND PROCEDURES
              
              92Item 9B.
              
              OTHER INFORMATION
              
              95Item 10.*
              
              DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
      GOVERNANCE
              
              95Item 11.*
              
              EXECUTIVE COMPENSATION
              
              95Item 12.*
              
              SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
      MANAGEMENT AND RELATED STOCKHOLDER MATTERS
              
              95Item 13.*
              
              CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
      DIRECTOR INDEPENDENCE
              
              95Item 14.*
              
              PRINCIPAL ACCOUNTANT FEES AND SERVICE
              
              95Item 15.
              
              EXHIBITS, FINANCIAL STATEMENT SCHEDULES
              
              96
 
 
 *
              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 1, 2010.
 
 i
  
  SPECIAL
NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
 Statements
in this Annual Report on Form 10-K that are not historical facts are
forward-looking statements within the “safe harbor” provision of the Private
Securities Litigation Reform Act of 1995 and may involve a number of risks and
uncertainties. We have used the words “anticipate,” “believe,” “could,”
“estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project” and similar
terms and phrases, including references to assumptions, in this report to
identify forward-looking statements. These forward-looking statements are made
based on expectations and beliefs concerning future events affecting us and are
subject to various risks, uncertainties and factors relating to our operations
and business environment, all of which are difficult to predict and many of
which are beyond our control, that could cause our actual results to differ
materially from those matters expressed in or implied by these forward-looking
statements. The following factors are among those that may cause actual results
to differ materially from our forward-looking statements:
 
 •
              market
      demand for coal, electricity and steel;•
              availability
      of qualified workers;•
              future
      economic or capital market conditions;•
              weather
      conditions or catastrophic weather-related damage;•
              our
      production capabilities;•
              consummation
      of financing, acquisition or disposition transactions and the effect
      thereof on our business;•
              a
      significant number of conversions of our Convertible Senior Notes prior to
      maturity;•
              our
      plans and objectives for future operations and expansion or
      consolidation;•
              our
      relationships with, and other conditions affecting, our
      customers;•
              availability
      and costs of key supplies or commodities such as diesel fuel, steel,
      explosives and tires;•
              availability
      and costs of capital equipment;•
              prices
      of fuels which compete with or impact coal usage, such as oil and natural
      gas;•
              timing
      of reductions or increases in customer coal
inventories;•
              long-term
      coal supply arrangements;•
              reductions
      and/or deferrals of purchases by major customers;•
              risks
      in or related to coal mining operations, including risks relating to
      third-party suppliers and carriers operating at our mines or
      complexes;•
              unexpected
      maintenance and equipment failure;•
              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
  Table of contents
 
 •
              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 and climate change;•
              impairment
      of the value of our long-lived and deferred tax assets;•
              our
      liquidity, including our ability to adhere to financial covenants related
      to our borrowing arrangements;•
              adequacy
      and sufficiency of our internal controls; and•
              legal
      and administrative proceedings, settlements, investigations and claims and
      the availability of related insurance
coverage.
 
 You
should keep in mind that any forward-looking statements made by us in this
Annual Report on Form 10-K or elsewhere speaks only as of the date on which the
statements were made. New risks and uncertainties arise from
time to time, and it is impossible for us to predict these events or
how they may affect us or anticipated results. We have no duty to, and do not
intend to, update or revise the forward-looking statements in this report after
the date of this report, except as may be required by law. In light of these
risks and uncertainties, you should keep in mind that any forward-looking
statement made in this report might not occur.
 
 iii
  Table of contents
  PART
I
 
 Introduction
 
 This
report is both our 2009 annual report to stockholders and our 2009 Annual Report
on Form 10-K required under the federal securities laws.
 
 Unless
the context otherwise indicates, as used in this annual report, the terms “ICG,”
“we,” “our,” “us” and similar terms refer to International Coal Group, Inc. and
its consolidated subsidiaries.
 
 The
term “coal reserves” as used in this report means proven and probable reserves
that are the part of a mineral deposit that can be economically and legally
extracted or produced at the time of the reserve determination and the term
“non-reserve coal deposits” in this report means a coal bearing body that has
been sufficiently sampled and analyzed to assume continuity between sample
points, but does not qualify as a commercially viable coal reserve as prescribed
by SEC rules until a final comprehensive SEC-prescribed evaluation is
performed.
 
 Because
certain terms used in the coal industry may be unfamiliar to many investors, we
have provided a “Glossary of Selected Terms” at the end of
Item 1.
 
 ITEM 1.
              BUSINESS
 
 Overview
 
 We
are a leading producer of coal in Northern and Central Appalachia with a broad
range of mid- to high-Btu, low- to medium-sulfur steam and metallurgical coal.
Our 12 Appalachian mining complexes are located in West Virginia, Kentucky,
Virginia and Maryland. We also have a complementary mining complex of mid- to
high-sulfur steam coal strategically located in the Illinois Basin. We
market our coal to a diverse customer base of largely investment grade electric
utilities, as well as domestic and international industrial customers. The high
quality of our coal and the availability of multiple transportation options,
including rail, truck and barge, throughout the Appalachian region enable us to
participate in both the domestic and international coal markets. Coal markets,
particularly Appalachian coal markets, have exhibited significant price
volatility in 2008 and 2009 and may continue to do so due to a number of
factors, including regulatory and other actions delaying the issuance of
necessary permits, general economic conditions and customer usage of
coal.
 
 As
of December 31, 2009, management estimates that we owned or controlled
approximately 325 million tons of metallurgical quality coal reserves and
approximately 765 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 431
million tons of non-reserve coal deposits. Our assets are high quality reserves
strategically located in Appalachia and the Illinois Basin and are operated
union free.
 
 For
the year ended December 31, 2009, we sold 16.8 million tons of coal, of which
approximately 16.0 million tons were produced from our mining activities and
approximately 0.8 million tons were purchased through brokered coal contracts
(coal purchased from third parties for resale), at an average sale price of
$60.16 and $52.62, respectively. Of the tons sold, 15.8 million tons were steam
coal and 1.0 million tons were metallurgical coal. Our steam coal sales volume
in 2009 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, 2009 were Progress Energy, Georgia
Power and Santee Cooper and we derived approximately 36% of our revenues from
sales to our five largest customers. We did not derive more than 10% of our
revenues from any single customer in 2009.
 
 1
  Table of contents
 
 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, 2009, 2008 and 2007 is included in Note 20
to our consolidated financial statements included elsewhere in this Annual
Report on Form 10-K.
 
 The
Coal Industry
 
 A
major contributor to the world energy supply, coal represents over 27% of the
world’s primary energy consumption according to the World Coal Institute. The
primary use for coal is to fuel electric power generation. In 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
mining methods: room-and-pillar or longwall. In 2009, approximately 47% of our
produced and processed coal volume came from underground mining operations using
the room-and-pillar method with continuous mining equipment.
 
 2
  Table of contents
 
 Room-and-Pillar
Mining
 
 In
room-and-pillar mining, rooms are cut into the coal seam leaving a series of
pillars, or columns of coal, to help support the mine roof and control the flow
of air. Continuous mining equipment is used to cut the coal from the mining
face. Generally, openings are driven 20 feet wide and the pillars are
rectangular in shape measuring 35-50 feet wide by 35-80 feet long. As mining
advances, a grid-like pattern of entries and pillars is formed. Shuttle cars are
used to transport coal to the conveyor belt for transport to the surface. When
mining advances to the end of a panel, retreat mining may begin. In retreat
mining, as much coal as is feasible is mined from the pillars that were created
in advancing the panel, allowing the roof to cave. When retreat mining is
completed to the mouth of the panel, the mined panel is abandoned. The
room-and-pillar method is often used to mine smaller coal blocks or thinner
seams. It is also employed whenever subsidence is prohibited. Seam recovery
ranges from 35% to 70%, with higher seam recovery rates applicable where retreat
mining is combined with room-and-pillar mining.
 
 Longwall
Mining
 
 The
other underground mining method commonly used in the United States is longwall
mining. We do not currently have any longwall mining operations, but we expect
to use this mining method in the development of our Tygart 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 2009, approximately
53% of our produced and processed coal volume came from surface mines. This
method involves the removal of overburden (earth and rock covering the coal)
with heavy earth moving equipment and explosives, extraction of the coal,
replacing the overburden and topsoil after the coal has been excavated,
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 two 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.
 
 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.
 
 3
  Table of contents
  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.
 
 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.
 
 4
  Table of contents
 
 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 2030, more than 114 gigawatts
of existing coal-fired capacity will have installed scrubbers. Additional
scrubbing will provide new market opportunities for our medium to high sulfur
coal. All new coal-fired electric utility generation plants built in the United
States will use clean coal-burning technology.
 
 Other
Characteristics
 
 Ash
is the inorganic residue remaining after the combustion of coal. As with sulfur
content, ash content varies from coal seam to coal seam. Ash content is an
important characteristic of coal because it increases transportation costs and
electric generating plants must handle and dispose of ash following
combustion.
 
 Moisture
content of coal varies by the type of coal, the region where it is mined and the
location of coal within a seam. In general, high moisture content decreases the
heat value per pound of coal, thereby increasing the delivered cost per Btu.
Moisture content in coal, as sold, can range from approximately 5% to 30% of the
coal’s weight.
 
 Operations
 
 As
of December 31, 2009, we operated a total of 11 surface and 11 underground coal
mines located in Kentucky, Maryland, Virginia, West Virginia and Illinois.
Approximately 53% of our 2009 production came from surface mines, and the
remaining 47% of our production came 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 22 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. 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.
 
 5
  Table of contents
 
 The
following table provides summary information regarding our principal active
operations as of December 31, 2009:
 
 Type
      and Number of MinesMining Complexes
              
              Location
              
              Preparation
                Plants
              
              
              Under-
                ground
              
              Surface
              
              Total
              
              Mining
                Method
      (1)
              
              Transportation
              
              Tons
                Produced
      in
                2009(in thousands)Eastern
              
              Cowen,
      WV
              
              1
              
              
              —
              
              1
              
              1
              
              MTR, TSL
              
              Rail
              
              2,500.7Hazard
              
              Hazard,
      KY
              
              —
              
              
              —
              
              4
              
              4
              
              CTR,
      MTR,
                TSL
              
              Rail,
      Truck
              
              3,669.6Flint
      Ridge
              
              Hazard,
      KY
              
              1
              
              
              1
              
              —
              
              1
              
              R&P
              
              Rail,
      Truck
              
              800.8Knott County
              
              Kite,
      KY
              
              1
              
              
              2
              
              —
              
              2
              
              R&P
              
              Rail
              
              518.1Raven
              
              Raven,
      KY
              
              1
              
              
              2
              
              —
              
              2
              
              R&P
              
              Rail
              
              728.5East
      Kentucky
              
              Pike
      Co., KY
              
              —
              
              
              —
              
              2
              
              2
              
              CTR,
      MTR, TSL
              
              Rail
              
              933.0Beckley
              
              Eccles,
      WV
              
              1
              
              
              1
              
              —
              
              1
              
              R&P
              
              Rail
              
              750.5Vindex
      Energy Corporation
              
              Garrett
      Co., MD
              
              1
              
              
              —
              
              3
              
              3
              
              CRM, TSL
              
              Truck, Rail
              
              740.1Patriot
      Mining Company
              
              Monongalia Co., WV
              
              —
              
              
              —
              
              1
              
              1
              
              CTR,
      TSL
              
              Barge, Rail, Truck
              
              744.9Wolf
      Run Mining Buckhannon Division
              
              Upshur Co., WV
              
              1
              
              
              2
              
              —
              
              2
              
              R&P
              
              Rail,
      Truck
              
              1,042.4Powell Mountain
              
              St.
      Charles, VA
              
              1
              
              
              1
              
              —
              
              1
              
              R&P
              
              Rail
              
              203.1Sentinel
              
              Barbour
      Co., WV
              
              1
              
              
              1
              
              —
              
              1
              
              R&P
              
              Rail,
      Truck
              
              1,367.5Illinois
              
              Williamsville,
      IL
              
              1
              
              
              1
              
              —
              
              1
              
              R&P
              
              Truck
              
              2,252.0
 
  (1)
              CRM
      = Cross Ridge Mining; CTR = Contour Mining; R&P = Room-and-pillar; MTR
      = Mountain Top Removal; HW = Highwall; TSL = Truck and
      Shovel/Loader.
 
 6
  Table of contents
  The
following table provides the last three years annual production and the average
prices received for our coal for each of our mining complexes:
 
 2009
              
              2008
              
              2007Mining
      Complexes
              
              Tons
                Produced
              
              Sales
                Realizations
      (1)
              
              Tons
                Produced
              
              Sales
                Realizations
      (1)
              
              Tons
                Produced
              
              Sales
                Realizations
      (1)Eastern
              
              2,500,707
              
              $
              66.92
              
              3,234,517
              
              $
              55.36
              
              3,268,000
              
              $
              42.15Hazard
              
              3,669,581
              
              $
              65.72
              
              4,055,874
              
              $
              54.56
              
              3,868,959
              
              $
              45.04Flint
      Ridge
              
              800,792
              
              $
              66.25
              
              1,055,996
              
              $
              55.05
              
              1,306,428
              
              $
              45.49Knott County
              
              518,095
              
              $
              64.84
              
              948,445
              
              $
              52.57
              
              1,039,714
              
              $
              46.41Raven
              
              728,487
              
              $
              66.81
              
              664,265
              
              $
              54.45
              
              608,068
              
              $
              48.30East
      Kentucky
              
              933,030
              
              $
              55.49
              
              1,058,092
              
              $
              58.39
              
              1,001,911
              
              $
              51.42Beckley(2)
              
              750,478
              
              $
              91.89
              
              531,842
              
              $
              106.66
              
              39,748
              
              $
              72.82Vindex
      Energy Corporation
              
              740,084
              
              $
              48.02
              
              939,141
              
              $
              54.43
              
              853,695
              
              $
              36.83Patriot
      Mining Company
              
              744,908
              
              $
              51.14
              
              929,645
              
              $
              40.56
              
              885,108
              
              $
              25.12Wolf
      Run Mining Buckhannon Division
              
              1,042,384
              
              $
              57.59
              
              993,807
              
              $
              56.48
              
              636,002
              
              $
              41.94Powell Mountain(3)
              
              203,110
              
              $
              106.45
              
              100,322
              
              $
              132.17
              
              —
              
              $
              —Sentinel
              
              1,367,597
              
              $
              57.42
              
              1,007,425
              
              $
              60.73
              
              681,814
              
              $
              47.22Illinois
              
              2,251,951
              
              $
              33.63
              
              2,261,028
              
              $
              29.94
              
              2,085,495
              
              $
              29.84Sycamore
      Group
              
              —
              (4)
              $
              —
              
              —
              (4)
              $
              —
              
              82,904
              
              $
              30.1416,251,204
              
              
              
              
              17,780,399
              
              
              
              
              16,357,846
 
 
 (1)
              Excludes
      freight and handling revenue.(2)
              Beckley
      was in development until the fall of 2008.(3)
              Powell
      Mountain was acquired in 2008.(4)
              The
      Sycamore No. 1 mine was depleted and reclaimed in
  2007.
  7
  Table of contents
  Northern
and Central Appalachian Mining Operations
 
 Below
is a map showing the location and access to our coal properties in Northern and
Central Appalachia as of December 31, 2009:
 
 
 
 Our
Northern and Central Appalachian mining facilities and reserves are
strategically located across West Virginia, Kentucky, Maryland, Virginia and
Ohio and are used to produce and ship coal to our customers located primarily in
the eastern half of the United States. All of our Northern and Central
Appalachian mining operations are union free.
 
 Our
mines in Central Appalachia produced 10.1 million tons of coal in 2009 and
our mines in Northern Appalachia produced 3.9 million tons of coal in 2009.
The coal produced in 2009 from our Northern and Central Appalachian mining
operations was, on average, 12,229 Btu/lb., 1.33% sulfur and 12.35% ash by
content. Shipments bound for electric utilities accounted for approximately 92%
of the coal shipped by these mines in 2009 compared to 91% of shipments in 2008.
Within each mining complex, mines have been developed at strategic locations in
proximity to our preparation plants and rail shipping facilities. The mines
located in Central Appalachia ship the majority of their coal via the CSX rail
road and, to a lesser extent, via the Norfolk Southern rail system. Some
shipments may also be delivered by truck or barge, depending on the customer.
Northern Appalachia shipments are primarily via CSX rail with some barge and
truck to customer shipments.
 
 As
of December 31, 2009, these mines had 2,006 employees.
 
 8
  Table of contents
  Eastern
 
 Eastern
operates the Birch River surface mine, located 60 miles east of Charleston,
near Cowen in Webster County, West Virginia. Birch River is extracting coal
from the Freeport, Upper Kittanning, Middle
Kittanning, Upper Clarion and Lower Clarion coal seams. Birch River
controls an estimated 9.7 million tons of coal reserves. Additional
potential reserves, mineable by both surface and deep mining methods, have been
identified in the immediate vicinity of the Birch River mine and
exploration activities are currently being conducted in order to add those
potential reserves to the reserve base.
 
 The
coal reserves are predominantly leased. The leases are retained by annual
minimum payments and by tonnage-based royalty payments. Most of the leased
reserves are held by four lessors. Most of the leases can be renewed until all
mineable and merchantable coal has been exhausted.
 
 Overburden
is removed by an excavator, front-end loaders, end dumps and bulldozers.
Approximately one-third of the total coal sales are run-of-mine, while the
other two-thirds are washed at Birch River’s preparation plant. Coal
is transported by conveyor belt from the preparation plant to Birch River’s
rail loadout, which is served by CSX via the A&O Railroad, a short-line
carrier that is partially owned by CSX.
 
 Hazard
 
 Hazard
currently operates four surface mines, a unit train loadout (Kentucky River
Loading) and other support facilities in eastern Kentucky, near Hazard. Hazard’s
four surface mines include East Mac & Nellie, Rowdy Gap, Sam
Campbell and Thunder Ridge. The coal from these mines is being extracted from
the Hazard 10, Hazard 9, Hazard 8, Hazard 7 and Hazard 5A seams. Nearly all of
the coal is marketed as a blend of run-of-mine product with the remainder being
washed. Overburden is removed by front-end loaders, end dumps, bulldozers and
cast blasting. East Mac & Nellie also utilizes a large capacity hydraulic
shovel. Coal is transported by on-highway trucks from the mines to the Kentucky
River Loading rail loadout, which is served by CSX. Some coal is direct shipped
to the customer by truck from the mine pits.
 
 We
estimate that Hazard controls 64.5 million tons of coal reserves, plus
8.0 million tons of coal that is classified as non-reserve coal deposits.
Most of the property has been adequately explored, but additional core drilling
will be conducted within specified locations to better define the
reserves.
 
 Approximately
63% of Hazard’s reserves are leased. Most of the leased reserves are held by
seven lessors. In several cases, Hazard has multiple leases with each lessor.
The leases are retained by annual minimum payments and by tonnage-based royalty
payments. Most of the leases can be renewed until all mineable and merchantable
coal has been exhausted.
 
 Flint
Ridge
 
 As
of year-end, Flint Ridge, located near Breathitt County, Kentucky, was currently
operating one underground mine and one preparation plant. The underground mine
operates in the Hazard 8 seam.
 
 Flint
Ridge’s underground mine is a room-and-pillar operation, utilizing continuous
miners and shuttle cars. All of the run-of-mine coal is processed at the Flint
Ridge preparation plant, which was extensively upgraded in early 2005. Since
July 2005, it has been processing coal from the Hazard and Flint Ridge mining
complexes.
 
 9
  Table of contents
  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 23.4 million tons of coal reserves, plus
0.9 million tons of non-reserve coal deposits. Approximately 98% of Flint
Ridge’s reserves are leased, while 2% are owned in fee. The leases are retained
by annual minimum payments and by tonnage-based royalty payments. Most of the
leases can be renewed until all mineable and merchantable coal has been
exhausted.
 
 Knott County
 
 Knott County
operates two underground mines, the Supreme Energy preparation plant and rail
loadout and other facilities necessary to support the mining operations in
eastern Kentucky, near Kite. Knott County owns certain reserves in fee with
the remaining reserves being leased from a number of lessors.
 
 Knott County
is producing coal from the Hazard 4 and Elkhorn 3 coal seams. The Calvary mine
is operating in the Hazard 4 coal seam, while the Classic mine is operating in
the Elkhorn 3 coal seam. Two additional properties are in the process of being
permitted for underground mine development. We estimate Knott County controls
18.1 million tons of coal reserves. A significant portion of the property
has been explored, but additional core drilling will be conducted within
specified locations to better define the reserves.
 
 Approximately
28% of Knott County’s reserves are owned in fee, while approximately 72%
are leased. The leases are retained by annual minimum payments and by
tonnage-based royalty payments. The leases typically can be renewed until all
mineable and merchantable coal has been exhausted.
 
 Knott County’s
two underground mines are room-and-pillar operations, utilizing continuous
miners and shuttle cars. 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.
 
 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 coal seam. Two additional properties are in the process of being
permitted for underground mine development. We estimate Raven controls
10.2 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 all leased from one lessor, Penn Virginia Resource Partners,
L.P. 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, which began operations in 2006. 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.
 
 10
  Table of contents
  Mt. Sterling
is an area surface mine that produces coal from the
Taylor, Coalburg, Winifrede, Buffalo and Stockton coal seams. All
of the coal is sold run-of-mine. We estimate that the Mt. Sterling mine
controls 1.5 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 cast blasting. 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
0.1 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 through early second quarter 2010.
 
 Although
Mt. Sterling and Peelpoplar are mined by East Kentucky, the properties are held
by our ICG Natural Resources subsidiary. The leases are retained by annual
minimum payments and by tonnage-based royalty payments. Most of the leases can
be renewed until all mineable and merchantable coal has been
exhausted.
 
 Beckley
 
 The
Beckley Pocahontas Mine, located near Beckley in Raleigh County, West Virginia,
was placed into production in the fall of 2008 and accesses a
31.3 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, shuttle cars and battery
haulers. Coal produced from the Beckley operation is marketed to domestic steel
producers and for export. Additionally, we have the ability to produce
metallurgical coal by reprocessing a nearby coal refuse pile located at Eccles,
West Virginia.
 
 Powell
Mountain
 
 Acquired
in 2008, Powell Mountain, located in Lee County, Virginia and Harlan County,
Kentucky, currently operates the Darby mine, a room-and-pillar mine operating
two sections with continuous miners and shuttle cars. The mine is operating in
the Darby seam with all coal being trucked to the Mayflower preparation plant
for processing. Coal is shipped by rail through the dual service rail loadout
facility with rail service provided by both the Norfolk Southern and CSX
railroads. Some purchased coal is brought into the facility for processing and
blending. We plan to begin operation of the new Middle Splint mine in
2011.
 
 Vindex
Energy Corporation
 
 Vindex
Energy Corporation operates three surface mines, 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.
All surface mines operated by Vindex Energy are truck-and-shovel/loader mining
operations which extract coal from the Upper Freeport, Bakerstown, Middle
Kittanning, Upper Kittanning, Pittsburgh and Redstone seams. In 2007, Vindex
added the Cabin Run property and the Buffalo properties to its reserve base. The
total surface mineable reserves at Vindex amount to approximately 11.0 million
tons.
 
 11
  Table of contents
  Vindex
also controls approximately 54.0 million tons of deep mineable reserves in the
Bakerstown and Upper Freeport seams. These reserves are low-volatile
metallurgical coals suitable for steel making. Permits are in place to allow the
prompt development of the reserves.
 
 Most
of the surface mine production is shipped directly to the customer as
run-of-mine product; however, approximately 15,000 tons per month are targeted
toward the export low-volatile metallurgical market. Any coal that must be
washed is processed at our preparation plant located near Mount Storm, West
Virginia, where the product is shipped to the customer by either truck or rail.
A second preparation plant with rail access remains idle, although it is
currently used for loading rail shipments to metallurgical
customers.
 
 Patriot
Mining Company
 
 Patriot Mining Company currently consists of the Guston Run surface mine,
located near Morgantown in Monongalia County, West Virginia. The majority of the
coal and surface is leased under renewable contracts with small annual minimum
holding costs. Coal is extracted from the Waynesburg seam using 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 a loading facility which is located near
Morgantown, West Virginia. Patriot Mining Company currently controls
approximately 9.4 million tons of coal reserves, of which 100% are
leased.
 
 Buckhannon
Division
 
 Wolf
Run Mining Company’s Buckhannon Division currently consists of two active
underground mines: the Imperial mine located in Upshur County, West Virginia,
near the town of Buckhannon, and the Sycamore No. 2 mine located in
Harrison County, West Virginia, approximately ten miles west of Clarksburg.
Nearly all of the reserves in Upshur County are owned, while those in Harrison
County are leased. The Buckhannon Division currently controls approximately 58.0
million tons of reserves, all of which are suited for underground
mining.
 
 The
Imperial mine extracts coal from the Middle Kittanning seam. The coal produced
at the Imperial mine is processed through the nearby Sawmill Run preparation
plant and shipped by CSX rail with origination by the A&O Railroad, although
some coal is trucked to local industrial customers. The reserves at the
Buckhannon Division have characteristics that make it marketable to both steam
and export metallurgical coal customers.
 
 The
Sycamore No. 2 mine 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. An independent contractor has operated the
mine since September 2007. The coal produced from the Sycamore No. 2 mine
is sold on a raw basis and shipped to Allegheny Power Service Corporation’s
Harrison Power Station by truck.
 
 Sentinel
 
 Sentinel
consists of one underground mine that extracts coal from the Clarion seam using
the room-and-pillar mining method. Clarion seam reserves at the Sentinel mine
amount to approximately 13.4 million tons, of which approximately 12% is
owned and 88% is leased. Additionally, 19.4 million tons of underground reserves
in the Lower Kittanning seam are accessible from the Sentinel mine.
 
 Coal
is fed directly from the mine to a preparation plant and loadout facility served
by the CSX railroad with origination by the A&O Railroad. The product can be
shipped to steam or metallurgical markets, by either rail or truck.
 
 12
  Table of contents
  New
Appalachian Mine Developments
 
 Tygart
Property
 
 The
Tygart property (formerly known as the Hillman property), located in Taylor
County, West Virginia, near Grafton, includes approximately 186.1 million
tons of deep coal reserves of both steam and metallurgical quality coal in the
Lower Kittanning seam, covering approximately 65,000 acres. The reserve extends
into parts of Barbour, Marion and Harrison Counties as well. ICG owns the
Tygart coal reserve, in addition to nearly 4,000 acres of surface property to
accommodate the development of two projected mining operations. In addition to
the Lower Kittanning reserves, significant non-reserve coal deposits in the
Kittanning, Freeport, Clarion and Mercer seams exist on the Tygart
property.
 
 The
West Virginia Department of Environmental Protection (the “WVDEP”) issued a
surface mine permit on June 5, 2007 for the Tygart No. 1 underground
longwall mine and preparation plant complex located on the Tygart property.
Following an appeal filed by anti-mining activists, 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 by the same activists to the WV Surface Mine Board resulted in
the suspension of the permit in October 2008 and cessation of construction
activity. A modified permit was reissued on May 27, 2009 by the WVDEP, and is
again under appeal by the same activists.
 
 Construction
of our Tygart No. 1 mining complex is not expected to resume until permit
appeals have been exhausted and market conditions justify the additional
production. Resumption of work is not currently expected before 2011. At full
production, Tygart No. 1 is expected to produce 3.5 million tons
annually of high quality coal that is well suited to both the utility market and
the high volatile metallurgical market.
 
 Upshur
Property
 
 The
Upshur Property, located in Northern Appalachia, contains approximately 93.0
million tons of non-reserve coal deposits 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 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.
 
 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 and 30.2 million tons of high-Btu, mid-sulfur underground reserves in
the Alma seam. Efforts are underway to secure an Army Corps of Engineers Section
404 authorization to complete permitting for surface mining on this property.
Our Section 404 permit application is currently under enhanced review by the
Environmental Protection Agency and the Army Corps of Engineers. We intend to
produce the coal by mountaintop, contour and highwall mining. Also, permitting
is now in progress for an Alma seam underground mine on this Central Appalachian
property.
 
 13
  Table of contents
 
 Illinois Basin
Mining Operations
 
 Below
is a map showing the location and access to our coal properties in the
Illinois Basin as of December 31, 2009:
 
 
 
 Illinois
operates one large underground coal mine, the Viper mine, in central Illinois.
Viper commenced mining operations in 1982 and produces coal from the Illinois
No. 5 Seam, also referred to as the Springfield Seam. Viper controls
approximately 46.1 million tons of coal reserves. Approximately 82% of the
coal reserves are leased, while 18% are owned in fee. The leases are retained by
annual minimum payments and by tonnage-based royalty payments.
 
 The
Viper mine is a room-and-pillar operation, utilizing continuous miners and
battery coal haulers. All of the raw coal is processed at Viper’s preparation
plant and shipped by truck to utility and industrial customers located in North
Central Illinois. A major rail line is located a short distance from the plant,
giving Viper the option of constructing a rail loadout. Shipments to electric
utilities account for approximately 68% of coal sales.
 
 Illinois
has begun the development of a new portal facility that will allow it to
eliminate the operation and maintenance of over five miles of underground
beltlines and to seal and close the previously mined area.
 
 As
of December 31, 2009, this mine had 287 employees.
 
 14
  Table of contents
 
 Other
Operations
 
 Brokered
coal sales
 
 In
addition to the coal we mine, we purchase and resell coal produced by third
parties to fulfill certain sales obligations.
 
 ADDCAR
Systems
 
 In
our highwall mining business, we have four 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. 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.
 
 During
the mining cycle, in addition to the tramming effort provided by the crawler
drive of the continuous miner, the ADDCAR highwall mining system increases the
cutting capability of the machine through additional forces provided by
hydraulic cylinders which transmit thrust to the back of the miner through
blocks mounted on the side of the conveyor cars. This additional energy allows
the continuous miner to achieve maximum cutting and loading rates as it moves
forward into the seam.
 
 In
addition to its standard highwall mining system, ADDCAR has also developed a
narrow bench highwall mining system and a steep-dip highwall mining system. The
narrow bench highwall mining system has a smaller operational footprint that
allows operation on narrower mine benches that are often found in Appalachia.
The first ADDCAR narrow bench highwall mining system was placed in operation in
2007. The steep-dip highwall mining system allows for mining in steeply dipping
coal seams often found in the western U.S. and Canada.  The first
ADDCAR steep-dip highwall mining system was delivered to a Canadian customer in
2009.
 
 We
currently have the exclusive North American distribution rights, as well as
certain international patent rights acquired in the third quarter of 2009, for
the ADDCAR highwall mining system.
 
 15
  Table of contents
  Coalbed
methane
 
 Our
subsidiary, CoalQuest, has entered into a lease and joint operating agreement
pursuant to which it leases coalbed methane, which is pipeline quality gas that
resides in coal seams, and participates in certain coalbed methane wells, from
its properties in Barbour, Harrison and Taylor counties in West Virginia. 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. 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 short-term
spot basis for some of our customers. Our three largest customers for the year
ended December 31, 2009 were Progress Energy, Georgia Power and Santee
Cooper and we derived approximately 36% of our revenues from sales to our
five largest customers. We did not derive more than 10% of our revenues from any
single customer in 2009.
 
 Long-term
coal supply agreements
 
 As
is customary in the coal industry, we enter into long-term supply contracts
(exceeding one year in duration) with many of our customers when market
conditions are appropriate. These contracts allow customers to secure a supply
for their future needs and provide us with greater predictability of sales
volumes and prices. For the year ended December 31, 2009, approximately 89% of
our coal sales revenues were derived from long-term supply contracts. We sell
the remainder of our coal through short-term contracts and on the spot market.
We have also entered into certain brokered transactions to purchase certain
amounts of coal to meet our sales commitments. These purchase coal contracts
expire in 2010 and are expected to provide us a minimum of approximately
0.5 million tons of coal through the remaining lives of the
contracts.
 
 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.
 
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  Some
of our long-term contracts provide for a pre-determined adjustment to the
stipulated base price at times specified in the agreement or at other periodic
intervals to account for changes due to inflation or deflation in prevailing
market prices.
 
 In
addition, most of our contracts contain provisions to adjust the base price due
to new statutes, ordinances or regulations that impact our costs related to
performance of the agreement. Also, some of our contracts contain provisions
that allow for the recovery of costs impacted by modifications or changes in the
interpretations or application of any applicable government
statutes.
 
 Price
reopener provisions are present in several of our long-term contracts. These
price reopener provisions may automatically set a new price based on prevailing
market price or, in some instances, require the parties to agree on a new price,
sometimes within a specified range of prices. In a limited number of agreements,
failure of the parties to agree on a price under a price reopener provision can
lead to termination of the contract. Under some of our contracts, we have the
right to match lower prices offered to our customers by other
suppliers.
 
 Quality
and volumes for the coal are stipulated in coal supply agreements and, in some
instances, buyers have the option to vary annual or monthly volumes. Most of our
coal supply agreements contain provisions requiring us to deliver coal within
certain ranges for specific coal characteristics such as heat content, sulfur,
ash, hardness and ash fusion temperature. Failure to meet these specifications
can result in economic penalties, suspension or cancellation of shipments or
termination of the contracts.
 
 Transportation/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
2009, approximately 99% 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 1%
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.
 
 Suppliers
 
 In
2009, we spent more than $324.6 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.
 
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 Competition
 
 The
coal industry is intensely competitive. Our main competitors are Massey Energy
Company, Arch Coal, Consol Energy, Alpha Natural Resources, James River Coal
Company, Patriot Coal Corporation and various other smaller, independent
producers. The most important factors on which we compete are coal price at the
mine, coal quality and characteristics, transportation costs and the reliability
of supply. Demand for coal and the prices that we are able to obtain for our
coal are closely linked to coal consumption patterns of the domestic electric
generation industry, which accounted for approximately 93% of domestic coal
consumption in 2008. These coal consumption patterns are influenced by factors
beyond our control, including the demand for electricity which is significantly
dependent upon economic activity, weather patterns in the United States,
government regulation, technological developments and the location,
availability, quality and price of competing sources of coal, changes in
international supply and demand, alternative fuels such as natural gas, oil and
nuclear and alternative energy sources, such as hydroelectric
power.
 
 Employees
 
 As
of December 31, 2009, we had 2,562 employees of which 24% were salaried and
76% 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, 2009, we had
$61.1 million in letters of credit supporting our reclamation surety bonds.
While bonds are issued against reclamation liability for a particular permit at
a particular site, collateral posted in support of the bond is not allocated to
a specific bond, but instead is part of a collateral pool supporting all bonds
issued by that particular insurer. Bonds are released in phases as reclamation
is completed in a particular area.
 
 Environmental,
Safety and Other Regulatory Matters
 
 Federal,
state and local authorities regulate the U.S. coal mining industry with respect
to matters such as permitting and licensing requirements, employee health and
safety, air quality standards, water pollution, plant and wildlife protection,
the reclamation and restoration of mining properties after mining has been
completed, the discharge of materials into the environment, surface subsidence
from underground mining and the effects of mining on groundwater quality and
availability. These laws and regulations have had, and will continue to have, a
significant effect on our costs of production and competitive position. Future
legislation, regulations or orders may be adopted or become effective which may
adversely affect our mining operations, cost structure or the ability of our
customers to use coal. For instance, new legislation, regulations or orders, as
well as future interpretations and more rigorous enforcement of existing laws,
may require substantial increases in equipment and operating costs to us and
delays, interruptions or a termination of operations, the extent of which we
cannot predict. Future legislation, regulations or orders or negative
perceptions due to environmental issues may also cause coal to become a less
attractive fuel source, resulting in a reduction in coal’s share of the market
for fuels used to generate electricity.
 
 We
endeavor to conduct our mining operations in compliance with all applicable
federal, state and local laws and regulations. However, due in part to the
extensive and comprehensive regulatory requirements, violations during mining
operations occur from time to time in the industry and at our
operations.
 
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 Mining
Permits and Approvals
 
 Numerous
governmental permits or approvals are required for mining operations. In
connection with obtaining these permits and approvals, we may be required to
prepare and present to federal, state or local authorities data pertaining to
the effect or impact that any proposed production or processing of coal may have
upon the environment. The requirements imposed by any of these authorities may
be costly and time consuming and may delay commencement or continuation of
mining operations and could have a material adverse effect on our business.
Applications for permits are subject to public comment and may be subject to
litigation from third parties seeking to deny issuance of a permit, which may
also delay commencement or continuation of mining operations and could have a
material adverse effect on our business. Regulations also provide that a mining
permit or modification can be delayed, refused or revoked if an officer,
director or a stockholder with a 10% or greater interest in the entity is
affiliated with or is in a position to control another entity that has
outstanding permit violations. Thus, past or ongoing violations of federal and
state mining laws could provide a basis to revoke existing permits and to deny
the issuance of additional permits.
 
 In
order to obtain mining permits and approvals from state regulatory authorities,
mine operators must also submit a comprehensive plan for mining and restoring,
upon the completion of mining operations, the mined property to its prior
condition, productive use or other permitted condition. Typically, we submit our
necessary mining permit applications for our planned mines promptly upon
securing the necessary property rights and required geologic and environmental
data. In our experience, mining permit approvals generally require 12 to 18
months after initial submission; however, in the current regulatory environment,
with enhanced scrutiny by regulators, increased opposition by environmental
groups and others and potential resultant delays and permit application denials,
we now anticipate that mining permit approvals will take even longer than
previously experienced, and some permits may not be issued at all. Significant
delays in obtaining, or denial of, permits could have a material adverse effect
on our business.
 
 Surface
Mining Control and Reclamation Act
 
 The
Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is
administered by the Department of Interior’s Office of Surface Mining
Reclamation and Enforcement (“OSM”), establishes mining, environmental
protection and reclamation standards for all aspects of surface mining, as well
as for the surface effects of deep mining. Mine operators must obtain SMCRA
permits and permit renewals from the 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.
 
 SMCRA
permit provisions include requirements for coal prospecting, mine plan
development, topsoil removal, storage and replacement, selective handling of
overburden materials, mine pit backfilling and grading, protection of the
hydrologic balance, subsidence control for underground mines, surface drainage
control, mine drainage and mine discharge control and treatment and
revegetation. These requirements seek to limit the adverse impacts of coal
mining and more restrictive requirements may be adopted from time to
time.
 
 The
mining permit application process is initiated by collecting baseline data to
adequately characterize the pre-mine environmental condition of the permit area.
This work includes surveys of cultural resources, soils, vegetation, wildlife,
assessment of surface and ground water hydrology, climatology and wetlands. In
conducting this work, we collect geologic data to define and model the soil and
rock structures and coal that we will mine. We develop mine and reclamation
plans by utilizing this geologic data and incorporating elements of the
environmental data. The mine and reclamation plan incorporates the provisions of
SMCRA, the state programs and the complementary environmental programs that
impact coal mining.
 
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  Also
included in the permit application are documents defining ownership and
agreements pertaining to coal, minerals, oil and gas, water rights, rights of
way and surface land, and documents required by the 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. From time to time, litigation is brought to modify, revoke or enjoin
the issuance of SMCRA and other permits. For example, our Hazard Thunder Ridge
permit was previously the subject of litigation seeking to enjoin the
construction of certain valley fills, and our Tygart Valley surface mine permit
is currently being administratively appealed by an anti-mining activist
group.
 
 Before
a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure
the performance of reclamation obligations. The Abandoned Mine Land Fund, which
is part of SMCRA, requires a fee on all coal produced. The proceeds are used to
reclaim mine lands closed or abandoned prior to 1977. On December 7, 2006,
the Abandoned Mine Land Program was extended for 15 years.
 
 SMCRA
stipulates compliance with many other major environmental statutes, including:
the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery
Act (“RCRA”), and the Comprehensive Environmental Response, Compensation and
Liability Act (“Superfund”).
 
 Surety
Bonds
 
 Federal
and state laws require us to obtain surety bonds to secure payment of certain
long-term obligations, including mine closure or reclamation costs, coal leases
and other miscellaneous obligations. Many of these bonds are renewable on a
yearly basis.
 
 Surety
bond costs have increased in recent years while the market terms of such bonds
have generally become more unfavorable. In addition, the number of companies
willing to issue surety bonds has decreased. Bonding companies also require
posting of collateral, typically in the form of letters of credit, to secure the
surety bonds. As of December 31, 2009, we had $61.1 million in letters of
credit supporting our reclamation surety bonds.
 
 Clean
Air Act
 
 The
federal Clean Air Act, and comparable state laws that regulate air emissions,
directly affect coal mining operations, but have a far greater indirect effect.
Direct impacts on coal mining and processing operations may occur through
permitting requirements and/or emission control requirements relating to
particulate matter, such as fugitive dust, or fine particulate matter measuring
2.5 micrometers in diameter or smaller. The Clean Air Act indirectly affects
coal mining operations by extensively regulating the air emissions of sulfur
dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired
electricity generating plants and coke ovens. Proposed regulations would also
subject greenhouse gas emissions to regulation under the Clean Air Act. The
general effect of such extensive regulation of emissions from coal-fired power
plants could be to reduce demand for coal.
 
 Clean
Air Act requirements that may directly or indirectly affect our operations
include the following:
 
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 Acid
Rain
 
 Title
IV of the Clean Air Act required a two-phase reduction of sulfur dioxide
emissions by electric utilities. Phase II became effective in 2000 and extended
the Title IV requirements to all coal-fired power plants with generating
capacity greater than 25 megawatts. The affected electricity generators have
sought to meet these requirements by, among other compliance methods, switching
to lower sulfur fuels, installing pollution control devices, reducing
electricity generating levels or purchasing sulfur dioxide emission allowances.
We cannot accurately predict the effect of these provisions of the Clean Air Act
on us in future years. 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.
 
 Criteria
Pollutants
 
 The
Clean Air Act authorizes the U.S. Environmental Protection Agency (the “EPA”) to
set standards, referred to as National Ambient Air Quality Standards (“NAAQS”)
for pollutants. Among the pollutants for which standards have been adopted
(criteria pollutants) are sulfur dioxide, nitrogen oxides, ozone, particulate
matter and fine particulates. Areas that are not in compliance with these
standards (non-attainment areas) must take steps to reduce emissions levels. The
EPA is required to regularly review these standards and may revise them
following such reviews. Revisions to the standards typically make them more
stringent and increase compliance costs as they are implemented.
 
 Following
identification of non-attainment areas, each individual state will identify the
sources of emissions and develop emission reduction plans. These plans may be
state-specific or regional in scope. Future regulation and enforcement of the
most recent ozone and PM2.5 standards will affect many power plants, especially
coal-fired plants and all plants in non-attainment areas.
 
 Significant
additional emissions control expenditures will be required at coal-fired power
plants to meet the current NAAQS for ozone. 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.
 
 New
source review requirements, which are imposed on major sources of pollutants,
such as coal-fired power plants, and new source performance standards also
impose control and emission requirements.
 
 Installation
of additional control measures, such as selective catalytic reduction devices,
will make it more costly to operate coal-fired electricity generating plants and
industrial boilers, thereby making coal a less attractive fuel and reducing
demand for our products.
 
 Mercury
 
 The
EPA has announced that it intends to initiate a rulemaking to adopt
technology-based standards for mercury emissions from coal-fired power plants in
response to a court order which vacated and remanded its 2005 Clean Air Mercury
Rule, which would have reduced mercury emissions from such plants by a
nationwide average of nearly 70%. The parties that overturned this rule
seek even greater reductions in mercury emissions uniformly applied to all power
plants. Some parties contend that during the pendency of this rulemaking, these
plants are subject to mercury emission limitations determined on a case-by-case
basis applying maximum achievable control technology.
 
 Other
proposals for controlling mercury emissions from coal-fired power plants have
been made, such as establishing state or regional emission standards. If these
proposals were enacted, the mercury content and variability of our coal would
become a factor in future sales and could reduce demand for our products. In
addition, seven Northeastern states have prepared and submitted to the EPA a
Northeast Regional Mercury Total Maximum Daily Load to reduce mercury in natural
water courses by reducing air deposition of mercury primarily from coal-fired
power plants in the Midwest.
 
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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.
 
 Climate
Change
 
 Global
climate change concerns have a potentially far-reaching impact upon our
business, including our reputation and results of operations. Concerns over
measurements, estimates and projections of global climate change, particularly
global warming, have resulted in widespread calls for the reduction, by
regulation and voluntary measures, of the emission of greenhouse gases, which
include carbon dioxide and methane. These measures could impact the market for
our coal and coalbed methane, increase our own energy costs and affect the value
of our coal reserves. The United States has not ratified the Framework
Convention on Global Climate Change, commonly known as the Kyoto Protocol, which
would require our nation to reduce greenhouse gas emissions to 93% of 1990
levels by 2012. The
United States is participating in international discussions to develop a treaty
or other agreement to require reductions in greenhouse gas emissions after 2012
and
has signed the Copenhagen Accord, which includes a non-binding commitment to
reduce greenhouse gas emissions.
 
 The
U.S. Congress is considering a variety of legislative proposals which would
restrict and/or tax the emission of greenhouse gases from the combustion of coal
and other fuels and which would mandate or encourage the generation of
electricity by new facilities that do not use coal.




A
step toward potential federal restriction on greenhouse gas emissions was taken
on December 7, 2009 when the EPA issued its so-called Endangerment Finding in
response to a decision of the Supreme Court of the United States. The EPA found
that the emission of six greenhouse gases, including carbon dioxide (which is
emitted from coal combustion) and methane (which is emitted from coal beds) may
reasonably be anticipated to endanger public health and welfare. Based on this
finding, EPA defined the mix of these six greenhouse gases to be “air pollution”
subject to regulation under the Clean Air Act. Although EPA has stated a
preference that greenhouse gas regulation be based on new federal legislation
rather than the existing Clean Air Act, many sources of greenhouse gas emissions
may be regulated without the need for further legislation. The EPA has already
proposed regulations that would impact major stationary sources of greenhouse
gas emissions, including coal-fired power plants, that could come into effect as
early as March 2010.
  In
addition to materially adversely impacting our markets and the demand for our
products, regulations enacted due to climate change concerns could affect our
operations by increasing our costs. Our energy costs could increase and we may
have to incur higher costs to control emissions of carbon dioxide, methane or
other pollutants from our operations.
  While
advocating for comprehensive federal legislation, many states have adopted
measures, sometimes as part of a regional collaboration, to reduce greenhouse
gases generated within their own jurisdiction. These measures include emission
regulations, including regional cap and trade programs, mandates for utilities
to generate a portion of their electricity without using coal and incentives or
goals for generating electricity using renewable resources. Some municipalities
have also adopted similar measures. Even in the absence of mandatory
requirements, some entities are electing to purchase electricity generated by
renewable resources for a variety of reasons, including participation in
programs calling for voluntary reductions in greenhouse gas emissions.
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 Passage
of additional state or federal laws or regulations regarding greenhouse gas
emissions or other actions to limit greenhouse gas emissions could result in
fuel switching, from coal to other fuel sources, by electric generators. Such
laws and regulations could, for example, include mandating decreases in
greenhouse gas emissions from coal-fired power plants, imposing taxes on
greenhouse gas emissions, requiring certain technology to capture and sequester
greenhouse gases from new coal-fired power plants and encouraging the production
of non-coal-fired power plants. Political and regulatory uncertainty over future
emissions controls have been cited as major factors in decisions by power
companies to postpone new coal-fired power plants. If measures such as these or
other similar measures, like controls on methane emissions from coal mines, are
ultimately imposed on the coal industry by federal or state governments or
pursuant to international treaty, our operating costs may be materially and
adversely affected. Similarly, alternative fuels (non-fossil fuels) could become
more attractive than coal in order to reduce greenhouse gas emissions, which
could result in a reduction in the demand for coal and, therefore, our
revenues.
  Clean
Water Act
 
 The
federal Clean Water Act (“CWA”) and corresponding state laws affect coal mining
operations by imposing restrictions on the discharge of certain pollutants into
water and on dredging and filling wetlands and jurisdictional waters. The CWA
establishes instream water quality standards, including anti-degradation
standards, and treatment standards for wastewater discharge through the National
Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, as well as
compliance with reporting requirements and performance standards, are
preconditions for the issuance and renewal of NPDES permits that govern the
discharge of pollutants into water.
  Permits
under Section 404 of the CWA are required for coal companies to conduct
dredging or filling activities in jurisdictional waters for the purpose of
conducting any instream activities, including installing culverts, creating
water impoundments, constructing refuse areas, creating slurry ponds, placing
valley fills or performing other mining activities. Jurisdictional waters
typically include intermittent and perennial streams and may, in certain
instances, include man-made conveyances that have a hydrologic connection to a
stream or wetland. The Army Corps of Engineers (“ACOE”) authorizes instream
activities under either a general “nationwide” permit or under an individual
permit, based on the expected environmental impact. A nationwide permit may be
issued for specific categories of filling activity that are determined to have
minimal environmental adverse effects; however, the effective term of such
permits is limited to no longer than five years. 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 than a nationwide permit, 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 instream activity. We do not expect
to seek further Nationwide Permit 21 authorizations for our relevant operations,
but will apply for individual permits.
 
 The
coal mining industry, and on occasion our operations, have been subject to
litigation to prevent, restrict or delay the issuance of permits under the Clean
Water Act. This litigation has resulted in more voluminous and costly permit
applications and requirements and delays in obtaining permits.
 
 On
July 15, 2009 the ACOE proposed to modify NWP 21 to preclude its use in a
six-state Appalachian region, including Kentucky and West Virginia. This action
was taken pursuant to a June 11, 2009 memorandum of understanding (“MOU”)
entered into by OSM, the EPA and ACOE to implement an interagency plan to
significantly reduce the harmful environmental consequences of Appalachian
surface coal mining.
 
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 In
accordance with the MOU, on November 30, 2009, the OSM published an Advance
Notice of Proposed Rulemaking announcing its intent to revise the stream buffer
zone rule. Certain of the proposed alternatives would effectively prohibit the
placement of materials generated by coal mining into intermittent or perennial
streams, which practice is essential to surface mining in central Appalachia. A
prohibition against excess spoil placement in such streams would essentially
eliminate surface mining in steep terrain, thus rendering much of our coal
reserves unmineable. Restrictions on the placement of coal refuse material in
such streams could limit the life of existing coal processing operations,
potentially block new coal preparation plants and at minimum significantly
increase our operating costs.
 
 Also
subsequent to the MOU, in September 2009, the EPA announced that 79 pending
permit applications for Appalachian coal mining warranted further review because
of continuing concerns about water quality and/or regulatory compliance issues.
These include four of our permit applications: Eastern Jennie Creek Surface
Mine, Hazard Rowdy Gap Surface Mine and Bearville North Surface Mine, and Knott
County. While the EPA has stated that its identification of these 79 permits
does not constitute a determination that the mining involved cannot be permitted
under the Clean Water Act and does not constitute a final recommendation from
the EPA to the ACOE on these projects, it is unclear how long the further review
will take for our four permits or what the final outcome will be. It is also
unclear what impact this process may have on our future applications for surface
coal mining permits. Excessive delays in permitting may require adjustment of
our production budget and mining plans.
 
 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 August 26, 2009 the citizen groups petitioned
the Supreme Court for a writ of certiorari. Replies to the writ of certiorari
from the ACOE and the intervenors are due March 9, 2010. Additionally, in
November 2009, Judge Chambers invalidated two additional permits in a parallel
case based on a finding that the public notices of the applications did not
provide sufficient information on the proposed mitigation plan to allow
meaningful public comment.
 
 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 Hazard’s Thunder Ridge surface mine in Perry County, Kentucky.
The plaintiffs, who were represented by the same counsel as the plaintiffs in
the Chambers lawsuit, made essentially the same claims but added 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. Hazard prepared and submitted supplemental
information, including a watershed scale cumulative impact assessment and a
site-specific fill minimization plan, for the ACOE’s consideration in
2008.  The ACOE reissued the Section 404 authorization in March
2009.  An agreement was executed on November 13, 2009 between the
plaintiffs and Hazard that allowed Hazard to proceed with development of the
remaining valley fills in exchange for certain changes to the mine reclamation
plan along with a $50,000 contribution to a local watershed restoration
project.  The court accepted the settlement and entered an order on
November 20, 2009 dismissing the litigation.
 
 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 instream 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.
 
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  Table of contents
 
 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. In addition, legislation has been introduced in the U.S. Congress
that would restrict or prevent mountaintop mining.
 
 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 2009, we recognized $11.6 million of
expense related to this excise tax.
 
 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.
 
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  Table of contents
 
 Subtitle
C of the RCRA exempted fossil fuel combustion byproducts from hazardous waste
regulation until the EPA completed a report to Congress and, in 1993, made a
determination on whether the combustion byproducts should be regulated as
hazardous. In the 1993 regulatory determination, the EPA addressed some high
volume-low toxicity coal combustion byproducts (“CCBs”) generated at electric
utility and independent power producing facilities, such as coal
ash.
 
 In
May 2000, the EPA concluded that CCBs do not warrant regulation as hazardous
waste under the RCRA and that the hazardous waste exemption applied to these
CCBs. 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. However, the EPA has
announced that it will issue a proposed rule to regulate the disposal of CCBs
under the RCRA. 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.
 
 Due
to the hazardous waste exemption for CCBs such as ash, some of the CCBs are
currently put to beneficial use. For example, at certain mines, we sometimes use
ash deposits from the combustion of coal as a beneficial use under our
reclamation plan. The alkaline ash used for this purpose serves to help
alleviate the potential for acid mine drainage. Also, we are paid to dispose of
CCBs at our Illinois mine by our customers. Efforts continue by environmental
groups and others for the adoption of more stringent disposal requirements for
CCBs. Any increased costs associated with handling or disposal of CCBs would
increase our customers’ operating costs and potentially reduce their coal
purchases. Increased regulation may cause us increased costs due to substitute
reclamation materials or decreased revenue due to discontinuing disposal on
behalf of our customers. In addition, contamination caused by the past disposal
of ash can lead to material liability.
 
 Federal and State Superfund
Statutes
 
 Superfund
and similar state laws affect coal mining and hard rock operations by creating
liability for investigation and remediation in response to releases of hazardous
substances into the environment and for damages to natural resources caused by
such releases. Under 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.
 
 Coal
Industry Retiree Health Benefit Act of 1992
 
 Unlike
many companies in the coal business, we do not have significant liabilities
under the Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”),
which requires the payment of substantial sums to provide lifetime health
benefits to union-represented miners (and their dependents) who retired before
1992, because liabilities under the Coal Act that had been imposed on our
predecessor or acquired companies were retained by the sellers and, if
applicable, their parent companies in the applicable acquisition agreements,
except for Anker Coal Group, Inc. (“Anker’). We should not be liable for these
liabilities retained by the sellers unless they and, if applicable, their parent
companies fail to satisfy their obligations with respect to Coal Act claims and
retained liabilities covered by the acquisition agreements. Upon the
consummation of the business combination with Anker, we assumed Anker’s Coal Act
liabilities, which were estimated to be $1.4 million at December 31,
2009.
 
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  Table of contents
 
 Endangered
Species Act
 
 The
federal Endangered Species Act and counterpart state legislation protect species
threatened with possible extinction. Protection of threatened and endangered
species may have the effect of prohibiting or delaying us from obtaining mining
permits and may include restrictions on timber harvesting, road building and
other mining or agricultural activities in areas containing the affected species
or their habitats. A number of species indigenous to our properties are
protected under the Endangered Species Act. However, based on the species that
have been identified to date and the current application of applicable laws and
regulations, we do not believe there are any species protected under the
Endangered Species Act that would materially and adversely affect our ability to
mine coal from our properties in accordance with current mining
plans.
 
 Emergency
Planning and Community Right to Know Act
 
 Some
of our subsidiary operations utilize materials and/or store substances that
require certain reporting to local and state authorities under the federal
Emergency Planning and Community Right to Know Act. If required reporting is
missed, it can result in the assessment of fines and penalties. We do not
believe that any potential fines or penalties that could potentially arise under
the federal Emergency Planning and Community Right to Know Act would materially
or adversely affect our ability to mine coal.
 
 Other
Regulated Substances
 
 Some
of our subsidiary operations utilize certain substances, such as ammonia or
caustic soda, for managing water quality in discharges from their mine sites.
These materials are considered hazardous and require safeguards in handling and
use and, if present in sufficient quantities, create emergency planning and
response requirements. The storage of petroleum products in certain quantities
can also trigger reporting, planning and response requirements. Our subsidiaries
are required to maintain careful control over the storage and use of these
substances. The subsidiaries attempt to minimize the amount of materials stored
at their operations that give rise to such concerns and to maximize the use of
less hazardous materials whenever feasible. If quantities are sufficient,
utilization of CCBs for reclamation can trigger certain reporting requirements
for constituent trace elements contained in CCBs.
 
 Additional
Information
 
 We
file annual, quarterly and current reports, as well as amendments to those
reports, proxy statements and other information with the 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 (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.
 
 27
  Table of contents
  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. See
Underground mine below.
 
 Fluidized bed
combustion. A process with a high success rate in removing sulfur
from coal during combustion. Crushed coal and limestone are suspended in the
bottom of a boiler by an upward stream of hot air. The coal is burned in this
bubbling, liquid-like (or fluidized) mixture. Rather than released as emissions,
sulfur from combustion gases combines with the limestone to form a solid
compound recovered with the ash.
 
 Fossil fuel. Fuel such
as coal, crude oil or natural gas formed from the fossil remains of organic
material.
 
 High-Btu coal. Coal
which has an average heat content of 12,500 Btus per pound or
greater.
 
 High sulfur coal. Coal
which, when burned, emits 2.5 pounds or more of sulfur dioxide per million
Btu.
 
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  Table of contents
 
 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 level, but low ash and sulfur
content.
 
 Nitrogen oxide (NOx). A
gas formed in high temperature environments such as coal combustion. It is a
harmful pollutant that contributes to acid rain.
 
 Non-reserve coal
deposits. Non-reserve coal deposits are coal bearing bodies that
have been sufficiently sampled and analyzed, but do not qualify as a
commercially viable coal reserve as prescribed by SEC rules until a final
comprehensive SEC-prescribed evaluation is performed.
 
 Northern
Appalachia. Coal producing area in Maryland, Ohio, Pennsylvania and
northern West Virginia.
 
 Overburden. Layers of
earth and rock covering a coal seam. In surface mining operations, overburden is
removed prior to coal extraction.
 
 Pillar. An area of coal
left to support the overlying strata in a mine; sometimes left permanently to
support surface structures.
 
 Powder River
Basin. Coal producing area in northeastern Wyoming and southeastern
Montana. This is the largest known source of coal reserves and the largest
producing region in the United States.
 
 Preparation
plant. Usually located on a mine site, although one plant may serve
several mines. A preparation plant is a facility for crushing, sizing and
washing coal to prepare it for use by a particular customer. The washing process
has the added benefit of removing some of the coal’s sulfur
content.
 
 Probable
reserves. Reserves for which quantity and grade and/or quality are
computed from information similar to that used for proven reserves, but the
sites for inspection, sampling and measurement are farther apart or are
otherwise less adequately spaced. The degree of assurance, although lower than
that for proven reserves, is high enough to assume continuity between points of
observation.
 
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  Table of contents
 
 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.
 
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  Table of contents
 
 ITEM 1A.
              RISK
      FACTORS
 
 Risks
Relating to Our Business
 
 A
decline in coal prices could reduce our revenues and the value of our coal
reserves.
 
 Our
results of operations are dependent upon the prices we receive for our coal, as
well as our ability to improve productivity and control costs. Any decreased
demand would cause spot prices to decline and require us to increase
productivity and decrease costs in order to maintain our margins. A decrease in
the price we receive for our coal could adversely affect our operating results
and our ability to generate the cash flows we require to meet our bank loan
requirements, improve our productivity and invest in our operations. The prices
we receive for coal depend upon factors beyond our control,
including:
 
 •
              supply
      of and demand for domestic and foreign coal;•
              demand
      for electricity;•
              domestic
      and foreign demand for steel and the continued financial viability of the
      domestic and/or foreign steel industry;•
              proximity
      to, capacity of and cost of transportation facilities;•
              domestic
      and foreign governmental legislation, regulations and
    taxes;•
              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;
 
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  Table of contents
 
 •
              increased
      water entering mining areas and increased or accidental mine water
      discharges;•
              increased
      or unexpected reclamation costs;•
              interruptions
      due to transportation delays;•
              unavailability
      of required equipment of the type and size needed to meet production
      expectations; and•
              unexpected
      mine safety accidents, including fires and
  explosions.
 
 These
conditions and events may increase our cost of mining and delay or halt
production at particular mines either permanently or for varying lengths of
time.
 
 Reduced
coal consumption by North American electric power generators could result in
lower prices for our coal, which could reduce our revenues and adversely impact
our earnings and the value of our coal reserves.
 
 Restrictions
on the emission of greenhouse gases, including carbon dioxide, continue to be
proposed and adopted by various legislative and regulatory bodies at federal,
state and local levels of government and at the international level. The
intended effect of these restrictions is to discourage the combustion of fossil
fuels in general and the generation of electricity by coal in particular
in favor of "alternative sources" of energy which do not involve the
combustion of fossil fuels. For example, on June 26, 2009 the U.S. House of
Representatives passed The American Clean Energy and Security Act of 2009 (House
Bill 2454). If enacted, this bill would create or expand myriad federal programs
designed to reduce energy produced by burning fossil fuels and increase
alternative energy sources. In particular, the bill would reduce greenhouse gas
emissions via a cap and trade system for larger emitters, including coal-fired
power plants. A cap would be placed on overall U.S. greenhouse gas emissions
beginning in 2012 and, compared to 2005 levels, would increasingly reduce
emissions by 83 percent in 2050. The economic impact of the cost of this cap on
coal users would be mitigated by allocating to electric utilities and
certain other industries "free allowances" which would progressively decrease
over time. A similar bill has been introduced in the U.S. Senate. The imposition
of such a program, or the effect of negative public perceptions of coal due to
climate change issues, may result in more electric power generators shifting
from coal to natural gas-fired plants or alternative energy sources. Any
reduction in the amount of coal consumed by North American electric power
generators could reduce the price of steam coal that we mine and sell, thereby
reducing our revenues and adversely impacting our earnings and the value of our
coal reserves. The
United States is participating in international discussions to develop a treaty
or other agreement to require reductions in greenhouse gas emissions after 2012
and
has signed the Copenhagen Accord, which includes a non-binding commitment to
reduce greenhouse gas emissions.
 
 A
step toward potential restriction on greenhouse gas emissions under the Clean
Air Act was taken on December 7, 2009 when the EPA issued its so-called
Endangerment Finding. The EPA found that the emission of six greenhouse gases,
including carbon dioxide (which is emitted from coal combustion) and methane
(which is emitted from coal beds) may reasonably be anticipated to endanger
public health and welfare. Based on this finding, the EPA defined the mix of
these six greenhouse gases to be “air pollution” subject to regulation under the
Clean Air Act. Although the EPA has stated a preference that greenhouse gas
regulation be based on new federal legislation rather than the existing Clean
Air Act, many sources of greenhouse gas emissions may be regulated without the
need for further legislation. The EPA has already proposed regulations that
would impact major stationary sources of greenhouse gas emissions, including
coal-fired power plants, that could come into effect as early as March
2010.
 
 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.
 
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  Table of contents
 
 Overall
economic activity and the associated demands for power by industrial users can
have significant effects on overall electricity demand. Robust economic activity
can cause much heavier demands for power, particularly if such activity results
in increased utilization of industrial assets during evening and nighttime
periods. An economic slowdown can significantly slow the growth of electrical
demand and, in some locations, result in contraction of demand. The economy
suffered a significant slowdown in the fourth quarter of 2008 that resulted in
lower demand. Any downward pressure on coal prices, whether due to increased use
of alternative energy sources, changes in weather patterns, decreases in overall
demand or otherwise, would likely cause our profitability to
decline.
 
 The
capability and profitability of our operations may be adversely affected by the
status of our long-term coal supply agreements and changes in purchasing
patterns in the coal industry.
 
 We
sell a significant portion of our coal under long-term coal supply agreements,
which we define as contracts with a term greater than 12 months. For the year
ended December 31, 2009, approximately 89% of our coal sales revenues were
derived from coal sales that were made under long-term coal supply agreements.
As of that date, we had 40 long-term sales agreements with a volume-weighted
average term of approximately 3.7 years. The prices for coal shipped under
these agreements are typically fixed for at least the initial year of the
contract, subject to certain adjustments in later years and thus may be below
the current market price for similar type coal at any given time, depending on
the timeframe of contract execution or initiation. As a consequence of the
substantial volume of our sales that are subject to these long-term agreements,
we have less coal available with which to capitalize on higher coal prices, if
and when they arise. In addition, in some cases, our ability to realize the
higher prices that may be available in the spot market may be restricted when
customers elect to purchase higher volumes allowable under some contracts. When
our current contracts with customers expire or are otherwise renegotiated, our
customers may decide not to extend or enter into new long-term contracts or, in
the absence of long-term contracts, our customers may decide to purchase fewer
tons of coal than in the past or on different terms, including under different
pricing terms.
 
 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.
 
 33
  Table of contents
 
 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.
 
 As
the ongoing global economic recession has caused the price of, and demand for,
coal to decline, certain of our coal customers have delayed shipments, or
requested deferrals, pursuant to our existing long-term coal supply agreements.
Other customers similarly may seek to delay shipments or request deferrals under
existing agreements. In the current economic environment, the spot market for
coal may not provide an acceptable alternative to sell our uncommitted
tons.  We currently are evaluating customer deferrals and are in
negotiations with a number of the customers that have made such requests. There
is no assurance that we will be able to resolve existing and potential deferrals
on favorable terms, or at all.
 
 Consequently,
due to the risks mentioned above, we may not achieve the revenue or profit we
expect to achieve from our long-term supply agreements.
 
 A
decline in demand for metallurgical coal would limit our ability to sell our
high quality steam coal as higher-priced metallurgical coal.
 
 Portions
of our coal reserves possess quality characteristics that enable us to mine,
process and market them as either metallurgical coal or high quality steam coal,
depending on the prevailing conditions in the metallurgical and steam coal
markets. A decline in the metallurgical market relative to the steam market
could cause us to shift coal from the metallurgical market to the steam market,
thereby reducing our revenues and profitability. However, some of our mines
operate profitably only if all or a portion of their production is sold as
metallurgical coal to the steel market. If demand for metallurgical coal
declined to the point where we could earn a more attractive return marketing the
coal as steam coal, these mines may not be economically viable and may be
subject to closure. Such closures would lead to accelerated reclamation costs,
as well as reduced revenue and profitability.
 
 Additionally,
while we have committed and priced the vast majority of our planned shipments of
coal production for next year, 61%, or approximately 900,000 tons, of our
uncommitted tonnage for 2010 is metallurgical coal.
 
 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.
 
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  Table of contents
 
 For
these reasons, estimates of the economically recoverable quantities and
qualities attributable to any particular group of properties, classifications of
reserves based on risk of recovery and estimates of net cash flows expected from
particular reserves prepared by different engineers or by the same engineers at
different times may vary substantially. Actual coal tonnage recovered from
identified reserve areas or properties, and revenues and expenditures with
respect to our reserves, may vary materially from estimates. These estimates,
thus, may not accurately reflect our actual reserves. Any inaccuracy in our
estimates related to our reserves could result in lower than expected revenues,
higher than expected costs or decreased profitability.
 
 Disruptions
in transportation services could limit our ability to deliver coal to our
customers, which could cause revenues to decline.
 
 We
depend primarily upon railroads, trucks and barges to deliver coal to our
customers. Disruption of railroad service due to weather-related problems,
strikes, lockouts and other events could temporarily impair our ability to
supply coal to our customers, resulting in decreased shipments and related sales
revenues. Decreased performance levels over longer periods of time could cause
our customers to look elsewhere for their fuel needs, negatively affecting our
revenues and profitability.
 
 Several
of our mines depend on a single transportation carrier or a single mode of
transportation. Disruption of any of these transportation services due to
weather-related problems, mechanical difficulties, strikes, lockouts,
bottlenecks and other events could temporarily impair our ability to supply coal
to our customers. Our transportation providers may face difficulties in the
future that may impair our ability to supply coal to our customers, resulting in
decreased revenues.
 
 If
there are disruptions of the transportation services provided by our primary
rail carriers that transport our produced coal and we are unable to find
alternative transportation providers to ship our coal, our business could be
adversely affected.
 
 Fluctuations
in transportation costs could impair our ability to supply coal to our
customers.
 
 Transportation
costs represent a significant portion of the total cost of coal for our
customers and, as a result, the cost of transportation is a critical factor in a
customer’s purchasing decision. Increases in transportation costs could make
coal a less competitive source of energy or could make our coal production less
competitive than coal produced from other sources.
 
 Conversely,
significant decreases in transportation costs could result in increased
competition from coal producers in other parts of the country. For instance,
coordination of the many eastern loading facilities, the large number of small
shipments, the steeper average grades of the terrain and a more unionized
workforce are all issues that combine to make shipments originating in the
eastern United States inherently more expensive on a per-mile basis than
shipments originating in the western United States. The increased competition
could have a material adverse effect on our business, financial condition and
results of operations.
 
 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.
 
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 The
unavailability of an adequate supply of coal reserves that can be mined at
competitive costs could cause our profitability to decline.
 
 Our
profitability depends substantially on our ability to mine coal reserves that
have the geological characteristics that enable them to be mined at competitive
costs and to meet the quality needed by our customers. Because our reserves
decline as we mine our coal, our future success and growth depend, in part, upon
our ability to acquire additional coal reserves that are economically
recoverable. Replacement reserves may not be available when required or, if
available, may not be capable of being mined at costs comparable to those
characteristic of the depleting mines. We may not be able to accurately assess
the geological characteristics of any reserves that we acquire, which may
adversely affect our profitability and financial condition. Exhaustion of
reserves at particular mines also may have an adverse effect on our operating
results that is disproportionate to the percentage of overall production
represented by such mines. Our ability to obtain other reserves in the future
could be limited by restrictions under our existing or future debt agreements,
competition from other coal companies for attractive properties, the lack of
suitable acquisition candidates or the inability to acquire coal properties on
commercially reasonable terms.
 
 Unexpected
increases in raw material costs or decreases in availability could significantly
impair our operating profitability.
 
 Our
coal mining operations use significant amounts of steel, rubber, petroleum
products and other raw materials in various pieces of mining equipment, supplies
and materials. Scrap steel prices have risen significantly and, historically,
the prices of scrap steel and petroleum have fluctuated. There may be other acts
of nature, terrorist attacks or threats or other conditions that could also
increase the costs of raw materials. If the price of steel, rubber, petroleum
products or other of these materials increase, our operational expenses will
increase, which could have a significant negative impact on our profitability.
Additionally, shortages in raw materials used in the manufacturing of supplies
and mining equipment could limit our ability to obtain such items which could
have an adverse effect on our ability to carry out our business
plan.
 
 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 was 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, civil litigation by various claimants has
been initiated 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, the impact of
litigation commenced against us and any claims that may be asserted against us
that are not covered, in whole or in part, by our insurance
policies.
 
 A
shortage of skilled labor in the mining industry could pose a risk to achieving
optimal labor productivity and competitive costs, which could adversely affect
our profitability.
 
 Efficient
coal mining using modern techniques and equipment requires skilled laborers,
preferably with at least a year of experience and proficiency in multiple mining
tasks. In order to support our planned expansion opportunities, we intend to
continue sponsoring both in-house and vocational coal mining programs at the
local level in order to train additional skilled laborers. A tight labor market
in 2008 led to the need to offer more competitive compensation packages. As a
result, $15.48 of our cost of coal sales per ton in 2009 was attributable
to labor and benefits, compared to $12.68 for 2008. In the event that a shortage
of experienced labor were to arise or we are unable to train the necessary
amount of skilled laborers, there could be an adverse impact on our labor
productivity and costs and our ability to expand production, which could have a
material adverse effect on our earnings.
 
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  Table of contents
 
 Our
ability to operate our company effectively could be impaired if we fail to
attract and retain key personnel.
 
 Our
senior management team averages 25 years of experience in the coal industry,
which includes developing innovative, low-cost mining operations, maintaining
strong customer relationships and making strategic, opportunistic acquisitions.
The loss of any of our senior executives could have a material adverse effect on
our business. There may be a limited number of persons with the requisite
experience and skills to serve in our senior management positions. We may not be
able to locate or employ qualified executives on acceptable terms. In addition,
as our business develops and expands, we believe that our future success will
depend greatly on our continued ability to attract and retain highly skilled
personnel with coal industry experience. Competition for these persons in the
coal industry is intense and we may not be able to successfully recruit, train
or retain qualified personnel. We may not be able to continue to employ key
personnel or attract and retain qualified personnel in the future. Our failure
to retain or attract key personnel could have a material adverse effect on our
ability to effectively operate our business.
 
 Acquisitions
that we may undertake involve a number of inherent risks, any of which could
cause us not to realize the anticipated benefits.
 
 We
continually seek to expand our operations and coal reserves through selective
acquisitions. If we are unable to successfully integrate the companies,
businesses or properties we acquire, our profitability may decline and we could
experience a material adverse effect on our business, financial condition or
results of operations. Acquisition transactions involve various inherent risks,
including:
 
 •
              uncertainties
      in assessing the value, strengths and potential profitability of, and
      identifying the extent of all weaknesses, risks, contingent and other
      liabilities (including environmental or mine safety liabilities) of,
      acquisition candidates;•
              potential
      loss of key customers, management and employees of an acquired
      business;•
              ability
      to achieve identified operating and financial synergies anticipated to
      result from an acquisition;•
              discrepancies
      between the estimated and actual reserves of the acquired
      business;•
              problems
      that could arise from the integration of the acquired business;
      and•
              unanticipated
      changes in business, industry or general economic conditions that affect
      the assumptions underlying our rationale for pursuing the
      acquisition.
 
 Any
one or more of these factors could cause us not to realize the benefits
anticipated to result from an acquisition. Any acquisition opportunities we
pursue could materially affect our liquidity and capital resources and may
require us to incur indebtedness, seek equity capital or both. In addition,
future acquisitions could result in our assuming more long-term liabilities
relative to the value of the acquired assets than we have assumed in our
previous acquisitions.
 
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  Table of contents
 
 Risks
inherent to mining could increase the cost of operating our
business.
 
 Our
mining operations are subject to conditions that can impact the safety of our
workforce or delay coal deliveries or increase the cost of mining at particular
mines for varying lengths of time. These conditions include:
 
 •
              fires
      and explosions from methane gas or coal dust;•
              accidental
      minewater discharges;•
              weather,
      flooding and natural disasters;•
              unexpected
      maintenance problems;•
              key
      equipment failures;•
              variations
      in coal seam thickness;•
              variations
      in the amount of rock and soil overlying the coal deposit;
    and•
              variations
      in rock and other natural materials and variations in geologic
      conditions.
 
 We
maintain insurance policies that provide limited coverage for some of these
risks, although there can be no assurance that these risks would be fully
covered by our insurance policies. Despite our efforts, significant mine
accidents could occur and have a substantial impact. 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 FASB Accounting Standards
Codification (“ASC”) Topic 740,Income Taxes (“ASC
740”), record any
resulting adjustments that may be required to deferred income tax expense. In
addition, we will reduce the deferred income tax asset for the benefits of NOL
and tax credit carryforwards used in future periods and will recognize and
record federal and state income tax expense at statutory rates in future
periods. If, in the future, we determine that it is more likely than not that we
will not realize all or a portion of the deferred tax assets, we will record a
valuation allowance against deferred tax assets which would result in a charge
to income tax expense.
 
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 Failure
to obtain or renew surety bonds in a timely manner and on acceptable terms could
affect our ability to secure reclamation and coal lease obligations, which could
adversely affect our ability to mine or lease coal.
 
 Federal
and state laws require us to obtain surety bonds to secure payment of certain
long-term obligations, such as mine closure or reclamation costs and federal and
state workers’ compensation costs. Certain business transactions, such as coal
leases and other obligations, may also require bonding. These bonds are
typically renewable annually. Surety bond issuers and holders may not continue
to renew the bonds or may demand additional collateral or other less favorable
terms upon those renewals. The ability of surety bond issuers and holders to
demand additional collateral or other less favorable terms has increased as the
number of companies willing to issue these bonds has decreased over time. Our
failure to maintain, or our inability to acquire, surety bonds that are required
by state and federal law would affect our ability to secure reclamation and coal
lease obligations, which could adversely affect our ability to mine or lease
coal. That failure could result from a variety of factors including, without
limitation:
 
 •
              lack
      of availability, higher expense or unfavorable market terms of new
      bonds;•
              restrictions
      on availability of collateral for current and future third-party surety
      bond issuers under the terms of our amended and restated credit facility;
      and•
              exercise
      by third-party surety bond issuers of their right to refuse to renew the
      surety.
 
 Failure
to maintain capacity for required letters of credit could limit our ability to
obtain or renew surety bonds.
 
 At
December 31, 2009, we had $73.6 million of letters of credit in place, of
which $61.1 million serve as collateral for reclamation surety bonds and
$12.5 million secured 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 requires continued capital investment, which we may be unable to
provide.
 
 Our
business strategy requires continued capital investment for, among other
purposes, managing acquired assets, acquiring new equipment, maintaining the
condition of our existing equipment and maintaining compliance with
environmental laws and regulations. To the extent that cash generated internally
and cash available under our credit facilities are not sufficient to fund
capital requirements, we will require additional debt and/or equity financing.
However, this type of financing may not be available, 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.
 
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  Table of contents
  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 we 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.”
 
 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 2008, however, the top
ten coal producers’ share had increased to approximately 66% of total domestic
coal production. Consequently, many of our competitors in the domestic coal
industry are major coal producers who have significantly greater financial
resources than us. The intense competition among coal producers may impact our
ability to retain or attract customers and may therefore adversely affect our
future revenues and profitability.
 
 The
demand for U.S. coal exports is dependent upon a number of factors outside of
our control, including the overall demand for electricity in foreign markets,
currency exchange rates, ocean freight rates, the demand for foreign-produced
steel both in foreign markets and in the U.S. market (which is dependent in part
on tariff rates on steel), general economic conditions in foreign countries,
technological developments and environmental and other governmental regulations
and any other pressures placed on companies that are connected to the emission
of greenhouse gases. If foreign demand for U.S. coal were to decline, this
decline could cause competition among coal producers in the United States to
intensify, potentially resulting in additional downward pressure on domestic
coal prices.
 
 Our
ability to collect payments from our customers could be impaired if their
creditworthiness deteriorates.
 
 Our
ability to receive payment for coal sold and delivered depends on the continued
creditworthiness of our customers. Our customer base is changing with an
increasing focus on metallurgical sales to domestic and export steel customers.
Despite the recent improvement in steel output, the steel industry experienced a
dramatic downturn in late 2008 that continued for most of 2009. Most of the
industry experienced steep losses during the period, thus if the current
recovery does not continue our ability to collect from some of our customers
could be impaired.
 
 Continued
deregulation by our utility customers that sell their power plants to their
non-regulated affiliates or third parties that may be less creditworthy, thereby
increasing the risk we bear on payment default. These new power plant owners may
have credit ratings that are below investment grade. Further, competition with
other coal suppliers could force us to extend credit to customers and on terms
that could increase the risk we bear on payment default.
 
 We
sometimes 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 can increase the time it takes to collect
accounts receivable.
 
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  Table of contents
  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.
 
 41
  Table of contents
  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 a class action lawsuit that alleges
that the registration statements filed in connection with our initial public
offering contained false and misleading statements, and that investors relied
upon those securities filings and suffered damages as a result. Some actions
brought against us from time to time may have merit. 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.
 
 Risks
Relating to Government Regulation
 
 Extensive
government regulations impose significant costs on our mining operations, and
future regulations could increase those costs or limit our ability to produce
and sell coal.
 
 The
coal mining industry is subject to increasingly strict regulation by federal,
state and local authorities with respect to matters such as:
 
 •
              limitations
      on land use;•
              employee
      health and safety;•
              mandated
      benefits for retired coal miners;•
              mine
      permitting and licensing requirements;•
              reclamation
      and restoration of mining properties after mining is
      completed;•
              air
      quality standards;•
              water
      pollution;•
              construction
      and permitting of facilities required for mining operations, including
      valley fills and other structures, including those constructed in natural
      water courses and wetlands;•
              protection
      of human health, plantlife and wildlife;•
              discharge
      of materials into the environment;•
              surface
      subsidence from underground mining; and•
              effects
      of mining on groundwater quality and
  availability.
 
 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.
 
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  Table of contents
 
 Under
federal law, each coal mine operator must secure payment of federal black lung
benefits to claimants who are current and former employees and contribute to a
trust fund for the payment of benefits and medical expenses to claimants who
last worked in the coal industry before July 1973. The trust fund is funded by
an excise tax on coal production. If this tax increases, or if we could no
longer pass it on to the purchaser of our coal under many of our long-term sales
contracts, it could increase our operating costs and harm our results. Recently,
there has been a renewed focus on rates of black lung disease among coal
workers. As a result, there may be greater federal scrutiny of the industry that
could lead to new and more costly regulation which may increase our cost of
contributions to the trust fund.
 
 The
costs, liabilities and requirements associated with existing and future
regulations may be costly and time-consuming and may delay commencement or
continuation of exploration or production operations. Failure to comply with
these regulations may result in the assessment of administrative, civil and
criminal penalties, the imposition of cleanup and site restoration costs and
liens, the issuance of injunctions to limit or cease operations, the suspension
or revocation of permits and other enforcement measures that could have the
effect of limiting production from our operations. We may also incur costs and
liabilities resulting from claims for damages to property or injury to persons
arising from our operations. We must compensate employees for work-related
injuries. If we do not make adequate provisions for our workers’ compensation
liabilities, it could harm our future operating results. If we are pursued for
these sanctions, costs and liabilities, our mining operations and, as a result,
our profitability could be adversely affected. See “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.
 
 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 related to
both surface and underground mining also require the development of valley
fills. We obtain permits to construct and operate valley fills and surface
impoundments from the Army Corps of Engineers (the “ACOE”) under the auspices of
Section 404 of the federal Clean Water Act. Lawsuits challenging the ACOE’s
authority to authorize surface mining activities under Nationwide Permit 21
(“NWP21”) 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.
 
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  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. In June
2007, Judge Chambers 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. 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. On August 26, 2009, the
environmental groups petitioned the Supreme Court for a writ of certiorari.
Additionally, in November 2009, Judge Chambers invalidated two additional
permits in a parallel case based on a finding that the public notices of the
applications did not provide sufficient information on the proposed mitigation
plan to allow meaningful public comment.
 
 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 Hazard’s Thunder Ridge
surface mine. Hazard intervened in the suit to protect our interests. A
settlement was negotiated between Hazard and the plaintiffs that allows Hazard
the use of the remaining valley fill in exchange for revisions to certain
portions of the revegetation plan and a donation of $50,000 to a local watershed
improvement project. The federal court on November 20, 2009 entered a
“Stipulation of Voluntary Dismissal” that ended the litigation. See “Legal
Proceedings” contained in Item 3 of this Annual Report on Form
10-K.
 
 Litigation of this type, which is designed to prevent or delay the issuance of
permits needed for mining or to make permit or regulatory standards more
stringent, whether brought directly against us or against governmental agencies
that establish environmental standards and issue permits, could greatly lengthen
the time needed to permit the mining of reserves, significantly increase our
operating costs, make it more difficult to economically recover a significant
portion of our reserves and lead to a material adverse effect on our financial
condition and results of operation.  We may not be able to increase the
price of our coal to cover higher production costs without reducing customer
demand for our coal.
 
 New
government regulations as a result of recent mining accidents 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.
 
 44
  Table of contents
 
 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.
 
 Federal or state legislation that restricts disposal of mining spoil material or
coal refuse material could eliminate certain mining methods, significantly
increase our operating costs and materially harm our financial condition and
operating results.
 
 The U.S. Congress and state legislatures have in the past and are currently
considering proposals that would effectively prohibit the placement of materials
generated by coal mining into waters of the United States, which practice is
essential to surface mining in central Appalachia. A prohibition against excess
spoil placement in streams would essentially eliminate surface mining in steep
terrain, thus rendering much of our coal reserves unmineable. Restrictions on
the placement of coal refuse material in streams or in abandoned underground
coal mines could limit the life of existing coal processing operations,
potentially block new coal preparation plants and at minimum significantly
increase our operating costs. Public concerns regarding the environmental,
health and aesthetic impacts of surface mining could, independent of regulation,
affect our reputation and reduce demand for our coal.
 
 Revision of the federal stream buffer zone regulation to restrict disposal of
mining spoil material or coal refuse material could eliminate certain mining
methods, significantly increase our operating costs and materially harm our
financial condition and operating results.
 
 On November 30, 2009, the Office of Surface Mining published an Advance Notice
of Proposed Rulemaking announcing its intent to revise the stream buffer zone
rule. Certain of the proposed alternatives would effectively prohibit the
placement of materials generated by coal mining into intermittent or perennial
streams, which practice is essential to surface mining in central Appalachia. A
prohibition against excess spoil placement in such streams would essentially
eliminate surface mining in steep terrain, thus rendering much of our coal
reserves unmineable. Restrictions on the placement of coal refuse material in
such streams could limit the life of existing coal processing operations,
potentially block new coal preparation plants and at minimum significantly
increase our operating costs.
 
 We must obtain governmental permits and approvals for mining operations, which
can be a costly and time-consuming process, can result in restrictions on our
operations and is subject to litigation that may delay or prevent us from
obtaining necessary permits.
 
 Our operations are principally regulated under surface mining permits issued
pursuant to the Surface Mining Control and Reclamation Act and state counterpart
laws. Such permits are issued for terms of five years with the right of
successive renewal. Separately, the Clean Water Act requires permits for
operations that discharge into waters of the United States. Valley fills and
refuse impoundments are authorized under permits issued by the ACOE. The EPA has
the authority, which it has rarely exercised until recently, to object to
permits issued by the ACOE. While the ACOE is authorized to issue permits
even when the EPA has objections, the EPA does have the ability to override the
ACOE decision and veto the permits.
 
 45
  Table of contents
 
 Under the provisions of a Memorandum of Understanding executed on June 11, 2009
between the EPA, the ACOE and the Department of the Interior, the ACOE intends
to suspend the use of NWP21 for surface mining activities in Appalachia while
NWP21 is modified to prohibit its use to authorize discharges of dredged or fill
material into waters of the United States for surface coal mining activities in
the Appalachian region of the following states: Kentucky, Ohio, Pennsylvania,
Tennessee, Virginia and West Virginia. In September 2009, the EPA announced 79
pending Clean Water Act 404 permit applications for Appalachian coal mining
warranted further review because of continuing concerns about water quality
and/or regulatory compliance issues. These include four of our permit
applications. One of the permit applications is for our Jennie Creek
surface mine. The failure to issue a Section 404 permit would prevent
the planned commencement of the Jennie Creek surface mine. Operating
alternatives to the other three applications under further review
exist, although the alternatives are less economical than the proposed
projects. While the EPA has stated that its identification of these 79 permits
does not constitute a determination that the mining involved cannot be permitted
under the Clean Water Act and does not constitute a final recommendation from
the EPA to the ACOE on these projects, it is unclear how long the further review
will take for our four permits or what the final outcome will be. It
is also unclear what impact this process may have on our future applications for
surface coal mining permits. Permitting under the Clean Water Act has been a
frequent subject of litigation by environmental advocacy groups that has
resulted in periodic delays in such permits issued by the ACOE. Excessive delays
in permitting may require adjustments of our production budget and mining
plans.
 
 Additionally, certain operations (particularly preparation plants) have permits
issued pursuant to the Clean Air Act and state counterpart laws allowing and
controlling the discharge of air pollutants. Regulatory authorities exercise
considerable discretion in the timing of permit issuance. Requirements imposed
by these authorities may be costly and time-consuming and may result in delays
in, or in some instances preclude, the commencement or continuation of
development or production operations. Adverse outcomes in lawsuits challenging
permits or failure to comply with applicable regulations could result in the
suspension, denial or revocation of required permits, which could have a
material adverse impact on our financial condition, results of operations or
cash flows.
 
 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. Furthermore,
in the current regulatory environment, with enhanced scrutiny by regulators,
increased opposition by environmental groups and others and potential resultant
delays and permit application denials, we now anticipate that mining permit
approvals will take even longer than previously experienced, and some permits
may not be issued at all.Accordingly, the permits we need may not be
issued, maintained or renewed, 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.
 
 If
the assumptions underlying our reclamation and mine closure obligations are
materially inaccurate, we could be required to expend greater amounts than
anticipated.
 
 The
SMCRA establishes operational, reclamation and closure standards for all aspects
of surface mining, as well as the surface effects of deep mining. Estimates of
our total reclamation and mine closure liabilities are based upon permit
requirements, engineering studies and our engineering expertise related to these
requirements. The estimate of ultimate reclamation liability is reviewed
periodically by our management and engineers. The estimated liability can change
significantly if actual costs vary from assumptions or if governmental
regulations change significantly. Asset retirement obligations are recorded as a
liability based on fair value, which is calculated as the present value of the
estimated future cash flows. In estimating future cash flows, we considered the
estimated current cost of reclamation and applied inflation rates and a
third-party profit, as necessary. The third-party profit is an estimate of the
approximate markup that would be charged by contractors for work performed on
behalf of us. The resulting estimated reclamation and mine closure obligations
could change significantly if actual amounts change significantly from our
assumptions.
 
 46
  Table of contents
  Our
operations may substantially impact the environment or cause exposure to
hazardous materials, and our properties may have significant environmental
contamination, any of which could result in material liabilities to
us.
 
 We
use, and in the past have used, hazardous materials and generate, and in the
past have generated, hazardous wastes. In addition, many of the locations that
we own or operate were used for coal mining and/or involved hazardous materials
usage either before or after we were involved with those locations. We may be
subject to claims under federal and state statutes and/or common law doctrines
for personal injury, property damages, natural resource damages and other
damages, as well as the investigation and clean up of soil, surface water,
groundwater and other media. Such claims may arise, for example, out of current
or former activities at sites that we own or operate currently, as well as at
sites that we or predecessor entities owned or operated in the past, and at
contaminated sites that have always been owned or operated by third parties. Our
liability for such claims may be joint and several, so that we may be held
responsible for more than our share of the remediation costs or other damages,
or even for the entire share. We have from time to time been subject to claims
arising out of contamination at our own and other facilities and may incur such
liabilities in the future.
 
 We
use, and in the past have used, alkaline CCBs during the reclamation process at
certain of our mines to aid in preventing the formation of acid mine drainage
and we have agreed to dispose of CCBs in some instances. Use of CCBs on a mined
area is subject to regulatory approval and is allowed only after it is proved to
be a beneficial use. The EPA has announced that it will issue a proposed rule to
regulate the disposal of CCBs under the Resource Conservation and Recovery Act.
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 or disposing of CCBs at certain of our
mines and find a replacement alkaline material for this purpose, which may add
to the cost of mine reclamation or decrease our revenue generated from disposal
contracts with certain of our customers.
 
 We
maintain extensive coal slurry impoundments at a number of our mines. Such
impoundments are subject to stringent regulation. Slurry impoundments maintained
by other coal mining operations have been known to fail, releasing large volumes
of coal slurry. Structural failure of an impoundment can result in extensive
damage to the environment and natural resources, such as bodies of water that
the coal slurry reaches, as well as liability for related personal injuries and
property damages and injuries to wildlife. Some of our impoundments overlie
mined out areas, which can pose a heightened risk of failure and of damages
arising out of failure, unless preventive measures are implemented in a timely
manner. We have commenced such measures to modify our method of operation at one
surface impoundment containing slurry wastes in order to reduce the risk of
releases to the environment from it, a process that has been incorporated into
the construction sequence of the impoundment and thus will take several years to
complete. If one of our impoundments were to fail, we could be subject to
substantial claims for the resulting environmental contamination and associated
liability, as well as for fines and penalties.
 
 These
and other impacts that our operations may have on the environment, as well as
exposures to hazardous substances or wastes associated with our operations and
environmental conditions at our properties, could result in costs and
liabilities that would materially and adversely affect us.
 
 Extensive
environmental regulations affect our customers and could reduce the demand for
coal as a fuel source and cause our sales to decline.
 
 The
Clean Air Act and similar state and local laws extensively regulate the amount
of sulfur dioxide, particulate matter, nitrogen oxides and other compounds
emitted into the air from coke ovens and electric power plants, which are the
largest end users of our coal. Such regulations will require significant
emissions control expenditures for many coal-fired power plants to comply with
applicable ambient air quality standards. As a result, these generators may
switch to other fuels that generate less of these emissions, possibly reducing
future demand for coal and the construction of coal-fired power
plants.
 
 47
  Table of contents
 
 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 significant reductions
in emissions from coal-fired utilities. More stringent emissions standards may
require many coal-fired sources to install additional pollution control
equipment, such as wet scrubbers. Increasingly, the EPA has been undertaking
multi-pollutant rulemakings to reduce emissions from coal-fired utilities. The
EPA has also announced that it will issue a proposed rule to regulate the
disposal of CCBs under the Resource Conservation and Recovery Act. These and
other future standards could have the effect of making the operation of
coal-fired plants less profitable, thereby decreasing demand for coal. The
majority of our coal supply agreements contain provisions that allow a purchaser
to terminate its contract if legislation is passed that either restricts the use
or type of coal permissible at the purchaser’s plant or results in specified
increases in the cost of coal or its use.
 
 There
have been several recent proposals in Congress that are designed to further
reduce emissions of sulfur dioxide, nitrogen oxides and mercury from power
plants, and certain ones could regulate additional air pollutants. If such
initiatives are enacted into law, power plant operators could choose fuel
sources other than coal to meet their requirements, thereby reducing the demand
for coal.
 
 A
regional haze program initiated by the EPA to protect and to improve visibility
at and around national parks, national wilderness areas and international parks
restricts the construction of new coal-fired power plants whose operation may
impair visibility at and around federally protected areas, and may require some
existing coal-fired power plants to install additional control measures designed
to limit haze-causing emissions.
 
 New
and pending laws regulating the environmental effects of emissions of greenhouse
gases could impose significant additional costs to doing business for the coal
industry and/or a shift in consumption to non-fossil fuels.
 
 Greenhouse
gas emissions have increasingly become the subject of a large amount of
international, national, regional, state and local attention. Future regulation
of greenhouse gas could occur pursuant to future U.S. treaty obligations,
statutory or regulatory changes under the Clean Air Act or new climate change
legislation, such as The American Clean Energy and Security Act of 2009, which
was passed by the U.S. House of Representatives. Increased efforts to control
greenhouse gas emissions, could result in reduced demand for coal if electric
power generators switch to lower carbon sources of fuel.
 
 48
  Table of contents
 
 Coal-fired
power plants can generate large amounts of greenhouse gas emissions, and, as a
result, have become subject to challenge, including the opposition to any new
coal-fired power plants or capacity expansions of existing plants, by
environmental groups seeking to curb the environmental effects of emissions of
greenhouse gases. Various legislation has been and 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 greenhouse gas emissions from coal-fired power plants,
instituting a tax on greenhouse gas emissions, banning the construction of new
coal-fired power plants that are not equipped with technology to capture and
sequester carbon dioxide, encouraging the growth of renewable energy sources
(such as wind or solar power) or nuclear for electricity production, and
financing the development of advanced coal burning plants which have greatly
reduced greenhouse gas emissions. Most states in the United States have taken
steps to regulate greenhouse gas emissions. Under the Clean Air Act, the EPA has
published its finding that greenhouse gases pose a threat to public health and
declared that a combination of six greenhouse gases constitutes an air
pollutant. The EPA has already proposed regulations that would impact major
stationary sources of greenhouse gas emissions, including coal-fired power
plants, that could come into effect as early as March 2010.
 
 These
or additional state or federal laws or regulations regarding greenhouse gas
emissions or other actions to limit greenhouse gas emissions could result in
fuel switching, from coal to other fuel sources, by electric generators.
Political and regulatory uncertainty over future emissions controls have been
cited as major factors in decisions by power companies to postpone new
coal-fired power plants. If measures such as these or other similar measures,
like controls on methane emissions from coal mines, are ultimately imposed on
the coal industry by federal or state governments or pursuant to international
treaty, our operating costs may be materially and adversely affected. Similarly,
alternative fuels (non-fossil fuels) could become more attractive than coal in
order to reduce greenhouse gas emissions, which could result in a reduction in
the demand for coal and, therefore, our revenues. Public concerns regarding
climate change could, independent of regulatory developments, adversely affect
our reputation and reduce demand for our coal.
 
 Risks
Relating to Our Common Stock
 
 The
market price of our common stock may be volatile, which could cause the value of
our common stock to decline.
 
 The
market price of our common stock has experienced, and may continue to
experience, significant volatility. Between January 1, 2008 and December
31, 2009, the trading price of our common stock on the New York Stock
Exchange ranged from a low of $1.09 per share to a high of $13.90 per share.
There are numerous factors contributing to the market price of our common stock,
including many over which we have no control. These risks include, among other
things:
 
 •
              our
      operating and financial performance and prospects;•
              our
      ability to repay our debt;•
              investor
      perceptions of us and the industry and markets in which we
      operate;•
              changes
      in earnings estimates or buy/sell recommendations by analysts;
      and•
              general
      financial, domestic, international, economic and other market
      conditions.
 
 49
  Table of contents
 
 In
addition, the stock market in recent years has experienced extreme price and
trading volume fluctuations that often have been unrelated or disproportionate
to the operating performance of individual companies. These broad market
fluctuations may adversely affect the price of our common stock, regardless of
our operating performance. Furthermore, stockholders may initiate securities
class action lawsuits if the market price of our stock drops significantly,
which may cause us to incur substantial costs and could divert the time and
attention of our management.
 
 Sales
of additional shares of our common stock could cause the price of our common
stock to decline.
 
 Sales
of substantial amounts of our common stock in the public market, or the
perception that those sales may occur, could adversely affect the price of our
common stock. In addition, future issuances of equity securities, including
pursuant to our shelf registration statement or the exercise of options, could
dilute the interests of our existing stockholders and could cause the market
price for our common stock to decline. We may issue equity securities in the
future for a number of reasons, including financing our operations and business
strategy, to adjust our ratio of debt to equity, or to satisfy our obligations
upon the exercise of outstanding warrants or options.
 
 As
of December 31, 2009, there were:
 
 •
              5,034,610
      shares of common stock issuable upon the exercise of stock options
      outstanding at a weighted-average exercise price of
  $5.00;•
              1,148,479
      shares of restricted stock subject to continuing vesting requirements;
      and•
              230,265
      restricted share units issued to directors to be converted to common stock
      upon separation of service.
 
 Our
leverage may harm our financial condition and results of
operations.
 
 Our
total consolidated long-term debt as of December 31, 2009 was approximately
$366.5 million. Our level of debt could have important consequences on our
future operations, including:
 
 •
              making
      it more difficult for us to meet our payment and other obligations under
      our outstanding senior and convertible notes and our other outstanding
      debt;•
              resulting
      in an event of default if we fail to comply with the financial and other
      restrictive covenants contained in our debt agreements, which could result
      in all of our debt becoming immediately due and
payable;•
              subjecting
      us to the risk of increased sensitivity to interest rate increases on our
      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
we or our subsidiaries incur additional debt, 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.
 
 50
  Table of contents
 
 Our
ability to pay principal and interest on and to refinance our debt depends upon
the operating performance of our subsidiaries, which will be affected by, among
other things, general economic, financial, competitive, legislative, regulatory
and other factors, some of which are beyond our control. In particular, economic
conditions could cause the price of coal to fall, our revenue to decline and
hamper our ability to repay our debt.
 
 Our
business may not generate sufficient cash flow from operations and future
borrowings may not be available to us under our senior credit facility or
otherwise in an amount sufficient to enable us to pay our debt, or to fund our
other liquidity needs. We may need to refinance all or a portion of our debt on
or before maturity. We may not be able to refinance any of our debt 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 other financial tests. The indenture governing our
outstanding senior notes and our senior credit facility also restrict our and
our subsidiaries’ ability to:
 
 •
              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 debt 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
  Table of contents
 
 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 notesmay 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 notesare 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 notesin 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 notesare surrendered. We have
$161.5 million of principal amount of convertible senior notesoutstanding. In the
event that a holder elects to convert its convertible senior notes, 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 $161.5 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 notesor 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.
 
 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.
 
 52
  Table of contents
 
 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, 2009, funds sponsored by WL Ross & Co. LLC (“WLR”) own
approximately 14% of our common stock and funds sponsored by Fairfax Financial
Holdings Limited (“Fairfax”) own approximately 26% of our common stock.
Circumstances may occur in which WLR, Fairfax or other major investors may have
an interest in pursuing acquisitions, divestitures or other transactions,
including among other things, taking advantage of certain corporate
opportunities that, in their judgment, could enhance their investment in us or
another company in which they invest. These transactions might involve risks to
our other holders of common stock or adversely affect us or other
investors.
 
 Future
sales of our common stock by our major stockholders may depress our share price
and influence our management policies.
 
 WLR
and Fairfax, which respectively own approximately 14% and 26% of our common
stock as of December 31, 2009, may seek alternatives for the disposition of
shares of our common stock. We have previously granted each of WLR and Fairfax
“demand” and “piggyback” registration rights relating to their shares of our
common stock. Sales of substantial amounts of our common stock in the public
market, or the perception that these sales may occur, could cause the market
price of our common stock to decline. In addition, if either WLR or Fairfax were
to sell its entire holdings to one person, that person could have significant
influence over our management policies.
 
 53
  Table of contents
 
 We
do not intend to pay cash dividends on our common stock in the foreseeable
future.
 
 We
have never declared or paid a cash dividend, and we currently do not anticipate
paying any cash dividends in the foreseeable future, see “Dividend Policy.” 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. If we were to decide in
the future to pay dividends, our ability to do so would be dependent on the
ability of our subsidiaries to make cash available to us, by dividend, debt
repayment or otherwise. 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.


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 297 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 793 million tons of mid- to high-Btu, low and high sulfur coal
located in Kentucky, West Virginia, Maryland, Illinois, Virginia and Ohio. Our
multi-region base and flexible product line allows us to adjust to changing
market conditions and sustain high sales volume by supplying a wide range of
customers.
 
 54
  Table of contents
  Our
total coal reserves could support current production levels for more than 67
years. The following table provides the location of our mining operations and
the type of coal produced at those operations as of December 31,
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(2)
              
              Leased
                Proven
                and
                Probable
                Reserves(2)
              
              Steam
                Proven
                and
                Probable
                Reserves(2)
              
              Metallurgical(2)(3)(4)
                Proven
      and
                Probable
                Reserves(in
      million tons)Northern
      AppalachianVindex
      Energy Corp.
              
              Assigned
              
              O
              
              MD
              
              S
              
              6.53
              
              0.00
              
              6.53
              
              6.53
              
              0.00Unassigned
              
              D
              
              MD
              
              S/UG
              
              58.48
              
              0.34
              
              58.14
              
              38.24
              
              20.24Total
      Vindex Energy Corp.
              
              
              
              
              
              
              
              
              
              65.01
              
              0.34
              
              64.67
              
              44.77
              
              20.24Patriot
      Mining Co.
              
              Assigned
              
              O
              
              WV
              
              S
              
              9.37
              
              0.00
              
              9.37
              
              9.37
              
              0.00Wolf
      Run Mining Buckhannon Division
              
              Assigned
              
              O
              
              WV
              
              UG
              
              27.44
              
              12.38
              
              15.06
              
              14.50
              
              12.94Unassigned
              
              D
              
              WV
              
              UG
              
              30.55
              
              28.82
              
              1.73
              
              0.00
              
              30.55Total
      Wolf Run Mining Buckhannon Division
              
              
              
              
              
              
              
              
              
              57.99
              
              41.20
              
              16.79
              
              14.50
              
              43.49Sentinel
              
              Assigned
              
              O
              
              WV
              
              UG
              
              45.40
              
              30.13
              
              15.27
              
              0.00
              
              45.40Unassigned
              
              D
              
              WV
              
              UG
              
              4.94
              
              4.94
              
              0.00
              
              0.00
              
              4.94Total
      Sentinel
              
              
              
              
              
              
              
              
              
              50.34
              
              35.07
              
              15.27
              
              0.00
              
              50.34CoalQuest
      Development LLC
              
              Unassigned
              
              D
              
              WV
              
              UG
              
              186.09
              
              186.09
              
              0.00
              
              32.71
              
              153.38(Tygart)ICG
      Natural Resources
              
              Unassigned
              
              D
              
              OH
              
              UG
              
              94.25
              
              94.25
              
              0.00
              
              94.25
              
              0.00(Paw
      Paw Creek)Total
      Northern Appalachian
              
              
              
              
              
              
              
              
              
              463.05
              
              356.95
              
              106.10
              
              195.60
              
              267.45Central
      AppalachianEastern
              
              Assigned
              
              O
              
              WV
              
              S
              
              7.47
              
              0.14
              
              7.33
              
              7.47
              
              0.00Unassigned
              
              D
              
              WV
              
              UG
              
              2.18
              
              0.00
              
              2.18
              
              2.18
              
              0.00Total
      Eastern
              
              
              
              
              
              
              
              
              
              9.65
              
              0.14
              
              9.51
              
              9.65
              
              0.00Hazard
              
              Assigned
              
              O
              
              KY
              
              S
              
              54.09
              
              23.11
              
              30.98
              
              54.09
              
              0.00Unassigned
              
              D
              
              KY
              
              UG
              
              10.40
              
              0.65
              
              9.75
              
              10.40
              
              0.00Total
      Hazard
              
              
              
              
              
              
              
              
              
              64.49
              
              23.76
              
              40.73
              
              64.49
              
              0.00Flint
      Ridge
              
              Assigned
              
              O
              
              KY
              
              UG
              
              23.38
              
              0.58
              
              22.80
              
              23.38
              
              0.00Knott County
              
              Assigned
              
              O
              
              KY
              
              UG
              
              14.77
              
              4.21
              
              10.56
              
              14.77
              
              0.00Unassigned
              
              D
              
              KY
              
              UG
              
              3.36
              
              0.85
              
              2.51
              
              3.36
              
              0.00Total Knott County
              
              
              
              
              
              
              
              
              
              18.13
              
              5.06
              
              13.07
              
              18.13
              
              0.00Raven
              
              Assigned
              
              O
              
              KY
              
              UG
              
              10.15
              
              0.00
              
              10.15
              
              10.15
              
              0.00East
      Kentucky
              
              Assigned
              
              O
              
              KY
              
              S
              
              1.57
              
              1.32
              
              0.25
              
              1.57
              
              0.00ICG
      Natural Resources
              
              Assigned
              
              D
              
              WV
              
              S
              
              14.71
              
              0.00
              
              14.71
              
              14.71
              
              0.00Unassigned
              
              D
              
              WV
              
              UG
              
              30.19
              
              2.20
              
              27.99
              
              30.19
              
              0.00(Jennie Creek)Total ICG
      Natural Resources
              
              
              
              
              
              
              
              
              
              44.90
              
              2.20
              
              42.70
              
              44.90
              
              0.00Powell Mountain
              
              Assigned
              
              O
              
              VA
              
              UG
              
              4.85
              
              0.00
              
              4.85
              
              4.85
              
              0.00Unassigned
              
              D
              
              VA
              
              S/UG
              
              22.02
              
              0.00
              
              22.02
              
              22.02
              
              0.00Total Powell Mountain
              
              
              
              
              
              
              
              
              
              26.87
              
              0.00
              
              26.87
              
              26.87
              
              0.00Beckley
              
              Assigned
              
              O
              
              WV
              
              UG
              
              31.28
              
              1.28
              
              30.00
              
              0.00
              
              31.28White
      Wolf Energy, Inc.
              
              Unassigned
              
              D
              
              VA
              
              UG
              
              25.91
              
              0.00
              
              25.91
              
              0.00
              
              25.91(Big Creek)Total
      Central Appalachian
              
              
              
              
              
              
              
              
              
              256.33
              
              34.34
              
              221.99
              
              199.14
              
              57.19Illinois
      BasinIllinois
              
              Assigned
              
              O
              
              IL
              
              UG
              
              46.07
              
              8.50
              
              37.57
              
              46.07
              
              0.00(Viper)ICG
      Natural Resources
              
              Unassigned
              
              D
              
              IL
              
              UG
              
              324.60
              
              324.60
              
              0.00
              
              324.60
              
              0.00Total
      Illinois Basin
              
              
              
              
              
              
              
              
              
              370.67
              
              333.10
              
              37.57
              
              370.67
              
              0.00Total Proven and Probable Reserves
              
              
              
              
              
              
              
              
              
              1,090.05
              
              724.39
              
              365.66
              
              765.41
              
              324.64
 
 
 (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 2009. Similarly, we believe a portion of production from
      Tygart could be sold into the metallurgical market when production
      begins.For
      a description of mining properties, see Item 1. Business under the
      headings “Northern and Central Appalachian Mining Operations” and
      “Illinois Basin Mining Operations.”
 
 55
  Table of contents
  The
following table provides the “quality” (average moisture, ash and sulfur
contents and Btu per pound) of our coal reserves as of December 31,
2009:
 
 As
      Received Quality
              
              Total
      Proven and Probable Reserves(2)Mining
      Operations
              
              Assigned
      or
                Unassigned
      (1)
              
              %
                Moisture
              
              %
                Ash
              
              %
                Sulfur
              
              Btu/lb.
              
              Lbs.
      SO2/
                million Btus
              
              <1.2 lbs.
                SO2
                Compliance
              
              >1.2 lbs
                SO2
                Non-ComplianceNorthern
      AppalachianVindex
      Energy Corp.(4)
              
              Assigned
              
              4.66
              
              19.29
              
              1.82
              
              11,700
              
              3.11
              
              0.00
              
              6.53Unassigned
              
              6.00
              
              13.37
              
              1.85
              
              12,563
              
              2.94
              
              0.00
              
              58.48Total
      Vindex Energy Corp.
              
              
              
              5.87
              
              13.96
              
              1.84
              
              12,477
              
              2.96
              
              0.00
              
              65.01Patriot
      Mining Co.
              
              Assigned
              
              6.00
              
              14.66
              
              3.08
              
              11,869
              
              5.19
              
              0.00
              
              9.37Wolf
      Run Mining Buckhannon Division(4)
              
              Assigned
              
              6.00
              
              8.05
              
              2.22
              
              13,071
              
              3.40
              
              0.00
              
              27.44Unassigned
              
              6.00
              
              8.92
              
              0.99
              
              13,069
              
              1.52
              
              0.00
              
              30.55Total Wolf Run Mining Buckhannon Division
              
              
              
              6.00
              
              8.51
              
              1.57
              
              13,070
              
              2.41
              
              0.00
              
              57.99Sentinel
              
              Assigned
              
              6.00
              
              8.43
              
              1.47
              
              13,180
              
              2.24
              
              0.00
              
              45.40Unassigned
              
              6.00
              
              8.04
              
              1.44
              
              13,353
              
              2.15
              
              0.00
              
              4.94Total
      Sentinel
              
              
              
              6.00
              
              8.39
              
              1.47
              
              13,197
              
              2.23
              
              0.00
              
              50.34CoalQuest
      Development LLC(4)
              
              Unassigned
              
              6.00
              
              9.25
              
              1.15
              
              13,145
              
              1.76
              
              0.00
              
              186.09(Tygart)ICG
      Natural Resources
              
              Unassigned
              
              6.00
              
              7.62
              
              2.07
              
              13,021
              
              3.18
              
              0.00
              
              94.25(Paw
      Paw Creek)Total
      Northern Appalachian
              
              
              
              
              
              
              
              
              
              
              
              
              
              0.00
              
              463.05Central
      AppalachianEastern
              
              Assigned
              
              6.00
              
              14.37
              
              1.23
              
              11,974
              
              2.05
              
              0.00
              
              7.47Unassigned
              
              6.00
              
              9.54
              
              1.23
              
              12,779
              
              1.93
              
              0.00
              
              2.18Total
      Eastern
              
              
              
              6.00
              
              13.28
              
              1.23
              
              12,156
              
              2.02
              
              0.00
              
              9.65Hazard
              
              Assigned
              
              6.00
              
              12.67
              
              1.40
              
              12,055
              
              2.33
              
              0.00
              
              54.09Unassigned
              
              6.00
              
              6.55
              
              0.84
              
              12,890
              
              1.30
              
              0.00
              
              10.40Total
      Hazard
              
              
              
              6.00
              
              11.69
              
              1.31
              
              12,190
              
              2.15
              
              0.00
              
              64.49Flint
      Ridge
              
              Assigned
              
              6.00
              
              8.15
              
              1.39
              
              12,768
              
              2.17
              
              1.33
              
              22.05Knott County
              
              Assigned
              
              6.02
              
              6.94
              
              1.56
              
              13,056
              
              2.39
              
              0.05
              
              14.72Unassigned
              
              6.00
              
              7.07
              
              1.79
              
              13,034
              
              2.75
              
              0.00
              
              3.36Total Knott County
              
              
              
              6.01
              
              6.96
              
              1.60
              
              13,052
              
              2.45
              
              0.05
              
              18.08Raven
              
              Assigned
              
              6.00
              
              7.21
              
              1.35
              
              12,912
              
              2.10
              
              0.00
              
              10.15East
      Kentucky
              
              Assigned
              
              5.94
              
              9.28
              
              0.85
              
              12,441
              
              1.37
              
              0.00
              
              1.57ICG
      Natural Resources
              
              Assigned
              
              7.00
              
              9.65
              
              0.75
              
              12,281
              
              1.22
              
              9.59
              
              5.12Unassigned
              
              7.00
              
              4.92
              
              1.27
              
              13,254
              
              1.92
              
              0.00
              
              30.19(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
              
              4.85
              
              0.00Unassigned
              
              6.00
              
              8.38
              
              2.01
              
              13,194
              
              3.04
              
              6.46
              
              15.56Total Powell Mountain
              
              
              
              6.00
              
              7.57
              
              1.76
              
              13,417
              
              2.62
              
              11.31
              
              15.56Beckley(3)
              
              Assigned
              
              6.00
              
              4.87
              
              0.70
              
              13,913
              
              1.01
              
              31.28
              
              0.00White
      Wolf Energy, Inc.(3)
              
              Unassigned
              
              6.00
              
              4.09
              
              0.63
              
              14,150
              
              0.89
              
              25.91
              
              0.00(Big Creek)Total
      Central Appalachian
              
              
              
              
              
              
              
              
              
              
              
              
              
              79.47
              
              176.86Illinois
      BasinIllinois
              
              Assigned
              
              16.00
              
              8.80
              
              2.86
              
              10,692
              
              5.35
              
              0.00
              
              46.07(Viper)ICG
      Natural Resources
              
              Unassigned
              
              12.75
              
              9.28
              
              2.88
              
              10,963
              
              5.25
              
              0.00
              
              324.60Total
      Illinois Basin
              
              
              
              
              
              
              
              
              
              
              
              
              
              0.00
              
              370.67Total
      Proven and Probable Reserves
              
              
              
              
              
              
              
              
              
              
              
              
              
              79.47
              
              1,010.58
 
 
 (1)
              “Assigned
      reserves” means coal which has been committed by the coal company to
      operating mine shafts, mining equipment and plant facilities, and all coal
      which has been leased by the coal company to others. “Unassigned reserves”
      represent coal which has not been committed, and which would require new
      mine shafts, mining equipment or plant facilities before operations could
      begin in the property. The primary reason for this distinction is to
      inform investors which coal reserves will require substantial capital
      investment before production can begin.(2)
              The
      proven and probable reserves are reported as recoverable reserves, which
      is that part of a coal deposit which could be economically and legally
      extracted or produced at the time of the reserve determination, taking
      into account mining recovery and preparation plant
  yield.(3)
              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 2009. Similarly, we believe a portion of production from
      Tygart could be sold into the metallurgical market when production
      begins.For
      a description of mining properties, see Item 1. Business under the
      headings “Northern and Central Appalachian Mining Operations” and
      “Illinois Basin Mining Operations.”
 
 56
  Table of contents
  Our
reserve estimates are based on geological data assembled and analyzed by our
staff of geologists and engineers. Reserve estimates are periodically updated to
reflect past coal production, new drilling information and other geologic or
mining data. Acquisitions, sales or dispositions of coal properties will also
change the reserve estimates. We estimate that we controlled 1.1 billion tons of
reserves at December 31, 2009. 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 66% of our coal reserves, with the remainder of our
coal reserves subject to leases from third-party landowners. Generally, these
leases convey mining rights to the coal producer in exchange for a percentage of
gross sales in the form of a royalty payment to the lessor, subject to minimum
payments. Leases generally last for the economic life of the reserves. The
average royalties paid by us for coal reserves from our producing properties was
$3.39 per ton in 2009, representing approximately 5.5% (net of freight and
handling) of our coal sales revenue in 2009. Consistent with industry practice,
we conduct only limited investigations of title to our coal properties prior to
leasing. Title to lands and reserves of the lessors or grantors and the
boundaries of our leased priorities are not completely verified until we prepare
to mine those reserves.
 
 Non-Reserve
Coal Deposits
 
 Non-reserve
coal deposits are coal-bearing bodies that have been sufficiently sampled and
analyzed in trenches, outcrops, drilling and underground workings to assume
continuity between sample points and, therefore, warrant further exploration
stage work. However, this coal does not qualify as a commercially viable coal
reserve as prescribed by SEC standards until a final comprehensive evaluation
based on unit cost per ton, recoverability and other material factors concludes
legal and economic feasibility. Non-reserve coal deposits may be classified as
such by limited property control, geologic limitations or both.
 
 57
  Table of contents
 
 The
following table provides the location of our mining operations and the type and
amount of non-reserve coal deposits at those complexes as of December 31,
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
      AppalachianVindex
      Energy Corp.
              
              Unassigned
              
              D
              
              MD
              
              S
              
              0.44
              
              0.00
              
              0.44Wolf
      Run Mining Buckhannon Division
              
              Assigned
              
              O
              
              WV
              
              UG
              
              1.45
              
              1.45
              
              0.00Unassigned
              
              D
              
              WV
              
              UG
              
              2.25
              
              2.25
              
              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(Tygart)Upshur
      Property
              
              Unassigned
              
              
              
              WV
              
              S
              
              92.96
              
              92.96
              
              0.00(Upshur)ICG
      Natural Resources
              
              Unassigned
              
              D
              
              OH
              
              UG
              
              5.77
              
              5.77
              
              0.00(Paw
      Paw Creek)Total
      Northern Appalachian
              
              
              
              
              
              
              
              
              
              143.41
              
              142.97
              
              0.44Central
      AppalachianEastern
              
              Assigned
              
              O
              
              WV
              
              S
              
              0.02
              
              0.02
              
              0.00Hazard
              
              Assigned
              
              O
              
              KY
              
              S
              
              8.02
              
              8.02
              
              0.00Flint
      Ridge
              
              Assigned
              
              O
              
              KY
              
              UG
              
              0.94
              
              0.94
              
              0.00Knott County
              
              Assigned
              
              O
              
              KY
              
              UG
              
              0.48
              
              0.48
              
              0.00ICG
      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
              
              S/UG
              
              21.62
              
              21.62
              
              0.00(Mobil)Powell Mountain
              
              Unassigned
              
              O
              
              VA
              
              UG
              
              46.07
              
              46.07
              
              0.00Beckley
              
              Unassigned
              
              D
              
              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
              
              2.57
              
              2.57
              
              0.00(Big
      Creek)Total
      Central Appalachian
              
              
              
              
              
              
              
              
              
              120.51
              
              118.63
              
              1.88Illinois
      BasinIllinois
              
              Assigned
              
              O
              
              IL
              
              UG
              
              38.47
              
              38.47
              
              0.00(Viper)ICG
      Natural Resources
              
              Unassigned
              
              
              
              IL
              
              UG
              
              57.92
              
              57.92
              
              0.00(Illinois)Total
      Illinois Basin
              
              
              
              
              
              
              
              
              
              96.39
              
              96.39
              
              0.00
 
 58
  Table of contents
  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
      DepositsAncillary
              
              
              
              
              
              
              
              
              
              (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
              
              
              
              MT
              
              S
              
              12.00
              
              12.00
              
              0.00(Montana)Unassigned
              
              
              
              WA
              
              S
              
              9.86
              
              9.86
              
              0.00(Washington)Total
      Ancillary
              
              
              
              
              
              
              
              
              
              71.01
              
              71.01
              
              0.00Total
      Non-Reserve Coal Deposits
              
              
              
              
              
              
              
              431.32
              
              429.00
              
              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 2009. Similarly, we believe a portion of the production
      from Tygart can be sold into the metallurgical market.For
      a description of mining properties, see Item 1. Business under the
      headings “Northern and Central Appalachian Mining Operations” and
      “Illinois Basin Mining Operations.”
 
 The
following table provides the “quality” (average moisture, ash and sulfur
contents and Btu per pound) of our non-reserve coal deposits as of December 31,
2009:
 
 As
      Received QualityMining
      Operations
              
              Assigned
      or
                Unassigned
      (1)
              
              %
                Moisture
              
              %
                Ash
              
              %
                Sulfur
              
              Btu/
      lb.
              
              Lbs. SO2/
                million BtusNorthern
      AppalachianVindex
      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
              
              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
              
              5.00ICG
      Natural Resources
              
              Unassigned
              
              6.00
              
              7.62
              
              2.07
              
              13,021
              
              3.18(Paw
      Paw Creek)Central
      AppalachianEastern
              
              Assigned
              
              6.00
              
              12.20
              
              1.20
              
              12,400
              
              1.94Hazard
              
              Assigned
              
              6.00
              
              13.00
              
              1.17
              
              11,965
              
              1.96Flint
      Ridge
              
              Assigned
              
              6.00
              
              8.15
              
              1.39
              
              12,768
              
              2.18Knott County
              
              Assigned
              
              6.00
              
              6.82
              
              1.90
              
              13,040
              
              2.91ICG
      Natural Resources
              
              Assigned
              
              7.00
              
              7.78
              
              0.63
              
              12,609
              
              1.01(Jennie Creek)ICG
      Natural Resources
              
              Unassigned
              
              6.00
              
              11.47
              
              1.91
              
              11,780
              
              3.24(Martin Co.,
                Muhlenberg Co.)ICG
      Natural Resources
              
              Unassigned
              
              6.00
              
              12.50
              
              1.10
              
              12,000
              
              1.83(Mobil)Powell Mountain
              
              Unassigned
              
              6.00
              
              5.78
              
              1.21
              
              13,348
              
              1.81Beckley(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)
 
 59
  Table of contents
 
 As
      received qualityMining
      operations
              
              Assigned
      or
                Unassigned
      (1)
              
              %
                Moisture
              
              %
                Ash
              
              %
                Sulfur
              
              Btu/
      lb.
              
              Lbs. SO2/
                million BtusIllinois
      BasinIllinois
              
              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)AncillaryICG
      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
              
              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 2009. Similarly, we believe a portion of the production from
      Tygart can be sold into the metallurgical market.For
      a description of mining properties, see Item 1. Business under the
      headings “Northern and Central Appalachian Mining Operations” and
      “Illinois Basin Mining Operations.”


ITEM 3.
            LEGAL
      PROCEEDINGS





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








ITEM 4.
            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, 2009.





60


Table of contents


PART
II





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





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





Stock
      PriceHigh
            
            
            Low2009January 1,
      2009 through March 31, 2009
            
            $
            3.24
            
            
            $
            1.09April 1,
      2009 through June 30, 2009
            
            
            3.70
            
            
            
            1.54July 1,
      2009 through September 30, 2009
            
            
            4.59
            
            
            
            2.24October 1,
      2009 through December 31, 2009
            
            
            5.35
            
            
            
            3.472008January 1,
      2008 through March 31, 2008
            
            $
            7.17
            
            
            $
            4.75April 1,
      2008 through June 30, 2008
            
            
            13.90
            
            
            
            6.00July 1,
      2008 through September 30, 2008
            
            
            13.37
            
            
            
            5.52October 1,
      2008 through December 31, 2008
            
            
            6.19
            
            
            
            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 January 15, 2010, there were approximately 249 holders of record of our
common stock and an additional 46,574 stockholders whose shares were held for
them in street name or nominee accounts.





Summary
of Equity Compensation Plans





Shown
below is information concerning our equity compensation plans and individual
compensation arrangements as of December 31, 2009.





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)
            
            4,715,558
            
            $
            4.60
            
            10,911,409Equity
      compensation plans not approved by stockholders(2)
            
            319,052
            
            
            10.97
            
            —5,034,610
            
            $
            5.00
            
            10,911,409








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





For
additional information regarding our equity compensation plans, refer to the
discussion in Note 13 to the audited consolidated financial statements included
in Item 15 of this Annual Report on Form 10-K.





61


Table of contents


Issuer
Purchases of Equity Securities





Period
            Number
      of Shares Purchased (1)
            
            Average
      Price Paid per Share(1)
            
            Number
      of Shares Purchased as Part of Publicly Announced Plans or
      Programs
            Approximate
      Dollar Value of Shares that May Yet be Purchased Under the Plans or
      ProgramsJanuary
      1, 2009 through January 31, 2009
            —
            
            $
            —
            
            —
            —February
      1, 2009 through February 28, 2009
            —
            
            
            —
            
            —
            —March
      1, 2009 through March 31, 2009
            4,768
            
            
            1.76
            
            —
            —April
      1, 2009 through April 30, 2009
            2,165
            
            
            1.99
            
            —
            —May
      1, 2009 through May 31, 2009
            —
            
            
            —
            
            —
            —June
      1, 2009 through June 30, 2009
            388
            
            
            2.86
            
            —
            —July
      1, 2009 through July 31, 2009
            —
            
            
            —
            
            —
            —August
      1, 2009 through August 31, 2009
            —
            
            
            —
            
            —
            —September
      1, 2009 through September 30, 2009
            —
            
            
            —
            
            —
            —October
      1, 2009 through October 31, 2009
            —
            
            
            —
            
            —
            —November
      1, 2009 through November 30, 2009
            —
            
            
            —
            
            —
            —December
      1, 2009 through December 31, 2009
            —
            
            
            —
            
            —
            —Total
            7,321
            
            $
            2.20
            
            —
            —




(1)
            During
      the year ended December 31, 2009, we withheld 7,321 shares of common stock
      from employees to satisfy estimated tax obligations upon the vesting of
      restricted stock under the terms of our 2005 Equity and Performance
      Incentive Plan. The value of the common stock that was withheld was based
      upon the closing price of our common stock on the applicable vesting
      dates.





Dividend
Policy





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





62


Table of contents




ITEM 6.
            SELECTED
      FINANCIAL DATA





The
selected historical consolidated financial data is derived from International
Coal Group, Inc.’s audited consolidated financial statements as of December 31,
2009 and 2008 and for the years ended December 31, 2009, 2008 and 2007 which is
included elsewhere in this Annual Report on Form 10-K. The selected historical
consolidated financial data of International Coal Group, Inc. as of
December 31, 2007, 2006 and 2005 and for the years ended December 31, 2006
and 2005 is derived from audited consolidated financial statements which are not
included in this Annual Report on Form 10-K.





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





During
the years ended December 31, 2008 and 2007, we recognized impairment losses of
$37.4 million and $170.4 million, respectively. For 2008, $30.2 million of the
loss related to impairment of goodwill at our ADDCAR subsidiary and $7.2 million
related to impairment of long-lived assets. For 2007, the impairment loss
related to impairment of goodwill at various of our business units. See Notes 4
and 5 to our audited consolidated financial statements included in Item 15 of
this Annual Report on Form 10-K for further discussion of the impairment
losses.





63


Table of contents


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





Year
      ended
              December 31,
              2009
            
            
            Year
      ended
              December 31,
              2008
            
            
            Year
      ended
              December 31,
              2007
            
            
            Year
      ended
              December 31,
              2006
            
            
            Year
      ended
              December 31,
              2005(1)Statement
      of Operations Data:Coal
      sales revenues
            
            $
            1,006,606
            
            
            $
            998,245
            
            
            $
            770,663
            
            
            $
            833,998
            
            
            $
            619,038Freight
      and handling revenues
            
            
            26,279
            
            
            
            45,231
            
            
            
            29,594
            
            
            
            18,890
            
            
            
            8,601Other
      revenues
            
            
            92,464
            
            
            
            53,260
            
            
            
            48,898
            
            
            
            38,706
            
            
            
            22,852Total
      revenues
            
            
            1,125,349
            
            
            
            1,096,736
            
            
            
            849,155
            
            
            
            891,594
            
            
            
            650,491Costs
      and Expenses:Cost
      of coal sales and other revenues
            
            
            868,303
            
            
            
            918,655
            
            
            
            766,158
            
            
            
            769,332
            
            
            
            510,097Freight
      and handling costs
            
            
            26,279
            
            
            
            45,231
            
            
            
            29,594
            
            
            
            18,890
            
            
            
            8,601Depreciation,
      depletion and amortization
            
            
            106,084
            
            
            
            96,047
            
            
            
            86,517
            
            
            
            72,218
            
            
            
            43,076Selling,
      general and administrative
            
            
            32,749
            
            
            
            38,147
            
            
            
            33,325
            
            
            
            34,578
            
            
            
            28,828Gain
      on sale of assets
            
            
            (3,659
            )
            
            
            (32,518
            )
            
            
            (38,656
            )
            
            
            (1,125
            )
            
            
            (502
            )Impairment
      loss
            
            
            —
            
            
            
            37,428
            
            
            
            170,402
            
            
            
            —
            
            
            
            —Total
      costs and expenses
            
            
            1,029,756
            
            
            
            1,102,990
            
            
            
            1,047,340
            
            
            
            893,893
            
            
            
            590,100Income
      (loss) from operations
            
            
            95,593
            
            
            
            (6,254
            )
            
            
            (198,185
            )
            
            
            (2,299
            )
            
            
            60,391Interest
      and Other Income (Expense):Loss
      on extinguishment of debt
            
            
            (13,293
            )
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            —Interest
      expense, net
            
            
            (53,044
            )
            
            
            (43,643
            )
            
            
            (35,989
            )
            
            
            (18,091
            )
            
            
            (14,394
            )Other,
      net
            
            
            —
            
            
            
            —
            
            
            
            319
            
            
            
            2,113
            
            
            
            3,302Total
      interest and other income (expense)
            
            
            (66,337
            )
            
            
            (43,643
            )
            
            
            (35,670
            )
            
            
            (15,978
            )
            
            
            (11,092
            )Income
      (loss) before income taxes
            
            
            29,256
            
            
            
            (49,897
            )
            
            
            (233,855
            )
            
            
            (18,277
            )
            
            
            49,299Income
      tax benefit (expense)
            
            
            (7,732
            )
            
            
            23,670
            
            
            
            85,944
            
            
            
            9,015
            
            
            
            (16,986
            )Net
      income (loss)
            
            
            21,524
            
            
            
            (26,227
            )
            
            
            (147,911
            )
            
            
            (9,262
            )
            
            
            32,313Net
      (income) loss attributable to noncontrolling interest
            
            
            (66
            )
            
            
            —
            
            
            
            349
            
            
            
            (58
            )
            
            
            15Net
      income (loss) attributable to International Coal Group,
    Inc.
            
            $
            21,458
            
            
            $
            (26,227
            )
            
            $
            (147,562
            )
            
            $
            (9,320
            )
            
            $
            32,328





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Year
      ended
              December 31,
              2009
            
            
            Year
      ended
              December 31,
              2008
            
            
            Year
      ended
              December 31,
              2007
            
            
            Year
      ended
              December 31,
              2006
            
            
            Year
      ended
              December 31,
              2005(1)Earnings
      Per Share:Basic
            
            $
            0.14
            
            
            $
            (0.17
            )
            
            $
            (0.97
            )
            
            $
            (0.06
            )
            
            $
            0.29Diluted
            
            
            0.14
            
            
            
            (0.17
            )
            
            
            (0.97
            )
            
            
            (0.06
            )
            
            
            0.29Weighted-Average
      Common Shares Outstanding:Basic
            
            
            153,630,446
            
            
            
            152,632,586
            
            
            
            152,304,461
            
            
            
            152,028,165
            
            
            
            111,120,211Diluted
            
            
            155,386,263
            
            
            
            152,632,586
            
            
            
            152,304,461
            
            
            
            152,028,165
            
            
            
            111,161,287Balance
      Sheet Data (at year end):Cash
      and cash equivalents
            
            $
            92,641
            
            
            $
            63,930
            
            
            $
            107,150
            
            
            $
            18,742
            
            
            $
            9,187Total
      assets
            
            
            1,367,960
            
            
            
            1,350,647
            
            
            
            1,303,363
            
            
            
            1,316,891
            
            
            
            1,051,403Long-term
      debt and capital leases
            
            
            384,309
            
            
            
            432,870
            
            
            
            391,248
            
            
            
            180,035
            
            
            
            45,462Total
      liabilities
            
            
            758,726
            
            
            
            841,530
            
            
            
            771,595
            
            
            
            655,326
            
            
            
            383,879Total
      stockholders’ equity
            
            
            609,234
            
            
            
            509,117
            
            
            
            531,768
            
            
            
            661,565
            
            
            
            667,524Total
      liabilities and stockholders’ equity
            
            
            1,367,960
            
            
            
            1,350,647
            
            
            
            1,303,363
            
            
            
            1,316,891
            
            
            
            1,051,403Statement
      of Cash Flows Data:Net
      cash from:Operating
      activities
            
            $
            115,754
            
            
            $
            78,729
            
            
            $
            22,471
            
            
            $
            55,591
            
            
            $
            77,319Investing
      activities
            
            
            (73,158
            )
            
            
            (124,040
            )
            
            
            (126,907
            )
            
            
            (160,769
            )
            
            
            (104,713
            )Financing
      activities
            
            
            (13,885
            )
            
            
            2,091
            
            
            
            192,844
            
            
            
            114,733
            
            
            
            12,614Capital
      expenditures
            
            
            66,345
            
            
            
            132,800
            
            
            
            160,807
            
            
            
            165,658
            
            
            
            108,231








(1)
            On
      November 18, 2005, we completed our reorganization and acquisition of
      Anker and CoalQuest Development LLC (“CoalQuest”). The results of
      operations are included in our consolidated results of operations since
      that date.








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





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





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Table of contents


Overview





We
produce, process and sell coal from 13 regional mining complexes, which, as of
December 31, 2009 were supported by 11 active underground mines, 11 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 included in Item 15 of
this Annual Report on Form 10-K. We also broker coal produced by others, the
majority of which is shipped directly from the third-party producer to the
ultimate customer. Our coal sales are primarily to large utilities and
industrial customers in the Eastern region of the United States and domestic and
international steel companies and brokers. In addition, we generate other
revenues from the manufacture and operation of highwall mining systems, parts
sales and shop services relating to those systems and coal handling and
processing fees.





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





Certain
Trends and Economic Factors Affecting the Coal Industry





Our
revenues depend on the price at which we are able to sell our coal. The pricing
environment for domestic steam and metallurgical coal during 2009 weakened from
the relatively strong pricing experienced throughout much of 2008. Near the end
of 2008 and continuing into 2009, 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.
Accordingly, we have experienced decreased costs for commodities, such as fuel,
explosives and steel products. We did, however, see an increase in our labor and
healthcare costs as a result of wage increases given in late 2008 in an effort
to remain competitive in what had been a tight labor market and an increase in
medical benefits over the prior year. While compensation related costs
increased over 2008, we expect that current economic conditions will reduce
the inflationary pressures that drove up such costs in recent years. Conversely,
we expect to experience higher costs for surety bonds and letters of credit
resulting from more stringent regulatory requirements.





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





Critical
Accounting Policies and Estimates





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





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Table of contents


Revenue
Recognition





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





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





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





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





Accounts
Receivable and Allowance for Doubtful Accounts





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





Reclamation





Our
asset retirement obligations arise from the Federal Surface Mining Control and
Reclamation Act of 1977 and similar state statutes, which require that mine
property be restored in accordance with specified standards and an approved
reclamation plan. We record these reclamation obligations according to the
provisions of ASC Topic 410, Asset Retirement and Environmental
Obligations (“ASC 410”). ASC 410 requires the fair value of a liability
for an asset retirement obligation to be recognized in the period in which the
legal obligation associated with the retirement of the long-lived asset is
incurred. Fair value of reclamation liabilities is determined based on the
present value of the estimated future expenditures. When the liability is
initially recorded, the offset is capitalized by increasing the carrying amount
of the related long-lived asset. Over time, the liability is accreted to its
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 closure activities could be
materially different than currently estimated. To settle the liability, the mine
property is reclaimed and, to the extent there is a difference between the
liability and the amount of cash paid to perform the reclamation, a gain or loss
upon settlement is recognized. On at least an annual basis, we review our entire
reclamation liability and make necessary adjustments for permit changes as
granted by state authorities, additional costs resulting from accelerated mine
closures and revisions to cost estimates and productivity assumptions to reflect
current experience. At December 31, 2009, we had recorded asset retirement
obligation liabilities of $75.0 million, including amounts reported as current
liabilities. While the precise amount of these future costs cannot be determined
with certainty, as of December 31, 2009, we estimate that the aggregate
undiscounted cost of final mine closure is approximately $151
million.





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Table of contents


Advance
Royalties





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





Inventories





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





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





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





Depreciation,
Depletion and Amortization





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





Mine
development, coal lands and mineral rights costs are amortized using the
units-of-production method, based on estimated recoverable tons. There are
uncertainties inherent in estimating quantities of recoverable tons related to
particular mine development, coal lands and mineral rights areas. Recoverable
tons contained in an area are based on engineering estimates which can, and
often do, change as the tons are mined. Any change in the number of recoverable
tons contained in mine development, coal lands and mineral rights areas will
result in a change in the depletion rate and corresponding depletion expense.
For the year ended December 31, 2009, we recognized $6.3 million of depletion
expense.





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




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Table of contents


Coal
Reserves





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





Each
of these factors may in fact vary considerably from the assumptions used in
estimating reserves. For these reasons, estimates of the economically
recoverable quantities of coal attributable to a particular group of properties,
and the classifications of these reserves based on risk of recovery and
estimates of future net cash flows, may vary substantially. Actual production,
revenues and expenditures with respect to these reserves will likely vary from
estimates, and these variances may be material. At December 31, 2009, we
estimate that we had 1.1 billion tons of coal reserves.





Asset
Impairments





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





Financial
Instruments





Pursuant
to ASC Subtopic 470-20-65-1,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”), our convertible notes are
accounted for as convertible debt and the embedded conversion option in the
convertible notes has been accounted for as a component of equity.





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Table of contents


Coal
Supply Agreements





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





Share
Based Compensation





We
account for our share based awards in accordance with ASC Topic 718,Compensation—Stock Compensation (“ASC
718”). Share based compensation expense is generally measured at the grant date
and recognized as expense over the vesting period of the award. We utilize
restricted stock and stock options as part of our share based compensation
program. Determining fair value requires us to make a number of assumptions,
including expected term, risk-free rate and expected volatility. Due to our
limited operating history, the expected term 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 assumptions used in calculating the fair value of share based
awards represent our best estimates and involve inherent uncertainties and the
application of management judgment. Although we believe the assumptions and
estimates we have made are reasonable and appropriate, different assumptions
could materially impact our reported financial results.





Debt
Issuance Costs





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





Income
Taxes





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





A
tax position is initially recognized in the financial statements when it is more
likely than not the position will be sustained upon examination by applicable
tax authorities. Such tax positions are initially and subsequently measured as
the largest amount of tax benefit that is more likely than not to be realized
upon ultimate settlement with the tax authority assuming full knowledge of the
position and all relevant facts. The amount of our uncertain income tax
positions, unrecognized benefits and accrued interest were immaterial at
December 31, 2009 and 2008.





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Table of contents


Postretirement
Medical Benefits





Some
of our subsidiaries have 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. Our estimates of these costs are adjusted based upon actuarially
determined amounts using a rate of 5.75% as of December 31, 2009. 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, 2009 was based on an assumed
heath care inflationary rate of 6.40% in the operating period decreasing to
4.50% in 2061, 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,
2009 by $0.4 million and increase the accumulated postretirement benefit
obligation at December 31, 2009 by $2.1 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, 2009 by $0.4 million and decrease the accumulated
postretirement benefit obligation at December 31, 2009 by $2.0 million. If our
assumptions do not materialize as expected or if regulatory changes were to
occur, actual cash expenditures and costs that we incur could differ materially
from our current estimates.





Workers’
Compensation





Workers’
compensation is a system by which individuals who sustain personal injuries due
to job-related accidents are compensated for their disabilities, medical costs
and, on some occasions, for the costs of their rehabilitation, and by which the
survivors of workers who suffer fatal injuries receive compensation for lost
financial support. The workers’ compensation laws are administered by state
agencies with each state having its own rules and regulations regarding
compensation that is owed to an employee who is injured in the course of
employment or the beneficiary of an employee that suffers fatal injuries in the
course of employment. Our operations are covered through a combination of
participation in a state run program and insurance policies. Our estimates of
these costs are adjusted based upon actuarially determined amounts using a
discount rate of 4.75% as of December 31, 2009. The discount rate assumption
reflects the rates available on a hypothetical portfolio of high-quality fixed
income debt instruments whose cash flows match the timing and amount of expected
benefit payments. If we were to decrease our estimate of the discount rate to
3.75%, the present value of our workers’ compensation liability would increase
by approximately $0.4 million. If we were to increase our estimate of the
discount rate to 5.75%, the present value of our workers’ compensation liability
would decrease by approximately $0.3 million. At December 31, 2009, we have
recorded an accrual of $10.3 million for workers’ compensation benefits. Actual
losses may differ from these estimates, which could increase or decrease our
costs.





71





Table of contents


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
6.00% as of December 31, 2009. 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 5.00%, the
present value of our black lung benefit liability would increase by
approximately $4.8 million. If we were to increase our estimate of the discount
rate to 7.00%, the present value of our black lung benefit liability would
decrease by approximately $3.8 million. At December 31, 2009, we have recorded
an accrual of $25.9 million for black lung benefits. Individual losses in excess
of $0.5 million at the state level and $0.5 million at the federal level are
covered by our large deductible stop loss insurance. Actual losses may differ
from these estimates, which could increase or decrease our costs.





Coal
Industry Retiree Health Benefit Act of 1992





The
Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”) provides for
the funding of health benefits for certain union retirees and their spouses or
dependants. The Coal Act established the Combined Fund into which employers who
are “signatory operators” and “related persons” are obligated to pay annual
premiums for beneficiaries. The Coal Act also created a second benefit fund for
miners who retired between July 21, 1992 and September 30, 1994 and
whose former employers are no longer in business. Upon the consummation of the
business combination with Anker, we assumed Anker’s Coal Act liabilities, which
were estimated to be $1.4 million at December 31, 2009. 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 5.50% as of December 31, 2009. 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
4.50%, the present value of our Coal Act liability would increase by
approximately $0.1 million. If we were to increase our estimate of the discount
rate to 6.50%, the present value of our Coal Act liability would decrease by
approximately $0.1 million. Prior to the business combination with Anker, we did
not have any liability under the Coal Act.





Corporate
Vacation Policy





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





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Table of contents


Results of
Operations





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





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





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





Year
      ended
              December
      31,
            
            
            Increase
              (Decrease)2009
            
            
            2008
            
            
            $
      or Tons
            
            %(in thousands, except percentages
      and per ton data)Coal
      sales revenues
            
            $
            1,006,606
            
            
            $
            998,245
            
            
            $
            8,361
            
            1
            %Freight
      and handling revenues
            
            
            26,279
            
            
            
            45,231
            
            
            
            (18,952
            )
            (42
            )%Other
      revenues
            
            
            92,464
            
            
            
            53,260
            
            
            
            39,204
            
            74
            %Total
      revenues
            
            $
            1,125,349
            
            
            $
            1,096,736
            
            
            $
            28,613
            
            3
            %Tons
      sold
            
            
            16,833
            
            
            
            18,914
            
            
            
            (2,081
            )
            (11
            )%Coal
      sales revenue per ton
            
            $
            59.80
            
            
            $
            52.78
            
            
            $
            7.02
            
            13
            %





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





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





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





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





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





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Table of contents




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





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





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





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





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





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





Costs
and expenses





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





Year
      ended
              December
      31,
            
            
            Increase
              (Decrease)2009
            
            
            2008
            
            
            $
            
            %(in thousands, except percentages
      and per ton data)Cost
      of coal sales
            
            $
            832,214
            
            
            $
            882,983
            
            
            $
            (50,769
            )
            (6
            )%Freight
      and handling costs
            
            
            26,279
            
            
            
            45,231
            
            
            
            (18,952
            )
            (42
            )%Cost
      of other revenues
            
            
            36,089
            
            
            
            35,672
            
            
            
            417
            
            1
            %Depreciation,
      depletion and amortization
            
            
            106,084
            
            
            
            96,047
            
            
            
            10,037
            
            10
            %Selling,
      general and administrative expenses
            
            
            32,749
            
            
            
            38,147
            
            
            
            (5,398
            )
            (14
            )%Gain
      on sale of assets
            
            
            (3,659
            )
            
            
            (32,518
            )
            
            
            28,859
            
            89
            %Impairment
      loss
            
            
            —
            
            
            
            37,428
            
            
            
            (37,428
            )
            (100
            )%Total
      costs and expenses
            
            $
            1,029,756
            
            
            $
            1,102,990
            
            
            $
            (73,234
            )
            (7
            )%Cost
      of coal sales per ton
            
            $
            49.44
            
            
            $
            46.68
            
            
            $
            2.76
            
            6
            %








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Table of contents





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





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





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





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





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





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





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





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Table of contents




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





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





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





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





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





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Table of contents





Adjusted
EBITDA by Reportable Segment





Adjusted
EBITDA represents net income before deducting interest, income taxes,
depreciation, depletion, amortization, loss on extinguishment of debt,
impairment charges and noncontrolling interest. Adjusted EBITDA is presented
because it is an important supplemental measure of our performance used by our
chief operating decision maker in such areas as capital investment and
allocation of resources. Other companies in our industry may calculate Adjusted
EBITDA differently than we do, limiting its usefulness as a comparative measure.
Adjusted EBITDA is reconciled to its most comparable GAAP measure on
page 79 of this Annual Report on Form 10-K and in Note 20 to our
consolidated financial statements for the year ended December 31,
2009.





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





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





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





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





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





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





77


Table of contents


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





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





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





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





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





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





78


Table of contents





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





*
Not meaningful





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





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





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Table of contents





The
following table depicts tons sold by reportable 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.





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.





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Table of contents


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
            %





The
following table depicts cost of coal sales by reportable 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.





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Table of contents


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.





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 Reportable Segment





Adjusted
EBITDA represents net income before deducting interest, 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 84 of
this Annual Report on Form 10-K and in Note 20 to our consolidated financial
statements for the year ended December 31, 2008.





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Table of contents


The
following table depicts reportable 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.





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 Reportable Segment





The
following tables reconcile Adjusted EBITDA to net income (loss) by reportable
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
            %





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Table of contents




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
            )%





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
            %








84




Table of contents


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 on hand, cash flows from
operations, borrowings under our senior credit facility and 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, 2009, our
available liquidity was $119.0 million, including cash and cash equivalents of
$92.6 million and $26.4 million available for borrowing under our $100.0 million
senior credit facility. Total debt represented 39% of our total capitalization
at December 31, 2009. Our total capitalization represents our current and
long-term debt combined with our total stockholders’ equity.





In
December 2009, we entered into a series of privately negotiated agreements
pursuant to which we issued a total of 18,660,550 shares of our common stock in
exchange for $63.5 million aggregate principal amount of our 9.00% Convertible
Senior Notes due 2012 (the “Convertible Notes”). One of the exchange
agreements, as amended, provided for closing of additional exchanges on each of
January 11, 2010 and January 19, 2010 for exchanges occurring in 2010.
Subsequent to December 31, 2009, we issued a total of 6,198,668 shares of our
common stock in exchange for $22.0 million aggregate principal amount of our
Convertible Notes.





On December 18, 2009, we filed a shelf registration statement on Form S-3
with the SEC that became effective on January 15, 2010. Under this universal
shelf registration statement, we have the capacity to offer and sell, from time
to time, up to $600.0 million aggregate value of securities, including common
stock and debt securities. This registration statement allows us to
opportunistically access the capital markets based on our liquidity and capital
needs subject to favorable market and other conditions.





In
September 2009, we executed an amendment to our $100.0 million credit facility
that affected certain debt covenants. The amendment modified the maximum
permitted leverage and minimum interest coverage ratios for 2010 and thereafter.
The amendment also decreased the maximum capital spending and added a minimum
liquidity requirement for 2010. Management believes, based on currently
available information, that we will remain in compliance with the financial
covenants in our credit facility.





We
currently expect our total capital expenditures will be approximately $85.0
million to $95.0 million in 2010, substantially all of which will be for
equipment and infrastructure at our existing operations. Cash paid for capital
expenditures was approximately $66.3 million for the year ended December
31, 2009. We have funded and expect to continue to fund these capital
expenditures from our internal operations and equipment financing arrangements,
such as our $50.0 million equipment revolving credit facility with Caterpillar
Financial Services Corporation. We believe that these sources of capital will be
sufficient to fund our anticipated capital expenditures through 2010. To the
extent necessary, management believes it has flexibility on the timing of these
cash requirements by managing the pace of capital spending. In addition,
management may from time to time raise additional capital through the
disposition of non-core assets, engaging in sale-leaseback transactions or
utilizing our shelf registration statement. The need and timing of seeking
additional capital in the future will be subject to market
conditions.





85


Table of contents





Approximately
$29.9 million of cash paid for capital expenditures for the year ended December
31, 2009 was attributable to our Central Appalachian operations. This amount
represents investments of approximately $6.3 million in our Beckley mining
complex and $6.3 million in our Hazard complex. We paid approximately $21.1
million at our Northern Appalachian operations for the year ended December 31,
2009, approximately $7.8 million of which was for investments at our Sentinel
complex. We invested approximately $11.4 million in our Illinois Basin
operations for the development of a new mine portal and ongoing operations
improvements. Approximately $3.9 million of cash paid for capital expenditures
for the year ended December 31, 2009 was within our Ancillary segment, primarily
for the upgrading of highwall mining machinery and the purchase of safety
equipment.





More
stringent regulatory requirements imposed upon the mining
industry demand substantial capital expenditures to meet safety
standards. For the year ended December 31, 2009, we spent $5.4 million to
meet these standards and anticipate spending an additional $3.2 million in
2010.





Cash
Flows





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





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





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





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 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.





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Credit
Facility and Long-Term Debt Obligations





As
of December 31, 2009, our total long-term indebtedness, including capital lease
obligations, consisted of the following (in thousands):





20099.00%
      Convertible senior notes, due 2012, net of debt discount
      of  $9,480
            
            $
            152,02210.25%
      Senior notes, due 2014
            
            
            175,000Equipment
      notes
            
            
            54,417Capital
      leases and other
            
            
            2,870Total
            
            
            384,309Less
      current portion
            
            
            (17,794
            )Long-term
      debt and capital leases
            
            $
            366,515





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.





In
December 2009, we entered into a series of privately negotiated agreements in
order to induce conversions of our outstanding Convertible Notes. In connection
with such agreements, we issued a total of 18,660,550 shares of our common stock
in exchange for $63.5 million aggregate principal amount of our Convertible
Notes. As a result of the exchanges, we recognized losses on extinguishment of
the related debt totaling $13.3 million for the year ended December 31,
2009.





One
of the exchange agreements, as amended, provided for closing of additional
exchanges on each of January 11, 2010 and January 19, 2010 for exchange
transactions occurring in 2010. Subsequent to December 31, 2009, the noteholder
actually exchanged $22.0 million aggregate principal amount of Convertible Notes
for 6,198,668 shares of our common stock. As a result of the exchanges settled
in January 2010, we recognized a loss on extinguishment of the related debt
totaling $5.4 million subsequent to December 31, 2009.





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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, 2009.
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 WL Ross & Co. LLC, 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.





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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, 2009, we were in
compliance with our covenants under the indenture.





Credit facility. We have a
$100.0 million revolving credit facility (the “Credit Facility”) which matures
on June 23, 2011. A maximum of $80.0 million may be used for letters of
credit. In September 2009, we executed an amendment to the Credit Facility that
affected certain debt covenants. The amendment modified the maximum permitted
leverage and minimum interest coverage ratios for 2010 and thereafter. The
amendment also decreased the maximum capital spending and added a minimum
liquidity requirement for 2010. Pursuant to the amendment, interest on the
borrowings under the Credit Facility is payable, at our option, at either the
base rate plus an applicable margin of 2.75% to 3.50% or LIBOR plus an
applicable margin of 3.75% to 4.50%, based on our leverage ratio. As of
December 31, 2009, we had no borrowings outstanding and letters of credit
totaling $73.6 million outstanding, leaving $26.4 million available for future
borrowing capacity, and were in compliance with our financial covenants under
the Credit Facility.





Equipment notes. The
equipment notes, having various maturity dates extending to September 2014, are
collateralized by mining equipment. As of December 31, 2009, we had amounts
outstanding with terms ranging from 36 up to 60 months at a weighted-average
interest rate of 7.35%. At December 31, 2009, additional funds are available
under our revolving equipment credit facility for terms ranging up to 60 months
with a current interest rate of 6.75%.





Capital lease and other. We
lease certain mining equipment under a capital lease. We imputed interest on our
capital lease using a rate of 10.44%. Additionally, we have an insurance
policy with a coverage period of 17 months that we financed over 15 months at an
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 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.





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Our
ability to meet our long-term debt obligations will depend upon our future
performance, which in turn, will depend upon general economic, financial and
business conditions, along with competition, legislation and regulation —factors that are largely
beyond our control. We believe that cash flow from operations, together with
other available sources of funds, including additional borrowings under our
credit facility and equipment credit facility, will be adequate at least through
2010 for making required payments of principal and interest on our indebtedness
and for funding anticipated capital expenditures and working capital
requirements. To the extent necessary, management believes it has some
flexibility to manage its cash requirements by controlling the pace and timing
of capital spending, utilizing availability under its credit facilities,
reducing certain costs and idling high-cost operations. In addition, management
may from time to time raise additional capital through the disposition of
non-core assets or engage 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.





Our
Convertible Senior Notes (the “Convertible Notes”) were not convertible as of
December 31, 2009. In the event that the Convertible Notes were to become
convertible and a significant number of the holders 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 WL
Ross & Co. LLC, 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.





Contractual
Obligations





The
following is a summary of our significant future contractual obligations by year
as of December 31, 2009 (in thousands):





Payments
      Due by PeriodLess than
              1
      year
            
            
            1-3
      years
            
            
            3-5
      years
            
            
            More than
              5
      years
            
            
            TotalLong-term
      debt and capital lease(1)
            
            $
            53,885
            
            
            $
            254,180
            
            
            $
            212,165
            
            
            $
            —
            
            
            $
            520,230Operating
      leases
            
            
            98
            
            
            
            79
            
            
            
            15
            
            
            
            2
            
            
            
            194Coal
      purchase obligations(2)
            
            
            14,377
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            14,377Diesel
      fuel purchase obligations(2)
            
            
            39,859
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            39,859Advisory
      Services Agreement(3)
            
            
            2,000
            
            
            
            1,500
            
            
            
            —
            
            
            
            —
            
            
            
            3,500Minimum
      royalties
            
            
            10,462
            
            
            
            18,489
            
            
            
            15,535
            
            
            
            29,815
            
            
            
            74,301Postretirement
      medical benefits
            
            
            430
            
            
            
            2,091
            
            
            
            4,067
            
            
            
            182,279
            
            
            
            188,867Total
            
            $
            121,111
            
            
            $
            276,339
            
            
            $
            231,782
            
            
            $
            212,096
            
            
            $
            841,328








(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 10.09% on
      our equipment notes.(2)
            Reflects
      estimates of obligations.(3)
            See “Certain Relationships and
      Related Transactions, and Director
  Independence.”





We
have excluded uncertain tax liabilities as defined in ASC Topic 740, Income Taxes, from the table
above due to the immateriality of such amounts.




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Off-Balance
Sheet Arrangements





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





Federal
and state laws require us to secure payment of certain long-term obligations,
such as mine closure and reclamation costs, coal leases and other obligations.
We typically secure these payment obligations by using surety bonds, an
off-balance sheet instrument. The use of surety bonds is less expensive than
posting an all cash bond or a bank letter of credit, either of which would
require a greater use of our credit facility. We then use bank letters of credit
to secure our surety bonding obligations as a lower cost alternative than
securing those bonds with cash. We currently have a $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, 2009, we had outstanding surety bonds with third parties for
post-mining reclamation totaling $112.4 million, plus $4.5 million for
miscellaneous purposes. As of December 31, 2009, we maintained letters of credit
totaling $73.6 million to secure reclamation surety bonds and other
obligations.





Inflation





Inflation
in the United States has been relatively low in recent years and did not have a
material impact on results of operations for the years ended December 31, 2009,
2008 and 2007. 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





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





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ITEM 7A.
            QUANTITATIVE
      AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK





Interest rate risk. In
May 2006, we entered into an Interest Rate Collar Agreement, which became
effective on March 31, 2007 and expired and was settled on March 31,
2009, to hedge our interest risk on $200.0 million notional amount of revolving
debt. 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%. This
agreement was entered into in conjunction with our amended and restated credit
facility dated June 23, 2006. We recognized the changes in the fair value
of this agreement in the income statement in the period of change. For the year
ended December 31, 2009, we recognized an immaterial loss 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. We manage this risk through the use of long-term coal supply agreements,
rather than through the use of derivative instruments. As of December 31, 2009,
91% of our 2010 projected sales are committed and priced. Any committed and
unpriced projected sales are subject to future market price
volatility. Additionally, the prices of coal shipped under long-term supply
agreements may be below the current market prices for similar types of coal at
any given time. As a result of the substantial volume of sales that are subject
to these long-term agreements, we have less coal available with which to
capitalize on stronger coal prices if and when they arise.





ITEM 8.
            FINANCIAL
      STATEMENTS AND SUPPLEMENTARY DATA





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





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





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





ITEM 9A.
            CONTROLS
      AND PROCEDURES





We
maintain a set of disclosure controls and procedures designed to provide
reasonable assurance that information required to be disclosed by us in reports
that we file or submit under the Securities Exchange Act of 1934 (the “Exchange
Act”) is recorded, processed, summarized and reported within the time periods
specified in Securities and Exchange Commission rules and forms. Our disclosure
controls and procedures are also designed to provide reasonable assurance that
information required to be disclosed in the reports that we file or submit under
the Exchange Act is accumulated and communicated to our management, including
the Chief Executive Officer and Chief Financial Officer, to allow timely
decisions regarding required disclosure. Periodically, we review the design and
effectiveness of our disclosure controls and controls over financial reporting
to ensure they remain effective. If such reviews identify a need, we will make
modifications to improve the design and effectiveness of our control structure.
We conducted an evaluation of our controls and procedures (as defined in Rules
13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended
(the “Exchange Act”) under the supervision and with the participation of our
management, including our Chief Executive Officer and Chief Financial Officer.
Based on this evaluation, our Chief Executive Officer and Chief Financial
Officer have concluded that our controls and procedures were effective as of
December 31, 2009.





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





Management’s
Report on Internal Control Over Financial Reporting





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





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





Under
the supervision and with the participation of our management, including our
Chief Executive Officer and Chief Financial Officer, we conducted an evaluation
of our controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)
under the Exchange Act using the criteria set by the Committee of Sponsoring
Organizations of the Treadway Commission (“COSO”) 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, 2009.





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





Changes
in Internal Control Over Financial Reporting





There
have been no changes in our internal controls over financial reporting during
the fourth quarter of fiscal year 2009 that would have materially affected, or
would be reasonably likely to materially affect, our internal control over
financial reporting.


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Table of contents


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, 2009, 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, 2009, 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, 2009 of the Company and our report dated January 29, 2010 expressed
an unqualified opinion on those financial statements and financial statement
schedules.





/s/ Deloitte &
      Touche LLPCincinnati,
      OhioJanuary
      29, 2010





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ITEM 9B.
            OTHER
      INFORMATION





None.





Part
III





ITEM 10.
            DIRECTORS,
      EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE





The
information requested by Items 401, 405, 406 and 407(c)(3), (d)(4) and (d)(5) of
Regulation S-K is incorporated herein by reference to the definitive Proxy
Statement used in connection with the solicitation of proxies for our Annual
Meeting of Stockholders to be held on May 19, 2010 (the “Definitive Proxy
Statement”).





ITEM 11.
            EXECUTIVE
      COMPENSATION





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





ITEM 12.
            SECURITY
      OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
      STOCKHOLDER MATTERS





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





See
“Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities—Summary of Equity Compensation Plans” on
page 61 of this Annual Report on Form 10-K for information required by
Item 201(d) of Regulation S-K.





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





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





ITEM 14.
            PRINCIPAL
      ACCOUNTANT FEES AND SERVICE





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





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PART
IV





ITEM 15.
            EXHIBITS,
      FINANCIAL STATEMENT SCHEDULES





(a)
            Financial
      Statements:





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





PageInternational
      Coal Group, Inc. and SubsidiariesReport of Independent Registered Public Accounting
      Firm
            
            F-1Consolidated Balance Sheets as of December 31, 2009 and
      2008
            
            F-2Consolidated Statements of Operations for the years ended
      December 31, 2009, 2008 and 2007
            
            F-3Consolidated Statements of Stockholders’ Equity and
      Comprehensive Income for the years ended December 31, 2009, 2008 and
      2007
            
            F-4Consolidated Statements of Cash Flows for the years ended
      December 31, 2009, 2008 and 2007
            
            F-5Notes to Consolidated Financial Statements for the years ended
      December 31, 2009, 2008 and 2007
            
            F-6(b)    Exhibits.(i)     See
      the Exhibit Index.(c)    Financial
      Statement Schedules.PageSchedule I—Condensed Financial Information of the
      Registrant
            
            F-39Schedule II—Valuation and Qualifying
      Accounts
            
            F-44





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





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  REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 To
the Board of Directors and Stockholders of
 International
Coal Group, Inc.
 Scott
Depot, West Virginia
 
 We
have audited the accompanying consolidated balance sheets of International Coal
Group, Inc. and subsidiaries (the “Company”) as of December 31, 2009 and 2008,
and the related consolidated statements of operations, stockholders’ equity and
comprehensive income, and cash flows for each of the three years in the period
ended December 31, 2009. 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, 2009
and 2008, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2009 in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such financial statement schedules, when considered in relation
to the basic consolidated financial statements taken as a whole, present fairly,
in all material respects, the information set forth therein.
 
 We
have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the Company’s internal control over
financial reporting as of December 31, 2009, based on the criteria established
inInternal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated January 29, 2010 expressed an
unqualified opinion on the Company’s internal control over financial
reporting.
 
 /s/
      Deloitte & Touche LLPCincinnati,
      OhioJanuary
      29, 2010
 
 F-1


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





CONSOLIDATED BALANCE SHEETS


December
31, 2009 and 2008


(Dollars
in thousands, except per share amounts)








December
      31,
              2009
            
            
            December 31,
              2008ASSETSCURRENT
      ASSETS:Cash
      and cash equivalents
            
            $
            92,641
            
            
            $
            63,930Accounts
      receivable, net of allowances of $222 and $1,516
            
            
            80,291
            
            
            
            75,321Inventories,
      net
            
            
            82,037
            
            
            
            58,788Deferred
      income taxes
            
            
            15,906
            
            
            
            17,649Prepaid
      insurance
            
            
            6,351
            
            
            
            13,380Income
      taxes receivable
            
            
            1,423
            
            
            
            8,030Prepaid
      expenses and other
            
            
            9,960
            
            
            
            10,893Total
      current assets
            
            
            288,609
            
            
            
            247,991PROPERTY,
      PLANT, EQUIPMENT AND MINE DEVELOPMENT, net
            
            
            1,038,200
            
            
            
            1,069,297DEBT
      ISSUANCE COSTS, net
            
            
            7,634
            
            
            
            10,462ADVANCE
      ROYALTIES, net
            
            
            18,025
            
            
            
            17,462OTHER
      NON-CURRENT ASSETS
            
            
            15,492
            
            
            
            5,435Total
      assets
            
            $
            1,367,960
            
            
            $
            1,350,647LIABILITIES
      AND STOCKHOLDERS’ EQUITYCURRENT
      LIABILITIES:Accounts
      payable
            
            $
            63,582
            
            
            $
            75,810Short-term
      debt
            
            
            2,166
            
            
            
            4,741Current
      portion of long-term debt and capital leases
            
            
            17,794
            
            
            
            15,319Current
      portion of reclamation and mine closure costs
            
            
            9,390
            
            
            
            11,139Current
      portion of employee benefits
            
            
            3,973
            
            
            
            3,359Accrued
      expenses and other
            
            
            74,803
            
            
            
            87,704Total
      current liabilities
            
            
            171,708
            
            
            
            198,072LONG-TERM
      DEBT AND CAPITAL LEASES
            
            
            366,515
            
            
            
            417,551RECLAMATION
      AND MINE CLOSURE COSTS
            
            
            65,601
            
            
            
            68,107EMPLOYEE
      BENEFITS
            
            
            63,767
            
            
            
            56,563DEFERRED
      INCOME TAXES
            
            
            57,399
            
            
            
            51,154BELOW-MARKET
      COAL SUPPLY AGREEMENTS
            
            
            29,939
            
            
            
            43,888OTHER
      NON-CURRENT LIABILITIES
            
            
            3,797
            
            
            
            6,195Total
      liabilities
            
            
            758,726
            
            
            
            841,530COMMITMENTS
      AND CONTINGENCIESSTOCKHOLDERS’
      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, 172,820,047 and
      172,812,726 shares issued and outstanding, respectively, as of December
      31, 2009 and 153,322,245 shares issued and outstanding, as of December 31,
      2008
            
            
            1,728
            
            
            
            1,533Treasury
      stock
            
            
            (14
            )
            
            
            —Additional
      paid-in capital
            
            
            732,124
            
            
            
            656,997Accumulated
      other comprehensive income (loss)
            
            
            1,048
            
            
            
            (2,277
            )Retained
      deficit
            
            
            (125,713
            )
            
            
            (147,171
            )Total
      International Coal Group, Inc. stockholders’ equity
            
            
            609,173
            
            
            
            509,082Noncontrolling
      interest
            
            
            61
            
            
            
            35Total
      stockholders’ equity
            
            
            609,234
            
            
            
            509,117Total
      liabilities and stockholders’ equity
            
            $
            1,367,960
            
            
            $
            1,350,647





See
notes to consolidated financial statements.


F-2


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





CONSOLIDATED STATEMENTS OF OPERATIONS


Years
ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Year
      Ended December 31,2009
            
            
            2008
            
            
            2007REVENUES:Coal
      sales revenues
            
            $
            1,006,606
            
            
            $
            998,245
            
            
            $
            770,663Freight
      and handling revenues
            
            
            26,279
            
            
            
            45,231
            
            
            
            29,594Other
      revenues
            
            
            92,464
            
            
            
            53,260
            
            
            
            48,898Total
      revenues
            
            
            1,125,349
            
            
            
            1,096,736
            
            
            
            849,155COSTS
      AND EXPENSES:Cost
      of coal sales
            
            
            832,214
            
            
            
            882,983
            
            
            
            732,112Freight
      and handling costs
            
            
            26,279
            
            
            
            45,231
            
            
            
            29,594Cost
      of other revenues
            
            
            36,089
            
            
            
            35,672
            
            
            
            34,046Depreciation,
      depletion and amortization
            
            
            106,084
            
            
            
            96,047
            
            
            
            86,517Selling,
      general and administrative
            
            
            32,749
            
            
            
            38,147
            
            
            
            33,325Gain
      on sale of assets
            
            
            (3,659
            )
            
            
            (32,518
            )
            
            
            (38,656
            )Goodwill
      impairment loss
            
            
            —
            
            
            
            30,237
            
            
            
            170,402Long-lived
      asset impairment loss
            
            
            —
            
            
            
            7,191
            
            
            
            —Total
      costs and expenses
            
            
            1,029,756
            
            
            
            1,102,990
            
            
            
            1,047,340Income
      (loss) from operations
            
            
            95,593
            
            
            
            (6,254
            )
            
            
            (198,185
            )INTEREST
      AND OTHER INCOME (EXPENSE):Loss
      on extinguishment of debt
            
            
            (13,293
            )
            
            
            —
            
            
            
            —Interest
      expense, net
            
            
            (53,044
            )
            
            
            (43,643
            )
            
            
            (35,989
            )Other,
      net
            
            
            —
            
            
            
            —
            
            
            
            319Total
      interest and other income (expense)
            
            
            (66,337
            )
            
            
            (43,643
            )
            
            
            (35,670
            )Income
      (loss) before income taxes
            
            
            29,256
            
            
            
            (49,897
            )
            
            
            (233,855
            )INCOME
      TAX BENEFIT (EXPENSE)BENEFIT
            
            
            (7,732
            )
            
            
            23,670
            
            
            
            85,944Net
      income (loss)
            
            
            21,524
            
            
            
            (26,227
            )
            
            
            (147,911
            )Net
      (income) loss attributable to noncontrolling interest
            
            
            (66
            )
            
            
            —
            
            
            
            349Net
      income (loss) attributable to International Coal Group,
    Inc.
            
            $
            21,458
            
            
            $
            (26,227
            )
            
            $
            (147,562
            )Earnings
      per share:Basic
            
            $
            0.14
            
            
            $
            (0.17
            )
            
            $
            (0.97
            )Diluted
            
            
            0.14
            
            
            
            (0.17
            )
            
            
            (0.97
            )Weighted-average
      common shares outstanding:Basic
            
            
            153,630,446
            
            
            
            152,632,586
            
            
            
            152,304,461Diluted
            
            
            155,386,263
            
            
            
            152,632,586
            
            
            
            152,304,461





See
notes to consolidated financial statements.





F-3




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





CONSOLIDATED STATEMENTS OF STOCKHOLDERS’EQUITY AND COMPREHENSIVE
INCOME


Years
ended December 31, 2009, 2008 and 2007


(Dollars
in thousands)








Common
      Stock
            
            Treasury
      Stock
            
            Additional
      Paid-in Capital
            
            Accumulated
      Other Comprehensive Income (Loss)
            
            Retained
      Earnings (Deficit)
            
            Total
      International Coal Group, Inc. Stockholders’ Equity
            
            Noncontrolling
      Interest
            
            Total
      Stockholders’ EquityShares
            
            AmountBalance—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 postretirement benefit net loss, 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 net gain, 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 postretirement benefit net loss, 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 net gain, net of tax of $358
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            (590
            )
            
            —
            
            
            (590
            )
            
            —
            
            
            (590
            )Comprehensive
      loss
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            (26,974
            )Issuance
      of restricted stock and stock awards, net of forfeitures
            
            312,436
            
            
            3
            
            
            —
            
            
            (3
            )
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Stock
      options exercised
            
            17,700
            
            
            —
            
            
            —
            
            
            149
            
            
            —
            
            
            —
            
            
            149
            
            
            —
            
            
            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
            
            
            509,117Net
      income
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            21,458
            
            
            21,458
            
            
            66
            
            
            21,524Postretirement
      benefit obligation adjustments, net of tax of $323
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            2,663
            
            
            —
            
            
            2,663
            
            
            —
            
            
            2,663Amortization
      of postretirement benefit net loss, net of tax of $117
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            171
            
            
            —
            
            
            171
            
            
            —
            
            
            171Black
      lung benefit obligation adjustments, net of tax of $416
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            735
            
            
            —
            
            
            735
            
            
            —
            
            
            735Amortization
      of black lung benefit net gain, net of tax of $146
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            (244
            )
            
            —
            
            
            (244
            )
            
            —
            
            
            (244
            )Comprehensive
      income
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            24,849Purchases
      of treasury stock
            
            (7,321
            )
            
            —
            
            
            (14
            )
            
            —
            
            
            —
            
            
            —
            
            
            (14
            )
            
            —
            
            
            (14
            )Distributions
      to noncontrolling interest
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            (40
            )
            
            (40
            )Issuance
      of common stock in exchange for convertible notes
            
            18,660,550
            
            
            187
            
            
            —
            
            
            71,430
            
            
            —
            
            
            —
            
            
            71,617
            
            
            —
            
            
            71,617Issuance
      of restricted stock and stock awards, net of forfeitures
            
            837,252
            
            
            8
            
            
            —
            
            
            (8
            )
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Compensation
      expense on share based awards
            
            —
            
            
            —
            
            
            —
            
            
            3,705
            
            
            —
            
            
            —
            
            
            3,705
            
            
            —
            
            
            3,705Balance—December
      31, 2009
            
            172,812,726
            
            $
            1,728
            
            $
            (14
            )
            $
            732,124
            
            $
            1,048
            
            $
            (125,713
            )
            $
            609,173
            
            $
            61
            
            $
            609,234





See notes
to consolidated financial statements.





F-4


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





CONSOLIDATED STATEMENTS OF CASH FLOWS


Years
ended December 31, 2009, 2008 and 2007


(Dollars
in thousands)








Year
      Ended December 31,2009
            
            
            2008
            
            
            2007CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      income (loss)
            
            $
            21,524
            
            
            $
            (26,227
            )
            
            $
            (147,911
            )Adjustments
      to reconcile net income (loss) to net cash from operating
      activities:
            
            
            
            
            
            
            —
            
            
            
            —Depreciation,
      depletion and amortization
            
            
            106,084
            
            
            
            96,047
            
            
            
            86,517Loss
      on extinguishment of debt
            
            
            13,293
            
            
            
            —
            
            
            
            —Impairment
      loss
            
            
            —
            
            
            
            37,428
            
            
            
            170,402Amortization
      of deferred finance costs and debt discount
            
            
            7,001
            
            
            
            6,141
            
            
            
            9,516Amortization
      of accumulated employee benefit obligations
            
            
            (102
            )
            
            
            (518
            )
            
            
            (19
            )Compensation
      expense on share based awards
            
            
            3,705
            
            
            
            4,174
            
            
            
            5,224Gain
      on sale of assets, net
            
            
            (3,659
            )
            
            
            (32,518
            )
            
            
            (38,656
            )Provision
      for bad debt
            
            
            (1,294
            )
            
            
            994
            
            
            
            503Deferred
      income taxes
            
            
            7,859
            
            
            
            (24,434
            )
            
            
            (87,399
            )Changes
      in Assets and Liabilities:Accounts
      receivable
            
            
            (3,676
            )
            
            
            7,918
            
            
            
            (13,606
            )Inventories
            
            
            (23,249
            )
            
            
            (17,333
            )
            
            
            (92
            )Prepaid
      expenses and other
            
            
            14,569
            
            
            
            (3,545
            )
            
            
            3,202Other
      non-current assets
            
            
            399
            
            
            
            (2,744
            )
            
            
            (457
            )Accounts
      payable
            
            
            (16,814
            )
            
            
            7,116
            
            
            
            12,588Accrued
      expenses and other
            
            
            (13,089
            )
            
            
            24,677
            
            
            
            11,648Reclamation
      and mine closure costs
            
            
            1,341
            
            
            
            (5,281
            )
            
            
            5,509Other
      liabilities
            
            
            1,862
            
            
            
            6,834
            
            
            
            5,502Net
      cash from operating activities
            
            
            115,754
            
            
            
            78,729
            
            
            
            22,471CASH
      FLOWS FROM INVESTING ACTIVITIES:Proceeds
      from the sale of assets
            
            
            3,695
            
            
            
            8,786
            
            
            
            46,524Additions
      to property, plant, equipment and mine development
            
            
            (66,345
            )
            
            
            (132,197
            )
            
            
            (160,807
            )Cash
      paid related to acquisitions, net
            
            
            —
            
            
            
            (603
            )
            
            
            (12,717
            )Withdrawals
      (deposits) of restricted cash
            
            
            (10,468
            )
            
            
            (26
            )
            
            
            193Contribution
      to joint venture
            
            
            (40
            )
            
            
            —
            
            
            
            (100
            )Net
      cash from investing activities
            
            
            (73,158
            )
            
            
            (124,040
            )
            
            
            (126,907
            )CASH
      FLOWS FROM FINANCING ACTIVITIES:Borrowings
      on short-term debt
            
            
            2,611
            
            
            
            6,310
            
            
            
            26,082Repayments
      on short-term debt
            
            
            (5,186
            )
            
            
            (1,569
            )
            
            
            (45,368
            )Borrowings
      on long-term debt
            
            
            9,086
            
            
            
            3,496
            
            
            
            65,000Repayments
      on long-term debt and capital leases
            
            
            (19,104
            )
            
            
            (6,295
            )
            
            
            (68,585
            )Purchases
      of treasury stock
            
            
            (14
            )
            
            
            —
            
            
            
            —Debt
      issuance costs
            
            
            (1,278
            )
            
            
            —
            
            
            
            (9,285
            )Proceeds
      from stock options exercised
            
            
            —
            
            
            
            149
            
            
            
            —Proceeds
      from convertible notes offering
            
            
            —
            
            
            
            —
            
            
            
            225,000Net
      cash from financing activities
            
            
            (13,885
            )
            
            
            2,091
            
            
            
            192,844NET
      CHANGE IN CASH AND CASH EQUIVALENTS
            
            
            28,711
            
            
            
            (43,220
            )
            
            
            88,408CASH
      AND CASH EQUIVALENTS, BEGINNING OF PERIOD
            
            
            63,930
            
            
            
            107,150
            
            
            
            18,742CASH
      AND CASH EQUIVALENTS, END OF PERIOD
            
            $
            92,641
            
            
            $
            63,930
            
            
            $
            107,150Supplemental
      information:Cash
      paid for interest (net of amount capitalized)
            
            $
            47,327
            
            
            $
            36,193
            
            
            $
            20,113Cash
      received for income taxes
            
            $
            7,006
            
            
            $
            —
            
            
            $
            2,971Supplemental
      disclosure of non-cash items:Issuance
      of common stock in exchange for convertible notes
            
            $
            71,617
            
            
            $
            —
            
            
            $
            —Purchases
      of property, plant, equipment and mine development through accounts
      payable
            
            $
            17,416
            
            
            $
            12,942
            
            
            $
            547Purchases
      of property, plant, equipment and mine development through financing
      arrangements
            
            $
            17,066
            
            
            $
            40,708
            
            
            $
            10,971Assets
      acquired through the assumption of liabilities
            
            $
            —
            
            
            $
            17,464
            
            
            $
            2,016Assets
      acquired through the exchange of property
            
            $
            —
            
            
            $
            22,608
            
            
            $
            —





See notes
to consolidated financial statements.


F-5


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








1.
            ORGANIZATION





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





2.
            SUMMARY
      OF SIGNIFICANT ACCOUNTING POLICIES AND
GENERAL





Principles of
Consolidation—The consolidated financial statements include the accounts
of ICG, whose subsidiaries are generally controlled through a majority voting
interest, but may be controlled by means of a significant noncontrolling
ownership, by contract, lease or otherwise. In certain cases, ICG subsidiaries
(i.e., Variable Interest Entities (“VIEs”)) may also be consolidated based on a
risks and rewards approach as required by the Financial Accounting Standards
Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 810, Consolidation (“ASC 810”).
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.
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-6


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(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.





Financial
Instruments—Pursuant to 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), 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 $23,790 and $22,573; the current
portion of $5,765 and $5,111 is included in prepaid expense at December 31, 2009
and 2008, 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, 2009 and 2008, the Company has recorded allowances for such
circumstances totaling $4,206 and $3,909, respectively.





F-7




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Coal Supply
Agreements—The Company’s below-market coal supply agreements (sales
contracts) represent coal supply agreements acquired through acquisitions
accounted for as business combinations for which the prevailing market price for
coal specified in the contract was in excess of the contract price. The
liability recorded related to these coal supply agreements was based on
discounted cash flows resulting from the difference between the below-market
contract price and the prevailing market price at the date of acquisition. The
below-market coal supply agreements are amortized on the basis of tons shipped
over the term of the respective contract. The net book value of the Company’s
below-market coal supply agreements was $29,939 and $43,888 at December 31, 2009
and 2008, respectively. Amortization income on the below-market coal supply
agreements was $6,228, $9,590 and $19,214 in 2009, 2008 and 2007,
respectively. Amortization income is included in depreciation, depletion and
amortization expense. Based on the expected shipments related to the remaining
below-market contracts, the Company expects to record annual amortization income
in each of the next five years as reflected in the table below.





Below-market
              contracts2010
            
            $
            3,2792011
            
            
            3,5482012
            
            
            3,5482013
            
            
            3,5482014
            
            
            3,548








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





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





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





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-8


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Debt Issuance
Costs—Debt issuance costs reflect fees incurred to obtain financing. Debt
issuance costs related to the Company’s outstanding debt are amortized over the
life of the related debt. Amortization expense for the years ended December 31,
2009, 2008 and 2007 was $2,884, $2,428 and $8,082, respectively, and is included
in interest expense. Loss on extinguishment of debt for the year ended December
31, 2009 includes $1,182 representing deferred financing fees written-off as a
result of the Company exchanging a portion of its Convertible Senior Notes for
shares of its common stock. See Note 9. Amortization expense for the year ended
December 31, 2007 includes $5,348 representing deferred financing fees
written-off as a result of amending and restating the Company’s prior credit
agreements. There were no deferred financing fees written-off in
2008.





Restricted
Cash—Restricted cash includes amounts required by various casualty
insurance and reclamation agreements. Restricted cash of $12,057 and $1,589 at
December 31, 2009 and 2008, respectively, is included in other non-current
assets.





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





Asset
Impairments—The Company follows ASC Subtopic 360-10-45,Impairment or Disposal of
Long-Lived Assets(“ASC 360-10-45”) which requires that projected future
cash flows from use and disposition of assets be compared with the carrying
amounts of those assets when impairment indicators are present. When the sum of
projected cash flows is less than the carrying amount, impairment losses are
indicated. If the fair value of the assets is less than the carrying amount of
the assets, an impairment loss is recognized. In determining such impairment
losses, discounted cash flows or asset appraisals are utilized to determine the
fair value of the assets being evaluated. Also, in certain situations, expected
mine lives are shortened because of changes to planned operations. When that
occurs and it is determined that the mine’s underlying costs are not recoverable
in the future, reclamation and mine closure obligations are accelerated and the
mine closure accrual is increased accordingly. To the extent it is determined
asset carrying values will not be recoverable during a shorter mine life, a
provision for such impairment is recognized. During the year ended December 31,
2008, the Company recognized an impairment loss of $7,191 in accordance with ASC
360. No such losses were incurred in 2009 or 2007. See Note 4.





F-9


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








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





A
tax position is initially recognized in the financial statements when it is more
likely than not the position will be sustained upon examination by applicable
taxing authorities. Such tax positions are initially and subsequently measured
as the largest amount of tax benefit that is more likely than not to be realized
upon ultimate settlement with the taxing authority assuming full knowledge of
the position and all relevant facts. The Company recognizes interest expense and
penalties related to unrecognized tax benefits as interest expense and other
expense, respectively, in its consolidated statement of operations. The amount
of the Company’s uncertain income tax positions, unrecognized benefits and
accrued interest were immaterial at December 31, 2009 and 2008.





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





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





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





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





F-10




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Postretirement
Benefits Other Than Pensions—As prescribed by ASC Topic 715,Compensation–Retirement Benefits(“ASC
715”), accruals are made during an employee’s actual working career, based on
actuarially determined estimates, for the expected costs of providing
postretirement benefits other than pensions for current and future retired
employees and their dependents, which are primarily healthcare benefits.
Actuarial gains and losses are amortized over the estimated average remaining
service period for active employees utilizing the minimum amortization method
prescribed by ASC 715. The Company’s liability is reduced by the amount of
Medicare prescription drug reimbursement that it expects to receive under the
Drug Improvement and Modernization Act of 2003. See Note 12. As prescribed by
ASC 715, changes in the funded status of the plan when the obligation is
remeasured, are recognized through comprehensive income.





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





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


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Recent Accounting
Pronouncements—In May 2009, the FASB issued ASC Topic 855,Subsequent Events (“ASC
855”). ASC 855 establishes principles and requirements for events that occur
after the balance sheet date, but before the issuance of the financial
statements. ASC 855 requires disclosure of the date through which subsequent
events have been evaluated and disclosure of certain non-recognized subsequent
events. ASC 855 is effective for interim and annual periods ending after June
15, 2009. Adoption of ASC 855 did not have a material impact on the Company’s
financial position, results of operations or cash flows.





In
June 2009, the FASB issued amendments to ASC Subtopic 810-10-15-13,Variable Interest Entities
(“ASC 810-10-15-13”) to improve financial reporting by enterprises involved with
variable interest entities and to provide more relevant and reliable information
to users of financial statements. The amendment to ASC 810-10-15-13 is effective
as of the first fiscal year beginning after November 15, 2009. The Company
does not believe that adoption of the amendment to ASC 810-10-15-13 will
materially impact its financial position, results of operations or cash
flows.





In
June 2009, the FASB issued ASC Topic 105,Generally Accepted Accounting
Principles (“ASC 105”). ASC 105 makes the FASB Accounting Standards
Codification the single source of authoritative U.S. accounting and reporting
standards, but it does not change accounting principles generally accepted in
the United States of America. ASC 105 is effective for interim and annual
periods ending after September 15, 2009. Adoption of ASC 105 did not have a
material impact on the Company’s financial condition, results of operations or
cash flows.





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





3.
            INVENTORIES





As
of December 31, 2009 and 2008, inventories consisted of the
following:





2009
            
            
            2008Coal
            
            $
            49,120
            
            
            $
            28,436Parts
      and supplies
            
            
            35,065
            
            
            
            32,159Reserve
      for obsolescence, parts and supplies
            
            
            (2,148
            )
            
            
            (1,807
            )Total
            
            $
            82,037
            
            
            $
            58,788





F-12


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








4.
            PROPERTY,
      PLANT, EQUIPMENT AND MINE
DEVELOPMENT





As
of December 31, 2009 and 2008, property, plant, equipment and mine development
are summarized by major classification as follows:





2009
            
            
            2008Coal
      lands and mineral rights
            
            $
            586,706
            
            
            $
            586,512Plant
      and equipment
            
            
            620,451
            
            
            
            571,083Mine
      development
            
            
            195,756
            
            
            
            181,876Land
      and land improvements
            
            
            26,351
            
            
            
            24,119Coalbed
      methane well development costs
            
            
            14,889
            
            
            
            14,8891,444,153
            
            
            
            1,378,479Less
      accumulated depreciation, depletion and amortization
            
            
            (405,953
            )
            
            
            (309,182
            )Net
      property, plant and equipment
            
            $
            1,038,200
            
            
            $
            1,069,297





Depreciation,
depletion and amortization expense related to property, plant, equipment and
mine development for the years ended December 31, 2009, 2008 and 2007 was
$112,267, $105,637 and $105,726, respectively.





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





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





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 the terms of the transaction, the purchaser was
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-13




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(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 Natural Resources Company
(“Horizon”) and Anker Coal Group, Inc. (“Anker”)/CoalQuest Development, LLC
(“CoalQuest”). The Company assigned the goodwill to certain of the acquired
reporting units based on their estimated fair values. The Company tested
goodwill for impairment on an annual basis, at a minimum, and more frequently if
a triggering event occurred. The 2008 goodwill testing identified impairment of
goodwill at the Company’s ADDCAR Systems, LLC (“ADDCAR”) subsidiary resulting in
a $30,237 impairment loss. 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.
The losses reflected the negative impact of several contributing factors which
resulted in a reduction in the forecasted cash flows used to estimate fair
value. The Company was unable to attain forecasted projections that were used to
initially value the business units at the date of acquisition.





6.
            ACCRUED
      EXPENSES AND OTHER





As
of December 31, 2009 and 2008, accrued expenses and other consisted of the
following:





2009
            
            
            2008Compensation
      and related expenses
            
            $
            33,414
            
            
            $
            38,076Interest
            
            
            15,690
            
            
            
            17,776Royalties
            
            
            6,177
            
            
            
            5,826Sales
      and production related taxes
            
            
            5,395
            
            
            
            5,574Deferred
      revenue
            
            
            454
            
            
            
            5,506Personal
      property, land and mineral taxes
            
            
            4,717
            
            
            
            3,719Transportation
            
            
            1,946
            
            
            
            3,453Other
            
            
            7,010
            
            
            
            7,774Total
            
            $
            74,803
            
            
            $
            87,704





7.
            INVESTMENT
      IN JOINT OPERATING AGREEMENT





One
of the Company’s subsidiaries, CoalQuest, entered into an agreement with CDX
Gas, LLC (“CDX”) for the purpose of exploration and development of coalbed
methane under a joint operating agreement, whereby CoalQuest has the right to
obtain up to a 50% undivided working interest in each well drilled on property
owned by the Company. The Company accounts for this joint operation using the
proportionate consolidation method, whereby its share of assets, liabilities,
revenues and expenses are included in the appropriate classification in the
Company’s financial statements. As of December 31, 2009 and 2008, the Company
recorded assets of $1,095 and $2,356, net of accumulated amortization of $13,794
and $12,533, 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, 2009, 2008 and
2007, the Company recognized $2,972, $11,532 and $8,724, respectively, of
coalbed methane revenue and royalty income related to the operating agreement
which is included in other revenues in the consolidated statement of
operations.





F-14




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








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 included 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.





9.
            DEBT





Long-Term
Debt and Capital Leases





As
of December 31, 2009 and 2008, long-term debt and capital leases consisted of
the following:





2009
            
            
            20089.00%
      Convertible Senior Notes, due 2012, net of debt discount of $9,480and $17,369,
      respectively
            
            $
            152,022
            
            
            $
            207,63110.25%
      Senior Notes, due 2014
            
            
            175,000
            
            
            
            175,000Equipment
      notes
            
            
            54,417
            
            
            
            43,378Capital
      leases and other
            
            
            2,870
            
            
            
            6,861Total
            
            
            384,309
            
            
            
            432,870Less
      current portion
            
            
            (17,794
            )
            
            
            (15,319
            )Long-term
      debt and capital lease
            
            $
            366,515
            
            
            $
            417,551





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.





In
December 2009, the Company entered into a series of privately negotiated
agreements in order to induce conversions of its outstanding Convertible Notes.
In connection with such agreements, the Company issued a total of 18,660,550
shares of its common stock in exchange for $63,498 aggregate principal amount of
its Convertible Notes. As a result of the exchanges, the Company recognized
losses on extinguishment of the related debt totaling $13,293 for the year ended
December 31, 2009. The Company did not incur any such losses in 2008 and
2007.





One
of the exchange agreements, as amended, provided for closing of additional
exchanges on each of January 11, 2010 and January 19, 2010 for exchange
transactions occurring in 2010. Subsequent to December 31, 2009, the noteholder
actually exchanged $22,000 aggregate principal amount of Convertible Notes for
6,198,668 shares of the Company’s common stock. As a result of the exchanges
settled in January 2010, the Company recognized a loss on extinguishment of the
related debt totaling $5,397 subsequent to December 31, 2009.




F-15


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








The
Convertible Notes are the Company’s senior unsecured obligations and are
guaranteed on a senior unsecured basis by the Company’s material current and
future domestic subsidiaries. The Convertible Notes and the related guarantees
rank equal in right of payment to all of the Company’s and the guarantors’
respective existing and future unsecured senior indebtedness. Interest is
payable semi-annually in arrears on February 1st and
August 1st of
each year. The Company assesses the convertibility of the Convertible Notes on
an ongoing basis. The Convertible Notes were not convertible as of December
31, 2009.





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 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 the
Convertible Notes become convertible, 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 WL Ross &
Co. LLC (“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-16


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Effective
January 1, 2009, the Company adopted ASC 470-20-65-1 (see Note 2). ASC
470-20-65-1 requires disclosure of the carrying amount of the equity component
of the related convertible debt, as well as the interest expense resulting from
amortization of the debt discount and interest expense recognized on the
principal amount of the debt. As of December 31, 2009 and 2008, the equity
component of the convertible debt was $9,702 and $13,517, respectively, and is
included in additional paid-in capital. Interest expense resulting from
amortization of the debt discount was $4,117, $3,714 and $1,434 for the years
ended December 31, 2009, 2008 and 2007, respectively. Interest expense on the
principal amount of the Convertible Notes was $20,042, $20,250 and $8,517 for
the years ended December 31, 2009, 2008 and 2007, respectively.





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, the Company 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, 2009,
the Company was in compliance with its covenants under the
indenture.





Credit
facility— The Company has a $100,000 revolving credit facility (the
“Credit Facility”) which matures on June 23, 2011. A maximum of $80,000 may
be used for letters of credit. In September 2009, the Company executed an
amendment to the Credit Facility that affected certain debt covenants. The
amendment modified the maximum permitted leverage and minimum interest coverage
ratios for 2010 and thereafter. The amendment also decreased the maximum capital
spending and added a minimum liquidity requirement for 2010. Pursuant to the
amendment, interest on the borrowings under the Credit Facility is payable, at
the Company’s option, at either the base rate plus an applicable margin of
2.75% to 3.50% or LIBOR plus an applicable margin of 3.75% to 4.50%, based
on the Company’s leverage ratio. As of December 31, 2009, the Company had no
borrowings outstanding and letters of credit totaling $73,551 outstanding,
leaving $26,449 available for future borrowing capacity, and was in compliance
with its financial covenants under the Credit Facility.





F-17




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Equipment
notes—The equipment notes, having various maturity dates extending to
September 2014, are collateralized by mining equipment. As of December 31, 2009,
the Company had amounts outstanding with terms ranging from 36 to 60 months and
a weighted-average interest rate of 7.35%. At December 31, 2009, additional
funds are available under the Company’s revolving equipment credit facility for
terms up to 60 months with a current interest rate of 6.75%.





Capital lease and
other—The Company leases certain mining equipment under a capital lease.
The Company imputed interest on its capital lease using a rate of
10.44%. Additionally, the Company has an insurance policy with a coverage
period of 17 months that it financed over 15 months at an interest rate of
5.42%.





Future
maturities of long-term debt and capital leases are as follows as of December
31, 2009:





Year
      ending December 31:2010
            
            $
            17,7942011
            
            
            16,2632012
            
            
            175,5472013
            
            
            8,3382014
            
            
            175,847Thereafter
            
            
            —Total
            
            
            393,789Less
      debt discount
            
            
            (9,480
            )Total
            
            $
            384,309





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 1.78%. As of December 31, 2009 and 2008, the Company
had $2,166 and $4,741, 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 margins. The
third-party profit margin 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. The
assets that give rise to the obligation are primarily related to mine
development, preparation plants and loadouts.





F-18


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








The
following schedule represents activity in the accrual for reclamation and mine
closure costs for the years ended December 31, 2009 and 2008:





2009
            
            
            2008Balance
      at beginning of year
            
            $
            79,246
            
            
            $
            85,920Revisions
      of estimated cash flows
            
            
            (3,574
            )
            
            
            (5,896
            )Liabilities
      incurred (net of disposals) or assumed in acquisitions
            
            
            (546
            )
            
            
            1,438Expenditures
            
            
            (7,566
            )
            
            
            (9,594
            )Accretion
            
            
            7,431
            
            
            
            7,378Balance
      at end of year
            
            $
            74,991
            
            
            $
            79,246





At
December 31, 2009 and 2008, the accrued reclamation and mine closure costs are
included in the accompanying consolidated balance sheets as
follows:





2009
            
            
            2008Current
      portion of reclamation and mine closure costs
            
            $
            9,390
            
            
            $
            11,139Non-current
      portion of reclamation and mine closure costs
            
            
            65,601
            
            
            
            68,107Total
            
            $
            74,991
            
            
            $
            79,246





11.
            INCOME
      TAXES





The
income tax (benefit) expense for the years ended December 31, 2009, 2008 and
2007 is comprised of the following:





2009
            
            
            2008
            
            
            2007Current:Federal
            
            $
            (1,249
            )
            
            $
            374
            
            
            $
            1,046State
            
            
            1,122
            
            
            
            390
            
            
            
            409(127
            )
            
            
            764
            
            
            
            1,455Deferred:Federal
            
            
            5,582
            
            
            
            (21,877
            )
            
            
            (75,684
            )State
            
            
            2,277
            
            
            
            (2,557
            )
            
            
            (11,715
            )7,859
            
            
            
            (24,434
            )
            
            
            (87,399
            )Income
      tax (benefit) expense
            
            $
            7,732
            
            
            $
            (23,670
            )
            
            $
            (85,944
            )





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, 2009, 2008 and 2007:





F-19




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








2009
            
            
            2008
            
            
            2007Federal
      income tax benefit computed at statutory rate
            
            $
            10,298
            
            
            $
            (17,464
            )
            
            $
            (81,727
            )State
      income tax expense (net of federal tax benefits) computed at statutory
      rate
            
            
            2,235
            
            
            
            (1,414
            )
            
            
            (7,345
            )Percentage
      depletion in excess of tax basis at statutory rate
            
            
            (9,204
            )
            
            
            (6,477
            )
            
            
            (1,784
            )Penalties
            
            
            1,007
            
            
            
            1,869
            
            
            
            —Goodwill
      impairment
            
            
            —
            
            
            
            (490
            )
            
            
            4,046Loss
      on extinguishment of debt
            
            
            2,841
            
            
            
            —
            
            
            
            —Other
            
            
            555
            
            
            
            306
            
            
            
            866Income
      tax (benefit) expense
            
            $
            7,732
            
            
            $
            (23,670
            )
            
            $
            (85,944
            )





Significant
components of the Company’s deferred tax assets and liabilities as of
December 31, 2009 and 2008 are summarized as follows:





2009
            
            
            2008Deferred
      tax assets:Accrued
      employee benefits
            
            $
            26,526
            
            
            $
            22,772Accrued
      reclamation and closure
            
            
            30,810
            
            
            
            30,274Below-market
      contracts
            
            
            10,124
            
            
            
            15,691NOL
      carryover
            
            
            79,510
            
            
            
            71,305Goodwill
            
            
            50,528
            
            
            
            53,960Other
            
            
            16,502
            
            
            
            19,705Total
      deferred tax assets
            
            
            214,000
            
            
            
            213,707Valuation
      allowance for deferred tax assets
            
            
            (2,561
            )
            
            
            (2,396
            )Total deferred tax assets, net of valuation allowance
            
            
            211,439
            
            
            
            211,311Deferred
      tax liabilities:Property,
      coal lands and mine development costs
            
            
            (246,579
            )
            
            
            (232,937
            )Other
            
            
            (6,353
            )
            
            
            (11,879
            )Total
      deferred tax liabilities
            
            
            (252,932
            )
            
            
            (244,816
            )Net
      deferred tax liability
            
            $
            (41,493
            )
            
            $
            (33,505
            )Classified
      in balance sheet:Deferred
      income taxes—current
            
            $
            15,906
            
            
            $
            17,649Deferred
      income taxes—non-current
            
            
            (57,399
            )
            
            
            (51,154
            )Total
            
            $
            (41,493
            )
            
            $
            (33,505
            )





The
Company has a total net operating loss (“NOL”) carryover of $207,668, of which
$2,707 expires in 2024, $17,154 expires in 2025, $4,818 expires in 2026, $99,792
expires in 2027, $58,514 expires in 2028 and $24,683 expires in 2029. 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
carryover in the amount of $36,121, of which $4,451 expires in 2024, $16,796
expires in 2025, $10,186 expires in 2028 and $4,688 expires in 2029. 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 2005, 2006 and 2007.





F-20


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Internal
Revenue Code (“IRC”) Section 382 imposes significant limitations on the annual
utilization of NOL carryforwards if a “change in ownership” is deemed to occur.
Generally, an ownership change is deemed to occur if the Company experiences a
cumulative change in ownership of greater than 50% within a three-year testing
period. The Company completed an IRC Section 382 study and determined that no
ownership change had occurred in 2009.





The
Company recorded valuation allowances against certain state NOL carryforwards
that, more likely than not, are expected to expire without being utilized. The
valuation allowance increased $165, $808 and $883 during the years ended
December 31, 2009, 2008 and 2007, respectively.





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





12.
            EMPLOYEE
      BENEFITS





Employee
benefits at December 31, 2009 and 2008 are summarized as follows:





2009
            
            
            2008Postretirement
      benefits
            
            $
            30,048
            
            
            $
            27,974Black
      lung benefits
            
            
            25,936
            
            
            
            22,824Workers’
      compensation benefits
            
            
            10,307
            
            
            
            7,847Coal
      Act benefits
            
            
            1,449
            
            
            
            1,277Total
            
            
            67,740
            
            
            
            59,922Less
      current portion
            
            
            (3,973
            )
            
            
            (3,359
            )Employee
      benefits—non-current
            
            $
            63,767
            
            
            $
            56,563





Valuation
Date—All actuarially determined benefits were determined as of December
31, 2009 and 2008.





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 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 5.75% and 6.25% to determine
the postretirement benefit liability as of December 31, 2009 and 2008,
respectively, and 6.25%, 6.50% and 5.75% to determine the net periodic benefit
costs for the years ended December 31, 2009, 2008 and 2007,
respectively.





F-21


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Postretirement
benefit information for the years ended December 31, 2009 and 2008 is as
follows:





2009
            
            
            2008Changes
      in Benefit Obligations:Accumulated
      benefit obligations at beginning of period
            
            $
            27,974
            
            
            $
            25,024Service
      cost
            
            
            3,335
            
            
            
            2,607Interest
      cost
            
            
            1,748
            
            
            
            1,627Actuarial
      gain
            
            
            (2,986
            )
            
            
            (1,257
            )Benefits
      paid
            
            
            (23
            )
            
            
            (27
            )Accumulated
      benefit obligation at end of period
            
            
            30,048
            
            
            
            27,974Fair
      value of plan assets at end of period
            
            
            —
            
            
            
            —Net
      liability recognized
            
            $
            30,048
            
            
            $
            27,974





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




2009
              
              
              2008
              
              
              2007Balance
      at beginning of year
              
              $
              8,548
              
              
              $
              10,235
              
              
              $
              6,925Actuarial
      (gain) loss
              
              
              (2,986
              )
              
              
              (1,257
              )
              
              
              3,593Amortization
      of actuarial loss
              
              
              (288
              )
              
              
              (430
              )
              
              
              (283
              )Balance
      at end of year
              
              $
              5,274
              
              
              $
              8,548
              
              
              $
              10,235





The
Company expects to recognize $113 of the net actuarial loss as a component of
the net periodic benefit cost during 2010. Components of net periodic benefit
cost for the years ended December 31, 2009, 2008 and 2007 are as
follows:





2009
            
            
            2008
            
            
            2007Net
      periodic benefit cost:Service
      cost
            
            $
            3,335
            
            
            $
            2,607
            
            
            $
            2,057Interest
      cost
            
            
            1,748
            
            
            
            1,627
            
            
            
            1,054Amortization
      of actuarial loss
            
            
            288
            
            
            
            430
            
            
            
            283Benefit
      cost
            
            $
            5,371
            
            
            $
            4,664
            
            
            $
            3,394





For
measurement purposes at December 31, 2009, a 6.40% annual rate of increase in
the per capita cost of covered healthcare benefits was assumed, gradually
decreasing to 4.50% in 2061 and remaining level thereafter.





The
expense and liability estimates can fluctuate by significant amounts based upon
the assumptions used. As of December 31, 2009, 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 $432 and $2,115,
respectively. Conversely, a one-percentage-point decrease would reduce total
service and interest cost components and the postretirement benefit obligation
by $414 and $2,016, respectively.





F-22


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Estimated
future benefit payments for the years indicated ending after December 31, 2009
are as follows:





2010
            
            $
            4302011
            
            
            8132012
            
            
            1,2782013
            
            
            1,8062014
            
            
            2,2612015
      – 2019
            
            
            20,937Total
            
            $
            27,525





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. As of December 31, 2009, the Company determined the effects of the Act
resulted in a $2,496 reduction of its postretirement benefit obligation. The Act
is expected to result in a $560 reduction of the Company’s postretirement
benefit cost for the year ended December 31, 2010. The effect on the
Company’s postretirement benefit cost components includes reductions of $304,
$144 and $112 to the service cost, interest cost and amortization of accumulated
postretirement benefit obligation, respectively.





Black
Lung—The Company’s actuarially determined liability for self-insured
black lung benefits at December 31, 2009 and 2008 was based on discount rates of
6.00% and 5.75%, respectively, and various other assumptions, including
incidence of claims, benefits escalation, terminations and life expectancy. The
Company determined net periodic benefit costs using discount rates of 5.75%,
6.50% and 6.00% for the years ended December 31, 2009, 2008 and 2007,
respectively.





The
annual black lung expense consists of actuarially determined amounts for
self-insured obligations.





Black
lung benefit information for the years ended December 31, 2009 and 2008 is as
follows:





2009
            
            
            2008Changes
      in Benefit Obligations:Accumulated
      benefit obligations at beginning of period
            
            $
            22,824
            
            
            $
            17,758Service
      cost
            
            
            2,771
            
            
            
            2,045Interest
      cost
            
            
            1,579
            
            
            
            1,611Actuarial
      (gain) loss
            
            
            (1,151
            )
            
            
            1,451Benefits
      paid
            
            
            (87
            )
            
            
            (41
            )Accumulated
      benefit obligation at end of period
            
            
            25,936
            
            
            
            22,824Fair
      value of plan assets at end of period
            
            
            —
            
            
            
            —Net
      liability
            
            $
            25,936
            
            
            $
            22,824





F-23


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








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




2009
              
              
              2008
              
              
              2007Balance
      at beginning of year
              
              $
              (4,631
              )
              
              $
              (7,030
              )
              
              $
              (3,431
              )Actuarial
      (gain) loss
              
              
              (1,151
              )
              
              
              1,451
              
              
              
              (3,901
              )Amortization
      of actuarial gain
              
              
              390
              
              
              
              948
              
              
              
              302Balance
      at end of year
              
              $
              (5,392
              )
              
              $
              (4,631
              )
              
              $
              (7,030
              )




The
Company expects to recognize $140 of the net actuarial gain as a component of
the net periodic benefit cost during 2010. Components of net periodic benefit
cost for the years ended December 31, 2009, 2008 and 2007 are as
follows:





2009
            
            
            2008
            
            
            2007Net
      periodic benefit cost:Service
      cost
            
            $
            2,771
            
            
            $
            2,045
            
            
            $
            2,799Interest
      cost
            
            
            1,579
            
            
            
            1,611
            
            
            
            1,262Amortization
      of actuarial gain
            
            
            (390
            )
            
            
            (948
            )
            
            
            (302
            )Benefit
      cost
            
            $
            3,960
            
            
            $
            2,708
            
            
            $
            3,759





Estimated
future benefit payments for the years indicated ending after December 31, 2009
are as follows:





2010
            
            $
            3462011
            
            
            8232012
            
            
            8372013
            
            
            1,0392014
            
            
            1,4592015
      – 2019
            
            
            11,202Total
            
            $
            15,706





Workers’
Compensation—The operations of the Company are subject to the federal and
state workers’ compensation laws. These laws provide for the payment of benefits
to disabled workers and their dependents, including lifetime benefits for black
lung. The Company’s subsidiary operations are insured by a combination of
participation in a state run program and insurance policies. Based upon
actuarially determined information, the Company estimates its workers’
compensation liability to be approximately $10,307 and $7,847 at December 31,
2009 and 2008, discounted at 4.75% and 5.50%, respectively.





UMWA Combined
Benefit Fund (Coal Act)—The Coal Industry Retiree Health Benefit Act of
1992 (the “Coal Act”) provides for the funding of medical and death benefits for
certain retired members of the UMWA. It provides for the assignment of
beneficiaries to their former employers and any unassigned beneficiaries to
employers based on a formula. Based upon actuarially determined amounts for the
latest list of beneficiaries assigned to the Company’s Hunter Ridge Holdings,
Inc. (“Hunter Ridge”) subsidiary, the Company estimates the amount of its
obligation under the Coal Act to be approximately $1,449 and $1,277 as of
December 31, 2009 and 2008, discounted at 5.50% and 6.25%, respectively. The
Company recognized interest expense related to the Coal Act of $74, $80 and $302
for the years ended December 31, 2009, 2008 and 2007, respectively.





F-24


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








401(k)
Plans—The Company sponsors a 401(k) savings and retirement plan for all
employees, except those employed by its Hunter Ridge subsidiary. Under the plan,
the Company matches voluntary contributions of participants up to a maximum
contribution of 3% of a participant’s salary. The Company also contributes an
additional 3% non-elective contribution for every employee eligible to
participate in the program. The expense under this plan for the Company was
$7,153, $6,971 and $4,293 for the years ended December 31, 2009, 2008 and 2007,
respectively.





For
those employees employed by Hunter Ridge, the Company also has a separate 401(k)
savings plan. The plan provides for a 100% match of the first 3% of employee
contributions and 50% of the next 2% of employee contributions. The Company also
contributes an additional 5% non-elective contribution for every employee who
meets certain eligibility requirements. The expense under this plan for the
Company was $2,537, $1,956 and $1,776 for the years ended December 31, 2009,
2008 and 2007, respectively.





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 18,000,000 shares of common stock. Option awards are generally granted
with an exercise price equal to the market price of the Company’s stock at the
date of grant and have 10-year contractual terms. The option and restricted
stock awards generally vest in equal annual installments of 25% over a four-year
period. The Company recognizes expense related to the awards on a straight-line
basis over the vesting period. 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 2009, 2008 and 2007 was calculated using the following
assumptions:





2009
            
            
            2008
            
            
            2007Expected
      term (in years)
            
            
            5
            
            
            
            5
            
            
            
            5Expected
      volatility
            
            
            48.2%
      - 50.8
            %
            
            
            43.0%
      - 48.2
            %
            
            
            43.0%
      - 48.1
            %Weighted-average
      volatility
            
            
            50.8
            %
            
            
            43.5
            %
            
            
            43.2
            %Risk-free
      rate
            
            
            1.4%
      - 2.8
            %
            
            
            1.7%
      - 3.7
            %
            
            
            4.0%
      - 5.1
            %Expected
      dividends
            
            
            —
            
            
            
            —
            
            
            
            —





The
Company estimated a forfeiture rate of 4.50%, 4.50% and 3.25% for 2009, 2008 and
2007, 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.





F-25


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Share
based employee compensation expense of $2,304, $2,596 and $3,134, net of tax of
$1,401, $1,578 and $2,090, related to the issuance of all stock awards
outstanding was included in earnings for the years ended December 31, 2009, 2008
and 2007, respectively.





A
summary of the Company’s outstanding options as of December 31, 2009, and
changes during the year ended December 31, 2009, is as follows:





Options
            
            Shares
            
            
            Weighted-
              Average
              Exercise
              Price
            
            
            Weighted-
              Average
              Remaining
              Contractual
              Term
              (years)
            
            
            Aggregate
              Intrinsic
              ValueOutstanding
      at January 1, 2009
            
            
            2,831,192
            
            
            $
            7.88Granted
            
            
            2,329,156
            
            
            
            1.54Exercised
            
            
            —
            
            
            
            —Forfeited
      and expired
            
            
            (125,738
            )
            
            
            5.71Outstanding
      at December 31, 2009
            
            
            5,034,610
            
            
            
            5.00
            
            
            
            7.95
            
            
            $
            5,328Vested or expected to vest at December
      31, 2009
            
            
            4,762,538
            
            
            
            5.12
            
            
            
            7.90
            
            
            $
            4,873Exercisable
      at December 31, 2009
            
            
            1,834,958
            
            
            
            8.60
            
            
            
            6.42
            
            
            $
            19





The
weighted-average grant-date fair value of options granted during the years ended
December 31, 2009, 2008 and 2007 was $0.70, $2.64 and $2.65, respectively. The
total intrinsic value of options exercised during the year ended December 31,
2008 was $47. There were no options exercised in 2009 or 2007.





A
summary of the status of the Company’s nonvested restricted stock awards as of
December 31, 2009 and changes during the year ended December 31, 2009 is as
follows:





Nonvested
      Shares
            
            Shares
            
            
            Weighted-
              Average Grant-Date
              Fair
      ValueNonvested
      at January 1, 2009
            
            
            556,344
            
            
            $
            7.00Granted
            
            
            852,097
            
            
            
            1.56Vested
            
            
            (224,445
            )
            
            
            7.35Forfeited
            
            
            (35,517
            )
            
            
            4.41Nonvested
      at December 31, 2009
            
            
            1,148,479
            
            
            
            2.97





The
weighted-average grant-date fair value of restricted stock granted during the
years ended December 31, 2009, 2008 and 2007 was $1.56, $6.74 and $5.87,
respectively. The total fair value of restricted stock vested during the years
ended December 31, 2009, 2008 and 2007 was $1,649, $3,361 and $3,221,
respectively.





F-26




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








As
of December 31, 2009, there was $5,398 of unrecognized compensation cost related
to non-vested share based awards that is expected to be recognized over a
weighted-average period of 2.4 years.





The
Plan provides recipients the ability to satisfy tax obligations upon vesting of
shares of restricted stock by having the Company withhold a portion of the
shares otherwise deliverable to the recipients. During the year ended December
31, 2009, the Company withheld 7,321 shares of common stock from employees in
connection with tax withholding obligations. The value of the common stock that
was withheld was based upon the closing price of the common stock on the
applicable vesting dates. Such shares were included in treasury stock in the
Company’s consolidated balance sheet at December 31, 2009.





In
December 2008, the Company’s Board of Directors (the “Board”) approved an annual
restricted share unit grant with a grant date value equal to $50 for each member
of the Board to be granted at the same time as the annual equity awards granted
to executive officers. Each restricted share unit represents a contingent right
to receive one share of issuer common stock upon the six-month anniversary of
the date on which the director ceases to provide services, subject to certain
provisions. The number of shares issuable is calculated by dividing $50 by the
closing stock price of the Company’s common stock on the New York Stock Exchange
on the grant date. Each non-employee director was issued 32,895 restricted share
units on March 3, 2009. The weighted-average grant-date fair value of restricted
share units granted during the year ended December 31, 2009 was $1.52. The total
fair value of restricted share units vested during the year ended December 31,
2009 was $350. There were no restricted share units granted during the years
ended December 31, 2008 and 2007.





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 has consolidated the accounts of Sycamore as of December 31, 2009 and 2008,
as well as the results of operations for the years ended December 31, 2009, 2008
and 2007. 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, 2009, 2008 and
2007 are as follows:





2009
            
            
            2008
            
            
            2007Assets
            
            $
            188
            
            
            $
            213
            
            
            $
            257Liabilities
            
            
            65
            
            
            
            138
            
            
            
            187Revenue
            
            
            —
            
            
            
            —
            
            
            
            1,808Net
      income (loss)
            
            
            66
            
            
            
            —
            
            
            
            (403
            )








F-27




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








15.
            EARNINGS
      PER SHARE





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





Reconciliations
of the weighted-average shares used to compute basic and diluted earnings per
share for the years ended December 31, 2009, 2008 and 2007 are as
follows:





2009
            
            
            2008
            
            
            2007Net
      income (loss) attributable to International Coal Group,
    Inc.
            
            $
            21,458
            
            
            $
            (26,227
            )
            
            $
            (147,562
            )Average
      common shares outstanding—Basic
            
            
            153,630,446
            
            
            
            152,632,586
            
            
            
            152,304,461Incremental
      shares arising from:Stock
      options
            
            
            290,019
            
            
            
            —
            
            
            
            —Restricted
      shares
            
            
            1,367,577
            
            
            
            —
            
            
            
            —Restricted
      share units
            
            
            98,221
            
            
            
            —
            
            
            
            —Convertible
      senior notes
            
            
            —
            
            
            
            —
            
            
            
            —Average
      common shares outstanding—Diluted
            
            
            155,386,263
            
            
            
            152,632,586
            
            
            
            152,304,461Earnings
      Per Share:Basic
            
            $
            0.14
            
            
            $
            (0.17
            )
            
            $
            (0.97
            )Diluted
            
            
            0.14
            
            
            
            (0.17
            )
            
            
            (0.97
            )





Options
to purchase 2,748,672 shares of common stock outstanding at December 31, 2009
and 3,384,443 shares of potentially issuable common stock related to an
agreement to exchange Convertible Notes subsequent to December 31,
2009 (see Note 9) have been excluded from the computation of diluted earnings
per share for the year ended December 31, 2009 because their effect would have
been anti-dilutive. Options to purchase 2,831,192 shares of common stock and
556,344 shares of restricted common stock outstanding at December 31, 2008 have
been excluded from the computation of diluted earnings per share for the year
ended December 31, 2008 because their effect would have been anti-dilutive.
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 earnings per share for the year ended December 31,
2007 because their effect would have been anti-dilutive.





The
principal amount of the Convertible Notes is payable in cash and amounts above
the principal amount, if any, will be settled with shares of the Company’s
common stock or, at the Company’s option, cash. The volume weighted-average
price of the Company’s common stock for the applicable cash settlement averaging
period was below the initial conversion price of $6.10 per share. Accordingly,
there were no potentially dilutive shares related to the Convertible Notes at
December 31, 2009 and 2008.





F-28


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(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, 2009, the Company had commitments under 40
sales contracts to deliver annually scheduled base quantities of coal to 31
customers. The contracts expire from 2010 through 2020 with the Company
contracted to supply approximately 49.8 million tons of coal over the
remaining lives of the contracts (approximately 13.7 million tons in
2010).





Diesel Fuel
Purchase Contracts—As of December 31, 2009 and 2008, the Company had
commitments to purchase $39,859 and $73,753, respectively, of diesel fuel during
2010 and 2009, respectively.





Coal Purchase
Contracts—As of December 31, 2009, 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 Company’s future contractual
purchase obligations were $14,377 as of December 31, 2009. The commitment is
scheduled to be fulfilled in 2010. The Company incurred purchased coal expense
of approximately $23,448, $23,363 and $13,892 for the years ended December 31,
2009, 2008 and 2007 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,
2009, 2008 and 2007 was $4,138, $4,970 and $6,254, respectively. Property under
capital lease included in property, plant, equipment and mine development in the
consolidated balance sheet at December 31, 2009 and 2008 was approximately
$3,430 and $3,816, less accumulated depreciation of approximately $386 and $0,
respectively. Depreciation expense related to assets under capital lease for the
year ended December 31, 2009 was $386 and is included in depreciation, depletion
and amortization in the Company’s consolidated statement of operations. The
Company entered into its only capital lease on December 31, 2008 and,
accordingly, did not record depreciation expense related to the asset for the
years ended December 31, 2008 and 2007. The Company imputed interest on its
capital lease using a rate of 10.44% in order to reduce the net minimum lease
payments to present value.





F-29




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








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, 2009, 2008 and 2007 was approximately $55,063, $52,232 and
$37,680, respectively. Certain agreements require minimum annual royalties to be
paid regardless of the amount of coal mined during the year. Certain agreements
may be cancelable at the Company’s discretion.





Non-cancelable
future minimum royalty and lease payments as of December 31, 2009 are as
follows:





Royalties
            
            
            Operating
      Leases
            
            
            Capital
      LeasesYear
      ended December 31,2010
            
            $
            10,462
            
            
            $
            98
            
            
            $
            1,7262011
            
            
            10,201
            
            
            
            56
            
            
            
            1,1512012
            
            
            8,288
            
            
            
            23
            
            
            
            —2013
            
            
            7,875
            
            
            
            8
            
            
            
            —2014
            
            
            7,660
            
            
            
            7
            
            
            
            —Thereafter
            
            
            29,815
            
            
            
            2
            
            
            
            —Total
      minimum lease payments
            
            $
            74,301
            
            
            $
            194
            
            
            $
            2,877Less—amount
      representing interest
            
            
            
            
            
            
            
            
            
            
            (247
            )Present
      value of minimum lease payments
            
            
            
            
            
            
            
            
            
            
            2,630Less—current
      portion
            
            
            
            
            
            
            
            
            
            
            (1,523
            )Total
      long-term portion of capital leases
            
            
            
            
            
            
            
            
            
            $
            1,107





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 $4,053, $4,457 and $3,883 for the
years ended December 31, 2009, 2008 and 2007, respectively. ICG has determined
it does not hold a significant variable interest in LCC and it is not the
primary beneficiary of LCC.





F-30




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Legal
Matters—On August 23, 2006, a survivor of the Sago mine accident,
Randal McCloy, filed a complaint in the Kanawha Circuit Court in Kanawha County,
West Virginia. The claims brought by Randal McCloy and his family against the
Company and certain of its subsidiaries, and against W.L. Ross & Co.,
and Wilbur L. Ross, Jr., individually, were dismissed on February 14, 2008,
after the parties reached a confidential settlement. Sixteen other complaints
have been filed in Kanawha Circuit Court by the representatives of many of the
miners who died in the Sago mine accident, and several of these plaintiffs have
filed amended complaints to expand the group of defendants in the cases. The
complaints allege various causes of action against the Company and its
subsidiary, Wolf Run Mining Company, one of its shareholders, W.L.
Ross & Co., and Wilbur L. Ross, Jr., individually, related to the
accident and seek compensatory and punitive damages. In addition, the plaintiffs
also allege causes of action against other third parties, including claims
against the manufacturer of Omega block seals used to seal the area where the
explosion occurred and against the manufacturer of self-contained self-rescuer
(“SCSR”) devices worn by the miners at the Sago mine. Some of these third
parties have been dismissed from the actions upon settlement. The amended
complaints add other of the Company’s subsidiaries to the cases, including ICG,
Inc., ICG, LLC and Hunter Ridge Coal Company, unnamed parent, subsidiary and
affiliate companies of the Company, W.L. Ross & Co., and Wilbur L.
Ross, Jr., and other third parties, including a provider of electrical services
and a supplier of components used in the SCSR devices. The Company believes that
it is appropriately insured for these and other potential claims, and has fully
paid its deductible applicable to its insurance policies. In addition to the
dismissal of the McCloy claim, the Company has settled and dismissed five other
actions. These settlements required the release of the Company, its
subsidiaries, W.L. Ross & Co., and Wilbur L. Ross, Jr. The Company will
vigorously defend itself against the remaining complaints.





Allegheny
Energy Supply (“Allegheny”), the sole customer of coal produced at the Company’s
subsidiary Wolf Run Mining Company’s (“Wolf Run”) Sycamore No. 2 mine,
filed a lawsuit against Wolf Run, Hunter Ridge Holdings, Inc.
(“Hunter Ridge”), and the Company in state court in Allegheny County,
Pennsylvania on December 28, 2006, and amended its complaint on
April 23, 2007. Allegheny claims that the Company breached a coal supply
contract when it declared force majeure under the contract upon idling the
Sycamore No. 2 mine in the third quarter of 2006. 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. On September 23, 2009, Allegheny filed a second amended
complaint alleging several alternative theories of liability in its effort to
extend contractual liability to the Company, which was not a party to the
original contract and did not exist at the time Wolf Run and Allegheny entered
into the contract. No new substantive claims were asserted. The Company answered
the second amended complaint on October 13, 2009, denying all of the new claims.
In late September 2009, Allegheny suspended deliveries from the Sycamore No. 2
mine, claiming excessive inventory at its Harrison station, and on October 6,
2009, issued a notice of force majeure related to transmission line work and
replacement of a transformer. Allegheny retracted its notice of force majeure on
November 12, 2009. Upon Allegheny’s subsequent request, the Sycamore No. 2 mine
resumed production promptly, and deliveries resumed from the mine as of December
21, 2009.





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Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(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,
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
alleged 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 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. The ACOE completed its evaluation
on March 25, 2009, and on March 27, 2009, reinstated Hazard’s permit. Pursuant
to earlier agreements with the plaintiffs in the litigation, the Company
provided thirty (30) days notice to plaintiffs’ counsel of Hazard’s intent to
proceed with activities authorized under the permit. After such notice, the
plaintiffs agreed to amend the earlier agreement to allow Hazard partial use of
the reinstated permit, including construction of an additional valley fill.
Subsequently, the parties agreed to pursue resolution of the case in accordance
with a scheduling order entered by the court. Pursuant to that order, the
plaintiffs filed an amended complaint on July 10, 2009. The amended complaint
modified the plaintiffs’ allegations to apply to the reissued permit, rather
than the original permit. On November 13, 2009, the parties entered into a final
settlement agreement resolving the disputed issues between them. The action was
dismissed by the District Court on November 24, 2009.





On
January 7, 2008, Saratoga Advantage Trust (“Saratoga”) filed a class action
lawsuit in the U.S. District Court for the Southern District of West Virginia
against the Company and certain of its officers and directors. The complaint
asserts claims under Sections 10(b) and 20(a) of the Securities Exchange
Act of 1934, and Rule 10b-5 promulgated thereunder, based on alleged false and
misleading statements in the registration statements filed in connection with
the Company’s November 2005 reorganization and December 2005 public offering of
common stock. In addition, the complaint challenges other of the Company’s
public statements regarding its operating condition and safety record. On July
6, 2009, Saratoga filed an amended complaint asserting essentially the same
claims but seeking to add an individual co-plaintiff. The Company has filed a
motion to dismiss the amended complaint. The Company 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 prepared and submitted a permit
modification to alleviate the Board’s concerns. The revision was approved by the
WVDEP on May 27, 2009, reinstating the Tygart permit. As expected, T.E.A.M.
appealed the reinstatement. A hearing was commenced on January 12, 2010, but was
not concluded. The Board scheduled the resumption of the hearing for February 9,
2010.





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





F-32


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Environmental
Matters—The exact nature of environmental control problems, if any, which
the Company may encounter in the future cannot be predicted, primarily because
of the increasing number, complexity and changing character of environmental
requirements that may be enacted by federal and state authorities.





Performance
Bonds—The Company has outstanding surety bonds with third parties of
approximately $116,962 as of December 31, 2009 to secure reclamation and other
performance commitments. In addition, at December 31, 2009 the Company has
$73,551 of letters of credit outstanding under the revolving credit facility,
$61,126 of which provides support to the third parties for their issuance of
surety bonds. In addition, the Company has posted cash collateral of $12,057 and
$1,589 to secure reclamation and other performance commitments as of December
31, 2009 and 2008, 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 2010 to 2011 or, in some cases, until all
coal reserves are exhausted.





17.
            CONCENTRATION
      OF CREDIT RISK AND MAJOR CUSTOMERS





The
Company markets its coal principally to electric utilities in the United States,
the majority of which have investment grade credit ratings. As of December 31,
2009 and 2008, trade accounts receivable from electric utilities totaled
approximately $56,222 and $49,059, respectively. The Company evaluates each
customer’s creditworthiness prior to entering into transactions and constantly
monitors the credit extended, but does not require its customers to provide
collateral. Credit losses are provided for in the consolidated financial
statements and historically have been minimal.





The
Company did not derive 10% or more of its revenues from any single customer for
the years ended December 31, 2009 and 2008. For the year ended December 31,
2007, the Company had $97,389 of sales to one customer that exceeded 10% of
revenues.





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-33




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








18.
            FAIR
      VALUE OF FINANCIAL INSTRUMENTS





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





The
Company entered into an Interest Rate Collar Agreement (the “Collar”) that
expired and was settled on March 31, 2009. The interest rate collar was
designed as a cash flow hedge to offset the impact of changes in the LIBOR
interest rate above 5.92% and below 4.80%. The fair value of the Collar was
$1,665 as of December 31, 2008 based on a forward LIBOR curve, which was
observable at commonly quoted intervals for the full term of the agreement
(Level 2). The Company recognized the change in the fair value of this agreement
in the period of change. For the years ended December 31, 2009, 2008 and 2007,
the Company recognized losses of $6, $1,993 and $1,649, respectively, related to
the change in fair value. The losses are included in interest expense in the
Company’s consolidated statements of operations.





Cash and Cash
Equivalents, Accounts Receivable, Accounts Payable, Short-Term Debt and Other
Current Liabilities—The carrying amounts approximate the fair value due
to the short maturity of these instruments.





Long-term
Debt—At December 31, 2009 and 2008, the Company had $161,502 and
$225,000, respectively, aggregate principal amount of its 9.0% Convertible Notes
outstanding. The fair value of the Convertible Notes was approximately $177,458
and $114,683 as of December 31, 2009 and 2008, respectively. At December 31,
2009 and 2008, the Company had $175,000 aggregate principal amount of its 10.25%
Senior Notes outstanding. The fair value of the Senior Notes was approximately
$168,219 and $131,250 as of December 31, 2009 and 2008,
respectively.





The
carrying value of the Company’s other debt approximates fair value at December
31, 2009 and 2008.





19.
            RELATED
      PARTY TRANSACTIONS AND BALANCES





Under
an Advisory Services Agreement dated as of October 1, 2004 between the
Company and WL Ross & Co., LLC (“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.





F-34


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








20.
            SEGMENT
      INFORMATION





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





Reportable
segment results for continuing operations for the year ended December 31, 2009
and segment assets as of December 31, 2009 were as follows:





Central
              Appalachian
            
            
            Northern
              Appalachian
            
            
            Illinois
              Basin
            
            
            Ancillary
            
            
            ConsolidatedRevenue
            
            $
            734,687
            
            
            $
            223,486
            
            
            $
            83,908
            
            
            $
            83,268
            
            
            $
            1,125,349Adjusted
      EBITDA
            
            
            169,842
            
            
            
            31,005
            
            
            
            14,405
            
            
            
            (13,575
            )
            
            
            201,677Depreciation,
      depletion and amortization
            
            
            71,298
            
            
            
            20,991
            
            
            
            7,957
            
            
            
            5,838
            
            
            
            106,084Capital
      expenditures
            
            
            44,289
            
            
            
            21,159
            
            
            
            17,573
            
            
            
            4,864
            
            
            
            87,885Total
      assets
            
            
            723,818
            
            
            
            184,626
            
            
            
            55,311
            
            
            
            404,205
            
            
            
            1,367,960





Revenue
in the Ancillary category consists primarily of $41,678 relating to the
Company’s brokered coal sales and $18,737 relating to contract highwall mining
activities. Capital expenditures include non-cash amounts of $34,482 for the
year ended December 31, 2009. Capital expenditures do not include $12,942 paid
during the year ended December 31, 2009 related to capital expenditures
accrued in prior periods.





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.





F-35


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








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.





Adjusted
EBITDA represents net income before deducting interest, income taxes,
depreciation, depletion, amortization, loss on extinguishment of debt,
impairment charges and noncontrolling interest. Adjusted EBITDA is presented
because it is an important supplemental measure of 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 31,2009
            
            
            2008
            
            
            2007Net
      income (loss) attributable to International Coal Group,
    Inc.
            
            $
            21,458
            
            
            $
            (26,227
            )
            
            $
            (147,562
            )Depreciation,
      depletion and amortization
            
            
            106,084
            
            
            
            96,047
            
            
            
            86,517Interest
      expense, net
            
            
            53,044
            
            
            
            43,643
            
            
            
            35,989Income
      tax expense (benefit)
            
            
            7,732
            
            
            
            (23,670
            )
            
            
            (85,944
            )Loss
      on extinguishment of debt
            
            
            13,293
            
            
            
            —
            
            
            
            —Impairment
      loss
            
            
            —
            
            
            
            37,428
            
            
            
            170,402Noncontrolling
      interest
            
            
            66
            
            
            
            —
            
            
            
            (349
            )Adjusted
      EBITDA
            
            $
            201,677
            
            
            $
            127,221
            
            
            $
            59,053





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-36


Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(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):





2009Three months
              ended
              March 31
            
            
            Three months
              ended
              June 30
            
            
            Three months
              ended
              September 30
            
            
            Three months
              ended
              December 31Revenue
            
            $
            304,966
            
            
            $
            277,797
            
            
            $
            296,622
            
            
            $
            245,964Income
      from operations
            
            
            18,235
            
            
            
            26,205
            
            
            
            37,689
            
            
            
            13,464Net
      income (loss) attributable to International Coal Group,
    Inc.
            
            
            3,693
            
            
            
            10,382
            
            
            
            18,716
            
            
            
            (11,333
            )Basic
      earnings per common share
            
            $
            0.02
            
            
            $
            0.07
            
            
            $
            0.12
            
            
            $
            (0.07
            )Diluted
      earnings per common share
            
            $
            0.02
            
            
            $
            0.07
            
            
            $
            0.12
            
            
            $
            (0.07
            )





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
            )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
            )








F-37




Table of contents


INTERNATIONAL
COAL GROUP, INC. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS


For
the years ended December 31, 2009, 2008 and 2007


(Dollars
in thousands, except per share amounts)








Included
in net income (loss) attributable to International Coal Group, Inc. for the
three months ended December 31, 2009 are losses on extinguishment of debt
totaling $13,293 related to the Company entering into a series of privately
negotiated agreements pursuant to which it issued a total of 18,660,550 shares
of its common stock in exchange for $63,498 aggregate principal amount of its
Convertible Notes.





Included
in net income (loss) attributable to International Coal Group, Inc. for the
three months ended December 31, 2008 is an impairment loss of $37,428. Of the
loss, $30,237 related to impairment of goodwill at the Company’s ADDCAR
subsidiary and $7,191 related to impairment of long-lived assets. See Notes 4
and 5 to the Company’s consolidated financial statements for further discussion
of the impairment losses.





23.
            SUBSEQUENT
      EVENTS





The
Company has evaluated events and transactions occurring subsequent to the
balance sheet date for items that should potentially be recognized or disclosed
in its financial statements. The evaluation was conducted through January 29,
2010, the date of the filing of this Annual Report on Form 10-K.





Subsequent
to December 31, 2009, pursuant to an exchange agreement discussed in Note 9, a
noteholder exchanged $22,000 aggregate principal amount of Convertible Notes for
6,198,668 shares of the Company’s common stock. As a result of the exchanges
settled in January 2010, the Company recognized a loss on extinguishment of the
related debt totaling $5,397 subsequent to December 31, 2009.




F-38




Table of contents


Schedule I—Condensed FinancialInformation of the
Registrant





International
Coal Group, Inc.





Parent
Company Balance Sheets


(Dollars
in thousands, except per share amounts)





December
      31,
              2009
            
            
            December 31,
              2008ASSETSCURRENT
      ASSETS:Prepaid
      expenses and other
            
            $
            391
            
            
            $
            —DEBT
      ISSUANCE COSTS, net
            
            
            5,822
            
            
            
            8,851DEFERRED
      INCOME TAXES
            
            
            37,877
            
            
            
            18,806INVESTMENT
      IN SUBSIDIARIES
            
            
            906,952
            
            
            
            877,885Total
      assets
            
            $
            951,042
            
            
            $
            905,542LIABILITIES
      AND STOCKHOLDERS’ EQUITYCURRENT
      LIABILITIES:Accounts
      payable
            
            $
            451
            
            
            $
            —Accrued
      expenses and other
            
            
            14,396
            
            
            
            16,709Total
      current liabilities
            
            
            14,847
            
            
            
            16,709LONG-TERM
      DEBT
            
            
            327,022
            
            
            
            382,631Total
      liabilities
            
            
            341,869
            
            
            
            399,340COMMITMENTS
      AND CONTINGENCIESSTOCKHOLDERS’
      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, 172,820,047 and
      172,812,726 shares issued and outstanding, respectively, as of December
      31, 2009 and 153,322,245 shares issued and outstanding, as of December 31,
      2008
            
            
            1,728
            
            
            
            1,533Treasury
      stock
            
            
            (14
            )
            
            
            —Additional
      paid-in capital
            
            
            732,124
            
            
            
            656,997Accumulated
      other comprehensive income (loss)
            
            
            1,048
            
            
            
            (5,157
            )Retained
      deficit
            
            
            (125,713
            )
            
            
            (147,171
            )Total
      stockholders’ equity
            
            
            609,173
            
            
            
            506,202Total
      liabilities and stockholders’ equity
            
            $
            951,042
            
            
            $
            905,542








F-39


Table of contents


International
Coal Group, Inc.





Parent
Company Statements of Operations


(Dollars
in thousands, except per share amounts)





Year
      Ended December 31,2009
            
            
            2008
            
            
            2007INCOME
      FROM OPERATIONS
            
            $
            —
            
            
            $
            —
            
            
            $
            —INTEREST
      AND OTHER INCOME (EXPENSE):Loss
      on extinguishment of debt
            
            
            (13,293
            )
            
            
            —
            
            
            
            —Interest
      expense, net
            
            
            (44,002
            )
            
            
            (42,905
            )
            
            
            (28,579
            )Loss
      before income taxes
            
            
            (57,295
            )
            
            
            (42,905
            )
            
            
            (28,579
            )INCOME
      TAX BENEFIT
            
            
            19,071
            
            
            
            16,218
            
            
            
            10,803EQUITY
      IN NET INCOME (LOSS) OF SUBSIDIARIES
            
            
            59,682
            
            
            
            460
            
            
            
            (129,786
            )Net
      income (loss)
            
            $
            21,458
            
            
            $
            (26,227
            )
            
            $
            (147,562
            )Earnings
      per share:Basic
            
            $
            0.14
            
            
            $
            (0.17
            )
            
            $
            (0.97
            )Diluted
            
            
            0.14
            
            
            
            (0.17
            )
            
            
            (0.97
            )Weighted-average
      common shares outstanding:Basic
            
            
            153,630,446
            
            
            
            152,632,586
            
            
            
            152,304,461Diluted
            
            
            155,386,263
            
            
            
            152,632,586
            
            
            
            152,304,461





F-40


Table of contents


International
Coal Group, Inc.





Parent
Company Statements of Cash Flows


(Dollars
in thousands)








Year
      Ended December 31,2009
            
            
            2008
            
            
            2007NET
      CASH FROM OPERATING ACTIVITIES
            
            $
            (40,453
            )
            
            $
            (38,266
            )
            
            $
            (19,036
            )CASH
      FLOWS FROM INVESTING ACTIVITIES:Investment
      in subsidiaries
            
            
            40,511
            
            
            
            38,266
            
            
            
            (198,121
            )Net
      cash from investing activities
            
            
            40,511
            
            
            
            38,266
            
            
            
            (198,121
            )CASH
      FLOWS FROM FINANCING ACTIVITIES:Proceeds
      from convertible notes offering
            
            
            —
            
            
            
            —
            
            
            
            225,000Debt
      issuance costs
            
            
            (58
            )
            
            
            —
            
            
            
            (7,843
            )Net
      cash from financing activities
            
            
            (58
            )
            
            
            —
            
            
            
            217,157NET
      CHANGE IN CASH AND CASH EQUIVALENTS
            
            
            —
            
            
            
            —
            
            
            
            —CASH
      AND CASH EQUIVALENTS, BEGINNING OF PERIOD
            
            
            —
            
            
            
            —
            
            
            
            —CASH
      AND CASH EQUIVALENTS, END OF PERIOD
            
            $
            —
            
            
            $
            —
            
            
            $
            —





F-41


Table of contents




LONG-TERM
      DEBT





As
of December 31, 2009 and 2008, long-term debt consisted of the following (in
thousands):





2009
            
            
            20089.00%
      Convertible Senior Notes, due 2012, net of debt discount of $9,480 and
      $17,369, respectively
            
            $
            152,022
            
            
            $
            207,63110.25%
      Senior Notes, due 2014
            
            
            175,000
            
            
            
            175,000Long-term
      debt
            
            $
            327,022
            
            
            $
            382,631





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.





In
December 2009, the Company entered into a series of privately negotiated
agreements in order to induce conversions of its outstanding Convertible Notes.
In connection with such agreements, the Company issued a total of 18,660,550
shares of its common stock in exchange for $63,498 aggregate principal amount of
its Convertible Notes. As a result of the exchanges, the Company recognized
losses on extinguishment of the related debt totaling $13,293 for the year ended
December 31, 2009. The Company did not incur any such losses in 2008 and
2007.





One
of the exchange agreements, as amended, provided for closing of additional
exchanges on each of January 11, 2010 and January 19, 2010 for exchange
transactions occurring in 2010. Subsequent to December 31, 2009, the noteholder
actually exchanged $22,000 aggregate principal amount of Convertible Notes for
6,198,668 shares of the Company’s common stock. As a result of the exchanges
settled in January 2010, the Company recognized a loss on extinguishment of the
related debt totaling $5,397 subsequent to December 31, 2009.





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.





F-42


Table of contents




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, 2009,
the Company was in compliance with its covenants under the
indenture.





See
Note 9 to the audited consolidated financial statements included in Item 15 of
this Annual Report on Form 10-K for further discussion of the Convertible Notes
and Notes.





Future
maturities of long-term debt are as follows as of December 31, 2009 (in
thousands):





Year
      ending December 31:2010
            
            $
            —2011
            
            
            —2012
            
            
            161,5022013
            
            
            —2014
            
            
            175,000Total
            
            
            336,502Less
      debt discount
            
            
            (9,480
            )Total
            
            $
            327,022





F-43




Table of contents


Schedule II—Valuationand 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, 2009Allowance
      for doubtful accounts
            
            $
            1,516
            
            
            $
            (1,294
            )
            
            $
            —
            
            
            $
            222Reserve
      for inventory obsolescence
            
            
            1,807
            
            
            
            341
            
            
            
            —
            
            
            
            2,148Reserve
      for loss—advance royalties
            
            
            3,909
            
            
            
            1,438
            
            
            
            (1,141
            )
            
            
            4,206Year
      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
            )
            
            
            3,771





F-44




Table of contents


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:
January 29, 2010










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
            
            January
      29, 2010Bennett
      K. Hatfield
            
            (Principal
      Executive Officer)/s/
      Bradley W. Harris
            
            Senior
      Vice President, Chief Financial Officer and Treasurer
            
            January
      29, 2010Bradley
      W. Harris
            
            (Principal
      Accounting and Principal Financial Officer)*
            
            Non-Executive
      Chairman and Director
            
            January
      29, 2010Wilbur L. Ross,
      Jr.*
            
            Director
            
            January
      29, 2010Maurice
      E. Carino, Jr.*
            
            Director
            
            January
      29, 2010Cynthia
      B. Bezik*
            
            Director
            
            January
      29, 2010William
      J. Catacosinos*
            
            Director
            
            January
      29, 2010Stanley
      N. Gaines*
            
            Director
            
            January
      29, 2010Samuel
      A. Mitchell*
            
            Director
            
            January
      29, 2010Wendy
      L. Teramoto





*
            The
      undersigned, by signing his name hereto, does sign and execute this Annual
      Report on Form 10-K pursuant to the Powers of Attorney executed by the
      above-named officers and Directors of the Company and filed with the
      Securities and Exchange Commission on behalf of such officers and
      Directors.





INTERNATIONAL
      COAL GROUP, INC.By:
            /s/
      Bennett K. HatfieldBennett
      K. Hatfield, Attorney-in-Fact







Table of contents


EXHIBIT INDEX





Exhibit No.
            
            Description
            
            Note3.1
            
            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.,
      as further amended on November 28, 2007
            
            (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
            
            Registration
      Rights Agreement, dated as of July 31, 2007, among International Coal
      Group, Inc., the guarantors party thereto and UBS Securities LLC, as
      purchaser
            
            (J)4.5
            
            Registration
      Rights Agreement, dated May 16, 2008, among International Coal Group, Inc.
      and Fairfax Financial Holdings Limited
            
            (R)4.6
            
            Indenture,
      dated June 23, 2006, among International Coal Group, Inc., the guarantors
      party thereto and The Bank of New York Trust Company, N.A., as Trustee,
      relating to International Coal Group, Inc.’s 10.25% Senior
      Notes
            
            (H)4.7
            
            Form
      of 10.25% Senior Note (included in Exhibit 4.6)
            
            (H)4.8
            
            Form
      of Guarantee relating to International Coal Group, Inc.’s 10.25% Senior
      Notes (included in Exhibit 4.6)
            
            (H)4.9
            
            First
      Supplemental Indenture, dated December 3, 2009, among International Coal
      Group, Inc., the guarantors party thereto and The Bank of New York Mellon
      Trust Company, N.A., as Trustee, relating to International Coal Group,
      Inc.’s 10.25% Senior Notes
            
            (S)4.10
            
            Indenture,
      dated as of July 31, 2007, among International Coal Group, Inc., the
      guarantors party thereto and The Bank of New York Trust Company, N.A., as
      Trustee, relating to International Coal Group, Inc.’s 9.00% Convertible
      Senior Notes
            
            (J)4.11
            
            Form
      of 9.00% Convertible Senior Note (included in Exhibit 4.9)
            
            (J)4.12
            
            Form
      of Guarantee relating to International Coal Group, Inc.’s 9.00%
      Convertible Senior Notes
            
            (J)4.13
            
            First
      Supplemental Indenture, dated December 3, 2009, among International Coal
      Group, Inc., the guarantors party thereto and The Bank of New York Mellon
      Trust Company, N.A., as Trustee, relating to International Coal Group,
      Inc.’s 9.00% Convertible Senior Notes
            
            (S)




Table of contents




Exhibit No.
            
            Description
            
            Note10.3
            
            Advisory
      Services Agreement effective as of October 1, 2004 between International
      Coal Group, LLC and W.L. Ross & Co. LLC
            
            (A)10.4
            
            Amended
      and Restated Employment Agreement dated as of December 31, 2009 by and
      between Bennett K. Hatfield and International Coal Group,
    Inc.
            
            (S)10.6
            
            International
      Coal Group, Inc. Amended and Restated 2005 Equity and Performance
      Incentive Plan
            
            (Q)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
            
            Form
      of Non-Employee Director Restricted Share Unit Agreement
            
            (O)10.12
            
            International
      Coal Group, Inc. Executive Severance Plan
            
            (I)10.13
            
            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 18, 1990, assigning to Laurel Run Mining
Co.(d) Consent
      Letter, dated as of October 25, 1995(e) Partial
      Assignment, dated October 30, 1995, assigning to East Kentucky Energy
      Corp.(f) Assignment,
      dated October 30, 1995, assigning to East Kentucky Energy
      Corp.(g) Assignment
      of Real Property Agreements, dated September 30, 2004, assigning to
      ICG Eastern, LLC


Table of contents


Exhibit No.
            
            Description
            
            Note10.15
            
            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, LLC10.19
            
            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




Table of contents





Exhibit No.
            
            Description
            
            Note(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
            
            (S)10.25
            
            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, LLC




Table of contents




Exhibit No.
            
            Description
            
            Note10.28‡
            
            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 1, 2004(d) Coal
      Price Adjustment Agreement, effective as of October 1,
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‡
            
            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)10.31‡
            
            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)10.32‡
            
            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)10.33‡
            
            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)10.34
            
            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)


Table of contents





Exhibit No.
            
            Description
            
            Note10.35
            
            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)10.36
            
            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)10.37
            
            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)10.38
            
            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
            
            Amendment
      No. 4 to the Second Amended and Restated Credit Agreement, dated as of
      September 28, 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
            
            (P)11.1
            
            Statement
      regarding Computation of Earnings Per Share
            
            (S)12.1
            
            Statement
      regarding Computation of Ratio of Earnings to Fixed
Charges
            
            (S)21.1
            
            List
      of Subsidiaries
            
            (S)23.1
            
            Consent
      of Deloitte & Touche, LLP
            
            (S)24.1
            
            Power
      of attorney, dated January 28, 2010
            
            (S)31.1
            
            Certification
      of the Chief Executive Officer
            
            (S)31.2
            
            Certification
      of the Principal Financial Officer
            
            (S)32.1
            
            Certification
      Pursuant to § 906 of the Sarbanes-Oxley Act of 2002
            
            (S)





Table of contents




(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. As
      further amended in Exhibit 99.1 to International Coal Group, Inc.’s
      Current Report on Form 8-K filed on November 28, 2007.(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 for the year ended December 31, 2008, filed on February 27, 2009
      and incorporated herein by reference.(P)
            Previously
      filed as an exhibit to International Coal Group Inc.’s Current Report on
      Form 8-K, filed on September 29, 2009, and incorporated herein by
      reference.(Q)
            Previously
      filed as Annex A to International Coal Group Inc.’s Definitive Proxy
      Statement on Schedule 14A (File No. 1-32679) filed on April 15,
      2009.(R)
            Previously
      filed as Exhibit 1.2 to Amendment No. 1 to Schedule 13D of Fairfax
      Financial Holdings Limited, filed on May 29, 2008.(S)
            Filed
      herewith.‡
            Confidential
      treatment requested as to certain portions that have been omitted and
      filed separately with the Securities and Exchange
    Commission.