Eastern
Eastern operates the Birch River surface mine, located 60 miles east of
Charleston, near Cowen in Webster County, West
Virginia. Birch River is extracting coal from
the Freeport, Upper Kittanning, Middle Kittanning, Upper
Clarion and Lower Clarion coalbeds. We estimate that Birch River controls
5.0 million tons of coal reserves. Additional potential reserves have been
identified in the immediate vicinity of the Birch River mine and exploration activities are
currently being conducted in order to add those potential reserves to the
reserve base.
Approximately 36% of the coal reserves
are leased, while approximately 64% are owned in fee. Most of the leased
reserves are held by four lessors. The leases are retained by annual minimum
payments and by tonnage-based royalty payments. Most leases can be renewed until
all mineable and merchantable coal has been exhausted.
Overburden is removed by a dragline,
excavator, front-end loaders, end dumps and bulldozers. Approximately
one-third of the total coal sales are run-of-mine, while the other
two-thirds are washed at Birch River’s preparation plant. Coal is
transported by conveyor belt from the preparation plant to Birch River’s rail loadout, which is served by CSX
via the A&O Railroad, a short-line carrier that is partially owned by
CSX.
Hazard
Hazard currently operates seven surface
mines, a unit train loadout (Kentucky River Loading) and other support
facilities in eastern Kentucky, near Hazard. The coal reserves and operations
were acquired in late-1997 and 1998 by AEI Resources.
Hazard’s seven surface mines include
East Mac & Nellie, Vicco, Rowdy Gap, County Line, Sam Campbell, Thunder Ridge and
Middle Fork. The coal from these mines is being extracted from the Hazard 10,
Hazard 9, Hazard 8, Hazard 7 and Hazard 5A seams. Nearly all of the coal is
marketed as a blend of run-of-mine product with the remainder being washed.
Overburden is removed by front-end loaders, end dumps, bulldozers and blast
casting. East Mac & Nellie also utilizes a large capacity hydraulic shovel.
Coal is transported by on-highway trucks from the mines to the Kentucky River
Loading rail loadout, which is served by CSX. Some coal is direct shipped to the
customer by truck from the mine pits.
We estimate that Hazard controls
61.9 million tons of coal reserves, plus 6.4 million tons of coal that
is classified as non-reserve coal deposits. Most of the property has been
adequately explored, but additional core drilling will be conducted within
specified locations to better define the reserves.
Approximately 58% of Hazard’s reserves
are leased. Most of the leased reserves are held by seven lessors. In several
cases, Hazard has multiple leases with each lessor. The leases are retained by
annual minimum payments and by tonnage-based royalty payments. Most leases can
be renewed until all mineable and merchantable coal has been
exhausted.
Flint Ridge
As of year end, Flint Ridge, located
near Breathitt
County, Kentucky, was currently operating three
underground mines and one preparation plant. Two underground mines operate in
the Hazard 8 seam, while the third underground mine operates in the Hazard 5A
seam.
Flint Ridge’s three underground mines
are room-and-pillar operations, utilizing continuous miners and both battery
powered ram cars and shuttle cars. All of the run-of-mine coal is processed at
the Flint Ridge preparation plant, which is an existing preparation plant
structure that was extensively upgraded in early 2005. Since July 2005, it has
been processing coal from the Hazard and Flint Ridge mining
complexes.
The majority of the processed coal is
trucked to the Kentucky River Loading rail loadout. Some processed coal is
trucked directly to the customer from the preparation
facility.
We estimate that Flint Ridge controls
24.2 million tons of coal reserves, plus 0.9 million tons of
non-reserve coal deposits. Approximately 97% of Flint Ridge’s reserves are
leased, while 3% are owned in fee. The leases are retained by annual minimum
payments and by tonnage-based royalty payments. Most leases can be renewed until
all mineable and merchantable coal has been exhausted.
10
Knott County
Knott County operates three underground mines, the
Supreme Energy preparation plant and rail loadout and other facilities necessary
to support the mining operations in eastern Kentucky, near Kite. Knott County was acquired by AEI Resources from
Zeigler in 1998 with reserves acquired through a lease from Penn
Virginia.
Knott County is producing coal from the Hazard 4 and
Elkhorn 3 coalbeds. Two mines are operating in
the Hazard 4 coalbed: Calvary and Clean Energy. The Classic mine is
operating in the Elkhorn 3 coalbed. Three additional properties
are in the process of being permitted for underground mine development. We
estimate this property contains 15.2 million tons of coal reserves. A
significant portion of the property has been explored, but additional core
drilling will be conducted within specified locations to better define the
reserves.
Approximately 25% of Knott County’s reserves are owned in fee, while
approximately 75% are leased. The leases are retained by annual minimum payments
and by tonnage-based royalty payments. The leases can be renewed until all
mineable and merchantable coal has been exhausted.
Knott County’s three underground mines are
room-and-pillar operations, utilizing continuous miners and shuttle cars. Nearly
all of the run-of-mine coal is processed at the Supreme Energy preparation
plant; some of the Hazard 4 run-of-mine coal is blended with the washed coal.
All of Knott County’s coal is transported by rail from
loadouts served by CSX.
Raven
Raven, located in Knott County, Kentucky, operates two underground mines and the
Raven preparation plant. Raven’s two underground mines are producing coal from
the Elkhorn 2 coalbed. We estimate this property
contains 12.2 million tons of coal reserves. Most of the property has been
extensively explored, but additional core drilling will be conducted within
specified locations to better define the reserves.
Raven’s reserves are 100% leased from
one lessor. The leases are retained by annual minimum payments and by
tonnage-based royalty payments. The leases can be renewed until all mineable and
merchantable coal has been exhausted.
Raven’s two underground mines are
room-and-pillar operations, utilizing continuous miners and battery powered ram
cars. The coal is processed at the Raven preparation plant. Operations at the
Raven preparation plant began in 2006 in conjunction with Loadout, LLC, an
affiliate of Penn Virginia Resources Partners, L.P. Nearly all of Raven’s coal
is transported by rail via CSX.
East Kentucky
East Kentucky is a surface mining
operation located in Martin and Pike Counties, Kentucky, near the Tug Fork
River. East Kentucky currently operates the Mt. Sterling and Peelpoplar surface
mines and the Sandlick loadout. The loadout is serviced by Norfolk Southern
railroad. East Kentucky was acquired by AEI Resources in the second quarter of
1999.
Mt. Sterling is an area surface mine that produces
coal from the Taylor, Coalburg, Winifrede, Buffalo and Stockton coalbeds. All of the coal is sold run-of-mine.
We estimate that the Mt. Sterling mine controls 2.7 million tons of coal reserves, of
which 88% are owned. No additional exploration
is required. Overburden at the Mt. Sterling mine is removed by front-end
loaders, end dumps, bulldozers and blast casting. Coal from the pits is
transported by truck to the Sandlick loadout.
Peelpoplar is a surface mine that
produces coal using contour mining from the Little Fireclay and Whitesburg
Middle coal seams that we estimate to control 0.2 million tons of coal reserves,
none of which are owned. Mining is performed
using a front-end loader/truck spread and
bulldozers. Coal produced is transported by on-highway trucks to the Sandlick
loadout. We plan to operate the Peelpoplar mine though 2009.
Although Mt. Sterling and Peelpoplar are
mined by East Kentucky, the properties are held by ICG Natural Resources. The
leases are retained by annual minimum payments and by tonnage-based royalty
payments. Most leases can be renewed until all mineable and merchantable coal
has been exhausted.
11
Beckley
The Beckley Pocahontas Mine was placed
into production in the fall of 2008. It is located in Central Appalachia in
Raleigh County, West Virginia. The Beckley Pocahontas mine accesses a
32.0 million-ton deep reserve of high quality low-volatile metallurgical
coal in the Pocahontas No. 3 seam. Most of the 16,800 acre Beckley reserve
is leased from three land companies: Western Pocahontas Properties, Crab Orchard
Coal Company and Beaver Coal Company.
Construction of the slope portal and a
new preparation plant was completed in late 2007 with remaining development
completed in 2008. Underground production is by means of the room-and-pillar
method with continuous miners and battery haulers. We are marketing the coal
produced from the Beckley reserve to domestic steel producers and
for export. Additionally, we began marketing metallurgical coal produced from
reprocessing a nearby coal refuse pile located at Eccles, West Virginia.
Vindex Energy
Corporation
Vindex Energy Corporation operates three
surface mines, the Carlos mine, the Island mine and the Jackson Mountain mine, all located in Garrett and
Allegany
Counties, Maryland. The reserves at Vindex are leased from
multiple landowners under leases that expire at varying times and are renewable
with annual holding costs. Vindex Energy is a cross-ridge mining operation
extracting coal from the Upper Freeport, Bakerstown, Middle Kittanning, Upper
Kittanning, Pittsburgh and Redstone seams. All surface mines
operated by Vindex Energy are truck-and-shovel/loader mining operations and are
conducted with relatively new equipment. Exploration and development is
conducted on a continual basis ahead of mining. In 2007, Vindex added the Cabin
Run property to its reserve base. The total reserves for the assigned surface
operations at Vindex amount to approximately 7.3 million
tons.
Most of the surface mine production is
shipped directly to the customer as run-of-mine product. Any coal that must be
washed is processed at our preparation plant located near Mount Storm, West Virginia, where the product is shipped to the
customer by either truck or rail.
Patriot Mining
Company
Patriot Mining Company consists of the
Guston Run surface mine, located near Morgantown in Monongalia County, West Virginia. The Crown No. 4 surface mine was
depleted in the third quarter of 2007 and the Fort Grand surface mine was
temporarily idled in the fourth quarter of 2008. The majority of the coal and
surface is leased under renewable contracts with small annual minimum holding
costs. Coal is extracted from the Waynesburg seam using contour mining methods
with dozers, loaders and trucks. As mining progresses, reserves are being
acquired and permitted for future operations. The coal is shipped to the
customer by rail, truck or barge using our barge loading
facility.
We estimate that Patriot Mining Company
currently controls approximately 6.2 million tons of coal reserves, of
which 1% are owned.
Buckhannon Division
Wolf Run Mining Company’s Buckhannon
Division currently consists of two active underground mines: the Imperial mine
located in Upshur
County, West Virginia, near the town of Buckhannon, and the Sycamore No. 2 mine
located in Harrison
County, West Virginia, approximately ten miles west of
Clarksburg. Nearly all of the reserves in the
Buckhannon Division are owned. The Buckhannon Division also owns the Sago mine,
which was idled in March 2007. The decision was made in December 2008 to
permanently close the Sago mine due to deteriorating conditions and the high
cost necessary to reactivate the mine.
The Imperial mine extracts coal from the
Middle Kittanning seam. All of the coal extracted from the Imperial mine is
processed through the nearby Sawmill Run preparation plant. This coal is
primarily shipped by CSX rail with origination by the A&O Railroad, a
short-line operator, although some coal is trucked to local industrial
customers. The reserves at the Buckhannon Division have characteristics that
make it marketable to both steam and export metallurgical coal
customers.
The Sycamore No. 2 mine began
producing coal from the Pittsburgh seam by the room-and-pillar mining
method with continuous miners and shuttle cars in the fourth quarter of 2005.
The reserve is primarily leased from one landowner with an annual minimum
holding costs and an automatic renewal based on an annual minimum production of
250,000 tons. Unexpected adverse mining conditions forced the idling of the
Sycamore No. 2 mine during the third quarter of 2006; however, an
independent contractor resumed production at the mine in September 2007. The
coal produced from the Sycamore No. 2 mine is sold on a raw basis and
shipped to Allegheny Power Service Corporation’s Harrison Power Station by
truck.
Powell
Mountain
Acquired in 2008, Powell Mountain,
located in Lee County, Virginia and Harlan County, Kentucky, currently operates
the Darby mine, a room-and-pillar mine operating two sections with both shuttle
cars and ram cars. The mine is operating in the Darby seam with all coal being
trucked to the Mayflower preparation plant for processing. Coal is shipped by
rail through the dual service rail loadout facility with rail service provided
by both the Norfolk Southern and CSX railroads. Some
purchased coal is brought into the facility for processing and blending. We plan
to begin operation of the new Middle Splint mine in 2010.
Sentinel
Wolf Run Mining Company’s Sentinel mine,
located in Barbour County, West Virginia, was acquired by Anker in 1990 and has
been operating ever since. Historically, coal was extracted from the Upper and
Lower
Kittanning seams; however,
the mine was idled in the second quarter of 2006 to extend the slope and shafts
to the underlying Clarion seam. Developmental mining in the Clarion seam began
in November 2006 and the current operation now includes three continuous miner
sections using the room-and-pillar mining method. Clarion coalbed reserves at
the Sentinel mine amount to approximately 15.4 million tons, of which
approximately 12% is owned and 88% is leased.
Coal is fed directly from the mine to a
preparation plant and loadout facility served by the CSX railroad with
origination by the A&O Railroad, as short-line operator. The product can be
shipped to steam or metallurgical markets.
12
New Appalachian Mine
Developments
Hillman Property
The Hillman property, located in Taylor
County, West Virginia, near Grafton, includes approximately 186.0 million
tons of deep coal reserves of both steam and metallurgical quality coal in the
Lower
Kittanning seam covering
approximately 65,000 acres. The reserve extends into parts of Barbour,
Marion and Harrison Counties as well. ICG owns the Hillman coal
reserve in addition to nearly 4,000 acres of surface property to accommodate the
development of two projected mining operations. In addition to the Lower
Kittanning reserves, we also own significant non-reserve coal deposits in the
Kittanning, Freeport, Clarion and Mercer seams on the
Hillman property.
The West Virginia Department of
Environmental Protection (“WVDEP”) issued a permit on June 5, 2007 for the
Tygart No. 1 underground longwall mine and preparation plant complex
located on the Hillman Property. On appeal, the WV Surface Mine Board remanded
the permit for additional modifications. The modified permit application was
approved in April 2008 and mine site development commenced. A subsequent appeal
to the WV Surface Mine Board resulted in the suspension of the permit in October
2008 and cessation of construction activity. A modified permit application is
awaiting reissuance from WVDEP.
Construction of our Tygart No. 1 mining
complex is not expected to resume until market conditions justify the additional
production. We will continue to evaluate timing of the development as market
conditions evolve, but resumption of work is not currently expected before 2011.
At full production, we expect Tygart No. 1 to produce 3.5 million tons
annually of high quality coal that is well suited to both the utility market and
the high volatile metallurgical market.
Upshur Property
The Upshur Property, located in Northern
Appalachia, contains approximately 93.0 million tons of non-reserve coal
deposits owned or controlled by us in the Middle and Lower Kittanning seams. Due to unique geologic
characteristics and coal quality constraints, Upshur is a potential location for
an on-site power plant. Some preliminary research, including air quality
monitoring, has been completed as part of conceptual planning for the future
construction of a circulating fluidized bed power plant at
Upshur.
Big Creek Property
Our Big Creek reserve, located in
Central Appalachia, covers 10,000 acres of leased coal lands located north of
the town of Richlands in Tazewell County, Virginia. Total recoverable reserves are
25.9 million tons in the Jawbone, Greasy Creek and War Creek seams. The Big
Creek reserve is all leased from Southern Regional Industrial Realty. The War
Creek mine, which is permitted as a room-and-pillar mining operation, is
expected to be developed in the future as market conditions warrant. We receive
an overriding royalty on coalbed methane production from this
property.
Juliana Complex
The Juliana property, located in Webster
County, West Virginia, was extensively mined in the past by a predecessor of
ICG. Contour and mountaintop removal surface mining methods were utilized to
produce coal from the Kittanning and Upper Freeport seams. In addition, a substantial
amount of deep-mined coal was produced from the Middle Kittanning
seam.
Currently at Juliana, there are two
Kittanning deep mine permits and one surface mine permit in place. Permitted
deep and surface non-reserve coal deposits are 1.2 million tons and 1.9 million
tons, respectively.
Jennie Creek Property
The Jennie Creek reserve, located in Mingo County, West Virginia, is a 44.9 million ton reserve of
surface and deep mineable steam coal. This property contains 14.7 million tons
of surface mineable, low sulfur coal reserves. A deep reserve in the high Btu,
mid-sulfur Alma seam constitutes the largest block of
coal at 30.2 million tons. Permitting is now in progress for a surface mine on
this Central Appalachian property. Development of the entire Jennie Creek reserve had been subject to the
resolution of certain disputes with lessors arising out of the Horizon
bankruptcy proceedings. We resolved our litigation with the lessors of the
Jennie Creek coal reserves in 2007. Using the
results of an extensive core drilling project completed on the property in 2007
and 2008, the surface mine plan was updated and corresponding changes are being
made to the mining permits. The coal will be produced by contouring, highwall
mining and area mining.
13
Illinois Basin Mining Operations
Below is a map showing the location and
access to our coal operations in the Illinois Basin:
Illinois operates one large underground coal
mine, the Viper mine, in central Illinois. Viper commenced mining operations in
1982 as a union free operation for Shell Oil Company. Viper was acquired by
Ziegler in 1992 and subsequently acquired by AEI Resources in
1998.
The Viper mine is mining the Illinois
No. 5 Seam, also referred to as the Springfield Seam. We estimate that
Viper controls approximately 42.6 million tons of coal reserves, plus an
additional 38.5 million tons of non-reserve coal deposits.
Approximately 79% of the coal reserves
are leased, while 21% are owned in fee. The leases are retained by annual
minimum payments and by tonnage-based royalty payments. The leases can be
renewed until all mineable and merchantable coal has been
exhausted.
The Viper mine is a room-and-pillar
operation, utilizing continuous miners and battery coal haulers. Management
believes that Illinois is one of the lowest cost and highest
productivity mines in the Illinois Basin. All of the raw coal is processed at
Viper’s preparation plant. The clean coal is transported to utility and
industrial customers located in North Central Illinois by on-highway trucks
operated by independent trucking companies. A major rail line is located a short
distance from the plant, giving Viper the option of constructing a rail loadout.
Shipments to electric utilities account for approximately 64% of coal
sales.
The underground equipment,
infrastructure and preparation plant are well maintained. Underground equipment
is routinely replaced or rebuilt depending on the age and mechanical condition
of the equipment. Illinois plans to develop a new portal facility
that will allow it to eliminate the need to operate over five miles of
underground beltlines and to maintain the extensive previously mined
area.
14
Other Operations
Brokered coal sales
In addition to the coal we mine, we
purchase and resell coal produced by third parties from their controlled
reserves to meet our customers’ specifications.
ADDCAR Systems
In our highwall mining business, we have
five systems in operation using our patented ADDCAR highwall mining system and
intend to build additional ADDCAR systems as required. ADDCAR(TM) is the registered trademark of ICG. The
ADDCAR highwall mining system is an innovative and efficient mining system often
deployed at reserves that cannot be economically mined by other
methods.
A typical ADDCAR highwall mining system
consists of a launch vehicle, continuous miner, conveyor cars, a stacker
conveyor, electric generator, water tanker for cooling and dust suppression and
a wheel loader with forklift attachment.
A five person crew operates the entire
ADDCAR highwall mining system with control of the continuous miner being
performed remotely by one person from the climate-controlled cab located at the
rear of the launch vehicle. Our system utilizes a navigational package to
provide horizontal guidance, which helps to control rib width, and thus roof
stability. In addition, the system provides vertical guidance for avoiding or
limiting out of seam dilutions. The ADDCAR highwall mining system is equipped
with high-quality video monitors to provide the operator with visual displays of
the mining process from inside each entry being mined.
The mining cycle begins by aligning the
ADDCAR highwall mining system onto the desired heading and starting the entry.
As the remotely controlled continuous miner penetrates the coal seam, ADDCAR
conveyor cars are added behind it, forming a continuous cascading conveyor
train. This continues until the entry is at the planned full depth of up to
1,200 to 1,500 feet. After retraction, the launch vehicle is moved to the next
entry, leaving a support pillar of coal between entries. This process recovers
as much as 65% of the reserves while keeping all personnel outside the coal seam
in a safe working environment. A wide range of seam heights can be mined with
high production in seams as low as 3.5 feet and as high as 15 feet in a single
pass. If the seam height is greater than 15 feet, then multi-lifts can be mined
to create an unlimited entry height. The navigational features on the ADDCAR
highwall mining system allow for multi-lift mining while ensuring that the
designed pillar width is maintained.
During the mining cycle, in addition to
the tramming effort provided by the crawler drive of the continuous miner, the
ADDCAR highwall mining system increases the cutting capability of the machine
through additional forces provided by hydraulic cylinders which transmit thrust
to the back of the miner through blocks mounted on the side of the conveyor
cars. This additional energy allows the continuous miner to achieve maximum
cutting and loading rates as it moves forward into the seam. The first ADDCAR
narrow bench mining system was placed in operation in 2007.
We currently have the exclusive North
American distribution rights for the ADDCAR highwall mining
system.
15
Coalbed methane
CoalQuest has entered into a lease and
joint operating agreement pursuant to which it leases coalbed methane, which is
pipeline quality gas that resides in coal seams, and participates in certain
coalbed methane wells, from its properties in Barbour, Harrison and Taylor
counties in West
Virginia. The first
production well owned in part by CoalQuest began commercial operations in June
2006 and ten additional wells partially owned by CoalQuest were brought online
by the end of 2007. During 2008, the counterparty to the lease and joint
operating agreement declared bankruptcy. As a result, we recorded a reserve
against related outstanding accounts receivable. The counterparty continues to
operate the wells under the protection of the bankruptcy court. Our coalbed
methane lessee developed other wells in which CoalQuest is not a partial owner.
In the eastern United
States, conventional
natural gas fields are typically located in various sedimentary formations at
depths ranging from 2,000 to 15,000 feet. Exploration companies often put
capital at risk by searching for gas in commercially exploitable quantities at
these depths. By contrast, the coal seams from which we recover coalbed methane
are typically less than 1,000 feet deep and are usually better defined than
deeper formations. We believe that this contributes to lower exploration costs
than those incurred by producers that operate in deeper, less defined
formations. We believe this project is part of the first application of
proprietary horizontal drilling technology for coalbed methane in northern
West Virginia coalfields. We have not filed reserve
estimates with any federal agency.
We receive an overriding royalty on
coalbed methane production from the Crab Orchard Coal Company and Beaver Coal
Company coal reserves leased by ICG Beckley in Raleigh County, West Virginia and from the leased Big Creek coal
reserves in Tazewell
County, Virginia. We also lease coalbed methane from
certain of our properties in Kentucky and will receive rents and royalties on
future production.
Customers
Our primary customers are investment
grade electric utility companies primarily in the eastern half of the
United States. The majority of our customers purchase
coal for terms of one year or longer, but we also supply coal on a spot basis
for some of our customers. Our three largest customers for the year ended
December 31, 2008 were Progress Energy, Georgia Power Company and Allegheny
Energy Supply Company and we derived approximately 32% of our coal revenues from
sales to our five largest customers. We did not derive more than 10% of our coal
sales revenues from any single customer in 2008.
Long-term coal supply
agreements
As is customary in the coal industry, we
enter into long-term supply contracts (exceeding one year in duration) with many
of our customers when market conditions are appropriate. These contracts allow
customers to secure a supply for their future needs and provide us with greater
predictability of sales volume and sales price. For the year ended December 31,
2008, approximately 51% of our revenues were derived from long-term supply
contracts. We sell the remainder of our coal through short-term contracts and on
the spot market. We have also entered into certain brokered transactions to
purchase certain amounts of coal to meet our sales commitments. These purchase
coal contracts expire between 2009 and 2010 and are expected to provide us a
minimum of approximately 1.9 million tons of coal through the remaining
lives of the contracts.
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.
16
The terms of our coal supply agreements
result from competitive bidding and extensive negotiations with customers.
Consequently, the terms of these contracts vary significantly by customer,
including price adjustment features, price reopener terms, coal quality
requirements, quantity adjustment mechanisms, permitted sources of supply,
future regulatory changes, extension options, force majeure provisions and
termination and assignment provisions.
Some of our long-term contracts provide
for a pre-determined adjustment to the stipulated base price at times specified
in the agreement or at other periodic intervals to account for changes due to
inflation or deflation in prevailing market prices.
In addition, most of our contracts
contain provisions to adjust the base price due to new statutes, ordinances or
regulations that impact our costs related to performance of the agreement. Also,
some of our contracts contain provisions that allow for the recovery of costs
impacted by modifications or changes in the interpretations or application of
any applicable government statutes.
Price reopener provisions are present in
many of our long-term contracts. These price reopener provisions may
automatically set a new price based on prevailing market price or, in some
instances, require the parties to agree on a new price, sometimes within a
specified range of prices. In a limited number of agreements, failure of the
parties to agree on a price under a price reopener provision can lead to
termination of the contract. Under some of our contracts, we have the right to
match lower prices offered to our customers by other
suppliers.
Quality and volumes for the coal are
stipulated in coal supply agreements and, in some instances, buyers have the
option to vary annual or monthly volumes. Most of our coal supply agreements
contain provisions requiring us to deliver coal within certain ranges for
specific coal characteristics such as heat content, sulfur, ash, hardness and
ash fusion temperature. Failure to meet these specifications can result in
economic penalties, suspension or cancellation of shipments or termination of
the contracts.
Transportation/Logistics
We ship coal to our customers by rail,
truck or barge. We typically pay the transportation costs for our coal to be
delivered to the barge or rail loadout facility, where the coal is then loaded
for final delivery. Once the coal is loaded in the barge or railcar, our
customer is typically responsible for the freight costs to the ultimate
destination. Transportation costs vary greatly based on the customer’s proximity
to the mine and our proximity to the loadout facilities. We use a variety of
independent companies for our transportation needs and typically enter into
multiple agreements with transportation companies throughout the
year.
In 2008, approximately 98% of our coal
(both produced and purchased) from our Central Appalachian operations was
delivered to our customers by rail generally on either the Norfolk Southern or
CSX rail lines, with the remaining 2% delivered by truck. For our Illinois Basin operations, all of our coal was
delivered by truck to customers, generally within an 80 mile radius of our
Illinois mine.
We believe we enjoy good relationships
with rail carriers and barge companies due, in part, to our modern coal-loading
facilities and the experience of our transportation and distribution
employees.
Suppliers
In 2008, we spent more than $375.6
million to procure goods and services in support of our business activities,
excluding capital expenditures. Principal commodities include maintenance and
repair parts and services, fuel, roof control and support items, explosives,
tires, conveyance structure, ventilation supplies and lubricants. Our outside
suppliers perform a significant portion of our equipment rebuilds and repairs
both on- and off-site, as well as construction and reclamation
activities.
Each of our regional mining operations
has developed its own supplier base consistent with local needs. We have a
centralized sourcing group for major supplier contract negotiation and
administration, for the negotiation and purchase of major capital goods and to
support the business units. The supplier base has been relatively stable for
many years, but there has been some consolidation. We are not dependent on any
one supplier in any region. We promote competition between suppliers and seek to
develop relationships with those suppliers whose focus is on lowering our costs.
We seek suppliers who identify and concentrate on implementing continuous
improvement opportunities within their area of expertise.
17
Competition
The coal industry is intensely
competitive. Our main competitors are Massey Energy Company, Arch Coal, Consol
Energy, Alpha Natural Resources, Foundation Coal Holdings, James River Coal
Company, Patriot Coal Corporation and various other smaller, independent
producers. The most important factors on which we compete are coal price at the
mine, coal quality and characteristics, transportation costs and the reliability
of supply. Demand for coal and the prices that we are able to obtain for our
coal are closely linked to coal consumption patterns of the domestic electric
generation industry, which accounted for approximately 93% of domestic coal
consumption in 2007. These coal consumption patterns are influenced by factors
beyond our control, including the demand for electricity which is significantly
dependent upon economic activity and summer and winter temperatures in the
United States, government regulation, technological developments and the
location, availability, quality and price of competing sources of coal, changes
in international supply and demand, alternative fuels such as natural gas, oil
and nuclear and alternative energy sources, such as hydroelectric
power.
Employees
As of December 31, 2008, we had 2,727
employees of which 22% were salaried and 78% were hourly. We believe our
relationship with our employees is positive. Our entire workforce is union
free.
Reclamation
Reclamation expenses are a significant
part of any coal mining operation. Prior to commencing mining operations, a
company is required to apply for numerous permits in the state where the mining
is to occur. Before a state will approve and issue these permits, it typically
requires the mine operator to present a reclamation plan which meets regulatory
criteria and to secure a surety bond to guarantee performance of reclamation in
an amount determined under state law. Bonding companies also require posting of
collateral, typically in the form of letters of credit, to secure the surety
bonds. As of December 31, 2008, the Company had $61.1 million in letters of
credit supporting its reclamation surety bonds. While bonds are issued against
reclamation liability for a particular permit at a particular site, collateral
posted in support of the bond is not allocated to a specific bond, but instead
is part of a collateral pool supporting all bonds issued by that particular
insurer. Bonds are released in phases as reclamation is completed in a
particular area.
Environmental, Safety and Other
Regulatory Matters
Federal, state and local authorities
regulate the U.S. coal mining industry with respect to matters such as
permitting and licensing requirements, employee health and safety, air quality
standards, water pollution, plant and wildlife protection, the reclamation and
restoration of mining properties after mining has been completed, the discharge
of materials into the environment, surface subsidence from underground mining
and the effects of mining on groundwater quality and availability. These laws
and regulations have had, and will continue to have, a significant effect on our
costs of production and competitive position. Future legislation, regulations or
orders may be adopted or become effective which may adversely affect our mining
operations, cost structure or the ability of our customers to use coal. For
instance, new legislation, regulations or orders, as well as future
interpretations and more rigorous enforcement of existing laws, may require
substantial increases in equipment and operating costs to us and delays,
interruptions or a termination of operations, the extent of which we cannot
predict. Future legislation, regulations or orders may also cause coal to become
a less attractive fuel source, resulting in a reduction in coal’s share of the
market for fuels used to generate electricity.
We endeavor to conduct our mining
operations in compliance with all applicable federal, state and local laws and
regulations. However, due in part to the extensive and comprehensive regulatory
requirements, violations during mining operations occur from time to time in the
industry and at our operations.
18
Mining Permits and
Approvals
Numerous governmental permits or
approvals are required for mining operations. In connection with obtaining these
permits and approvals, we may be required to prepare and present to federal,
state or local authorities data pertaining to the effect or impact that any
proposed production or processing of coal may have upon the environment. The
requirements imposed by any of these authorities may be costly and time
consuming and may delay commencement or continuation of mining operations.
Applications for permits are subject to public comment and may be subject to
litigation from environmental groups or other third parties seeking to deny
issuance of a permit, which may also delay commencement or continuation of
mining operations. Regulations also provide that a mining permit or modification
can be delayed, refused or revoked if an officer, director or a stockholder with
a 10% or greater interest in the entity is affiliated with or is in a position
to control another entity that has outstanding permit violations. Thus, past or
ongoing violations of federal and state mining laws could provide a basis to
revoke existing permits and to deny the issuance of additional
permits.
In order to obtain mining permits and
approvals from state regulatory authorities, mine operators must submit a
reclamation plan for restoring, upon the completion of mining operations, the
mined property to its prior condition, productive use or other permitted
condition. Typically, we submit our necessary mining permit applications for our
planned mines promptly upon securing the necessary property rights and required
geologic and environmental data. In our experience, mining permit approvals
generally require 12 to 18 months after initial submission.
Surface Mining Control and Reclamation
Act
The Surface Mining Control and
Reclamation Act of 1977 (“SMCRA”), which is administered by the Office of
Surface Mining Reclamation and Enforcement (“OSM”), establishes mining,
environmental protection and reclamation standards for all aspects of surface
mining, as well as many aspects of deep mining. Mine operators must obtain SMCRA
permits and permit renewals from the OSM, or the appropriate state regulatory
agency, for authorization of certain mining operations that result in a
disturbance of the surface. If a state adopts a regulatory program as
comprehensive as the federal mining program under SMCRA, the state becomes the
regulatory authority. States in which we have active mining operations have
achieved primary control of enforcement through federal approval of the state
program.
SMCRA permit provisions include
requirements for coal prospecting, mine plan development, topsoil removal,
storage and replacement, selective handling of overburden materials, mine pit
backfilling and grading, protection of the hydrologic balance, subsidence
control for underground mines, surface drainage control, mine drainage and mine
discharge control and treatment and revegetation. These requirements seek to
limit the adverse impacts of coal mining and more restrictive requirements may
be adopted from time to time.
The mining permit application process is
initiated by collecting baseline data to adequately characterize the pre-mine
environmental condition of the permit area. This work includes surveys of
cultural resources, soils, vegetation, wildlife, assessment of surface and
ground water hydrology, climatology and wetlands. In conducting this work, we
collect geologic data to define and model the soil and rock structures and coal
that it will mine. We develop mine and reclamation plans by utilizing this
geologic data and incorporating elements of the environmental data. The mine and
reclamation plan incorporates the provisions of SMCRA, the state programs and
the complementary environmental programs that impact coal
mining.
Also included in the permit application
are documents defining ownership and agreements pertaining to coal, minerals,
oil and gas, water rights, rights of way and surface land, and documents
required by the OSM’s Applicant Violator System, including the mining and
compliance history of officers, directors and principal owners of the
entity.
Once a permit application is prepared
and submitted to the regulatory agency, it goes through a completeness review
and technical review. Public notice and opportunity for public comment on a
proposed permit is required before a permit can be issued. Some SMCRA mine
permits take over a year to prepare, depending on the size and complexity of the
mine and typically take 12 to 18 months, or even longer, to be issued.
Regulatory authorities have considerable discretion in the timing of the permit
issuance and the public has rights to comment on, and otherwise engage in, the
permitting process, including through intervention in the
courts.
19
Before a SMCRA permit is issued, a mine
operator must submit a bond or otherwise secure the performance of reclamation
obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a
fee on all coal produced. The proceeds are used to reclaim mine lands closed or
abandoned prior to 1977. On December 7, 2006, the Abandoned Mine Land
Program was extended for 15 years.
SMCRA stipulates compliance with many
other major environmental statutes, including: the Clean Air Act, the Clean
Water Act, the Resource Conservation and Recovery Act (“RCRA”), and the
Comprehensive Environmental Response, Compensation and Liability Act
(“Superfund”).
Surety Bonds
Federal and state laws require us to
obtain surety bonds to secure payment of certain long-term obligations including
mine closure or reclamation costs, federal and state workers’ compensation
costs, coal leases and other miscellaneous obligations. Many of these bonds are
renewable on a yearly basis.
Surety bond costs have increased in
recent years while the market terms of such bonds have generally become more
unfavorable. In addition, the number of companies willing to issue surety bonds
has decreased. Bonding companies also require posting of collateral, typically
in the form of letters of credit, to secure the surety bonds. As of December 31,
2008, the Company had $73.6 million in letters of credit supporting its surety
bonds, including reclamation bonds.
Clean Air Act
The federal Clean Air Act, and
comparable state laws that regulate air emissions, directly affect coal mining
operations, but have a far greater indirect effect. Direct impacts on coal
mining and processing operations may occur through permitting requirements
and/or emission control requirements relating to particulate matter, such as
fugitive dust or fine particulate matter measuring 2.5 micrometers in diameter
or smaller. The Clean Air Act indirectly affects coal mining operations by
extensively regulating the air emissions of sulfur dioxide, nitrogen oxides,
mercury and other compounds emitted by coal-fired electricity generating plants
and coke ovens. The general effect of such extensive regulation of emissions
from coal-fired power plants could be to reduce demand for
coal.
Clean Air Act requirements that may
directly or indirectly affect our operations include the
following:
Acid Rain
Title IV of the Clean Air Act required a
two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II
became effective in 2000 and extended the Title IV requirements to all
coal-fired power plants with generating capacity greater than 25 megawatts. The
affected electricity generators have sought to meet these requirements by, among
other compliance methods, switching to lower sulfur fuels, installing pollution
control devices, reducing electricity generating levels or purchasing sulfur
dioxide emission allowances. We cannot accurately predict the effect of these
provisions of the Clean Air Act on us in future years. At this time, we believe
that implementation of Phase II has resulted in an upward pressure on the price
of lower sulfur coals as coal-fired power plants continue to comply with the
more stringent restrictions of Title IV.
Fine Particulate Matter and
Ozone
The Clean Air Act requires the U.S.
Environmental Protection Agency (the “EPA”) to set standards, referred to as
National Ambient Air Quality Standards (“NAAQS”) for certain pollutants. Areas
that are not in compliance with these standards (“non-attainment areas”) must
take steps to reduce emissions levels. In 1997, the EPA revised the NAAQS for
particulate matter and ozone; although previously subject to legal challenge,
these revisions were subsequently upheld, but implementation was delayed for
several years.
20
For ozone, these changes include
replacement of the existing one-hour average standard with a more stringent
eight-hour average standard. On April 15, 2004, the EPA announced that
counties in 32 states failed to meet the new eight-hour standard for ozone. The
EPA is also considering whether to revise the ozone standard. States which fail
to meet the new standard had until June 2007 to develop plans for pollution
control measures that allow them to come into compliance with the standards. On
January 16, 2009, the EPA proposed additional requirements for non-attainment
areas that could impose new requirements on power plants.
For particulates, the changes include
retaining the existing standard for particulate matter with an aerodynamic
diameter less than or equal to 10 microns and adding a new standard for fine
particulate matter with an aerodynamic diameter less than or equal to 2.5
microns (“PM2.5”). Following identification of non-attainment areas, each
individual state will identify the sources of emissions and develop emission
reduction plans. These plans may be state-specific or regional in scope. Under
the Clean Air Act, individual states have up to twelve years from the date of
designation to secure emissions reductions from sources contributing to the
problem. In addition, on April 25, 2005, the EPA issued a finding that
states have failed to submit State Implementation Plans that satisfy the
requirements of the Clean Air Act with respect to the interstate transport of
pollutants relative to the achievement of the 8-hour ozone and the PM2.5
standards. Because of this finding, the EPA must promulgate a Federal
Implementation Plan for any state which does not submit its own plan. The EPA
issued a more stringent PM2.5 standard which became effective December 18,
2006. On December 22, 2008, the EPA identified portions of 25 states as being in
non-attainment with the PM2.5 standard. Meeting the new PM2.5 standard may
require reductions of nitrogen oxide and sulfur dioxide emissions. Future
regulation and enforcement of these new ozone and PM2.5 standards will affect
many power plants, especially coal-fired plants and all plants in non-attainment
areas.
Significant additional emissions control
expenditures will be required at coal-fired power plants to meet the current
NAAQS for ozone. Nitrogen oxides, which are a by-product of coal combustion, can
lead to the creation of ozone. Accordingly, emissions control requirements for
new and expanded coal-fired power plants and industrial boilers will continue to
become more demanding in the years ahead.
NOx SIP Call
The NOx SIP Call program was established
by the EPA in October of 1998 to reduce the transport of ozone on prevailing
winds from the Midwest and South to states in the Northeast,
which said they could not meet federal air quality standards because of
migrating pollution. Under Phase I of the program, the EPA requires 900,000 tons
of nitrogen oxide reductions from power plants in 22 states east of the
Mississippi River and the District of Columbia beginning in May 2004. Phase II of the
rule required a further reduction of about 100,000 tons of nitrogen oxides per
year by May 1, 2007. Installation of additional control measures required
under the final rules, such as selective catalytic reduction
devices, will make it more costly to operate coal-fired electricity generating
plants, thereby making coal a less attractive fuel.
Interstate Air Quality
Rule
On March 10, 2005, the EPA adopted
new rules for reducing emissions of sulfur dioxide and nitrogen oxides. This
Clean Air Interstate Rule calls for power plants in 29 eastern states and the
District of
Columbia to reduce emission
levels of sulfur dioxide and nitrous oxide. The rule regulates these pollutants
under a cap and trade program similar to the system now in effect for acid
deposition control. The stringency of the cap may require many coal-fired
sources to install additional pollution control equipment, such as wet
scrubbers. This increased sulfur emission removal capability pursuant to this
rule could result in decreased demand for low sulfur coal, potentially driving
down prices for low sulfur coal. Emissions would be permanently capped and could
not increase. The rule seeks to cut sulfur dioxide emissions by 45% in 2010 and
by 57% in 2015. On December 23, 2008, the United States Court of Appeals for the
District of Columbia remanded, without vacating, the Clean Air Interstate Rule
to the EPA for further proceedings consistent with the Court’s July 11, 2008
opinion which found numerous fatal flaws in the Rule. The EPA has not determined
how to respond to the Court’s decision.
21
Mercury
The EPA has
announced that it intends to initiate a rulemaking to adopt technology-based
standards for mercury emissions from coal-fired power plants in response to a
court order which vacated and remanded its 2005 Clean Air Mercury Rule, which
would have reduced mercury emissions from such plants by a nationwide average of
nearly 70%. The parties that overturned this rule seek even reductions in
mercury emissions uniformly applied to all power plants. Some parties contend
that during the pendency of this rulemaking, these plants are subject to mercury
emission limitations determined on a case-by-case basis applying maximum
achievable control technology.
Other proposals for
controlling mercury emissions from coal-fired power plants have been made, such
as establishing state or regional emission standards. If these proposals were
enacted, the mercury content and variability of our coal would become a factor
in future sales. In addition, seven Northeastern states have prepared and
submitted to the EPA a Northeast Regional Mercury Total Maximum Daily Load to
reduce mercury in waterbodies by reducing air deposition of mercury primarily
from coal-fired power plants in the Midwest.
Carbon Dioxide
In February 2003, a number of states
notified the EPA that they planned to sue the agency to force it to set new
source performance standards for utility emissions of carbon dioxide and to
tighten existing standards for sulfur dioxide and particulate matter for utility
emissions. In June 2003, three of these states sued the EPA seeking a court
order requiring the EPA to designate carbon dioxide as a criteria pollutant and
to issue a new NAAQS for carbon dioxide. If these lawsuits result in the
issuance of a court order requiring the EPA to set emission limitations for
carbon dioxide and/or lower emission limitations for sulfur dioxide and
particulate matter, it could reduce the amount of coal our customers would
purchase from us.
Regional Haze
The EPA has initiated a regional haze
program designed to protect and improve visibility at and around national parks,
national wilderness areas and international parks. This program restricts the
construction of new coal-fired power plants whose operation may impair
visibility at and around federally protected areas. Moreover, this program may
require certain existing coal-fired power plants to install additional control
measures designed to limit haze-causing emissions, such as sulfur dioxide,
nitrogen oxides, volatile organic chemicals and particulate matter. These
limitations could affect the future market for coal. On July 6, 2005, the
EPA issued regulations revising its regional haze program.
Clean Water Act
The federal Clean Water Act (“CWA”) and
corresponding state laws affect coal mining operations by imposing restrictions
on the discharge of certain pollutants into water and on dredging and filling
wetlands and jurisdictional waters. The CWA establishes in-stream water quality
standards and treatment standards for wastewater discharge through the National
Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, as well as
compliance with reporting requirements and performance standards, are
preconditions for the issuance and renewal of NPDES permits that govern the
discharge of pollutants into water.
22
Permits under Section 404 of the
CWA are required for coal companies to conduct dredging or filling activities in
jurisdictional waters for the purpose of conducting any instream activities,
including installing culverts, creating water impoundments, constructing refuse
areas, creating slurry ponds, placing valley fills or performing other mining
activities. Jurisdictional waters typically include intermittent and perennial
streams and may, in certain instances, include man-made conveyances that have a
hydrologic connection to a stream or wetland. The Army Corps of Engineers
(“ACOE”) authorizes in-stream activities under either a general “nationwide”
permit or under an individual permit, based on the expected environmental
impact. A nationwide permit may be issued for specific categories of filling
activity that are determined to have minimal environmental adverse effects;
however, the effective term of such permits is limited to no longer than five
years. Nationwide Permit 21 authorizes the disposal of dredge-and-fill material
from mining activities into the waters of the United States. An individual permit typically
requires a more comprehensive application process, including public notice and
comment, but an individual permit can be issued for the project life. We have
secured nationwide permits and individual permits, depending on the expected
duration and timing of the proposed in-stream activity.
Judge Robert C. Chambers of the U.S.
District Court for the Southern District of West Virginia ruled in March 2007 in
a lawsuit filed by several citizen groups against the ACOE that the ACOE failed
to adequately assess the impacts of surface mining on headwaters and approved
mitigation that did not appropriately compensate for stream losses. Judge
Chambers in June 2007 found that sediment ponds situated within a stream channel
violated the prohibition against using the waters of the U.S. for waste treatment and further decided
that using the reach of stream between a valley fill and the sediment pond to
transport sediment-laden runoff is prohibited by the Clean Water Act.
In February
2009, the Fourth Circuit
Court of Appeals overturned
these decisions and remanded the case for further proceedings.
On December 6, 2007, the Sierra
Club and Kentucky Waterways Alliance sued the ACOE in the U.S. District Court
for the Western District of Kentucky alleging that the ACOE Louisville District
wrongfully issued a Section 404 authorization to ICG Hazard’s Thunder Ridge
surface mine in Perry County, Kentucky. The plaintiffs, who are represented by
the same counsel as the plaintiffs in the Chambers lawsuit, make essentially the
same claims but add the charge that the ACOE violated the National Environmental
Policy Act requirement that stream impacts first must be avoided or in the
alternative minimized. On December 26, 2007, the ACOE suspended the
Section 404 permit to allow it to review and supplement as needed the
administrative record on which the permit decision is based. We are cooperating
with the ACOE in defending the ACOE’s decision to issue the permit. Our Thunder
Ridge surface mine continues to operate on previously permitted areas and, in
accordance with an agreement reached among the parties, on certain portions of
the newly permitted area.
On October 23, 2003, several
citizens groups sued the ACOE in the U.S. District Court for the Southern
District of West Virginia seeking to invalidate “nationwide” permits utilized by
the ACOE and the coal industry for permitting most in-stream disturbances
associated with coal mining, including excess spoil valley fills and refuse
impoundments. Although the lower court enjoined the issuance of authorizations
under Nationwide Permit 21, that decision was overturned by the Fourth Circuit
Court of Appeals, which concluded that the ACOE complied with the Clean Water
Act in promulgating Nationwide Permit 21. While this case remained dormant since
the appeals court decision, the judge asked the parties to brief the court
regarding the effects of the Chambers’ decision on the Nationwide Permit 21
program. The requested briefs were filed in 2008 and the case is pending
decision or further directive by the court.
A lawsuit making similar claims
regarding the Nationwide Permit 21 filed in the United States Court for the Eastern District of Kentucky by
a number of environmental groups is still pending. This suit also seeks, among
other things, an injunction preventing the ACOE from authorizing pursuant to
Nationwide Permit 21 “further discharges of mining rock, dirt or coal refuse
into valley fills or surface impoundments” associated with certain specific
mining permits, including permits issued to some of our mines in Kentucky. Granting of such relief would
interfere with the further operation of these mines. The judge ordered a
briefing schedule for the parties in this litigation.
In September 2008 the Sixth Circuit
Court of Appeals partly affirmed and partly rejected a federal district court’s
decision that had upheld EPA’s approval of Kentucky’s new anti-degradation regulations.
Anti-degradation regulations prohibit diminution of water quality in streams.
The circuit court upheld Kentucky’s methodology for designating high
quality waters, even though environmental groups claimed the methodology
resulted in too few high quality designations. The circuit court also affirmed
Kentucky’s designation method on a water
body-by-water body approach and rejected environmentalist claims that such
designations must be conducted on a parameter by parameter basis. The court also
upheld Kentucky’s exclusion of “impaired” waters from
anti-degradation review. However, the circuit court struck down the district
court’s approval of Kentucky’s alternative anti-degradation
implementation procedures for coal mining. See “Legal Proceedings” contained in
Item 3 of this Annual Report on Form 10-K.
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.
23
Under the Black Lung Benefits Revenue
Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981,
each coal mine operator must secure payment of federal black lung benefits to
claimants who are current and former employees and to a trust fund for the
payment of benefits and medical expenses to claimants who last worked in the
coal industry prior to July 1, 1973. The trust fund is funded by an excise
tax on production of up to $1.10 per ton for underground coal and up to $0.55
per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales
price. The excise tax does not apply to coal shipped outside the United States. In 2008, we recorded $11.8 million of
expense related to this excise tax.
Resource Conservation and Recovery
Act
The RCRA affects coal mining operations
by establishing requirements for the treatment, storage and disposal of
hazardous wastes. Certain coal mine wastes, such as overburden and coal cleaning
wastes, are exempted from hazardous waste management.
Subtitle C of the RCRA exempted fossil
fuel combustion by-products (“CCBs”) from hazardous waste regulation until the
EPA completed a report to Congress and, in 1993, made a determination on whether
the CCBs should be regulated as hazardous. In the 1993 regulatory determination,
the EPA addressed some high volume-low toxicity coal combustion by-products
generated at electric utility and independent power producing facilities, such
as coal ash.
In May 2000, the EPA concluded that CCBs
do not warrant regulation as hazardous waste under the RCRA and that the
hazardous waste exemption applied to these CCBs. However, the EPA has determined
that national non-hazardous waste regulations under the RCRA Subtitle D are
needed for CCBs disposed in surface impoundments and landfills and used as
mine-fill. The agency also concluded beneficial uses of these CCBs, other than
for mine-filling, pose no significant risk and no additional national
regulations are needed. As long as the exemption remains in effect, it is not
anticipated that regulation of CCBs will have any material effect on the amount
of coal used by electricity generators. Most state hazardous waste laws also
exempt CCBs and instead treat them as either a solid waste or a special waste.
Efforts continue by environmental groups and others for the adoption of more
stringent disposal requirements for CCBs. Any increased costs associated with
handling or disposal of CCBs would increase our customers’ operating costs and
potentially reduce their coal purchases. In addition, contamination caused by
the past disposal of ash can lead to material liability.
Due to the hazardous waste exemption for
CCBs such as ash, some of the CCBs are currently put to beneficial use. For
example, at certain mines, the Company sometimes uses ash deposits from the
combustion of coal as a beneficial use under its reclamation plan. The alkaline
ash used for this purpose serves to help alleviate the potential for acid mine
drainage.
Federal and State Superfund
Statutes
Superfund and similar state laws affect
coal mining and hard rock operations by creating liability for investigation and
remediation in response to releases of hazardous substances into the environment
and for damages to natural resources caused by such releases. Under Superfund,
joint and several liability may be imposed on waste generators, site owners or
operators and others regardless of fault. In addition, mining operations may
have reporting obligations under these laws.
24
Climate Change
Global climate change has a potentially
far-reaching impact upon our business. Concerns over measurements, estimates and
projections of global climate change, particularly global warming, have resulted
in widespread calls for the reduction, by regulation and voluntary measures, of
the emission greenhouse gases, which include carbon dioxide and methane. These
measures could impact the market for our coal and coalbed methane, increase our
own energy costs and affect the value of our coal reserves. The United States has not ratified the Framework
Convention on Global Climate Change, commonly known as the Kyoto Protocol, which
would require our nation to reduce greenhouse gas emissions to 93% of 1990
levels by 2012. The United
States is participating in
international discussions which are underway to develop a treaty to require
additional reductions in greenhouse gas emissions after 2012. The United States has yet to adopt a federal program for
controlling greenhouse gas emissions. However, Congress is considering a variety
of legislative proposals which would restrict and/or tax the emission of carbon
dioxide from the combustion of coal and other fuels and which would mandate or
encourage the generation of electricity by new facilities that do not use coal.
Even without new legislation, the emission of greenhouse gases may be restricted
by future regulation, as the U.S. Supreme Court held in 2007 that the EPA has
authority under the Clean Air Act to regulate these gases. The EPA is
considering the potential mechanisms for regulating greenhouse gas emissions
under the Clean Air Act, including whether to impose restrictions on the
emission of carbon dioxide. Federal regulation of the emission of carbon dioxide
from coal-fired electric generating stations could adversely affect the demand
for coal.
While advocating for comprehensive
federal legislation, many states have adopted measures, sometimes as part of a
regional collaboration, to reduce green house gases generated within their own
jurisdiction. These measures include emission regulations, mandates for
utilities to generate a portion of its electricity without using coal and
incentives or goals for generating electricity using renewable resources. Some
municipalities have also adopted similar measures. Even in the absence of
mandatory requirements, some entities are electing to purchase electricity
generated by renewable resources for a variety of reasons, including
participation in programs calling for voluntary reductions in greenhouse gas
emissions.
In addition to impacting our markets,
regulations enacted due to climate change concerns could affect our operations
by increasing our costs. Our energy costs could increase, and we may have to
incur higher costs to control emissions of carbon dioxide, methane or other
pollutants from our operations.
Coal Industry Retiree Health Benefit Act
of 1992
Unlike many companies in the coal
business, we do not have significant liabilities under the Coal Industry Retiree
Health Benefit Act of 1992 (the “Coal Act”), which requires the payment of
substantial sums to provide lifetime health benefits to union-represented miners
(and their dependents) who retired before 1992, because liabilities under the
Coal Act that had been imposed on our predecessor or acquired companies were
retained by the sellers and, if applicable, their parent companies in the
applicable acquisition agreements, except for Anker. We should not be liable for
these liabilities retained by the sellers unless they and, if applicable, their
parent companies fail to satisfy their obligations with respect to Coal Act
claims and retained liabilities covered by the acquisition agreements. Upon the
consummation of the business combination with Anker, we assumed Anker’s Coal Act
liabilities, which were estimated to be $1.3 million at December 31,
2008.
Endangered Species
Act
The federal Endangered Species Act and
counterpart state legislation protect species threatened with possible
extinction. Protection of threatened and endangered species may have the effect
of prohibiting or delaying us from obtaining mining permits and may include
restrictions on timber harvesting, road building and other mining or
agricultural activities in areas containing the affected species or their
habitats. A number of species indigenous to our properties are protected under
the Endangered Species Act. Based on the species that have been identified to
date and the current application of applicable laws and regulations, however, we
do not believe there are any species protected under the Endangered Species Act
that would materially and adversely affect our ability to mine coal from our
properties in accordance with current mining plans.
Emergency Planning and Community Right
to Know Act
Some of our subsidiary operations
utilize materials and/or store substances that require certain reporting to
local and state authorities under the federal Emergency Planning and Community
Right to Know Act. If required reporting is missed it can result in the
assessment of fines and penalties. We do not believe that any potential fines or
penalties that could potentially arise under the federal Emergency Planning and
Community Right to Know Act would materially or adversely affect our ability to
mine coal.
Other Regulated
Substances
Some of our subsidiary operations
utilize certain substances, such as ammonia or caustic soda, for managing water
quality in discharges from their mine sites. These materials are considered
hazardous and require safeguards in handling and use and, if present in
sufficient quantities, create emergency planning and response requirements. The
storage of petroleum products in certain quantities can also trigger reporting,
planning and response requirements. Our subsidiaries are required to maintain
careful control over the storage and use of these substances. The subsidiaries
attempt to minimize the amount of materials stored at their operations that give
rise to such concerns and to maximize the use of less hazardous materials
whenever feasible. If quantities are sufficient, utilization of CCBs for
reclamation can trigger certain reporting requirements for constituent trace
elements contained in CCBs.
25
Additional
Information
We file annual, quarterly and current
reports, as well as amendments to those reports, proxy statements and other
information with the Securities and Exchange Commission (“SEC”). You may access
and read our SEC filings without charge through our website, www.intlcoal.com,
or the SEC’s website, www.sec.gov. You may also read and copy any document we
file at the SEC’s public reference room located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1–800–SEC–0330
for further information on the public reference room. You may also request
copies of our filings, at no cost, by telephone at (304) 760-2400 or by
mail at: International Coal Group, Inc., 300 Corporate Centre Drive, Scott
Depot, West Virginia 25560, Attention: Secretary.
GLOSSARY OF SELECTED
TERMS
Ash. Impurities consisting of silica,
alumina, calcium, iron and other incombustible matter that are contained in
coal. Since ash increases the weight of coal, it adds to the cost of handling
and can affect the burning characteristics of coal.
Base
load. The lowest level
of power production needs during a season or year.
Bituminous
coal. A middle rank
coal (between sub-bituminous and anthracite) formed by additional pressure and
heat on lignite. It is the most common type of coal with moisture content less
than 20% by weight and heating value of 10,000 to 14,000 Btus per pound. It is
dense and black and often has well-defined bands of bright and dull material. It
may be referred to as soft coal.
British thermal
unit or Btu. A measure of the thermal energy
required to raise the temperature of one pound of pure liquid water one degree
Fahrenheit at the temperature at which water has its greatest density (39
degrees Fahrenheit). On average, coal contains about 22 million Btu per
ton.
By-product. Useful substances made from the
gases and liquids left over when coal is changed into coke.
Central
Appalachia. Coal
producing area in eastern Kentucky, Virginia and southern West Virginia.
Clean coal burning
technologies. A number
of innovative, new technologies designed to use coal in a more efficient and
cost-effective manner while enhancing environmental protection. Several
promising technologies include fluidized-bed combustion, integrated gasification
combined cycle, limestone injection multi-stage burner, enhanced flue gas
desulfurization (or scrubbing), coal liquefaction and coal
gasification.
Coal
seam. A bed or stratum
of coal. Usually applies to a large deposit.
Coke. A hard, dry carbon substance
produced by heating coal to a very high temperature in the absence of air. Coke
is used in the manufacture of iron and steel. Its production results in a number
of useful byproducts.
Compliance
coal. Coal which, when
burned, emits 1.2 pounds or less of sulfur dioxide per million Btu, as required
by Phase II of the Clean Air Act Acid Rain program.
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Continuous
miner. A machine that
simultaneously extracts and loads coal. This is distinguished from a
conventional, or cyclic, unit, which must stop the extraction process for
loading to commence.
Deep
mine. An underground
coal mine.
Dragline. A large excavating machine used
in the surface mining process to remove overburden (see “Overburden” below). The
dragline has a large bucket suspended from the end of a huge boom, which may be
275 feet long or larger. The bucket is suspended by cables and capable of
scooping up vast amounts of overburden as it is pulled across the excavation
area. The dragline, which can “walk” on huge pontoon-like “feet,” is one of the
largest land-based machines in the world.
Fluidized bed
combustion. A process
with a high success rate in removing sulfur from coal during combustion. Crushed
coal and limestone are suspended in the bottom of a boiler by an upward stream
of hot air. The coal is burned in this bubbling, liquid-like (or fluidized)
mixture. Rather than released as emissions, sulfur from combustion gases
combines with the limestone to form a solid compound recovered with the
ash.
Fossil
fuel. Fuel such as
coal, crude oil or natural gas formed from the fossil remains of organic
material.
High Btu
coal. Coal which has
an average heat content of 12,500 Btus per pound or greater.
High sulfur
coal. Coal which, when
burned, emits 2.5 pounds or more of sulfur dioxide per million
Btu.
Highwall. The unexcavated face of exposed
overburden and coal in a surface mine or in a face or bank on the uphill side of
a contour mine excavation.
Illinois Basin. Coal producing area in
Illinois, Indiana and western Kentucky.
Longwall
mining. The most
productive underground mining method in the United States. One of three main underground coal
mining methods currently in use. Employs a rotating drum, or less commonly a
steel plow, which is pulled mechanically back and forth across a face of coal
that is usually about a thousand feet long. The loosened coal falls onto a
conveyor for removal from the mine.
Low sulfur
coal. Coal which, when
burned, emits 1.6 pounds or less of sulfur dioxide per million
Btu.
Medium sulfur
coal. Coal which, when
burned, emits between 1.6 and 2.5 pounds of sulfur dioxide per million
Btu.
Metallurgical
coal. The various
grades of coal suitable for carbonization to make coke for steel manufacture.
Also known as “met” coal, its quality depends on four important criteria:
volatile matter, which affects coke yield; the level of impurities including
sulfur and ash, which affects coke quality; composition, which affects coke
strength; and basic characteristics, which affect coke oven safety. Met coal
typically has a particularly high Btu, but low ash and sulfur
content.
Nitrogen
oxide (NOx). A gas
formed in high temperature environments such as coal combustion. It is a harmful
pollutant that contributes to acid rain.
Non-reserve coal
deposits. Non-reserve
coal deposits are coal bearing bodies that have been sufficiently sampled and
analyzed, but do not qualify as a commercially viable coal reserve as prescribed
by SEC rules until a final comprehensive SEC prescribed evaluation is
performed.
Northern
Appalachia. Coal
producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.
Overburden. Layers of earth and rock covering
a coal seam. In surface mining operations, overburden is removed prior to coal
extraction.
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Pillar. An area of coal left to support
the overlying strata in a mine; sometimes left permanently to support surface
structures.
Powder River
Basin. Coal producing
area in northeastern Wyoming and southeastern Montana. This is the largest known source of
coal reserves and the largest producing region in the United States.
Preparation
plant. Usually located
on a mine site, although one plant may serve several mines. A preparation plant
is a facility for crushing, sizing and washing coal to prepare it for use by a
particular customer. The washing process has the added benefit of removing some
of the coal’s sulfur content.
Probable
reserves. Reserves for
which quantity and grade and/or quality are computed from information similar to
that used for proven reserves, but the sites for inspection, sampling and
measurement are farther apart or are otherwise less adequately spaced. The
degree of assurance, although lower than that for proven reserves, is high
enough to assume continuity between points of observation.
Reclamation. The process of restoring land and
environmental values to a mining site after the coal 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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Risks Relating To Our
Business
A decline in coal prices could reduce
our revenues and the value of our coal reserves.
Our results of operations are dependent
upon the prices we receive for our coal, as well as our ability to improve
productivity and control costs. Any decreased demand would cause spot prices to
decline and require us to increase productivity and decrease costs in order to
maintain our margins. During the first half of 2008, the spot market prices
increased leading to a higher average price per ton of coal. A decrease in those
prices in 2009 could adversely affect our operating results and our ability to
generate the cash flows we require to meet our bank loan requirements, improve
our productivity and invest in our operations. The prices we receive for coal
depend upon factors beyond our control, including:
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supply of and demand for domestic
and foreign coal;
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demand for
electricity;
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domestic and foreign demand for
steel and the continued financial viability of the domestic and/or foreign
steel industry;
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proximity to, capacity of and cost
of transportation facilities;
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domestic and foreign governmental
regulations and taxes;
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air emission standards for
coal-fired power plants;
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regulatory, administrative and
judicial decisions;
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price and availability of
alternative fuels, including the effects of technological developments;
and
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effect of worldwide energy
conservation measures.
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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:
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unavailability of qualified
labor;
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our inability to acquire, maintain
or renew necessary permits or mining or surface rights in a timely manner,
if at all;
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unfavorable geologic conditions,
such as the thickness of the coal deposits and the amount of rock embedded
in or overlying the coal deposits;
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failure of reserve estimates to
prove correct;
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changes in governmental regulation
of the coal industry, including the imposition of additional taxes, fees
or actions to suspend or revoke our permits or changes in the manner of
enforcement of existing regulations;
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mining and processing equipment
failures and unexpected maintenance problems;
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adverse weather and natural
disasters, such as heavy rains and flooding;
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increased water entering mining
areas and increased or accidental mine water
discharges;
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increased or unexpected
reclamation costs;
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interruptions due to
transportation delays;
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unavailability of required
equipment of the type and size needed to meet production expectations;
and
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unexpected mine safety accidents,
including fires and
explosions.
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These conditions and events may increase
our cost of mining and delay or halt production at particular mines either
permanently or for varying lengths of time. We were impacted during 2008 by a
tightening labor market increasing our compensation costs, as well as increases
in costs for repairs and maintenance, diesel fuel, blasting supplies, roof
control supplies and contract labor, all of which increased the cost of coal
sales.
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Reduced coal consumption by North
American electric power generators could result in lower prices for our coal,
which could reduce our revenues and adversely impact our earnings and the value
of our coal reserves.
Steam coal accounted for 94% of
all our coal sales volume in 2008 and the majority of our sales of steam
coal in 2008 were to electric power generators. Domestic electric power
generation accounted for approximately 93% of all U.S. coal consumption in 2007, according to
the EIA. The amount of coal consumed for U.S. electric power generation is affected
primarily by the overall demand for electricity, the location, availability,
quality and price of competing fuels for power such as natural gas, nuclear,
fuel oil and alternative energy sources such as hydroelectric power,
technological developments and environmental and other governmental
regulations.
Although we expect that new power plants
will be built to produce electricity during peak periods of demand, we also
expect that many of these new power plants will be fired by natural gas because
gas-fired plants are cheaper to construct than coal-fired plants and because
natural gas is a cleaner burning fuel. Gas-fired generation from existing and
newly constructed gas-fired facilities has the potential to displace coal-fired
generation, particularly from older, less efficient coal-powered generators. In
addition, the increasingly stringent requirements of the Clean Air Act and the
potential regulation of greenhouse gas emissions may result in more electric
power generators shifting from coal to natural gas-fired plants or alternative
energy sources. Furthermore, environmental activists have evidenced an intent to
use regulatory and judicial processes to block the construction of any new
coal-fired power plants or capacity expansions to existing plants due to climate
change concerns, at least until carbon dioxide emissions controls for such
plants are imposed by federal law. Any reduction in the amount of coal consumed
by North American electric power generators could reduce the price of steam coal
that we mine and sell, thereby reducing our revenues and adversely impacting our
earnings and the value of our coal reserves.
Weather patterns also can greatly affect
electricity generation. Extreme temperatures, both hot and cold, cause increased
power usage and, therefore, increased generating requirements from all sources.
Mild temperatures, on the other hand, result in lower electrical demand, which
allows generators to choose the lowest-cost sources of power generation when
deciding which generation sources to dispatch. Accordingly, significant changes
in weather patterns could reduce the demand for our coal.
Overall economic activity and the
associated demands for power by industrial users can have significant effects on
overall electricity demand. Robust economic activity can cause much heavier
demands for power, particularly if such activity results in increased
utilization of industrial assets during evening and nighttime periods. An
economic slowdown can significantly slow the growth of electrical demand and, in
some locations, result in contraction of demand. The economy suffered a
significant slowdown in the fourth quarter of 2008 that resulted in lower
demand. Any downward pressure on coal prices, whether due to increased use of
alternative energy sources, changes in weather patterns, decreases in overall
demand or otherwise, would likely cause our profitability to
decline.
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The capability and profitability of our
operations may be adversely affected by the status of our long-term coal supply
agreements and changes in purchasing patterns in the coal
industry.
We sell a significant portion of our
coal under long-term coal supply agreements, which we define as contracts with a
term greater than 12 months. For the year ended December 31, 2008, approximately
51% of our revenues were derived from coal sales that were made under long-term
coal supply agreements. As of that date, we had 49 long-term sales agreements
with a volume-weighted average term of approximately 3.8 years. The prices for
coal shipped under these agreements are typically fixed for at least the initial
year of the contract, subject to certain adjustments in later years and thus may
be below the current market price for similar type coal at any given time,
depending on the timeframe of contract execution or initiation. As a consequence
of the substantial volume of our sales that are subject to these long-term
agreements, we have less coal available with which to capitalize on higher coal
prices, if and when they arise. In addition, in some cases, our ability to
realize the higher prices that may be available in the spot market may be
restricted when customers elect to purchase higher volumes allowable under some
contracts. When our current contracts with customers expire or are otherwise
renegotiated, our customers may decide not to extend or enter into new long-term
contracts or, in the absence of long-term contracts, our customers may decide to
purchase fewer tons of coal than in the past or on different terms, including
under different pricing terms.
Furthermore, as electric utilities seek
to adjust to requirements of the Clean Air Act, and the potential for more
stringent requirements, they could become increasingly less willing to enter
into long-term coal supply agreements and instead may purchase higher
percentages of coal under short-term supply agreements. To the extent the
electric utility industry shifts away from long-term supply agreements, it could
adversely affect us and the level of our revenues. For example, fewer electric
utilities will have a contractual obligation to purchase coal from us, thereby
increasing the risk that we will not have a market for our production.
Furthermore, spot market prices tend to be more volatile than contractual
prices, which could result in decreased revenues.
Certain provisions in our long-term
supply agreements may provide limited protection during periods of adverse
economic conditions. For example, the customer may be forced to reduce
electricity output due to weak demand. If the low demand were to persist for an
extended period the customer might be forced to delay our contract shipments
thereby reducing our revenue.
Price adjustment, “price reopener” and
other similar provisions in long-term supply agreements may reduce the
protection from short-term coal price volatility traditionally provided by such
contracts. Most of our coal supply agreements contain provisions that allow for
the purchase price to be renegotiated at periodic intervals. These price
reopener provisions may automatically set a new price based on the prevailing
market price or, in some instances, require the parties to agree on a new price,
sometimes between a specified range of prices. In some circumstances, failure of
the parties to agree on a price under a price reopener provision can lead to
termination of the contract. Any adjustment or renegotiations leading to a
significantly lower contract price would result in decreased revenues.
Accordingly, supply contracts with terms of one year or more may provide only
limited protection during adverse market conditions.
Coal supply agreements also typically
contain force majeure provisions allowing temporary suspension of performance by
us or our customers during the duration of specified events beyond the control
of the affected party. Additionally, most of our coal supply agreements contain
provisions requiring us to deliver coal meeting quality thresholds for certain
characteristics such as heat value (measured in Btus), sulfur content, ash
content, hardness and ash fusion temperature. Failure to meet these
specifications could result in economic penalties, including price adjustments,
the rejection of deliveries or, in the extreme, termination of the
contracts.
Consequently, due to the risks mentioned
above, we may not achieve the revenue or profit we expect to achieve from our
long-term supply agreements.
The
duration or severity of the current global financial crisis are uncertain and
may have an impact on our business and financial conditions in ways that we
currently cannot predict.
The
continued credit crisis and related turmoil in the global financial system may
impact our business and our financial condition. In light of the current
economic condition in the financial markets, there can be no assurance the
lenders participating in our credit facility will fulfill their commitments in
accordance with their legal obligations under the credit facility. If one or
more of the lenders were to default on its obligation to fund its commitment,
the portion of the credit facility provided by such defaulting lender would not
be available to us. We also have access to a revolving credit facility to
purchase equipment from one of our vendors. The ability of the vendor to provide
this financing in the future may be negatively impacted by the current credit
crisis. Our ability to obtain alternate financing on acceptable terms (if at
all) may be severely restricted at a time when we would like, or need, to do so,
which could have an adverse impact on our ability to meet capital
commitments.
Additionally,
while we have committed and priced the vast majority of our planned shipments of
coal production for next year, 26%, or approximately 434,000 tons, of our
uncommitted tonnage for 2009 is metallurgical coal. Visibility into the domestic
and international metallurgical coal markets is difficult because of recently
announced price and production cuts by steel producers in several countries,
including the U.S. The depth and duration of this imminent slowdown in the steel
sector has yet to be defined and a reduction in global steel production could
adversely impact overall demand for, and/or result in deferrals of or refusal to
receive shipments of, our metallurgical coal, which could have a negative effect
on our revenues.
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A decline in demand for metallurgical
coal would limit our ability to sell our high quality steam coal as
higher-priced metallurgical coal.
Portions of our coal reserves possess
quality characteristics that enable us to mine, process and market them as
either metallurgical coal or high quality steam coal, depending on the
prevailing conditions in the metallurgical and steam coal markets. A decline in
the metallurgical market relative to the steam market could cause us to shift
coal from the metallurgical market to the steam market, thereby reducing our
revenues and profitability. However, some of our mines operate profitably only
if all or a portion of their production is sold as metallurgical coal to the
steel market. If demand for metallurgical coal declined to the point where we
could earn a more attractive return marketing the coal as steam coal, these
mines may not be economically viable and may be subject to closure. Such
closures would lead to accelerated reclamation costs, as well as reduced revenue
and profitability.
Inaccuracies in our estimates of
economically recoverable coal reserves could result in lower than expected
revenues, higher than expected costs or decreased
profitability.
We base our reserves information on
engineering, economic and geological data assembled and analyzed by our staff,
which includes various engineers and geologists, and which is periodically
reviewed by outside firms. The reserves estimates as to both quantity and
quality are annually updated to reflect production of coal from the reserves,
acquisitions, dispositions, depleted reserves and new drilling or other data
received. There are numerous uncertainties inherent in estimating quantities and
qualities of and costs to mine recoverable reserves, including many factors
beyond our control. Estimates of economically recoverable coal reserves and net
cash flows necessarily depend upon a number of variable factors and assumptions,
all of which may vary considerably from actual results such
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geological and mining conditions
which may not be fully identified by available exploration data or which
may differ from experience in current
operations;
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historical production from the
area compared with production from other similar producing areas;
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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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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.
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We depend heavily on a small number of
large customers, the loss of any of which would adversely affect our operating
results.
Our three largest customers for the year
ended December 31, 2008 were Progress Energy, Georgia Power Company and
Allegheny Energy Supply Company and we derived approximately 32% of our coal
revenues from sales to our five largest customers. At December 31, 2008, we had
coal supply agreements with these customers that expire at various times from
2009 to 2011. We typically discuss extension of existing agreements or entering
into long-term agreements with our customers, however these negotiations may not
be successful and these customers may not continue to purchase coal from us
pursuant to long-term coal supply agreements. If a number of these customers
were to significantly reduce their purchases of coal from us, or if we were
unable to sell coal to them on terms as favorable to us as the terms under our
current agreements, our financial condition and results of operations could
suffer materially.
Disruptions in transportation services
could limit our ability to deliver coal to our customers, which could cause
revenues to decline.
We depend primarily upon railroads,
trucks and barges to deliver coal to our customers. Disruption of railroad
service due to weather-related problems, strikes, lockouts and other events
could temporarily impair our ability to supply coal to our customers, resulting
in decreased shipments and related sales revenues. Decreased performance levels
over longer periods of time could cause our customers to look elsewhere for
their fuel needs, negatively affecting our revenues and
profitability.
Several of our mines depend on a single
transportation carrier or a single mode of transportation. Disruption of any of
these transportation services due to weather-related problems, mechanical
difficulties, strikes, lockouts, bottlenecks and other events could temporarily
impair our ability to supply coal to our customers. Our transportation providers
may face difficulties in the future that may impair our ability to supply coal
to our customers, resulting in decreased revenues.
If there are disruptions of the
transportation services provided by our primary rail carriers that transport our
produced coal and we are unable to find alternative transportation providers to
ship our coal, our business could be adversely affected.
Fluctuations in transportation costs
could impair our ability to supply coal to our customers.
Transportation costs represent a
significant portion of the total cost of coal for our customers and, as a
result, the cost of transportation is a critical factor in a customer’s
purchasing decision. Increases in transportation costs could make coal a less
competitive source of energy or could make our coal production less competitive
than coal produced from other sources.
Conversely, significant decreases in
transportation costs could result in increased competition from coal producers
in other parts of the country. For instance, coordination of the many eastern
loading facilities, the large number of small shipments, the steeper average
grades of the terrain and a more unionized workforce are all issues that combine
to make shipments originating in the eastern United States inherently more expensive on a per-mile
basis than shipments originating in the western United States. The increased competition could have a
material adverse effect on our business, financial condition and results of
operations.
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Disruption in supplies of coal produced
by third parties could temporarily impair our ability to fill our customers’
orders or increase our costs.
In addition to marketing coal that is
produced from our controlled reserves, we purchase and resell coal produced by
third parties from their controlled reserves to meet customer specifications.
Disruption in our supply of third-party coal could temporarily impair our
ability to fill our customers’ orders or require us to pay higher prices in
order to obtain the required coal from other sources. Any increase in the prices
we pay for third-party coal could increase our costs and, therefore, lower our
earnings.
The unavailability of an adequate supply
of coal reserves that can be mined at competitive costs could cause our
profitability to decline.
Our profitability depends substantially
on our ability to mine coal reserves that have the geological characteristics
that enable them to be mined at competitive costs and to meet the quality needed
by our customers. Because our reserves decline as we mine our coal, our future
success and growth depend, in part, upon our ability to acquire additional coal
reserves that are economically recoverable. Replacement reserves may not be
available when required or, if available, may not be capable of being mined at
costs comparable to those characteristic of the depleting mines. We may not be
able to accurately assess the geological characteristics of any reserves that we
acquire, which may adversely affect our profitability and financial condition.
Exhaustion of reserves at particular mines also may have an adverse effect on
our operating results that is disproportionate to the percentage of overall
production represented by such mines. Our ability to obtain other reserves in
the future could be limited by restrictions under our existing or future debt
agreements, competition from other coal companies for attractive properties, the
lack of suitable acquisition candidates or the inability to acquire coal
properties on commercially reasonable terms.
Unexpected increases in raw material
costs or decreases in availability could significantly impair our operating
profitability.
Our coal mining operations use
significant amounts of steel, rubber, petroleum products and other raw materials
in various pieces of mining equipment, supplies and materials, including the
roof bolts required by the room-and-pillar method of mining described
previously. Scrap steel prices have risen significantly and, historically, the
prices of scrap steel and petroleum have fluctuated. In 2008, we were adversely
impacted by margin compressions due to cost increases for various commodities
and services such as diesel fuel, explosives (ANFO), roof control supplies and
coal trucking, influenced by the price variability of crude oil and natural gas.
There may be other acts of nature, terrorist attacks or threats or other
conditions that could also increase the costs of raw materials. If the price of
steel, rubber, petroleum products or other of these materials increase, our
operational expenses will increase, which could have a significant negative
impact on our profitability. Additionally, shortages in raw materials used in
the manufacturing of supplies and mining equipment could limit our ability to
obtain such items which could have an adverse effect on our ability to carry out
our business plan.
The accident at the Sago mine could
negatively impact our business.
On January 2, 2006, an explosion
occurred at our Sago mine in West Virginia, which will be sealed and permanently
closed in 2009. The explosion tragically resulted in the deaths of twelve miners
and the critical injury of another miner. As a result of the accident, the
federal and state investigations and related matters and civil litigation
arising out of the accident, our business may be negatively impacted by various
factors including the diversion of management’s attention from our day-to-day
business, further negative media attention, any negative perceptions about our
safety record affecting our ability to attract skilled labor, the impact of
litigation commenced against us, any increased premiums for insurance and any
claims that may be asserted against us that are not covered, in whole or in
part, by our insurance policies.
34
A shortage of skilled labor in the
mining industry could pose a risk to achieving optimal labor productivity and
competitive costs, which could adversely affect our
profitability.
Efficient coal mining using modern
techniques and equipment requires skilled laborers, preferably with at least a
year of experience and proficiency in multiple mining tasks. In order to support
our planned expansion opportunities, we intend to sponsor both in-house and
vocational coal mining programs at the local level in order to train additional
skilled laborers. Labor and benefit costs have increased in 2008 due to a
tightening labor market resulting in the need to offer more competitive
compensation packages. Contract labor costs also increased over prior year. In
2008, $12.68 and $1.60 of our cost of coal sales per ton were attributable to
labor and benefits and contract labor, respectively, compared to $10.60 and
$1.11 for 2007. In the event the shortage of experienced labor continues or
worsens or we are unable to train the necessary amount of skilled laborers,
there could be an adverse impact on our labor productivity and costs and our
ability to expand production and therefore have a material adverse effect on our
earnings.
Our ability to operate our company
effectively could be impaired if we fail to attract and retain key
personnel.
Our senior management team averages 24
years of experience in the coal industry, which includes developing innovative,
low-cost mining operations, maintaining strong customer relationships and making
strategic, opportunistic acquisitions. The loss of any of our senior executives
could have a material adverse effect on our business. There may be a limited
number of persons with the requisite experience and skills to serve in our
senior management positions. We may not be able to locate or employ qualified
executives on acceptable terms. In addition, as our business develops and
expands, we believe that our future success will depend greatly on our continued
ability to attract and retain highly skilled personnel with coal industry
experience. Competition for these persons in the coal industry is intense and we
may not be able to successfully recruit, train or retain qualified personnel. We
may not be able to continue to employ key personnel or attract and retain
qualified personnel in the future. Our failure to retain or attract key
personnel could have a material adverse effect on our ability to effectively
operate our business.
Acquisitions that we may undertake
involve a number of inherent risks, any of which could cause us not to realize
the anticipated benefits.
We continually seek to expand our
operations and coal reserves through selective acquisitions. If we are unable to
successfully integrate the companies, businesses or properties we acquire, our
profitability may decline and we could experience a material adverse effect on
our business, financial condition or results of operations. Acquisition
transactions involve various inherent risks, including:
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uncertainties in assessing the
value, strengths and potential profitability of, and identifying the
extent of all weaknesses, risks, contingent and other liabilities
(including environmental or mine safety liabilities) of, acquisition
candidates;
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potential loss of key customers,
management and employees of an acquired
business;
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ability to achieve identified
operating and financial synergies anticipated to result from an
acquisition;
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discrepancies between the
estimated and actual reserves of the acquired
business;
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problems that could arise from the
integration of the acquired business; and
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unanticipated changes in business,
industry or general economic conditions that affect the assumptions
underlying our rationale for pursuing the
acquisition.
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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.
35
Risks inherent to mining could increase
the cost of operating our business.
Our mining operations are subject to
conditions that can impact the safety of our workforce or delay coal deliveries
or increase the cost of mining at particular mines for varying lengths of time.
These conditions include fires and explosions from methane gas or coal dust;
accidental minewater discharges; weather, flooding and natural disasters;
unexpected maintenance problems; key equipment failures; variations in coal seam
thickness; variations in the amount of rock and soil overlying the coal deposit;
variations in rock and other natural materials and variations in geologic
conditions. We maintain insurance policies that provide limited coverage for
some of these risks, although there can be no assurance that these risks would
be fully covered by our insurance policies. Despite our efforts, significant
mine accidents could occur and have a substantial impact. See “– The accident at
the Sago mine could negatively impact our business.”
Inability of contract miner or brokerage
sources to fulfill the delivery terms of their contracts with us could reduce
our profitability.
In conducting our mining operations, we
utilize third-party sources of coal production, including contract miners and
brokerage sources, to fulfill deliveries under our coal supply agreements. Our
profitability or exposure to loss on transactions or relationships such as these
is dependent upon the reliability (including financial viability) and price of
the third-party supply, our obligation to supply coal to customers in the event
that adverse geologic mining conditions restrict deliveries from our suppliers,
our willingness to participate in temporary cost increases experienced by our
third-party coal suppliers, our ability to pass on temporary cost increases to
our customers, the ability to substitute, when economical, third-party coal
sources with internal production or coal purchased in the market and other
factors. Brokerage sources and contract miners may experience adverse geologic
mining and/or financial difficulties that make their delivery of coal to us at
the contractual price difficult or uncertain. If we have difficulty with our
third-party sources of coal, our profitability could
decrease.
36
We may be unable to generate sufficient
taxable income from future operations to fully utilize our significant tax net
operating loss carryforwards or maintain our deferred tax
assets.
As a result of our acquisition of Anker
and of historical financial results, we have recorded deferred tax assets. If we
fail to generate profits in the foreseeable future, our deferred tax assets may
not be fully utilized. We evaluate our ability to utilize our net operating loss
(“NOL”) and tax credit carryforwards each period and, in compliance with SFAS
No. 109, Accounting for
Income Taxes (“SFAS
109”), record any resulting adjustments that
may be required to deferred income tax expense. In addition, we will reduce the
deferred income tax asset for the benefits of NOL and tax credit carryforwards
used in future periods and will recognize and record federal and state income
tax expense at statutory rates in future periods. If, in the future, we
determine that it is more likely than not that we will not realize all or a
portion of the deferred tax assets, we will record a valuation allowance against
deferred tax assets which would result in a charge to income tax
expense.
Failure to obtain or renew surety bonds
in a timely manner and on acceptable terms could affect our ability to secure
reclamation and coal lease obligations, which could adversely affect our ability
to mine or lease coal.
Federal and state laws require us to
obtain surety bonds to secure payment of certain long-term obligations, such as
mine closure or reclamation costs, federal and state workers’ compensation
costs. Certain business transactions, such as coal leases and other obligations,
may also require bonding. These bonds are typically renewable annually. Surety
bond issuers and holders may not continue to renew the bonds or may demand
additional collateral or other less favorable terms upon those renewals. The
ability of surety bond issuers and holders to demand additional collateral or
other less favorable terms has increased as the number of companies willing to
issue these bonds has decreased over time. Our failure to maintain, or our
inability to acquire, surety bonds that are required by state and federal law
would affect our ability to secure reclamation and coal lease obligations, which
could adversely affect our ability to mine or lease coal. That failure could
result from a variety of factors including, without
limitation:
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lack of availability, higher
expense or unfavorable market terms of new
bonds;
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restrictions on availability of
collateral for current and future third-party surety bond issuers under
the terms of our amended and restated credit facility;
and
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exercise by third-party surety
bond issuers of their right to refuse to renew the
surety.
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Failure to maintain capacity for
required letters of credit could limit our ability to obtain or renew surety
bonds.
At December 31, 2008, we had $73.6
million of letters of credit in place, of which $61.1 million serves as
collateral for reclamation surety bonds and $12.5 million secures miscellaneous
obligations. Our amended and restated credit facility provides for a revolving
credit facility of $100.0 million, of which up to $80.0 million may be used for
letters of credit. If we do not maintain sufficient borrowing capacity under our
amended and restated credit facility for additional letters of credit, we may be
unable to obtain or renew surety bonds required for our mining
operations.
Our business may require continued
capital investment, which we may be unable to provide.
Our business strategy may require
continued capital investment. We require capital for, among other purposes,
managing acquired assets, acquiring new equipment, maintaining the condition of
our existing equipment and maintaining compliance with environmental laws and
regulations. To the extent that cash generated internally and cash available
under our credit facilities are not sufficient to fund capital requirements, we
will require additional debt and/or equity financing. However, this type of
financing may not be available, particularly in current market conditions, or if
available, may not be on satisfactory terms. Future debt financings, if
available, may result in increased interest and amortization expense, increased
leverage and decreased income available to fund further acquisitions and
expansion. In addition, future debt financings may limit our ability to
withstand competitive pressures and render us more vulnerable to economic
downturns. If we fail to generate sufficient earnings or to obtain sufficient
additional capital in the future or fail to manage our capital investments
effectively, we could be forced to reduce or delay capital expenditures, sell
assets or restructure or refinance our indebtedness.
In
addition, the credit agreement governing our amended and restated credit
facility contains customary affirmative and negative covenants for credit
facilities of this type, including, but not limited to, limitations on the
incurrence of indebtedness, asset dispositions, acquisitions, investments,
dividends and other restricted payments, liens and transactions with affiliates.
The credit agreement requires us to meet certain financial tests, including a
maximum leverage ratio, a minimum interest coverage ratio, and a limit on
capital expenditures. If we fail to comply with any affirmative or negative
covenant, or to meet any financial test, in our credit agreement, we may be
unable to obtain or renew surety bonds required for our mining
operations.
The
credit agreement also contains customary events of default, including, but not
limited to, failure to pay principal or interest, breach of covenants or
representations and warranties, cross-default to other indebtedness, judgment
default and insolvency. If an event of default occurs under the credit
agreement, the lenders under the credit agreement will be entitled to take
various actions, including demanding payment for all amounts outstanding
thereunder and foreclosing on any collateral. If the lenders were to do so, our
other debt obligations including the senior notes and the convertible notes,
would also have the right to accelerate those obligations which the Company
would be unable to satisfy. See “–
Our ability and the ability
of some of our subsidiaries to engage in some business transactions or to pursue
our business strategy may be limited by the terms of our existing
debt” and “– The duration or severity of the current
global financial crisis are uncertain and may have an impact on our business and
financial conditions in ways that we currently cannot predict.”
37
Increased consolidation and competition
in the U.S. coal industry may adversely affect our
ability to retain or attract customers and may reduce domestic coal
prices.
During the last several years, the
U.S. coal industry has experienced increased
consolidation, which has contributed to the industry becoming more competitive.
According to the EIA, in 1995, the top ten coal producers accounted for
approximately 50% of total domestic coal production. By 2007, however, the top
ten coal producers’ share had increased to approximately 65% of total domestic
coal production. Consequently, many of our competitors in the domestic coal
industry are major coal producers who have significantly greater financial
resources than us. The intense competition among coal producers may impact our
ability to retain or attract customers and may therefore adversely affect our
future revenues and profitability.
The demand for U.S. coal exports is
dependent upon a number of factors outside of our control, including the overall
demand for electricity in foreign markets, currency exchange rates, ocean
freight rates, the demand for foreign-produced steel both in foreign markets and
in the U.S. market (which is dependent in part on tariff rates on steel),
general economic conditions in foreign countries, technological developments and
environmental and other governmental regulations. If foreign demand for
U.S. coal were to decline, this decline
could cause competition among coal producers in the United States to intensify, potentially resulting in
additional downward pressure on domestic coal prices.
Our ability to collect payments from our
customers could be impaired if their creditworthiness
deteriorates.
Our ability to receive payment for coal
sold and delivered depends on the continued creditworthiness of our customers.
Our customer base is changing with deregulation as utilities sell their power
plants to their non-regulated affiliates or third parties that may be less
creditworthy, thereby increasing the risk we bear on payment default. These new
power plant owners may have credit ratings that are below investment grade. In
addition, a recent slowdown in the global steel sector has resulted in
announced price and production cuts by steel producers in several countries,
which could impact the ability of our metallurgical coal customers to settle
outstanding amounts due to us. Further, competition with other coal suppliers
could force us to extend credit to customers and on terms that could increase
the risk we bear on payment default.
We have contracts to supply coal to
energy trading and brokering companies under which those companies sell coal to
end users. In recent years, the creditworthiness of the energy trading and
brokering companies with which we do business declined, increasing the risk that
we may not be able to collect payment for all coal sold and delivered to or on
behalf of these energy trading and brokering companies.
In
the current economic climate certain of our customers and their customers may be
affected by cash flow problems, which has the potential to increase the time it
takes to collect accounts receivables.
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.
38
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.
We are subject to various legal
proceedings, which may have a material adverse effect on our
business.
We are parties to a number of legal
proceedings incidental to normal business activities, including several
complaints related to the accident at our Sago mine, a breach of contract
complaint by one of our customers related to the idling of our Sycamore
No. 2 mine and class action lawsuits that allege that the registration
statements filed in connection with our initial public offering contained false
and misleading statements, and that investors relied upon those securities
filings and suffered damages as a result. Some actions brought against us from
time to time may have merit. There is always the potential that an individual
matter or the aggregation of many matters could have an adverse effect on our
financial condition, results of operations or cash flows. See “Legal
Proceedings” contained in Item 3 of this Annual Report on Form
10-K.
Because of our limited operating
history, historical information regarding our company prior to October 1,
2004 is of little relevance in understanding our business as currently
conducted.
We were incorporated in March 2005 as a
holding company and ICG, Inc. was incorporated in May 2004 for the sole purpose
of acquiring certain assets of Horizon. Until the completion of the Horizon
asset acquisition, we had substantially no operations. As a result, historical
information regarding our company prior to October 1, 2004, which does not
include the historical financial information for Anker and CoalQuest, is of
limited relevance in understanding our business as currently conducted. The
financial statements for the Horizon predecessor periods have been prepared from
the books and records of Horizon as if we had existed as a separate legal entity
under common management for all periods presented (that is, on a “carve-out”
basis). The financial statements for the Horizon predecessor periods include
allocations of certain expenses, taxation charges, interest and cash balances
relating to the predecessor based on management’s estimates. In light of these
allocations and estimates, the Horizon predecessor financial information is not
necessarily indicative of our consolidated financial position, results of
operations and cash flows if we had operated during the Horizon predecessor
period presented. See “Selected Financial Data” and “Management’s Discussion and
Analysis of Financial Condition and Results of Operations.”
Risks Relating To Government
Regulation
Extensive government regulations impose
significant costs on our mining operations, and future regulations could
increase those costs or limit our ability to produce and sell
coal.
The coal mining industry is subject to
increasingly strict regulation by federal, state and local authorities with
respect to matters such as:
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limitations on land
use;
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employee health and
safety;
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mandated benefits for retired coal
miners;
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mine permitting and licensing
requirements;
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reclamation and restoration of
mining properties after mining is completed;
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air quality
standards;
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water
pollution;
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construction and permitting of
facilities required for mining operations, including valley fills and
other structures, including those constructed in waterbodies and
wetlands;
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protection of human health,
plantlife and wildlife;
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discharge of materials into the
environment;
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surface subsidence from
underground mining; and
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effects of mining on groundwater
quality and availability.
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39
In particular, federal and state
statutes require us to restore mine property in accordance with specific
standards and an approved reclamation plan, and require that we obtain and
periodically renew permits for mining operations. If we do not make adequate
provisions for all expected reclamation and other costs associated with mine
closures, it could harm our future operating results.
Federal and state safety and health
regulation in the coal mining industry may be the most comprehensive and
pervasive system for protection of employee safety and health affecting any
segment of the U.S. industry. It is costly and
time-consuming to comply with these requirements and new regulations or orders
may materially adversely affect our mining operations or cost structure, any of
which could harm our future results.
Under federal law, each coal mine
operator must secure payment of federal black lung benefits to claimants who are
current and former employees and contribute to a trust fund for the payment of
benefits and medical expenses to claimants who last worked in the coal industry
before July 1973. The trust fund is funded by an excise tax on coal production.
If this tax increases, or if we could no longer pass it on to the purchaser of
our coal under many of our long-term sales contracts, it could increase our
operating costs and harm our results. New regulations that took effect in 2001
could significantly increase our costs related to contesting and paying black
lung claims. If new laws or regulations increase the number and award size of
claims, it could substantially harm our business.
The costs, liabilities and requirements
associated with these and other regulations may be costly and time-consuming and
may delay commencement or continuation of exploration or production operations.
Failure to comply with these regulations may result in the assessment of
administrative, civil and criminal penalties, the imposition of cleanup and site
restoration costs and liens, the issuance of injunctions to limit or cease
operations, the suspension or revocation of permits and other enforcement
measures that could have the effect of limiting production from our operations.
We may also incur costs and liabilities resulting from claims for damages to
property or injury to persons arising from our operations. We must compensate
employees for work-related injuries. If we do not make adequate provisions for
our workers’ compensation liabilities, it could harm our future operating
results. If we are pursued for these sanctions, costs and liabilities, our
mining operations and, as a result, our profitability could be adversely
affected. See “Environmental, Safety and Other Regulatory
Matters.”
The possibility exists that new
legislation and/or regulations and orders may be adopted that may materially
adversely affect our mining operations, our cost structure and/or our customers’
ability to use coal. New legislation or administrative regulations (or new
judicial interpretations or administrative enforcement of existing laws and
regulations), including proposals related to the protection of the environment
that would further regulate and tax the coal industry, may also require us or
our customers to change operations significantly or incur increased costs. These
regulations, if proposed and enacted in the future, could have a material
adverse effect on our financial condition and results of
operations.
Judicial rulings that restrict disposal
of mining spoil material could significantly increase our operating costs,
discourage customers from purchasing our coal and materially harm our financial
condition and operating results.
Mining in the mountainous terrain of
Appalachia typically requires the use of valley
fills for the disposal of excess spoil (rock and soil material) generated by
construction and mining activities. In our surface mining operations, we use
mountaintop removal mining wherever feasible because it allows us to recover
more tons of coal per acre and facilitates the permitting of larger projects,
which allows mining to continue over a longer period of time than would be the
case using other mining methods. Mountaintop removal mining, along with other
methods of surface mining, depends on valley fills to dispose of mining spoil
material. Construction of roads, underground mine portal sites, coal processing
and handling facilities and coal refuse embankments or impoundments also require
the development of valley fills. We obtain permits to construct and operate
valley fills and surface impoundments from the Army Corps of Engineers (the
“ACOE”) under the auspices of Section 404 of the federal Clean Water Act.
Lawsuits challenging the ACOE’s authority to authorize surface mining activities
under Nationwide Permit 21 or under more comprehensive individual permits have
been instituted by environmental groups, which also advocate for changes in
federal and state laws that would prevent or further restrict the issuance of
such permits. The Fourth
Circuit Court of Appeals in 2005 vacated and remanded one such suit that was
originally filed in West Virginia, concluding that the ACOE complied with the
Clean Water Act when it promulgated the 2002 version of Nationwide Permit 21.
Final disposition of that case is pending before Judge Joseph R. Goodwin of the
U.S. District Court for the Southern District of West Virginia. A similar
lawsuit filed in federal court in Kentucky is still pending. Both of those cases
had additional briefing by the parties in 2008 and are awaiting decision or
further direction from the courts.
In a March 2007 decision pertaining
originally to certain Section 404 permits issued to Massey Energy Company, Judge
Robert C. Chambers of the U.S. District Court for the Southern District of West
Virginia ruled that the ACOE failed to adequately assess the impacts of surface
mining on headwaters and approved mitigation that did not appropriately
compensate for stream losses. Judge Chambers in June 2007 found that sediment
ponds situated within a stream channel violated the prohibition against using
the waters of the U.S. for waste treatment and further decided
that using the reach of stream between a valley fill and the sediment pond to
transport sediment-laden runoff is prohibited by the Clean Water Act. The ACOE
along with several intervenors appealed Judge Chambers’ decisions to the Fourth
Circuit Court of Appeals, which heard oral arguments in September 2008. A three
judge panel of the Fourth Circuit on February 13, 2009 reversed, vacated and
remanded Judge Chambers’ March 2007 and June 2007 decisions in their entirety,
ruling that the ACOE properly exercised its discretion in the permit review and
approval process. The appellees have not publicly stated their intentions with
respect to further appeals.
A similar challenge to the ACOE
Section 404 permit process was launched by environmental groups in
Kentucky in December 2007 when a lawsuit was
filed in federal court against the ACOE alleging that it wrongfully issued a
Section 404 authorization for the expansion of ICG Hazard’s Thunder Ridge
surface mine. That permit was suspended on December 26, 2007 to allow the
ACOE to review the documentation on which the permit decision was based.
Subsequently, the AOCE requested supplemental information from ICG Hazard, which
has been provided. All court proceedings are on hold in this case while the ACOE
considers its decision. The Company currently has two subsidiaries in that
jurisdiction of Kentucky that will require Section 404
permits within the next two years. If permitting requirements are substantially
increased or if mining methods at issue are limited or prohibited, it could
greatly lengthen the time needed to permit new reserves, significantly increase
our operational costs, make it more difficult to economically recover a
significant portion of our reserves and lead to a material adverse effect on our
financial condition and results of operation. We may not be able to increase the
price we charge for coal to cover higher production costs without reducing
customer demand for our coal. See “Legal Proceedings” contained in
Item 3 of this Annual Report on Form 10-K.
40
New government regulations as a result
of recent mining accidents are increasing our costs.
Both the federal and state governments
impose stringent health and safety standards on the mining industry. Regulations
are comprehensive and affect nearly every aspect of mining operations, including
training of mine personnel, mining procedures, blasting, the equipment used in
mining operations and other matters. As a result of past mining
accidents,additional federal and state health and safety regulations have been
adopted that have increased operating costs and affect our mining operations.
State and federal legislation has been adopted that, among other things,
requires additional oxygen supplies, communication and tracking devices, refuge
chambers, stronger seal construction and monitoring standards and mine rescue
teams. The legislation also raised the maximum civil penalty for certain
violations of federal mine safety regulations to $220,000 from $60,000. We
expect that new regulations or stricter enforcement of existing regulations will
increase our costs related to worker health and safety. Additionally, we could
be subject to civil penalties and other penalties if we violate mining
regulations.
Mining in Northern and Central Appalachia is more complex and involves more
regulatory constraints than mining in the other areas, which could affect
productivity and cost structures of these areas.
The geological characteristics of
Northern and Central Appalachian coal reserves, such as depth of overburden and
coal seam thickness, make them complex and costly to mine. As mines become
depleted, replacement reserves may not be available when required or, if
available, may not be capable of being mined at costs comparable to those
characteristic of the depleting mines. In addition, as compared to mines in the
Powder River Basin in northeastern Wyoming and southeastern Montana, permitting, licensing and other
environmental and regulatory requirements are more dynamic and thus more costly
and time-consuming to satisfy. These factors could materially adversely affect
the mining operations and cost structures of, and customers’ ability to use coal
produced by, our mines in Northern and Central Appalachia.
MSHA or other federal or state
regulatory agencies may order certain of our mines to be temporarily or
permanently closed, which could adversely affect our ability to meet our
customers’ demands.
MSHA or other federal or state
regulatory agencies may order certain of our mines to be temporarily or
permanently closed. Our customers may challenge our issuance of force majeure
notices in connection with such closures. If these challenges are successful, we
may have to purchase coal from third-party sources to satisfy those challenges,
incur capital expenditures to re-open the mines and negotiate settlements with
the customers, which may include price reductions, the reduction of commitments
or the extension of time for delivery, terminate customers’ contracts or face
claims initiated by our customers against us. The resolution of these challenges
could have an adverse impact on our financial position, results of operations or
cash flows.
We may be unable to obtain and renew
permits necessary for our operations, which would reduce our production, cash
flow and profitability.
Mining companies must obtain numerous
permits that impose strict regulations on various environmental and safety
matters in connection with coal mining. These include permits issued by various
federal and state agencies and regulatory bodies. The permitting rules are
complex and may change over time, making our ability to comply with the
applicable requirements more difficult or even impossible, thereby precluding
continuing or future mining operations. The public has certain rights to comment
upon and otherwise engage in the permitting process, including through court
intervention. Accordingly, the permits we need may not be issued, maintained or
renewed, or may not be issued or renewed in a timely fashion or may involve
requirements that restrict our ability to conduct our mining operations. An
inability to conduct our mining operations pursuant to applicable permits would
reduce our production, cash flows and profitability.
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If the assumptions underlying our
reclamation and mine closure obligations are materially inaccurate, we could be
required to expend greater amounts than anticipated.
The SMCRA establishes operational,
reclamation and closure standards for all aspects of surface mining, as well as
the surface effects of deep mining. Estimates of our total reclamation and
mine-closing liabilities are based upon permit requirements, engineering studies
and our engineering expertise related to these requirements. The estimate of
ultimate reclamation liability is reviewed periodically by our management and
engineers. The estimated liability can change significantly if actual costs vary
from assumptions or if governmental regulations change significantly. We adopted
SFAS No. 143, Accounting for
Asset Retirement Obligations (“SFAS No. 143”), effective
January 1, 2003. SFAS No. 143 requires that asset retirement
obligations be recorded as a liability based on fair value, which is calculated
as the present value of the estimated future cash flows. In estimating future
cash flows, we considered the estimated current cost of reclamation and applied
inflation rates and a third-party profit, as necessary. The third-party profit
is an estimate of the approximate markup that would be charged by contractors
for work performed on behalf of us. The resulting estimated reclamation and mine
closure obligations could change significantly if actual amounts change
significantly from our assumptions.
Our operations may substantially impact
the environment or cause exposure to hazardous materials, and our properties may
have significant environmental contamination, any of which could result in
material liabilities to us.
We use, and in the past have used,
hazardous materials and generate, and in the past have generated, hazardous
wastes. In addition, many of the locations that we own or operate were used for
coal mining and/or involved hazardous materials usage either before or after we
were involved with those locations. We may be subject to claims under federal
and state statutes and/or common law doctrines, for toxic torts, natural
resource damages and other damages, as well as the investigation and clean up of
soil, surface water, groundwater and other media. Such claims may arise, for
example, out of current or former activities at sites that we own or operate
currently, as well as at sites that we or predecessor entities owned or operated
in the past, and at contaminated sites that have always been owned or operated
by third parties. Our liability for such claims may be joint and several, so
that we may be held responsible for more than our share of the remediation costs
or other damages, or even for the entire share. We have from time to time been
subject to claims arising out of contamination at our own and other facilities
and may incur such liabilities in the future.
We use, and in the past have used,
alkaline CCBs during the reclamation process at
certain of our mines to aid in preventing the formation of acid mine drainage. Use
of CCBs on a mined area is subject to regulatory approval and is
allowed only after it is
proved to be a beneficial use. If in the future CCBs were to be
classified as a hazardous waste or if more stringent disposal requirements were
to be otherwise established for these wastes, we may be required to cease using
CCBs and find a replacement alkaline
material for this purpose, which may add to the cost of mine
reclamation.
We maintain extensive coal slurry
impoundments at a number of our mines. Such impoundments are subject to
regulation. Slurry impoundments maintained by other coal mining operations have
been known to fail, releasing large volumes of coal slurry. Structural failure
of an impoundment can result in extensive damage to the environment and natural
resources, such as bodies of water that the coal slurry reaches, as well as
liability for related personal injuries and property damages and injuries to
wildlife. Some of our impoundments overlie mined out areas, which can pose a
heightened risk of failure and of damages arising out of failure. We have
commenced measures to modify our method of operation at one surface impoundment
containing slurry wastes in order to reduce the risk of releases to the
environment from it, a process that will take several years to complete. If one
of our impoundments were to fail, we could be subject to substantial claims for
the resulting environmental contamination and associated liability, as well as
for fines and penalties.
These and other impacts that our
operations may have on the environment, as well as exposures to hazardous
substances or wastes associated with our operations and environmental conditions
at our properties, could result in costs and liabilities that would materially
and adversely affect us.
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Extensive environmental regulations
affect our customers and could reduce the demand for coal as a fuel source and
cause our sales to decline.
The Clean Air Act and similar state and
local laws extensively regulate the amount of sulfur dioxide, particulate
matter, nitrogen oxides and other compounds emitted into the air from coke ovens
and electric power plants, which are the largest end-users of our coal. Such
regulations will require significant emissions control expenditures for many
coal-fired power plants to comply with applicable ambient air quality standards.
As a result, these generators may switch to other fuels that generate less of
these emissions, possibly reducing future demand for coal and the construction
of coal-fired power plants.
The Federal Clean Air Act, including the
Clean Air Act Amendments of 1990, and corresponding state laws that regulate
emissions of materials into the air affect coal mining operations both directly
and indirectly. Measures intended to improve air quality that reduce coal’s
share of the capacity for power generation could diminish our revenues and harm
our business, financial condition and results of operations. The price of lower
sulfur coal may decrease as more coal-fired utility power plants install
additional pollution control equipment to comply with stricter sulfur dioxide
emission limits, which may reduce our revenues and harm our results. In
addition, regulatory initiatives including the nitrogen oxide rules, new ozone
and particulate matter standards, regional haze regulations, new source review,
regulation of mercury emissions and legislation or regulations that establish
restrictions on greenhouse gas emissions or provide for other multiple pollutant
reductions could make coal a less attractive fuel to our utility customers and
substantially reduce our sales.
Various new and proposed laws and
regulations may require further reductions in emissions from coal-fired
utilities. The EPA is reconsidering the March 2005 Clean Air Interstate Rule
pursuant to a court order which remanded, but did not vacate, that rule, which
further regulated sulfur dioxide and nitrogen oxides from coal-fired power
plants. Among other things, in affected states, the rule mandates reductions in
sulfur dioxide emissions by approximately 45% below 2003 levels by 2010, and by
approximately 57% below 2003 levels by 2015. The stringency of this cap may
require many coal-fired sources to install additional pollution control
equipment, such as wet scrubbers. The EPA has announced that it intends to
initiate a rulemaking to adopt technology-based standards for mercury emissions
form coal-fired power plants in response to a court order which vacated and
remanded its 2005 Clean Air Mercury Rule. The EPA has not determined how to
respond to the Court’s decision. In February 2008, the Court ruled that the
EPA’s 2005 Clean Air Mercury Rule violates the Clean Air Act and gave the
agency two years to develop
mercury emissions standards. Some states, including Georgia and North
Carolina, are adopting or proposing to adopt more stringent restrictions on
mercury emissions than those contained in the remanded Clean Air Mercury Rule.
These and other future standards could have the effect of making the operation
of coal-fired plants less profitable, thereby decreasing demand for coal. The
majority of our coal supply agreements contain provisions that allow a purchaser
to terminate its contract if legislation is passed that either restricts the use
or type of coal permissible at the purchaser’s plant or results in specified
increases in the cost of coal or its use.
There have been several recent proposals
in Congress that are designed to further reduce emissions of sulfur dioxide,
nitrogen oxides and mercury from power plants, and certain ones could regulate
additional air pollutants. If such initiatives are enacted into law, power plant
operators could choose fuel sources other than coal to meet their requirements,
thereby reducing the demand for coal.
A regional haze program initiated by the
EPA to protect and to improve visibility at and around national parks, national
wilderness areas and international parks restricts the construction of new
coal-fired power plants whose operation may impair visibility at and around
federally protected areas, and may require some existing coal-fired power plants
to install additional control measures designed to limit haze-causing
emissions.
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New and pending laws regulating the
environmental effects of emissions of greenhouse gases could impose significant
additional costs to doing business for the coal industry and/or a shift in
consumption to non-fossil fuels.
Greenhouse gas emissions have
increasingly become the subject of a large amount of international, national,
state and local attention. Although the United States did not join the 1992 Framework
Convention on Global Climate Change, commonly known as the Kyoto Protocol,
future regulation of greenhouse gas could occur either pursuant to future
U.S. treaty obligations or pursuant to
statutory or regulatory changes under the Clean Air Act. Increased efforts to
control greenhouse gas emissions, including the future joining of the Kyoto
Protocol, could result in reduced demand for coal if electric power generators
switch to lower carbon sources of fuel. If the United States were to ratify the Kyoto Protocol, the
United States would be required to reduce greenhouse
gas emissions to 93% of 1990 levels in a series of phased reductions from 2008
to 2012.
Coal-fired power plants can generate
large amounts of carbon emissions, and, as a result, have become subject to
challenge, including the opposition to any new coal-fired power plants or
capacity expansions of existing plants, by environmental groups seeking to curb
the environmental effects of emissions of greenhouse gases. Various legislation
has been and will continue to be introduced in Congress which reflects a wide
variety of strategies for reducing greenhouse gas emissions in the United States. These strategies include mandating
decreases in carbon dioxide emissions from coal-fired power plants, instituting
a carbon tax on emissions of carbon dioxide, banning the construction of new
coal-fired power plants that are not equipped with technology to capture and
sequester carbon dioxide, encouraging the growth of renewable energy sources
(such as wind or solar power) or nuclear for electricity production, financing
the development of advanced coal burning plants which have greatly reduced
carbon dioxide emissions. Most states in the United States have taken steps to regulate greenhouse
gas emissions. In addition, in Massachusetts v. Environmental Protection Agency, a
U.S. Supreme Court decision in April 2007, the U.S. Supreme Court ruled in favor
of twelve states and several cities of the United States against the EPA, and held that carbon
dioxide and other greenhouse gases can qualify as pollutants under the Clean Air
Act. As a result, the EPA may issue regulations related to greenhouse gas
emissions.
Passage of additional state or federal
laws or regulations regarding greenhouse gas emissions or other actions to limit
carbon dioxide emissions could result in fuel switching, from coal to other fuel
sources, by electric generators. Such laws and regulations could, for example,
include mandating decreases in carbon dioxide emissions from coal-fired power
plants, imposing taxes on carbon emissions, requiring certain technology to
capture and sequester carbon dioxide from new coal-fired power plants and
encouraging the production of non-coal-fired power plants. Political and
regulatory uncertainty over future emissions controls have been cited as major
factors in decisions by power companies to postpone new coal-fired power plants.
If measures such as these or other similar measures, like controls on methane
emissions from coal mines, are ultimately imposed by federal or state
governments or pursuant to international treaty on the coal industry, our
operating costs may be materially and adversely affected. Similarly, alternative
fuels (non fossil-fuels) could become more attractive than coal in order to
reduce carbon emissions, which could result in a reduction in the demand for
coal and, therefore, our revenues.
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Risks Relating To Our Common
Stock
Our leverage may harm our financial
condition and results of operations.
Our total consolidated long-term debt as
of December 31, 2008 was approximately $434.9 million and represented
approximately 47% of our total capitalization, excluding current indebtedness of
approximately $20.1 million, as of that date.
Our level of indebtedness could have
important consequences on our future operations, including:
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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;
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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;
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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;
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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;
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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
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placing us at a competitive
disadvantage compared to our competitors that have less debt or are less
leveraged.
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If new debt is added
to our and our subsidiaries’ current debt levels, the related risks that we and
they now face could intensify. In addition to the principal repayments on our
outstanding debt, we have other demands on our cash resources, including, among
others, capital expenditures and operating expenses.
Our ability to pay principal and
interest on and to refinance our debt depends upon the operating performance of
our subsidiaries, which will be affected by, among other things, general
economic, financial, competitive, legislative, regulatory and other factors,
some of which are beyond our control. In particular, economic conditions could
cause the price of coal to fall, our revenue to decline and hamper our ability
to repay our indebtedness, including our outstanding senior and convertible
notes.
Our business may not generate sufficient
cash flow from operations and future borrowings may not be available to us under
our senior credit facility or otherwise in an amount sufficient to enable us to
pay our indebtedness including anticipated interest on the notes, or to fund our
other liquidity needs. We may need to refinance all or a portion of our
indebtedness on or before maturity. We may not be able to refinance any of our
indebtedness on commercially reasonable terms, on terms acceptable to us or at
all.
Our ability and the ability of some of
our subsidiaries to engage in some business transactions or to pursue our
business strategy may be limited by the terms of our existing
debt.
Our credit facility contains a number of
financial covenants requiring us to meet financial ratios and financial
condition tests. The indenture governing our outstanding senior notes and our
senior credit facility also restrict our and our subsidiaries’ ability
to:
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incur additional debt or issue
guarantees;
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pay dividends on, redeem or
repurchase capital stock;
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make certain
investments;
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make
acquisitions;
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incur, or permit to exist,
liens;
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enter into transactions with
affiliates;
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guarantee the debt of other
entities, including joint ventures;
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merge or consolidate or otherwise
combine with another company; and
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transfer or sell a material amount
of our assets outside the ordinary course of
business.
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These covenants could adversely affect
our ability to finance our future operations or capital needs or to execute
preferred business strategies.
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Our ability to borrow under our credit
facility will depend upon our ability to comply with these covenants and our
borrowing base requirements. Our ability to meet these covenants and
requirements may be affected by events beyond our control and we may not meet
these obligations. From time to time, we have amended or revised our financial
covenants, and have also received waivers of covenant compliance under our
senior credit facility. However, we may not continue to receive waivers from our
lenders or be permitted to amend the financial covenants. Our failure to comply
with these covenants and requirements could result in an event of default under
the indenture governing our outstanding senior notes that, if not cured or
waived, could permit acceleration of our outstanding convertible and senior
notes and permit foreclosure on any collateral granted as security under our
senior credit facility. If our indebtedness is accelerated, we may not be able
to repay the notes or borrow sufficient funds to refinance the notes. Even if we
were able to obtain new financing, it may not be on commercially reasonable
terms, on terms that are acceptable to us, or at all. If our debt is in default
for any reason, our business, financial condition and results of operations
could be materially and adversely affected.
We are subject to limitations on capital
expenditures under our senior credit facility. Because of these limitations, we
may not be able to pursue our business strategy to replace our equipment fleet
as it ages, develop additional mines or pursue additional acquisitions without
additional financing.
We may not be able to repurchase our
Convertible Senior Notes if noteholders convert prior to
maturity.
Upon the occurrence of specific events,
our Convertible Senior Notes may become convertible, requiring us to settle in
cash the principal amount of the note, and any excess conversion value may be
settled in cash or in shares of our common stock, at our option, as provided by
the terms of the indenture governing the Convertible Senior Notes. The
Convertible Senior Notes are convertible at an initial conversion price, subject
to adjustment, of $6.10 per share (approximately 163.8136 shares per $1,000
principal amount of the Convertible Senior Notes). If we elect to settle any
excess conversion value of the Convertible Senior Notes in cash, the holder will
receive, for each $1,000 principal amount, the conversion rate multiplied by a
20-day average closing price of the common stock as set forth in the indenture
beginning on the third trading day after the Convertible Senior Notes are
surrendered. We have $225.0 million of principal amount of Convertible Senior
Notes outstanding. In the event that a holder elects to convert its Convertible
Senior Note, we would need to seek a waiver or amendment from our lenders to
fund any cash settlement of any such conversion from working capital and/or
borrowings under our amended credit facility in excess of $25.0 million per
year. There is no assurance we will have sufficient cash on hand or available to
fund the $225.0 million or that we would receive a waiver or amendment,
especially in light of the current credit environment. In addition, if a
significant number of noteholders were to convert their notes prior to maturity,
we may not have enough available funds at any particular time to make the
required repayments. Our failure to repurchase converted notes at a time when
noteholders have the right to convert would constitute a default under the
indenture. This default would, in turn, constitute an event of default under our
amended and restated credit facility and could constitute an event of default
under our Senior Notes, any of which could cause repayment of the related debt
to be accelerated after any applicable notice or grace periods. If debt
repayment were to be accelerated, we may not have sufficient funds to repurchase
the Convertible Senior Notes or repay the debt. Alternatively, upon conversion,
we may issue additional stock to satisfy the payment obligation related to any
excess conversion value which could lead to immediate and potentially
substantial dilution in net tangible book value per share.
Changes in the accounting treatment of
certain of our existing securities could decrease our earnings per
share.
There may be, in the future, potentially
new or different accounting pronouncements or regulatory rulings, which could
impact the way we are required to account for our securities, and which may have
an adverse impact on our future financial condition and results of operations.
With respect to our convertible notes, we are required under accounting
principles generally accepted in the United States of America (“GAAP”) as
presently in effect to include in outstanding shares for purposes of computing
diluted earnings per share only a number of shares underlying the notes that, at
the end of a given quarter, have a value in excess of the outstanding principal
amount of the notes. This is because of the “net share settlement” feature of
the notes, under which we are required to pay the principal amount of the notes
in cash. The accounting method for net share settled convertible securities was
recently considered by the FASB, which issued FASB Staff Position (“FSP”)
APB 14-1, Accounting for
Convertible Debt Instruments That May be Settled in Cash Upon Conversion
(Including Partial Cash Settlement) (“FSP APB 14-1”). FSP APB 14-1, which
is effective for financial statements for fiscal years beginning after December
15, 2008, and interim periods within those fiscal years, requires that net share settled
convertible securities under which the debt and equity components of the security be bifurcated and
accounted for separately. Adoption of FSP APB 14-1 will result in us recognizing
additional interest expense.
The conditional conversion feature of
the notes could result in a holder receiving less than the value of the common
stock into which a note would otherwise be convertible.
At certain times, the notes are
convertible into cash and, if applicable, shares of our common stock only if
specified conditions are met. If these conditions are not met, a holder will not
be able to convert the notes at that time, and, upon a later conversion, a
holder may not be able to receive the value of the common stock into which the
convertible notes would otherwise have been convertible had such conditions been
met.
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.
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Provisions of our debt could discourage
an acquisition of us by a third-party.
Certain provisions of our debt could
make it more difficult or more expensive for a third-party to acquire us. Upon
the occurrence of certain transactions constituting a fundamental change,
holders of both series of notes will have the right, at their option, to require
us to repurchase, at a cash repurchase price equal to 100% of the principal
amount plus accrued and unpaid interest on the notes, all of their notes or any
portion of the principal amount of such notes in integral multiples of $1,000.
We may also be required to issue additional shares of our common stock upon
conversion of such notes in the event of certain fundamental
changes.
Anti-takeover provisions in our charter
documents and Delaware corporate law may make it difficult for
our stockholders to replace or remove our current board of directors and could
deter or delay third parties from acquiring us, which may adversely affect the
marketability and market price of our common stock.
Provisions in our amended and restated
certificate of incorporation and bylaws and in Delaware corporate law may make it difficult for
stockholders to change the composition of our board of directors in any one
year, and thus prevent them from changing the composition of management. In
addition, the same provisions may make it difficult and expensive for a
third-party to pursue a tender offer, change in control or takeover attempt that
is opposed by our management and board of directors. Public stockholders who
might desire to participate in this type of transaction may not have an
opportunity to do so. These anti-takeover provisions could substantially impede
the ability of public stockholders to benefit from a change in control or change
our management and board of directors and, as a result, may adversely affect the
marketability and market price of our common stock.
We are also subject to the anti-takeover
provisions of Section 203 of the Delaware General Corporation Law. Under
these provisions, if anyone becomes an “interested stockholder,” we may not
enter into a “business combination” with that person for three years without
special approval, which could discourage a third-party from making a takeover
offer and could delay or prevent a change of control. For purposes of
Section 203, “interested stockholder” means, generally, someone owning more
than 15% or more of our outstanding voting stock or an affiliate of ours that
owned 15% or more of our outstanding voting stock during the past three years,
subject to certain exceptions as described in
Section 203.
Under any change of control, the lenders
under our credit facilities would have the right to require us to repay all of
our outstanding obligations under the facility.
There may be circumstances in which the
interests of our major stockholders could be in conflict with the interests of a
stockholder or noteholder.
As of December 31, 2008, funds sponsored
by WLR own approximately 16% of our common stock. Circumstances may occur in
which WLR or other major investors may have an interest in pursuing
acquisitions, divestitures or other transactions, including among other things,
taking advantage of certain corporate opportunities that, in their judgment,
could enhance their investment in us or another company in which they invest.
These transactions might invoke risks to our other holders of common stock or
adversely affect us or other investors.
We may from time to time engage in
transactions with related parties and affiliates that include, among other
things, business arrangements, lease arrangements for certain coal reserves and
the payment of fees or commissions for the transfer of coal reserves by one
operating company to another. These transactions, if any, may adversely effect
our sales volumes, margins and earnings.
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If
we do not meet the New York Stock Exchange continued listing requirements,
our common stock may be delisted, and we may be required to repurchase or
refinance our 9.00% Convertible Senior Notes Due
2012.
In
order to maintain our listing on the New York Stock Exchange (“NYSE”), we must
continue to meet the NYSE minimum share price listing rule, the minimum market
capitalization rule and other continued listing criteria. If our common stock
were delisted, it could (i) reduce the liquidity and market price of our
common stock; (ii) negatively impact our ability to raise equity financing
and access the public capital markets; and (iii) materially adversely
impact our results of operations and financial condition. In addition, if our
common stock is not listed on the NYSE or another national exchange, holders of
our 9.00% senior convertible notes due 2012 will be entitled to require us to
repurchase their convertible notes. Our credit facility and senior notes provide
that the occurrence of this repurchase right constitutes a default pursuant to
their respective agreements.
If our stockholders sell substantial
amounts of our common stock, the market price of our common stock may
decline.
As of December 31, 2008, we had
153,322,245 shares of common stock outstanding. The number of shares of common
stock available for resale in the public market is limited in certain
circumstances by restrictions under federal securities. All of the shares sold in our public offering, as
well as all of the shares issued by us in the corporate reorganization, are
freely tradable without restrictions or further registration under the
Securities Act of 1933, as amended, except for any shares held by our
affiliates, as defined in Rule 144 of the Securities Act. Additional shares of
common stock underlying options granted or to be granted will become available
for sale in the public market. We have also filed a registration statement on
Form S-8 that registered 8,525,302 shares of common stock covering shares of
restricted stock granted to our executives and the shares of common stock to be
issued pursuant to the exercise of options we have granted or will grant under
our employee stock option plan and a certain employment agreement. Our stock
price could drop significantly if the holders of these restricted shares sell
them or the market perceives they intend to sell them. These sales may also make
it more difficult for us to sell securities in the future at a time and at a
price we deem appropriate.
We may not pay dividends for the
foreseeable future.
We may retain any future earnings to
support the development and expansion of our business or make additional
payments under our credit facilities and, as a result, we may not pay cash
dividends in the foreseeable future. Our payment of any future dividends will be
at the discretion of our board of directors after taking into account various
factors, including our financial condition, operating results, cash needs,
growth plans and the terms of any credit agreements that we may be a party to at
the time. Our credit facilities limit us from paying cash dividends or other
payments or distributions with respect to our capital stock in excess of certain
limitations. In addition, the terms of any future credit agreement may contain
similar restrictions on our ability to pay any dividends or make any
distributions or payments with respect to our capital stock. Accordingly,
investors must rely on sales of their common stock after price appreciation,
which may never occur, as the only way to realize their
investment.
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UNRESOLVED STAFF
COMMENTS
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None.
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Coal Reserves
“Reserves” are defined by SEC Industry
Guide 7 as that part of a mineral deposit which could be economically and
legally extracted or produced at the time of the reserve determination. “Proven
(Measured) Reserves” are defined by SEC Industry Guide 7 as reserves for which
(1) quantity is computed from dimensions revealed in outcrops, trenches,
workings or drill holes; grade and/or quality are computed from the results of
detailed sampling and (2) the sites for inspection, sampling and
measurement are spaced so closely and the geologic character is so well defined
that size, shape, depth and mineral content of reserves are well-established.
“Probable reserves” are defined by SEC Industry Guide 7 as reserves for which
quantity and grade and/or quality are computed from information similar to that
used for proven (measured) reserves, but the sites for inspection, sampling and
measurement are farther apart or are otherwise less adequately spaced. The
degree of assurance, although lower than that for proven (measured) reserves, is
high enough to assume continuity between points of
observation.
We estimate that there are approximately
291 million tons of coal reserves that can be developed by our existing
operations, which will allow us to maintain current production levels for an
extended period of time. ICG Natural Resources and CoalQuest own and lease all
of our reserves that are not currently assigned to, or associated with, one of
our mining operations. These reserves contain approximately 726 million tons of
mid to high Btu, low and high sulfur coal located in Kentucky, West Virginia, Maryland, Illinois and Virginia. Our multi-region base and flexible
product line allows us to adjust to changing market conditions and sustain high
sales volume by supplying a wide range of customers.
49
Our total coal reserves could support
current production levels for more than 58 years. The following table provides
the location of our mining operations and the type of coal produced at those
operations as of January 1, 2009:
|
|
Assigned or
Unassigned
(1)
|
|
Operating (O) or
Development
(D)
|
|
State
|
|
Mining
Method
Surface
(S)
or
Underground
(UG)
|
|
Total
Proven
and
Probable
Reserves
(2)
|
|
Owned
Proven
and
Probable
Reserves
|
|
Leased
Proven
and
Probable
Reserves
|
|
Steam
Proven
and
Probable
Reserves
|
|
Metallurgical(3)(4)
Proven
and
Probable
Reserves
|
|
|
|
|
|
|
|
|
|
|
(in
million tons)
|
Northern
Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vindex Energy
Corp.
|
|
Assigned
|
|
O
|
|
MD
|
|
S
|
|
7.27
|
|
0.00
|
|
7.27
|
|
7.27
|
|
0.00
|
|
|
Unassigned
|
|
D
|
|
MD
|
|
S/UG
|
|
52.83
|
|
0.35
|
|
52.48
|
|
32.58
|
|
20.25
|
Total Vindex Energy
Corp.
|
|
|
|
|
|
|
|
|
|
60.10
|
|
0.35
|
|
59.75
|
|
39.85
|
|
20.25
|
Patriot Mining
Co.
|
|
Assigned
|
|
O
|
|
WV
|
|
S
|
|
6.18
|
|
0.05
|
|
6.13
|
|
6.18
|
|
0.00
|
|
|
Unassigned
|
|
D
|
|
WV
|
|
S
|
|
0.00
|
|
0.00
|
|
0.00
|
|
0.00
|
|
0.00
|
Total Patriot Mining
Co.
|
|
|
|
|
|
|
|
|
|
6.18
|
|
0.05
|
|
6.13
|
|
6.18
|
|
0.00
|
Wolf Run Mining Buckhannon
Division
|
|
Assigned
|
|
O
|
|
WV
|
|
UG
|
|
28.50
|
|
13.16
|
|
15.34
|
|
14.86
|
|
13.64
|
|
|
Unassigned
|
|
D
|
|
WV
|
|
UG
|
|
30.55
|
|
28.81
|
|
1.74
|
|
0.00
|
|
30.55
|
Total Wolf Run Mining Buckhannon
Division
|
|
|
|
|
|
|
|
|
|
59.05
|
|
41.97
|
|
17.08
|
|
14.86
|
|
44.19
|
Sentinel
|
|
Assigned
|
|
O
|
|
WV
|
|
UG
|
|
47.33
|
|
30.41
|
|
16.92
|
|
0.00
|
|
47.33
|
|
|
Unassigned
|
|
D
|
|
WV
|
|
UG
|
|
4.94
|
|
4.94
|
|
0.00
|
|
0.00
|
|
4.94
|
Total
Sentinel
|
|
|
|
|
|
|
|
|
|
52.27
|
|
35.35
|
|
16.92
|
|
0.00
|
|
52.27
|
CoalQuest Development
LLC
|
|
Unassigned
|
|
D
|
|
WV
|
|
UG
|
|
186.09
|
|
186.09
|
|
0.00
|
|
32.71
|
|
153.38
|
|
|
(Hillman)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Appalachia Total
|
|
|
|
|
|
|
|
|
|
363.69
|
|
263.81
|
|
99.88
|
|
93.60
|
|
270.09
|
Central
Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eastern
|
|
Assigned
|
|
O
|
|
WV
|
|
S
|
|
4.95
|
|
3.15
|
|
1.80
|
|
4.95
|
|
0.00
|
|
|
Unassigned
|
|
D
|
|
WV
|
|
S
|
|
6.70
|
|
0.00
|
|
6.70
|
|
6.70
|
|
0.00
|
Total
Eastern
|
|
|
|
|
|
|
|
|
|
11.65
|
|
3.15
|
|
8.50
|
|
11.65
|
|
0.00
|
Hazard
|
|
Assigned
|
|
O
|
|
KY
|
|
S
|
|
61.94
|
|
26.12
|
|
35.82
|
|
61.94
|
|
0.00
|
|
|
Unassigned
|
|
D
|
|
KY
|
|
S
|
|
0.00
|
|
0.00
|
|
0.00
|
|
0.00
|
|
0.00
|
Total
Hazard
|
|
|
|
|
|
|
|
|
|
61.94
|
|
26.12
|
|
35.82
|
|
61.94
|
|
0.00
|
Flint Ridge
|
|
Assigned
|
|
O
|
|
KY
|
|
UG
|
|
24.18
|
|
0.63
|
|
23.55
|
|
24.18
|
|
0.00
|
Knott County
|
|
Assigned
|
|
O
|
|
KY
|
|
UG
|
|
3.42
|
|
2.93
|
|
0.49
|
|
3.42
|
|
0.00
|
|
|
Unassigned
|
|
D
|
|
KY
|
|
UG
|
|
11.78
|
|
0.93
|
|
10.85
|
|
11.78
|
|
0.00
|
Total Knott County
|
|
|
|
|
|
|
|
|
|
15.20
|
|
3.86
|
|
11.34
|
|
15.20
|
|
0.00
|
Raven
|
|
Assigned
|
|
O
|
|
KY
|
|
UG
|
|
10.03
|
|
0.00
|
|
10.03
|
|
10.03
|
|
0.00
|
|
|
Unassigned
|
|
D
|
|
KY
|
|
UG
|
|
2.20
|
|
0.00
|
|
2.20
|
|
2.20
|
|
0.00
|
Total Raven
|
|
|
|
|
|
|
|
|
|
12.23
|
|
0.00
|
|
12.23
|
|
12.23
|
|
0.00
|
East
Kentucky
|
|
Assigned
|
|
O
|
|
KY
|
|
S
|
|
2.94
|
|
2.39
|
|
0.55
|
|
2.94
|
|
0.00
|
ICG Natural
Resources
|
|
Assigned
|
|
D
|
|
WV
|
|
S
|
|
14.70
|
|
0.00
|
|
14.70
|
|
14.70
|
|
0.00
|
|
|
Unassigned
|
|
D
|
|
WV
|
|
UG
|
|
30.20
|
|
2.21
|
|
27.99
|
|
30.20
|
|
0.00
|
|
|
(Jennie Creek)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total ICG Natural
Resources
|
|
|
|
|
|
|
|
|
|
44.90
|
|
2.21
|
|
42.69
|
|
44.90
|
|
0.00
|
Powell Mountain
|
|
Assigned
|
|
O
|
|
VA
|
|
UG
|
|
5.05
|
|
0.00
|
|
5.05
|
|
5.05
|
|
0.00
|
|
|
Unassigned
|
|
D
|
|
VA
|
|
S/UG
|
|
22.02
|
|
0.00
|
|
22.02
|
|
22.02
|
|
0.00
|
Total Powell Mountain
|
|
|
|
|
|
|
|
|
|
27.07
|
|
0.00
|
|
27.07
|
|
27.07
|
|
0.00
|
Beckley
|
|
Assigned
|
|
O
|
|
WV
|
|
UG
|
|
32.03
|
|
1.28
|
|
30.75
|
|
0.00
|
|
32.03
|
White Wolf Energy,
Inc.
|
|
Unassigned
|
|
D
|
|
VA
|
|
UG
|
|
25.91
|
|
0.00
|
|
25.91
|
|
0.00
|
|
25.91
|
|
|
(Big Creek)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central Appalachia Total
|
|
|
|
|
|
|
|
|
|
258.05
|
|
39.64
|
|
218.41
|
|
200.11
|
|
57.94
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois
|
|
Assigned
|
|
O
|
|
IL
|
|
UG
|
|
42.58
|
|
8.93
|
|
33.65
|
|
42.58
|
|
0.00
|
|
|
(Viper)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ICG Natural
Resources
|
|
Unassigned
|
|
D
|
|
IL
|
|
UG
|
|
352.88
|
|
352.88
|
|
0.00
|
|
352.88
|
|
0.00
|
Total Other
|
|
|
|
|
|
|
|
|
|
395.46
|
|
361.81
|
|
33.65
|
|
395.46
|
|
0.00
|
Total Proven and Probable Reserves
|
|
|
|
|
|
|
|
|
|
1,017.20
|
|
665.26
|
|
351.94
|
|
689.17
|
|
328.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
“Assigned reserves” means coal
which has been committed by the coal company to operating mine shafts,
mining equipment and plant facilities, and all coal which has been leased
by the coal company to others. “Unassigned reserves” represent coal which
has not been committed, and which would require new mineshafts, mining
equipment or plant facilities before operations could begin in the
property. The primary reason for this distinction is to inform investors
which coal reserves will require substantial capital investment before
production can begin.
|
(2)
|
The proven and probable reserves
are reported as recoverable reserves, which is that part of a coal deposit
which could be economically and legally extracted or produced at the time
of the reserve determination, taking into account mining recovery and
preparation plant yield.
|
(3)
|
Beckley and White Wolf Energy, Inc. meet
historical metallurgical coal quality
specifications.
|
|
(4)
|
We sold coal with ash and sulfur
contents as high as 10% and 1.5%, respectively, into the metallurgical
market from Vindex Energy, Buckhannon and Sentinel in 2008. Similarly, we
believe all production from Vindex Energy and portions of Hillman
could be sold on this metallurgical market when production
begins.
|
50
The following table provides the
“quality” (average moisture, ash and sulfur contents and Btu per pound) of our
coal reserves as of January 1, 2009:
|
|
|
|
As Received
Quality
|
|
Total
Reserves
|
|
|
Assigned or
Unassigned
(1)
|
|
%
Moisture
|
|
%
Ash
|
|
%
Sulfur
|
|
Btu/lb.
|
|
Lbs. SO2/
million Btu’s
|
|
<1.2 lbs.
SO2
Compliance
|
|
>1.2 lbs
SO2
Non-Compliance
|
Northern
Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vindex Energy Corp.(3)
|
|
Assigned
|
|
4.66
|
|
19.27
|
|
1.80
|
|
11,702
|
|
3.07
|
|
0.00
|
|
7.27
|
|
|
Unassigned
|
|
6.00
|
|
13.10
|
|
1.75
|
|
12,613
|
|
2.78
|
|
0.00
|
|
52.83
|
Total Vindex Energy
Corp.
|
|
|
|
5.84
|
|
13.85
|
|
1.76
|
|
12,503
|
|
2.81
|
|
0.00
|
|
60.10
|
Patriot Mining
Co.
|
|
Assigned
|
|
6.00
|
|
14.96
|
|
2.67
|
|
11,830
|
|
4.52
|
|
0.00
|
|
6.18
|
|
|
Unassigned
|
|
6.00
|
|
19.06
|
|
2.13
|
|
11,240
|
|
3.79
|
|
0.00
|
|
0.00
|
Total
Patriot Mining Co.
|
|
|
|
6.00
|
|
14.96
|
|
2.67
|
|
11,830
|
|
4.52
|
|
0.00
|
|
6.18
|
Wolf Run Mining Buckhannon
Division(3)
|
|
Assigned
|
|
6.00
|
|
8.07
|
|
2.21
|
|
13,070
|
|
3.39
|
|
0.00
|
|
28.50
|
|
|
Unassigned
|
|
6.00
|
|
8.92
|
|
0.99
|
|
13,069
|
|
1.52
|
|
0.00
|
|
30.55
|
Total Wolf Run Mining Buckhannon Division
|
|
|
|
6.00
|
|
8.51
|
|
1.58
|
|
13,069
|
|
2.42
|
|
0.00
|
|
59.05
|
Sentinel(3)
|
|
Assigned
|
|
6.00
|
|
8.38
|
|
1.48
|
|
13,184
|
|
2.25
|
|
0.00
|
|
47.33
|
|
|
Unassigned
|
|
6.00
|
|
8.04
|
|
1.44
|
|
13,353
|
|
2.15
|
|
0.00
|
|
4.94
|
Total
Sentinel
|
|
|
|
6.00
|
|
8.35
|
|
1.48
|
|
13,200
|
|
2.24
|
|
0.00
|
|
52.27
|
CoalQuest Development
LLC(3)
|
|
Unassigned
|
|
6.00
|
|
9.25
|
|
1.15
|
|
13,145
|
|
1.76
|
|
0.00
|
|
186.09
|
|
|
(Hillman)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Appalachia Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.00
|
|
363.69
|
Central
Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eastern
|
|
Assigned
|
|
6.00
|
|
14.42
|
|
1.24
|
|
11,964
|
|
2.07
|
|
0.00
|
|
4.95
|
|
|
Unassigned
|
|
6.00
|
|
14.42
|
|
1.24
|
|
11,964
|
|
2.07
|
|
0.00
|
|
6.70
|
Total
Eastern
|
|
|
|
6.00
|
|
14.42
|
|
1.24
|
|
11,964
|
|
2.07
|
|
0.00
|
|
11.65
|
Hazard
|
|
Assigned
|
|
6.00
|
|
12.59
|
|
1.38
|
|
12,070
|
|
2.28
|
|
0.00
|
|
61.94
|
Flint Ridge
|
|
Assigned
|
|
6.00
|
|
8.15
|
|
1.39
|
|
12,768
|
|
2.17
|
|
1.36
|
|
22.82
|
Knott County
|
|
Assigned
|
|
6.09
|
|
8.73
|
|
1.78
|
|
12,799
|
|
2.78
|
|
0.31
|
|
3.11
|
|
|
Unassigned
|
|
6.00
|
|
6.90
|
|
1.58
|
|
13,051
|
|
2.42
|
|
0.00
|
|
11.78
|
Total Knott County
|
|
|
|
6.02
|
|
7.31
|
|
1.62
|
|
12,994
|
|
2.50
|
|
0.31
|
|
14.89
|
Raven
|
|
Assigned
|
|
6.00
|
|
8.00
|
|
1.18
|
|
12,787
|
|
1.85
|
|
0.00
|
|
10.03
|
|
|
Unassigned
|
|
6.00
|
|
4.10
|
|
2.07
|
|
13,477
|
|
3.07
|
|
0.00
|
|
2.20
|
Total Raven
|
|
|
|
6.00
|
|
7.30
|
|
1.34
|
|
12,911
|
|
2.08
|
|
0.00
|
|
12.23
|
East
Kentucky
|
|
Assigned
|
|
5.88
|
|
9.37
|
|
0.87
|
|
12,450
|
|
1.40
|
|
0.00
|
|
2.94
|
ICG Natural
Resources
|
|
Assigned
|
|
7.00
|
|
9.65
|
|
0.75
|
|
12,281
|
|
1.22
|
|
9.59
|
|
5.11
|
|
|
Unassigned
|
|
7.00
|
|
4.92
|
|
1.27
|
|
13,254
|
|
1.92
|
|
0.00
|
|
30.20
|
|
|
(Jennie Creek)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total ICG Natural
Resources
|
|
|
|
7.00
|
|
6.47
|
|
1.10
|
|
12,935
|
|
1.70
|
|
9.59
|
|
35.31
|
Powell Mountain
|
|
Assigned
|
|
6.00
|
|
3.92
|
|
0.62
|
|
14,428
|
|
0.86
|
|
5.05
|
|
0.00
|
|
|
Unassigned
|
|
6.00
|
|
8.38
|
|
2.01
|
|
13,194
|
|
3.04
|
|
6.46
|
|
15.56
|
Total Powell Mountain
|
|
|
|
6.00
|
|
6.81
|
|
1.75
|
|
13,476
|
|
2.60
|
|
11.51
|
|
15.56
|
Beckley(2)
|
|
Assigned
|
|
6.00
|
|
4.87
|
|
0.70
|
|
13,913
|
|
1.01
|
|
32.03
|
|
0.00
|
|
|
(Beckley )
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
White Wolf Energy,
Inc.(2)
|
|
Unassigned
|
|
6.00
|
|
4.09
|
|
0.63
|
|
14,150
|
|
0.89
|
|
25.91
|
|
0.00
|
|
|
(Big Creek
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central Appalachia Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80.71
|
|
177.34
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois
|
|
Assigned
(Viper)
|
|
16.00
|
|
8.80
|
|
2.86
|
|
10,692
|
|
5.35
|
|
0.00
|
|
42.58
|
ICG Natural
Resources
|
|
Unassigned
|
|
12.53
|
|
9.32
|
|
2.93
|
|
10,986
|
|
5.33
|
|
0.00
|
|
352.88
|
Total Other
|
|
|
|
12.90
|
|
9.27
|
|
2.92
|
|
10,954
|
|
5.33
|
|
0.00
|
|
395.46
|
Total Proven and Probable
Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80.71
|
|
936.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
“Assigned reserves” means coal
which has been committed by the coal company to operating mine shafts,
mining equipment and plant facilities, and all coal which has been leased
by the coal company to others. “Unassigned reserves” represent coal which
has not been committed, and which would require new mine shafts, mining
equipment or plant facilities before operations could begin in the
property. The primary reason for this distinction is to inform investors
which coal reserves will require substantial capital investment before
production can begin.
|
(2)
|
Beckley and White Wolf Energy, Inc. meet
historical metallurgical coal quality
specifications.
|
(3)
|
We sold coal with ash and sulfur
contents as high as 10% and 1.5%, respectively, into the metallurgical
market from Vindex Energy, Buckhannon and Sentinel in 2008. Similarly, we
believe all production from Vindex Energy and portions of Hillman
could be sold on this metallurgical market when production
begins.
|
51
Our reserve estimate is based on
geological data assembled and analyzed by our staff of geologists and engineers.
Reserve estimates are periodically updated to reflect past coal production, new
drilling information and other geologic or mining data. Acquisitions, sales or
dispositions of coal properties will also change the reserves. We estimate that
we controlled 1,017 million tons of reserves at December 31, 2008. Changes in
mining methods may increase or decrease the recovery basis for a coal seam, as
will plant processing efficiency tests. We maintain reserve information in
secure computerized databases, as well as in hard copy. The ability to update
and/or modify the reserves is restricted to a few individuals and the
modifications are documented.
Actual reserves may vary substantially
from the estimates. Estimated minimum recoverable reserves are comprised of coal
that is considered to be merchantable and economically recoverable by using
mining practices and techniques prevalent in the coal industry at the time of
the reserve study, based upon then-current prevailing market prices for coal. We
use the mining method that we believe will be most profitable with respect to
particular reserves. We believe the volume of our current reserves exceeds the
volume of our contractual delivery requirements. Although the reserves shown in
the table above include a variety of qualities of coal, we presently blend coal
of different qualities to meet contract specifications. See “Risk Factors—Risks
Relating To Our Business.”
We currently own approximately 65% of
our coal reserves, with the remainder of our coal reserves subject to leases
from third-party landowners. Generally, these leases convey mining rights to the
coal producer in exchange for a percentage of gross sales in the form of a
royalty payment to the lessor, subject to minimum payments. Leases generally
last for the economic life of the reserves. The average royalties paid by us for
coal reserves from our producing properties was $2.94 per ton in 2008,
representing approximately 5.2% (net of freight and handling) of our coal sales
revenue in 2008. Consistent with industry practice, we conduct only limited
investigations of title to our coal properties prior to leasing. Title to lands
and reserves of the lessors or grantors and the boundaries of our leased
priorities are not completely verified until we prepare to mine those
reserves.
Non-Reserve Coal
Deposits
Non-reserve coal deposits are
coal-bearing bodies that have been sufficiently sampled and analyzed in
trenches, outcrops, drilling and underground workings to assume continuity
between sample points and, therefore, warrant further exploration stage work.
However, this coal does not qualify as a commercially viable coal reserve as
prescribed by SEC standards until a final comprehensive evaluation based on unit
cost per ton, recoverability and other material factors concludes legal and
economic feasibility. Non-reserve coal deposits may be classified as such by
either limited property control or geologic limitations, or
both.
52
The following table provides the
location of our mining operations and the type and amount of non-reserve coal
deposits at those complexes as of January 1, 2009:
|
|
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
Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vindex Energy
Corp.
|
|
Unassigned
|
|
D
|
|
MD
|
|
S
|
|
0.44
|
|
0.00
|
|
0.44
|
Wolf Run Mining Buckhannon
Division
|
|
Assigned
|
|
O
|
|
WV
|
|
UG
|
|
1.46
|
|
1.46
|
|
0.00
|
|
|
Unassigned
|
|
D
|
|
WV
|
|
UG
|
|
2.24
|
|
2.24
|
|
0.00
|
Total Wolf Run Mining Buckhannon
Division
|
|
|
|
|
|
|
|
|
|
3.70
|
|
3.70
|
|
0.00
|
Sentinel
|
|
Assigned
|
|
O
|
|
WV
|
|
UG
|
|
1.64
|
|
1.64
|
|
0.00
|
|
|
Unassigned
|
|
D
|
|
WV
|
|
UG
|
|
0.76
|
|
0.76
|
|
0.00
|
Total
Sentinel
|
|
|
|
|
|
|
|
|
|
2.40
|
|
2.40
|
|
0.00
|
CoalQuest
Development LLC
|
|
Unassigned
|
|
D
|
|
WV
|
|
UG
|
|
38.14
|
|
38.14
|
|
0.00
|
|
|
(Hillman)
|
|
|
|
|
|
|
|
|
|
|
|
|
Upshur
Property
|
|
Unassigned
|
|
|
|
WV
|
|
S
|
|
92.96
|
|
92.96
|
|
0.00
|
|
|
(Upshur)
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Appalachia Total
|
|
|
|
|
|
|
|
|
|
137.64
|
|
137.20
|
|
0.44
|
Central
Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eastern
|
|
Assigned
|
|
O
|
|
WV
|
|
S
|
|
0.02
|
|
0.02
|
|
0.00
|
Hazard
|
|
Assigned
|
|
O
|
|
KY
|
|
S
|
|
6.39
|
|
6.39
|
|
0.00
|
Flint Ridge
|
|
Assigned
|
|
O
|
|
KY
|
|
UG
|
|
0.94
|
|
0.94
|
|
0.00
|
Knott County
|
|
Assigned
|
|
O
|
|
KY
|
|
UG
|
|
0.00
|
|
0.00
|
|
0.00
|
East
Kentucky
|
|
Assigned
|
|
O
|
|
KY
|
|
S
|
|
0.00
|
|
0.00
|
|
0.00
|
|
|
(Mount Sterling)
|
|
|
|
|
|
|
|
|
|
|
|
|
ICG Natural
Resources
|
|
Assigned
|
|
D
|
|
WV
|
|
S
|
|
0.22
|
|
0.22
|
|
0.00
|
|
|
(Jennie
Creek)
|
|
|
|
|
|
|
|
|
|
|
|
|
ICG Natural
Resources
|
|
Unassigned
|
|
D
|
|
KY
|
|
S/UG
|
|
35.59
|
|
35.59
|
|
0.00
|
|
|
(Martin Co.,
Muhlenberg Co.)
|
|
|
|
|
|
|
|
|
|
|
|
|
ICG Natural
Resources
|
|
Unassigned
|
|
|
|
WV
|
|
UG
|
|
21.62
|
|
21.62
|
|
0.00
|
|
|
(Mobil)
|
|
|
|
|
|
|
|
|
|
|
|
|
Powell Mountain
|
|
Unassigned
|
|
O
|
|
VA
|
|
UG
|
|
46.07
|
|
46.07
|
|
0.00
|
Beckley
|
|
Unassigned
|
|
O
|
|
WV
|
|
UG
|
|
1.88
|
|
0.00
|
|
1.88
|
Juliana Mining Co.,
Inc.
|
|
Unassigned
|
|
D
|
|
WV
|
|
S/UG
|
|
3.10
|
|
3.10
|
|
0.00
|
White Wolf Energy,
Inc.
|
|
Unassigned
|
|
D
|
|
VA
|
|
UG
|
|
2.58
|
|
2.58
|
|
0.00
|
|
|
(Big Creek)
|
|
|
|
|
|
|
|
|
|
|
|
|
Central Appalachia Total
|
|
|
|
|
|
|
|
|
|
118.41
|
|
116.53
|
|
1.88
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois
|
|
Assigned
|
|
O
|
|
IL
|
|
UG
|
|
38.47
|
|
38.47
|
|
0.00
|
|
|
(Viper)
|
|
|
|
|
|
|
|
|
|
|
|
|
ICG Natural
Resources
|
|
Unassigned
|
|
|
|
IL
|
|
UG
|
|
57.92
|
|
57.92
|
|
0.00
|
|
|
(Illinois)
|
|
|
|
|
|
|
|
|
|
|
|
|
53
|
|
Assigned or
Unassigned(1)
|
|
Operating (O) or
Development (D)
|
|
State
|
|
Mining Method
Surface (S)
or
Underground (UG)
|
|
Total
Non-Reserve
Coal Deposits
|
|
Steam
Non-Reserve
Coal Deposits
|
|
Metallurgical(2)(3)
Non-Reserve
Coal
Deposits
|
|
|
|
|
|
|
|
|
|
|
(in million
tons)
|
ICG Natural
Resources
|
|
Unassigned
|
|
|
|
AR
|
|
S
|
|
39.15
|
|
39.15
|
|
0.00
|
|
|
(Arkansas)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unassigned
|
|
|
|
CA
|
|
UG
|
|
10.00
|
|
10.00
|
|
0.00
|
|
|
(California)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unassigned
|
|
|
|
OH
|
|
UG
|
|
98.00
|
|
98.00
|
|
0.00
|
|
|
(Ohio)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unassigned
|
|
|
|
MT
|
|
S
|
|
12.00
|
|
12.00
|
|
0.00
|
|
|
(Montana)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unassigned
|
|
|
|
WA
|
|
S
|
|
9.86
|
|
9.86
|
|
0.00
|
|
|
(Washington)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other
|
|
|
|
|
|
|
|
|
|
265.40
|
|
265.40
|
|
0.00
|
Total Non-Reserve Coal
Deposits
|
|
|
|
|
|
|
|
521.45
|
|
519.13
|
|
2.32
|
(1)
|
“Assigned non-reserve coal
deposits” mean coal which has been committed by the coal company to
operating mine shafts, mining equipment and plant facilities, and all coal
which has been leased by the coal company to others. “Unassigned
non-reserve coal deposits” represent coal which has not been committed,
and which would require new mine shafts, mining equipment or plant
facilities before operations could begin in the
property.
|
(2)
|
Beckley and White Wolf Energy,
Inc. meet historical metallurgical coal quality
specifications.
|
(3)
|
We sold coal with ash and sulfur
contents as high as 10% and 1.5%, respectively, into the metallurgical
market from Vindex Energy, Buckhannon and Sentinel in 2008. Similarly, we
believe all production from Vindex Energy and portions of Hillman can
be sold on this metallurgical
market.
|
The following table provides the
“quality” (average moisture, ash and sulfur contents and Btu per pound) of our
non-reserve coal deposits as of January 1, 2009:
|
|
|
|
As Received
Quality
|
|
|
Assigned or
Unassigned
(1)
|
|
%
Moisture
|
|
%
Ash
|
|
%
Sulfur
|
|
Btu/ lb.
|
|
Lbs. SO2/
million Btu’s
|
Northern
Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
Vindex Energy Corp.
(3)
|
|
Unassigned
|
|
6.00
|
|
14.15
|
|
1.49
|
|
12,409
|
|
2.40
|
Wolf Run Mining Buckhannon
Division(3)
|
|
Assigned
|
|
6.00
|
|
7.43
|
|
2.83
|
|
13,086
|
|
4.32
|
|
|
Unassigned
|
|
6.00
|
|
9.00
|
|
1.20
|
|
13,000
|
|
1.85
|
Sentinel(3)
|
|
Assigned
|
|
6.00
|
|
8.30
|
|
1.40
|
|
13,100
|
|
2.14
|
|
|
Unassigned
|
|
6.00
|
|
8.30
|
|
1.40
|
|
13,100
|
|
2.14
|
Upshur
Property
|
|
Unassigned
|
|
6.00
|
|
43.00
|
|
2.00
|
|
8,000
|
|
5.00
|
Central
Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
Eastern
|
|
Assigned
|
|
6.00
|
|
12.20
|
|
1.20
|
|
12,400
|
|
1.94
|
Hazard
|
|
Assigned
|
|
6.00
|
|
13.51
|
|
1.07
|
|
11,880
|
|
1.79
|
Flint Ridge
|
|
Assigned
|
|
6.00
|
|
8.15
|
|
1.39
|
|
12,768
|
|
2.18
|
Knott County
|
|
Assigned
|
|
N/A
|
|
N/A
|
|
N/A
|
|
N/A
|
|
N/A
|
East
Kentucky
|
|
Assigned
|
|
N/A
|
|
N/A
|
|
N/A
|
|
N/A
|
|
N/A
|
|
|
(Mt. Sterling)
|
|
|
|
|
|
|
|
|
|
|
ICG Natural
Resources
|
|
Assigned
|
|
7.00
|
|
7.78
|
|
0.63
|
|
12,609
|
|
1.01
|
|
|
(Jennie Creek)
|
|
|
|
|
|
|
|
|
|
|
ICG Natural
Resources
|
|
Unassigned
|
|
6.00
|
|
11.47
|
|
1.91
|
|
11,780
|
|
3.24
|
|
|
(Martin Co.,
Muhlenberg Co.)
|
|
|
|
|
|
|
|
|
|
|
ICG Natural
Resources
|
|
Unassigned
(Mobil)
|
|
6.00
|
|
12.50
|
|
1.10
|
|
12,000
|
|
1.83
|
Powell Mountain
|
|
Unassigned
|
|
6.00
|
|
5.78
|
|
1.21
|
|
13,348
|
|
1.81
|
Beckley(2)
|
|
Unassigned
|
|
6.00
|
|
4.80
|
|
0.70
|
|
13,800
|
|
1.01
|
Juliana Mining Co.,
Inc.
|
|
Unassigned
|
|
6.00
|
|
7.50
|
|
0.82
|
|
13,100
|
|
1.25
|
White Wolf Energy,
Inc.(2)
|
|
Unassigned
|
|
6.00
|
|
7.40
|
|
0.60
|
|
13,500
|
|
0.89
|
|
|
(Big
Creek)
|
|
|
|
|
|
|
|
|
|
|
54
|
|
|
|
As received
quality
|
|
|
Assigned or
Unassigned
(1)
|
|
%
Moisture
|
|
%
Ash
|
|
%
Sulfur
|
|
Btu/ lb.
|
|
Lbs. SO2/
million Btu’s
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois
|
|
Assigned
|
|
16.00
|
|
9.50
|
|
3.50
|
|
10,500
|
|
6.67
|
|
|
(Viper)
|
|
|
|
|
|
|
|
|
|
|
ICG Natural
Resources
|
|
Unassigned
|
|
13.00
|
|
9.00
|
|
3.00
|
|
11,000
|
|
5.45
|
|
|
(Illinois)
|
|
|
|
|
|
|
|
|
|
|
ICG Natural
Resources
|
|
Unassigned
|
|
N/A
|
|
8.00
|
|
0.40
|
|
5,650
|
|
1.42
|
|
|
(Arkansas)
|
|
|
|
|
|
|
|
|
|
|
|
|
Unassigned
|
|
6.00
|
|
13.00
|
|
3.50
|
|
11,700
|
|
5.98
|
|
|
(California)
|
|
|
|
|
|
|
|
|
|
|
|
|
Unassigned
|
|
6.00
|
|
8.40
|
|
2.50
|
|
12,650
|
|
3.95
|
|
|
(Ohio)
|
|
|
|
|
|
|
|
|
|
|
|
|
Unassigned
|
|
N/A
|
|
8.00
|
|
0.30
|
|
8,900
|
|
0.67
|
|
|
(Montana)
|
|
|
|
|
|
|
|
|
|
|
|
|
Unassigned
|
|
N/A
|
|
8.00
|
|
0.50
|
|
7,025
|
|
1.42
|
|
|
(Washington)
|
|
|
|
|
|
|
|
|
|
|
(1)
|
“Assigned non-reserve coal
deposits” mean coal which has been committed by the coal company to
operating mine shafts, mining equipment and plant facilities, and all coal
which has been leased by the coal company to others. “Unassigned
non-reserve coal deposits” represent coal which has not been committed,
and which would require new mineshafts, mining equipment or plant
facilities before operations could begin in the
property.
|
(2)
|
Beckley and White Wolf Energy,
Inc. meet historical metallurgical coal quality
specifications.
|
(3)
|
We sold coal with ash and sulfur
contents as high as 10% and 1.5%, respectively, into the metallurgical
market from Vindex Energy, Buckhannon and Sentinel 2008. Similarly, we
believe all production from Vindex Energy and portions of Hillman can
be sold on this metallurgical
market.
|
On August 23, 2006, a survivor of
the Sago mine accident, Randal McCloy, filed a complaint in the Kanawha Circuit
Court in Kanawha County, West Virginia. The claims brought by Randal McCloy and
his family against us and certain of our subsidiaries, and against W.L.
Ross & Co., and Wilbur L. Ross, Jr., individually, were dismissed on
February 14, 2008, after the parties reached a confidential settlement.
Sixteen other complaints have been filed in Kanawha Circuit Court by the
representatives of many of the miners who died in the Sago mine accident, and
several of these plaintiffs have filed amended complaints to expand the group of
defendants in the cases. The complaints allege various causes of action against
us and our subsidiary, Wolf Run Mining Company, one of our shareholders, W.L.
Ross & Co., and Wilbur L. Ross Jr., individually, related to the
accident and seek compensatory and punitive damages. In addition, the plaintiffs
also allege causes of action against other third parties, including claims
against the manufacturer of Omega block seals used to seal the area where the
explosion occurred and against the manufacturer of self-contained self-rescuer
(“SCSR”) devices worn by the miners at the Sago mine. Some of these third
parties have been dismissed from the actions upon settlement. The amended
complaints add other of our subsidiaries to the cases, including ICG, Inc., ICG,
LLC and Hunter Ridge Coal Company, unnamed parent, subsidiary and affiliate
companies of us, W.L. Ross & Co., and Wilbur L. Ross Jr., and other
third parties, including a provider of electrical services and a supplier of
components used in the SCSR devices. We believe that we are appropriately
insured for these and other potential claims, and we have fully paid our
deductible applicable to our insurance policies. In addition to the dismissal of
the McCloy claim, we have settled and dismissed five other actions. These
settlements required the release of us, our subsidiaries, W. L. Ross &
Co., and Wilbur L. Ross, Jr. Some of the plaintiffs involved in one of the
dismissed actions have sought permission from the Supreme Court of Appeals of
West Virginia to appeal the settlement, alleging that the settlement negotiated
by the decedent’s estate should not have been approved by the trial court.
The trial court overruled those plaintiffs’ objections to the settlement,
and, although the West Virginia Supreme Court of Appeals refused to stay the
effectiveness of the settlement, the plaintiffs’ petition for appeal to the West
Virginia Supreme Court of Appeals was recently presented to the court. The court
has not yet ruled whether it will accept the petition for appeal or decline to
hear the appeal. We will
vigorously defend ourselves against the remaining complaints and any appeal of
any prior settlements.
Allegheny Energy Supply (“Allegheny”),
the sole customer of coal produced at our subsidiary Wolf Run Mining Company’s
(“Wolf Run”) Sycamore No. 2 mine, filed a lawsuit against Wolf Run, Hunter
Ridge Holdings, Inc. (“Hunter Ridge”), and us in state court in Allegheny
County, Pennsylvania on December 28, 2006, and amended its complaint on
April 23, 2007. Allegheny claims that we breached a coal supply contract
when we declared force majeure under the contract upon idling the Sycamore
No. 2 in the third quarter of 2006. The Sycamore No. 2 mine was idled
after encountering adverse geologic conditions and abandoned gas wells that were
previously unidentified and unmapped. The amended complaint also alleges that
the production stoppages constitute a breach of the guarantee agreement by
Hunter Ridge and breach of certain representations made upon entering into the
contract in early 2005, a claim that Allegheny has since voluntarily dropped.
Allegheny claims that it will incur costs in excess of $100.0 million to purchase replacement coal over the
life of the contract. We, Wolf Run and Hunter Ridge answered the amended
complaint on August 13, 2007, disputing all of the remaining claims. On November
3, 2008, we, Wolf Run and Hunter Ridge filed an amended answer and
counterclaim against the plaintiffs seeking to void the coal supply agreement
due to, among other things, fraudulent inducement and conspiracy. The
counterclaim alleges further that Allegheny breached a confidentiality agreement
with Hunter Ridge, which prohibited the solicitation of its employees. After the
coal supply agreement was executed, Allegheny hired the then-president of Anker
Coal Group, Inc. (now Hunter Ridge) who engaged in negotiations on behalf of
Wolf Run and Hunter Ridge. In addition to seeking a declaratory judgment that
the coal supply agreement and guaranty be deemed void and unenforceable and
rescission of the contracts, the counterclaim also seeks compensatory and
punitive damages.
55
On December 6, 2007, the Kentucky
Waterways Alliance, Inc., and The Sierra Club sued the U.S. Army Corps of
Engineers (the “ACOE”) in the United States District Court for the Western
District of Kentucky, Louisville Division (the “Court”), asserting that a permit
to construct five valley fills was issued unlawfully to our Hazard subsidiary
for its Thunder Ridge Surface mine. The suit alleges that the ACOE failed to
comply with the requirements of both Section 404 of the Clean Water Act and
the National Environmental Policy Act. Hazard has intervened in the suit to
protect our interests. The ACOE suspended the Section 404 permit on
December 26, 2007 in order to evaluate the issues raised by the plaintiffs.
That evaluation is now in progress. If the ACOE reinstates the permit and the
Court subsequently finds that the permit is unlawful, production could be
materially affected at the Thunder Ridge Surface mine and the process of
obtaining ACOE permits for coal mining activities in Kentucky could become more
difficult.
On January 7, 2008, Saratoga
Advantage Trust filed a class action lawsuit in the U.S. District Court for the
Southern District of West Virginia against us and certain of our officers and
directors. The complaint asserts claims under Sections 10(b) and 20(a) of
the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder,
based on alleged false and misleading statements in the registration statements
filed in connection with our November 2005 reorganization and December 2005
public offering of common stock. In addition, the complaint challenges other of
our public statements regarding our operating condition and safety record. We
intend to vigorously defend the action.
On July 3, 2007, Taylor Environmental
Advocacy Membership, Inc. (“T.E.A.M.”) filed a petition to appeal the issuance
of ICG Tygart Valley, LLC’s (“Tygart Valley”) Surface Mine Permit U-2004-06
against the West Virginia Department of Environmental Protection (the “WVDEP”)
in an action before the West Virginia Surface Mine Board (the “Board”). On
December 10, 2007, the Board remanded the permit to the WVDEP for revision to
certain provisions related to pre-mining water monitoring and cumulative
hydrologic impacts. The WVDEP issued a modification on April 1, 2008 addressing
those issues. T.E.A.M. filed an appeal of the WVDEP’s approval of the permit
modification on April 30, 2008. On October 7, 2008, the Board issued an order
remanding the permit to the WVDEP requiring Tygart Valley to address a technical
issue related to projected post-mining water quality. Tygart Valley has prepared
and submitted a permit modification to alleviate the board’s concerns. All site
development will be suspended until the WVDEP has approved the permit
modification. If the WVDEP issues the permit as modified, there will be
additional opportunity for appeal by T.E.A.M.
In addition, from time to time, we are
involved in legal proceedings arising in the ordinary course of business. These
proceedings include assessments of penalties for citations and orders asserted
by MSHA and other regulatory agencies, none of which are expected by management
to, individually or in the aggregate, have a material adverse effect on us. In
the opinion of management, we have recorded adequate reserves for liabilities
arising in the ordinary course and it is management’s belief there is no
individual case or group of related cases pending that is likely to have a
material adverse effect on our financial condition, results of operations or
cash flows.
|
SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS
|
No matters were submitted to a vote of
security holders during the quarter ended December 31, 2008.
56
PART II
|
MARKET FOR REGISTRANT’S COMMON
EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
|
Our common stock is listed on the New
York Stock Exchange (the “NYSE”) under the symbol “ICO.” The following table
sets forth, for the quarterly periods indicated, the high and low sales prices
per share at the end of the day of our common stock reported on the
NYSE.
|
Stock Price
|
|
|
High
|
|
Low
|
|
2007
|
|
|
|
|
|
|
|
|
$ |
5.61 |
|
|
$ |
4.70 |
|
|
|
|
6.48 |
|
|
|
5.24 |
|
|
|
|
6.12 |
|
|
|
3.85 |
|
|
|
|
5.57 |
|
|
|
4.45 |
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
$ |
6.98 |
|
|
$ |
5.28 |
|
|
|
|
13.28 |
|
|
|
6.01 |
|
|
|
|
13.11 |
|
|
|
5.61 |
|
|
|
|
5.98 |
|
|
|
1.50 |
|
These quotes are provided solely for
informational purposes and may not be indicative of any price at which the
shares of common stock may trade in the future.
As of February 19, 2009, there were
approximately 243 holders of record of our common stock and an additional 48,402
stockholders whose shares were held for them in street name or nominee
accounts.
Summary of Equity Compensation
Plans
Shown below is information concerning
our equity compensation plans and individual compensation arrangements as of
December 31, 2008.
|
|
Equity Compensation Plan
Information
|
|
|
Number of Securities
To Be Issued
Upon
Exercise
of
Outstanding
Options
|
|
Weighted
Average
Exercise
Price of
Outstanding
Options
|
|
Number of Securities
Remaining Available
For Future Issuance
Under Equity
Compensation
Plans
|
Equity
compensation plans approved by stockholders(1)
|
|
2,512,140
|
|
$
|
7.49
|
|
5,175,023
|
Equity
compensation plans not approved by stockholders(2)
|
|
319,052
|
|
|
10.97
|
|
—
|
|
|
2,831,192
|
|
$
|
7.88
|
|
5,175,023
|
(1)
|
We have two compensation plans:
the 2005 Equity and Performance Incentive Plan, which was approved by
stockholders on October 24, 2005, and the Director Compensation
Plan.
|
(2)
|
Represents stock option grant to
purchase 319,052 shares of our common stock to our President and Chief
Executive Officer pursuant to his employment
agreement.
|
For additional information regarding our
equity compensation plans, refer to the discussion in Note 13 to our audited
consolidated financial statements included elsewhere in this
report.
Dividend Policy
We have never declared or paid a
dividend on our common stock. We may retain any future earnings to support the
development and expansion of our business or make additional payments under our
credit facilities and, as a result, we may not pay cash dividends in the
foreseeable future. Our payment of any future dividends will be at the
discretion of our board of directors after taking into account various factors,
including our financial condition, operating results, cash needs, growth plans
and the terms of any credit agreements that we may be a party to at the time.
Our credit facility and indenture governing the senior notes limits us from
paying cash dividends or other payments or distributions with respect to our
capital stock in excess of certain limitations. In addition, the terms of any
future credit agreement may contain similar restrictions on our ability to pay
dividends or make payments or distributions with respect to our capital
stock.
57
International Coal Group, Inc. was
formed in March 2005 as a wholly owned subsidiary of ICG, Inc. in order to
effect a corporate reorganization. On November 18, 2005, we completed the
reorganization. Prior to this reorganization, ICG, Inc. was the top-tier holding
company. Upon completion of the reorganization, International Coal Group, Inc.
became the new top-tier parent holding company. International Coal Group, Inc.
is a holding company which does not have any independent external operations,
assets or liabilities, other than through its operating subsidiaries. Prior to
the acquisition of certain assets of Horizon as of September 30, 2004, ICG,
Inc. did not have any material assets, liabilities or results of operations. The
selected historical consolidated financial data is derived from International
Coal Group, Inc.’s audited consolidated financial statements as of December 31,
2008 and 2007 and for the years ended December 31, 2008, 2007 and 2006 which is
included elsewhere in this report. The selected historical consolidated
financial data of International Coal Group, Inc. as of December 31, 2006,
2005 and 2004, the year ended December 31, 2005 and for the period May 13,
2004 (inception) to December 31, 2004 is derived from audited consolidated
financial statements which are not included in this report. The selected
historical consolidated financial data as of and for the nine months ended
September 30, 2004 is derived from the consolidated financial statements of
Horizon, our predecessor, which has been audited and is not included in this
report. In the opinion of management, the financial data reflect all
adjustments, consisting of all normal and recurring adjustments, necessary for a
fair presentation of the results for those periods. The results of operations
for interim periods are not necessarily indicative of the results to be expected
for the full year or for any future period. The financial statements for the
predecessor periods have been prepared on a “carve-out” basis to include our
assets, liabilities and results of operations that were previously included in
financial statements of Horizon. The financial statements for the predecessor
periods include allocations of certain expenses, taxation charges, interest and
cash balances relating to the predecessor based on management’s estimates. The
predecessor financial information is not necessarily indicative of our
consolidated financial position, results of operations and cash flows if we had
operated during the predecessor periods presented.
During
the years ended December 31, 2008 and 2007, we recorded impairment losses of
$37.4 million and $170.4 million, respectively. For 2008, $30.2 million of the
loss related to impairment of goodwill at our ADDCAR subsidiary and $7.2 million
related to impairment of long-lived assets. For 2007, the impairment loss
related to impairment of goodwill at various of our business units. See Notes 4
and 5 to our consolidated
financial statements for further discussion of the impairment
losses.
On
November 18, 2005, we consummated a business combination with each of Anker and
CoalQuest. The results of operations of Anker and CoalQuest are included in our
consolidated results of operations since that date.
58
You should read the following data in
conjunction with “Management’s Discussion and Analysis of Financial Condition
and Results of Operations” and with the financial information included elsewhere
in this report, including the consolidated financial statements of International
Coal Group, Inc. and the related notes thereto. Amounts shown are in thousands,
except per share data.
|
|
International Coal Group,
Inc.
|
|
|
Horizon
(Predecessor to International Coal
Group, Inc.)
|
|
|
|
Year ended
|
|
|
Year ended
|
|
|
Year ended
|
|
|
Year ended
|
|
|
Period from
|
|
|
Period from
|
|
Statement of Operations
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
revenues
|
|
$
|
998,245
|
|
|
$
|
770,663
|
|
|
$
|
833,998
|
|
|
$
|
619,038
|
|
|
$
|
130,463
|
|
|
$
|
346,981
|
|
Freight and handling
revenues
|
|
|
45,231
|
|
|
|
29,594
|
|
|
|
18,890
|
|
|
|
8,601
|
|
|
|
880
|
|
|
|
3,700
|
|
Other
revenues
|
|
|
53,260
|
|
|
|
48,898
|
|
|
|
38,706
|
|
|
|
22,852
|
|
|
|
5,648
|
|
|
|
22,841
|
|
Total
revenues
|
|
|
1,096,736
|
|
|
|
849,155
|
|
|
|
891,594
|
|
|
|
650,491
|
|
|
|
136,991
|
|
|
|
373,522
|
|
Costs and
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales and other
revenues
|
|
|
918,655
|
|
|
|
766,158
|
|
|
|
769,332
|
|
|
|
510,097
|
|
|
|
113,527
|
|
|
|
306,429
|
|
Freight and handling
costs
|
|
|
45,231
|
|
|
|
29,594
|
|
|
|
18,890
|
|
|
|
8,601
|
|
|
|
880
|
|
|
|
3,700
|
|
Depreciation, depletion and
amortization
|
|
|
96,047
|
|
|
|
86,517
|
|
|
|
72,218
|
|
|
|
43,076
|
|
|
|
7,932
|
|
|
|
27,547
|
|
Selling, general and
administrative
|
|
|
38,147
|
|
|
|
33,325
|
|
|
|
34,578
|
|
|
|
28,828
|
|
|
|
4,205
|
|
|
|
8,477
|
|
Gain on sale of
assets
|
|
|
(32,518
|
)
|
|
|
(38,656
|
)
|
|
|
(1,125
|
)
|
|
|
(502
|
)
|
|
|
(10
|
)
|
|
|
(226
|
)
|
Impairment
loss
|
|
|
37,428
|
|
|
|
170,402
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Writedowns and special
items
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
10,018
|
|
Total costs and
expenses
|
|
|
1,102,990
|
|
|
|
1,047,340
|
|
|
|
893,893
|
|
|
|
590,100
|
|
|
|
126,534
|
|
|
|
355,945
|
|
Income (loss) from
operations
|
|
|
(6,254
|
)
|
|
|
(198,185
|
)
|
|
|
(2,299
|
)
|
|
|
60,391
|
|
|
|
10,457
|
|
|
|
17,577
|
|
Interest and Other Income
(Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense,
net
|
|
|
(41,107
|
)
|
|
|
(35,140
|
)
|
|
|
(18,091
|
)
|
|
|
(14,394
|
)
|
|
|
(3,453
|
)
|
|
|
(114,211
|
)
|
Reorganization
items
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(12,471
|
)
|
Other, net
|
|
|
—
|
|
|
|
319
|
|
|
|
2,113
|
|
|
|
3,302
|
|
|
|
16
|
|
|
|
1,442
|
|
Total interest and other income
(expense)
|
|
|
(41,107
|
)
|
|
|
(34,821
|
)
|
|
|
(15,978
|
)
|
|
|
(11,092
|
)
|
|
|
(3,437
|
)
|
|
|
(125,240
|
)
|
Income (loss) before income taxes
and minority interest
|
|
|
(47,361
|
)
|
|
|
(233,006
|
)
|
|
|
(18,277
|
)
|
|
|
49,299
|
|
|
|
7,020
|
|
|
|
(107,663
|
)
|
Income tax (expense)
benefit
|
|
|
22,711
|
|
|
|
85,623
|
|
|
|
9,015
|
|
|
|
(16,986
|
)
|
|
|
(2,660
|
)
|
|
|
—
|
|
Minority
interest
|
|
|
—
|
|
|
|
349
|
|
|
|
(58
|
)
|
|
|
15
|
|
|
|
—
|
|
|
|
—
|
|
Net income
(loss)
|
|
$
|
(24,650
|
)
|
|
$
|
(147,034
|
)
|
|
$
|
(9,320
|
)
|
|
$
|
32,328
|
|
|
$
|
4,360
|
|
|
$
|
(107,663
|
)
|
59
|
|
International Coal Group,
Inc.
|
|
|
Horizon
(Predecessor to International Coal
Group, Inc.)
|
|
|
|
Year ended
|
|
|
Year ended
|
|
|
Year ended
|
|
|
Year ended
|
|
|
Period from
|
|
|
Period from
|
|
Earnings Per Share(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.16
|
)
|
|
$
|
(0.97
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
0.29
|
|
|
$
|
0.04
|
|
|
$
|
—
|
|
Diluted
|
|
|
(0.16
|
)
|
|
|
(0.97
|
)
|
|
|
(0.06
|
)
|
|
|
0.29
|
|
|
|
0.04
|
|
|
|
—
|
|
Weighted-Average Common Shares
Outstanding (1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
152,632,586
|
|
|
|
152,304,461
|
|
|
|
152,028,165
|
|
|
|
111,120,211
|
|
|
|
106,605,999
|
|
|
|
—
|
|
Diluted
|
|
|
152,632,586
|
|
|
|
152,304,461
|
|
|
|
152,028,165
|
|
|
|
111,161,287
|
|
|
|
106,605,999
|
|
|
|
—
|
|
Balance Sheet Data (at period
end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
63,930
|
|
|
$
|
107,150
|
|
|
$
|
18,742
|
|
|
$
|
9,187
|
|
|
$
|
23,967
|
|
|
$
|
—
|
|
Total
assets
|
|
|
1,349,669
|
|
|
|
1,303,563
|
|
|
|
1,316,891
|
|
|
|
1,051,403
|
|
|
|
457,045
|
|
|
|
539,606
|
|
Long-term debt and capital
leases
|
|
|
450,239
|
|
|
|
412,330
|
|
|
|
180,035
|
|
|
|
45,462
|
|
|
|
175,681
|
|
|
|
29
|
|
Total liabilities and minority
interest
|
|
|
854,879
|
|
|
|
789,192
|
|
|
|
658,541
|
|
|
|
384,917
|
|
|
|
302,534
|
|
|
|
1,422,290
|
|
Total stockholders’ equity
(members’ deficit)
|
|
|
494,790
|
|
|
|
514,371
|
|
|
|
658,350
|
|
|
|
666,486
|
|
|
|
154,511
|
|
|
|
(882,684
|
)
|
Total liabilities and
stockholders’ equity (members’ deficit)
|
|
|
1,349,669
|
|
|
|
1,303,563
|
|
|
|
1,316,891
|
|
|
|
1,051,403
|
|
|
|
457,045
|
|
|
|
539,606
|
|
Statement of Cash Flows
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
activities
|
|
$
|
77,953
|
|
|
$
|
22,095
|
|
|
$
|
55,591
|
|
|
$
|
77,319
|
|
|
$
|
30,264
|
|
|
$
|
28,085
|
|
Investing
activities
|
|
|
(123,264
|
)
|
|
|
(126,531
|
)
|
|
|
(160,769
|
)
|
|
|
(104,713
|
)
|
|
|
(329,168
|
)
|
|
|
3,437
|
|
Financing
activities
|
|
|
2,091
|
|
|
|
192,844
|
|
|
|
114,733
|
|
|
|
12,614
|
|
|
|
322,871
|
|
|
|
(32,381
|
)
|
Capital
expenditures
|
|
|
132,024
|
|
|
|
160,431
|
|
|
|
165,658
|
|
|
|
108,231
|
|
|
|
5,583
|
|
|
|
6,624
|
|
(1)
|
Earnings per share data and
average shares outstanding are not presented the period from
January 1, 2004 to September 30, 2004 because they were prepared
on a carve-out basis. The financial statements prepared for predecessor
periods are carve-out financial statements reflecting the operations and
financial condition of the Horizon assets acquired by us as of
September 30, 2004 (collectively, the “combined companies”). The
predecessor financial statements were prepared from the separate accounts
and records maintained by the combined companies. In addition, certain
assets and expense items represent allocations from Horizon. The accounts
allocated include vendor advances, reclamation deposits and selling,
general and administrative
expenses.
|
60
|
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.
Overview
We produce, process and sell steam coal
from 13 regional mining complexes, which, as of December 31, 2008 were supported
by 14 active underground mines, 14 active surface mines and 10 preparation
plants located throughout West Virginia, Kentucky, Virginia, Maryland and
Illinois. We have three reportable business segments, which are based on the
coal regions in which we operate: (i) Central Appalachian, comprised of
both surface and underground mines, (ii) Northern Appalachian, also
comprised of both surface and underground mines and (iii) Illinois Basin,
representing one underground mine. For more information about our reportable
business segments, please see our audited consolidated financial statements and
the notes thereto appearing elsewhere in this report. We also broker coal
produced by others, the majority of which is shipped directly from the
third-party producer to the ultimate customer. Our steam coal sales are
primarily to large utilities and industrial customers in the Eastern region of
the United
States. In addition, we
generate other revenues from the manufacture and operation of highwall mining
systems, parts sales and shop services relating to those systems and coal
handling and processing fees.
ICG, Inc. was formed by WL
Ross & Co. LLC (“WLR”), and other investors, in May 2004 to acquire and
operate competitive coal mining facilities. International Coal Group, Inc. was
formed in March 2005 and became the parent holding company pursuant to a
reorganization on November 18, 2005. Through the acquisition of key assets
from the Horizon bankruptcy estate, the WLR investor group was able to target
properties strategically located in Appalachia and the Illinois Basin with high quality reserves that are
union free. With the proceeds of our December 2005 public offering, we retired
substantially all of our then outstanding debt. Consistent with the WLR investor
group’s strategy to acquire attractive coal assets, the Anker and CoalQuest
acquisitions further diversified our reserves in November
2005.
Our primary expenses are wages and
benefits, repair and maintenance expenditures, diesel fuel purchases, blasting
supplies, coal transportation costs, cost of purchased coal, royalties, freight
and handling costs and taxes incurred in selling our coal.
Certain Trends and Economic Factors
Affecting the Coal Industry
Our revenues depend on the price at
which we are able to sell our coal. The pricing environment for domestic steam
and metallurgical coal during the first three quarters of 2008 was relatively
strong. In the fourth quarter of 2008, coal prices dropped drastically due to
decreased demand for metallurgical coal caused by the global economic crisis and
decreased demand for steam coal caused by high inventory levels at utilities. We
have experienced increased operating costs for fuel and explosives, steel
products, tires, healthcare and labor. While prices of labor and
commodities
increased over prior year, we expect that current economic
conditions will reduce the inflationary pressures that drove up such costs in
2008. However, we expect to
experience higher costs for surety bonds and letters of
credit.
For additional information regarding
some of the risks and uncertainties that affect our business and the industry in which we operate, see
Item 1A. Risk Factors.
Critical Accounting Policies and
Estimates
Our financial statements are prepared in
accordance with accounting principles that are generally accepted in the
United States of
America. The preparation of
these financial statements requires management to make estimates and judgments
that affect the reported amount of assets, liabilities, revenues and expenses,
as well as the disclosure of contingent assets and liabilities. Management
evaluates its estimates on an on-going basis. Management bases its estimates and
judgments on historical experience and other factors that are believed to be
reasonable under the circumstances. Actual results may differ from the estimates
used. Our actual results have generally not differed materially from our
estimates. However, we monitor such differences and, in the event that actual
results are significantly different from those estimated, we disclose any
related impact on our results of operations, financial position and cash flows.
Note 2 to our audited consolidated
financial statements provides a description of significant accounting policies.
We believe that of these
significant accounting policies, the following involve a higher degree of
judgment or complexity:
61
Revenue Recognition
Coal revenues result from sales
contracts (long-term coal agreements or purchase orders) with electric
utilities, industrial companies or other coal-related organizations, primarily
in the eastern United
States. Revenue is
recognized and recorded at the time of shipment or delivery to the customer, at
fixed or determinable prices and the title or risk of loss has passed in
accordance with the terms of the sales agreement. Under the typical terms of
these agreements, risk of loss transfers to the customers at the mine or port,
where coal is loaded to the rail, barge, truck or other transportation sources
that deliver coal to its destination.
Coal
sales revenues also result from the sale of brokered coal produced by others.
Revenue is recognized and recorded at the time of shipment or delivery to the
customer, prices are fixed or determinable and the title or risk of loss has
passed in accordance with the terms of the sale agreement. The revenues related
to brokered coal sales are included in coal sales revenues on a gross basis and
the corresponding cost of the coal from the supplier is recorded in cost of coal
sales in accordance with Emerging Issues Task Force (“EITF”) 99-19, Reporting Revenue Gross as a
Principal versus Net as an Agent.
Freight and handling costs paid to
third-party carriers and invoiced to coal customers are recorded as freight and
handling costs and freight and handling revenues,
respectively.
Other revenues primarily consist of
contract mining income, coalbed methane sales, ash disposal services, equipment
and parts sales, equipment rebuild and maintenance services, royalties and coal
handling and processing income. With respect to other revenues recognized in
situations unrelated to the shipment of coal, we carefully review the facts and
circumstances of each transaction and apply the relevant accounting literature
as appropriate and do not recognize revenue until the following criteria are
met: persuasive evidence of an arrangement exists, delivery has occurred or
services have been rendered, the seller’s price to the buyer is fixed or
determinable and collectibility is reasonably assured. Advance payments received
are deferred and recognized in revenue as related income is
earned.
Accounts
Receivable and Allowance for Doubtful Accounts
Accounts
receivable are recorded at the invoiced amount and do not bear interest. The
allowance for doubtful accounts represents management’s best estimate of the
amount of probable credit losses in our existing accounts receivable. We
establish provisions for losses on accounts receivable when it is probable that
all or part of the outstanding balance will not be collected. Management
regularly reviews collectability and establishes or adjusts the allowance as
necessary. Although we believe the estimate of credit losses we have made is
reasonable and appropriate, inability to collect outstanding accounts receivable
amounts could materially impact our reported financial results.
Reclamation
Our asset retirement obligations arise
from the Federal Surface Mining Control and Reclamation Act of 1977 and similar
state statutes, which require that mine property be restored in accordance with
specified standards and an approved reclamation plan. We record these
reclamation obligations according to the provisions of SFAS No. 143.
SFAS No. 143 requires the fair value of a liability for an asset
retirement obligation to be recognized in the period in which the legal
obligation associated with the retirement of the long-lived asset is incurred.
Fair value of reclamation liabilities is determined based on the present value
of the estimated future expenditures. When the liability is initially recorded,
the offset is capitalized by increasing the carrying amount of the related
long-lived asset. Over
time, the liability is
accreted to its present value, and the capitalized cost is depreciated over the
useful life of the related asset. If the assumptions used to estimate the
liability do not materialize as expected or regulatory changes were to occur,
reclamation costs or obligations to perform reclamation and mine closing
activities could be materially different than currently estimated. To settle the liability, the obligation
is paid, and to the extent there is a difference between the liability and the
amount of cash paid, a gain or loss upon settlement is recorded. On at least an
annual basis, we review our entire reclamation liability and make necessary
adjustments for permit changes as granted by state authorities, additional costs
resulting from accelerated mine closures and revisions to cost estimates and
productivity assumptions to reflect current experience. At December 31, 2008, we
had recorded asset retirement obligation liabilities of $79.2 million, including
amounts reported as current liabilities. While the precise amount of these
future costs cannot be determined with certainty, as of December 31, 2008, we
estimate that the aggregate undiscounted cost of final mine closure is
approximately $149.5 million.
Advance
Royalties
We
are required, under certain royalty lease agreements, to make minimum royalty
payments whether or not mining activity is being performed on the leased
property. These minimum payments may be recoupable once mining begins on the
leased property. The recoupable minimum royalty payments are capitalized and
amortized based on the units-of-production method at a rate defined in the lease
agreement once mining activities begin. Unamortized deferred royalty costs are
expensed when mining has ceased or a decision is made not to mine on such
property. We have recorded an allowance for such circumstances based upon
management estimates. We believe the estimate for losses is appropriate.
However, actual amounts that we recoup through mining activity could vary
resulting in a material impact to our financial results.
Inventories
Coal
inventories are stated at lower of average cost or market and represent coal
contained in stockpiles, including those tons that have been mined and hauled to
our loadout facilities, but not yet shipped to customers. These inventories are
stated in clean coal equivalent tons and take into account any loss that may
occur during the processing stage. Coal must be of a quality that can be sold on
existing sales orders to be carried as coal inventory. Coal inventory volumes
are determined through survey procedures. The surveys involve assumptions,
inherent uncertainties and the application of management judgment.
Parts
and supplies inventories are valued at average cost, less an allowance for
obsolescence. We establish provisions for losses in parts and supplies inventory
values through analysis of turnover of inventory items and adjust the allowance
as necessary.
Although
we believe the estimates we have made with respect to the valuation of our coal
and parts and supplies inventories are reasonable and appropriate, changes in
assumptions (coal inventories) or actual utilization of items (parts and
supplies inventories) could materially impact our reported financial
results.
62
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.
Coal lands and mineral rights are
depleted using the units-of-production method, based on estimated recoverable
interest. The coal lands and mineral rights fair values are established by
either using engineering studies or market values as established when coal lands
and mineral rights are purchased on the open market. These values are then
evaluated as to the number of recoverable tons contained in a particular mining
area. Once the coal lands and mineral rights values are established, and the
number of recoverable tons contained in a particular coal lands and mineral
rights area is determined, a “units-of-production” depletion rate can be
calculated. This rate is then utilized to calculate depletion expense for each
period mining is conducted on a particular coal lands and mineral rights
area.
Any uncertainty surrounding the
application of the depletion policy is directly related to the assumptions as to
the number of recoverable tons contained in a particular coal lands and mineral
rights area. The amount of compensation paid for the coal lands and mineral
rights is a set amount; however, the “recoverable tons” contained in the coal
lands and mineral rights area are based on engineering estimates which can, and
often do, change as the tons are mined. Any change in the number of “recoverable
tons” contained in a coal lands and mineral rights area will result in a change
in the depletion rate and corresponding depletion expense. For the year ended
December 31, 2008, we recorded $2.0 million of depletion
expense.
Mine development costs are amortized
using the units-of-production method, based on estimated recoverable tons in the
same manner described above.
Other property, plant and equipment are
depreciated using the straight-line method based on estimated useful
lives.
Coal Reserves
There
are numerous uncertainties inherent in estimating quantities of economically
recoverable coal reserves, many of which are beyond our control. As a result,
estimates of economically recoverable coal reserves are by their nature
uncertain. Information about our reserves consists of estimates based on
engineering, economic and geological data assembled by our internal engineers
and geologists. Reserve estimates
are periodically updated to reflect past coal production, new drilling
information and other geologic or mining data. Acquisitions, sales or
dispositions of coal properties will also change the reserves. Some of
the factors and assumptions that impact economically recoverable reserve
estimates include: (i) geological conditions; (ii) historical production from
the area compared with production from other producing areas; (iii) the assumed
effects of regulations and taxes by governmental agencies; (iv) assumptions
governing future prices; and (v) future operating costs.
Each
of these factors may in fact vary considerably from the assumptions used in
estimating reserves. For these reasons, estimates of the economically
recoverable quantities of coal attributable to a particular group of properties,
and classifications of these reserves based on risk of recovery and estimates of
future net cash flows, may vary substantially. Actual production, revenues and
expenditures with respect to reserves will likely vary from estimates, and these
variances may be material. At December 31, 2008, we had 1.0 billion tons of coal
reserves.
Goodwill
As a result of a prior acquisition, we
had assigned goodwill to our ADDCAR reporting unit based upon its estimated fair
value. Pursuant to SFAS No. 142, goodwill and intangible assets that are
determined to have an indefinite useful life are not amortized, but instead must
be tested for impairment at least annually, and more frequently if a triggering
event occurs. We perform our impairment test as of October 31 each year.
The goodwill impairment test consists of two steps. The first identifies
potential impairment by comparing the fair value of a reporting unit with its
carrying amount, including goodwill. Fair value of a reporting unit is estimated
using present value techniques, such as discounted cash flows of projected
future operations developed by management or a weighting of income and market
approaches. If the fair value of the reporting unit exceeds the carrying amount,
goodwill is not considered impaired and the second step is not necessary. If the
carrying value of the reporting unit exceeds the fair value, the second step is
necessary to measure the amount of impairment loss by comparing the implied fair
value of goodwill with its carrying amount. Implied fair value of goodwill is
determined as the amount that the fair value of the assets of a business unit
exceeds their carrying value, excluding goodwill. Impairment loss is measured as
the amount of the carrying value of goodwill that exceeds its implied fair
value. We performed an impairment test of goodwill related to our ADDCAR
subsidiary as of October 31, 2008. The results of the 2008 annual
impairment test indicated that its estimated fair value was less than the
carrying amount of the respective business unit assets, including goodwill, and,
therefore, was impaired. As a result, we recorded a $30.2 million non-cash
impairment charge to reduce the carrying amount of these assets to their
estimated fair value. Subsequent to this impairment charge, we have no goodwill
remaining as of December 31, 2008.
Asset Impairments
We follow SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets, which requires that projected future
cash flows from use and disposition of assets be compared with the carrying
amounts of those assets when impairment indicators are present. When the sum of
projected cash flows is less than the carrying amount, impairment losses are
indicated. If the fair value of the assets is less than the carrying amount of
the assets, an impairment loss is recognized. In determining such impairment
losses, discounted cash flows or asset appraisals are utilized to determine the
fair value of the assets being evaluated. Also, in certain situations, expected
mine lives are shortened because of changes to planned operations. When that
occurs and it is determined that the mine’s underlying costs are not recoverable
in the future, reclamation and mine closing obligations are accelerated and the
mine closing accrual is increased accordingly. To the extent it is determined
asset carrying values will not be recoverable during a shorter mine life, a
provision for such impairment is recognized. Recognition of an impairment will
decrease asset values, increase operating expenses and decrease net income.
In December 2008, we made the decision to permanently close our Sago mine
during the first quarter of 2009. Upon making this decision, we performed an
impairment test of related mine development costs, which resulted in a $7.2
million non-cash impairment charge to reduce the carrying amount of these assets
to their estimated fair value. There were no other impairment charges related to
long-lived assets recognized in 2008 as a result of our impairment
tests.
63
Derivative
Financial Instruments
We
use derivative financial instruments to manage interest rate risk. We do not use
derivative financial instruments for trading or speculative purposes. Statement
of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended (“SFAS No. 133”),
establishes accounting and reporting standards for derivative instruments and
hedging activities. To qualify for hedge accounting under SFAS No. 133, the
effectiveness of each hedging relationship is assessed both at hedge inception
and at each reporting period thereafter. Also, at the end of each reporting
period, ineffectiveness in the hedging relationships is measured as the
difference between the change in fair value of the derivative instruments and
the change in fair value of either the hedged items (fair value hedges) or
expected cash flows (cash flow hedges). Ineffectiveness, if any, is recorded in
interest expense. We have not designated our derivatives as hedging instruments
and we recognize changes in the fair value of our derivatives in earnings in the
period of change.
We enter into coal supply contracts
with many of our customers.
Certain of these
agreements meet the definition of a derivative
under SFAS No. 133. We analyze these agreements for qualification for the normal
purchase, normal sale exception under the standard. We enter into the contracts with the
intent to supply the related coal and do not trade the contracts. If we change our intentions with
respect to delivery on or operation of these contracts, the accounting for the
contracts could change.
Coal
Supply Agreements
We
have allocated purchase price to below-market coal supply agreements acquired in
acquisitions accounted for as business combinations. In accordance with
SFAS No. 141, Business Combinations, value
was allocated to coal supply agreements based on discounted cash flows
attributable to the difference between the below-market contract price and the
prevailing market price at the date of acquisition and was capitalized and is
being amortized on the basis of coal to be shipped over the term of the
contracts. Determination of fair value requires management’s judgment and often
involves the use of significant estimates and assumptions.
Stock-Based
Compensation
We
account for our stock-based awards in accordance with SFAS No. 123(R), Share Based Payment (“SFAS
No. 123(R)”). Under SFAS No. 123(R), stock-based compensation
expense is generally measured at the grant date and recognized as expense over
the vesting period of the award. We utilize restricted stock and stock options
as part of our stock-based compensation program. Determining fair value requires
us to make a number of assumptions, including expected term, risk-free rate and
expected volatility. The assumptions used in calculating the fair value of
stock-based awards represent our best estimates, but these estimates involve
inherent uncertainties and the application of management judgment. Although we
believe the assumptions and estimates we have made are reasonable and
appropriate, changes in assumptions could materially impact our reported
financial results.
Debt
Issuance Costs
Debt
issuance costs reflect fees incurred to obtain financing. Debt issuance costs
related to our outstanding debt are amortized over the life of the related debt.
From time to time, we write-off deferred financing fees as a result of amending
or canceling related credit agreements. Such write-offs could be material and
occur in the period that the decision to amend or cancel the related credit
agreement is made.
Income Taxes
We account for income taxes in
accordance with SFAS No. 109, which requires the recognition of deferred
tax assets and liabilities using enacted tax rates for the effect of temporary
differences between the book and tax basis of recorded assets and liabilities.
SFAS No. 109 also requires that deferred tax assets be reduced by a
valuation allowance, if it is more likely than not that some portion or all of
the deferred tax asset will not be realized. In evaluating the need for a
valuation allowance, we take into account various factors, including the timing
of the realization of deferred tax liabilities, the expected level of future
taxable income and available tax planning strategies. If future taxable income
is lower than expected or if expected tax planning strategies are not available
as anticipated, we may record a change to the valuation allowance through income
tax expense in the period the determination is made.
Postretirement Medical
Benefits
Some of our subsidiaries have long- and
short-term liabilities for postretirement benefit cost obligations. Detailed
information related to these liabilities is included in the notes to our
consolidated financial statements included elsewhere in this report. Liabilities
for postretirement benefits are not funded. The liability is actuarially
determined and we use various actuarial assumptions, including the discount rate
and future cost trends, to estimate the costs and obligations for postretirement
benefits. The discount rate assumption reflects the rates available on a
hypothetical portfolio of high-quality fixed income debt instruments whose cash
flows match the timing and amount of expected benefit payments. The discount
rate used to determine the net periodic benefit cost for postretirement medical
benefits was 6.25% for the year ended December 31, 2008. We make assumptions
related to future trends for medical care costs in the estimates of retiree
healthcare and work-related injury and illness obligations. The future
healthcare cost trend rate represents the rate at which healthcare costs are
expected to increase over the life of the plan. The healthcare cost trend rate
assumptions are determined primarily based upon our, and our predecessor’s,
historical rate of change in retiree healthcare costs. The postretirement
expense in the operating period ended December 31, 2008 was based on an assumed
heath care inflationary rate of 8.3% in the operating period decreasing to 5.0%
in 2015, which represents the ultimate healthcare cost trend rate for the
remainder of the plan life. A one-percentage point increase in the assumed
ultimate healthcare cost trend rate would increase the service and interest cost
components of the postretirement benefit expense for the year ended December 31,
2008 by $0.4 million and increase the accumulated postretirement benefit
obligation at December 31, 2008 by $1.8 million. A one-percentage point decrease
in the assumed ultimate healthcare cost trend rate would decrease the service
and interest cost components of the postretirement benefit expense for the year
ended December 31, 2008 by $0.4 million and decrease the accumulated
postretirement benefit obligation at December 31, 2008 by $1.7 million. If our
assumptions do not materialize as expected or if regulatory changes were to
occur, actual cash expenditures and costs that we incur could differ materially
from our current estimates.
64
Workers’
Compensation
Workers’
compensation is a system by which individuals who sustain personal injuries due
to job-related accidents are compensated for their disabilities, medical costs
and, on some occasions, for the costs of their rehabilitation, and by which the
survivors of workers who suffer fatal injuries receive compensation for lost
financial support. The workers’ compensation laws are administered by state
agencies with each state having its own rules and regulations regarding
compensation that is owed to an employee who is injured in the course of
employment or the beneficiary of an employee that suffers fatal injuries in the
course of employment. Our operations are covered through a combination of
participation in a state run program and insurance policies. Our estimates of
these costs are adjusted based upon actuarially determined amounts using a
discount rate of 5.50% as of December 31, 2008. The discount rate assumption
reflects the rates available on a hypothetical portfolio of high-quality fixed
income debt instruments whose cash flows match the timing and amount of expected
benefit payments. If we were to decrease our estimate of the discount rate to
4.5%, the present value of our workers’ compensation liability would increase by
approximately $0.4 million. If we were to increase our estimate of the discount
rate to 6.5%, the present value of our workers’ compensation liability would
decrease by approximately $0.2 million. At December 31, 2008, we have recorded
an accrual of $7.8 million for workers’ compensation benefits. Actual losses may
differ from these estimates, which could increase or decrease our
costs.
Coal Workers’
Pneumoconiosis
We are responsible under various federal
statutes, and various states’ statutes, for the payment of medical and
disability benefits to eligible employees resulting from occurrences of coal
workers’ pneumoconiosis disease (black lung). Our operations are covered through
a combination of participation in a state run program and insurance policies. We
accrue for any self-insured liability by recognizing costs when it is probable
that a covered liability has been incurred and the cost can be reasonably
estimated. Our estimates of these costs are adjusted based upon actuarially
determined amounts using a discount rate of 5.75% as of December 31,
2008. The discount rate assumption reflects
the rates available on a hypothetical portfolio of high-quality fixed income
debt instruments whose cash flows match the timing and amount of expected
benefit payments. If we were to decrease our estimate of the discount
rate to 4.75%, the present value of our black lung benefit liability would
increase by approximately $13.7 million. If we were to increase our estimate of
the discount rate to 6.75%, the present value of our black lung benefit
liability would decrease by approximately $10.1 million. At December 31, 2008, we have recorded an accrual
of $27.5 million for black lung benefits. Individual losses in excess of $0.5
million at the state level and $0.5 million at the federal level are covered by
our large deductible stop loss insurance. Actual losses may differ from these
estimates, which could increase or decrease our costs.
Coal Industry Retiree Health Benefit Act
of 1992
The Coal Industry
Retiree Health Benefit Act of 1992 (the “Coal Act”) provides for the funding of
health benefits for certain union retirees and their spouses or dependants. The
Coal Act established the Combined Fund into which employers who are “signatory
operators” and “related persons” are obligated to pay annual premiums for
beneficiaries. The Coal Act also created a second benefit fund for miners who
retired between July 21, 1992 and September 30, 1994 and whose former
employers are no longer in business. Upon the consummation of the
business combination with Anker, we assumed Anker’s Coal Act liabilities, which
were estimated to be $1.3 million at December 31, 2008. Actual losses may differ from these
estimates, which could increase or decrease our costs. Our estimates of these
costs are adjusted based upon actuarially determined amounts using a discount rate of 6.25% as of
December 31, 2008. The discount rate
assumption reflects the rates available on a hypothetical portfolio of
high-quality fixed income debt instruments whose cash flows match the timing and
amount of expected benefit payments. If we were to decrease our estimate of
the discount rate to 5.25%, the present value of our Coal Act liability would
increase by approximately $0.9 million. If we were to increase our estimate of
the discount rate to 7.25%, the present value of our Coal Act liability would
decrease by approximately $0.8 million. Prior to the business
combination with Anker, we did not have any liability under the Coal
Act.
65
Results of
Operations
Revenues, coal sales revenues by
operating segment and tons sold by operating segment
The following table depicts revenues for
the years ended December 31, 2008 and 2007 for the indicated
categories:
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2008
|
|
|
2007
|
|
|
$ or Tons
|
|
%
|
|
|
|
(in thousands, except percentages and per ton data)
|
|
Coal sales
revenues
|
|
$
|
998,245
|
|
|
$
|
770,663
|
|
|
$
|
227,582
|
|
30
|
%
|
Freight and handling
revenues
|
|
|
45,231
|
|
|
|
29,594
|
|
|
|
15,637
|
|
53
|
%
|
Other
revenues
|
|
|
53,260
|
|
|
|
48,898
|
|
|
|
4,362
|
|
9
|
%
|
Total
revenues
|
|
|
1,096,736
|
|
|
|
849,155
|
|
|
|
247,581
|
|
29
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
18,914
|
|
|
|
18,343
|
|
|
|
571
|
|
3
|
%
|
Coal sales revenue per
ton
|
|
$
|
52.78
|
|
|
$
|
42.01
|
|
|
$
|
10.77
|
|
26
|
%
|
The following table depicts coal sales
revenues by operating segment for years ended December 31, 2008 and
2007:
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Central
Appalachian
|
|
$
|
672,077
|
|
|
$
|
512,352
|
|
|
$
|
159,725
|
|
31
|
%
|
Northern
Appalachian
|
|
|
209,932
|
|
|
|
121,200
|
|
|
|
88,732
|
|
73
|
%
|
Illinois Basin
|
|
|
69,796
|
|
|
|
60,368
|
|
|
|
9,428
|
|
16
|
%
|
Ancillary
|
|
|
46,440
|
|
|
|
76,743
|
|
|
|
(30,303
|
)
|
(39
|
)%
|
Total coal sales
revenues
|
|
$
|
998,245
|
|
|
$
|
770,663
|
|
|
$
|
227,582
|
|
30
|
%
|
The following table depicts tons sold by
operating segment for the years ended December 31, 2008 and 2007:
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2008
|
|
|
2007
|
|
|
Tons
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Central
Appalachian
|
|
|
11,617
|
|
|
|
11,323
|
|
|
|
294
|
|
3
|
%
|
Northern
Appalachian
|
|
|
3,937
|
|
|
|
3,291
|
|
|
|
646
|
|
20
|
%
|
Illinois Basin
|
|
|
2,331
|
|
|
|
2,025
|
|
|
|
306
|
|
15
|
%
|
Ancillary
|
|
|
1,029
|
|
|
|
1,704
|
|
|
|
(675
|
)
|
(40
|
)%
|
Total tons sold
|
|
|
18,914
|
|
|
|
18,343
|
|
|
|
571
|
|
3
|
%
|
Coal sales
revenues—Coal sales
revenues are derived from sales of produced coal and brokered coal contracts.
Coal sales revenues increased for the year ended December 31, 2008 compared to the year ended December 31, 2007 due to a 26% increase in sales realization per ton
resulting from increased spot market and short-term contract sales entered
into in order to capitalize on favorable market conditions during the first three quarters of
2008. Further impacting the
increase in coal sales revenue was a 3% increase in tons sold compared to the
same period of 2007. Partially offsetting the impact of improved realization per
ton and the increase in tons sold was a decrease in coal sales revenues
attributable to the expiration of certain brokered coal
contracts.
Central
Appalachian. Coal sales
revenues from our Central Appalachian segment for the year ended December 31, 2008
increased over the same
period in 2007 primarily due to an increase of $12.61 per ton, which was driven by higher
average prices of our coal sold pursuant to short-term supply agreements and on the spot market, including
increased sales of metallurgical coal,
primarily from increased production at our new Beckley
operation.
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.
66
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.
67
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 operating segment for the years ended December 31, 2008 and
2007:
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Central
Appalachian
|
|
$
|
595,683
|
|
|
$
|
468,958
|
|
|
$
|
126,725
|
|
27
|
%
|
Northern
Appalachian
|
|
|
193,389
|
|
|
|
147,745
|
|
|
|
45,644
|
|
31
|
%
|
Illinois Basin
|
|
|
57,424
|
|
|
|
46,701
|
|
|
|
10,723
|
|
23
|
%
|
Ancillary
|
|
|
36,487
|
|
|
|
68,708
|
|
|
|
(32,221
|
)
|
(47
|
)%
|
Cost of coal
sales
|
|
$
|
882,983
|
|
|
$
|
732,112
|
|
|
$
|
150,871
|
|
21
|
%
|
Cost of coal
sales—For the year ended December 31, 2008, our cost of coal sales increased
compared to the year ended
December 31, 2007 primarily
as a result of a 17% increase in cost per ton, as well as a
3% increase in tons sold as described
above.
Central
Appalachian. Cost of coal
sales from our Central Appalachian segment increased to $51.28 per ton for the year ended December 31, 2008
from $41.42 per ton for the year ended December 31, 2007
primarily as a result of
increased labor and
diesel fuel costs. Labor
and benefit costs increased due to a tightening labor market resulting in the
need to offer more competitive compensation packages. Diesel fuel costs
increased over prior period as a result of higher per gallon fuel costs and
additional gallons used. Further impacting the increase in cost of coal sales
were increases in repairs and maintenance costs, contract labor costs,
royalties, severance taxes and reclamation costs.
Northern
Appalachian. Our Northern
Appalachian segment cost of coal sales per ton increased to $49.13 for the year ended December 31, 2008
from $44.89 for the year ended December 31, 2007
due to increased
labor, diesel fuel and repairs and maintenance
costs resulting from certain high-dollar repairs performed during 2008. Additionally, royalties, severance taxes and trucking
costs increased at our
Northern Appalachian segment primarily due to increased coal
sales. Partially offsetting
these increases was a
decrease in purchased coal costs due to increased production at our Vindex and
Sentinel complexes.
Illinois Basin. For the year ended December 31, 2008, our Illinois Basin cost of coal sales increased by
$1.57 per ton primarily due to increased labor, roof control supplies
and repairs and maintenance costs. Labor increased as demand for skilled miners
increased over 2007.
Roof control supplies
increased as prices for steel were escalated for much of 2008. Additionally, repairs and maintenance
costs have increased due to several repairs on underground mining equipment
during 2008. Partially offsetting the
aforementioned increases was a decrease in royalty expense resulting from increased
mining of owned reserves rather than leased reserves as compared to
2007.
Ancillary. Cost of coal sales from our Ancillary
segment decreased for the year ended December 31, 2008
primarily due to
a decrease in purchased coal costs related to the expiration of certain
brokered coal contracts.
68
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.
69
Adjusted EBITDA by Operating
Segment
Adjusted EBITDA represents net income
before deducting interest expense, income taxes, depreciation, depletion,
amortization, impairment charges and minority 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 minority 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 71 of this Annual Report on Form 10-K and in Note 20 to our
consolidated financial statements for the year ended December 31,
2008.
The following table depicts operating
segment Adjusted EBITDA for the years ended December 31, 2008 and
2007:
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Central
Appalachian
|
|
$
|
107,186
|
|
|
$
|
47,442
|
|
|
$
|
59,744
|
|
126
|
%
|
Northern
Appalachian
|
|
|
23,687
|
|
|
|
(22,215
|
)
|
|
|
45,902
|
|
207
|
%
|
Illinois Basin
|
|
|
14,784
|
|
|
|
15,463
|
|
|
|
(679
|
)
|
(4
|
)%
|
Ancillary
|
|
|
(18,436
|
)
|
|
|
18,363
|
|
|
|
(36,799
|
)
|
(200
|
)%
|
Total Adjusted
EBITDA
|
|
$
|
127,221
|
|
|
$
|
59,053
|
|
|
$
|
68,168
|
|
115
|
%
|
Adjusted EBITDA from
our Central Appalachian segment for the year ended December 31, 2008 increased compared to the year ended December 31, 2007 primarily due to a $24.6 million
pre-tax gain on an exchange of coal reserves. The increase was further impacted
by an increase of approximately 294,000 tons sold and an increase in profit
margins of $2.74 per ton over prior year.
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.
70
Reconciliation of Adjusted EBITDA to Net
income (loss) by Operating Segment
The following tables reconcile Adjusted
EBITDA to net income (loss) by operating segment for the years ended December
31, 2008 and 2007:
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Central
Appalachian
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
47,244
|
|
|
$
|
(184,372
|
)
|
|
$
|
231,616
|
|
126
|
%
|
Depreciation, depletion and
amortization
|
|
|
64,132
|
|
|
|
60,015
|
|
|
|
4,117
|
|
7
|
%
|
Interest expense,
net
|
|
|
2,145
|
|
|
|
1,397
|
|
|
|
748
|
|
54
|
%
|
Income tax
benefit
|
|
|
(6,335
|
)
|
|
|
—
|
|
|
|
(6,335
|
)
|
(100
|
)%
|
Impairment
loss
|
|
|
—
|
|
|
|
170,402
|
|
|
|
(170,402
|
)
|
(100
|
)%
|
Adjusted
EBITDA
|
|
$
|
107,186
|
|
|
$
|
47,442
|
|
|
$
|
59,744
|
|
126
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Northern
Appalachian
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
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
|
%
|
Minority
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 Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
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)
|
|
Ancillary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
(82,070
|
)
|
|
$
|
60,414
|
|
|
$
|
(142,484
|
)
|
(236
|
)%
|
Depreciation, depletion and
amortization
|
|
|
6,689
|
|
|
|
10,508
|
|
|
|
(3,819
|
)
|
(36
|
)%
|
Interest expense,
net
|
|
|
37,918
|
|
|
|
33,064
|
|
|
|
4,854
|
|
15
|
%
|
Income tax
benefit
|
|
|
(11,210
|
)
|
|
|
(85,623
|
)
|
|
|
74,413
|
|
87
|
%
|
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)
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(24,650
|
)
|
|
$
|
(147,034
|
)
|
|
$
|
122,384
|
|
83
|
%
|
Depreciation, depletion and
amortization
|
|
|
96,047
|
|
|
|
86,517
|
|
|
|
9,530
|
|
11
|
%
|
Interest expense,
net
|
|
|
41,107
|
|
|
|
35,140
|
|
|
|
5,967
|
|
17
|
%
|
Income tax
benefit
|
|
|
(22,711
|
)
|
|
|
(85,623
|
)
|
|
|
62,912
|
|
73
|
%
|
Impairment
loss
|
|
|
37,428
|
|
|
|
170,402
|
|
|
|
(132,974
|
)
|
(78
|
)%
|
Minority
interest
|
|
|
—
|
|
|
|
(349
|
)
|
|
|
349
|
|
100
|
%
|
Adjusted
EBITDA
|
|
$
|
127,221
|
|
|
$
|
59,053
|
|
|
$
|
68,168
|
|
115
|
%
|
71
Revenues
The following table depicts revenues for
the years ended December 31, 2007 and 2006 for the indicated
categories:
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
$ or Tons
|
|
%
|
|
|
|
(in thousands, except percentages and per ton data)
|
|
Coal sales
revenues
|
|
$
|
770,663
|
|
|
$
|
833,998
|
|
|
$
|
(63,335
|
)
|
(8
|
)%
|
Freight and handling
revenues
|
|
|
29,594
|
|
|
|
18,890
|
|
|
|
10,704
|
|
57
|
%
|
Other
revenues
|
|
|
48,898
|
|
|
|
38,706
|
|
|
|
10,192
|
|
26
|
%
|
Total
revenues
|
|
$
|
849,155
|
|
|
$
|
891,594
|
|
|
$
|
(42,439
|
)
|
(5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
18,343
|
|
|
|
19,371
|
|
|
|
(1,028
|
)
|
(5
|
)%
|
Coal sales revenue per
ton
|
|
$
|
42.01
|
|
|
$
|
43.05
|
|
|
$
|
(1.04
|
)
|
(2
|
)%
|
Coal sales
revenues. Coal sales
revenues are derived from sales of produced coal and brokered coal contracts.
Coal sales revenues decreased $63.3 million for the year ended December 31,
2007, or 8%, compared to 2006. This decrease was due to a 5% decrease in tons
sold in 2007 compared to 2006 that resulted from a decrease of approximately
4.7 million tons sold related to the idling, closure or cutback of
production at mines in 2007 as discussed below and the expiration of certain
brokered coal contracts, as well as geologic issues at several other mines. The
decrease in coal sales revenue from decreased sales tons was further impacted by
a $1.04 per ton reduction in sales realization of our coal primarily sold
pursuant to coal supply agreements. These decreases were partially offset by a
3.4 million ton increase in tons sold from new mines that commenced full
production in 2007 and from mines that experienced a full year of production in
2007.
Freight and handling
revenues. Freight and
handling revenues represent dollar-for-dollar reimbursement for shipments from
certain of our operations for which we initially pay the freight and handling
costs and are then reimbursed by the customer. Freight and handling revenues and
costs increased $10.7 million to $29.6 million for the year ended
December 31, 2007 compared to 2006 due to an increase in shipments from
locations operating under such agreements, as well as increased transportation
rates and fuel surcharges.
Other
revenues. Other
revenues increased $10.2 million for the year ended December 31, 2007
compared to 2006. The increase was due to $6.8 million of revenue generated from
coalbed methane wells owned jointly by our subsidiary, CoalQuest, and CDX, as
well as increased revenue of $3.7 million from our highwall mining activities
and shop services and $7.2 million from the sale of a narrow bench highwall
mining system by ADDCAR. Partially offsetting these increases was a decrease in
plant processing revenue of $1.1 million. Additionally, we recognized a $7.0
million gain in 2006 related to the termination of a contractual coal delivery
obligation. No comparable gain was recognized in 2007.
72
Coal sales revenues and tons sold by
segment
The following table depicts coal sales
revenues by operating segment for the years ended December 31, 2007 and
2006:
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Central
Appalachian
|
|
$
|
512,352
|
|
|
$
|
534,429
|
|
|
$
|
(22,077
|
)
|
(4
|
)%
|
Northern
Appalachian
|
|
|
121,200
|
|
|
|
109,184
|
|
|
|
12,016
|
|
11
|
%
|
Illinois Basin
|
|
|
60,368
|
|
|
|
49,842
|
|
|
|
10,526
|
|
21
|
%
|
Ancillary
|
|
|
76,743
|
|
|
|
140,543
|
|
|
|
(63,800
|
)
|
(45
|
)%
|
Total coal sales
revenues
|
|
$
|
770,663
|
|
|
$
|
833,998
|
|
|
$
|
(63,335
|
)
|
(8
|
)%
|
The following table depicts tons sold by
operating segment for the years ended December 31, 2007 and
2006:
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
Tons
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Central
Appalachian
|
|
|
11,323
|
|
|
|
10,904
|
|
|
|
419
|
|
4
|
%
|
Northern
Appalachian
|
|
|
3,291
|
|
|
|
3,281
|
|
|
|
10
|
|
*
|
%
|
Illinois Basin
|
|
|
2,025
|
|
|
|
2,020
|
|
|
|
5
|
|
*
|
%
|
Ancillary
|
|
|
1,704
|
|
|
|
3,166
|
|
|
|
(1,462
|
)
|
(46
|
)%
|
Total tons sold
|
|
|
18,343
|
|
|
|
19,371
|
|
|
|
(1,028
|
)
|
(5
|
)%
|
Coal sales revenues from our Central
Appalachian segment decreased approximately $22.1 million, or 4%, for the year
ended December 31, 2007 as compared to the year ended December 31,
2006. This decrease was primarily attributable to a decrease of $3.76 per ton in
the average sales price of our coal primarily sold pursuant to coal supply
agreements. The decrease in sales realization was partially offset by an
increase in tons sold of approximately 0.4 million, or 4%, over 2006 due to
various mines, principally at our Eastern and Raven locations, significantly
increasing or reaching full production in 2007.
For the year ended December 31,
2007, our Northern Appalachian coal sales revenues increased approximately $12.0
million, or 11%, as compared to 2006 due to an increase in sales realization of
$3.55 per ton as segment operations benefited from favorable pricing from its
coal supply agreements, as well as an increase in sales of metallurgical coal at
prevailing market prices. Tons sold from our Northern Appalachian operations
remained constant as compared to the prior year.
Coal sales revenues from our
Illinois Basin segment increased approximately $10.5
million, or 21%, as compared to 2006 due to an increase in coal sales revenue of
$5.12 per ton resulting from more favorable terms on its coal supply
agreements.
Our Ancillary segment’s coal sales
revenues are comprised of coal sold under brokered coal contracts. We
experienced a decrease of $63.8 million, or 45%, due to a decrease of
1.5 million tons primarily resulting from the expiration of brokered coal
contracts.
73
Costs and expenses
The following table depicts cost of
operations for the years ended December 31, 2007 and 2006 for the indicated
categories:
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages and per ton data)
|
|
Cost of coal
sales
|
|
$
|
732,112
|
|
|
$
|
739,914
|
|
|
$
|
(7,802
|
)
|
(1
|
)%
|
Freight and handling
costs
|
|
|
29,594
|
|
|
|
18,890
|
|
|
|
10,704
|
|
57
|
%
|
Cost of other
revenues
|
|
|
34,046
|
|
|
|
29,418
|
|
|
|
4,628
|
|
16
|
%
|
Depreciation, depletion and
amortization
|
|
|
86,517
|
|
|
|
72,218
|
|
|
|
14,299
|
|
20
|
%
|
Selling, general and
administrative expenses
|
|
|
33,325
|
|
|
|
34,578
|
|
|
|
(1,253
|
)
|
(4
|
)%
|
Net gain on sale of
assets
|
|
|
(38,656
|
)
|
|
|
(1,125
|
)
|
|
|
(37,531
|
)
|
*
|
%
|
Goodwill impairment
loss
|
|
|
170,402
|
|
|
|
—
|
|
|
|
170,402
|
|
100
|
%
|
Total costs and
expenses
|
|
$
|
1,047,340
|
|
|
$
|
893,893
|
|
|
$
|
153,447
|
|
17
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales per
ton
|
|
$
|
39.91
|
|
|
$
|
38.20
|
|
|
$
|
1.71
|
|
4
|
%
|
Cost of coal
sales. For the year
ended December 31, 2007, our total cost of coal sales decreased $7.8
million, or 1%, to $732.1 million compared to $739.9 million for the year ended
December 31, 2006. The decrease in cost of coal sales was primarily the
result of a 5% decrease in tons sold as described above which was partially
offset by a 4% increase in cost per ton.
Mining operations that significantly
increased or reached full production in 2007 at our East Mac and Nellie, Flint
Ridge Deep, Raven, Mt. Sterling, Guston Run, Crown Surface, Imperial, Sentinel,
County Line and Middle Fork mines increased cost of coal sales by $144.0
million. Increased costs from new mining operations were partially offset by a
decrease in costs of $111.9 million resulting from the closure or cutback of
production at our higher cost Flint Ridge Surface, Rowdy Gap, Flint Ridge
Highwall, Blackberry Creek, New Hill, Sago, Crown East II, Sycamore No. 1,
Island, Tip Top and Elk Hollow mines. Cost of
coal sales at existing mines, as well as from brokered coal contracts, decreased
$40.5 million, primarily as a result of a 1.1 million ton decrease in
coal sales.
Cost of coal sales per ton increased to
$39.91 for the year ended December 31, 2007 compared to $38.20 in 2006, an
increase of $1.71. The increase was mainly due to a $1.34 per ton increase in
the average cost of produced coal sold. The increase in cost per ton of produced
coal was caused by increases of: $0.46 per ton in labor and benefit costs; $0.27
per ton in contract labor; $0.44 per ton insurance and worker’s compensation
costs; $0.18 per ton in fuel, oil and lubricants; $0.26 per ton in blending
material; $0.10 per ton in insurance; and $0.20 per ton in roof control
supplies. The increases were partially offset by decreases of: $0.52 per ton in
equipment and vehicle lease costs. Purchased coal increased $3.87 per ton,
resulting in an increase of $0.38 per ton in the average cost of coal
sold.
Cost of other
revenues. For the year
ended December 31, 2007, cost of other revenues increased $4.6 million, or
16%, to $34.0 million compared to $29.4 million for the year ended
December 31, 2006. Of the increase, approximately $4.7 million was due to
costs related to ADDCAR’s sales of mining equipment during the year and
exploration and development of coalbed methane resulted in an additional
increase of $1.8 million.
Depreciation,
depletion and amortization. Depreciation, depletion and
amortization expense increased $14.3 million, or 20%, to $86.5 million for the
year ended December 31, 2007 compared to $72.2 million in 2006. The
principal component of the increase was an increase in depreciation and
amortization expense of $14.5 million for the year ended December 31, 2007
related to increased property and equipment purchased to improve efficiency at
existing operations and to equip new mine developments. Additional increases in
depreciation and amortization expense were due to coalbed methane well
development costs of $5.5 million. The increases were partially offset by an
increase in amortization income on below-market coal supply agreements of $5.7
million during the year ended December 31, 2007.
Selling, general and
administrative expenses. Selling, general and
administrative expenses for the year ended December 31, 2007 were $33.3
million compared to $34.6 million for the year ended December 31, 2006. The
decrease of $1.3 million was primarily attributable to gifts aggregating $2.0
million made in 2006 to the families of the thirteen miners involved in the Sago
mine accident, partially offset by an increase of $1.3 million in professional
and legal fees.
Net gain on sale of
assets. Net gain on
sale of assets increased $37.5 million for the year ended December 31, 2007
from 2006, primarily due to a gain of approximately $36.8 million related to the
sale of our Denmark property in the third quarter of
2007.
Goodwill impairment
loss. The goodwill
impairment loss reflects the negative impact of several contributing factors
which resulted in a reduction in the forecasted cash flows used to estimate fair
value. These factors include, but are not limited to, a significant decrease in
the sales price of coal through our annual measurement date, increases in the
cost of diesel fuel, explosives, tires, roofbolts and other materials used in
mining coal, increased labor costs due to tightening labor markets, significant
investments in the areas of safety and compliance and increased interest rates
contributing to a higher discount rate. Furthermore, the business, regulatory
and marketplace environments in which we currently operate differs significantly
from the historical environments that drove the business cases used to value and
record the acquisition of these business units. Accordingly, we have been unable
to attain the forecasted projections that were used to initially value the
business units at the date of acquisition. The goodwill impairment losses were
at the following business units: $32.9 million at Hazard, $58.5 million at
Eastern, $43.0 million at East Kentucky and $36.0 million at Knott County.
74
Adjusted EBITDA by
Segment
Adjusted EBITDA represents net income
before deducting interest expense, income taxes, depreciation, depletion,
amortization, impairment charges and minority 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 minority interest. Adjusted EBITDA is calculated
differently than the prior year in that it includes an adjustment for impairment
charges. No impairment charges were incurred in the prior year. Other companies
in our industry may calculate Adjusted EBITDA differently than we do, limiting
its usefulness as a comparative measure. Adjusted EBITDA is reconciled to its
most comparable GAAP measure on page 76 of this Annual Report on Form 10-K and
in Note 20 to our consolidated financial statements for the year ended
December 31, 2007.
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Central
Appalachian
|
|
$
|
47,442
|
|
|
$
|
108,598
|
|
|
$
|
(61,156
|
)
|
(56
|
)%
|
Northern
Appalachian
|
|
|
(22,215
|
)
|
|
|
(36,586
|
)
|
|
|
14,371
|
|
39
|
%
|
Illinois Basin
|
|
|
15,463
|
|
|
|
4,476
|
|
|
|
10,987
|
|
245
|
%
|
Ancillary
|
|
|
18,363
|
|
|
|
(4,456
|
)
|
|
|
22,819
|
|
512
|
%
|
Total Adjusted
EBITDA
|
|
$
|
59,053
|
|
|
$
|
72,032
|
|
|
$
|
(12,979
|
)
|
(18
|
)%
|
Adjusted EBITDA from our Central
Appalachian segment decreased $61.2 million, or 56%, for the year ended
December 31, 2007 as compared to the year ended December 31, 2006. The
decrease was primarily due to the decreased realization per ton as discussed
above. Also impacting the decrease were inflated operating costs per ton
primarily resulting from regulatory issues and short-term mine constraints. The
reduced realizations and increased costs resulted in a decrease in profit
margins of $5.99 per ton. Additionally, activities incidental to our coal
producing activities decreased by $1.5 million in 2007 further contributing to
the decrease in Adjusted EBITDA.
The increase in Adjusted EBITDA from our
Northern Appalachian segment of $14.4 million for the year ended
December 31, 2007 was primarily due to an increase in coal sales revenue as
of $3.55 per ton and decreased costs of $1.02 per ton resulting in increased
profit margins of $4.57 per ton.
Adjusted EBITDA from our Illinois Basin segment increased $11.0 million during
the year ended December 31, 2007 due to a $5.12 per ton increase in sales
realization over 2006 with cost per ton remaining constant with prior
year.
The increase in Adjusted EBITDA from our
Ancillary segment of $22.8 million was primarily due to the sale of the
Denmark property in September 2007, which
resulted in a gain of $36.8 million, as well as from increased contributions to
income from our investment in coalbed methane wells and from our ADDCAR
subsidiary as discussed above. These increases were partially offset by a
decrease in Adjusted EBITDA resulting from the expiration of brokered coal
contracts.
75
Reconciliation of Adjusted EBITDA to Net
income (loss) by Segment
The following tables reconcile Adjusted
EBITDA to net income (loss) by segment for the years ended December 31,
2007 and 2006:
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Central
Appalachian
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
(184,372
|
)
|
|
$
|
59,620
|
|
|
$
|
(243,992
|
)
|
(409
|
)%
|
Depreciation, depletion and
amortization
|
|
|
60,015
|
|
|
|
48,050
|
|
|
|
11,965
|
|
25
|
%
|
Interest expense,
net
|
|
|
1,397
|
|
|
|
928
|
|
|
|
469
|
|
51
|
%
|
Impairment
loss
|
|
|
170,402
|
|
|
|
—
|
|
|
|
170,402
|
|
100
|
%
|
Adjusted
EBITDA
|
|
$
|
47,442
|
|
|
$
|
108,598
|
|
|
$
|
(61,156
|
)
|
(56
|
)%
|
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Northern
Appalachian
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(31,790
|
)
|
|
$
|
(47,907
|
)
|
|
$
|
16,117
|
|
34
|
%
|
Depreciation, depletion and
amortization
|
|
|
9,467
|
|
|
|
10,822
|
|
|
|
(1,355
|
)
|
(13
|
)%
|
Interest expense,
net
|
|
|
457
|
|
|
|
441
|
|
|
|
16
|
|
4
|
%
|
Minority
interest
|
|
|
(349
|
)
|
|
|
58
|
|
|
|
(407
|
)
|
(702
|
)%
|
Adjusted
EBITDA
|
|
$
|
(22,215
|
)
|
|
$
|
(36,586
|
)
|
|
$
|
14,371
|
|
39
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Illinois Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
8,714
|
|
|
$
|
(1,978
|
)
|
|
$
|
10,692
|
|
541
|
%
|
Depreciation, depletion and
amortization
|
|
|
6,527
|
|
|
|
6,287
|
|
|
|
240
|
|
4
|
%
|
Interest expense,
net
|
|
|
222
|
|
|
|
167
|
|
|
|
55
|
|
33
|
%
|
Adjusted
EBITDA
|
|
$
|
15,463
|
|
|
$
|
4,476
|
|
|
$
|
10,987
|
|
245
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Ancillary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
60,414
|
|
|
$
|
(19,055
|
)
|
|
$
|
79,469
|
|
417
|
%
|
Depreciation, depletion and
amortization
|
|
|
10,508
|
|
|
|
7,059
|
|
|
|
3,449
|
|
49
|
%
|
Interest expense,
net
|
|
|
33,064
|
|
|
|
16,555
|
|
|
|
16,509
|
|
100
|
%
|
Income tax
benefit
|
|
|
(85,623
|
)
|
|
|
(9,015
|
)
|
|
|
(76,608
|
)
|
(850
|
)%
|
Adjusted
EBITDA
|
|
$
|
18,363
|
|
|
$
|
(4,456
|
)
|
|
$
|
22,819
|
|
512
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
|
|
Increase
(Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
%
|
|
|
|
(in thousands, except percentages)
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(147,034
|
)
|
|
$
|
(9,320
|
)
|
|
$
|
(137,714
|
)
|
*
|
%
|
Depreciation, depletion and
amortization
|
|
|
86,517
|
|
|
|
72,218
|
|
|
|
14,299
|
|
20
|
%
|
Interest expense,
net
|
|
|
35,140
|
|
|
|
18,091
|
|
|
|
17,049
|
|
94
|
%
|
Income tax
benefit
|
|
|
(85,623
|
)
|
|
|
(9,015
|
)
|
|
|
(76,608
|
)
|
(850
|
)%
|
Impairment
loss
|
|
|
170,402
|
|
|
|
—
|
|
|
|
170,402
|
|
100
|
%
|
Minority
interest
|
|
|
(349
|
)
|
|
|
58
|
|
|
|
(407
|
)
|
(702
|
)%
|
Adjusted
EBITDA
|
|
$
|
59,053
|
|
|
$
|
72,032
|
|
|
$
|
(12,979
|
)
|
(18
|
)%
|
76
Liquidity and Capital
Resources
Our business is capital intensive and
requires substantial capital expenditures for, among other things, purchasing
and upgrading equipment used in developing and mining our coal lands, as well as
remaining in compliance with environmental laws and regulations. Our principal
liquidity requirements are to finance our coal production, fund capital
expenditures and service our debt and reclamation obligations. We may also
engage in acquisitions from time to time. Our primary sources of liquidity to
meet these needs are cash flows from sales of our coal, other income, borrowings
under our senior credit facility, the proceeds of our convertible notes offering
and capital equipment financing arrangements.
We believe the principal indicators of
our liquidity are our cash position and remaining availability under our credit
facility. As of December 31, 2008, our available liquidity was $90.3 million,
including cash of $63.9 million and $26.4 million available for borrowing under
our $100.0 million senior credit facility. Total debt represented 48% of our
total capitalization at December 31, 2008. Our total capitalization represents
our current and long-term debt combined with our total stockholders’
equity.
In
February 2009, we executed an amendment to our $100.0 million credit facility
that affected certain 2009 debt covenants. The amendment modified the maximum
permitted leverage and minimum interest coverage ratios. The amendment also
decreased the maximum capital spending and added a minimum liquidity
requirement. Debt covenants for years subsequent to 2009 were not affected by
the amendment.
The
recent and unprecedented disruption in the current credit markets has had a
significant adverse impact on a number of financial institutions. At this time,
our liquidity has not been materially impacted by the current credit environment
and we do not expect that it will be materially impacted in the
near-future. We will continue to closely monitor our liquidity and the
credit markets. However, we cannot predict with any certainty the impact to us
of any further disruption in the credit environment. See “Risk Factors – The duration or severity of the current
global financial crisis are uncertain and may have an impact on our business and
financial conditions in ways that we currently cannot predict.”
Our Convertible Senior Notes (the
“Convertible Notes”) became convertible at the option of holders beginning
July 1, 2008. The conversion period expired on September 30, 2008
pursuant to the terms of the governing indenture with no holders exercising
their conversion rights. The Convertible Notes may become
convertible again in the future under certain conditions. Accordingly, we will reassess the convertibility on a
quarterly basis.
We currently expect our total capital
expenditures will be approximately $100.0 million in 2009, substantially all of
which will be for equipment and infrastructure at our existing operations. Cash
paid for capital expenditures was approximately $132.0 million for the year
ended December 31, 2008. We have funded and will continue to fund these capital
expenditures from our internal operations and with proceeds from our convertible
notes offering in 2007. We believe that these sources of capital and our $50.0
million equipment revolving credit facility with Caterpillar Financial Services
Corporation will be sufficient to fund our anticipated capital expenditures
under our current budget plan through the end of 2009. Although we expect
to experience some periods of tightening liquidity availability, we expect to be
able to manage through such periods. To the extent necessary, management
believes it has flexibility in the timing of the cash requirements by managing
the pace of capital spending. In addition, management may from time to time
raise additional capital through the disposition of non-core assets or engaging
in sale-leaseback transactions. The need and timing of seeking
additional capital in the future will be subject to market
conditions.
Approximately $85.5 million of 2008 cash
paid for capital expenditures was attributable to Central Appalachian
operations. This amount represents investments of approximately $44.1 million in
our Beckley mining complex, as well as additional
investments of $41.4 million for upgrades at the remaining Central Appalachian
operations. We paid approximately $30.8 million at our Northern Appalachian
operations in the year ended December 31, 2008, approximately $20.6 million of
which was for development of our Sentinel and Tygart properties. Expenditures of
approximately $4.9 million for our Illinois Basin operations were for ongoing operations
improvements. Approximately $10.8 million of cash paid for capital expenditures
for the year ended December 31, 2008 was within our Ancillary segment for safety
equipment, as well as for upgrades at various other
subsidiaries.
As a result of recent accidents in the
mining industry, additional regulatory requirements were promulgated that will
require additional capital expenditures to meet enhanced safety standards. For
the year ended December 31, 2008, we spent $4.2 million to meet these standards
and anticipate spending an additional $4.3 million in 2009.
77
Cash Flows
Net cash provided by
operating activities was $78.0 million for the year ended December 31, 2008, an increase of $55.9 million from the same period in 2007.
This increase is attributable to a decrease in net loss of $63.2 million after adjustment for non-cash
charges offset by a decrease in net operating assets and liabilities of
$7.3 million.
For the year ended December 31, 2008, net cash used in investing activities
was $123.3 million compared to $126.5 million for the year ended December 31, 2007. For the year ended December 31,
2008, $132.0 million of cash was used for
development and acquisition of new mining complexes and to support existing
mining operations compared to $169.3 million in the same period 2007.
Additionally, we collected proceeds from asset sales of $8.8 million during the year ended December 31, 2008 versus $46.5 million during the comparable period of
2007.
Net cash used 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 partially
offset by borrowings of
$9.8 million provided by long-term and short-term notes entered into during the
year and proceeds from
stock options exercised of $0.1 million.
Net cash provided by operating
activities was $22.1 million for the year ended December 31, 2007, a
decrease of $33.5 million from 2006. This decrease is attributable to an
increase in net operating assets and liabilities of $41.1 million offset by a
decrease in net loss of $74.6 million after adjustment for non-cash
charges.
For the year ended December 31,
2007, net cash used in investing activities was $126.5 million compared to
$160.8 million for the year ended December 31, 2006. For 2007, $169.3
million of cash was used to support existing mining operations and for
development of new mining complexes compared to $165.7 million in 2006.
Investing activities for 2007 also included cash paid of $3.8 million
representing contingency payments related to the Horizon acquisition as compared
to $4.7 million in 2006. Additionally, we collected proceeds from asset sales of
$46.5 million during the year ended December 31, 2007 versus $3.8 million
during 2006.
Net cash provided by financing
activities of $192.8 million for the year ended December 31, 2007 was
primarily due to proceeds of $225.0 million from our convertible senior notes
offering. Additionally, we had borrowings of $65.0 million on our credit
facility and an additional $26.1 million was provided by short-term notes
entered into during the year. These borrowings were offset by repayments on our
short-term and long-term debt and capital leases of $45.4 million and $68.6
million, respectively. Also impacting financing activities for the year ended
December 31, 2007 was additional finance costs of $9.3 million related to
the issuance of our convertible notes and amending our credit
facility.
Credit Facility and Long-Term Debt
Obligations
As of December 31, 2008, our total
long-term indebtedness, including capital lease obligations, consisted of the
following (in thousands):
|
|
2008
|
|
9.00% Convertible senior notes,
due 2012
|
|
$
|
225,000
|
|
10.25% Senior notes, due
2014
|
|
|
175,000
|
|
Equipment
notes
|
|
|
43,378
|
|
Capital
leases
|
|
|
3,817
|
|
Insurance
notes
|
|
|
3,044
|
|
Total
|
|
|
450,239
|
|
Less current
portion
|
|
|
15,319
|
|
Long-term
debt
|
|
$
|
434,920
|
|
Convertible senior
notes. In 2007, we
completed a private offering of $225.0 million aggregate principal amount of
9.00% Convertible Senior Notes (the “Convertible Notes”) due 2012. The
Convertible Notes are our senior unsecured obligations and are guaranteed on a
senior unsecured basis by our material future and current domestic subsidiaries.
The Convertible Notes and the related guarantees rank equal in right of payment
to all of our and the guarantors’ respective existing and future unsecured
senior indebtedness. Interest is payable semi-annually in arrears on
February 1 and August 1 of each year.
The Convertible Notes became convertible
at the option of holders beginning July 1, 2008. The conversion period
expired on September 30, 2008 pursuant to the terms of the governing indenture
with no holders exercising their conversion rights. The Convertible Notes may
become convertible again in the future under certain conditions. Accordingly,
we will reassess the convertibility on a
quarterly basis.
78
The principal amount of the Convertible
Notes is payable in cash and amounts above the principal amount, if any, will be
convertible into shares of our common stock or, at our option, cash. The Convertible Notes are
convertible at an initial conversion price, subject to adjustment, of $6.10 per
share (approximating 163.8136 shares per one thousand dollar principal amount of
the Convertible Notes). The volume weighted-average price of our stock subsequent to the expiration date
of the conversion period was below $6.10 per share. Accordingly, there were no
potentially convertible shares at December 31, 2008. The Convertible Notes are
convertible upon the occurrence of certain events, including (i) prior to
February 12, 2012 during any calendar quarter after September 30,
2007, if the closing sale price per share of our common stock for each of 20 or more
trading days in a period of 30 consecutive trading days ending on the last
trading day of the immediately preceding calendar quarter exceeds 130% of the
conversion price in effect on the last trading day of the immediately preceding
calendar quarter; (ii) prior to February 12, 2012 during the five
consecutive business days immediately after any five consecutive trading day
period in which the average trading price for the notes on each day during such
five trading-day period was equal to or less than 97% of the closing sale price
of our common stock on such day multiplied by
the then current conversion rate; (iii) upon the occurrence of specified
corporate transactions; and (iv) at any time from, and including
February 1, 2012 until the close of business on the second business day
immediately preceding August 1, 2012. In addition, upon events defined as a
“fundamental change” under the Convertible Notes indenture,
we may be required to
repurchase the Convertible Notes at a repurchase price in cash equal to 100% of
the principal amount of the notes to be repurchased, plus any accrued and unpaid
interest to, but excluding, the fundamental change repurchase date. As such, in
the event of a fundamental change or the aforementioned average pricing
thresholds are met, we would be required to classify the
entire amount outstanding of the Convertible Notes as a current liability in the
following quarter. In the event that a significant number of the holders of
the Convertible Notes were to convert their notes prior to maturity, we may not
have enough available funds at any particular time to make the required
repayments. Under these circumstances, we would look to WLR, our banking
group and other potential lenders to obtain short-term funding until such time
that we could secure necessary financing on a long-term basis. The availability
of any such financing would depend upon the circumstances at the time, including
the terms of any such financing, and other factors. In addition, if conversion occurs in
connection with certain changes in control, we may be required to deliver additional
shares of our common stock (a “make whole” premium)
by increasing the conversion rate with respect to such
notes.
Senior
notes. In 2006, we
sold $175.0 million aggregate principal amount of our 10.25% Senior Notes (the
“Notes”) due July 15, 2014. Interest on the Notes is payable semi-annually
in arrears on July 15 and January 15 of each year. The Notes are
senior unsecured obligations and are guaranteed on a senior unsecured basis by
all of our current and future domestic subsidiaries that are material or that
guarantee our amended and restated credit facility. The Notes and the guarantees
rank equally with all of our and the guarantors’ existing and future senior
unsecured indebtedness, but are effectively subordinated to all of our and the
guarantors existing and future senior secured indebtedness to the extent of the
value of the assets securing that indebtedness and to all liabilities of our
subsidiaries that are not guarantors. We have the option to redeem all or a
portion of the Notes at 100% of the aggregate principal amount at maturity at
any time on or after July 15, 2010. At any time prior to July 15,
2010, we may also redeem all or a portion of the Notes at a redemption price
equal to 100% of the aggregate principal amount of the Notes plus an applicable
premium as of, and accrued and unpaid interest and additional interest, if any,
to, but not including the date of redemption. At any time before July 15,
2009, we may also redeem up to 35% of the aggregate principal amount of the
Notes at a redemption price of 110.25% of the principal amount, plus accrued and
unpaid interest, if any, to the date of redemption, with the proceeds of certain
equity offerings. Upon a change of control, we may be required to offer to
purchase the Notes at a purchase price equal to 101% of the principal amount,
plus accrued and unpaid interest.
The indenture governing the Notes
contains covenants that limit our ability to, among other things, incur
additional indebtedness, issue preferred stock, pay dividends, repurchase, repay
or redeem our capital stock, make certain investments, sell assets and incur
liens. As of December 31, 2008, we were in compliance with our covenants
under the indenture.
Credit
facility. In 2006, we
entered into a second amended and restated credit agreement (the “Amended Credit
Facility”) consisting of a revolving credit facility which matures on
June 23, 2011. In July 2007, concurrent with the issuance of the
convertible notes, we further amended the Amended Credit Facility to reduce the
commitments thereunder to $100.0 million, of which a maximum of $80.0 million
may be used for letters of credit. The amendment, among other things, modified
the maximum permitted leverage ratio, the minimum interest coverage ratio and
the maximum amount of capital expenditures permitted. Further, the amendment
revised certain interest rate thresholds and unused commitment fee levels under
the Amended Credit Facility. In February 2009, we executed a further
amendment to the Amended Credit Facility that affected certain 2009 debt
covenants. The amendment modified the maximum permitted leverage and minimum
interest coverage ratios. The amendment also decreased the maximum capital
spending and added a minimum liquidity requirement. Debt covenants for years
subsequent to 2009 were not affected by the amendment. As of December 31, 2008, we had no
borrowings outstanding and letters of credit totaling $73.6 million outstanding,
leaving $26.4 million available for future borrowing capacity. Interest on the
borrowings under the Amended Credit Facility is payable, at our option, at
either the base rate plus an applicable margin based on our leverage ratio of
1.25% to 2.00% as of December 31, 2008 or LIBOR plus an applicable margin
based on our leverage ratio of 2.25% to 3.00% as of December 31, 2008. As
of December 31, 2008, we were in compliance with our financial covenants under
the Amended Credit Facility.
Equipment
notes and
other. The equipment notes, having various maturity dates extending to
January 2014, are collateralized by mining equipment.
As of December 31, 2008, we had amounts outstanding for 36-month
through 60-month terms with a weighted-average interest rate of
6.42%. At December 31,
2008, additional funds are
available under
our revolving equipment credit facility for
terms ranging from 36 to 60 months with a current interest rate of 8.75%. Additionally, we finance
certain of our annual insurance premiums at a current interest rate of
5.42%.
79
Other
As a regular part of our business, we
review opportunities for, and engage in discussions and negotiations concerning,
the acquisition of coal mining assets and interests in coal mining companies,
and acquisitions of, or combinations with, coal mining companies. When we
believe that these opportunities are consistent with our growth plans and our
acquisition criteria, we will make bids or proposals and/or enter into letters
of intent and other similar agreements, which may be binding or nonbinding, that
are customarily subject to a variety of conditions and usually permit us to
terminate the discussions and any related agreement if, among other things, we
are not satisfied with the results of our due diligence investigation. Any
acquisition opportunities we pursue could materially affect our liquidity and
capital resources and may require us to incur indebtedness, seek equity capital
or both. There can be no assurance that additional financing will be available
on terms acceptable to us, or at all.
Additionally, we have other long-term
liabilities, including, but not limited to, mine reclamation and mine closure
costs, below-market coal supply agreements and “black lung” costs, and some of
our subsidiaries have long-term liabilities relating to retiree health and other
employee benefits.
Our
ability to meet our long-term debt obligations will depend upon our future
performance, which, in turn, will depend upon general economic, financial and
business conditions, along with competition, legislation and regulation—factors
that are largely beyond our control. Based upon our current operations, we
believe that cash flow from operations, together with other available sources of
funds will be adequate for at least through the end of 2009 for making required
payments of principal and interest on our indebtedness and for funding
anticipated capital expenditures and working capital requirements. Although we
expect to experience some periods of tightening liquidity availability, we
expect to be able to manage through such periods. To the extent necessary,
management believes it has flexibility in the timing of the cash requirements by
managing the pace of capital spending. In addition, management may from time to
time raise additional capital through the disposition of non-core assets or
engaging in sale-leaseback transactions. However, we cannot assure you that our
operating results, cash flow and capital resources will be sufficient for
repayment of our debt obligations in the future.
Contractual
Obligations
The following is a summary of our
significant future contractual obligations by year as of December 31, 2008 (in
thousands):
|
|
Payments due by
period
|
|
|
|
Less than
1
year
|
|
|
1-3 years
|
|
|
3-5 years
|
|
|
More than
5
years
|
|
|
Total
|
|
Long-term debt,
capital lease and other obligations(1)
|
|
$ |
57,990 |
|
|
$ |
101,104 |
|
|
$ |
286,703 |
|
|
$ |
184,785 |
|
|
$ |
630,582 |
|
Operating
leases
|
|
|
87 |
|
|
|
82 |
|
|
|
— |
|
|
|
— |
|
|
|
169 |
|
Coal purchase
obligations(2)
|
|
|
22,926 |
|
|
|
14,377 |
|
|
|
— |
|
|
|
— |
|
|
|
37,303 |
|
Diesel fuel purchase
obligations(2)
|
|
|
73,753 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
73,753 |
|
Advisory Services
Agreement(3)
|
|
|
2,000 |
|
|
|
3,500 |
|
|
|
— |
|
|
|
— |
|
|
|
5,500 |
|
Minimum
royalties
|
|
|
10,111 |
|
|
|
19,640 |
|
|
|
16,636 |
|
|
|
37,004 |
|
|
|
83,391 |
|
Postretirement medical
benefits
|
|
|
523 |
|
|
|
2,505 |
|
|
|
5,068 |
|
|
|
170,230 |
|
|
|
178,326 |
|
Total
|
|
$ |
167,390 |
|
|
$ |
141,208 |
|
|
$ |
308,407 |
|
|
$ |
392,019 |
|
|
$ |
1,009,024 |
|
(1)
|
Amounts are inclusive of interest
assuming interest rates of 10.25% for our senior notes, 9.0% for our
convertible notes and ranging from 5.10% to 8.75% on our equipment
notes.
|
(2)
|
Reflects estimates of
obligations.
|
|
|
(3)
|
See “Certain relationships and
related party transactions.”
|
|
We have excluded from the table above
uncertain tax liabilities as defined in FASB Interpretation No. 48,
“Accounting for
Uncertainty in Income Taxes,” due to the immateriality of such
amounts.
80
Off-Balance Sheet
Arrangements
In the normal course of business, we are
a party to certain off-balance sheet arrangements. These arrangements include
guarantees and financial instruments with off-balance sheet risk, such as bank
letters of credit and performance or surety bonds. No liabilities related to
these arrangements are reflected in our consolidated balance sheets and we do
not expect any material adverse effects on our financial condition, results of
operations or cash flows to result from these off-balance sheet
arrangements.
Federal and state laws require us to
secure payment of certain long-term obligations, such as mine closure and
reclamation costs, federal and state workers’ compensation, coal leases and
other obligations. We typically secure these payment obligations by using surety
bonds, an off-balance sheet instrument. The use of surety bonds is less
expensive than posting an all cash bond or a bank letter of credit, either of
which would require a greater use of our credit facility. We then use bank
letters of credit to secure our surety bonding obligations as a lower cost
alternative than securing those bonds with cash. We currently have a $130.4
million committed bonding facility pursuant to which we are required to provide
bank letters of credit in an amount up to 50% of the aggregate bond liability.
Recently, surety bond costs have increased, while the market terms of surety
bonds have generally become less favorable. To the extent that surety bonds
become unavailable, we would seek to secure our reclamation obligations with
letters of credit, cash deposits or other suitable forms of
collateral.
As of December 31, 2008, we had
outstanding surety bonds with third parties for post-mining reclamation totaling
$111.0 million, plus $4.7 million for miscellaneous purposes. As of December 31,
2008, we maintained letters of credit totaling $73.6 million to secure
reclamation surety bonds and other obligations.
Inflation
Inflation in the United States has been relatively low in recent years
and did not have a material impact on results of operations for the years ended
December 31, 2008, 2007 and 2006. However, commodities prices have increased at
a rate greater than that of the general economy, specifically prices for fuel
and explosives, steel products, tires, healthcare and labor.
Recent Accounting
Pronouncements
Fair Value
Measurements. In September 2006, the FASB issued SFAS
No. 157, Fair Value
Measurements (“SFAS
No. 157”). SFAS No. 157 clarifies the definition of fair value,
establishes a framework for measuring fair value and expands the disclosures on
fair value measurements. SFAS No. 157 is effective for fiscal years
beginning after November 15, 2007. Adoption of SFAS No. 157 did not
have a material impact on our financial position, results of operations or cash
flows; however, adoption did result in additional information being included in
the footnotes accompanying our consolidated financial
statements.
In
February 2008, the FASB issued FSP 157-2, Effective Date of FASB Statement No.
157 (“FSP 157-2”). FSP 157-2 permits delayed adoption of SFAS No. 157 for
certain non-financial assets and liabilities, which are not recognized at fair
value on a recurring basis, until fiscal years, and interim periods within those
fiscal years, beginning after November 15, 2008. Adoption of FSP 157-2 did
not have a material impact on our financial position, results of operations or
cash flows.
Fair Value
Option. In February 2007, the FASB issued SFAS
No. 159, The Fair Value
Option for Financial Assets and Financial Liabilities—Including an amendment of
FASB Statement No. 115
(“SFAS No. 159”). SFAS No. 159 provides entities with an option to
report selected financial assets and liabilities at fair value and establishes
presentation and disclosure requirements designed to facilitate comparisons
between entities that choose different measurement attributes for similar types
of assets and liabilities. SFAS No. 159 is effective as of the beginning of
the first fiscal year that begins after November 15, 2007. Adoption of SFAS
No. 159 did not have a material impact on our financial position, results
of operations or cash flows.
Financial Assets. In
October 2008, the FASB issued FSP 157-3, Determining Fair Value of a
Financial Asset in a Market That Is Not Active (“FSP 157-3”). FSP 157-3
clarified the application of SFAS No. 157 in an inactive market. It demonstrated
how the fair value of a financial asset is determined when the market for that
financial asset is inactive. FSP 157-3 was effective upon issuance, including
prior periods for which financial statements had not been issued. Adoption of
FSP 157-3 did not have a material impact on our financial position, results of
operations or cash flows.
81
Convertible
Debt. In May 2008, the FASB issued FSP APB
14-1,
Accounting for Convertible Debt Instruments That May be Settled in Cash Upon
Conversion (Including Partial Cash Settlement) (“FSP APB 14-1”). FSP APB 14-1 requires
the liability and equity components of convertible debt instruments that may be
settled in cash upon conversion to be separately accounted for in a manner that
reflects the issuer’s nonconvertible debt borrowing rate. To allocate the
proceeds from a convertible debt offering in this manner, a company would first
need to determine the carrying amount of the liability component, which would be
based on the fair value of a similar liability (excluding any embedded
conversion options). The resulting debt discount would be amortized over the
period during which the debt is expected to be outstanding as additional
non-cash interest expense.
FSP APB 14-1 is effective for financial statements for fiscal years beginning
after December 15, 2008, and interim periods within those fiscal
years, and would be applied
retrospectively for all periods presented. We have determined our
non-convertible borrowing rate would have been 11.7% at issuance. The expected
effect of adoption of FSP APB 14-1 is as follows:
|
|
2008
|
|
|
2007
|
|
Property, plant, equipment and
mine development
|
|
$
|
1,151
|
|
|
$
|
376
|
|
Debt issuance costs,
net
|
|
|
(173
|
)
|
|
|
(576
|
)
|
Total
assets
|
|
$
|
978
|
|
|
$
|
(200
|
)
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital
leases
|
|
$
|
(17,369
|
)
|
|
$
|
(21,082
|
)
|
Deferred tax
liability
|
|
|
6,935
|
|
|
|
7,893
|
|
Total
liabilities
|
|
|
(10,434
|
)
|
|
|
(13,189
|
)
|
|
|
|
|
|
|
|
|
|
Paid-in-capital
|
|
|
13,517
|
|
|
|
13,517
|
|
Retained
deficit
|
|
|
(2,105
|
)
|
|
|
(528
|
)
|
Total stockholders’
equity
|
|
|
11,412
|
|
|
|
12,989
|
|
Total liabilities and
stockholders’ equity
|
|
$
|
978
|
|
|
$
|
(200
|
)
|
Interest expense,
net
|
|
$
|
(2,536
|
)
|
$
|
(849
|
)
|
Income
tax benefit
|
|
|
959
|
|
|
321
|
|
Net
loss
|
|
$
|
(1,577
|
)
|
$
|
(528
|
)
|
Business
Combinations. In December
2007, the FASB issued SFAS No. 141 (Revised 2007), Business
Combinations (“SFAS
No. 141(R)”). SFAS No. 141(R) will significantly change the accounting
for business combinations. Under SFAS No. 141(R), an acquiring entity will
be required to recognize all the assets acquired and liabilities assumed in a
transaction at the acquisition-date fair value with limited exceptions. SFAS
No. 141(R) will change the accounting treatment for certain specific
acquisition-related items including: (i) expensing acquisition-related
costs as incurred, (ii) valuing noncontrolling interests at fair value at
the acquisition date and (iii) expensing restructuring costs associated
with an acquired business. SFAS No. 141(R) also includes a substantial
number of new disclosure requirements. SFAS No. 141(R) is to be applied to
any business combination for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after
December 15, 2008. Upon adoption, SFAS No. 141(R) will impact the
accounting for our future business combinations.
Noncontrolling
Interests. In December
2007, the FASB issued SFAS No. 160, Noncontrolling
Interests in Consolidated Financial Statements (“SFAS No. 160”). SFAS
No. 160 establishes new accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a noncontrolling interest in a subsidiary
(minority interest) is an ownership interest in the consolidated entity that
should be reported as equity in the consolidated financial statements and
separate from the parent company’s equity. Among other requirements, this
statement requires consolidated net income to be reported at amounts that
include the amounts attributable to both the parent and the noncontrolling
interest. It also requires disclosure, on the face of the consolidated statement
of operations, of the amounts of consolidated net income attributable to the
parent and to the noncontrolling interest. SFAS No. 160 is effective for
fiscal years, and interim periods within those fiscal years, beginning on or
after December 15, 2008. We are currently evaluating the effect, if any,
that the adoption of SFAS No. 160 will have on our financial position,
results of operations and cash flows.
82
Derivative
Instruments. In March 2008,
the FASB issued SFAS No. 161, Disclosures about
Derivative Instruments and Hedging Activities – an amendment of FASB Statement
No. 133 (“SFAS
No. 161”). SFAS No. 161 requires additional disclosures for derivative
instruments and hedging activities that include how and why an entity uses
derivatives, how these instruments and the related hedged items are accounted
for under FASB Statement No. 133, Accounting for
Derivative Instruments and Hedging Activities, and related interpretations and how
derivative instruments and related hedged items affect the entity’s financial
position, results of operations and cash flows. SFAS No. 161 is effective
for fiscal years, and interim periods within those fiscal years, beginning after
November 15, 2008. Adoption of SFAS No. 161 did not impact the
footnotes accompanying our consolidated financial
statements.
GAAP
Hierarchy. In May 2008, the FASB issued SFAS
No. 162, The Hierarchy of
Generally Accepted Accounting Principles (“SFAS No. 162”). SFAS No. 162
identifies the sources of accounting principles and the framework for selecting
the principles to be used in the preparation of financial statements of
nongovernmental entities that are presented in conformity with generally
accepted accounting principles. SFAS No. 162 directs the hierarchy to the
entity, rather than the independent auditors, as the entity is responsible for
selecting accounting principles for financial statements that are presented in
conformity with generally accepted accounting principles. SFAS No. 162 is
effective for fiscal years, and interim periods within those fiscal years,
beginning on or after December 31, 2008. Adoption of SFAS No. 162 did not
have a material impact on our financial position, results of operations or cash
flows.
Share-Based Payments. In June 2008, the FASB
issued EITF 03-6-1,
Determining Whether Instruments Granted in Share-Based Payment Transactions Are
Participating Securities (“EITF 03-6-1”). EITF 03-6-1 clarifies that all
outstanding unvested share-based payment awards that contain rights to
nonforfeitable dividends participate in undistributed earnings with common
shareholders. Awards of this nature are considered participating securities and
the two-class method of computing basic and diluted earnings per share must be
applied. EITF 03-6-1 is effective for fiscal years beginning after December 15,
2008. Adoption of EITF 03-6-1 did not have a material impact on our financial
position, results of operations or cash flows.
Financial Instruments. In June
2008, the FASB ratified EITF 07-5, Determining Whether an Instrument
(or an Embedded Feature) Is Indexed to an Entity’s Own Stock (“EITF
07-5”). EITF 07-5 provides that an entity should use a two step approach to
evaluate whether an equity-linked financial instrument (or embedded feature) is
indexed to its own stock, including evaluating the instrument’s contingent
exercise and settlement provisions. It also clarifies the impact of foreign
currency denominated strike prices and market-based employee stock option
valuation instruments on the evaluation. EITF 07-5 is effective for fiscal years
beginning after December 15, 2008. Adoption of EITF 07-5 did not have a material
impact on our financial position, results of operations or cash
flows.
83
|
QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET
RISK
|
Interest rate
risk. In May 2006, we
entered into an Interest Rate Collar Agreement, which became effective on
March 31, 2007 and expires March 31, 2009, to hedge our interest risk
on $200.0 million notional amount of revolving debt. The interest rate collar is
designed as a cash flow hedge to offset the impact of changes in the LIBOR
interest rate above 5.92% and below 4.80%. This agreement was entered into in
conjunction with our amended and restated credit facility dated June 23,
2006. We recognize the change in the fair value of this agreement in the income
statement in the period of change. For the year ended December 31, 2008, we
recorded a loss of $2.0 million related to changes in fair market
value.
Market price
risk. We are exposed
to market price risk in the normal course of mining and selling coal. As of
December 31, 2008, 92% of 2009 planned production is committed for sale, leaving
approximately 8% uncommitted for sale. A hypothetical decrease of $1.00 per ton
in the market price for coal would reduce pre-tax income by approximately $1.5
million for 2009.
|
FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA
|
Our financial statements and
supplementary data are included at the end of this report beginning on page
F-1.
84
|
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.
We
maintain a set of disclosure controls and procedures designed to provide
reasonable assurance that information required to be disclosed by us in reports
that we file or submit under the Securities Exchange Act of 1934 (the “Exchange
Act”) is recorded, processed, summarized and reported within the time periods
specified in Securities and Exchange Commission rules and forms. Our disclosure
controls and procedures are also designed to provide reasonable assurance that
information required to be disclosed in the reports that we file or submit under
the Exchange Act is accumulated and communicated to our management, including
the Chief Executive Officer and Chief Financial Officer, to allow timely
decisions regarding required disclosure. Periodically, we review the design and
effectiveness of our disclosure controls and controls over financial reporting
to ensure they remain effective. If such reviews identify a need, we will make
modifications to improve the design and effectiveness of our control
structure.
Control
systems, no matter how well designed and operated, can provide only reasonable,
not absolute, assurance that control objectives are met. Because of inherent
limitations in all control systems, no evaluation of controls can provide
assurance that all control issues and instances of fraud, if any, within a
company will be detected. Additionally, controls can be circumvented by
individuals, by collusion of two or more people, or by management override. Over
time, controls can become inadequate because of changes in conditions or the
degree of compliance may deteriorate. Further, the design of any system of
controls is based in part upon assumptions about the likelihood of future
events. There can be no assurance that any design will succeed in achieving its
stated goals under all future conditions. Because of the inherent limitations in
any cost-effective control system, misstatements due to errors or fraud may
occur and not be detected.
Management’s Report on Internal Control
Over Financial Reporting
Management
is responsible for maintaining and establishing adequate internal control over
financial reporting. Our internal control framework and processes were designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of our consolidated financial statements for external
purposes in accordance with accounting principles generally accepted in the
United States of America.
Because
of inherent limitations, any system of internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
Under
the supervision and with the participation of our management, including our
Chief Executive Officer and Chief Financial Officer, we conducted an evaluation
of our controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)
under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) using
the criteria set by the Committee of Sponsoring Organizations of the Treadway
Commission (“COSO”) in
Internal Control—Integrated Framework. Based on this evaluation, our
Chief Executive Officer and Chief Financial Officer have concluded that our
controls and procedures were effective as of December 31,
2008.
Our
Independent Registered Public Accounting Firm, Deloitte & Touche LLP,
has audited the effectiveness of our internal control over financial reporting,
as stated in their attestation report included on page F-1 of Item
15.
Changes in Internal Control Over
Financial Reporting
There
have been no changes in our internal controls over financial reporting during
the fourth quarter of fiscal year 2008 that would have materially affected, or
would be reasonably likely to materially affect, our internal control over
financial reporting.
None.
85
Part III
|
DIRECTORS, EXECUTIVE OFFICERS AND
CORPORATE GOVERNANCE
|
The information requested by Items 401,
405 and 406 of Regulation S-K is incorporated herein by reference to the
definitive Proxy Statement used in connection with the solicitation of proxies
for our Annual Meeting of Stockholders to be held on May 20, 2009 (the
“Definitive Proxy Statement”).
|
SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
|
See “Market for Registrant’s Common
Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities—Summary of Equity Compensation Plans” on page 57 of this Annual
Report on Form 10-K for information required by Item 201(d) of Regulation
S-K.
|
CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS, AND DIRECTOR INDEPENDENCE
|
|
PRINCIPAL ACCOUNTANT FEES AND
SERVICE
|
The information with respect to the fees
and services related to our independent registered public accounting firm,
Deloitte & Touche LLP, and the disclosure of the Audit Committee’s
pre-approval policies and procedures are contained in the Definitive Proxy
Statement and will be incorporated herein by reference.
86
PART IV
|
EXHIBITS, FINANCIAL STATEMENT
SCHEDULES
|
(a)
|
Financial
Statements:
|
The following financial statements are
filed as part of this Annual Report on Form 10-K under
Item 8:
|
|
Page
|
|
|
|
|
|
|
|
F-1
|
|
|
|
|
F-3
|
|
|
|
|
F-4
|
|
|
|
|
F-5
|
|
|
|
|
F-6
|
|
|
|
|
F-7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Page
|
|
|
F-34
|
|
|
|
|
F-38
|
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.
87
To the Board of Directors and
Stockholders of
International Coal Group,
Inc.
Scott Depot, West Virginia
We have audited the internal control
over financial reporting of International Coal Group, Inc. and subsidiaries (the
“Company”) as of December 31, 2008, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Company’s management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s Report on Internal Control
Over Financial Reporting. Our responsibility is to express an opinion on the
Company’s internal control over financial reporting based on our
audit.
We conducted our audit in accordance
with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing
and evaluating the design and operating effectiveness of internal control based
on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A company’s internal control over
financial reporting is a process designed by, or under the supervision of, the
company’s principal executive and principal financial officers, or persons
performing similar functions, and effected by the company’s board of directors,
management, and other personnel to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance of records
that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance
that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that
receipts and expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a
material effect on the financial statements.
Because of the inherent limitations of
internal control over financial reporting, including the possibility of
collusion or improper management override of controls, material misstatements
due to error or fraud may not be prevented or detected on a timely basis. Also,
projections of any evaluation of the effectiveness of the internal control over
financial reporting to future periods are subject to the risk that the controls
may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained,
in all material respects, effective internal control over financial reporting as
of December 31, 2008, based on the criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have also audited, in accordance with
the standards of the Public Company Accounting Oversight Board (United States),
the consolidated financial statements and financial statement schedules as of
and for the year ended December 31, 2008 of the Company and our report dated
February 27, 2009 expressed an unqualified opinion on those financial statements
and financial statement schedules.
|
/s/ Deloitte &
Touche LLP
|
|
Cincinnati, Ohio
|
|
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
To the Board of Directors and
Stockholders of
International Coal Group,
Inc.
Scott Depot, West Virginia
We have audited the accompanying
consolidated balance sheets of International Coal Group, Inc. and subsidiaries
(the “Company”) as of December 31, 2008 and 2007, and the related consolidated
statements of operations, stockholders’ equity, and cash flows for each of the
three years in the period ended December 31, 2008. Our audits also included the
financial statement schedules listed in the Index at Item 15. These
financial statements and financial statement schedules are the responsibility of
the Company’s management. Our responsibility is to express an opinion on these
financial statements and financial statement schedules based on our
audits.
We conducted our audits in accordance
with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated
financial statements present fairly, in all material respects, the financial
position of the Company as of December 31, 2008 and 2007, and the results of
their operations and their cash flows for each of the three years
in the period ended December 31, 2008 in conformity with accounting principles
generally accepted in the United States of America. Also, in our opinion, such
financial statement schedules, when considered in relation to the basic
consolidated financial statements taken as a whole, present fairly, in all
material respects, the information set forth therein.
We have also audited, in accordance with
the standards of the Public Company Accounting Oversight Board (United States),
the Company’s internal control over financial reporting as of December 31, 2008,
based on the criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated February 27,
2009 expressed an unqualified opinion on the
Company’s internal control over financial reporting.
F-2
(Dollars in thousands, except per share
amounts)
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
63,930
|
|
|
$
|
107,150
|
|
Accounts receivable, net of
allowances of $1,516
and
$539
|
|
|
75,321
|
|
|
|
83,765
|
|
Inventories,
net
|
|
|
58,788
|
|
|
|
40,679
|
|
Deferred income
taxes
|
|
|
17,649
|
|
|
|
5,000
|
|
Prepaid
insurance
|
|
|
13,380
|
|
|
|
10,618
|
|
Income taxes
receivable
|
|
|
8,030
|
|
|
|
8,854
|
|
Prepaid expenses and
other
|
|
|
10,893
|
|
|
|
9,138
|
|
Total current
assets
|
|
|
247,991
|
|
|
|
265,204
|
|
|
|
|
|
|
|
|
|
|
PROPERTY, PLANT, EQUIPMENT AND
MINE DEVELOPMENT, net
|
|
|
1,068,146
|
|
|
|
974,334
|
|
DEBT ISSUANCE COSTS,
net
|
|
|
10,635
|
|
|
|
13,466
|
|
ADVANCE ROYALTIES,
net
|
|
|
17,462
|
|
|
|
14,661
|
|
GOODWILL
|
|
|
—
|
|
|
|
30,237
|
|
OTHER NON-CURRENT
ASSETS
|
|
|
5,435
|
|
|
|
5,661
|
|
Total
assets
|
|
$
|
1,349,669
|
|
|
$
|
1,303,563
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’
EQUITY
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
75,810
|
|
|
$
|
70,042
|
|
Short-term
debt
|
|
|
4,741
|
|
|
|
—
|
|
Current portion of long-term
debt and capital
leases
|
|
|
15,319
|
|
|
|
4,234
|
|
Current portion of reclamation and
mine closure costs
|
|
|
11,139
|
|
|
|
7,333
|
|
Current portion of employee
benefits
|
|
|
3,359
|
|
|
|
2,925
|
|
Accrued expenses and
other
|
|
|
87,704
|
|
|
|
62,723
|
|
Total current
liabilities
|
|
|
198,072
|
|
|
|
147,257
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT AND CAPITAL
LEASES
|
|
|
434,920
|
|
|
|
408,096
|
|
RECLAMATION AND MINE CLOSURE
COSTS
|
|
|
68,107
|
|
|
|
78,587
|
|
EMPLOYEE
BENEFITS
|
|
|
61,194
|
|
|
|
55,132
|
|
DEFERRED INCOME
TAXES
|
|
|
42,468
|
|
|
|
52,355
|
|
BELOW-MARKET COAL SUPPLY
AGREEMENTS
|
|
|
43,888
|
|
|
|
39,668
|
|
OTHER NON-CURRENT
LIABILITIES
|
|
|
6,195
|
|
|
|
8,062
|
|
Total
liabilities
|
|
|
854,844
|
|
|
|
789,157
|
|
|
|
|
|
|
|
|
|
|
MINORITY
INTEREST
|
|
|
35
|
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND
CONTINGENCIES
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS’
EQUITY:
|
|
|
|
|
|
|
|
|
Preferred stock – par value $0.01, 200,000,000 shares
authorized, none issued
|
|
|
—
|
|
|
|
—
|
|
Common stock – par value $0.01, 2,000,000,000
shares authorized,
153,322,245 and
152,992,109 shares, respectively, issued and
outstanding
|
|
|
1,533
|
|
|
|
1,530
|
|
Additional paid-in
capital
|
|
|
643,480
|
|
|
|
639,160
|
|
Accumulated other comprehensive
loss
|
|
|
(5,157
|
)
|
|
|
(5,903
|
)
|
Retained
deficit
|
|
|
(145,066
|
)
|
|
|
(120,416
|
)
|
Total stockholders’
equity
|
|
|
494,790
|
|
|
|
514,371
|
|
Total liabilities and
stockholders’ equity
|
|
$
|
1,349,669
|
|
|
$
|
1,303,563
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements.
F-3
(Dollars in thousands, except per share
amounts)
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
revenues
|
|
$
|
998,245
|
|
|
$
|
770,663
|
|
|
$
|
833,998
|
|
Freight and handling
revenues
|
|
|
45,231
|
|
|
|
29,594
|
|
|
|
18,890
|
|
Other
revenues
|
|
|
53,260
|
|
|
|
48,898
|
|
|
|
38,706
|
|
Total
revenues
|
|
|
1,096,736
|
|
|
|
849,155
|
|
|
|
891,594
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal
sales
|
|
|
882,983
|
|
|
|
732,112
|
|
|
|
739,914
|
|
Freight and handling
costs
|
|
|
45,231
|
|
|
|
29,594
|
|
|
|
18,890
|
|
Cost of other
revenues
|
|
|
35,672
|
|
|
|
34,046
|
|
|
|
29,418
|
|
Depreciation, depletion and
amortization
|
|
|
96,047
|
|
|
|
86,517
|
|
|
|
72,218
|
|
Selling, general and
administrative
|
|
|
38,147
|
|
|
|
33,325
|
|
|
|
34,578
|
|
Gain on sale of
assets
|
|
|
(32,518
|
)
|
|
|
(38,656
|
)
|
|
|
(1,125
|
)
|
Goodwill impairment
loss
|
|
|
30,237
|
|
|
|
170,402
|
|
|
|
—
|
|
Long-lived asset impairment
loss
|
|
|
7,191
|
|
|
|
—
|
|
|
|
—
|
|
Total costs and
expenses
|
|
|
1,102,990
|
|
|
|
1,047,340
|
|
|
|
893,893
|
|
Loss from
operations
|
|
|
(6,254
|
)
|
|
|
(198,185
|
)
|
|
|
(2,299
|
)
|
INTEREST AND OTHER INCOME
(EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense,
net
|
|
|
(41,107
|
)
|
|
|
(35,140
|
)
|
|
|
(18,091
|
)
|
Other, net
|
|
|
—
|
|
|
|
319
|
|
|
|
2,113
|
|
Total interest and other income
(expense)
|
|
|
(41,107
|
)
|
|
|
(34,821
|
)
|
|
|
(15,978
|
)
|
Loss before income taxes and
minority interest
|
|
|
(47,361
|
)
|
|
|
(233,006
|
)
|
|
|
(18,277
|
)
|
INCOME TAX
BENEFIT
|
|
|
22,711
|
|
|
|
85,623
|
|
|
|
9,015
|
|
MINORITY
INTEREST
|
|
|
—
|
|
|
|
349
|
|
|
|
(58
|
)
|
Net loss
|
|
$
|
(24,650
|
)
|
|
$
|
(147,034
|
)
|
|
$
|
(9,320
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and
diluted
|
|
$
|
(0.16
|
)
|
|
$
|
(0.97
|
)
|
|
$
|
(0.06
|
)
|
Weighted-average common shares
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and
diluted
|
|
|
152,632,586
|
|
|
|
152,304,461
|
|
|
|
152,028,165
|
|
See notes to consolidated financial
statements.
F-4
(Dollars in
thousands)
|
|
Common
Stock
|
|
Additional Paid-in
Capital
|
|
Unearned Compensation
Restricted
Stock
|
|
Accumulated Other Comprehensive
Income
|
|
Retained Earnings
(Deficit)
|
|
Total
|
|
Shares
|
|
Amount
|
|
|
152,321,908
|
|
$
|
1,523
|
|
$
|
632,897
|
|
$
|
(4,622
|
)
|
$
|
—
|
|
$
|
36,688
|
|
$
|
666,486
|
|
Net loss
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9,320
|
)
|
|
(9,320
|
)
|
Comprehensive
loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,320
|
)
|
Effect of adoption of SFAS
No. 158, net of tax of $3,079
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,846
|
)
|
|
—
|
|
|
(3,846
|
)
|
Effect of adoption of EITF 04-6,
net of tax of $400
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(638
|
)
|
|
(638
|
)
|
Effect of adoption of
SFAS No. 123(R)
|
|
—
|
|
|
—
|
|
|
(4,622
|
)
|
|
4,622
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Issuance of restricted stock and
stock awards, net of forfeitures
|
|
584,580
|
|
|
6
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Compensation expense on
share-based awards
|
|
—
|
|
|
—
|
|
|
5,668
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,668
|
|
|
|
152,906,488
|
|
|
1,529
|
|
|
633,937
|
|
|
—
|
|
|
(3,846
|
)
|
|
26,730
|
|
|
658,350
|
|
Net loss
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(147,034
|
)
|
|
(147,034
|
)
|
Postretirement benefit obligation
adjustments, net of tax of $1,362
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,231
|
)
|
|
—
|
|
|
(2,231
|
)
|
Amortization of accumulated
postretirement benefit obligation, net of tax of
$109
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
174
|
|
|
—
|
|
|
174
|
|
Comprehensive
loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(149,091
|
)
|
Effect of adoption of FIN
48
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(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
|
|
|
|
152,992,109
|
|
|
1,530
|
|
|
639,160
|
|
|
—
|
|
|
(5,903
|
)
|
|
(120,416
|
)
|
|
514,371
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(24,650
|
)
|
|
(24,650
|
)
|
Postretirement benefit obligation
adjustments, net of tax of $727
|
|
|
|
|
|
|
|
|
|
|
|
|
|
530
|
|
|
—
|
|
|
530
|
|
Amortization of accumulated
postretirement benefit obligation, net of tax of
$214
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
216
|
|
|
—
|
|
|
216
|
|
Comprehensive
loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23,904
|
)
|
Issuance of restricted stock and
stock awards, net of forfeitures
|
|
312,436
|
|
|
3
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Stock options
exercised
|
|
17,700
|
|
|
—
|
|
|
149
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
149
|
|
Compensation expense on
share-based awards
|
|
—
|
|
|
—
|
|
|
4,174
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,174
|
|
|
|
153,322,245
|
|
$
|
1,533
|
|
$
|
643,480
|
|
$
|
—
|
|
$
|
(5,157
|
)
|
$
|
(145,066
|
)
|
$
|
494,790
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements.
F-5
(Dollars in
thousands)
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
CASH FLOWS FROM OPERATING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(24,650
|
)
|
|
$
|
(147,034
|
)
|
|
$
|
(9,320
|
)
|
Adjustments to reconcile net loss
to net cash from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and
amortization
|
|
|
96,047
|
|
|
|
86,517
|
|
|
|
72,218
|
|
Impairment
loss
|
|
|
37,428
|
|
|
|
170,402
|
|
|
|
—
|
|
Write-off and amortization of
deferred finance costs included in interest expense
|
|
|
2,831
|
|
|
|
8,291
|
|
|
|
3,418
|
|
Amortization of accumulated
postretirement benefit obligation
|
|
|
430
|
|
|
|
283
|
|
|
|
—
|
|
Minority
interest
|
|
|
—
|
|
|
|
(349
|
)
|
|
|
58
|
|
Compensation expense on
share-based awards
|
|
|
4,174
|
|
|
|
5,224
|
|
|
|
5,668
|
|
Gain on sale of assets,
net
|
|
|
(32,518
|
)
|
|
|
(38,656
|
)
|
|
|
(1,125
|
)
|
Provision for bad
debt
|
|
|
994
|
|
|
|
503
|
|
|
|
—
|
|
Deferred income
taxes
|
|
|
(23,477
|
)
|
|
|
(87,078
|
)
|
|
|
3,239
|
|
Changes in Assets and
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
7,918
|
|
|
|
(13,606
|
)
|
|
|
(5,885
|
)
|
Inventories
|
|
|
(17,333
|
)
|
|
|
(92
|
)
|
|
|
(20,958
|
)
|
Prepaid expenses and
other
|
|
|
(3,545
|
)
|
|
|
3,202
|
|
|
|
(10,201
|
)
|
Other non-current
assets
|
|
|
(2,744
|
)
|
|
|
(457
|
)
|
|
|
(2,553
|
)
|
Accounts
payable
|
|
|
7,116
|
|
|
|
12,588
|
|
|
|
(1,832
|
)
|
Accrued expenses and
other
|
|
|
24,677
|
|
|
|
11,648
|
|
|
|
12,268
|
|
Reclamation and mine closure
costs
|
|
|
(5,281
|
)
|
|
|
5,509
|
|
|
|
5,014
|
|
Other
liabilities
|
|
|
5,886
|
|
|
|
5,200
|
|
|
|
5,582
|
|
Net cash from operating
activities
|
|
|
77,953
|
|
|
|
22,095
|
|
|
|
55,591
|
|
CASH FLOWS FROM INVESTING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from the sale of
assets
|
|
|
8,786
|
|
|
|
46,524
|
|
|
|
3,782
|
|
Net proceeds from
sale-leaseback
|
|
|
—
|
|
|
|
—
|
|
|
|
5,413
|
|
Additions to property, plant,
equipment and mine development
|
|
|
(131,421
|
)
|
|
|
(160,431
|
)
|
|
|
(165,658
|
)
|
Cash paid related to acquisitions,
net
|
|
|
(603
|
)
|
|
|
(12,717
|
)
|
|
|
(4,721
|
)
|
Withdrawals (deposits) of
restricted cash
|
|
|
(26
|
)
|
|
|
193
|
|
|
|
415
|
|
Distribution to joint
venture
|
|
|
—
|
|
|
|
(100
|
)
|
|
|
—
|
|
Net cash from investing
activities
|
|
|
(123,264
|
)
|
|
|
(126,531
|
)
|
|
|
(160,769
|
)
|
CASH FLOWS FROM FINANCING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings on short-term
debt
|
|
|
6,310
|
|
|
|
26,082
|
|
|
|
10,375
|
|
Repayments on short-term
debt
|
|
|
(1,569
|
)
|
|
|
(45,368
|
)
|
|
|
(20,400
|
)
|
Borrowings on long-term
debt
|
|
|
3,496
|
|
|
|
65,000
|
|
|
|
71,543
|
|
Repayments on long-term debt and
capital leases
|
|
|
(6,295
|
)
|
|
|
(68,585
|
)
|
|
|
(112,418
|
)
|
Debt issuance
costs
|
|
|
—
|
|
|
|
(9,285
|
)
|
|
|
(9,367
|
)
|
Proceeds from stock options
exercised
|
|
|
149
|
|
|
|
—
|
|
|
|
—
|
|
Proceeds from senior notes
offering
|
|
|
—
|
|
|
|
—
|
|
|
|
175,000
|
|
Proceeds from convertible notes
offering
|
|
|
—
|
|
|
|
225,000
|
|
|
|
—
|
|
Net cash from financing
activities
|
|
|
2,091
|
|
|
|
192,844
|
|
|
|
114,733
|
|
NET CHANGE IN CASH AND CASH
EQUIVALENTS
|
|
|
(43,220
|
)
|
|
|
88,408
|
|
|
|
9,555
|
|
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD
|
|
|
107,150
|
|
|
|
18,742
|
|
|
|
9,187
|
|
CASH AND CASH EQUIVALENTS, END OF
PERIOD
|
|
$
|
63,930
|
|
|
$
|
107,150
|
|
|
$
|
18,742
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest (net of
amount capitalized)
|
|
$
|
36,193
|
|
|
$
|
20,113
|
|
|
$
|
4,898
|
|
Cash (paid) received for income
taxes
|
|
$
|
—
|
|
|
$
|
2,971
|
|
|
$
|
(150
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of
non-cash items:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of property, plant,
equipment and mine development through accounts
payable
|
|
$
|
12,942
|
|
|
$
|
547
|
|
|
$
|
5,145
|
|
Purchases of property, plant,
equipment and mine development through financing
arrangements
|
|
$
|
40,708
|
|
|
$
|
10,971
|
|
|
$
|
26,175
|
|
Assets acquired through the
assumption of liabilities
|
|
$
|
17,464
|
|
|
$
|
2,016
|
|
|
$
|
—
|
|
Assets acquired through the
exchange of property
|
|
$
|
22,608
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
F-6
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
(Dollars in thousands, except per share
amounts)
Entity
Matters—International Coal Group, Inc. (“ICG” or
the “Company”) is a leading producer of coal in Northern and Central Appalachia
and also has operations and reserves in the Illinois Basin. The Company’s customers are primarily
investment grade electric utilities, as well as domestic industrial and steel
customers that demand a variety of coal products. The Company’s ability to
produce a comprehensive range of high Btu steam and metallurgical quality coal
allows it to blend coal, which enables it to market differentiated coal products
to a variety of customers with different coal quality
demands.
ICG, Inc. was formed on May 13,
2004 by WL Ross & Co., LLC (“WLR”) and other investors to acquire and
operate competitive coal mining facilities. On September 30, 2004, ICG,
Inc. acquired certain properties and assets, and assumed certain liabilities, of
Horizon Natural Resources Company (“Horizon”) through Section 363 asset
sales of the United States Bankruptcy Court.
International Coal Group, Inc. was
formed in March 2005, as a wholly owned subsidiary of ICG, Inc., in order to
effect a corporate reorganization. On November 18, 2005, the reorganization
was completed. Prior to this reorganization, ICG, Inc. was the top-tier holding
company. Upon completion of the reorganization, International Coal Group, Inc.
became the new top-tier parent holding company. In the corporate reorganization,
the stockholders of ICG, Inc. received one share of International Coal Group,
Inc. common stock for each share of ICG, Inc. common stock. In addition, the
Company completed acquisitions of Anker Coal Group, Inc. (“Anker”) and CoalQuest
Development, LLC (“CoalQuest”), on November 18, 2005.
2.
|
SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES AND GENERAL
|
Principles
of Consolidation—The
consolidated financial statements include the accounts of ICG, whose
subsidiaries are generally controlled through a majority voting interest, but
may be controlled by means of a significant minority ownership, by contract,
lease or otherwise. In certain cases, ICG subsidiaries (i.e., Variable Interest
Entities (“VIEs”)) may also be consolidated based on a risks and rewards
approach as required by the Financial Accounting Standards Board (“FASB”)
revised Interpretation No. 46 (“FIN 46(R)”). See Note 14 to the
consolidated financial statements for further discussion regarding the
consolidation of VIEs. The Company accounts for its undivided interest in
coalbed methane wells (see Note 7) using the proportionate consolidation method,
whereby its share of assets, liabilities, revenues and expenses are included in
the appropriate classification in the financial statements. The consolidated
financial statements are presented in accordance with accounting principles
generally accepted in the United States of America. Significant intercompany transactions
and balances have been eliminated.
Cash
and Cash Equivalents—The
Company considers all highly-liquid investments with maturities of three months
or less at the time of purchase to be cash equivalents. Cash equivalents consist
of a money market fund. Because of the short maturity of these investments, the
carrying amounts approximate the fair value.
Accounts
Receivable and Allowance for Doubtful Accounts—Accounts receivable are recorded at the
invoiced amount and do not bear interest. The allowance for doubtful accounts is
the Company’s best estimate of the amount of probable credit losses in the
Company’s existing accounts receivable. The Company establishes provisions for
losses on accounts receivable when it is probable that all or part of the
outstanding balance will not be collected. The Company regularly reviews
collectability and establishes or adjusts the allowance as
necessary.
Inventories—Components of inventories consist of
coal and parts and supplies (see Note 3).
Coal inventories are stated at lower of average cost or
market and represent coal contained in stockpiles,
including those tons that have been mined and hauled to our loadout facilities,
but not yet shipped to customers. These inventories are stated in clean coal
equivalent tons and take into account any loss that may occur during the
processing stage. Coal must be of a quality that can be sold on existing sales
orders to be carried as coal inventory. The majority of the Company’s coal
inventory does not require extensive processing prior to shipment. In most
cases, processing consists of crushing or sizing the coal prior to loading into
the truck or rail car for shipment to the customer.
Parts
and supplies inventories are valued at average cost, less an allowance for obsolescence. The Company
establishes provisions for losses in parts and supplies inventory values through
analysis of turnover of inventory items and adjusts the allowance as
necessary.
Derivative
Financial Instruments—The
Company uses interest rate swaps to manage interest rate risk. The Company does
not use derivative financial instruments for trading or speculative purposes.
Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended (“SFAS No. 133”),
establishes accounting and reporting standards for derivative instruments and
hedging activities.
In May 2006, the Company entered into an
Interest Rate Collar Agreement (the “Collar Agreement”), which became effective
as of March 31, 2007 and will expire on March 31, 2009. The Company
uses the Collar Agreement to hedge its interest rate risk on $200,000 notional
amount of revolving debt. The interest rate collar is designed as a cash flow
hedge to offset the impact of changes in the LIBOR interest rate above 5.92% and
below 4.80%. The Company has not designated its derivatives as hedging
instruments and recognizes the change in the fair value of its derivatives in
its consolidated statement of operations in the period of change. The derivative
liability, resulting from adjusting the Collar Agreement to its fair value of
approximately $1,665, including the Company’s initial net investment of $300, is
included in accrued expenses and other in the Company’s consolidated balance
sheet at December 31, 2008. Such adjustment resulted in losses of approximately
$1,993, $1,649 and $939 for years ended December 31, 2008, 2007 and 2006,
respectively, and is included in interest expense.
F-7
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
Pursuant to EITF 90-19, Convertible Bonds
with Issuer Option to Settle for Cash upon Conversion, EITF 00-19, Accounting for
Derivative Financial Instruments Indexed to, and Potentially Settled in, a
Company’s Own Stock and
EITF 01-6, The Meaning of
Indexed to a Company’s Own Stock , 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 not been accounted for as a
separate derivative.
Advance
Royalties—The Company is
required, under certain royalty lease agreements, to make minimum royalty
payments whether or not mining activity is being performed on the leased
property. These minimum payments may be recoupable once mining begins on the
leased property. The recoupable minimum royalty payments are capitalized and
amortized based on the units-of-production method at a rate defined in the lease
agreement once mining activities begin. The Company has recorded net advance
royalties of $22,573 and $20,188, the current portion of $5,111 and $5,528 is
included in prepaid expense at December 31, 2008 and 2007, respectively.
Unamortized deferred royalty costs are expensed when mining has ceased or a
decision is made not to mine on such property. At December 31, 2008 and 2007,
the Company has recorded allowances for such circumstances totaling $3,909 and
$3,771, respectively.
Coal
Supply Agreements—Purchase
price allocated to the Company’s below-market coal supply agreements (sales
contracts) acquired in acquisitions accounted for as business combinations were
capitalized and are being amortized on the basis of coal to be shipped over the
term of the contracts. Purchase price allocated to the Company’s above-market
coal supply agreement was capitalized and is being reduced as related cash
payments are received. Value was allocated to coal supply agreements based on
discounted cash flows attributable to the difference between the above- or
below-market contract price and the prevailing market price at the date of
acquisition. The net book value of the Company’s above-market coal supply
agreement was $3,447 and $3,713 at December 31, 2008 and 2007, respectively.
This amount is recorded in other assets in the Company’s consolidated balance
sheets. The net book value of the below-market coal supply agreements was
$43,888 and $39,668 at December 31, 2008 and 2007, respectively. Amortization
income on the below-market coal supply agreements was $9,590, $19,214 and
$13,494 in 2008, 2007 and 2006, respectively. Amortization income is included in
depreciation, depletion and amortization expense. Based on expected shipments
related to these contracts, the Company expects to record annual amortization
income on the below-market coal supply agreements in each of the next five years
as reflected in the table below.
|
|
Below-market
|
|
2009
|
|
$ |
10,091 |
|
2010
|
|
|
7,881 |
|
2011
|
|
|
3,186 |
|
2012
|
|
|
3,186 |
|
2013
|
|
|
3,186 |
|
Property,
Plant, Equipment and Mine Development—Property, plant, equipment and mine
development costs, including coal lands and mineral rights, are recorded at
cost, which includes construction overhead and capitalized interest. Interest
cost applicable to major asset additions is capitalized during the construction
period and totaled $5,946 and $5,057 for the years ended December 31, 2008 and
2007, respectively. Expenditures for major renewals and betterments are
capitalized, while expenditures for maintenance and repairs are expensed as
incurred. Coal lands and mineral rights costs are depleted using the
units-of-production method, based on estimated recoverable interest. Mine
development costs are amortized using the units-of-production method, based on
estimated recoverable interest. Other property, plant and equipment is
depreciated using the straight-line method with estimated useful lives as
follows:
|
|
Years
|
|
Buildings
|
|
10 to 45
|
|
Mining and other equipment and
related facilities
|
|
1 to 20
|
|
Land
improvements
|
|
|
15 |
|
Transportation
equipment
|
|
2 to 7
|
|
Furniture and
fixtures
|
|
3 to 10
|
|
Goodwill—Goodwill represents the excess of costs
over fair value of net assets of businesses acquired. Pursuant to SFAS
No. 142, Goodwill and Other
Intangible Assets (“SFAS
No. 142”), goodwill and intangible assets that are determined to have an
indefinite useful life are not amortized, but instead must be tested for
impairment at least annually. The goodwill impairment test consists of two
steps. The first identifies potential impairment by comparing the fair value of
a reporting unit with its carrying amount, including goodwill. Fair value of a
reporting unit is estimated using present value techniques, such as discounted
cash flows of projected future operations developed by management, or a
weighting of income and market approaches. If the fair value of the reporting
unit exceeds the carrying amount, goodwill is not considered impaired and the
second step is not necessary. If the carrying value of the reporting unit
exceeds the fair value, the second step is necessary to measure the amount of
impairment loss by comparing the implied fair value of goodwill with its
carrying amount. Implied fair value of goodwill is determined as the amount that
the fair value of the assets of a business unit exceeds their carrying value,
excluding goodwill. Impairment loss is measured as the amount of the carrying
value of goodwill that exceeds its implied fair value. The Company performs its
impairment test as of October 31st of each year. See Note
5.
F-8
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(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, 2008, 2007
and 2006 was $2,831, $8,291 and $3,418, respectively, and is included in
interest expense. Amortization expense for 2008, 2007 and 2006 includes $0,
$5,348 and $1,369, respectively, representing deferred financing fees
written-off as a result of amending and restating the Company’s prior credit
agreements.
Restricted
Cash—Restricted cash
includes amounts required by various royalty and reclamation agreements.
Restricted cash of $1,589 and $1,563 at December 31, 2008 and 2007,
respectively, is included in other non-current assets.
Coal
Mine Reclamation and Mine Closure Costs—The Company’s asset retirement
obligations arise from the Federal Surface Mining Control and Reclamation Act of
1977 and similar state statutes, which require that mine property be restored in
accordance with specified standards and an approved reclamation plan. The
Company records these reclamation obligations according to the provisions of
SFAS No. 143, Accounting for Asset
Retirement Obligations
(“SFAS No. 143”). SFAS No. 143 requires the fair value of a
liability for an asset retirement obligation to be recognized in the period in
which the legal obligation associated with the retirement of the long-lived
asset is incurred. Fair value of reclamation liabilities is determined based on
the present value of the estimated future expenditures. When the liability is
initially recorded, the offset is capitalized by increasing the carrying amount
of the related long-lived asset. Over time, the liability is accreted to its
present value and the capitalized cost is depreciated over the useful life of
the related asset. To settle the liability, the obligation is paid, and to the
extent there is a difference between the liability and the amount of cash paid,
a gain or loss upon settlement is recorded. On at least an annual basis, the
Company reviews its entire reclamation liability and makes necessary adjustments
for permit changes as granted by state authorities, additional costs resulting
from accelerated mine closures and revisions to cost estimates and productivity
assumptions.
Asset
Impairments—The Company
follows SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets, which requires that projected future
cash flows from use and disposition of assets be compared with the carrying
amounts of those assets when impairment indicators are present. When the sum of
projected cash flows is less than the carrying amount, impairment losses are
indicated. If the fair value of the assets is less than the carrying amount of
the assets, an impairment loss is recognized. In determining such impairment
losses, discounted cash flows or asset appraisals are utilized to determine the
fair value of the assets being evaluated. Also, in certain situations, expected
mine lives are shortened because of changes to planned operations. When that
occurs and it is determined that the mine’s underlying costs are not recoverable
in the future, reclamation and mine closing obligations are accelerated and the
mine closing accrual is increased accordingly. To the extent it is determined
asset carrying values will not be recoverable during a shorter mine life, a
provision for such impairment is recognized. During the year ended December 31,
2008, the Company recognized an impairment loss of $7,191 in accordance with
SFAS No. 144. See Note 4.
Income
Tax Provision—The provision
for income taxes includes federal, state and local income taxes currently
payable and deferred taxes arising from temporary differences between the
financial statement and tax basis of assets and liabilities. Income taxes are
recorded under the liability method. Under this method, deferred income taxes
are recognized for the estimated future tax effects of differences between the
tax basis of assets and liabilities and their financial reporting amounts, as
well as net operating loss carryforwards and tax credits based on enacted tax
laws. Valuation allowances are established when necessary to reduce deferred tax
assets to the amount expected to be realized.
The Company recognizes interest expense
and penalties related to unrecognized tax benefits as interest expense and other
expense, respectively, in its consolidated statement of
operations.
F-9
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
Revenue
Recognition—Coal revenues
result from sales contracts (long-term coal contracts or purchase orders) with
electric utilities, industrial companies or other coal-related organizations,
primarily in the eastern United States. Revenue is recognized and recorded at
the time of shipment or delivery to the customer, prices are fixed or
determinable and the title or risk of loss has passed in accordance with the
terms of the sales agreement. Under the typical terms of these agreements, risk
of loss transfers to the customers at the mine or port, where coal is loaded to
the rail, barge, truck or other transportation source that delivers coal to its
destination.
Coal
sales revenues also result from the sale of brokered coal produced by others.
Revenue is recognized and recorded at the time of shipment or delivery to the
customer, prices are fixed or determinable and the title or risk of loss has
passed in accordance with the terms of the sale agreement. The revenues related
to brokered coal sales are included in coal sales revenues on a gross basis and
the corresponding cost of the coal from the supplier is recorded in cost of coal
sales in accordance with Emerging Issues Task Force (“EITF”) 99-19, Reporting Revenue Gross as a
Principal versus Net as an Agent.
Freight and handling costs paid to
third-party carriers and invoiced to coal customers are recorded as freight and
handling costs and freight and handling revenues,
respectively.
Other revenues primarily consist of
contract mining income, coalbed methane sales, ash disposal services, equipment
and parts sales, equipment rebuild and maintenance services, royalties and coal
handling and processing income. With respect to other revenues recognized in
situations unrelated to the shipment of coal, we carefully review the facts and
circumstances of each transaction and apply the relevant accounting literature
as appropriate and do not recognize revenue until the following criteria are
met: persuasive evidence of an arrangement exists, delivery has occurred or
services have been rendered, the seller’s price to the buyer is fixed or
determinable and collectibility is reasonably assured. Advance payments received
are deferred and recognized in revenue as related income is
earned.
Postretirement
Benefits Other Than Pensions—As prescribed by SFAS
No. 106, Employers’
Accounting for Postretirement Benefits Other Than Pensions (“SFAS No. 106”), accruals are
made, based on actuarially determined estimates, for the expected costs of
providing postretirement benefits other than pensions for current and future
retired employees and their dependents, which are primarily healthcare and life
insurance benefits, during an employee’s actual working career. Actuarial gains
and losses are amortized over the estimated average remaining service period for
active employees utilizing the minimum amortization method prescribed by SFAS
No. 106. The Company’s liability is reduced by the amount of Medicare
prescription drug reimbursement that it expects to receive under the Drug
Improvement and Modernization Act of 2003. See Note 12.
As prescribed by SFAS
No. 158, Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans – an
amendment of FASB Statements No. 87, 88, 106 and 132(R), changes in the funded status of the
plan are recognized through other comprehensive income.
Workers’
Compensation and Black Lung Benefits—The Company is liable under federal and
state laws to pay workers’ compensation and pneumoconiosis (black lung) benefits
to eligible employees. The Company utilizes a combination of participation in a
state run program and insurance policies. For black lung liabilities, provisions
are made for actuarially determined estimated benefits. The Company follows SFAS
No. 112, Employers’
Accounting for Postemployment Benefits for purposes of accounting for its
black lung liabilities.
Stock-Based
Compensation—The Company
accounts for its stock-based awards in accordance with SFAS
No. 123(R), Share Based
Payment (“SFAS
No. 123(R)”). SFAS No. 123(R) establishes standards of accounting for
transactions in which an entity exchanges its equity instruments for goods or
services. It also addresses transactions in which an entity incurs liabilities
in exchange for goods or services that are based on the fair value of the
entity’s equity instruments or that may be settled by the issuance of those
equity instruments. Under the fair value recognition provisions of SFAS
No. 123(R), the Company measures stock-based compensation cost based upon
the grant date fair value of the award, which is recognized as expense on a
straight-line basis over the corresponding vesting period. The Company uses the
Black-Scholes option valuation model to determine the estimated fair value of
its stock options at the date of grant. Determining the fair value of
share-based awards at the grant date requires several assumptions. These
assumptions include the expected life of the option, the risk-free interest
rate, volatility of the price of the Company’s common stock and expected
dividend yield on the Company’s common stock. See Note 13.
Management’s
Use of Estimates—The
preparation of the consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Significant items subject to
such estimates and assumptions include, but are not limited to, the allowance
for doubtful accounts; coal inventories; parts and supplies inventory reserves;
coal lands and mineral rights; advance royalty reserves; asset retirement
obligations; employee benefit liabilities; future cash flows associated with
assets; useful lives for depreciation, depletion and amortization; income taxes;
and fair value of financial instruments. Due to the subjective nature of these
estimates, actual results could differ from those estimates.
F-10
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
Recent
Accounting Pronouncements—In September 2006, the Financial
Accounting Standards Board (“FASB”) issued Statement of Financial Accounting
Standards (“SFAS”) No. 157, Fair Value
Measurements (“SFAS No. 157”). SFAS No. 157
clarifies the definition of fair value, establishes a framework for measuring
fair value and expands the disclosures on fair value measurements. SFAS
No. 157 is effective for fiscal years beginning after November 15,
2007. Adoption of SFAS No. 157 did not have a material impact on the
Company’s financial position, results of operations or cash flows; however,
adoption did result in additional information being included in the footnotes
accompanying the Company’s consolidated financial statements. See Note
18.
In February 2008, the
FASB issued FASB Staff Position (“FSP”) 157-2, Effective Date of
FASB Statement No. 157
(“FSP 157-2”). FSP 157-2 permits delayed adoption of SFAS 157 for certain
non-financial assets and liabilities, which are not recognized at fair value on
a recurring basis, until fiscal years, and interim periods within those fiscal
years, beginning after November 15, 2008. Adoption of FSP 157-2 did not have a material
impact on the Company’s financial position, results of
operations or cash flows.
In February 2007, the
FASB issued SFAS No. 159, The Fair Value
Option for Financial Assets and Financial Liabilities – Including an amendment
of FASB Statement No. 115 (“SFAS No. 159”). SFAS
No. 159 provides entities with an option to report selected financial
assets and liabilities at fair value and establishes presentation and disclosure
requirements designed to facilitate comparisons between entities that choose
different measurement attributes for similar types of assets and liabilities.
SFAS No. 159 is effective as of the beginning of the first fiscal year that
begins after November 15, 2007. Adoption of SFAS No. 159 did not have
a material impact on the Company’s financial position, results of operations or
cash flows.
In October 2008, the
FASB issued FSP 157-3, Determining Fair
Value of a Financial Asset in a Market That Is Not Active (“FSP 157-3”). FSP 157-3 clarified the
application of SFAS No. 157 in an inactive market. It demonstrated how the fair
value of a financial asset is determined when the market for that financial
asset is inactive. FSP 157-3 was effective upon issuance, including prior
periods for which financial statements had not been issued. Adoption of FSP
157-3 did not have a material impact on the Company’s financial position,
results of operations or cash flows.
In May 2008, the FASB
issued FSP APB 14-1, Accounting for
Convertible Debt Instruments That May be Settled in Cash Upon Conversion
(Including Partial Cash Settlement) (“FSP APB 14-1”). FSP APB 14-1 requires
the liability and equity components of convertible debt instruments that may be
settled in cash upon conversion to be separately accounted for in a manner that
reflects the issuer’s nonconvertible debt borrowing rate. To allocate the
proceeds from a convertible debt offering in this manner, a company would first
need to determine the carrying amount of the liability component, which would be
based on the fair value of a similar liability, excluding any embedded
conversion options. The resulting debt discount would be amortized over the
period during which the debt is expected to be outstanding as additional
non-cash interest expense. FSP APB 14-1 is effective for financial statements
for fiscal years beginning after December 15, 2008, and interim periods within
those fiscal years, and would be
applied retrospectively for all periods presented. The Company has determined
its non-convertible borrowing rate would have been 11.7% at issuance.
The expected effect of
adoption of FSP APB 14-1 is as follows:
|
|
2008
|
|
|
2007
|
|
Property, plant, equipment and
mine development
|
|
|
1,151
|
|
|
|
376
|
|
Debt issuance costs,
net
|
|
|
(173
|
)
|
|
|
(576
|
)
|
Total
assets
|
|
$
|
978
|
|
|
$
|
(200
|
)
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital
leases
|
|
$
|
(17,369
|
)
|
|
$
|
(21,082
|
)
|
Deferred tax
liability
|
|
|
6,935
|
|
|
|
7,893
|
|
Total
liabilities
|
|
|
(10,434
|
)
|
|
|
(13,189
|
)
|
|
|
|
|
|
|
|
|
|
Paid-in-capital
|
|
|
13,517
|
|
|
|
13,517
|
|
Retained
deficit
|
|
|
(2,105
|
)
|
|
|
(528
|
)
|
Total stockholders’
equity
|
|
|
11,412
|
|
|
|
12,989
|
|
Total liabilities and
stockholders’ equity
|
|
$
|
978
|
|
|
$
|
(200
|
)
|
|
|
|
|
|
|
|
|
|
Interest expense,
net
|
|
$
|
(2,536
|
)
|
$
|
(849
|
)
|
Income
tax benefit
|
|
|
959
|
|
|
321
|
|
Net
loss
|
|
$
|
(1,577
|
)
|
$
|
(528
|
)
|
|
|
|
|
|
|
|
|
In December 2007, the
FASB issued SFAS No. 141 (Revised 2007), Business
Combinations (“SFAS
No. 141(R)”). SFAS No. 141(R) will significantly change the accounting
for business combinations. Under SFAS No. 141(R), an acquiring entity will
be required to recognize all the assets acquired and liabilities assumed in a
transaction at the acquisition-date fair value with limited exceptions. SFAS
No. 141(R) will change the accounting treatment for certain specific
acquisition-related items including: (i) expensing acquisition-related
costs as incurred, (ii) valuing noncontrolling interests at fair value at
the acquisition date and (iii) expensing restructuring costs associated
with an acquired business. SFAS No. 141(R) also includes a substantial
number of new disclosure requirements. SFAS No. 141(R) is to be applied to
any business combination for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after
December 15, 2008. Upon adoption, SFAS No. 141(R) will impact the
accounting for the Company’s future business combinations.
F-11
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
In December 2007, the
FASB issued SFAS No. 160, Noncontrolling
Interests in Consolidated Financial Statements (“SFAS No. 160”). SFAS
No. 160 establishes new accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a noncontrolling interest in a subsidiary
(minority interest) is an ownership interest in the consolidated entity that
should be reported as equity in the consolidated financial statements and
separate from the parent company’s equity. Among other requirements, this
statement requires consolidated net income to be reported at amounts that
include the amounts attributable to both the parent and the noncontrolling
interest. It also requires disclosure, on the face of the consolidated statement
of operations, of the amounts of consolidated net income attributable to the
parent and to the noncontrolling interest. SFAS No. 160 is effective for
fiscal years, and interim periods within those fiscal years, beginning on or
after December 15, 2008. The Company is currently evaluating the effect, if
any, the adoption of SFAS No. 160 will have on its financial position,
results of operations and cash flows.
In March 2008, the
FASB issued SFAS No. 161, Disclosures about
Derivative Instruments and Hedging Activities – an amendment of FASB Statement
No. 133 (“SFAS
No. 161”). SFAS No. 161 requires additional disclosures for derivative
instruments and hedging activities that include how and why an entity uses
derivatives, how these instruments and the related hedged items are accounted
for under FASB Statement No. 133, Accounting for
Derivative Instruments and Hedging Activities, and related interpretations and how
derivative instruments and related hedged items affect the entity’s financial
position, results of operations and cash flows. SFAS No. 161 is effective
for fiscal years, and interim periods within those fiscal years, beginning after
November 15, 2008. Adoption of SFAS No. 161
did not impact the footnotes accompanying the Company’s consolidated financial
statements.
In May 2008, the
FASB issued SFAS No. 162, The Hierarchy of
Generally Accepted Accounting Principles (“SFAS No. 162”). SFAS No. 162
identifies the sources of accounting principles and the framework for selecting
the principles to be used in the preparation of financial statements of
nongovernmental entities that are presented in conformity with generally
accepted accounting principles. SFAS No. 162 directs the hierarchy to the
entity, rather than the independent auditors, as the entity is responsible for
selecting accounting principles for financial statements that are presented in
conformity with generally accepted accounting principles. SFAS No. 162 is
effective for fiscal years, and interim periods within those fiscal years,
beginning on or after December 15, 2008. Adoption of SFAS No. 162
did not have a material impact on the Company’s financial position, results of
operations or cash flows.
In June 2008, the
FASB issued EITF 03-6-1, Determining
Whether Instruments Granted in Share-Based Payment Transactions Are
Participating Securities (“EITF 03-6-1”). EITF 03-6-1 clarifies
that all outstanding unvested share-based payment awards that contain rights to
nonforfeitable dividends participate in undistributed earnings with common
shareholders. Awards of this nature are considered participating securities and
the two-class method of computing basic and diluted earnings per share must be
applied. EITF 03-6-1 is effective for fiscal years beginning after December 15,
2008. Adoption of EITF 03-6-1 did not have a material impact on the Company’s financial position, results of
operations or cash flows.
In June 2008, the
FASB ratified EITF 07-5, Determining Whether
an Instrument (or an Embedded Feature) Is Indexed to an Entity’s Own
Stock (“EITF 07-5”). EITF
07-5 provides that an entity should use a two step approach to evaluate whether
an equity-linked financial instrument (or embedded feature) is indexed to its
own stock, including evaluating the instrument’s contingent exercise and
settlement provisions. It also clarifies the impact of foreign currency
denominated strike prices and market-based employee stock option valuation
instruments on the evaluation. EITF 07-5 is effective for fiscal years beginning
after December 15, 2008. Adoption of EITF 07-5 did not have a material impact on the Company’s financial position, results of
operations or cash flows.
|
|
2008
|
|
|
2007
|
|
Coal
|
|
$
|
28,436
|
|
|
$
|
19,855
|
|
Parts and
supplies
|
|
|
32,159
|
|
|
|
21,602
|
|
Reserve for obsolescence, parts
and supplies
|
|
|
(1,807
|
)
|
|
|
(778
|
)
|
Total
|
|
$
|
58,788
|
|
|
$
|
40,679
|
|
F-12
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
4.
|
PROPERTY, PLANT, EQUIPMENT AND
MINE DEVELOPMENT
|
As of December 31, 2008 and 2007,
property, plant, equipment and mine development are summarized by major
classification as follows:
|
|
2008
|
|
|
2007
|
|
Coal lands and mineral
rights
|
|
$
|
586,512
|
|
|
$
|
594,034
|
|
Plant and
equipment
|
|
|
571,083
|
|
|
|
442,530
|
|
Mine
development
|
|
|
180,725
|
|
|
|
133,181
|
|
Land and land
improvements
|
|
|
24,119
|
|
|
|
20,889
|
|
Coalbed methane well development
costs
|
|
|
14,889
|
|
|
|
14,276
|
|
|
|
|
1,377,328
|
|
|
|
1,204,910
|
|
Less accumulated depreciation,
depletion and amortization
|
|
|
(309,182
|
)
|
|
|
(230,576
|
)
|
Net property, plant and
equipment
|
|
$
|
1,068,146
|
|
|
$
|
974,334
|
|
Depreciation, depletion and amortization
expense related to property, plant, equipment and mine development for the years
ended December 31, 2008, 2007 and 2006 was $105,637, $105,726 and $85,344,
respectively.
In
June 2008, the Company exchanged certain coal reserves with a third-party. In
addition to reserves, the Company received $3,000 in cash. As a result, the
Company recognized a pre-tax gain of $24,633 based upon the fair value of the
underlying assets received in the exchange, which is included in gain on sale of
assets in its statement of operations for the year ended December 31, 2008.
Additionally, in September 2008, the Company exchanged certain property
resulting in the recognition of a $975 pre-tax gain based upon the fair value of
the underlying assets given up in the exchange. The gain is included in gain on
sale of assets in the Company’s statement of operations for the year ended
December 31, 2008.
In
December 2008, the Company made the decision to permanently close its Sago mine
during the first quarter of 2009. As a result of this decision, the Company
recorded a $7,191 impairment charge. The assets of the Sago mine had been
included in the Company’s Northern Appalachian business segment.
In September 2007, the Company sold its
Denmark reserve in Southern Illinois for $39,000 in cash. As a result, the
Company recognized a gain of $36,782 which is included in gain on sale of assets
in its statement of operations for the year ended December 31, 2007. Under terms
of the transaction, the purchaser is also obligated to pay the Company an
overriding royalty totaling $4,000 on certain future production that will be
recognized as the reserves are mined.
F-13
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
The
Company recorded goodwill related to its acquisition of certain assets and
assumption of certain liabilities of Horizon and Anker/CoalQuest. The Company
assigned the goodwill to certain of the acquired reporting units based on their
estimated fair values. In accordance with SFAS No. 142, the Company tests
goodwill for impairment on an annual basis, at a minimum, and more frequently if
a triggering event occurs. The 2008 goodwill testing identified impairment of
goodwill at the Company’s ADDCAR Systems, LLC (“ADDCAR”) subsidiary resulting in
a $30,237 impairment loss. The loss reflects the negative impact of several
contributing factors which resulted in a reduction in the forecasted cash flows
to estimate fair value. These factors include but are not limited to less than
anticipated demand for and increased costs of contract mining services, an
increased reliance on lower-margin mining equipment sales and the need for
capital investment to replace aging equipment. Furthermore, the business,
regulatory and marketplace environment in which the Company currently operates
differs significantly from the historical environment that drove the business
case used to value and record the acquisition of this business unit.
Accordingly, the Company has been unable to attain the forecasted projections
that were used to initially value the business unit at the date of
acquisition.
The goodwill testing performed in 2007 identified impairment of goodwill at the following business units: $32,914
at Hazard, $58,511 at Eastern, $42,941 at East Kentucky and $36,036 at
Knott County.
In 2006, goodwill and certain assets
acquired and liabilities assumed were adjusted to fair value as a result of the
finalization of the purchase price allocation associated with the
Anker/CoalQuest acquisitions. Goodwill was primarily allocated to property,
plant, equipment and mine development. The adjustments to the purchase price
allocation of Horizon represents allocation of additional purchase price due to
excess actual expenses related to the acquisition over management’s original
estimates and reallocation of purchase price to assets and liabilities for which
fair values were not available at the time of the acquisition. The adjustments
to the purchase price allocation of Horizon recorded during 2006 were due to a
refund of legal fees held in escrow. Bonding royalties represent payments made
on the gross sales receipts for coal mined and sold by the former Horizon
companies that ICG acquired (see Note 16). At December 31, 2006, the entire
goodwill balance related to the Horizon
acquisition.
The changes in the carrying amount of
goodwill were as follows:
|
|
$
|
344,394
|
|
Adjustments to purchase price
allocation of Horizon
|
|
|
(812
|
)
|
Bonding
royalty
|
|
|
3,975
|
|
Adjustments to purchase price
allocation of Anker/CoalQuest
|
|
|
(150,800
|
)
|
|
|
|
196,757
|
|
Bonding
royalty
|
|
|
3,882
|
|
Impairment
loss
|
|
|
(170,402
|
)
|
|
|
|
30,237
|
|
Impairment
loss
|
|
|
(30,237
|
)
|
Balance as of December 31,
2008
|
|
$
|
—
|
|
6.
|
ACCRUED EXPENSES AND
OTHER
|
|
|
2008
|
|
|
2007
|
|
Compensation and related
expenses
|
|
$ |
38,076 |
|
|
$ |
25,147 |
|
Interest
|
|
|
17,776 |
|
|
|
17,330 |
|
Royalties
|
|
|
5,826 |
|
|
|
4,282 |
|
Sales and production related
taxes
|
|
|
5,574 |
|
|
|
5,098 |
|
Deferred
revenue
|
|
|
5,506 |
|
|
|
— |
|
Personal property, land and
mineral taxes
|
|
|
3,719 |
|
|
|
3,582 |
|
Transportation
|
|
|
3,453 |
|
|
|
2,655 |
|
Other
|
|
|
7,774 |
|
|
|
4,629 |
|
Total
|
|
$ |
87,704 |
|
|
$ |
62,723 |
|
F-14
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
7.
|
INVESTMENT IN JOINT OPERATING
AGREEMENT
|
In July 2005, CoalQuest entered
into an agreement with CDX Gas, LLC (“CDX”) for the purpose of exploration and
development of coalbed methane under a joint operating agreement, whereby
CoalQuest has the right to obtain up to a 50% undivided working interest in each
well drilled on property owned by the Company. The Company accounts for this
joint operation using the proportionate consolidation method, whereby its share
of assets, liabilities, revenues and expenses are included in the appropriate
classification in the Company’s financial statements. As of December 31, 2008
and 2007, the Company recorded assets of $2,356 and $5,891 net of accumulated
depletion of $12,533 and $8,385, respectively, related to the operating
agreement. This amount is included in net property, plant, equipment and mine
development in the consolidated balance sheet. For the years ended December 31,
2008, 2007 and 2006, the Company recorded $8,597, $7,741 and $1,949 and $2,935,
$983 and $313, respectively, of coalbed methane revenue and royalty income,
respectively, related to the operating agreement which is included in other
revenues in the consolidated statement of operations. During 2008, CDX declared
bankruptcy. As a result, the Company recorded a reserve against outstanding
accounts receivable due from CDX totaling $1,282.
In May 2008, the Company entered
into an agreement to purchase the membership interests of Powdul Acquisition
LLC. The purchase resulted in the Company acquiring the idle Powell Mountain underground mining operation and
related assets. The cost of the acquired entity totaled $18,067 which included
cash paid of $450, other related acquisition costs of $153 and total liabilities
of $17,464. Total liabilities include current liabilities of $132, asset
retirement obligations of $3,522 and a below-market contract valued at $13,810.
As a result of the purchase price allocation, the Company recorded current
assets of $1,335, mineral interests of $10,998, development costs of $1,922 and
property, plant and equipment of $3,812. The acquisition would not have had a
material impact on the Company’s results of operations had it taken place on
January 1, 2008.
Long-Term
Debt and Capital Leases
|
|
2008
|
|
|
2007
|
|
9.00% Convertible Senior Notes,
due 2012
|
|
$ |
225,000 |
|
|
$ |
225,000 |
|
10.25% Senior Notes, due
2014
|
|
|
175,000 |
|
|
|
175,000 |
|
Equipment
notes
|
|
|
43,378 |
|
|
|
12,330 |
|
Capital leases and
other
|
|
|
6,861 |
|
|
|
— |
|
Total
|
|
|
450,239 |
|
|
|
412,330 |
|
Less current
portion
|
|
|
15,319 |
|
|
|
4,234 |
|
Long-term
debt
|
|
$ |
434,920 |
|
|
$ |
408,096 |
|
Convertible
senior notes—In 2007, the Company completed a private
offering of $225,000 aggregate principal amount of 9.00% Convertible Senior
Notes (the “Convertible Notes”) due 2012. The Convertible Notes are the
Company’s senior unsecured obligations and are guaranteed on a senior unsecured
basis by the Company’s material future and current domestic subsidiaries. The
Convertible Notes and the related guarantees rank equal in right of payment to
all of the Company’s and the guarantors’ respective existing and future
unsecured senior indebtedness. Interest is payable semi-annually in arrears on
February 1 and August 1 of each year.
F-15
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
The Convertible Notes became convertible
at the option of holders beginning July 1, 2008. The conversion period
expired on September 30, 2008 pursuant to the terms of the governing indenture
with no holders exercising their conversion rights. The Convertible Notes may
become convertible again in the future under certain conditions. Accordingly,
the Company will reassess the convertibility on a
quarterly basis.
The principal amount of the Convertible
Notes is payable in cash and amounts above the principal amount, if any, will be
convertible into shares of the Company’s common stock or, at the Company’s option, cash. The Convertible Notes are
convertible at an initial conversion price, subject to adjustment, of $6.10 per
share (approximating 163.8136 shares per one thousand dollar principal amount of
the Convertible Notes). The volume weighted-average price of the Company’s stock subsequent to the expiration date
of the conversion period was below $6.10 per share. Accordingly, there were no
potentially convertible shares at December 31, 2008. The Convertible Notes are
convertible upon the occurrence of certain events, including (i) prior to
February 12, 2012 during any calendar quarter after September 30,
2007, if the closing sale price per share of the Company’s common stock for each of 20 or more
trading days in a period of 30 consecutive trading days ending on the last
trading day of the immediately preceding calendar quarter exceeds 130% of the
conversion price in effect on the last trading day of the immediately preceding
calendar quarter; (ii) prior to February 12, 2012 during the five
consecutive business days immediately after any five consecutive trading day
period in which the average trading price for the notes on each day during such
five trading-day period was equal to or less than 97% of the closing sale price
of the
Company’s common stock on
such day multiplied by the then current conversion rate; (iii) upon the
occurrence of specified corporate transactions; and (iv) at any time from,
and including February 1, 2012 until the close of business on the second
business day immediately preceding August 1, 2012. In addition, upon events
defined as a “fundamental change” under the Convertible Notes indenture, the
Company may be required to
repurchase the Convertible Notes at a repurchase price in cash equal to 100% of
the principal amount of the notes to be repurchased, plus any accrued and unpaid
interest to, but excluding, the fundamental change repurchase date. As such, in
the event of a fundamental change or the aforementioned average pricing
thresholds are met, the
Company would be required
to classify the entire amount outstanding of the Convertible Notes as a current
liability in the following quarter. In the event that a significant number of the holders of
the Convertible Notes were to convert their notes prior to maturity, the Company
may not have enough available funds at any particular time to make the required
repayments. Under these circumstances, the Company would look to WLR, its
banking group and other potential lenders to obtain short-term funding until
such time that it could secure necessary financing on a long-term basis. The
availability of any such financing would depend upon the circumstances at the
time, including the terms of any such financing, and other factors. In addition, if conversion occurs in
connection with certain changes in control, the Company may be required to deliver additional
shares of the
Company’s common stock (a
“make whole” premium) by increasing the conversion rate with respect to such
notes. For a discussion of the effects of the
Convertible Notes on earnings per share, see Note 15.
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,
2010. At any time prior to July 15, 2010, 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, 2008, the Company was in
compliance with its covenants under the indenture.
F-16
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
Credit
facility—In 2006, the Company entered into a
second amended and restated credit agreement (the “Amended Credit Facility”)
consisting of a revolving credit facility which matures on June 23, 2011.
In July 2007, concurrent with the issuance of the Convertible Notes, the Company
again amended the Amended Credit Facility to reduce the commitments thereunder
to $100,000 of which a maximum of $80,000 may be used for letters of credit. The
amendment, among other things, modified the maximum permitted leverage ratio,
the minimum interest coverage ratio and the maximum amount of capital
expenditures permitted. Further, the amendment revised certain interest rate
thresholds and unused commitment fee levels under the Amended Credit Facility.
In February 2009, the Company executed a further amendment to the Amended
Credit Facility that affected certain 2009 debt covenants. The amendment
modified the maximum permitted leverage and minimum interest coverage ratios.
The amendment also decreased the maximum capital spending and added a minimum
liquidity requirement. Debt covenants for years subsequent to 2009 were not
affected by the amendment. As of
December 31, 2008, the Company had no borrowings outstanding and letters of
credit totaling $73,551 outstanding, leaving $26,449 available for future
borrowing capacity. Interest on the borrowings under the Amended Credit Facility
is payable, at the Company’s option, at either the base rate plus an applicable
margin based on the Company’s leverage ratio of 1.25% to 2.00% as of
December 31, 2008 or LIBOR plus an applicable margin based on the Company’s
leverage ratio of 2.25% to 3.00% as of December 31, 2008. As of December
31, 2008, the Company was in compliance with its financial covenants under the
Amended Credit Facility.
Equipment
notes
and other—The equipment
notes, having
various maturity dates
extending to January
2014, are collateralized by
mining equipment. As of December 31, 2008, the Company had amounts outstanding
for 36-month through 60-month terms with a weighted-average interest rate of
6.42%. At December 31,
2008, additional funds are
available under the
Company’s revolving equipment credit facility for terms ranging from 36 to 60
months with a current interest rate of 8.75%. Additionally, the Company
finances certain of its annual insurance premiums at a current interest rate of
5.42%.
Future maturities of long-term debt
and capital leases
are as follows as of
December 31, 2008:
Year ending
December 31:
|
|
|
|
2009
|
|
$ |
15,319 |
|
2010
|
|
|
11,771 |
|
2011
|
|
|
9,839 |
|
2012
|
|
|
232,936 |
|
2013
|
|
|
5,306 |
|
Thereafter
|
|
|
175,068 |
|
Total
|
|
$ |
450,239 |
|
Short-Term Debt
The Company finances the majority of its
annual insurance premiums, a portion of which is included in short-term debt.
The weighted-average interest rate applicable to the notes was 4.65%. As of
December 31, 2008 and 2007, the Company had $4,741 and $0, respectively,
outstanding related to insurance financing.
F-17
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
10.
|
ASSET RETIREMENT
OBLIGATION
|
The Company’s
reclamation liabilities primarily consist of spending estimates related to
reclaiming surface land and support facilities at both surface and underground
mines in accordance with federal and state reclamation laws as defined by each
mine permit. The obligation and corresponding asset are recognized in the period
in which the liability is incurred.
The Company estimates
its ultimate reclamation liability based upon detailed engineering calculations
of the amount and timing of the future cash flows to perform the required work.
The Company considers the estimated current cost of reclamation and applies
inflation rates and third-party profit. The third-party profit is an estimate of
the approximate markup that would be charged by contractors for work performed
on the Company’s behalf. The discount rate applied is based on the rates of
treasury bonds with maturities similar to the estimated future cash flow,
adjusted for the Company’s credit standing.
At December 31, 2008
and 2007, the asset retirement obligation accrual for reclamation and mine
closure costs totaled $79,246 and $85,920, respectively. The assets that give
rise to the obligation are primarily related to mine development, preparation
plants and loadouts.
The following
schedule represents activity in the accrual for reclamation and mine closure
costs for the years ended December 31:
|
|
2008
|
|
|
2007
|
|
Balance at beginning of
year
|
|
$
|
85,920
|
|
|
$
|
92,670
|
|
Revisions of estimated cash
flows
|
|
|
(5,896
|
)
|
|
|
(12,620
|
)
|
Liabilities incurred (net of
disposals) or assumed in acquisitions
|
|
|
1,438
|
|
|
|
7,295
|
|
Expenditures
|
|
|
(9,594
|
)
|
|
|
(8,237
|
)
|
Accretion
|
|
|
7,378
|
|
|
|
6,812
|
|
Balance at end of
year
|
|
$
|
79,246
|
|
|
$
|
85,920
|
|
At December 31, 2008
and 2007, the accrued reclamation and mine closure costs are included in the
accompanying consolidated balance sheets as follows:
|
|
2008
|
|
|
2007
|
|
Current portion of reclamation and
mine closure costs
|
|
$
|
11,139
|
|
|
$
|
7,333
|
|
Non-current portion of Reclamation
and mine closure costs (non-current)
|
|
|
68,107
|
|
|
|
78,587
|
|
Total
|
|
$
|
79,246
|
|
|
$
|
85,920
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
375
|
|
|
$
|
1,046
|
|
|
$
|
(11,487
|
)
|
State
|
|
|
391
|
|
|
|
409
|
|
|
|
(767
|
)
|
|
|
|
766
|
|
|
|
1,455
|
|
|
|
(12,254
|
)
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(21,019
|
)
|
|
|
(75,406
|
)
|
|
|
2,637
|
|
State
|
|
|
(2,458
|
)
|
|
|
(11,672
|
)
|
|
|
602
|
|
|
|
|
(23,477
|
)
|
|
|
(87,078
|
)
|
|
|
3,239
|
|
Income tax
benefit
|
|
$
|
(22,711
|
)
|
|
$
|
(85,623
|
)
|
|
$
|
(9,015
|
)
|
F-18
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
The following table presents the
difference between the income tax benefit in the accompanying statements of
operations and the amounts obtained by applying the statutory U.S. federal income tax rate of 35% to
income and losses before income taxes for the years ended December 31, 2008,
2007 and 2006:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Federal income tax benefit
computed at statutory rate
|
|
$
|
(16,576
|
)
|
|
$
|
(81,430
|
)
|
|
$
|
(6,397
|
)
|
State income tax expense (net of
federal tax benefits) computed at statutory rate
|
|
|
(1,343
|
)
|
|
|
(7,321
|
)
|
|
|
(108
|
)
|
Percentage depletion in excess of
tax basis at statutory rate
|
|
|
(6,477
|
)
|
|
|
(1,784
|
)
|
|
|
(3,084
|
)
|
Penalties
|
|
|
1,869
|
|
|
|
—
|
|
|
|
—
|
|
Goodwill
impairment
|
|
|
(490
|
)
|
|
|
4,046
|
|
|
|
—
|
|
Other
|
|
|
306
|
|
|
|
866
|
|
|
|
574
|
|
Income tax
benefit
|
|
$
|
(22,711
|
)
|
|
$
|
(85,623
|
)
|
|
$
|
(9,015
|
)
|
Significant components of the Company’s
deferred tax assets and liabilities as of December 31, are summarized as
follows:
|
|
2008
|
|
|
2007
|
|
Deferred tax
assets:
|
|
|
|
|
|
|
|
|
Accrued employee
benefits
|
|
$
|
24,523
|
|
|
$
|
23,352
|
|
Accrued reclamation and
closure
|
|
|
30,274
|
|
|
|
31,271
|
|
|
|
|
15,691
|
|
|
|
16,777
|
|
NOL
carryover
|
|
|
68,909
|
|
|
|
48,637
|
|
Goodwill
|
|
|
53,960
|
|
|
|
40,501
|
|
Other
|
|
|
19,705
|
|
|
|
11,100
|
|
|
|
|
213,062
|
|
|
|
171,638
|
|
Deferred tax
liabilities:
|
|
|
|
|
|
|
|
|
Property, coal lands and mine
development costs
|
|
|
(232,937
|
)
|
|
|
(212,474
|
)
|
Other
|
|
|
(4,944
|
)
|
|
|
(6,519
|
)
|
|
|
|
(237,881
|
)
|
|
|
(218,993
|
)
|
Net deferred tax
liability
|
|
$
|
(24,819
|
)
|
|
$
|
(47,355
|
)
|
|
|
|
|
|
|
|
|
|
Classified in balance
sheet:
|
|
|
|
|
|
|
|
|
Deferred income
taxes—current
|
|
$
|
17,649
|
|
|
$
|
5,000
|
|
Deferred income
taxes—non-current
|
|
|
(42,468
|
)
|
|
|
(52,355
|
)
|
Total
|
|
$
|
(24,819
|
)
|
|
$
|
(47,355
|
)
|
The Company
has a total net operating loss (“NOL”) carryover of $186,441, of which $2,707
expires in 2024, $17,154 expires in 2025, $5,331 expires in 2026, $99,748
expires in 2027 and $61,501 expires in 2028. The Company is subject to a
limitation of approximately $6,900 per year on $19,861 of the NOLs attributable
to certain acquired entities. However, due to the cumulative nature of the
limitation, the Company has full utilization of NOLs starting in 2008. The
Company also has an alternative minimum tax (“AMT”) loss in the amount of
$35,392, of which $4,451 expires in 2024, $16,796 expires in 2025, and $14,145
expires in 2028. The AMT NOL attributable to certain acquired entities of
$21,247 is subject to the same annual limitation specified above for the regular
NOL. The NOLs reflect $582 of excess tax deductions, which reduce the NOL
carryforward portion of the deferred tax asset. The Company will recognize the
excess tax deduction at such time that the deduction will reduce taxes payable.
Adjustments have been made to certain regular and AMT NOL carryovers as a result
of current Internal Revenue Service audits of 2006 and 2007.
Internal
Revenue Code (“IRC”) Section 382 imposes significant limitations on the annual
utilization of NOL carryforwards if a “change in ownership” is deemed to occur.
Generally, an ownership change is deemed to occur if the Company experiences a
cumulative change in ownership of greater than 50% within a three-year testing
period. The Company completed an IRC Section 382 study and determined that an
ownership change had occurred. Although the IRC Sec 382 ownership change result
in an annual limitation of the Company’s NOL carryforwards, all NOLs are
expected to be fully utilized within the remaining NOL carryforward
period.
The Company
recorded a valuation allowance of $2,396 against certain state NOL carryforwards
that, more likely than not, are expected to expire without being
utilized.
The Company
files income tax returns in the U.S. and various states. Generally, the Company
is no longer subject to U.S. federal, state and local income tax examinations by
tax authorities for years before 2005. The Company is currently under
examination by the Internal Revenue Service and the state of West Virginia for
certain tax years pertaining to income taxes.
F-19
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
|
|
2008
|
|
|
2007
|
|
Postretirement
benefits
|
|
$ |
27,974 |
|
|
$ |
25,024 |
|
Black lung
benefits
|
|
|
27,455 |
|
|
|
24,788 |
|
Workers’ compensation
benefits
|
|
|
7,847 |
|
|
|
6,781 |
|
Coal Act
benefits
|
|
|
1,277 |
|
|
|
1,464 |
|
Total
|
|
|
64,553 |
|
|
|
58,057 |
|
Less current
portion
|
|
|
3,359 |
|
|
|
2,925 |
|
Employee
benefits—non-current
|
|
$ |
61,194 |
|
|
$ |
55,132 |
|
Postretirement
Benefits—Employees of the
Company who complete ten years of service, and certain employees who have
completed eight years of service with the former Horizon companies and complete
two years with ICG, will be eligible to receive postretirement benefits, which
consists of healthcare benefits. Upon reaching the retirement age of 65, in
order to receive a maximum medical life-time benefit of one hundred thousand
dollars per family, eligible retired employees must pay two hundred and fifty
dollars per month per family. The Company accrues postretirement benefit expense
based on actuarially determined amounts. The amount of postretirement benefit
cost accrued is impacted by various assumptions (discount rate, healthcare cost
increases, etc.) that the Company uses in determining its postretirement
obligations. The Company assumed discount rates of 6.25% and 6.50% for the years
ended December 31, 2008 and 2007, respectively. Postretirement benefit expense
for the Company totaled $4,664, $3,394 and $2,021 for the years ended December
31, 2008, 2007 and 2006, respectively.
|
|
2008
|
|
|
2007
|
|
Changes in Benefit
Obligations:
|
|
|
|
|
|
|
|
|
Accumulated benefit obligations at
beginning of period
|
|
$
|
25,024
|
|
|
$
|
18,331
|
|
Service
cost
|
|
|
2,607
|
|
|
|
2,057
|
|
Interest
cost
|
|
|
1,627
|
|
|
|
1,054
|
|
Actuarial
(gain)/loss
|
|
|
(1,257
|
)
|
|
|
3,593
|
|
Benefits
paid
|
|
|
(27
|
)
|
|
|
(11
|
)
|
Accumulated benefit obligation at
end of period
|
|
|
27,974
|
|
|
|
25,024
|
|
Fair value of plan assets at end
of period
|
|
|
—
|
|
|
|
—
|
|
Net liability
recognized
|
|
$
|
27,974
|
|
|
$
|
25,024
|
|
The changes in the actuarial loss that
are included in accumulated other comprehensive income were as
follows:
|
|
$
|
10,235
|
|
Actuarial
gain
|
|
|
(1,257
|
)
|
Amortization of actuarial
gain
|
|
|
(430
|
)
|
|
|
|
8,548
|
|
The Company expects to recognize $288 of
the net actuarial gain as a component of the net periodic benefit cost during
2009. Components of net
periodic benefit cost for the years ended December 31, 2008, 2007 and 2006 are
as follows:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Net periodic benefit
cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
2,607
|
|
|
$
|
2,057
|
|
|
$
|
1,297
|
|
Interest
cost
|
|
|
1,627
|
|
|
|
1,054
|
|
|
|
668
|
|
Amortization of actuarial
gain/loss
|
|
|
430
|
|
|
|
283
|
|
|
|
56
|
|
Benefit
cost
|
|
$
|
4,664
|
|
|
$
|
3,394
|
|
|
$
|
2,021
|
|
For measurement purposes, an 8.33%
annual rate of increase in the per capita cost of covered healthcare benefits
was assumed, gradually decreasing to 5.00% in 2015 and remaining level
thereafter.
F-20
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
The expense and liability estimates can
fluctuate by significant amounts based upon the assumptions used. As of December
31, 2008, a one-percentage-point increase in assumed healthcare cost trend rates
would increase total service and interest cost components and the postretirement
benefit obligation by $410 and $1,793, respectively. Conversely, a
one-percentage-point decrease would reduce total service and interest cost
components and the postretirement benefit obligation by $378 and $1,713,
respectively.
Estimated future benefit payments for
the years indicated ending after December 31, 2008 are as
follows:
2009
|
|
$
|
523
|
2010
|
|
|
925
|
2011
|
|
|
1,580
|
2012
|
|
|
2,134
|
2013
|
|
|
2,934
|
2014 – 2018
|
|
|
25,652
|
Total
|
|
$
|
33,748
|
The Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (the “Act") provides for a
prescription drug benefit under Medicare (“Medicare Part D”), as well as a
federal subsidy to sponsors of retiree healthcare benefit plans that provide a
benefit that is at least actuarially equivalent to Medicare Part D. The Company
accounts for the subsidy as prescribed by FSP FAS 106-2, Accounting and
Disclosure Requirements related to the Medicare Prescription Drug, Improvement
and Modernization Act of 2003 (“FSP 106-2”). As of December 31,
2008, the Company determined the effects of the Act resulted in a $426 reduction
of its postretirement benefit obligation. The Act is expected to result in a
$113 reduction of the Company’s postretirement benefit cost for the year ended
December 31, 2009. The effect on the Company’s postretirement benefit cost
components includes reductions of $65, $27 and $21 to the service cost, interest
cost and amortization of accumulated postretirement benefit obligation,
respectively.
Workers’
Compensation and Black Lung—The operations of the Company are
subject to the federal and state workers’ compensation laws. These laws provide
for the payment of benefits to disabled workers and their dependents, including
lifetime benefits for black lung. The Company’s subsidiary operations are
insured by a combination of participation in a state run program and insurance
policies. The Company’s workers’ compensation liability is discounted at
5.50%.
The Company’s actuarially determined
liability for self-insured black lung benefits is based on a 5.75% discount rate
and various other assumptions, including incidence of claims, benefits
escalation, terminations and life expectancy. The annual black lung expense
consists of actuarially determined amounts for self-insured obligations. The
estimated amount of discounted obligations for self-insured black lung claims,
plus an estimate for incurred but not reported claims, was $22,824 and $17,758
as of December 31, 2008 and 2007, respectively. The unrecognized projected black
lung benefit obligations (difference between recorded accrual and projected
obligations) at December 31, 2008 and 2007 was a gain of approximately $4,631
and $7,030, respectively, and is being provided for over the future service
period of current employees. The projected black lung obligations may vary in a
given year based on the timing of claims filed and changes in assumptions. The
Company recorded expenses related to black lung of $1,097, $2,709 and $4,245 for
the years ended December 31, 2008, 2007 and 2006,
respectively.
F-21
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
UMWA
Combined Benefit Fund (Coal Act)—The Coal Industry Retiree Health
Benefit Act of 1992 (the “Coal Act”) provides for the funding of medical and
death benefits for certain retired members of the UMWA. It provides for the
assignment of beneficiaries to their former employers and any unassigned
beneficiaries to employers based on a formula. Based upon actuarially determined
amounts for the latest list of beneficiaries assigned to Anker, the Company
estimates the amount of its obligation under the Coal Act to be approximately
$1,277 and $1,464 as of December 31, 2008 and 2007, discounted at 6.25% and
6.00%, respectively. The Company recorded interest expense related to the Coal
Act of $80, $302 and $345 for the years ended December 31, 2008, 2007 and 2006,
respectively.
401(k)
Plans—The Company sponsors
a savings and retirement plan for substantially all employees. The Company
matches voluntary contributions of participants, except for those previously
employed by Anker, up to a maximum contribution of 3% of a participant’s salary.
The Company also contributes an additional 3% non-elective contribution for
every employee eligible to participate in the program. The expense under this
plan for the Company was $6,971, $4,293 and $5,182 for the years ended December
31, 2008, 2007 and 2006, respectively.
For those employees previously employed
by Anker, and who meet eligibility requirements, the Company also has a 401(k)
savings plan. The plan provides for a 100% match of the first 3% of employee
contributions and 50% of the next 2% of employee contributions. The Company also
contributes an additional 5% non-elective contribution for every employee
eligible to participate in the program. The expense under this plan for the
Company was $1,956, $1,776 and $1,736 for the years ended December 31, 2008,
2007 and 2006, respectively.
13.
|
EMPLOYEE STOCK
AWARDS
|
The Company’s 2005 Equity and
Performance Incentive Plan (the “Plan”) permits the granting of stock options,
restricted shares, stock appreciation rights, restricted share units,
performance shares or performance units to its employees for up to 8,000,000
shares of common stock. Option awards are generally granted with an exercise
price equal to the market price of the Company’s stock at the date of grant and
have 10-year contractual terms. The option and restricted stock awards generally
vest in equal annual installments of 25% over a four-year period. The Company
recognizes expense related to the awards on a straight-line basis over the
vesting period. The Company issues new shares upon the exercise of option
awards.
The Black-Scholes option pricing model
was used to calculate the estimated fair value of the options granted. The
estimated grant date fair value of the options granted in 2008, 2007 and 2006
was calculated using the following assumptions:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Expected term (in
years)
|
|
|
5 |
|
|
|
5 |
|
|
|
5 |
|
Expected
volatility
|
|
|
43.0% - 48.2 |
% |
|
|
43.0%
- 48.1 |
% |
|
|
48.1 |
% |
Weighted-average
volatility
|
|
|
43.5 |
% |
|
|
43.2 |
% |
|
|
48.1 |
% |
Risk-free
rate
|
|
|
1.7% - 3.7 |
% |
|
|
4.0% - 5.1 |
% |
|
|
4.6% - 5.2 |
% |
Expected
dividends
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company estimated a forfeiture rate
of 4.50%, 3.25% and 1.00% for 2008, 2007 and 2006,
respectively.
Due to the Company’s limited operating
history, the expected lives and volatility are estimated based on other
companies in the coal industry. The risk-free interest rates are based on the
rates of zero coupon U.S. Treasury bonds with similar maturities on the date of
grant. The forfeiture rate was determined based on estimates of future turnover
of the Company’s employees eligible under the plan.
F-22
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
Stock-based employee compensation
expense of $2,596, $3,134 and $3,501, net of tax of $1,578, $2,090 and $2,167,
related to the issuance of all stock awards outstanding was included in earnings
for the years ended December 31, 2008, 2007 and 2006,
respectively.
|
|
Shares
|
|
Weighted-
Average
Exercise
Price
|
|
Weighted-
Average
Remaining
Contractual
Term
(years)
|
|
Aggregate
Intrinsic
Value
|
|
|
|
2,012,342
|
|
$
|
8.76
|
|
|
|
|
|
Granted
|
|
1,055,160
|
|
|
6.35
|
|
|
|
|
|
Exercised
|
|
(17,700
|
)
|
|
8.39
|
|
|
|
|
|
Forfeited and
expired
|
|
(218,610
|
)
|
|
8.44
|
|
|
|
|
|
|
|
2,831,192
|
|
|
7.88
|
|
7.9
|
$
|
(15,811
|
)
|
|
|
2,725,556
|
|
|
7.93
|
|
7.9
|
$
|
(15,338
|
)
|
|
|
1,329,907
|
|
|
9.28
|
|
7.0
|
$
|
(9,280
|
)
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average grant-date fair
value of options granted during the years ended December 31, 2008, 2007 and 2006
was $2.64, $2.65 and $3.93, respectively. The total intrinsic value of options
exercised during the year ended December 31, 2008 was $47. There were no options
exercised in 2007 or 2006.
|
|
Shares
|
|
|
Weighted-
Average Grant-Date
Fair
Value
|
|
|
|
|
574,190 |
|
|
$ |
9.15 |
|
Granted
|
|
|
349,194 |
|
|
|
6.74 |
|
Vested
|
|
|
(323,020
|
) |
|
|
10.40 |
|
Forfeited
|
|
|
(44,020
|
) |
|
|
8.00 |
|
|
|
|
556,344 |
|
|
|
7.00 |
|
|
|
|
|
|
|
|
|
|
The weighted-average grant-date fair
value of restricted stock granted during the years ended December 31, 2008, 2007
and 2006 was $6.74, $5.87 and $8.50, respectively. The total fair value of
restricted stock vested during the years ended December 31, 2008, 2007 and 2006
was $3,361, $3,221 and $2,933, respectively.
As of December 31, 2008, there was
$6,237 of unrecognized compensation cost related to non-vested stock-based
awards that is expected to be recognized over a weighted-average period of 2.6
years.
F-23
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
14.
|
VARIABLE INTEREST
ENTITIES
|
The Company acquired a 50% interest in
Sycamore Group, LLC (“Sycamore”) in conjunction with its acquisition of Anker.
Sycamore was established as a joint venture with an unrelated third-party to
mine coal from the Sycamore No. 1 mine. The reserve from Sycamore
No. 1 was depleted and the mine closed during the first quarter of 2007.
The Company considers itself to be the primary beneficiary of Sycamore, based on
an evaluation of its involvement with Sycamore and the provisions of FIN 46(R),
and has consolidated the accounts of Sycamore as of December 31, 2008 and 2007,
as well as the results of operations for the year ended December 31, 2008, 2007
and 2006. The creditors of Sycamore have no recourse to the general credit of
ICG. Amounts related to Sycamore that are included in the consolidated financial
statements of ICG as of and for the years ending December 31, 2008, 2007 and
2006, are as follows:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Assets
|
|
$
|
213
|
|
|
$
|
257
|
|
|
$
|
3,342
|
|
Liabilities
|
|
|
138
|
|
|
|
187
|
|
|
|
1,097
|
|
Revenue
|
|
|
—
|
|
|
|
1,808
|
|
|
|
10,343
|
|
Net income
(loss)
|
|
|
—
|
|
|
|
(403
|
)
|
|
|
130
|
|
Reconciliations of the weighted-average
shares used to compute basic and diluted earnings per share for the years ended
December 31, 2008, 2007 and 2006 are as follows:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Net loss
|
|
$
|
(24,650
|
)
|
|
$
|
(147,034
|
)
|
|
$
|
(9,320
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average common shares
outstanding—Basic
|
|
|
152,632,586
|
|
|
|
152,304,461
|
|
|
|
152,028,165
|
|
Incremental shares arising from
stock options
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Incremental shares arising from
restricted shares
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Incremental shares arising from
convertible notes
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Average common shares
outstanding—Diluted
|
|
|
152,632,586
|
|
|
|
152,304,461
|
|
|
|
152,028,165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per
Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and
Diluted
|
|
$
|
(0.16
|
)
|
|
$
|
(0.97
|
)
|
|
$
|
(0.06
|
)
|
Options to purchase 2,831,192 shares of
common stock and 556,344 shares of restricted common stock outstanding at
December 31, 2008 have been excluded from the computation of diluted net loss
per share for the year ended December 31, 2008 because their effect would have
been anti-dilutive. Options to purchase 2,012,342 shares of common stock and
574,190 shares of restricted common stock outstanding at December 31, 2007 have
been excluded from the computation of diluted net loss per share for the year
ended December 31, 2007 because their effect would have been anti-dilutive.
Options to purchase 1,814,302 shares of common stock and 787,540 shares of
restricted common stock outstanding at December 31, 2006 have been excluded from
the computation of diluted net loss per share for the year ended December 31,
2006 because their effect would have been anti-dilutive.
In July 2007, the
Company completed the offering of its Convertible Notes. The principal amount of
the Convertible Notes is payable in cash and amounts above the principal amount,
if any, will be convertible into shares of the Company’s common stock or, at the
Company’s option, cash. The volume weighted-average price of the Company’s
stock during the applicable measurement period was below $6.10 per share.
Accordingly, there were no potentially dilutive shares at December 31,
2008.
F-24
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
16.
|
COMMITMENTS AND
CONTINGENCIES
|
Guarantees
and Financial Instruments with Off-balance Sheet Risk—In the normal course of business, the
Company is a party to certain guarantees and financial instruments with
off-balance sheet risk, such as bank letters of credit and performance or surety
bonds. No liabilities related to these arrangements are reflected in the
Company’s consolidated balance sheets. Management does not expect any material
losses to result from these guarantees or off-balance sheet financial
instruments.
Coal
Sales Contracts—As of
December 31, 2008, the Company had commitments under 49 sales contracts to
deliver annually scheduled base quantities of coal to 34 customers. The
contracts expire from 2009 through 2020 with the Company contracted to supply a
minimum of approximately 63.5 million tons of coal over the remaining lives
of the contracts (maximum of approximately 16.9 million tons in
2009).
Coal
Purchase Contracts—As of
December 31, 2008, the Company had commitments to purchase coal to meet its
sales commitments. Certain of the contracts have sales price adjustment
provisions, subject to certain limitations and adjustments, based on a variety
of factors and indices. The following is a summary of the Company’s future
contractual purchase obligations by year as of December 31,
2008:
Year ending
December 31:
|
|
|
|
2009
|
|
$ |
22,926 |
|
2010
|
|
|
14,377 |
|
Total
|
|
$ |
37,303 |
|
F-25
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
Leases—The Company leases various mining,
transportation and other equipment under operating and capital leases. Lease
expense for the years ended December 31, 2008, 2007 and 2006 was $4,970, $6,254
and $15,194, respectively. Property under capital lease included in property,
plant, equipment and mine development in the consolidated balance sheet at
December 31, 2008 was approximately $3,816, less accumulated depreciation
of approximately $0. There were no capital leases at December 31, 2007. At
December 31, 2008, the Company imputed interest on its capital lease using
a rate of 10% in order to reduce the net minimum lease payments to present
value. Depreciation expense related to assets under capital leases is included
in depreciation, depletion and amortization in the Company’s consolidated
statement of operations.
The Company also leases coal lands and
mineral rights under agreements that call for royalties to be paid as the coal
is mined. Total royalty expense for the years ended December 31, 2008, 2007 and
2006 was approximately $52,232, $37,680 and $38,458, respectively. Certain
agreements require minimum annual royalties to be paid regardless of the amount
of coal mined during the year. Certain agreements may be cancelable at the
Company’s discretion.
Non-cancelable future minimum royalty
and lease payments as of December 31, 2008 are as follows:
|
|
Royalties
|
|
|
Operating
Leases
|
|
|
Capital
Leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
10,111 |
|
|
$ |
87 |
|
|
$ |
1,726 |
|
2010
|
|
|
9,925 |
|
|
|
63 |
|
|
|
1,726 |
|
2011
|
|
|
9,715 |
|
|
|
19 |
|
|
|
863 |
|
2012
|
|
|
8,408 |
|
|
|
— |
|
|
|
— |
|
2013
|
|
|
8,228 |
|
|
|
— |
|
|
|
— |
|
Thereafter
|
|
|
37,004 |
|
|
|
— |
|
|
|
— |
|
Total minimum lease
payments
|
|
$ |
83,391 |
|
|
$ |
169 |
|
|
$ |
4,315 |
|
Less—amount representing
interest
|
|
|
|
|
|
|
|
|
|
|
499 |
|
Present
value of minimum lease payments
|
|
|
|
|
|
|
|
|
|
|
3,816 |
|
Less—current
portion
|
|
|
|
|
|
|
|
|
|
|
1,430 |
|
Total
long-term portion of capital leases
|
|
|
|
|
|
|
|
|
|
$ |
2,386 |
|
Bonding
Royalty and Additional Payment—Lexington Coal Company, LLC (“LCC”) was
organized in part by the founding ICG stockholders in conjunction with the
acquisition of the former Horizon companies. LCC was organized to assume certain
reclamation liabilities and assets of Horizon not otherwise being acquired by
ICG or others. There was initially a limited commonality of ownership of LCC and
ICG. In order to provide support to LCC, ICG provided a $10,000 letter of credit
to support reclamation obligations (Bonding Royalty) and in addition agreed to
pay a 0.75% payment on the gross sales receipts for coal mined and sold by the
former Horizon companies that ICG acquired from Horizon until the completion by
LCC of all reclamation liabilities that LCC assumed from Horizon (“Additional
Payments”). The Company
made payments totaling $4,457, $3,883 and $3,975 for the years ended December
31, 2008, 2007 and 2006, respectively.
Under the Bonding Royalty, ICG was
required to pay an additional 0.75% on gross sales referred to above to a fund
controlled by one of its sureties until all letters of credit issued by such
surety for both ICG and LCC were cash collateralized. During 2005, the surety
released ICG of its obligation to maintain additional cash collateral and
refunded all of the cash previously paid to collateralize the letters of credit.
In March 2006, the $10,000 letter of credit to support reclamation obligations
(Bonding Royalty) was also released. Under the provisions of FIN 46(R), ICG has
determined it does not hold a significant variable interest in LCC and it is not
the primary beneficiary of LCC.
F-26
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
Legal
Matters—On August 23, 2006, a survivor of
the Sago mine accident, Randal McCloy, filed a complaint in the Kanawha Circuit
Court in Kanawha
County, West Virginia. The claims brought by Randal McCloy
and his family against the Company and certain of its subsidiaries, and against
W.L. Ross & Co., and Wilbur L. Ross, Jr., individually, were dismissed
on February 14, 2008, after the parties reached a confidential settlement.
Sixteen other complaints have been filed in Kanawha Circuit Court by the
representatives of many of the miners who died in the Sago mine accident, and
several of these plaintiffs have filed amended complaints to expand the group of
defendants in the cases. The complaints allege various causes of action against
the Company and its subsidiary, Wolf Run Mining Company, one of the Company’s
shareholders, W.L. Ross & Co., and Wilbur L. Ross Jr., individually,
related to the accident and seek compensatory and punitive damages. In addition,
the plaintiffs also allege causes of action against other third parties,
including claims against the manufacturer of Omega block seals used to seal the
area where the explosion occurred and against the manufacturer of self-contained
self-rescuer (“SCSR”) devices worn by the miners at the Sago mine. Some of these
third parties have been dismissed from the actions upon settlement. The amended
complaints add other of the Company’s subsidiaries to the cases, including ICG,
Inc., ICG, LLC and Hunter Ridge Coal Company, unnamed parent, subsidiary and
affiliate companies of the Company, W.L. Ross & Co., and Wilbur L. Ross
Jr., and other third parties, including a provider of electrical services and a
supplier of components used in the SCSR devices. The Company believes that it is
appropriately insured for these and other potential claims, and it has fully
paid its deductible applicable to its insurance policies. In addition to the
dismissal of the McCloy claim, the Company has settled and dismissed five other
actions. These settlements required the release of the Company, the Company’s
subsidiaries, W. L. Ross & Co., and Wilbur L. Ross, Jr. Some of the
plaintiffs involved in one of the dismissed actions have sought permission from
the Supreme Court of Appeals of West Virginia to appeal the settlement, alleging
that the settlement negotiated by the decedent’s estate should not have been
approved by the trial court. The trial court overruled those plaintiffs’
objections to the settlement, and, although the West Virginia Supreme Court of
Appeals refused to stay the effectiveness of the settlement, the plaintiffs’
petition for appeal to the West Virginia Supreme Court of Appeals was recently
presented to the court. The court has not yet ruled whether it will accept the
petition for appeal or decline to hear the appeal. The Company will vigorously defend
itself against the remaining complaints and any appeal of any prior
settlements.
Allegheny Energy Supply (“Allegheny”),
the sole customer of coal produced at the Company’s subsidiary Wolf Run Mining
Company’s (“Wolf Run”) Sycamore No. 2 mine, filed a lawsuit against Wolf
Run, Hunter Ridge Holdings, Inc. (“Hunter Ridge”), and the Company in state
court in Allegheny County, Pennsylvania on December 28, 2006, and amended
its complaint on April 23, 2007. Allegheny claims that the Company breached
a coal supply contract when it declared force majeure under the contract upon
idling the Sycamore No. 2 in the third quarter of 2006. The Sycamore
No. 2 mine was idled after encountering adverse geologic conditions and
abandoned gas wells that were previously unidentified and unmapped. The amended
complaint also alleges that the production stoppages constitute a breach of the
guarantee agreement by Hunter Ridge and breach of certain representations made
upon entering into the contract in early 2005, a claim that Allegheny has since
voluntarily dropped. Allegheny claims that it will incur costs in excess of
$100,000 to purchase replacement coal over the life of the contract. The
Company, Wolf Run and Hunter Ridge answered the amended complaint on August 13,
2007, disputing all of the remaining claims. On November 3, 2008, the Company,
Wolf Run and Hunter Ridge filed an amended answer and counterclaim against the
plaintiffs seeking to void the coal supply agreement due to, among other things,
fraudulent inducement and conspiracy. The counterclaim alleges further that
Allegheny breached a confidentiality agreement with Hunter Ridge, which
prohibited the solicitation of its employees. After the coal supply agreement
was executed, Allegheny hired the then-president of Anker Coal Group, Inc. (now
Hunter Ridge) who engaged in negotiations on behalf of Wolf Run and Hunter
Ridge. In addition to seeking a declaratory judgment that the coal supply
agreement and guaranty be deemed void and unenforceable and rescission of the
contracts, the counterclaim also seeks compensatory and punitive
damages.
On December 6, 2007, the Kentucky
Waterways Alliance, Inc., and The Sierra Club sued the U.S. Army Corps of
Engineers (the “ACOE”) in the United States District Court for the Western
District of Kentucky, Louisville Division (the “Court”), asserting that a permit
to construct five valley fills was issued unlawfully to the Company’s Hazard
subsidiary for its Thunder Ridge Surface mine. The suit alleges that the ACOE
failed to comply with the requirements of both Section 404 of the Clean
Water Act and the National Environmental Policy Act. Hazard has intervened in
the suit to protect the Company’s interests. The ACOE suspended the
Section 404 permit on December 26, 2007 in order to evaluate the
issues raised by the plaintiffs. That evaluation is now in progress. If the ACOE
reinstates the permit and the Court subsequently finds that the permit is
unlawful, production could be materially affected at the Thunder Ridge Surface
mine and the process of obtaining ACOE permits for coal mining activities in
Kentucky could become more difficult.
On January 7, 2008, Saratoga
Advantage Trust filed a class action lawsuit in the U.S. District Court for the
Southern District of West Virginia against the Company and certain of its
officers and directors. The complaint asserts claims under Sections 10(b) and
20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated
thereunder, based on alleged false and misleading statements in the registration
statements filed in connection with the Company’s November 2005 reorganization
and December 2005 public offering of common stock. In addition, the complaint
challenges other of the Company’s public statements regarding the Company’s
operating condition and safety record. The Company intends to vigorously defend
the action.
On
July 3, 2007, Taylor Environmental Advocacy Membership, Inc. (“T.E.A.M.”) filed
a petition to appeal the issuance of ICG Tygart Valley, LLC’s (“Tygart Valley”)
Surface Mine Permit U-2004-06 against the West Virginia Department of
Environmental Protection (the “WVDEP”) in an action before the West Virginia
Surface Mine Board (the “Board”). On December 10, 2007, the Board remanded the
permit to the WVDEP for revision to certain provisions related to pre-mining
water monitoring and cumulative hydrologic impacts. The WVDEP issued a
modification on April 1, 2008 addressing those issues. T.E.A.M. filed an appeal
of the WVDEP’s approval of the permit modification on April 30, 2008. On October
7, 2008, the Board issued an order remanding the permit to the WVDEP requiring
Tygart Valley to address a technical issue related to projected post-mining
water quality. Tygart Valley has prepared and submitted a permit modification to
alleviate the board’s concerns. All site development will be suspended until the
WVDEP has approved the permit modification. If the WVDEP issues the permit
as modified, there will be additional opportunity for appeal by
T.E.A.M.
From time to time, the Company is
involved in legal proceedings arising in the ordinary course of business. These
proceedings include assessments of penalties for citations and orders asserted
by the Mine Safety and Health Administration, and other regulatory agencies none
of which are expected by management to individually or in the aggregate have a
material adverse effect on the Company. In the opinion of management, the
Company has recorded adequate reserves for liabilities arising in the ordinary
course and it is management’s belief there is no individual case or group of
related cases pending that is likely to have a material adverse effect on the
financial condition, results of operations or cash flows of the
Company.
F-27
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
Environmental
Matters—Based upon current
knowledge, the Company believes it is in material compliance with environmental
laws and regulations as currently promulgated. However, the exact nature of
environmental control problems, if any, which the Company may encounter in the
future cannot be predicted, primarily because of the increasing number,
complexity and changing character of environmental requirements that may be
enacted by federal and state authorities.
Performance
Bonds—The Company has
outstanding surety bonds with third parties of approximately $115,667 as of
December 31, 2008 to secure reclamation and other performance commitments. In
addition, at December 31, 2008 the Company has $73,551 of letters of credit
outstanding under the revolving credit facility, a portion of which $61,126
provides support to the third parties for their issuance of surety bonds. In
addition, the Company has posted cash collateral of $1,589 and $1,563 to secure
reclamation and other performance commitments as of December 31, 2008 and 2007,
respectively. This cash collateral is included in other non-current assets on
the consolidated balance sheets.
Contract
Mining Agreements—ICG’s
subsidiary, ADDCAR, performs contract mining services for various third parties
and utilizes contract miners on some of its operations. Terms of the agreements
generally allow either party to terminate the agreements on a short-term basis.
The guaranteed monthly contract tonnage is mutually agreed upon and failure to
meet the guaranteed contract tonnage may result in termination of the contract.
Completion dates for work under these contracts vary in dates ranging from 2009
to 2010.
17.
|
CONCENTRATION OF CREDIT RISK AND
MAJOR CUSTOMERS
|
The Company markets its coal principally
to electric utilities in the United States, the majority of which have investment
grade credit ratings. As of December 31, 2008 and 2007, trade accounts
receivable from electric utilities totaled approximately $49,059 and $57,029,
respectively. The Company evaluates each customer’s creditworthiness prior to
entering into transactions and constantly monitors the credit extended, but does
not require its customers to provide collateral. Credit losses are provided for
in the consolidated financial statements and historically have been
minimal.
The Company had coal sales to the
following major customers that equaled or exceeded 10% of
revenues:
|
|
Total
Receivable
Balance
|
|
|
Year Ended
Total
Revenues
|
|
|
Total
Receivable
Balance
|
|
|
Year Ended
Total
Revenues
|
|
|
Total
Receivable
Balance
|
|
|
Year Ended
Total
Revenues
|
|
Customer A
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
2,886 |
|
|
$ |
97,389 |
|
|
$ |
4,893 |
|
|
$ |
135,025 |
|
Customer B
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
6,397 |
|
|
|
117,249 |
|
Customer C
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
6,041 |
|
|
|
94,935 |
|
Deposits held with banks may exceed the
amount of insurance provided on such deposits. Generally, these deposits may be
redeemed upon demand and are maintained with financial institutions of reputable
credit and, therefore, bear minimal risk.
F-28
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
18.
|
FAIR VALUE OF FINANCIAL
INSTRUMENTS
|
The estimated fair values of the
Company’s financial instruments are determined based on relevant market
information. These estimates involve uncertainty and cannot be determined with
precision. The following methods and assumptions were used to estimate the fair
value of each class of financial instrument.
Effective January 1, 2008, the
Company adopted SFAS No. 157, which clarifies the definition of fair value,
establishes a framework for measuring fair value and expands the disclosures on
fair value measurements. SFAS No. 157 applies whenever other statements
require or permit assets or liabilities to be measured at fair value. SFAS
No. 157 requirements for certain non-financial assets and liabilities have
been deferred until the first quarter of 2009 in accordance with FASB Staff
Position 157-2, Effective Date of
FASB Statement No. 157. SFAS No. 157 establishes the
following fair value hierarchy that prioritizes the inputs used to measure fair
value:
•
|
Level 1 –
|
Unadjusted quoted prices for
identical assets or liabilities in active
markets.
|
|
|
|
•
|
Level 2 –
|
Inputs other than Level 1 that are
based on observable market data, either directly or indirectly. These
include quoted prices for similar assets or liabilities in active markets,
quoted prices for identical assets or liabilities in inactive markets,
inputs that are observable that are not prices and inputs that are derived
from or corroborated by observable markets.
|
|
|
|
•
|
Level 3 –
|
Developed from unobservable data,
reflecting an entity’s own
assumptions.
|
The Company entered into an Interest
Rate Collar Agreement (the “Collar”) that expires on March 31, 2009. The
interest rate collar was designed as a cash flow hedge to offset the impact of
changes in the LIBOR interest rate above 5.92% and below 4.80%. At December 31,
2008, a liability for the fair value of the Collar was included in accrued
expenses and other on the Company’s consolidated balance sheet. The value of the
interest rate collar is based on a forward LIBOR curve, which is observable at
commonly quoted intervals for the full term of the agreement. The Company
recognizes the change in the fair value of this agreement in the period of
change. For the years ended December 31, 2008, 2007 and 2006, the Company
recorded losses of $1,993, $1,649 and $939 respectively, related to the change
in fair value. The losses are included in interest expense in the Company’s
consolidated statement of operations.
The following table presents the fair
value hierarchy for financial liabilities measured at fair value on a recurring
basis:
|
|
|
|
|
Fair Value Measurements Using:
|
|
Description
|
|
December 31,
2008
|
|
|
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
|
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Interest Rate Collar
Agreement
|
|
$ |
1,665 |
|
|
$ |
— |
|
|
$ |
1,665 |
|
|
$ |
— |
|
Cash
and Cash Equivalents, Accounts Receivable, Accounts Payable, Short-Term Debt and
Other Current Liabilities—The carrying amounts approximate the
fair value due to the short maturity of these instruments.
Long-term
Debt—At December 31,
2008 and 2007, the Company had $225,000 aggregate principal amount of its 9.0%
Convertible Notes outstanding. The fair value of the Convertible Notes was
approximately $114,683 and $266,445 as of December 31, 2008 and 2007,
respectively. At December 31, 2008 and 2007, the Company had $175,000
aggregate principal amount of its 10.25% Senior Notes outstanding. The fair
value of the Senior Notes was approximately $131,250 and $167,125 as of
December 31, 2008 and 2007, respectively.
F-29
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
19.
|
RELATED PARTY TRANSACTIONS AND
BALANCES
|
Under an Advisory Services Agreement
dated as of October 1, 2004 between the Company and WLR, WLR has agreed to
provide advisory services to the Company (consisting of consulting and advisory
services in connection with strategic and financial planning, investment
management and administration and other matters relating to the business and
operation of the Company of a type customarily provided by sponsors of U.S.
private equity firms to companies in which they have substantial investments,
including any consulting or advisory services which the Board of Directors
reasonably requests). WLR is paid a quarterly fee of $500 and reimbursed for any
reasonable out-of-pocket expenses (including expenses of third-party advisors
retained by WLR). The agreement is for a period of seven years; however, it may
be terminated upon the occurrence of certain events.
The Company has paid legal fees relating
to the representation of WLR and the Company’s Chairman, Mr. Wilbur L.
Ross, Jr., by counsel in connection with various litigation matters pending
against the Company, WLR and Mr. Wilbur L. Ross, Jr. related to the
Sago mine accident. The Company did not record any expense in 2008 relating to
these matters. During the year ended December 31, 2007 the Company recorded
expenses totaling approximately $739 relating to these
matters.
The Company extracts, processes and
markets steam and metallurgical coal from deep and surface mines for sale to
electric utilities and industrial customers, primarily in the eastern
United States. The Company operates only in the
United States with mines in the Central Appalachian,
Northern Appalachian and Illinois Basin regions. The Company has three
reportable business segments: Central Appalachian, Northern Appalachian and
Illinois Basin. The Company’s Central Appalachian
operations are located in southern West Virginia, eastern Kentucky and western Virginia and include eight mining complexes. The
Company’s Northern Appalachian operations are located in northern West Virginia and Maryland and include four mining complexes. The
Company’s Illinois Basin operations include one mining complex.
The Company also has an Ancillary category, which includes the Company’s
brokered coal functions, corporate overhead, contract highwall mining services
and land activities.
F-30
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
|
|
Central
Appalachian
|
|
|
Northern
Appalachian
|
|
|
Illinois
Basin
|
|
|
Ancillary
|
|
|
Consolidated
|
|
Revenue
|
|
$ |
702,958 |
|
|
$ |
230,660 |
|
|
$ |
79,682 |
|
|
$ |
83,436 |
|
|
$ |
1,096,736 |
|
Adjusted
EBITDA
|
|
|
107,186 |
|
|
|
23,687 |
|
|
|
14,784 |
|
|
|
(18,436
|
) |
|
|
127,221 |
|
Depreciation, depletion and
amortization
|
|
|
64,132 |
|
|
|
17,884 |
|
|
|
7,342 |
|
|
|
6,689 |
|
|
|
96,047 |
|
Impairment
losses
|
|
|
— |
|
|
|
7,191 |
|
|
|
— |
|
|
|
30,237 |
|
|
|
37,428 |
|
Capital
expenditures
|
|
|
111,980 |
|
|
|
41,624 |
|
|
|
7,146 |
|
|
|
11,069 |
|
|
|
171,819 |
|
Total
assets
|
|
|
751,018 |
|
|
|
184,666 |
|
|
|
40,848 |
|
|
|
373,137 |
|
|
|
1,349,669 |
|
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.
|
|
Central
Appalachian
|
|
|
Northern
Appalachian
|
|
|
Illinois
Basin
|
|
|
Ancillary
|
|
|
Consolidated
|
|
Revenue
|
|
$ |
530,255 |
|
|
$ |
133,284 |
|
|
$ |
68,440 |
|
|
$ |
117,176 |
|
|
$ |
849,155 |
|
Adjusted
EBITDA
|
|
|
47,442 |
|
|
|
(22,215
|
) |
|
|
15,463 |
|
|
|
18,363 |
|
|
|
59,053 |
|
Depreciation, depletion and
amortization
|
|
|
60,015 |
|
|
|
9,467 |
|
|
|
6,527 |
|
|
|
10,508 |
|
|
|
86,517 |
|
Impairment
losses
|
|
|
170,402 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
170,402 |
|
Capital
expenditures
|
|
|
129,021 |
|
|
|
37,896 |
|
|
|
2,639 |
|
|
|
11,695 |
|
|
|
181,251 |
|
Total
assets
|
|
|
653,288 |
|
|
|
161,306 |
|
|
|
37,861 |
|
|
|
451,108 |
|
|
|
1,303,563 |
|
Goodwill
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
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.
|
|
Central
Appalachian
|
|
|
Northern
Appalachian
|
|
|
Illinois
Basin
|
|
|
Ancillary
|
|
|
Consolidated
|
|
Revenue
|
|
$ |
541,844 |
|
|
$ |
122,041 |
|
|
$ |
56,606 |
|
|
$ |
171,103 |
|
|
$ |
891,594 |
|
Adjusted
EBITDA
|
|
|
108,598 |
|
|
|
(36,586
|
) |
|
|
4,476 |
|
|
|
(4,456
|
) |
|
|
72,032 |
|
Depreciation, depletion and
amortization
|
|
|
48,050 |
|
|
|
10,822 |
|
|
|
6,287 |
|
|
|
7,059 |
|
|
|
72,218 |
|
Capital
expenditures
|
|
|
95,033 |
|
|
|
73,173 |
|
|
|
7,950 |
|
|
|
20,822 |
|
|
|
196,978 |
|
Total
assets
|
|
|
752,200 |
|
|
|
147,285 |
|
|
|
41,103 |
|
|
|
376,303 |
|
|
|
1,316,891 |
|
Goodwill
|
|
|
167,105 |
|
|
|
— |
|
|
|
— |
|
|
|
29,652 |
|
|
|
196,757 |
|
Revenue in the Ancillary category
consists primarily of $141,919 relating to the Company’s brokered coal sales and
$25,249 relating to contract highwall mining activities. Capital expenditures
include non-cash amounts of $31,320.
F-31
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
Adjusted EBITDA represents net income
before deducting interest expense, income taxes, depreciation, depletion,
amortization, impairment charges and minority 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:
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
Net loss
|
|
$
|
(24,650
|
)
|
|
$
|
(147,034
|
)
|
|
$
|
(9,320
|
)
|
Depreciation, depletion and
amortization
|
|
|
96,047
|
|
|
|
86,517
|
|
|
|
72,218
|
|
Interest expense,
net
|
|
|
41,107
|
|
|
|
35,140
|
|
|
|
18,091
|
|
Income tax
benefit
|
|
|
(22,711
|
)
|
|
|
(85,623
|
)
|
|
|
(9,015
|
)
|
Impairment
loss
|
|
|
37,428
|
|
|
|
170,402
|
|
|
|
—
|
|
Minority
interest
|
|
|
—
|
|
|
|
(349
|
)
|
|
|
58
|
|
Adjusted
EBITDA
|
|
$
|
127,221
|
|
|
$
|
59,053
|
|
|
$
|
72,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21.
|
SUPPLEMENTARY GUARANTOR
INFORMATION
|
International Coal Group, Inc. (the
“Parent Company”) issued $175,000 of Senior Notes due 2014 (the “Notes”) in June
2006 and $225,000 of Convertible Senior Notes due 2012 (the “Convertible Notes”)
in July 2007. The Parent Company has no independent assets or operations other
than those related to the issuance, administration and repayment of the Notes
and the Convertible Notes. All subsidiaries of the Parent Company (the
“Guarantors”), except for a minor non-guarantor joint venture, have fully and
unconditionally guaranteed the Notes and the Convertible Notes on a joint and
several basis. The Guarantors are 100% owned, directly or indirectly, by the
Parent Company. Accordingly, condensed consolidating financial information for
the Parent Company and the Guarantors are not presented.
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.
F-32
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS—(Continued)
(Dollars in thousands, except per share
amounts)
The following is a summary of selected
quarterly financial information (unaudited):
|
|
2008
|
|
|
|
Three months
ended
March 31
|
|
|
Three months
ended
June 30
|
|
|
Three months
ended
September 30
|
|
|
Three months
ended
December 31
|
|
Revenue
|
|
$
|
251,925
|
|
|
$
|
277,885
|
|
|
$
|
309,199
|
|
|
$
|
257,727
|
|
Income (loss) from
operations
|
|
|
(7,369
|
)
|
|
|
30,461
|
|
|
|
20,726
|
|
|
|
(50,072
|
)
|
Net income
(loss)
|
|
|
(11,546
|
)
|
|
|
14,138
|
|
|
|
9,708
|
|
|
|
(36,950
|
)
|
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
|
)
|
|
|
2007
|
|
|
|
Three months
ended
March 31
|
|
|
Three months
ended
June 30
|
|
|
Three months
ended
September 30
|
|
|
Three months
ended
December 31
|
|
Revenue
|
|
$
|
228,314
|
|
|
$
|
208,050
|
|
|
$
|
207,829
|
|
|
$
|
204,962
|
|
Income (loss) from
operations
|
|
|
(8,815
|
)
|
|
|
(10,850
|
)
|
|
|
10,230
|
|
|
|
(188,750
|
)
|
Net loss
|
|
|
(8,068
|
)
|
|
|
(10,234
|
)
|
|
|
(1,283
|
)
|
|
|
(127,449
|
)
|
Basic earnings per common
share
|
|
$
|
(0.05
|
)
|
|
$
|
(0.07
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.84
|
)
|
Diluted earnings per common
share
|
|
$
|
(0.05
|
)
|
|
$
|
(0.07
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.84
|
)
|
Included in
the three months ended December 31, 2008 and 2007 are impairment losses of
$37,428 and $170,402, respectively. For 2008, $30,237 of the loss related to
impairment of goodwill at the Company’s ADDCAR subsidiary and $7,191 related to
impairment of long-lived assets. For 2007, the impairment loss related to
impairment of goodwill at various of the Company’s business units. See Notes 4
and 5 to the Company’s
consolidated financial statements for further discussion of the impairment
losses.
F-33
International
Coal Group, Inc.
Parent
Company Balance Sheets
(Dollars
in thousands, except per share amounts)
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
DEBT ISSUANCE COSTS,
net
|
|
|
9,024
|
|
|
|
11,206
|
|
DEFERRED INCOME
TAXES
|
|
|
25,741
|
|
|
|
|
|
|
|
|
876,734
|
|
|
|
909,471
|
|
Total
assets
|
|
$
|
911,499
|
|
|
$
|
931,159
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’
EQUITY
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accrued expenses and
other
|
|
$
|
16,709
|
|
|
$ |
16,788
|
|
Total current
liabilities
|
|
|
16,709
|
|
|
|
16,788
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT AND CAPITAL
LEASES
|
|
|
400,000
|
|
|
|
400,000
|
|
Total
liabilities
|
|
|
416,709
|
|
|
|
416,788
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND
CONTINGENCIES
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS’
EQUITY:
|
|
|
|
|
|
|
|
|
Preferred stock – par value $0.01, 200,000,000 shares
authorized, none issued
|
|
|
—
|
|
|
|
—
|
|
Common stock – par value $0.01, 2,000,000,000
shares authorized,
153,322,245 and
152,992,109 shares, respectively, issued and
outstanding
|
|
|
1,533
|
|
|
|
1,530
|
|
Additional paid-in
capital
|
|
|
643,480
|
|
|
|
639,160
|
|
Accumulated other comprehensive
loss
|
|
|
(5,157
|
)
|
|
|
(5,903
|
)
|
Retained
deficit
|
|
|
(145,066
|
)
|
|
|
(120,416
|
)
|
Total stockholders’
equity
|
|
|
494,790
|
|
|
|
514,371
|
|
Total liabilities and
stockholders’ equity
|
|
$
|
911,499
|
|
|
$
|
931,159
|
|
F-34
International
Coal Group, Inc.
Parent
Company Statements of Operations
(Dollars
in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
INCOME FROM
OPERATIONS
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
INTEREST AND OTHER INCOME
(EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense,
net
|
|
|
(40,369
|
)
|
|
|
(27,730
|
)
|
|
|
(9,684
|
)
|
Loss before income
taxes
|
|
|
(40,369
|
)
|
|
|
(27,730
|
)
|
|
|
(9,684
|
)
|
INCOME TAX (EXPENSE)
BENEFIT
|
|
|
15,259
|
|
|
|
10,482
|
|
|
|
3,702
|
|
|
|
|
460
|
|
|
|
(129,786
|
)
|
|
|
(3,338
|
)
|
Net loss
|
|
$
|
(24,650
|
)
|
|
$
|
(147,034
|
)
|
|
$
|
(9,320
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and
diluted
|
|
$
|
(0.16
|
)
|
|
$
|
(0.97
|
)
|
|
$
|
(0.06
|
)
|
Weighted-average common shares
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and
diluted
|
|
|
152,632,586
|
|
|
|
152,304,461
|
|
|
|
152,028,165
|
|
F-35
International
Coal Group, Inc.
Parent
Company Statements of Cash Flows
(Dollars
in thousands)
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
NET CASH FROM OPERATING
ACTIVITIES
|
|
$
|
(38,266
|
)
|
|
$
|
(19,036
|
)
|
|
$
|
|
|
CASH FLOWS FROM INVESTING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,266
|
|
|
|
(198,121
|
)
|
|
|
(170,047
|
)
|
Net cash from investing
activities
|
|
|
38,266
|
|
|
|
(198,121
|
)
|
|
|
(170,047
|
)
|
CASH FLOWS FROM FINANCING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from senior notes
offering
|
|
|
—
|
|
|
|
—
|
|
|
|
175,000
|
|
Proceeds from convertible notes
offering
|
|
|
—
|
|
|
|
225,000
|
|
|
|
|
|
Debt issuance
costs
|
|
|
—
|
|
|
|
(7,843
|
)
|
|
|
(4,953
|
)
|
Net cash from financing
activities
|
|
|
—
|
|
|
|
217,157
|
|
|
|
170,047
|
|
NET CHANGE IN CASH AND CASH
EQUIVALENTS
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
CASH AND CASH EQUIVALENTS, END OF
PERIOD
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
F-36
|
|
2008
|
|
|
2007
|
|
9.00% Convertible Senior Notes,
due 2012
|
|
$ |
225,000 |
|
|
$ |
225,000 |
|
10.25% Senior Notes, due
2014
|
|
|
175,000 |
|
|
|
175,000 |
|
Total
|
|
|
400,000 |
|
|
|
400,000 |
|
Less current
portion
|
|
|
— |
|
|
|
— |
|
Long-term
debt
|
|
$ |
400,000 |
|
|
$ |
400,000 |
|
|
|
|
|
|
|
|
|
|
Convertible
senior notes—In 2007, the Company completed a private
offering of $225,000 aggregate principal amount of 9.00% Convertible Senior
Notes (the “Convertible Notes”) due 2012. The Convertible Notes are the
Company’s senior unsecured obligations and are guaranteed on a senior unsecured
basis by the Company’s material future and current domestic subsidiaries. The
Convertible Notes and the related guarantees rank equal in right of payment to
all of the Company’s and the guarantors’ respective existing and future
unsecured senior indebtedness. Interest is payable semi-annually in arrears on
February 1 and August 1 of each year.
Senior
notes—In 2006, the Company sold $175,000
aggregate principal amount of the Company’s 10.25% Senior Notes (the “Notes”)
due July 15, 2014. Interest on the Notes is payable semi-annually in
arrears on July 15 and January 15 of each year. The Notes are senior
unsecured obligations and are guaranteed on a senior unsecured basis by all of
the Company’s current and future domestic subsidiaries that are material or that
guarantee the Company’s amended and restated credit
facility.
The indenture governing the Notes
contains covenants that limit the Company’s ability to, among other things,
incur additional indebtedness, issue preferred stock, pay dividends, repurchase,
repay or redeem the Company’s capital stock, make certain investments, sell
assets and incur liens. As of December 31, 2008, the Company was in
compliance with its covenants under the indenture.
See Note 9 to the consolidated financial
statements included elsewhere in the Annual Report of 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, 2008 (in thousands):
Year ending
December 31:
|
|
|
|
2009
|
|
$ |
— |
|
2010
|
|
|
— |
|
2011
|
|
|
— |
|
2012
|
|
|
225,000 |
|
2013
|
|
|
— |
|
Thereafter
|
|
|
175,000 |
|
Total
|
|
$ |
400,000 |
|
|
|
|
|
|
F-37
|
|
Balance at
Beginning
of
Period
|
|
|
Charged to
Revenue,
Costs or
Expenses
|
|
|
Other
Additions
(Deductions)
|
|
|
Balance at
End of
Period
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful
accounts
|
|
$ |
539 |
|
|
$ |
994 |
|
|
$ |
(17 |
) |
|
$ |
1,516 |
|
Reserve for inventory
obsolescence
|
|
|
778 |
|
|
|
1,029 |
|
|
|
— |
|
|
|
1,807 |
|
Reserve for loss—advance
royalties
|
|
|
3,771 |
|
|
|
630 |
|
|
|
(492
|
) |
|
|
3,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful
accounts
|
|
$ |
36 |
|
|
$ |
503 |
|
|
$ |
— |
|
|
$ |
539 |
|
Reserve for inventory
obsolescence
|
|
|
576 |
|
|
|
(82
|
) |
|
|
284 |
|
|
|
778 |
|
Reserve for loss—advance
royalties
|
|
|
638 |
|
|
|
3,414 |
|
|
|
(281
|
) |
|
|
3,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful
accounts
|
|
$ |
— |
|
|
$ |
36 |
|
|
$ |
— |
|
|
$ |
36 |
|
Reserve for inventory
obsolescence
|
|
|
311 |
|
|
|
265 |
|
|
|
— |
|
|
|
576 |
|
Reserve for loss—advance
royalties
|
|
|
— |
|
|
|
(412
|
) |
|
|
1,050 |
|
|
|
638 |
|
F-38
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:
|
|
|
Bennett K.
Hatfield
President and Chief Executive
Officer
|
Pursuant to the requirements of the
Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and the capabilities and on the
dates indicated.
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
|
President, Chief Executive Officer
and Director
|
|
February 27, 2008
|
Bennett K.
Hatfield
|
|
(Principal Executive
Officer)
|
|
|
|
|
|
|
|
Senior Vice President and Chief
Financial Officer
|
|
February 27, 2008
|
Bradley W.
Harris
|
|
(Principal Accounting and
Principal Financial Officer)
|
|
|
|
|
|
|
|
Non-Executive Chairman and
Director
|
|
February 27, 2008
|
Wilbur L. Ross,
Jr.
|
|
|
|
|
|
|
|
|
|
Director
|
|
February 27, 2008
|
Maurice E. Carino,
Jr.
|
|
|
|
|
|
|
|
|
|
Director
|
|
February 27, 2008
|
Cynthia B.
Bezik
|
|
|
|
|
|
|
|
|
|
Director
|
|
February 27, 2008
|
William J.
Catacosinos
|
|
|
|
|
|
|
|
|
|
Director
|
|
February 27, 2008
|
Stanley N. Gaines
|
|
|
|
|
|
|
|
|
|
Director
|
|
February 27, 2008
|
Samuel A.
Mitchell
|
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
February 27, 2008
|
Wendy L.
Teramoto
|
|
|
|
|
*
|
The undersigned, by signing his
name hereto, does sign and execute this Annual Report on Form 10-K
pursuant to the Powers of Attorney executed by the above-named officers
and Directors of the Company and filed with the Securities and Exchange
Commission on behalf of such officers and
Directors.
|
INTERNATIONAL COAL GROUP,
INC.
|
|
|
By:
|
|
|
Bennett K. Hatfield,
Attorney-in-Fact
|
|
|
Description
|
|
Note
|
|
2.1
|
|
Business Combination Agreement
among International Coal Group, Inc. (n/k/a ICG, Inc.), ICG Holdco, Inc.
(n/k/a International Coal Group, Inc.), ICG Merger Sub, Inc., Anker Merger
Sub, Inc. and Anker Coal Group, Inc., dated as of March 31,
2005
|
|
(B
|
)
|
|
|
|
2.2
|
|
First Amendment to the Business
Combination Agreement among International Coal Group, Inc. (f/k/a ICG
Holdco, Inc.), ICG, Inc. (f/k/a International Coal Group, Inc.), ICG
Merger Sub, Inc., Anker Merger Sub, Inc. and Anker Coal Group, Inc., dated
as of May 10, 2005
|
|
(B
|
)
|
|
|
|
2.3
|
|
Second Amendment to the Business
Combination Agreement among International Coal Group, Inc. (f/k/a ICG
Holdco, Inc.), ICG, Inc. (f/k/a International Coal Group, Inc.), ICG
Merger Sub, Inc., Anker Merger Sub, Inc. and Anker Coal Group, Inc.,
effective as of June 29, 2005
|
|
(C
|
)
|
|
|
|
2.4
|
|
Business Combination Agreement
among International Coal Group, Inc. (n/k/a ICG, Inc.), ICG Holdco, Inc.
(n/k/a International Coal Group, Inc.), CoalQuest Merger Sub LLC,
CoalQuest Development LLC and the members of CoalQuest Development LLC,
dated as of March 31, 2005
|
|
(B
|
)
|
|
|
|
2.5
|
|
First Amendment to the Business
Combination Agreement among International Coal Group, Inc. (f/k/a ICG
Holdco, Inc.), ICG, Inc. (f/k/a International Coal Group, Inc.), CoalQuest
Merger Sub LLC, CoalQuest Development LLC and the members of CoalQuest
Development LLC, dated as of May 10, 2005
|
|
(B
|
)
|
|
|
|
2.6
|
|
Second Amendment to the Business
Combination Agreement among International Coal Group, Inc. (f/k/a ICG
Holdco, Inc.), ICG, Inc. (f/k/a International Coal Group, Inc.), CoalQuest
Merger Sub LLC, CoalQuest Development LLC and the members of CoalQuest
Development LLC, effective as of June 29, 2005
|
|
(C
|
)
|
|
|
|
3.1
|
|
|
|
(E
|
)
|
|
|
|
3.2
|
|
Form of Second Amended and
Restated By-laws of International Coal Group, Inc.
|
|
(F
|
)
|
|
|
|
4.1
|
|
Form of certificate of
International Coal Group, Inc. common stock
|
|
(D
|
)
|
|
|
|
4.2
|
|
Registration Rights Agreement by
and between International Coal Group, Inc., WLR Recovery Fund II, L.P.,
Contrarian Capital Management LLC, Värde Partners, Inc., Greenlight
Capital, Inc., and Stark Trading, Shepherd International Coal Holdings
Inc.
|
|
(B
|
)
|
|
|
|
4.3
|
|
Form of Registration Rights
Agreement between International Coal Group, Inc. and certain former Anker
Stockholders and CoalQuest members
|
|
(C
|
)
|
|
|
|
4.4
|
|
Indenture, dated June 23, 2006, by
and among ICG, the guarantors party thereto and The Bank of New York Trust
Company, N.A., as trustee relating to International Coal Group, Inc.’s
10.25% senior notes
|
|
(H
|
)
|
|
|
|
4.5
|
|
Form of 10.25% senior note
(included in Exhibit 4.1)
|
|
(H
|
)
|
|
|
|
4.6
|
|
Form of guarantee relating to
International Coal Group, Inc.’s 10.25% senior notes (included in Exhibit
4.1)
|
|
(H
|
)
|
|
|
|
4.7
|
|
Indenture, dated as of July 31,
2007, among International Coal Group, Inc., and the guarantors party
thereto and The Bank of New York Trust Company, N.A. as Trustee, relating
to International Coal Group, Inc.’s 9.00% Convertible
Notes.
|
|
(J
|
)
|
|
|
|
4.8
|
|
Form of 9.00% Senior Convertible
Note (included in Exhibit 4.7)
|
|
(J
|
)
|
|
|
|
4.9
|
|
Form of Guarantee relating to
International Coal Group, Inc.’s 9.00% Convertible
Notes
|
|
(J
|
)
|
|
|
|
4.10
|
|
Registration Rights Agreement,
dated as of July 31, 2007, among International Coal Group, Inc., and the
guarantors party thereto and UBS Securities LLC as
purchaser.
|
|
(J
|
)
|
|
|
|
10.1
|
|
Second Amended and Restated Credit
Agreement, dated June 23, 2006, by and among ICG, LLC, as borrower, the
guarantors party thereto, the lenders party thereto, J.P. Morgan
Securities Inc. and UBS Securities LLC, as joint lead arrangers and joint
bookrunners, JPMorgan Chase Bank, N.A. and CIT Capital Securities LLC, as
co-syndication agents, Bank of America, N.A. and Wachovia Bank, N.A. as
co-documentation agents, JPMorgan Chase Bank, N.A. and Bank of America,
N.A. as issuing banks, UBS Loan Finance LLC, as swingline lender, and UBS
AG, Stamford Branch, as an issuing bank, administrative agent and
collateral agent
|
|
(H
|
)
|
|
|
Description
|
|
Note
|
|
10.2
|
|
Security Agreement dated as of
September 30, 2004 among ICG, LLC and the guarantors party thereto and UBS
AG, Stamford Branch, as Collateral Agent
|
|
(A
|
)
|
|
|
|
10.3
|
|
Advisory Services Agreement
effective as of October 1, 2004 between International Coal Group, LLC and
W.L. Ross & Co. LLC
|
|
(A
|
)
|
|
|
|
10.4
|
|
Employment Agreement dated March
14, 2005 by and between Bennett K. Hatfield and International Coal Group,
Inc.
|
|
(A
|
)
|
|
|
|
10.5
|
|
Employment Agreement dated April
25, 2005 by and between Roger L. Nicholson and International Coal Group,
Inc.
|
|
(B
|
)
|
|
|
|
10.6
|
|
International Coal Group, Inc.
2005 Equity and Performance Incentive Plan
|
|
(D
|
)
|
|
|
|
10.7
|
|
International Coal Group, Inc.
2005 Equity and Performance Incentive Plan: Incentive Stock Option
Agreement
|
|
(D
|
)
|
|
|
|
10.8
|
|
International Coal Group, Inc.
2005 Equity and Performance Incentive Plan: Non-Qualified Stock Option
Agreement
|
|
(D
|
)
|
|
|
|
10.9
|
|
International Coal Group, Inc.
2005 Equity and Performance Incentive Plan: Restricted Share
Agreement
|
|
(D
|
)
|
|
|
|
10.10
|
|
Form of Indemnification
Agreement
|
|
(D
|
)
|
|
|
|
10.11
|
|
Fee Lease between Kentucky Union
Company, lessor, and ICG Hazard, LLC (assigned from Leslie Resources,
Inc.), lessee, of Flint Ridge Surface Mine, amended
by:
|
|
(C
|
)
|
|
|
|
|
|
(a) Assignment of Real
Property Agreements, dated September 30, 2004, assigning to
ICG Hazard, LLC
|
|
|
|
|
|
|
10.14
|
|
Coal Lease between Knight-Ink
Heirs, lessor, and ICG Eastern, LLC (assigned from Cherry River Coal and
Coke Company), lessee, of Birch River Mine, amended
by:
|
|
(C
|
)
|
|
|
|
|
|
(a) Partial Assignment of
Lease, dated September 20, 1984, assigning to Twin River Coal
Co.
|
|
|
|
|
|
|
|
|
(b) General Conveyance,
Assignment and Transfer, dated December 8, 1988, assigning to Island Creek
Coal Co.
|
|
|
|
|
|
|
|
|
(c) Assignment, dated
December 12, 1990, assigning to Laurel Run Mining
Co.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
|
|
|
|
|
|
Description
|
|
Note
|
|
10.15
|
|
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) Memorandum of Lease and
Sublease Agreement, dated June 1, 2001
|
|
|
|
|
|
|
|
|
(c) Assignment of Real
Property Agreements, dated September 30, 2004, assigning to
ICG Eastern, LLC
|
|
|
|
|
|
|
10.17
|
|
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) Memorandum of Lease and
Sublease Agreement, dated June 1, 2001
|
|
|
|
|
|
|
|
|
(c) Assignment of Real
Property Agreements, dated September 30, 2004, assigning to
ICG Eastern, LLC
|
|
|
|
|
|
|
10.18
|
|
Fee Lease between ACIN
(successor-in-interest to CSTL, LLC), lessor, and ICG Hazard, LLC
(assigned from Leslie Resources, Inc.), lessee, of County Line and Rowdy Gap Mines, amended
by:
|
|
(C
|
)
|
|
|
|
|
|
(a) Assignment of Real
Property Agreements, dated September 30, 2004, assigning to
ICG Hazard, LLC
|
|
|
|
|
|
|
10.19
|
|
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.
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(c) Assignment of Real
Property Agreements, dated September 30, 2004, assigning to
ICG Hazard, LLC
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10.20
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Lease between Allegany Coal and
Land Company, lessor, and Patriot Mining Company, Inc., lessee, of
Allegany County, Maryland Mine, including:
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(C
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)
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10.21
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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:
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(C
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)
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(a) Modification and
Amendment, dated and effective December 28, 1970
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(b) Second Modification and
Amendment, dated and effective August 22, 1974
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(c) Agreement and Partial
Surrender and Release, dated and effective October 13,
1980
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(d) Amendment, dated and
effective January 1, 1983
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(e) Amendment, dated and
effective January 1, 1986
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Description
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Note
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(f) Amendment, dated and
effective January 1, 1991
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(h) Acceptance by Pine Valley
Coal Company, Inc., dated and effective October 31,
1994
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10.22
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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:
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(C
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)
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(a) Amendment, dated and
effective August 1, 1975
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(b) Amendment, dated and
effective August 1, 1986
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(c) Amendment, dated and
effective August 1, 1991
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(d) Acceptance by Pine Valley
Coal Company, Inc., dated and effective October 31,
1994
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10.23
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Lease between Douglas Coal
Company, lessor, and Vindex Energy Corp. (assigned from Patriot Mining
Company, Inc.), lessee, of Island and Douglas Mine,
including:
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(C
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)
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(b) Guarantee, dated and
effective May 1994
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10.25
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Sublease between Reserve Coal
Properties, sublessors, and Patriot Mining Company, sublessee, of Sycamore
No. 2 Mine
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(C
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)
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10.27
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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:
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(B
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)
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(a) Amendment dated March 4,
1986, effective January 1, 1986
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(b) Second Amendment dated
April 22, 1986, effective January 1, 1986
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(c) Modification dated and
effective June 8, 1987
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(d) Modification dated and
effective November 4, 1988
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(e) Amendment dated and
effective January 1, 1989
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Description
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Note
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10.28‡
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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:
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(G
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)
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10.29‡
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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
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(G
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)
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10.30
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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
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(I
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)
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10.31
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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
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(N
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)
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10.32
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International Coal Group, Inc.
Executive Severance Plan
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(I
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)
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10.33
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International Coal Group Inc.
Director Compensation Plan
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(I
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)
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10.34‡
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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
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(I
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)
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10.35‡
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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.
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(L
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)
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10.36‡
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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.
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(L
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)
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10.37
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International Coal Group, Inc.
Director Compensation Plan (as amended 2007)
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(K
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)
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10.38
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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
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(J
|
)
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10.39‡
|
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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
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(M
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)
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10.40
|
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Form of Non-Employee
Director Restricted Share Unit Agreement
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(O
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)
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11.1
|
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Statement regarding Computation of
Earnings Per Share
|
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(O
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)
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21.1
|
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(O
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)
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23.1
|
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(O
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)
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24.1
|
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(O
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)
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31.1
|
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Certification of the Chief
Executive Officer
|
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(O
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)
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31.2
|
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Certification of the Principal
Financial Officer
|
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(O
|
)
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32.1
|
|
Certification Pursuant to § 906 of
the Sarbanes-Oxley Act of 2002
|
|
(O
|
)
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(A)
|
|
(B)
|
|
(C)
|
|
(D)
|
|
(E)
|
|
(F)
|
|
(G)
|
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(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)
|
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(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)
|
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(L)
|
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(M)
|
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(N)
|
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(O)
|
Filed
herewith.
|
‡
|
Confidential treatment requested
as to certain portions that have been omitted and filed separately with
the Securities and Exchange
Commission.
|