e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
Commission file number: 1-13105
(Exact name of registrant as specified in its charter)
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Delaware |
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43-0921172 |
(State or other jurisdiction
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(I.R.S. Employer |
of incorporation or organization)
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Identification Number) |
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One CityPlace Drive, Ste. 300, St. Louis, Missouri |
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63141 |
(Address of principal executive offices)
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(Zip code) |
Registrants telephone number, including area code:
(314) 994-2700
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered |
Common Stock, $.01 par value
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New York Stock Exchange |
Preferred Share Purchase Rights
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the
Act: None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant: (1) has
filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K is
not contained herein, and will not be contained, to the best of
registrants knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this
Form 10-K or any
amendment to this
Form 10-K.
o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2 of the
Exchange Act. (Check one):
Large Accelerated
Filer þ Accelerated
Filer o Non-Accelerated
Filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2 of the
Exchange
Act). Yes o No þ
The aggregate market value of the voting stock held by
non-affiliates of the registrant (excluding outstanding shares
beneficially owned by directors, officers and treasury shares)
as of June 30, 2006 was approximately $4.4 billion.
On February 26, 2007, approximately 142,374,800 shares
of the companys common stock, par value $0.01 per
share, were outstanding.
Portions of the companys definitive proxy statement for
the annual stockholders meeting to be held on
April 26, 2007 are incorporated by reference into
Part III of this
Form 10-K.
TABLE OF CONTENTS
Cautionary Statements Regarding Forward-Looking
Information
This document contains forward-looking
statements that is, statements related to
future, not past, events. In this context, forward-looking
statements often address our expected future business and
financial performance, and often contain words such as
expects, anticipates,
intends, plans, believes,
seeks, or will. Forward-looking
statements by their nature address matters that are, to
different degrees, uncertain. For us, particular uncertainties
arise from changes in the demand for our coal by the domestic
electric generation industry; from legislation and regulations
relating to the Clean Air Act and other environmental
initiatives; from operational, geological, permit, labor and
weather-related factors; from fluctuations in the amount of cash
we generate from operations; from future integration of acquired
businesses; and from numerous other matters of national,
regional and global scale, including those of a political,
economic, business, competitive or regulatory nature. These
uncertainties may cause our actual future results to be
materially different than those expressed in our forward-looking
statements. We do not undertake to update our forward-looking
statements, whether as a result of new information, future
events or otherwise, except as may be required by law. For a
description of some of the risks and uncertainties that may
affect our future results, you should see Risk
Factors beginning on page 26.
Glossary of Selected Mining Terms
Certain terms that we use in this Annual Report on
Form 10-K are
specific to the coal mining industry and may be technical in
nature. The following is a list of selected mining terms and the
definitions we attribute to them when we use them throughout
this document.
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Assigned reserves
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Recoverable coal reserves designated for mining by a specific
operation. |
Btu
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A measure of the energy required to raise the temperature of one
pound of water one degree of Fahrenheit. |
Compliance coal
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Coal which, when burned, emits 1.2 pounds or less of sulfur
dioxide per million Btu, requiring no blending or other sulfur
dioxide reduction technologies in order to comply with the
requirements of the Clean Air Act. |
Continuous miner
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A machine used in underground mining to cut coal from the seam
and load it onto conveyors or into shuttle cars in a continuous
operation. |
Dragline
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A large machine used in the surface mining process to remove the
overburden, or layers of earth and rock, covering a coal seam.
The dragline has a large bucket, suspended by cables from the
end of a long boom, which is able to scoop up large amounts of
overburden as it is dragged across the excavation area and
redeposit the overburden in another area. |
Longwall mining
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One of two major underground coal mining methods, employing a
rotating drum pulled mechanically back and forth across a long
face of coal. |
Low-sulfur coal
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Coal which, when burned, emits 1.6 pounds or less of sulfur
dioxide per million Btu. |
Preparation plant
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A facility used for crushing, sizing and washing coal to remove
impurities and to prepare it for use by a particular customer. |
Probable reserves
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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. |
Proven reserves
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Reserves for which (a) 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 (b) the sites for inspection, sampling and
measurement are spaced so closely and the geologic character is
so well defined that size, shape, depth and mineral content of
reserves are well established. |
Reclamation
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The restoration of land and environmental values to a mining
site after the coal is extracted. The process commonly includes
recontouring or shaping the land to its approximate
original appearance, restoring topsoil and planting native grass
and ground covers. |
Recoverable reserves
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The amount of proven and probable reserves that can actually be
recovered from the reserve base taking into account all mining
and preparation losses involved in producing a saleable product
using existing methods and under current law. |
Reserves
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That part of a mineral deposit which could be economically and
legally extracted or produced at the time of the reserve
determination. |
Room-and-pillar mining
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One of two major underground coal mining methods, utilizing
continuous miners creating a network of rooms within
a coal seam, leaving behind pillars of coal used to
support the roof of a mine. |
Unassigned reserves
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Recoverable coal reserves that have not yet been designated for
mining by a specific operation. |
PART I
Introduction
We are one of the largest coal producers in the United States.
At December 31, 2006, we operated 21 active mines located
in each of the three major low sulfur coal-producing regions of
the United States. Federal and state regulations controlling air
pollution affect the demand for certain types of coal by
limiting the amount of sulfur dioxide which may be emitted as a
result of fuel combustion. As a result of these regulations, we
believe demand for low sulfur coal exceeds demand for other
types of coal and often earns a premium in the marketplace.
Consequently, we focus on mining, processing and marketing
bituminous and sub-bituminous coal with low sulfur content. At
December 31, 2006, we estimate that our proven and probable
coal reserves had an average heat value of approximately 9,924
Btus and an average sulfur content of approximately 0.60%.
Because of these characteristics, we estimate that approximately
79.8% of our proven and probable coal reserves consists of
compliance coal.
We sell substantially all of our coal to producers of electric
power, steel producers and industrial facilities. For the year
ended December 31, 2006, we sold approximately
135.0 million tons of coal, including approximately
10.0 million tons of coal we purchased from third parties,
fueling approximately 6% of all electricity generated in the
United States. The locations of our mines enable us to ship coal
to most of the major coal-fired electric generation facilities
in the United States. The following table shows the breakdown of
our coal production by region for 2006 and 2005, expressed as a
percentage of the total tons produced:
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2006 | |
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2005 | |
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Powder River Basin
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70.7 |
% |
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65.8 |
% |
Western Bituminous
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14.2 |
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12.6 |
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Central Appalachia
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15.1 |
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21.6 |
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Total
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100.0 |
% |
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100.0 |
% |
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In 2006, we sold approximately 78.5% of our coal under long-term
supply arrangements with a term of more than one year. At
December 31, 2006, the average volume-weighted remaining
term of our long-term contracts was approximately
4.6 years, with remaining terms ranging from one to
11 years. At December 31, 2006, we had a sales
backlog, including a backlog subject to price reopener or
extension provisions, of approximately 460.9 million tons.
Despite a slight decline in United States demand for coal in
2006, we expect global and domestic demand for coal to grow over
time. Based on industry estimates of future production, we
expect demand growth to exert upward pressure on coal pricing in
the future. As a result, we have not yet priced a portion of the
coal we plan to produce over the next several years in order to
take advantage of expected price increases. At December 31,
2006, we had expected production available for repricing of
approximately 11 million to 16 million tons in 2007,
75 million to 85 million tons in 2008 and
110 million to 120 million tons in 2009.
1
Our History
We were organized in Delaware in 1969 as Arch Mineral
Corporation. In July 1997, we merged with Ashland Coal, Inc., a
subsidiary of Ashland Oil formed in 1975. As a result of the
merger, we became one of the largest producers of low-sulfur
coal in the eastern United States.
In June 1998, we expanded into the western United States when we
acquired the coal assets of Atlantic Richfield Company. This
acquisition included the Black Thunder and Coal Creek mines in
the Powder River Basin of Wyoming, the West Elk longwall mine in
Colorado and a 65% interest in Canyon Fuel Company, which
operates three longwall mines in Utah.
In October 1998, we added to our Powder River Basin reserves
when we were the successful bidder for the Thundercloud reserve,
a 412-million-ton
federal reserve tract adjacent to the Black Thunder mine. In
July 2004, we acquired the remaining 35% interest in Canyon Fuel
Company. In August 2004, we again expanded our position in the
Powder River Basin with the acquisition of Triton Coal
Companys North Rochelle mine adjacent to our Black Thunder
operation. In September 2004, we were the successful bidder for
the Little Thunder reserve, a
719-million-ton federal
reserve tract adjacent to the Black Thunder mine.
At the end of 2005, we sold the stock of Hobet Mining, Apogee
Coal Company and Catenary Coal Company and their four associated
mining operations (Hobet 21, Arch of West Virginia, Samples
and Campbells Creek) and approximately 455.0 million tons
of coal reserves in Central Appalachia to Magnum Coal Company,
which we refer to as Magnum.
The Coal Industry
Overview. Coal is a combustible, sedimentary, organic
rock formed from vegetation that has been consolidated between
other rock strata and altered by the combined effects of
pressure and heat over millions of years. The degree of change
undergone by coal as it matures from peat to anthracite
significantly affects its physical and chemical properties.
Initially, peat is converted into lignite, a relatively soft
material that can range in color from dark black to various
shades of brown. The continuing effects of temperature and
pressure causes lignite to transform into sub-bituminous coal.
Lignite and sub-bituminous coal are typically softer, friable
materials characterized by high moisture levels and low carbon
content. Because of their carbon content, lignite and
sub-bituminous coal generally produce less energy than
bituminous, or hard, coal, formed by continuing chemical and
physical changes. Under the right conditions, continuing organic
maturity can result in anthracite, a hard black rock with a high
carbon and energy content and a low level of moisture. According
to the World Coal Institute, which we refer to as the WCI,
sub-bituminous and bituminous coal comprise approximately 82% of
the global coal reserves.
Because of its chemical composition, coal is a major contributor
to the global energy supply, providing more than 39% of the
worlds electricity, according to the WCI. The United
States produces approximately one-fifth of the worlds coal
and is the second largest coal producer in the world, exceeded
only by China. Coal in the United States represents
approximately 95% of the domestic fossil energy reserves with
over 250 billion tons of recoverable coal, according to the
United States Geological Survey.
Coal is primarily used to fuel electric power generation in the
United States. Based on data from the Energy Information
Administration, which we refer to as the EIA, coal-based power
plants generated
2
approximately 50% of the electricity produced in the United
States in 2006. Coal also represents the lowest cost fossil fuel
used for electric power generation. According to the EIA, the
average delivered cost of coal to electric power generators
during the fourth quarter of 2006 was $1.67/mm Btu, which was
$5.67/mm Btu less expensive than residual fuel oil and $5.12/mm
Btu less expensive than natural gas.
Compared to other fuels used for electric power generation, coal
is domestically available and reliable. Prices for oil and
natural gas in the United States have reached record levels in
recent years because of tensions regarding international supply
and the impact of hurricane interruptions in the Gulf of Mexico
in 2005. Historically high oil and natural gas prices have
resulted in renewed interest, not only in adding new coal-based
electric power generation, but also in refining coal
into transportation fuels, such as low-sulfur diesel. According
to data from Platts, more than 90 gigawatts of new coal-based
generation is now planned in the United States. Additionally,
government and private sector interest in coal-gasification and
coal-to-liquids
technologies has increased.
We expect coal to continue to grow as a domestic fuel as capital
is deployed for mine development and expansion and for increased
railroad capacity. During 2006, the two existing rail
transportation providers in the Powder River Basin in Wyoming
expanded their rail capacity, and a potential third rail
transportation provider is advancing with plans to construct
additional access to this region. We believe this development
further demonstrates the commitment to coal as a future source
of fuel for the United States.
Coal is expected to remain the fuel of choice for domestic power
generation through at least 2030, according to the EIA. Through
that time, we expect new technologies intended to lower
emissions of sulfur dioxide, nitrous oxides, mercury, and
particulates will be introduced into the power generation
industry. We also expect advances in technologies designed to
capture and sequester carbon dioxide emissions. These
technologies have garnered greater attention in recent years due
to the perceived impact of carbon dioxide on the global climate.
We believe these technological advancements will help coal
retain its role as a key fuel for electric power generation well
into the future.
U.S. Coal Consumption. Coal produced in the United
States is used primarily by electric generation facilities to
generate electricity, by steel companies to produce coke for use
in blast furnaces and by a variety of industrial users to heat
and power foundries, cement plants, paper mills, chemical plants
and other manufacturing and processing facilities. Coal
consumption in the United States has increased from
398.1 million tons in 1960 to approximately
1.1 billion tons in 2006, based on information provided by
EIA.
3
According to the EIA, United States coal consumption by sector
for 2006 and 2005 is as follows (tons in millions):
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2006 | |
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2005 | |
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End Use |
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Tons | |
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% | |
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Tons | |
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% | |
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Electric generation
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1,023.3 |
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92.0 |
% |
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1,037.5 |
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92.2 |
% |
Industrial
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61.5 |
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5.5 |
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60.3 |
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5.3 |
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Steel production
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23.3 |
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2.1 |
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23.4 |
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2.1 |
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Residential/ Commercial
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4.3 |
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0.4 |
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4.2 |
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0.4 |
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Total
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1,112.4 |
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100.0 |
% |
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1,125.4 |
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100.0 |
% |
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Source: EIA
Coal has long been favored as an electricity generating fuel
because of its cost advantage and its availability throughout
the United States. According to the EIA, coal accounted for
approximately 50% of U.S. electricity generation in 2006
and is projected to account for approximately 57% in 2030, while
generation from natural gas is expected to peak in 2020. The
largest cost component in electricity generation at natural gas-
and coal-fired power plants is fuel. According to the National
Mining Association, which we refer to as the NMA, coal is the
lowest-cost fossil fuel used for electric power generation,
averaging less than one-third of the price of both petroleum and
natural gas. According to the EIA, for a new coal-fired power
plant built today, fuel costs would represent about one-half of
total operating costs, whereas the share for a new natural
gas-fired power plant would be almost 90%. Other factors that
influence an electric generation facilitys choice of
generation method may include facility cost, fuel transportation
infrastructure and environmental restrictions.
Planned new domestic coal-fueled electric generation capacity
announcements exceeded 90 gigawatts at December 31,
2006, equating to as much as 300 million tons of additional
coal demand annually. We estimate that, at December 31,
2006, approximately 15 gigawatts of generating capacity was
under construction or in advanced stages of development with
completion expected by 2010, an amount that could translate into
as much as 60 million tons of incremental coal demand
during that time period. We believe that demand growth from new
coal-fueled electric generation facilities represents an
important element to the long-term outlook for coal.
4
According to the EIA, the breakdown of United States electricity
generation by fuel source in 2006 is as follows:
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Electricity Generation Mode |
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% | |
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Coal
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50.1 |
% |
Nuclear
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20.1 |
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Natural gas
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19.0 |
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Hydro
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7.3 |
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Petroleum and other
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3.5 |
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Total
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100.0 |
% |
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Source: EIA
The EIA projects that generators of electricity will increase
their demand for coal as demand for electricity increases. The
EIA expects coal use for electricity generation to increase by
1.5% per year on average from 2005 to 2030. Coal
consumption has generally grown at the pace of electricity
growth because coal-fired generation is used in most cases to
meet base load requirements. We estimate that coal consumption
for power generation declined 0.9% in 2006 as a result of an
overall reduction in electricity generation demand. Demand for
electricity has historically grown in proportion to the United
States economic growth by gross domestic product. In 2006,
however, gross domestic product rose by approximately 3.4%
according to the U.S. Department of Commerce. According to
our estimates, this anomaly of a growing economy and declining
coal consumption has occurred only four times since the early
1950s.
Demand for coal is broadly influenced by weather as evidenced by
the decline in coal consumption in 2006 in response to very mild
weather patterns throughout much of the United States. Weather
patterns requiring greater use of heating or air-conditioning
translate into greater demand for coal generation. As a result
of the mild weather during 2006, coal stockpiles at electric
generation facilities totaled 136.0 million tons near the
end of 2006, according to the EIA, representing an approximate
47-day supply. In
comparison, coal stockpiles totaled 101.1 million tons, or
an approximate 35-day
supply at December 31, 2005, according to the EIA. We
believe that some electric generation facilities may decide to
maintain higher coal supplies in order to alleviate the impact
of critically low stockpiles such as those experienced at the
end of 2005. Coal consumption patterns are also influenced by
governmental regulation impacting coal production and power
generation; technological developments; and the location,
availability and quality of competing sources of energy,
including natural gas, oil and nuclear energy, and alternative
energy sources, such as hydroelectric power.
The other major market for coal is the steel industry. Coal is
essential for iron and steel production. According to the WCI,
approximately 64% of all steel is produced from iron made in
blast furnaces that use coal. The steel industry uses
metallurgical coal, which is distinguishable from other types of
coal because of its high carbon content, low expansion pressure,
low sulfur content and various other chemical attributes.
Because of these characteristics, the price offered by steel
makers for metallurgical coal is generally higher than the price
offered by electric generation facilities for steam coal.
5
Historically high oil and gas prices and global energy security
concerns have increased interest in converting coal into a
liquid fuel, a process known as liquefaction. Liquid fuel
produced from coal can be refined further to produce
transportation fuels and other oil products, such as plastics
and solvents. Public and governmental interest in these and
other coal-conversion technologies has increased, particularly
with the introduction of several legislative initiatives in
early 2007. Several projects have begun, including a
coal-to-liquids
facility proposed by DKRW Advanced Fuels LLC, a company in which
we acquired a 25% equity interest during 2006. We believe the
advancement of coal-conversion and other technologies represents
a positive development for the long-term demand for coal.
U.S. Coal Production. In 2006, total coal production
in the United States as estimated by the U.S. Department of
Energy was 1.1 billion tons. Production of coal in the
United States has increased from 434 million tons in 1960
to approximately 1.1 billion tons in 2006 based on
information provided by EIA. According to the EIA, the breakdown
of United States coal production by producing region for 2006
and 2005 is as follows (tons in millions):
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2006 | |
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2005 | |
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Tons | |
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% | |
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Tons | |
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% | |
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Western
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612.9 |
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52.9 |
% |
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585.0 |
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51.7 |
% |
Appalachia
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395.2 |
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34.1 |
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397.3 |
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35.1 |
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Interior(1)
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151.4 |
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13.0 |
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149.2 |
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13.2 |
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Total
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1,159.5 |
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100.0 |
% |
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1,131.5 |
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100.0 |
% |
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Source: EIA
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(1) |
Includes the Illinois Basin |
Western region. The western region includes the Powder
River Basin and the Western Bituminous region. The Powder River
Basin is located in northeastern Wyoming and southeastern
Montana. Coal from this region has a very low sulfur content and
a low heat value. The price of Powder River Basin coal is
generally less than that of coal produced in other regions
because Powder River Basin coal exists in greater abundance, is
easier to mine and thus has a lower cost of production. However,
Powder River Basin coal is generally lower in heat value, which
requires some electric power generation facilities to blend it
with higher Btu coal or retrofit existing coal plants to
accommodate lower Btu coal. The Western Bituminous region
includes western Colorado and eastern Utah. Coal from this
region typically has a low sulfur content and varies in heat
value. According to the EIA, coal produced in the western United
States increased from 408.3 million tons in 1994 to
612.9 million tons in 2006.
Appalachian region. The Appalachian region is divided
into the north, central and southern Appalachian regions.
Central Appalachia includes eastern Kentucky, Virginia and
southern West Virginia. Coal mined from this region generally
has a high heat value and low sulfur content. Northern
Appalachia includes Maryland, Ohio, Pennsylvania and northern
West Virginia. Coal from this region generally has a high heat
value and a high sulfur content. According to the EIA, coal
produced in the Appalachian region decreased from
445.4 million tons in 1994 to 395.2 million tons in
2006, primarily as a result of the depletion of economically
attractive reserves, permitting issues and increasing costs of
production.
6
Interior region. The Illinois basin includes Illinois,
Indiana and western Kentucky and is the major coal production
center in the interior region of the United States. Coal from
the Illinois basin varies in heat value and has high sulfur
content. Despite its high sulfur content, coal from the Illinois
basin can generally be used by some electric power generation
facilities that have installed pollution control devices, such
as scrubbers, to reduce emissions. During 2006, we acquired a
331/3%
interest in Knight Hawk Holdings, LLC, a coal producer in the
Illinois basin. We anticipate that Illinois basin coal will play
an increasingly vital role in the United States energy markets
in future periods. Other coal-producing states in the interior
region include Arkansas, Kansas, Louisiana, Mississippi,
Missouri, North Dakota, Oklahoma and Texas. According to the
EIA, coal produced in the interior region decreased from
179.9 million tons in 1994 to 151.4 million tons in
2006.
International Coal Production. Coal is imported into the
United States, primarily from Columbia and Venezuela. Imported
coal generally serves coastal states along the Gulf of Mexico,
such as Alabama and Florida, and states along the eastern
seaboard. We believe that significant new capital expenditures
for transportation infrastructure would have to be incurred by
inland coal consumers in the United States if they desired to
import significant quantities of foreign coal because most
domestic waterways and water transportation facilities are built
for export rather than import of coal. To date, the cost of
transporting coal from the coast to interior electric generation
facilities via rail has generally proven to be expensive.
However, coal imports have demonstrated recent strength due to
their competitive pricing, particularly when compared to
Appalachian coal. According to the EIA, coal imports increased
from 8.9 million tons in 1994 to 36.1 million tons in
2006.
Coal Mining Methods
The geological characteristics of coal reserves largely
determine the coal mining method employed. There are two primary
methods of mining coal: surface mining and underground mining.
Surface Mining. We use surface mining when coal is found
close to the surface. We have included the identity and location
of our surface mining operations in the table on page 12.
In 2006, approximately 74% of our coal production came from
surface mining operations.
Surface mining involves removing overburden (earth and rock
covering the coal) with heavy earth-moving equipment, such as
draglines, power shovels, excavators and loaders. Once exposed,
we drill, fracture and systematically remove the coal using haul
trucks or conveyors to transport the coal to a preparation plant
or to a unit train loadout facility. After we have removed the
coal, we use draglines, power shovels, excavators or loaders to
backfill the remaining pits with the overburden removed at the
beginning of the process. Once we have replaced the overburden
and topsoil, we reestablish vegetation and make other
improvements that have local community and environmental
benefits.
7
The following diagram illustrates a typical surface mining
operation:
Underground Mining. We use underground mining methods
when coal is located deep beneath the surface. We have included
the identity and location of our underground mining operations
in the table on page 12. In 2006, approximately 18% of our
coal production came from underground mining operations.
Our underground mines are typically operated using one or both
of two different techniques: longwall mining and room-and-pillar
mining.
Longwall mining involves the full extraction of coal from a
section of a coal seam using mechanical shearers. Longwall
mining is effective for long rectangular blocks of medium to
thick coal seams. Ultimate seam recovery using longwall mining
techniques can reach 70%. In longwall mining, we use continuous
miners described below to develop access to long rectangular
coal seams. Hydraulically-powered supports temporarily hold up
the roof of the mine while a rotating drum mechanically advances
across the face of the coal seam, loosening the coal. Chain
conveyors then move the loosened coal to an underground mine
conveyor system for delivery to the surface. Once coal is
extracted from an area, the roof is allowed to collapse in a
controlled fashion. In 2006, approximately 15% of our coal
production came from underground mining operations generally
using longwall mining techniques.
8
The following diagram illustrates a typical underground mining
operation using longwall mining techniques:
Room-and-pillar mining is effective for small blocks of thin
coal seams. In room-and-pillar mining, we cut a network of rooms
into the coal seam, leaving a series of pillars of coal to
support the roof of the mine. We use continuous mining equipment
to cut the coal from the mining face and shuttle cars to
transport the coal to a conveyor belt for further transportation
to the surface. The pillars generated as part of this mining
method can constitute up to 40% of the total coal in a seam.
Higher seam recovery rates can be achieved if retreat mining is
used. In retreat mining, we mine as much coal as possible from
the pillars as our workers retreat. We then allow the roof to
collapse in a controlled fashion. Once we have completed retreat
mining to the mouth of a panel, we generally abandon the mined
panel and seal it from the rest of the mine. In 2006,
approximately 3% of our coal production came from underground
mining operations generally using room-and-pillar mining
techniques.
9
The following diagram illustrates our typical underground mining
operation using room-and-pillar mining techniques:
The remaining 8% of our coal production in 2006 included coal we
purchased from third parties at prevailing market rates or
pursuant to other contractual arrangements.
Coal Preparation. Coal extracted from the ground,
particularly at our underground mining operations, contains
impurities, such as rock and dirt, and comes in a variety of
different-sized fragments. Each of our mining operations in the
Central Appalachia region uses a coal preparation plant located
near the mine or connected to the mine by a conveyor. These coal
preparation plants allow us to treat the coal we extract from
those mines to ensure a consistent quality and to enhance its
suitability for particular end-users. In 2006, our preparation
plants treated approximately 60% of the coal we produced in the
Central Appalachia region. For more information about our
preparation plants, you should see the section entitled
Our Mining Operations beginning on page 11.
The treatments we employ depend on the properties of the
extracted coal and its intended use. To remove impurities, we
crush raw coal and separate it into various sizes. For larger
pieces of coal, we use dense media separation techniques in
which we float coal in a tank containing a liquid of specific
gravity. Since coal is lighter than its impurities, it floats,
and we can separate it from rock and other sediment. We treat
smaller pieces of coal using a number of different methods,
including centrifuge and froth flotation devices. A centrifuge
spins material very quickly, causing solids and liquids to
separate. In a froth flotation system, a froth is produced by
blowing air into a water bath containing chemical reagents. This
process creates bubbles, which attract to the coal but not other
sediment.
10
Our Mining Operations
At December 31, 2006, we operated 21 active mines at 12
mining complexes located in the United States. We have three
reportable business segments, which are based on the low sulfur
coal producing regions in the United States in which we
operate the Powder River Basin, the Western
Bituminous region and the Central Appalachia region. These
geographically distinct areas are characterized by geology, coal
transportation routes to consumers, regulatory environments and
coal quality. These regional similarities have caused market and
contract pricing environments to develop by coal region and form
the basis for the segmentation of our operations.
The following map shows the locations of our mining operations:
11
The following table provides the location of and a summary of
information regarding our mining complexes at December 31,
2006, the total sales associated with these complexes for the
years ended December 31, 2004, 2005 and 2006 and the total
reserves associated with these complexes at December 31,
2006. The amounts disclosed below for the total cost of
property, plant and equipment of each mining complex do not
include the costs of the coal reserves that we have assigned to
any individual complex:
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Total Cost of | |
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Property, | |
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Plant and | |
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Tons Sold(2) | |
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Equipment at | |
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Captive | |
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Contract | |
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Mining | |
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December 31, | |
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Assigned | |
Mining Complex |
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Mines(1) | |
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Mines(1) | |
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Equipment | |
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Railroad | |
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2004 | |
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2005 | |
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2006 | |
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2006 | |
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Reserves | |
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(Million tons) | |
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($ in millions) | |
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(Million | |
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tons) | |
Powder River Basin:
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Black Thunder
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S |
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D, S |
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UP/BN |
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75.1 |
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87.6 |
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92.5 |
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$ |
577.2 |
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1,403.2 |
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Coal Creek(3)
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S |
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D, S |
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UP/BN |
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3.1 |
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140.4 |
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232.0 |
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Western Bituminous:
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Arch of Wyoming(4)
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UP |
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0.2 |
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23.0 |
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19.7 |
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Dugout Canyon(5)
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U |
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LW, C |
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UP |
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3.8 |
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4.9 |
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4.2 |
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105.0 |
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35.6 |
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Skyline(5)(6)
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U |
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LW, C |
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UP |
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0.6 |
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1.5 |
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96.3 |
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14.5 |
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Sufco(5)
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U |
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LW, C |
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UP |
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7.8 |
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7.5 |
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7.4 |
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178.5 |
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60.5 |
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West Elk
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U |
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LW, C |
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UP |
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6.2 |
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5.9 |
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5.0 |
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204.8 |
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66.9 |
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Central Appalachia:
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Coal-Mac
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U, S |
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L, E |
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NS/CSX |
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2.6 |
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3.2 |
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3.7 |
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138.5 |
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9.9 |
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Cumberland River
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S(2), U(2) |
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U(2) |
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NS |
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1.6 |
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2.3 |
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2.6 |
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110.0 |
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25.6 |
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Lone Mountain
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U(3) |
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C |
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NS/CSX |
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2.9 |
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2.6 |
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2.5 |
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162.4 |
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40.0 |
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Mingo Logan
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U |
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U |
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LW, C |
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NS |
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5.1 |
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4.7 |
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4.0 |
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136.9 |
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9.2 |
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Mountain Laurel
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U |
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CSX |
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242.3 |
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131.1 |
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Totals
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105.9 |
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118.7 |
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126.5 |
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$ |
2,115.3 |
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2,048.2 |
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Surface mine |
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Dragline |
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UP |
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Union Pacific Railroad |
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CSX |
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CSX Transportation |
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BN |
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Burlington Northern Railroad |
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Excavator/truck |
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NS |
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Norfolk Southern Railroad |
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LW |
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Longwall |
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C |
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Continuous miner |
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HW |
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Highwall miner |
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(1) |
Amounts in parenthesis indicate the number of captive and
contract mines at the mining complex at December 31, 2006.
Captive mines are mines which we own and operate on land owned
or leased by us. Contract mines are mines which other operators
mine for us under contracts on land owned or leased by us. |
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(2) |
Tons sold include tons of coal we purchased from third parties
and processed through our loadout facilities. Coal purchased
from third parties and processed through our loadout facilities
approximated 1.7 million tons for 2006, 2.2 million
tons for 2005 and 2.0 million tons for 2004. We have not |
12
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included tons of coal we
purchased from third parties that were not processed through our
loadout facilities in the amounts shown in the table above.
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In December 2005, we sold 100% of the stock of Hobet Mining,
Apogee Coal Company and Catenary Coal Company, which include the
Hobet 21, Arch of West Virginia, Samples and Campbells
Creek mining complexes and associated reserves, to Magnum Coal
Company. We have not included any information in the table above
relating to those complexes. |
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(3) |
In 2006, we resumed mining at our Coal Creek mine, which we had
idled in 2000. |
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(4) |
We placed the inactive surface mines at the Arch of Wyoming
complex into reclamation mode in 2004. |
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(5) |
Prior to July 31, 2004, we owned a 65% interest in Canyon
Fuel and accounted for it as an equity investment in our
financial statements. Prior to July 31, 2004, tons sold by
Canyon Fuel were not consolidated into our financial statements.
Subsequent to July 31, 2004 when we acquired the remaining
35% of Canyon Fuel, its financial results and tons sold are
consolidated into our financial statements. Amounts shown in the
table above represent 100% of Canyon Fuels sales volume
for all periods presented. |
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(6) |
In 2006, we resumed mining at our Skyline complex, which we had
idled in 2004. |
Powder River Basin. Our operations in the Powder River
Basin are located in Wyoming and include two surface mines.
During 2006, these mining complexes sold approximately
95.6 million tons of compliance coal to customers in the
United States. We control approximately 1.8 billion tons of
proven and probable coal reserves in the Powder River Basin.
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Black Thunder
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The Black Thunder mine is a surface mining complex located in
Campbell County, Wyoming. The mine complex is located on
approximately 24,300 acres, with a majority of coal
controlled by federal and state leases, as well as a small
amount of private fee coal acreage. The mine currently consists
of six active pit areas, two owned loadout facilities and one
leased loadout facility. All of the coal is shipped raw to
customers, and there are no preparation plant processes. All of
the production is shipped via the Burlington Northern and Union
Pacific railroads. The loadout facilities are capable of loading
a 14,500-ton unit train in two to three hours. |
Coal Creek
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The Coal Creek mine is a surface mining complex located in
Campbell County, Wyoming. The mine complex is located on
approximately 7,400 acres, with a majority of coal
controlled by federal and state leases, and a small amount of
private fee coal acreage. The mine currently consists of two
active pit areas and one loadout facility. All of the coal is
shipped raw to customers, and there are no preparation plant
processes. All of the production is shipped via the Burlington
Northern and Union Pacific railroads. The loadout facility is
capable of loading a 14,000-ton unit train in less than three
hours. |
Western Bituminous. Our operations in the Western
Bituminous region are located in southern Wyoming, Colorado and
Utah and include four underground mines and four inactive
surface mines. All of the surface mines are in reclamation mode.
During 2006, the mining complexes in the Western Bituminous
region sold approximately 18.1 million tons of compliance
coal to customers in the United States. We
13
control approximately 464.0 million tons of proven and
probable coal reserves in the Western Bituminous region.
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Arch of Wyoming
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The Arch of Wyoming mining complex is a surface mining complex
located in Carbon County, Wyoming. The complex consists of four
inactive surface mines that are in the final process of
reclamation and bond release. The complex also consists of a
mining area called Carbon Basin that has recently begun
preliminary development of the surface mining area known as the
Elk Mountain mine. The inactive surface mines under reclamation
are located on approximately 30,100 acres, with a majority
of coal controlled by federal, private and state leases. The
Carbon Basin mining area is located on approximately
29,900 acres with a majority of coal controlled by federal,
private and state leases. The Arch of Wyoming complex had
minimal coal production during 2006 attributable to the
development mining at the Elk Mountain mine. |
Dugout Canyon
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The Dugout Canyon mine is an underground mine located in Carbon
County, Utah. The mine is located on approximately
20,000 acres, with a majority of coal controlled by federal
and state leases, as well as a small amount of private fee coal
acreage. The mine currently consists of a single longwall, two
continuous miner sections and one truck loadout facility. We
wash a portion of the coal we produce at the Dugout Canyon mine
at a 400-ton per hour heavy media vessel preparation plant. All
of the production is shipped via the Union Pacific railroad or
directly to customers by highway trucks. The mine loadout
facility is capable of loading about 20,000 tons per day into
highway trucks. Train shipments are handled by a third-party
loadout that can load an 11,000-ton train in less than three
hours. |
Skyline
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The Skyline mine is an underground mine located in Carbon and
Emery Counties, Utah. The mine is located on approximately
13,300 acres, with a majority of coal controlled by federal
leases, as well as a small amount on private and county leases.
The mine currently consists of one continuous miner section, a
longwall and one loadout facility. All of the coal can be
shipped raw to customers, and there are no preparation plant
processes. All of the production is shipped via the Union
Pacific railroad or directly to customers by highway trucks. The
loadout facility is capable of loading a 12,000-ton unit train
in less than four hours. |
Sufco
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The Sufco mine is an underground mine located in Sevier County,
Utah. The mine is located on approximately 29,100 acres,
with a majority of coal controlled by federal and state leases,
as well as a small amount of private fee coal acreage. The mine
currently consists of a single longwall, two continuous miner
sections and one loadout facility. All of the coal is shipped
raw to customers without preparation plant processing. Coal is
shipped via the Union Pacific railroad or delivered directly to
customers by highway trucks. The rail loadout facility, located
approximately 80 miles from the mine, is capable of loading
an 11,000-ton unit train in less than three hours. |
14
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West Elk
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The West Elk mine is an underground mine located in Gunnison
County, Colorado. The mine is located on approximately
17,000 acres, with a majority of coal controlled by federal
and state leases, as well as a small amount of private fee coal
acreage. The mine currently consists of a single longwall, three
continuous miner sections and one loadout facility. All of the
coal is shipped raw to customers, and there are no preparation
plant processes. All of the production is shipped via the Union
Pacific railroad. The loadout facility is capable of loading an
11,000-ton unit train in less than three hours. |
Central Appalachia. Our operations in the Central
Appalachia region are located in southern West Virginia, eastern
Kentucky and Virginia and included eleven underground mines and
four surface mines at December 31, 2006. During 2006, these
operations sold approximately 12.8 million tons of
compliance and metallurgical coal to customers in the United
States and abroad. Metallurgical coal accounted for
2.0 million tons of total coal sales from these operations
in 2006. We control approximately 402.0 million tons of
proven and probable coal reserves in Central Appalachia.
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Coal-Mac
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Coal-Mac is a surface and underground mining complex located in
Logan County and Mingo County, West Virginia on approximately
46,800 acres. Coal-Mac utilizes seven production spreads to
surface mine and deliver coal to the Ragland or Holden 22 rail
loadouts. Coal trucked to the Ragland loadout is direct shipped
on the Norfolk Southern railroad. The Ragland loadout is capable
of loading 5,000 tons per hour. The Holden 22 loadout includes a
preparation plant and rail loadout system. Coal from the surface
mine is transported via truck to the plant where it is either
directly loaded or cleaned and then shipped on the CSX rail
system. The Holden 22 preparation plant has a feed capacity of
600 raw tons per hour. The Holden 22 loadout is capable of
loading 3,200 tons per hour. |
Cumberland River
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The Cumberland River complex is an underground and surface
mining complex located in Wise County, Virginia and Letcher
County, Kentucky. The complex is located on approximately
16,500 acres, primarily in Kentucky. The complex currently
consists of four underground mines (two captive, two contract),
two captive surface operations, two highwall miners (one
captive, one contract), and one preparation plant and loadout
facility. The preparation plant processes approximately
two-thirds of the production, and approximately one-third of the
production is shipped raw. All of the production is shipped
through the loadout facility in Virginia via the Norfolk
Southern railroad. The loadout facility is capable of loading a
12,500-ton unit train in less than four hours. |
Lone Mountain
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The Lone Mountain complex is an underground operation located in
Harlan County, Kentucky and Lee County, Virginia on
approximately 21,500 acres. The Lone Mountain complex
currently consists of three underground mines operating seven
continuous miner sections in total. The mined coal is conveyed
from Kentucky to Virginia and processed through a preparation
plant located near St. Charles, Virginia. The loadout facility
is capable of shipping on the Norfolk Southern and CSX
railroads. The loadout facility is capable of loading a
12,500-ton unit train in less than four hours. |
15
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Mingo Logan Ben Creek
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The Mingo Logan Ben Creek complex is an underground
operation located in Mingo County and Logan County, West
Virginia on approximately 21,800 acres. The Mingo
Logan Ben Creek complex currently consists of three
continuous miners that support a longwall. The mined coal is
processed through a preparation plant connected to the mine by a
conveyor. The loadout on the Norfolk Southern railroad is
connected to the preparation plant by a second conveyor. The
loadout facility is capable of loading a 15,000-ton unit train
in less than four hours. |
Mountain Laurel
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The Mountain Laurel complex is an underground operation that we
are developing in Logan County, West Virginia on approximately
29,900 acres. The Mountain Laurel complex will consist of
three to six continuous miners that support a longwall. Mine
development began in July 2004, and the first continuous miner
unit began development in late September 2005. Two more
continuous miner units were placed into production in the first
and third quarters of 2006. Full production will not be realized
until the longwall is placed into service in the second half of
2007. All raw coal is belted and processed through a
state-of-the-art 2,100 ton-per-hour preparation plant located at
the mine. The loadout facility is on the CSX railroad and is
connected to the plant by a 5,000 ton-per-hour conveyor. The
loadout facility, which was placed into service in the third
quarter of 2006, is capable of loading a 15,000-ton unit train
in less than four hours. |
We also incorporate by reference the information about the
operating results of each of our segments for the years ended
December 31, 2006, 2005 and 2004 contained in
Note 25 Segment Information to our consolidated
financial statements beginning on page F-1.
Transportation
We ship our coal to customers by means of railroad cars, river
barges or trucks, or a combination of these means of
transportation. We also ship our coal to Atlantic coast
terminals for shipment to domestic and international customers.
As is customary in the industry, once the coal is loaded onto
the barge or rail car, our customers are typically responsible
for the freight costs to the ultimate destination.
Transportation costs borne by the customer vary greatly based on
each customers proximity to the mine and our proximity to
the loadout facilities.
Our Arch Coal Terminal is located in Catlettsburg, Kentucky on a
111-acre site on the
Big Sandy River above its confluence with the Ohio River. The
terminal provides coal and other bulk material storage and can
load and offload river barges at the facility. The terminal can
provide up to 500,000 tons of storage and can process up to six
million tons of coal annually. In addition to providing storage
and transloading services, the terminal provides maintenance and
other services.
In addition, our subsidiaries together own a 17.5% interest in
Dominion Terminal Associates, which leases and operates a ground
storage-to-vessel coal
transloading facility in Newport News, Virginia. The facility
has a rated throughput capacity of 20 million tons of coal
per year and ground storage capacity of approximately
1.7 million tons. The facility serves international
customers, as well as domestic coal users located on the eastern
seaboard of the United States.
16
Sales, Marketing and Customers
Coal prices are influenced by a number of factors and vary
dramatically by region. As a result of these regional
characteristics, prices of coal by product type within a given
major coal producing region tend to be relatively consistent
with each other. The price of coal within a region is influenced
by market conditions, mine operating costs, coal quality,
transportation costs involved in moving coal from the mine to
the point of use and the costs of alternative fuels. In addition
to supply and demand factors, the price of coal at the mine is
influenced by geologic characteristics such as seam thickness,
overburden ratios and depth of underground reserves. It is
generally cheaper to mine coal seams that are thick and located
close to the surface than to mine thin underground seams. Within
a particular geographic region, underground mining, which is the
mining method we use in the Western Bituminous region and also a
method we use at certain mines in Central Appalachia, is
generally more expensive than surface mining, which is the
mining method we use in the Powder River Basin and also for
certain of our Central Appalachia mines. This is the case
because of the higher capital costs, including costs for
construction of extensive ventilation systems, and higher per
unit labor costs due to lower productivity associated with
underground mining.
In addition to the cost of mine operations, the price of coal is
also a function of quality characteristics such as heat value,
sulfur, ash and moisture content. Higher carbon and lower ash
content generally result in higher prices, and higher sulfur and
higher ash content generally result in lower prices.
Management, including our chief executive officer and chief
operating officer, reviews and makes resource allocations based
on the goal of maximizing our profits in light of the
comparative cost structures of our various operations. Because
most of our customers purchase coal on a regional basis, coal
can generally be sourced from several different locations within
a region. Once we have a contractual commitment to sell coal at
a certain price, our centralized marketing group assigns
contract shipments to our various mines which can be used to
source the coal in the appropriate region.
Long-Term Coal Supply Arrangements
We sell coal both under long-term contracts, the terms of which
are more than one year, and on a current market or spot basis
with terms of one year or less. In 2006, we sold approximately
78.5% of our coal under long-term supply arrangements. At
December 31, 2006, the average volume-weighted remaining
term of our long-term contracts was approximately
4.6 years, with remaining terms ranging from one to
11 years.
We expect to sell a significant portion of our coal under
long-term supply arrangements. We selectively renew or enter
into new long-term supply arrangements when we can do so at
prices that we believe are favorable. When our coal sales
contracts expire or are terminated, we are exposed to the risk
of having to sell coal into the spot market, where demand is
variable and prices are subject to greater volatility.
Provisions permitting renegotiation or modification of coal sale
prices are present in some of our more recently negotiated
long-term contracts and usually occur midway through a contract
or every two to three years, depending upon the length of the
contract. In some circumstances, either we have or our customer
has the option to terminate the contract if the parties cannot
agree on a new price.
17
We participate in the
over-the-counter
market for a small portion of our sales.
Competition
The coal industry is intensely competitive. The most important
factors on which we compete are coal quality, transportation
costs from the mine to the customer and the reliability of
supply. Our principal domestic competitors include Alpha Natural
Resources, Inc., CONSOL Energy Inc., Foundation Coal Holdings,
Inc., International Coal Group, Inc., James River Coal Company,
Massey Energy Company, Magnum Coal Company, Peabody Energy Corp.
and Rio Tinto Energy North America. Some of
these coal producers are larger than us and have greater
financial resources and larger reserve bases than we do. We also
compete directly with a number of smaller producers in each of
the geographic regions in which we operate. As the price of
domestic coal increases, we may also begin to compete with
companies that produce coal from one or more foreign countries,
such as Columbia and Venezuela.
Additionally, coal competes with other fuels, such as nuclear
energy, natural gas, hydropower and petroleum, for steam and
electrical power generation. Costs and other factors, such as
safety and environmental considerations, relating to these
alternative fuels affect the overall demand for coal as a fuel.
Geographic Data
We market our coal principally to electric generation facilities
in the United States. Coal sales to foreign customers
approximated $162.5 million for 2006, $166.0 million
for 2005 and $134.0 million for 2004.
Environmental Matters
Our operations, like operations of other coal companies, are
subject to regulation, primarily by federal and state
authorities, on matters such as the discharge of materials into
the environment; employee health and safety; mine permits and
other licensing requirements; reclamation and restoration
activities involving our mining properties; management of
materials generated by mining operations; surface subsidence
from underground mining; water pollution; air quality standards;
protection of wetlands; endangered plant and wildlife
protection; limitations on land use; storage of petroleum
products; and substances that are regarded as hazardous under
applicable laws including electrical equipment containing
polychlorinated biphenyls, which we refer to as PCBs.
Additionally, the electric generation industry is subject to
extensive regulation regarding the environmental impact of its
power generation activities, which could affect demand for our
coal. The possibility exists that new legislation or regulations
may be adopted or that the enforcement of existing laws could
become more stringent, either of which may have a significant
impact on our mining operations or our customers ability
to use coal and may require us or our customers to significantly
change operations or to incur substantial costs.
While it is not possible to quantify the expenditures we incur
to maintain compliance with all applicable federal and state
laws, those costs have been and are expected to continue to be
significant. Federal and state mining laws and regulations
require us to obtain surety bonds to guarantee performance or
payment of certain long-term obligations, including mine closure
and reclamation costs, federal and state
18
workers compensation benefits, coal leases and other
miscellaneous obligations. Compliance with these laws has
substantially increased the cost of coal mining for all domestic
coal producers.
The following is a summary of the various federal and state
environmental and similar regulations that have a material
impact on our operations:
Clean Air Act. The federal Clean Air Act and similar
state and local laws, which regulate emissions into the air,
affect coal mining and processing operations primarily through
permitting and emissions control requirements. The Clean Air Act
also indirectly affects coal mining operations by extensively
regulating the emissions from coal-fired industrial boilers and
power plants, which are the largest end-users of our coal. These
regulations can take a variety of forms, as explained below.
The Clean Air Act imposes obligations on the United States
Environmental Protection Agency, which we refer to as EPA, and
on the states to implement regulatory programs that will lead to
the attainment and maintenance of national ambient air quality
standards, which we refer to as NAAQS. EPA has promulgated a
number of NAAQS for air pollutants that are associated with the
combustion of coal, including sulfur dioxide, particulate
matter, nitrogen oxides and ozone. Owners of coal-fired power
plants and industrial boilers have been required to expend
considerable resources in an effort to comply with these
standards. As these standards become more stringent in the years
ahead, emissions control requirements for new and expanded
coal-fired power plants and industrial boilers will continue to
become more demanding.
In July 1997, EPA adopted more stringent standards for ozone and
particulate matter, which we refer to as PM. EPA adopted what is
commonly referred to as the
8-hour ozone standard,
established for the first time annual and daily standards for
fine PM, or particles that are 2.5 micrometers in diameter
(PM2.5), and revised the NAAQS for coarse PM, or particles that
are less than 10 micrometers in diameter (PM10). EPAs
Phase I and Phase II
8-hour ozone
implementation rules were challenged, and in December 2006, the
D.C. Circuit Court of Appeals vacated and remanded EPAs
Phase I 8-hour
ozone implementation rule. Litigation challenging certain EPA
designations for PM2.5 non-attainment areas is currently being
held in abeyance pending reconsideration by EPA. States having
designated non-attainment areas for the 1997 standards are
required to submit their state implementation plans for
achieving attainment of the
8-hour ozone standards
by April 2007 and the PM2.5 standards by April 2008 and are
likely to require electric power generators to reduce further
sulfur dioxide, nitrogen oxide and particulate matter emissions.
The attainment deadlines for
8-hour ozone
non-attainment areas range from 2007 to 2012 and for PM2.5
non-attainment areas range from 2010 to 2015.
In September 2006, EPA promulgated final, new PM NAAQS. EPA
strengthened the daily PM2.5 standards but retained the annual
PM2.5 standards and daily PM10 standards and revoked the annual
PM10 standards. The 2006 PM NAAQS are the subject of challenge
in the D.C. Circuit Court of Appeals. States having
non-attainment areas for the 2006 PM2.5 NAAQS are required to
submit their state implementation plans for the 2006 PM2.5 NAAQS
by April 2013, and the attainment dates range from 2015 to 2020.
With respect to ozone, EPA is currently obligated under a
consent decree to sign proposed and final rulemakings concerning
any new or revised ozone NAAQS in May 2007 and February 2008,
respectively.
In October 1998, EPA finalized a rule that requires
19 states in the eastern United States that have ambient
air quality programs to make substantial reductions in nitrogen
oxide emissions. Under the rule,
19
which is commonly known as NOx SIP Call, Phase I states
were required to reduce nitrogen oxide emissions by 2004, and
Phase II states are required to reduce nitrogen oxide
emissions by 2007. Except for five states (Indiana, Illinois,
Kentucky, Michigan and Virginia) that failed to submit their
Phase II NOx SIP Call rules, all affected states have
adopted and submitted to EPA NOx SIP Call rules. For the five
states that did not submit Phase II NOx SIP Call rules, EPA
is expected to promulgate a federal implementation plan in
February 2008. As a result of any federal and state
implementation plans, many electric power generation facilities
and large industrial plants have been or will be required to
install additional emission control measures.
EPA has also initiated a regional haze program designed to
protect and improve visibility at and around National Parks,
National Wilderness Areas and International Parks, particularly
those located in the southwest and southeast United States. This
program restricts the construction of new coal-fired power
plants whose operation may impair visibility at and around
federally protected areas. In June 2005, EPA finalized
amendments to the regional haze rules or Clean Air Visibility
Rule, which we refer to as CAVR, that will require certain
existing coal-fired power plants to install Best Available
Retrofit Technology, which we refer to as BART, to limit
haze-causing emissions, such as sulfur dioxide, nitrogen oxides,
and particulate matter. In October 2006, EPA published a final
emissions trading rule as an alternative to BART. As a result,
individual facilities may not have to install emission controls
provided the target emissions reductions are met. In December
2006, the D.C. Circuit Court of Appeals upheld EPAs CAVR,
rejecting arguments that EPAs CAVR improperly allows the
states covered by EPAs Clean Air Interstate Rule trading
program to forgo source-specific emissions control requirements
to reduce haze. Regional haze state implementation plans are due
in 2008.
New regulations concerning the routine maintenance provisions of
the New Source Review program were published in October 2003.
These regulations were challenged, and in March 2006, the D.C.
Circuit Court of Appeals vacated EPAs rule as contrary to
§111(a) (4) of the Clean Air Act. EPA and a utility
trade association petitioned the United States Supreme Court for
a writ of certiorari in November 2006. In addition, in
October 2005, the EPA published a proposed rule requiring an
hourly emissions test for power plants for determining an
emissions increase under the New Source Review program. In
September 2006, EPA proposed changes to the New Source Review
program concerning de-bottlenecking, aggregation, and project
netting.
In January 2004, the EPA Administrator announced that EPA would
be taking new enforcement actions against utilities for
violations of the existing New Source Review requirements, and
shortly thereafter, EPA issued enforcement notices to several
electric utility companies. Additionally, the
U.S. Department of Justice, on behalf of EPA, filed
lawsuits against several investor-owned electric utilities for
alleged violations of the Clean Air Act. EPA claims that these
utilities have failed to obtain permits required under the Clean
Air Act for alleged major modifications to their power plants.
Some of these lawsuits have been settled, with the owners
agreeing to install additional pollution control devices on
their coal-fired power plants, and other cases are still pending.
In March 2004, North Carolina submitted to EPA a petition under
§126 of the Clean Air Act regarding interstate transport of
pollution. In its petition, North Carolina alleges that power
plants in 12 southeastern and midwestern states contribute
significantly to non-attainment in, and interfere with
20
maintenance by, North Carolina with respect to the PM2.5
NAAQS. In addition, North Carolina alleges that power plants in
five states contribute significantly to non-attainment in, and
interfere with maintenance by, North Carolina with respect to
the 8-hour ozone NAAQS.
In March 2006, EPA promulgated a final rule denying North
Carolinas §126 petition. Following EPAs denial
of North Carolinas §126 petition, North Carolina and
environmental groups petitioned for review. Depending upon the
outcome of the litigation, EPAs response to North
Carolinas §126 petition could adversely impact the
coal needs of power plants in the affected states. With respect
to the international transport of pollution, Canadian cities
petitioned EPA in November 2006, under §115 of the Clean
Air Act, to require emissions reductions from 150 coal-fired
power plants in seven midwestern states. If EPA grants the
petition, then the affected plants could be required to reduce
emissions.
In March 2005, EPA issued three new rules that will impact
coal-fired power plants. The three new rules are (i) the
Clean Air Interstate Rule, which we refer to as CAIR, aimed at
capping emissions of sulfur dioxide and nitrogen oxides in the
eastern United States; (ii) the mercury de-listing rule,
which de-lists power plants as a source of mercury and other
toxic air pollutants and rescinds a finding made in 2000 that it
was appropriate and necessary to regulate power plants under
Section 112(c) of the Clean Air Act; and (iii) the
Clean Air Mercury Rule, which we refer to as CAMR, aimed at
capping and reducing mercury emissions from coal-fired power
plants. Both CAIR and CAMR provide power plant operators a
market-based system in which plants that exceed federal
requirements can sell emission allowances to plant operators who
need more time to comply with the stricter rules. CAIR requires
reductions of sulfur dioxide and/or nitrogen oxide emissions
across 28 eastern states and the District of Columbia and, when
fully implemented in 2015, CAIR will reduce sulfur dioxide
emissions in these states by over 70% and nitrogen oxide
emissions by over 60% from 2003 levels. Under CAMR, mercury
emissions from coal-fired power plants will not be regulated as
a Hazardous Air Pollutant, which would require installation of
Maximum Available Control Technology, which we refer to as MACT.
Instead, using the cap-and-trade system, these plants will have
until 2010 to cut mercury emission levels to 38 tons a year from
48 tons and until 2018 to bring that level down to 15 tons, a
69% reduction. All three rules are the subject of ongoing
litigation.
CAIR and CAMR state implementation plans were due November 2006.
More than 21 states missed the deadline for CAMR state
implementation plans. For these states, EPA is expected to
promulgate a CAMR federal implementation plan in 2007. More than
23 states have adopted or are in the process of adopting
state-specific rules that are more stringent than CAMR.
In December 2005, seven northeastern states (Connecticut,
Delaware, Maine, New Hampshire, New Jersey, New York, and
Vermont) signed the Regional Greenhouse Gas Initiative
agreement, which we refer to as RGGI, calling for a 10%
reduction of carbon dioxide emissions by 2019, with compliance
to begin January 1, 2009. Maryland has subsequently signed
on as a full participant in RGGI. The RGGI final model rule was
issued in August 2006, and the participating states are
developing their state rules. New York, for example, issued
draft rules in December 2006 proposing to auction, as opposed to
allocate, 100% of its allowances under RGGI. Climate change
developments are also taking place in California. In September
2006, California adopted greenhouse gas legislation requiring
that long-term base-load generators must not have greenhouse gas
emissions rates greater than that of combined cycle natural gas
generators. Rules implementing the new greenhouse gas
legislation for investor-owned utilities are expected in February
21
2007. A trading partnership between RGGI states and California
has been announced. These and other state climate change rules
will likely require additional controls on coal-based electric
power generation facilities and industrial boilers and may even
cause some users of coal to switch from coal to a lower carbon
fuel. In addition, there are a number of climate change lawsuits
alleging nuisance and other theories of liability against
various defendants pending in the lower courts. In November
2006, the United States Supreme Court heard oral argument in
Massachusetts v. EPA on whether EPA has improperly
failed to list carbon dioxide as a criteria pollutant. If this
litigation results in a court order directing EPA to promulgate
a new NAAQS for carbon dioxide, then the market demand for coal
could decline.
Other Clean Air Act programs are also applicable to power plants
that use our coal. For example, the acid rain control provisions
of Title IV of the Clean Air Act require a reduction of
sulfur dioxide emissions from power plants. Title IV
imposes a two-phase approach to the implementation of required
sulfur dioxide emissions reductions. Phase I, which became
effective in 1995, regulated the sulfur dioxide emissions levels
from 261 generating units at 110 power plants and targeted the
highest sulfur dioxide emitters. Phase II, implemented
January 1, 2000, made the regulations more stringent and
extended them to additional power plants, including all power
plants of greater than 25-megawatt capacity. Affected electric
power generation facilities can comply with these requirements
by: (i) burning lower sulfur coal, either exclusively or
mixed with higher sulfur coal, (ii) installing pollution
control devices such as scrubbers, which reduce the emissions
from high sulfur coal, (iii) reducing electricity
generating levels or (iv) purchasing or trading emissions
allowances. Specific emissions sources receive these allowances,
which electric utilities and industrial concerns can trade or
sell to allow other units to emit higher levels of sulfur
dioxide. Each allowance permits its holder to emit one ton of
sulfur dioxide.
Other proposed initiatives may have an effect upon coal
operations. Several so-called mutli-pollutant bills, which would
regulate additional air pollutants, have been proposed by
various members of Congress. While the details of all of these
proposed initiatives vary, there appears to be a movement toward
increased regulation of emissions, including carbon dioxide and
mercury.
Mine Health and Safety Laws. Stringent safety and health
standards have been imposed by federal legislation since the
adoption of the Mine Safety and Health Act of 1969. The Mine
Safety and Health Act of 1977, which significantly expanded the
enforcement of health and safety standards of the Mine Safety
and Health Act of 1969, imposes comprehensive safety and health
standards on all mining operations. In addition, as part of the
Mine Safety and Health Acts of 1969 and 1977, the Black Lung Act
requires payments of benefits by all businesses conducting
current mining operations to coal miners with black lung and to
some survivors of a miner who dies from this disease. The states
in which we operate also have mine safety and health laws. In
January 2006, the West Virginia legislature amended its mine
safety and health laws to require mine operators to notify
emergency response coordinators promptly after serious accidents
and provide miners with wireless tracking and communications
devices and self-contained self-rescue breathing equipment.
Federal legislation was enacted in June 2006 that imposes new
requirements for emergency response plans, notification
procedures in the event of accidents, and increased civil
penalties for violations of the law.
Surface Mining Control and Reclamation Act. The Surface
Mining Control and Reclamation Act, which we refer to as SMCRA,
establishes operational, reclamation and closure standards for
all aspects of surface
22
mining as well as many aspects of deep mining. SMCRA requires
that comprehensive environmental protection and reclamation
standards be met during the course of and upon completion of
mining activities. In conjunction with mining the property, we
are contractually obligated under the terms of our leases to
comply with all laws, including SMCRA and equivalent state and
local laws. These obligations include reclaiming and restoring
the mined areas by grading, shaping, preparing the soil for
seeding and by seeding with grasses or planting trees for use as
pasture or timberland, as specified in the approved reclamation
plan.
SMCRA also requires us to submit a bond or otherwise financially
secure the performance of our reclamation obligations. The
earliest a reclamation bond can be completely released is five
years after reclamation has been achieved. Federal law and some
states impose on mine operators the responsibility for repairing
the property or compensating the property owners for damage
occurring on the surface of the property as a result of mine
subsidence, a consequence of longwall mining and possibly other
mining operations. In addition, the Abandoned Mine Lands Act,
which is part of SMCRA, imposes a tax on all current mining
operations, the proceeds of which are used to restore mines
closed before 1977. The maximum tax is $0.35 per ton of
coal produced from surface mines and $0.15 per ton of coal
produced from underground mines. These amounts will decline to
$0.315 and $0.135, respectively, beginning October 2007.
We also lease some of our coal reserves to third-party
operators. Under SMCRA, responsibility for unabated violations,
unpaid civil penalties and unpaid reclamation fees of
independent mine lessees and other third parties could
potentially be imputed to other companies that are deemed,
according to the regulations, to have owned or
controlled the mine operator. Sanctions against the
owner or controller are quite severe and
can include civil penalties, reclamation fees and reclamation
costs. We are not aware of any claims against us asserting that
we own or control any of our
lessees operations.
Framework Convention on Global Climate Change. The United
States and more than 160 other nations are signatories to the
1992 Framework Convention on Global Climate Change, commonly
known as the Kyoto Protocol, that is intended to limit or
capture emissions of greenhouse gases such as carbon dioxide and
methane. The U.S. Senate has neither ratified the treaty
commitments, which would mandate a reduction in
U.S. greenhouse gas emissions, nor enacted any law
specifically controlling greenhouse gas emissions, and the Bush
Administration has withdrawn support for this treaty.
Nonetheless, future regulation of greenhouse gases could occur
either pursuant to future U.S. treaty obligations or
pursuant to statutory or regulatory changes under the Clean Air
Act.
Clean Water Act. The federal Clean Water Act prohibits
the discharge of pollutants into
waters of the United States without a
permit and defines each of these terms broadly. The
statute affects our mining operations in two distinct ways.
First, for any discharge of rock or soil into a topographic
feature that might constitute a stream, the U.S. Army Corps
of Engineers will require a permit specified under §404 of
the Clean Water Act for the placement of such fill
material into the stream. The Corps implementation of this
program and issuance of this permit has been highly litigated in
West Virginia since 1998.
Second, EPA, or states which have been delegated the duty,
require a permit specified under §402 of the Clean Water
Act for any discharge of water from any site that has been
disturbed by the act of mining.
23
The §402 permit imposes limitations on the composition of
the effluent that flows from the site, and requires that water
quality standards specified for the receiving stream also be
achieved. This requires our mining operations to always observe
certain management practices, such as routing all surface water
flows through sedimentation structures, before the discharge
enters public waters. Depending upon the precise water quality
standards that must be achieved, additional treatment of the
discharge may also be required.
Comprehensive Environmental Response, Compensation and
Liability Act. The Comprehensive Environmental Response,
Compensation and Liability Act, which we refer to as CERCLA, and
similar state laws affect coal mining operations by, among other
things, imposing cleanup requirements for threatened or actual
releases of hazardous substances that may endanger public health
or welfare or the environment. Under CERCLA and similar state
laws, joint and several liability may be imposed on waste
generators, site owners and lessees and others regardless of
fault or the legality of the original disposal activity.
Although the EPA excludes most wastes generated by coal mining
and processing operations from the hazardous waste laws, such
wastes can, in certain circumstances, constitute hazardous
substances for the purposes of CERCLA. In addition, the
disposal, release or spilling of some products used by coal
companies in operations, such as chemicals, could implicate the
liability provisions of the statute. Thus, coal mines that we
currently own or have previously owned or operated, and sites to
which we sent waste materials, may be subject to liability under
CERCLA and similar state laws. In particular, we may be liable
under CERCLA or similar state laws for the cleanup of hazardous
substance contamination at sites where we own surface rights.
Mining Permits and Approvals. Mining companies must
obtain numerous permits that strictly regulate environmental and
health and safety matters in connection with coal mining, some
of which have significant bonding requirements. 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 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. Regulations also provide that a mining permit
can be refused or revoked if an officer, director or a
shareholder with a 10% or greater interest in the entity is
affiliated with 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 the necessary
permit applications several months before we plan to begin
mining a new area. Some of our required permits are becoming
increasingly more difficult and expensive to obtain, and the
application review processes are taking longer to complete and
becoming increasingly subject to challenge.
Under some circumstances, substantial fines and penalties,
including revocation or suspension of mining permits, may be
imposed under the laws described above. Monetary sanctions and,
in severe circumstances, criminal sanctions may be imposed for
failure to comply with these laws. You should see the section
entitled Contingencies beginning on page 63 for
more information about certain litigation pertaining to our
permits.
24
Endangered Species. The federal Endangered Species Act
and counterpart state legislation protects species threatened
with possible extinction. Protection of 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. 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. The Bush
Administration has also proposed to add polar bears to the list
of endangered species. If that proposal should be finalized,
then that action could result in regulation of carbon dioxide
emissions to address global warming.
Other Environmental Laws. We are required to comply with
numerous other federal, state and local environmental laws in
addition to those previously discussed. These additional laws
include, for example, the Resource Conservation and Recovery
Act, the Safe Drinking Water Act, the Toxic Substance Control
Act and the Emergency Planning and Community
Right-to-Know Act. We
believe that we are in substantial compliance with all
applicable environmental laws.
Employees
At February 26, 2007, we employed a total of approximately
4,050 persons, approximately 220 of whom are represented by the
Scotia Employees Association. We believe that our relations with
all employees are good.
Executive Officers
The following is a list of our executive officers, their ages as
of February 26, 2007 and their positions and offices during
the last five years:
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C. Henry Besten, Jr.
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Mr. Besten, 58, is our Senior Vice President
Strategic Development and has served in such capacity since
December 2002. Mr. Besten also served as President of our
Arch Energy Resources, Inc. subsidiary from July 1997 to October
2006. From July 1997 to December 2002, Mr. Besten served as
our Vice President Strategic Marketing.
Mr. Besten also served as our acting Chief Financial
Officer from December 1999 to November 2000. |
John W. Eaves
|
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Mr. Eaves, 49, is our President and Chief Operating Officer and
has served in such capacity since April 2006. Mr. Eaves has
also been a director since February 2006. From December 2002 to
April 2006, Mr. Eaves served as our Executive Vice
President and Chief Operating Officer. From February 2000 to
December 2002, Mr. Eaves served as our Senior Vice
President Marketing and from September 1995 to
December 2002 as President of our Arch Coal Sales Company, Inc.
subsidiary. Mr. Eaves also served as our Vice
President Marketing from July 1997 through February
2000. Mr. Eaves also serves on the board of directors of
ADA-ES, Inc. |
Sheila B. Feldman
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Ms. Feldman, 52, is our Vice President Human
Resources and has served in such capacity since February 2003.
From 1997 to February 2003, Ms. Feldman was the Vice
President Human Resources and Public Affairs of
Solutia Inc. On December 17, 2003, Solutia Inc. and its
subsidiaries filed voluntary petitions for reorganization under
Chapter 11 of the United States Bankruptcy Code in the
U.S. Bankruptcy Court for the Southern District of New York. |
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Robert G. Jones
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Mr. Jones, 50, is our Vice President Law, General
Counsel and Secretary and has served in such capacity since
March 2000. Mr. Jones served as our Assistant General
Counsel from July 1997 through February 2000 and as Senior
Counsel from August 1993 to July 1997. |
Paul A. Lang
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Mr. Lang, 46, is our Senior Vice President
Operations and has served in such capacity since December 2006.
Mr. Lang served as President of Western Operations from
July 2005 through December 2006 and President and General
Manager of Thunder Basin Coal Company, L.L.C. from November 1998
through July 2005. |
Steven F. Leer
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Mr. Leer, 54, is our Chairman and Chief Executive Officer.
Mr. Leer served as our President and Chief Executive
Officer from 1992 to April 2006. Mr. Leer also serves on
the board of directors of the Norfolk Southern Corporation, USG
Corp., the Western Business Roundtable and the University of the
Pacific and is chairman of the Coal Industry Advisory Board.
Mr. Leer is a past chairman and continues to serve on the
board of directors of the Center for Energy and Economic
Development, the National Coal Council and the National Mining
Association. |
Robert J. Messey
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Mr. Messey, 61, is our Senior Vice President and Chief Financial
Officer and has served in such capacity since December 2000.
Mr. Messey also serves on the board of directors of Baldor
Electric Company and Stereotaxis, Inc. |
David B. Peugh
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Mr. Peugh, 52, is our Vice President Business
Development and has served in such capacity since 1995. |
Deck S. Slone
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Mr. Slone, 43, is our Vice President Investor
Relations and Public Affairs and has served in such capacity
since 2001. Mr. Slone has helped direct our investor
relations and public affairs functions since joining us in 1997. |
David N. Warnecke
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Mr. Warnecke, 51, is our Vice President Marketing
and Trading and is President of our Arch Coal Sales Company,
Inc. subsidiary. Previously, Mr. Warnecke served as
President of Arch Transportation Company and served as Executive
Vice President of Arch Coal Sales Company, Inc. until
June 1, 2005, when he was appointed President. |
Available Information
We file annual, quarterly and current reports, and amendments to
those reports, proxy statements and other information with the
Securities and Exchange Commission. You may access and read our
filings without charge through the SECs website, at
sec.gov. You may also read and copy any document we file at the
SECs 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.
We also make the documents listed above available through our
website, archcoal.com, as soon as practicable after we file or
furnish them with the SEC. You may also request copies of the
documents, at no cost, by telephone at (314) 994-2700 or by
mail at Arch Coal, Inc., One CityPlace Drive, Suite 300,
St. Louis, Missouri, Attention: Vice President
Investor Relations and Public Affairs. The information on our
website is not part of this Annual Report on
Form 10-K.
Our business involves certain risks and uncertainties. In
addition to the risks and uncertainties described below, we may
face other risks and uncertainties, some of which may be unknown
to us and some of which we may deem immaterial. If one or more
of these risks or uncertainties occur, our business, financial
condition or results of operations may be materially and
adversely affected.
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Risks Related to Our Business
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Our profitability and the
value of our coal reserves depend upon coal demand by United
States electric power generators and other factors beyond our
control. |
Our results of operations and the value of our coal reserves are
substantially dependent upon the prices we receive for our coal.
The prices we receive for our coal depend upon factors beyond
our control, including the coal consumption patterns of the
United States electric generation industry. According to the
EIA, the United States electric generation industry accounts for
approximately 92% of domestic coal consumption. Certain factors
beyond our control, including those listed below, influence the
amount of coal consumed for United States electric power
generation:
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the overall demand for electricity, which in turn significantly
depends on general economic conditions and summer and winter
temperatures in the United States; |
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environmental and government regulation, including air emission
standards for domestic and foreign coal-fired power plants; |
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the location, availability, quality and price of competing
sources of coal, alternative fuels, such as natural gas, oil and
nuclear, and alternative energy sources, such as hydroelectric,
wind and solar power; and |
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technological developments, including the effects of worldwide
energy conservation measures. |
Demand for our low sulfur coal and the prices we obtain for it
will also be affected by the price and availability of high
sulfur coal. In some instances, United States electric power
generators can use high sulfur coal together with emissions
allowances in order to satisfy federal and state air emission
standards. In addition, restrictions imposed by federal and
state air emission standards may cause some electric power
generators to shift from coal to natural gas-fired power plants.
A decrease in coal consumption by United States electric power
generators could reduce the prices we receive for our coal.
Significant decreases in the prices we receive for our coal
could have a material adverse effect on our profitability and
the value of our coal reserves.
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Certain conditions or
events beyond our control could negatively impact our coal
mining operations, our production or our operating
costs. |
We conduct coal mining operations in underground mines and at
surface mines. Certain factors beyond our control, including
those listed below, could disrupt our coal mining operations,
reduce our production or increase our operating costs:
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unexpected variations in geological conditions, such as the
thickness of the coal deposits and the amount of rock embedded
in or overlying the coal deposit; |
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mining and processing equipment failures and unexpected
maintenance problems; |
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interruptions due to transportation delays; |
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unexpected delays and difficulties in acquiring, maintaining or
renewing necessary permits or mining or surface rights; |
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unavailability of mining equipment and supplies and increases in
the price of mining equipment and supplies; |
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shortage of qualified labor and a significant rise in labor
costs; |
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fluctuations in the cost of industrial supplies, including
steel-based supplies, natural gas, diesel fuel and oil; |
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adverse weather and natural disasters, such as heavy rains and
flooding; |
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unexpected or accidental surface subsidence from underground
mining; |
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accidental mine water discharges, fires, explosions or similar
mining accidents; and |
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regulatory issues involving the plugging of and mining through
oil and gas wells that penetrate the coal seams we mine. |
If any of these conditions or events occur, particularly at our
Black Thunder mine, our coal mining operations may be disrupted,
we could experience a delay or halt of production or our
operating costs could increase significantly. In addition, if
our insurance coverage is limited or excludes certain of these
conditions or events, then we may not be able to recover any of
the losses we may incur as a result of such conditions or
events, some of which may be substantial.
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Increases in the price of
steel, diesel fuel or rubber tires could negatively affect our
operating costs. |
Our coal mining operations use significant amounts of steel,
diesel fuel and rubber tires. The costs of roof bolts we use in
our underground mining operations depend on the price of scrap
steel. We also use significant amounts of diesel fuel and tires
for the trucks and other heavy machinery we use, particularly at
our Black Thunder mine. A worldwide increase in mining,
construction and military activities has caused a shortage of
the large rubber tires we use in our mining operations. While we
have taken initiatives aimed at extending the useful lives of
our rubber tires, including increased driver training, improved
road maintenance and reduced driving speeds, we may be unable to
obtain a sufficient quantity of rubber tires in the future or at
prices which are favorable to us. If the prices of steel, diesel
fuel and rubber tires increase, our operating costs could be
negatively affected. In addition, if we are unable to procure
rubber tires, our coal mining operations may be disrupted or we
could experience a delay or halt of production.
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Our labor costs could
increase if the shortage of skilled coal mining workers
continues. |
Efficient coal mining using modern techniques and equipment
requires skilled workers with experience and proficiency in
multiple mining tasks. The resurgence in coal mining activity in
recent years has caused a significant tightening of the labor
supply. In addition, employee turnover rates in the coal
industry have increased during this period as coal producers
compete for skilled personnel. Because of the shortage of
trained coal miners in recent years, we have operated certain
facilities without full staff and have hired novice miners, who
are required to be accompanied by experienced workers as a
safety precaution. These measures have negatively affected our
productivity and our operating costs. If the shortage of
experienced labor continues or worsens, our production may be
negatively affected or our operating costs could increase.
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Disruptions in the
quantities of coal produced by our contract mine operators could
impair our ability to fill customer orders or increase our
operating costs. |
We use independent contractors to mine coal at certain of our
mining complexes, including select operations at our Coal-Mac,
Cumberland River and Mingo Logan mining complexes. Operational
difficulties at contractor-operated mines, changes in demand for
contract miners from other coal producers and other factors
beyond our control could affect the availability, pricing, and
quality of coal produced for us by contractors. Disruptions in
the quantities of coal produced for us by our contract mine
operators could impair our ability to fill our customer orders
or require us to purchase coal from other sources in order to
satisfy those orders. If we are unable to fill a customer order
or if we are required to purchase coal from other sources in
order to satisfy a customer order, we could lose existing
customers and our operating costs could increase.
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Our inability to acquire
additional coal reserves or our inability to develop coal
reserves in an economically feasible manner may adversely affect
our business. |
As we mine, we deplete our coal reserves. As a result, our
ability to produce coal in the future depends, in part, on our
ability to acquire additional coal reserves. We may not be able
to obtain replacement reserves when we require them. If
available, replacement reserves may not be available at
favorable prices, or we may not be capable of mining those
reserves at costs that are comparable with our existing coal
reserves. Our ability to obtain coal reserves in the future
could also be limited by restrictions under our existing or
future debt agreements and competition from other coal
producers. If we are unable to acquire coal reserves to replace
the coal reserves we mine, our future production may decrease
significantly and our operating results may be negatively
affected.
In addition to the availability of additional coal reserves, our
future performance depends on the accuracy with which we
estimate the quantity and quality of the coal included within
those reserves. We base our estimates of reserve information on
engineering, economic and geological data assembled, analyzed
and reviewed by internal and third-party engineers and
consultants. Certain assumptions and other factors beyond our
control, including those listed below, could affect the accuracy
of our estimates:
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unexpected geological and mining conditions which may not be
fully identified by available exploration data or drill hole
density and may differ from our experience in areas we currently
mine; |
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future coal prices, operating costs, capital expenditures,
severance and excise taxes, royalties and development and
reclamation costs; |
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future mining technology improvements; and |
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the assumed effects of federal and state environmental, safety
or other regulations. |
We control substantial undeveloped reserves and have not
identified the equipment or workforce that will be employed to
mine these reserves. Permits have been obtained for some of
these undeveloped reserves. We expect to obtain the required
remaining permits by the time we commence mining these reserves,
but we may be unable to do so at all or within the necessary
time period. Some of the required
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permits have become increasingly more difficult and expensive to
obtain and the application review processes are taking longer to
complete and have been subject to more frequent challenges.
Because of these uncertainties, the quantity and quality of the
coal we are ultimately able to recover within our coal reserves
may differ materially from our estimates. Inaccuracies in our
estimates could result in revenue that is lower than we expect
or operating costs that are higher than we expect.
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A defect in title or the
loss of a leasehold interest in certain property could limit our
ability to mine our coal reserves or result in significant
unanticipated costs. |
We conduct a significant part of our coal mining operations on
properties that we lease. A title defect or the loss of a lease
could adversely affect our ability to mine the associated coal
reserves. We may not verify title to our leased properties or
associated coal reserves until we have committed to developing
those properties or coal reserves. We may not commit to develop
property or coal reserves until we have obtained necessary
permits and completed exploration. As such, the title to
property that we intend to lease or coal reserves that we intend
to mine may contain defects prohibiting our ability to conduct
mining operations. Similarly, our leasehold interests may be
subject to superior property rights of other third parties. In
order to conduct our mining operations on properties where these
defects exist, we may incur unanticipated costs. In addition,
some leases require us to produce a minimum quantity of coal and
contain minimum production royalties. Our inability to satisfy
those requirements may cause the leasehold interest to terminate.
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The availability and
reliability of transportation facilities and fluctuations in
transportation costs could affect the demand for our coal or
impair our ability to supply coal to our
customers. |
We depend upon barge, rail, truck and belt transportation
systems to deliver coal to our customers. Disruptions in
transportation services due to weather-related problems,
mechanical difficulties, strikes, lockouts, bottlenecks, and
other events could impair our ability to supply coal to our
customers. As we do not have long-term contracts with
transportation providers to ensure consistent and reliable
service, decreased performance levels over longer periods of
time could cause our customers to look to other sources for
their coal needs. In addition, increases in transportation
costs, including the price of gasoline and diesel fuel, could
make coal a less competitive source of energy when compared to
alternative fuels or could make coal produced in one region of
the United States less competitive than coal produced in other
regions of the United States or abroad. If we experience
disruptions in our transportation services or if transportation
costs increase significantly and we are unable to find
alternative transportation providers, our coal mining operations
may be disrupted, we could experience a delay or halt of
production or our profitability could decrease significantly.
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We may be unable to
realize the benefits we expect to occur as a result of
acquisitions that we undertake. |
We continually seek to expand our operations and coal reserves
through acquisitions of other businesses and assets, including
leasehold interests. Certain risks, including those listed
below, could cause us not to realize the benefits we expect to
occur as a result of those acquisitions:
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uncertainties in assessing the value, risks, profitability and
liabilities (including environmental liabilities) associated
with certain businesses or assets; |
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the potential loss of key customers, management and employees of
an acquired business; |
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the possibility that operating and financial synergies expected
to result from an acquisition do not develop; |
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problems arising from the integration of an acquired
business; and |
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unanticipated changes in business, industry or general economic
conditions that affect the assumptions underlying the rationale
for a particular acquisition. |
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Our profitability depends
upon the long-term coal supply agreements we have with our
customers. Changes in purchasing patterns in the coal industry
could make it difficult for us to extend our existing long-term
coal supply agreements or to enter into new agreements in the
future. |
We sell a substantial portion of our coal under long-term coal
supply agreements, which we define as contracts with a term
greater than one year. Under these arrangements, we fix the
prices of coal shipped during the initial year and may adjust
the prices in later years. As a result, at any given time the
market prices for similar-quality coal may exceed the prices for
coal shipped under these arrangements. Changes in the coal
industry may cause some of our customers not to renew, extend or
enter into new long-term coal supply agreements with us or to
enter into agreements to purchase fewer tons of coal than in the
past or on different terms or prices. In addition, uncertainty
caused by federal and state regulations, including the Clean Air
Act, could deter our customers from entering into long-term coal
supply agreements.
Because we sell a substantial portion of our coal production
under long-term coal supply agreements, our ability to
capitalize on more favorable market prices may be limited.
Conversely, at any given time we are subject to fluctuations in
market prices for the quantities of coal that we have produced
but which we have not committed to sell. As described above
under Our profitability and the value of our coal reserves
depend upon coal demand by United States electric power
generators and other factors beyond our control, the
market prices for coal may be volatile and may depend upon
factors beyond our control. Our profitability may be adversely
affected if we are unable to sell uncommitted production at
favorable prices or at all. For more information about our
long-term coal supply agreements, you should see Long-Term
Coal Supply Arrangements beginning on page 17.
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The loss of, or
significant reduction in, purchases by our largest customers
could adversely affect our profitability. |
For the year ended December 31, 2006, we derived
approximately 25.3% of our total coal revenues from sales to our
three largest customers, Tennessee Valley Authority, American
Electric Power Company, Inc. and TUCO, Inc., and approximately
52.7% of our total coal revenues from sales to our ten largest
customers. At December 31, 2006, we had coal supply
agreements with those ten customers that expire at various times
from 2007 to 2017. We expect to renew, extend or enter into new
long-term coal supply agreements with those and other customers.
However, we may be unsuccessful in obtaining long-term coal
supply agreements with those customers, and those customers may
discontinue purchasing coal from us. If any of those customers,
particularly any of our three largest customers, was to
significantly reduce the quantities of coal it purchases from
us, or if we are unable to sell coal to those customers on terms
as favorable to us as the terms under our current long-term coal
supply agreements, our profitability could suffer significantly.
We have limited protection during adverse economic conditions
and may face economic penalties if we are unable to satisfy
certain quality specifications under our long-term coal supply
agreements.
Our long-term coal supply agreements typically contain force
majeure provisions allowing the parties to temporarily
suspend performance during specified events beyond their
control. Most of our long-term coal supply agreements also
contain provisions requiring us to deliver coal that satisfies
certain quality specifications, such as heat value, sulfur
content, ash content, hardness and ash fusion temperature. These
provisions in our long-term coal supply agreements could result
in negative economic consequences to us, including price
adjustments, purchasing replacement coal in a higher-priced open
market, the rejection of deliveries or, in the extreme, contract
termination. Our profitability may be negatively affected if we
are unable to seek protection during adverse economic conditions
or if we incur financial or other economic penalties as a result
of these provisions of our long-term supply agreements.
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The amount of indebtedness
we have incurred could significantly affect our
business. |
At December 31, 2006, we had consolidated indebtedness of
approximately $1.2 billion. We also have significant lease
and royalty obligations. Our ability to satisfy our debt, lease
and royalty obligations, and our ability to refinance our
indebtedness, will depend upon our future operating performance.
We may be unable to generate sufficient cash flow from
operations and future borrowings or other financing may be
unavailable in an amount sufficient to enable us to satisfy our
financial obligations or our other liquidity needs. Our ability
to satisfy our financial obligations may be adversely affected
if we incur additional indebtedness in the future. In addition,
the amount of indebtedness we have incurred could have
significant consequences to our business, including those listed
below:
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making it more difficult for us to satisfy our debt covenants
and debt service, lease payment and other obligations; |
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increasing our vulnerability to general adverse economic and
industry conditions; |
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limiting our ability to obtain additional financing to fund
future acquisitions, working capital, capital expenditures or
other general operating requirements; |
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causing a downgrade in our credit ratings if we incur additional
debt or are unable to service our existing debt; |
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reducing the availability of cash flow from operations to fund
acquisitions, working capital, capital expenditures or other
general operating purposes; |
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limiting our flexibility in planning for, or reacting to,
changes in our business and the industry in which we
compete; and |
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placing us at a competitive disadvantage when compared to
competitors with less relative amounts of debt. |
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We may be unable to comply
with restrictions imposed by our credit facilities and other
financing arrangements. |
The agreements governing our outstanding debt and our accounts
receivable securitization program impose a number of
restrictions on us. For example, the terms of our credit
facilities, leases and other financing arrangements contain
financial and other covenants that create limitations on our
ability to borrow the full amount under our credit facilities,
effect acquisitions or dispositions and incur additional debt
and require us to maintain various financial ratios and comply
with various other financial covenants. Our ability to comply
with these restrictions may be affected by events beyond our
control and, as a result, we may be unable to comply with these
restrictions. A failure to comply with these restrictions could
adversely affect our ability to borrow under our credit
facilities or result in an event of default under these
agreements. In the event of a default, our lenders and the
counterparties to our other financing arrangements could
terminate their commitments to us and declare all amounts
borrowed, together with accrued interest and fees, immediately
due and payable. If this were to occur, we might not be able to
pay these amounts, or we might be forced to seek an amendment to
our financing arrangements which could make the terms of these
arrangements more onerous for us.
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Failure to obtain or renew
surety bonds on acceptable terms could affect our ability to
secure reclamation and coal lease obligations and, therefore,
our ability to mine or lease coal. |
Federal and state laws require us to obtain surety bonds to
secure performance or payment of certain long-term obligations,
such as mine closure or reclamation costs, federal and state
workers compensation costs, coal leases and other
obligations. We generally reprice these bonds annually, however,
they are not cancellable by the surety. Surety bond issuers and
holders may increase premiums on the bonds or impose 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
required by federal and state law could affect our ability to
secure reclamation and coal lease obligations and, therefore,
our ability to mine or lease coal. Several factors, including
those listed below, could cause us to be unable to maintain or
to acquire surety bonds in the future:
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lack of availability, higher expenses or unfavorable market
terms of new bonds; |
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restrictions on availability of collateral for current and
future third party surety bond issuers under the terms of our
credit facility; and |
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insufficient borrowing capacity under our revolving credit
facility or our receivable securitization facility for
additional letters of credit. |
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Our profitability may be
adversely affected if we must satisfy certain below-market
contracts with coal we purchase on the open market or with coal
we produce at our remaining operations. |
We have agreed to guarantee Magnums obligations to supply
coal under certain coal sales contracts that we sold to Magnum,
the longest of which extends to the year 2017. In order for the
transfer of these coal sales contracts to become effective, the
customers must approve the assignments of the contracts to
Magnum. At December 31, 2006, one customer had not yet
approved these assignments. Until this customer consents, we
have agreed to purchase the coal required to satisfy these
obligations from Magnum at the same price we charge the customer
under the contracts. If Magnum cannot supply the coal required
under these coal sales contracts, we would be required to
purchase coal on the open market or supply coal from our
existing operations in order to satisfy our obligations under
these contracts. If we had purchased all of the coal required
under these contracts at market prices in effect on
December 31, 2006, we would have incurred a loss of
approximately $97.1 million related to these contracts.
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Terrorist attacks and
threats, escalation of military activity in response to such
attacks or acts of war may adversely affect our
business. |
Terrorist attacks and threats, escalation of military activity
or acts of war have significant effects on general economic
conditions, fluctuations in consumer confidence and spending and
market liquidity. Future terrorist attacks, rumors or threats of
war, actual conflicts involving the United States or its allies,
or military or trade disruptions affecting our customers may
significantly affect our operations and those of our customers.
As a result, we could experience delays or losses in
transportation and deliveries of coal to our customers,
decreased sales of our coal or extended collections from our
customers.
Risks Related to Environmental and Other Regulations
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Federal and state
regulations impose significant costs on us, and future
regulations could increase those costs or limit our ability to
produce and sell coal. |
Federal and state authorities regulate certain areas, including
those listed below, that significantly affect the coal mining
industry:
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the discharge of materials into the environment; |
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employee health and safety; |
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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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management of materials generated by mining operations; |
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surface subsidence from underground mining; |
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water pollution; |
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statutorily mandated benefits for current and retired coal
miners; |
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air quality standards; |
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protection of wetlands; |
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endangered plant and wildlife protection; |
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limitations on land use; |
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storage and disposal of petroleum products and substances that
are regarded as hazardous under applicable laws; and |
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management of electrical equipment containing PCBs. |
The costs, liabilities and requirements associated with these
regulations may be significant 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 mining operations. We may also incur costs
and liabilities resulting from claims for damages to property or
injury to persons arising from our operations. Our profitability
may be negatively affected if we incur significant costs and
liabilities as a result of these regulations. You should see
Environmental Matters beginning on page 18 for more
information about the federal and state regulations affecting us.
The possibility exists that new legislation and/or regulations
and orders may be adopted that may 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. Such regulations, if enacted in the
future, could have a material adverse effect on our business,
financial condition and results of operations.
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Our failure to obtain and
renew permits necessary for our mining operations could
negatively affect our business. |
Mining companies must obtain numerous permits that regulate
environmental and health and safety matters in connection with
coal mining, including permits issued by various federal and
state agencies and regulatory bodies. We believe that we have
obtained the necessary permits to mine our developed reserves at
our mining complexes. However, as we commence mining our
undeveloped reserves, we will need to apply for and obtain the
required permits. The permitting rules are complex and change
frequently, making our ability to comply with the applicable
requirements more difficult or even impossible. In addition,
private individuals and the public at large have certain rights
to comment on and otherwise engage in the permitting process,
including through intervention in the courts. Accordingly, the
permits we need for our mining operations may not be issued, or,
if issued, may not be issued in a timely fashion. The permits
may also involve requirements that may be changed or interpreted
in a manner which restricts our ability to conduct our mining
operations or to do so profitably. An inability to conduct our
mining operations pursuant to applicable permits would reduce
our production, cash flow and profitability.
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If the assumptions
underlying our estimates of reclamation and mine closure
obligations are inaccurate, our costs could be greater than
anticipated. |
SMCRA establishes operational, reclamation and closure standards
for all aspects of surface mining, as well as most aspects of
underground mining. We base our estimates of reclamation and
mine closure liabilities on permit requirements and our
engineering expertise related to these requirements. Our
management and engineers periodically review these estimates.
The estimates can change significantly if actual costs vary from
assumptions or if governmental regulations change significantly.
Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations, which we
refer to as Statement No. 143, requires us to record these
obligations as liabilities at fair value. In estimating fair
value, we considered the estimated current costs of reclamation
and mine closure and applied inflation rates and a third-party
profit, as required by Statement No. 143. The third-party
profit is an estimate of the approximate markup that would be
charged by contractors for work performed on our behalf. If
actual costs differ from our estimates, our profitability could
be negatively affected.
|
|
|
Our operations may impact
the environment or cause exposure to hazardous substances, and
our properties may have environmental contamination, which could
result in material liabilities to us. |
Our operations currently use hazardous materials and generate
limited quantities of hazardous wastes from time to time. We
could become subject to claims for toxic torts, natural resource
damages and other damages as well as for the investigation and
clean up of soil, surface water, groundwater, and other media.
Such claims may arise, for example, out of conditions at sites
that we currently own or operate, as well as at sites that we
previously owned or operated, or may acquire. Our liability for
such claims may be joint and several, so that we may be held
responsible for more than our share of the contamination or
other damages, or even for the entire share.
We maintain extensive coal refuse areas and slurry impoundments
at a number of our mining complexes. Such areas and impoundments
are subject to extensive regulation. Slurry impoundments have
been known to fail, releasing large volumes of coal slurry into
the surrounding environment. 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. 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.
Drainage flowing from or caused by mining activities can be
acidic with elevated levels of dissolved metals, a condition
referred to as acid mine drainage, which we refer to
as AMD. The treating of AMD can be costly. Although we do not
currently face material costs associated with AMD, it is
possible that we could incur significant costs in the future.
These and other similar unforeseen impacts that our operations
may have on the environment, as well as exposures to hazardous
substances or wastes associated with our operations, could
result in costs and liabilities that could materially and
adversely affect us.
36
|
|
|
Judicial rulings that
restrict how we may dispose of mining wastes could significantly
increase our operating costs, discourage customers from
purchasing our coal and materially harm our financial condition
and operating results. |
To dispose of mining overburden generated by our surface mining
operations, we often need to obtain permits to construct and
operate valley fills and surface impoundments. Some of these
permits are Clean Water Act § 404 permits issued by
the Army Corps of Engineers. Two of our operating subsidiaries
were identified in an existing lawsuit, which challenged the
issuance of such permits and asked that the Corps be ordered to
rescind them. Our operating subsidiaries are seeking to
intervene in the suit to protect their interests in being
allowed to operate under the issued permits and have asked that
the claims against them be dismissed. We cannot predict the
final outcome of this lawsuit. If mining methods at issue are
limited or prohibited, it could significantly increase our
operational costs, make it more difficult to economically
recover a significant portion of our reserves and lead to a
material adverse effect on our financial condition and results
of operation. We may not be able to increase the price we charge
for coal to cover higher production costs without reducing
customer demand for our coal. You should see the section
entitled Contingencies beginning on page 63 for
more information about the litigation described above.
|
|
ITEM 1B. |
UNRESOLVED STAFF COMMENTS. |
None.
At December 31, 2006, we owned or controlled primarily
through long-term leases approximately 156,000 acres of
coal land in West Virginia, 101,000 acres of coal land in
Wyoming, 72,000 acres of coal land in Illinois,
62,000 acres of coal land in Utah, 49,000 acres of
coal land in Kentucky, 22,000 acres of coal land in New
Mexico and 17,000 acres of coal land in Colorado. In
addition, we also owned or controlled through long-term leases
smaller parcels of property in Alabama, Indiana, Montana and
Texas. We lease approximately 115,000 acres of our coal
land from the federal government and approximately
28,000 acres of our coal land from various state
governments. These governmental leases have terms expiring
between 2007 and 2010 and are subject to readjustment and/or
extension and to earlier termination for failure to meeting
diligent development requirements. Our Pardee, Levan, Sufco,
Cardinal, Holden 22, Mingo Logan, Ragland, Medicine Bow and
Seminoe II preparation plants or loadout facilities are
located on properties held under leases which expire at varying
dates over the next 30 years. Most of the leases contain
options to renew. Our remaining preparation plants and loadout
facilities are located on property owned by us or for which we
have a special use permit.
Our executive headquarters occupy approximately
93,000 square feet of leased space at One CityPlace Drive,
in St. Louis, Missouri. Our subsidiaries currently own or
lease the equipment utilized in their mining operations. You
should see Item 1. Business beginning on
page 1 for more information about our mining operations,
mining complexes and transportation facilities.
Our Reserves
We estimate that we owned or controlled approximately
2.9 billion tons of proven and probable recoverable
reserves at December 31, 2006. Recoverable reserves include
only saleable coal and do not
37
include coal which would remain unextracted, such as for support
pillars, and processing losses, such as washery losses. Reserve
estimates are prepared by our engineers and geologists and
reviewed and updated periodically. Total recoverable reserve
estimates and reserves dedicated to mines and complexes change
from time to time to reflect mining activities, analysis of new
engineering and geological data, changes in reserve holdings and
other factors.
The following tables present by state our estimated assigned and
unassigned recoverable coal reserves at December 31, 2006:
Total Assigned Reserves
(Tons in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sulfur Content | |
|
|
|
|
|
|
|
|
|
Past | |
|
|
Total | |
|
|
|
|
|
(lbs. per million | |
|
As Received | |
|
Reserve | |
|
|
|
Reserve | |
|
|
Assigned | |
|
|
|
|
|
Btus) | |
|
Btu | |
|
Control | |
|
Mining Method | |
|
Estimates | |
|
|
Recoverable | |
|
|
|
|
|
| |
|
per | |
|
| |
|
| |
|
| |
|
|
Reserves | |
|
Proven | |
|
Probable | |
|
<1.2 | |
|
1.2-2.5 | |
|
>2.5 | |
|
lb.(1) | |
|
Leased | |
|
Owned | |
|
Surface | |
|
Under-ground | |
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Wyoming
|
|
|
1,655 |
|
|
|
1,612 |
|
|
|
43 |
|
|
|
1,611 |
|
|
|
44 |
|
|
|
|
|
|
|
8,849 |
|
|
|
1,639 |
|
|
|
16 |
|
|
|
1,655 |
|
|
|
|
|
|
|
1,840 |
|
|
|
1,748 |
|
Utah
|
|
|
110 |
|
|
|
59 |
|
|
|
51 |
|
|
|
94 |
|
|
|
16 |
|
|
|
|
|
|
|
11,491 |
|
|
|
108 |
|
|
|
2 |
|
|
|
|
|
|
|
110 |
|
|
|
112 |
|
|
|
108 |
|
Colorado
|
|
|
67 |
|
|
|
52 |
|
|
|
15 |
|
|
|
67 |
|
|
|
|
|
|
|
|
|
|
|
11,767 |
|
|
|
65 |
|
|
|
2 |
|
|
|
|
|
|
|
67 |
|
|
|
80 |
|
|
|
74 |
|
Central
App
|
|
|
216 |
|
|
|
175 |
|
|
|
41 |
|
|
|
59 |
|
|
|
157 |
|
|
|
|
|
|
|
13,021 |
|
|
|
215 |
|
|
|
1 |
|
|
|
74 |
|
|
|
142 |
|
|
|
409 |
|
|
|
243 |
|
Illinois
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,048 |
|
|
|
1,898 |
|
|
|
150 |
|
|
|
1,831 |
|
|
|
217 |
|
|
|
|
|
|
|
9,526 |
|
|
|
2,027 |
|
|
|
21 |
|
|
|
1,729 |
|
|
|
319 |
|
|
|
2,441 |
|
|
|
2,186 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
As received Btu per lb. includes the weight of moisture in the
coal on an as sold basis. |
Total Unassigned Reserves
(Tons in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sulfur Content | |
|
|
|
|
|
|
|
|
|
|
|
|
Total | |
|
|
|
|
|
(lbs. per million | |
|
As Received | |
|
|
|
|
|
|
Unassigned | |
|
|
|
|
|
Btus) | |
|
Btu | |
|
Reserve Control | |
|
Mining Method | |
|
|
Recoverable | |
|
|
|
|
|
| |
|
per | |
|
| |
|
| |
|
|
Reserves | |
|
Proven | |
|
Probable | |
|
<1.2 | |
|
1.2-2.5 | |
|
>2.5 | |
|
lb.(1) | |
|
Leased | |
|
Owned | |
|
Surface | |
|
Underground | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Wyoming
|
|
|
368 |
|
|
|
255 |
|
|
|
113 |
|
|
|
321 |
|
|
|
47 |
|
|
|
|
|
|
|
9,591 |
|
|
|
277 |
|
|
|
91 |
|
|
|
193 |
|
|
|
175 |
|
Utah
|
|
|
41 |
|
|
|
17 |
|
|
|
24 |
|
|
|
36 |
|
|
|
5 |
|
|
|
|
|
|
|
10,939 |
|
|
|
40 |
|
|
|
1 |
|
|
|
|
|
|
|
41 |
|
Colorado
|
|
|
52 |
|
|
|
42 |
|
|
|
10 |
|
|
|
52 |
|
|
|
|
|
|
|
|
|
|
|
11,579 |
|
|
|
52 |
|
|
|
|
|
|
|
|
|
|
|
52 |
|
Central
App
|
|
|
186 |
|
|
|
132 |
|
|
|
54 |
|
|
|
86 |
|
|
|
57 |
|
|
|
43 |
|
|
|
12,521 |
|
|
|
105 |
|
|
|
81 |
|
|
|
48 |
|
|
|
138 |
|
Illinois
|
|
|
220 |
|
|
|
152 |
|
|
|
68 |
|
|
|
|
|
|
|
|
|
|
|
220 |
|
|
|
11,407 |
|
|
|
36 |
|
|
|
184 |
|
|
|
2 |
|
|
|
218 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
867 |
|
|
|
598 |
|
|
|
269 |
|
|
|
495 |
|
|
|
109 |
|
|
|
263 |
|
|
|
10,865 |
|
|
|
510 |
|
|
|
357 |
|
|
|
243 |
|
|
|
624 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
As received Btu per lb. includes the weight of moisture in the
coal on an as sold basis. |
At December 31, 2006, approximately 13.0% of our coal
reserves were held in fee, with the balance controlled by
leases, most of which do not expire until the exhaustion of
mineable and merchantable coal. Other leases have primary terms
expiring in various years ranging from 2007 to 2020, and most
contain options to renew for stated periods. Under current
mining plans, substantially all reported leased reserves will be
mined out within the period of existing leases or within the
time period of assured lease renewals. Royalties are paid to
lessors either as a fixed price per ton or as a percentage of
the gross sales price of the mined coal. The majority of the
significant leases are on a percentage royalty basis. In some
cases, a
38
payment is required, payable either at the time of execution of
the lease or in annual installments. In most cases, the prepaid
royalty amount is applied to reduce future production royalties.
Federal and state legislation controlling air pollution affects
the demand for certain types of coal by limiting the amount of
sulfur dioxide which may be emitted as a result of fuel
combustion and encourages a greater demand for low sulfur coal.
All of our identified coal reserves have been subject to
preliminary coal seam analysis to test sulfur content. Of these
reserves, approximately 79.8% consist of compliance coal, or
coal which emits 1.2 pounds or less of sulfur dioxide per
million Btu upon combustion, while an additional 7.2% could be
sold as low-sulfur coal. The balance is classified as
high-sulfur coal. Some of our low-sulfur coal can be marketed as
compliance coal when blended with other compliance coal.
Accordingly, most of our reserves are primarily suitable for the
domestic steam coal markets. However, a substantial portion of
the low-sulfur and compliance coal reserves at the Mingo Logan,
Cumberland River and Lone Mountain operations may also be used
as a high-volatile, low-sulfur, metallurgical coal.
The carrying cost of our coal reserves at December 31, 2006
was $1.1 billion, consisting of $119.4 million of
prepaid royalties and the $988.3 million net book value of
coal lands and mineral rights.
Title to coal properties held by lessors or grantors to us and
our subsidiaries and the boundaries of properties are normally
verified at the time of leasing or acquisition. However, in
cases involving less significant properties and consistent with
industry practices, title and boundaries are not completely
verified until such time as our independent operating
subsidiaries prepare to mine such reserves. If defects in title
or boundaries of undeveloped reserves are discovered in the
future, control of and the right to mine such reserves could be
adversely affected.
From time to time, lessors or sublessors of land leased by our
subsidiaries have sought to terminate such leases on the basis
that such subsidiaries have failed to comply with the financial
terms of the leases or that the mining and related operations
conducted by such subsidiaries are not authorized by the leases.
Some of these allegations relate to leases upon which we conduct
operations material to our consolidated financial position,
results of operations and liquidity, but we do not believe any
pending claims by such lessors or sublessors have merit or will
result in the termination of any material lease or sublease.
We leased approximately 58,000 acres of property to other
coal operators in 2006. We received royalty income of
$5.0 million in 2006 from the mining of approximately
2.4 million tons, $7.1 million in 2005 from the mining
of approximately 3.0 million tons and $4.0 million in
2004 from the mining of approximately 2.9 million tons on
those properties. We have included reserves at properties leased
by us to other coal operators in the reserve figures set forth
in this report.
39
We must obtain permits from applicable state regulatory
authorities before we begin to mine particular reserves.
Applications for permits require extensive engineering and data
analysis and presentation, and must address a variety of
environmental, health and safety matters associated with a
proposed mining operation. These matters include the manner and
sequencing of coal extraction, the storage, use and disposal of
waste and other substances and other impacts on the environment,
the construction of overburden fills and water containment
areas, and reclamation of the area after coal extraction. We are
required to post bonds to secure performance under our permits.
As is typical in the coal industry, we strive to obtain mining
permits within a time frame that allows us to mine reserves as
planned on an uninterrupted basis. We generally begin preparing
applications for permits for areas that we intend to mine up to
three years in advance of their expected issuance date.
Regulatory authorities have considerable discretion in the
timing of permit issuance and the public has rights to comment
on and otherwise engage in the permitting process, including
through intervention in the courts.
Our reported coal reserves are those that could be economically
and legally extracted or produced at the time of their
determination. In determining whether our reserves meet this
standard, we take into account, among other things, our
potential inability to obtain a mining permit, the possible
necessity of revising a mining plan, changes in estimated future
costs, changes in future cash flows caused by changes in costs
required to be incurred to meet regulatory requirements and
obtaining mining permits, variations in quantity and quality of
coal, and varying levels of demand and their effects on selling
prices. We have obtained, or we have a high probability of
obtaining, all required permits or government approvals with
respect to our reserves. Except as described elsewhere in this
document with respect to permits to conduct mining operations
involving valley fills, which has been taken into account in
determining our reserves, we are not currently aware of matters
which would significantly hinder our ability to obtain future
mining permits or governmental approvals with respect to our
reserves.
We periodically engage third parties to review our reserve
estimates. The most recent third-party review of our reserve
estimates was conducted by Weir International Mining Consultants
in February 2007.
|
|
ITEM 3. |
LEGAL PROCEEDINGS. |
You should see Contingencies beginning on
page 63 for more information about our pending litigation.
|
|
ITEM 4. |
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. |
There were no matters submitted to a vote of security holders
through the solicitation of proxies or otherwise during the
fourth quarter of 2006.
40
PART II
|
|
ITEM 5. |
MARKET FOR REGISTRANTS COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES. |
Market for Registrants Common Equity and Related
Stockholder Matters
Our common stock is listed and traded on the New York Stock
Exchange under the symbol ACI. On February 26,
2007, our common stock closed at $31.01 on the New York Stock
Exchange. On that date, there were approximately 8,760 holders
of record of our common stock.
Holders of our common stock are entitled to receive dividends
when they are declared by our board of directors. When dividends
are declared on common stock, they are usually paid in
mid-March, June, September and December. We paid dividends on
our common stock totaling $31.4 million, or $0.22 per
share, in 2006 and $20.7 million, or $0.16 per share,
in 2005. There is no assurance as to the amount or payment of
dividends in the future because they are dependent on our future
earnings, capital requirements and financial condition.
The following table sets forth for each period indicated the
dividends paid per common share, the high and low sale prices of
our common stock and the closing price of our common stock on
the last trading day for each of the quarterly periods
indicated. The information in the following table has been
adjusted to reflect a two-for-one stock split of our common
stock in the form of a 100% stock dividend paid on May 15,
2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 | |
|
|
| |
|
|
March 31 | |
|
June 30 | |
|
September 30 | |
|
December 31 | |
|
|
| |
|
| |
|
| |
|
| |
Dividends per common share
|
|
$ |
0.04 |
|
|
$ |
0.06 |
|
|
$ |
0.06 |
|
|
$ |
0.06 |
|
High
|
|
|
44.15 |
|
|
|
56.45 |
|
|
|
44.13 |
|
|
|
37.03 |
|
Low
|
|
|
34.30 |
|
|
|
37.10 |
|
|
|
25.88 |
|
|
|
25.85 |
|
Close
|
|
|
37.97 |
|
|
|
42.37 |
|
|
|
28.91 |
|
|
|
30.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
|
| |
|
|
March 31 | |
|
June 30 | |
|
September 30 | |
|
December 31 | |
|
|
| |
|
| |
|
| |
|
| |
Dividends per common share
|
|
$ |
0.04 |
|
|
$ |
0.04 |
|
|
$ |
0.04 |
|
|
$ |
0.04 |
|
High
|
|
|
23.77 |
|
|
|
28.72 |
|
|
|
34.97 |
|
|
|
41.10 |
|
Low
|
|
|
16.60 |
|
|
|
20.15 |
|
|
|
25.14 |
|
|
|
30.50 |
|
Close
|
|
|
21.51 |
|
|
|
27.24 |
|
|
|
33.75 |
|
|
|
39.75 |
|
41
Stock Price Performance Graph
The following performance graph compares the cumulative total
return to stockholders on our common stock with the cumulative
total return on three indices: a peer group, the peer group used
in our definitive proxy statement for our 2006 Annual Meeting of
Stockholders and the Standard & Poors (S&P)
400 (Midcap) Index. The graph assumes that:
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|
|
|
|
you invested $100 in Arch Coal common stock and in each index at
the closing price on December 31, 2001; |
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|
|
all dividends were reinvested; |
|
|
|
annual reweighting of the peer groups; and |
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|
you continued to hold your investment through December 31,
2006. |
For 2006, our peer group, which we refer to for purposes of the
table below as the New Industry Peer Group, consists of CONSOL
Energy, Inc., Foundation Coal Holdings, Inc., Massey Energy
Company and Peabody Energy Corp. For purposes of preparing the
performance graph included in our definitive proxy statement for
our 2006 Annual Meeting of Stockholders, our peer group, which
we refer to for purposes of the table below as the Old Industry
Peer Group, consisted of CONSOL Energy, Inc., Freeport McMoran
Copper&Gold, Massey Energy Company, Newmont Mining Corp.,
Peabody Energy Corp. and Southern Copper Corp. We have updated
our peer group to include those companies that we believe are
most representative of our industry.
You are cautioned against drawing any conclusions from the data
contained in this graph, as past results are not necessarily
indicative of future performance. The indices used are included
for comparative purposes only and do not indicate an opinion of
management that such indices are necessarily an appropriate
measure of the relative performance of our stock.
42
5-Year Total
Stockholder Return
Arch Coal, Inc. v. S&P 400 (Midcap) Index and
Industry Peer Groups
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|
12/31/01 | |
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12/31/02 | |
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12/31/03 | |
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12/31/04 | |
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12/31/05 | |
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12/31/06 | |
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| |
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| |
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| |
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| |
|
| |
|
| |
Arch Coal, Inc.
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|
$ |
100 |
|
|
$ |
96 |
|
|
$ |
140 |
|
|
$ |
161 |
|
|
$ |
363 |
|
|
$ |
276 |
|
S&P 400 (Midcap)
|
|
|
100 |
|
|
|
85 |
|
|
|
116 |
|
|
|
135 |
|
|
|
152 |
|
|
|
168 |
|
New Industry Peer Group (4 companies)
|
|
|
100 |
|
|
|
75 |
|
|
|
121 |
|
|
|
213 |
|
|
|
359 |
|
|
|
333 |
|
Old Industry Peer Group (6 companies)
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|
|
100 |
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|
|
111 |
|
|
|
201 |
|
|
|
217 |
|
|
|
308 |
|
|
|
331 |
|
Issuer Purchases of Equity Securities
The following table summarizes information about shares of our
common stock that we purchased during the fourth quarter of 2006.
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|
Approximate Dollar | |
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|
|
Total Number | |
|
Value of | |
|
|
|
|
|
|
of Shares | |
|
Shares that | |
|
|
|
|
|
|
Purchased As | |
|
May Yet | |
|
|
|
|
|
|
Part of our | |
|
be Purchased | |
|
|
Total Number | |
|
Average Price | |
|
Share | |
|
Under Our | |
|
|
of Shares | |
|
Paid per | |
|
Repurchase | |
|
Share Repurchase | |
Period |
|
Purchased | |
|
Share | |
|
Program(1) | |
|
Program | |
|
|
| |
|
| |
|
| |
|
| |
Oct. 1 - Oct. 31, 2006
|
|
|
712,400 |
|
|
$ |
28.06 |
|
|
|
712,400 |
|
|
|
|
|
Nov. 1 - Nov. 30, 2006
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dec. 1 - Dec. 31, 2006
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
712,400 |
|
|
|
|
|
|
|
712,400 |
|
|
$ |
385,689,976 |
(2) |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
In September 2006, our board of directors authorized a share
repurchase program for the purchase of up to
14,000,000 shares of our common stock. There is no
expiration date on the current authorization, and we have not
made any decisions to suspend or cancel purchases under the
program. |
43
|
|
|
As of December 31, 2006, we
have purchased 1,562,400 shares of our common stock under
this program.
|
|
(2) |
Calculated using
12,437,600 shares of our common stock which we may purchase
under the program and $31.01, the closing price of our common
stock as reported on the New York Stock Exchange on
February 26, 2007.
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|
ITEM 6. |
SELECTED FINANCIAL DATA. |
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|
|
Year Ended December 31 | |
|
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| |
|
|
2006 | |
|
2005 | |
|
2004 | |
|
2003 | |
|
2002 | |
|
|
(1)(2) | |
|
(1)(2)(3)(4) | |
|
(3)(5)(6) | |
|
(3)(6)(7) | |
|
(3) | |
|
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| |
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| |
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| |
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| |
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| |
|
|
(Amounts in thousands, except per share data) | |
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales revenue
|
|
$ |
2,500,431 |
|
|
$ |
2,508,773 |
|
|
$ |
1,907,168 |
|
|
$ |
1,435,488 |
|
|
$ |
1,473,558 |
|
Income from operations
|
|
|
336,667 |
|
|
|
77,857 |
|
|
|
178,046 |
|
|
|
40,371 |
|
|
|
29,277 |
|
Income (loss) before cumulative effect of accounting change
|
|
|
260,931 |
|
|
|
38,123 |
|
|
|
113,706 |
|
|
|
20,340 |
|
|
|
(2,562 |
) |
Cumulative effect of accounting change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,654 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
260,931 |
|
|
|
38,123 |
|
|
|
113,706 |
|
|
|
16,686 |
|
|
|
(2,562 |
) |
Preferred stock dividends
|
|
|
(378 |
) |
|
|
(15,579 |
) |
|
|
(7,187 |
) |
|
|
(6,589 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$ |
260,553 |
|
|
$ |
22,544 |
|
|
$ |
106,519 |
|
|
$ |
10,097 |
|
|
$ |
(2,562 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per common share before cumulative effect
of accounting change
|
|
$ |
1.83 |
|
|
$ |
0.18 |
|
|
$ |
0.95 |
|
|
$ |
0.13 |
|
|
$ |
(0.02 |
) |
Diluted earnings (loss) per common share before cumulative
effect of accounting change
|
|
|
1.80 |
|
|
|
0.17 |
|
|
|
0.89 |
|
|
|
0.13 |
|
|
|
(0.02 |
) |
Basic earnings (loss) per common share
|
|
|
1.83 |
|
|
|
0.18 |
|
|
|
0.95 |
|
|
|
0.10 |
|
|
|
(0.02 |
) |
Diluted earnings (loss) per common share
|
|
|
1.80 |
|
|
|
0.17 |
|
|
|
0.89 |
|
|
|
0.10 |
|
|
|
(0.02 |
) |
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
3,320,814 |
|
|
$ |
3,051,440 |
|
|
$ |
3,256,535 |
|
|
$ |
2,387,649 |
|
|
$ |
2,182,808 |
|
Working capital
|
|
|
46,471 |
|
|
|
216,376 |
|
|
|
355,803 |
|
|
|
237,007 |
|
|
|
37,799 |
|
Long-term debt, less current maturities
|
|
|
1,122,595 |
|
|
|
971,755 |
|
|
|
1,001,323 |
|
|
|
700,022 |
|
|
|
740,242 |
|
Other long-term obligations
|
|
|
391,819 |
|
|
|
382,256 |
|
|
|
800,332 |
|
|
|
722,954 |
|
|
|
653,789 |
|
Stockholders equity
|
|
|
1,365,594 |
|
|
|
1,184,241 |
|
|
|
1,079,826 |
|
|
|
688,035 |
|
|
|
534,863 |
|
Common Stock Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends per share
|
|
$ |
0.2200 |
|
|
$ |
0.1600 |
|
|
$ |
0.1488 |
|
|
$ |
0.1152 |
|
|
$ |
0.1152 |
|
Shares outstanding at year-end
|
|
|
142,179 |
|
|
|
142,741 |
|
|
|
125,716 |
|
|
|
106,410 |
|
|
|
104,868 |
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
$ |
308,102 |
|
|
$ |
254,607 |
|
|
$ |
148,728 |
|
|
$ |
162,361 |
|
|
$ |
176,417 |
|
Depreciation, depletion and amortization
|
|
|
208,354 |
|
|
|
212,301 |
|
|
|
166,322 |
|
|
|
158,464 |
|
|
|
174,752 |
|
Capital expenditures
|
|
|
623,187 |
|
|
|
357,142 |
|
|
|
292,605 |
|
|
|
132,427 |
|
|
|
137,089 |
|
Dividend payments
|
|
|
31,815 |
|
|
|
27,639 |
|
|
|
24,043 |
|
|
|
17,481 |
|
|
|
12,045 |
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
134,976 |
|
|
|
140,202 |
|
|
|
123,060 |
|
|
|
100,634 |
|
|
|
106,691 |
|
Tons produced
|
|
|
126,015 |
|
|
|
129,685 |
|
|
|
115,861 |
|
|
|
93,966 |
|
|
|
99,641 |
|
Tons purchased from third parties
|
|
|
10,092 |
|
|
|
11,226 |
|
|
|
12,572 |
|
|
|
6,602 |
|
|
|
8,060 |
|
|
|
(1) |
On October 27, 2005, we conducted a precautionary
evacuation of our West Elk mine after we detected elevated
readings of combustion-related gases in an area of the mine
where we had completed mining activities but had not yet removed
final longwall equipment. We estimate that the |
44
|
|
|
idling resulted in
$30.0 million in lost profits during the first quarter of
2006, in addition to the effect of the idling and fire-fighting
costs incurred during the fourth quarter of 2005 of
$33.3 million.
|
|
(2) |
On December 31, 2005, we
sold all of the stock of three subsidiaries and their associated
mining operations and coal reserves in Central Appalachia to
Magnum. As a result of the transaction, we recognized a gain
during 2005 of $7.5 million which we recorded as a
component of other operating income. In addition, we recognized
expenses of $8.7 million during 2006 related to the
finalization of working capital adjustments to the purchase
price, adjustments to estimated volumes associated with sales
contracts acquired by Magnum and expense related to settlement
accounting for pension plan withdrawals.
|
|
(3) |
On May 15, 2006, we
completed a two-for-one stock split of our common stock in the
form of a 100% stock dividend. All share and per share amounts
have been retroactively restated for the split.
|
|
(4) |
On December 30, 2005, we
completed a reserve swap with Peabody Energy Corp. and sold to
Peabody a rail spur, rail loadout and an idle office complex
located in the Powder River Basin, for a purchase price of
$84.6 million. As a result of the transaction, we
recognized a gain of $46.5 million which we recorded as a
component of other operating income.
|
|
(5) |
During 2004, we acquired the
North Rochelle mine in the Powder River Basin. We also purchased
the remaining 35% interest in Canyon Fuel that we did not
already own and began consolidating Canyon Fuel in our financial
statements as of July 31, 2004.
|
|
(6) |
During 2004 and 2003, we sold
our investment in Natural Resource Partners in four separate
transactions occurring in December 2003 and March, June and
October 2004. We recognized a gain of $42.7 million in the
fourth quarter of 2003 and an aggregate gain of
$91.3 million during 2004.
|
|
(7) |
On January 1, 2003, we
adopted Statement No. 143 resulting in a cumulative effect
of accounting change of $3.7 million (net of tax).
|
|
|
ITEM 7. |
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS. |
Overview
Our three reportable business segments are based on the
low-sulfur coal producing regions in the United States in which
we operate the Powder River Basin, the Western
Bituminous region and the Central Appalachia region. These
geographically distinct areas are characterized by geology, coal
transportation routes to consumers, regulatory environments and
coal quality. These regional similarities have caused market and
contract pricing environments to develop by coal region and form
the basis for the segmentation of our operations.
Our results for 2006 reflect higher margins driven primarily by
increased price realization and the disposition of certain
Central Appalachia operations at the end of 2005. We achieved
those results despite continued rail challenges in the western
United States and weak near-term market conditions. In 2005, we
experienced significant disruptions in our rail service from
major repair and maintenance work in the Powder River Basin.
During 2006, we experienced some shipment disruptions due to
ongoing repairs and maintenance on the rail lines, although not
of the magnitude experienced in 2005. Our results for 2006 also
reflected production at our Coal Creek surface mine in Wyoming,
which restarted production in 2006, and Skyline longwall mine in
Utah, which commenced mining in a new reserve area in 2006.
45
Across all three of our segments, we have committed to sell a
large percentage of our coal under sales contracts that we
signed in periods when market prices of coal were lower than
current market prices. Beginning in 2006 and continuing over the
course of the next several years, many of these commitments will
expire, and we expect to reprice future coal production at more
favorable prices. Abnormal weather patterns, better than
expected performance by competing fuels, increased coal
production and an increase in utilities coal stockpiles
during 2006 resulted in lower consumption by electric power
generation facilities. Nevertheless, we believe domestic and
global demand growth for coal along with supply pressures,
particularly in the Appalachia basin, will cause coal prices to
increase. In addition, we expect demand growth from new domestic
coal-fueled capacity will also influence future coal consumption
and coal prices. At December 31, 2006, we had expected
production available for repricing of approximately
11 million to 16 million tons in 2007, 75 million
to 85 million tons in 2008 and 110 million to
120 million tons in 2009.
We expect public interest in domestic energy security to
accelerate the adoption of coal conversion and other clean-coal
technologies. We anticipate that growing legislative support for
reducing the geopolitical risks associated with United States
oil supplies will cause alternative fuel sources, including
liquid fuels generated from coal, to become more significant. We
believe that advancement of these technologies represents a
positive development for the long-term outlook for coal demand.
Items Affecting Comparability of Reported Results
The comparison of our operating results for the years ended
December 31, 2006, 2005 and 2004 is affected by the
following significant items:
Sale of select Central Appalachia operations
On December 31, 2005, we sold the stock of three
subsidiaries and their four associated mining operations and
coal reserves in Central Appalachia to Magnum Coal Company. The
three subsidiaries were Hobet Mining, Apogee Coal Company and
Catenary Coal Company, which included the Hobet 21, Arch of
West Virginia, Samples and Campbells Creek mining operations.
For the year ended December 31, 2005, these subsidiaries
sold 12.7 million tons of coal, had revenues of
$509.8 million and incurred a loss from operations of
$8.3 million, and for the year ended December 31,
2004, these subsidiaries sold 14.0 million tons of coal,
had revenues of $475.1 million and incurred a loss from
operations of $3.8 million. We recognized a net gain of
$7.5 million in the fourth quarter of 2005 in conjunction
with this transaction. The gain we recorded included accrued
losses of $65.4 million on firm commitments to purchase
coal in 2006 to supply below-market sales contracts, which could
no longer be sourced from our operations as a result of the
transaction. In addition, we recognized expenses of
$8.7 million during 2006 related to the finalization of
working capital adjustments to the purchase price, adjustments
to estimated volumes associated with sales contracts acquired by
Magnum and settlement accounting for pension plan withdrawals.
In accordance with the terms of the transaction, we paid
$50.2 million to Magnum in 2006 to purchase coal and to
offset certain ongoing operating expenses of Magnum. In
addition, we were required under the agreement to manage working
capital for the operations sold to Magnum for a period of time
after the transaction. As of December 31, 2006, we had a
current receivable due from Magnum of $8.5 million.
Peabody reserve swap and asset sale On
December 30, 2005, we completed a reserve swap with Peabody
Energy Corp. and sold to Peabody a rail spur, rail loadout and
an idle office complex located in
46
the Powder River Basin for a purchase price of
$84.6 million. In the reserve swap, we exchanged
60.0 million tons of coal reserves for a similar block of
60.0 million tons of coal reserves with Peabody in order to
facilitate more efficient mine plans for both companies. In
conjunction with the transactions, we will continue to lease the
rail spur and loadout and office facilities through 2008 while
we mine adjacent reserves. We recognized a gain of
$46.5 million on the transaction, after the deferral of
$7.0 million of the gain, equal to the present value of the
lease payments. The deferred gain will be recognized over the
term of the lease.
West Elk combustion event The
combustion-related event at our West Elk mine in Colorado in
October 2005 caused the idling of the mine into the first
quarter of 2006. We estimate that the idling resulted in
$30.0 million in lost profits during the first quarter of
2006, in addition to the effect of the idling and fire-fighting
costs incurred during the fourth quarter of 2005 of
$33.3 million. We recognized insurance recoveries related
to the event of $41.9 million during the year ended
December 31, 2006. We have reflected these insurance
recoveries as a reduction of our cost of coal sales for the year
ended December 31, 2006. We do not expect to recover any
significant additional amounts as a result of this event.
Accounting for pit inventory On
January 1, 2006, we adopted the provisions of Emerging
Issues Task Force Issue
No. 04-6,
Accounting for Stripping Costs in the Mining Industry.
This issue applies to stripping costs incurred in the production
phase of a mine for the removal of overburden or waste materials
for the purpose of obtaining access to coal that will be
extracted. Under the issue, stripping costs incurred during the
production phase of the mine are variable production costs that
are included in the cost of inventory produced and extracted
during the period the stripping costs are incurred.
Historically, we recorded stripping costs associated with the
tons of coal uncovered and not yet extracted (pit inventory) at
our surface mining operations as coal inventory. The cumulative
effect of adoption was to reduce inventory by $40.7 million
and deferred development cost by $2.0 million with a
corresponding decrease to retained earnings, net of tax, of
$26.1 million. This accounting change creates volatility in
our results of operations, as cost increases or decreases
related to fluctuations in pit inventory can only be attributed
to tons extracted from the pit. Due to decreases in pit
inventory, net income was $10.6 million higher during the
year ended December 31, 2006 than it would have been under
our previous methodology of accounting for pit inventory.
Sales of interests in Natural Resource Partners
L.P. During 2004, we sold our remaining limited
partnership units of Natural Resource Partners L.P., resulting
in proceeds of approximately $111.4 million and a gain of
$91.3 million.
Acquisition of Triton Coal Company, LLC On
August 20, 2004, we acquired (1) Vulcan Coal Holdings,
L.L.C., which owned all of the common equity of Triton Coal
Company, LLC, and (2) all of the preferred units of Triton
for a purchase price of $382.1 million, including
transaction costs and working capital adjustments. Following the
consummation of the transaction, we completed an agreement to
sell Tritons Buckskin mine to Kiewit Mining Acquisition
Company. The net sales price for this second transaction was
$73.1 million. The total purchase price, including related
costs and fees, was funded with cash on hand, including the
proceeds from the Buckskin sale, $22.0 million in
borrowings under our existing revolving credit facility and a
$100.0 million term loan at our Arch Western Resources
subsidiary. We integrated the North Rochelle mine into our
existing Black Thunder mine in the Powder River Basin.
47
Acquisition of remaining interests of Canyon
Fuel On July 31, 2004, we purchased the
remaining 35% interest in Canyon Fuel that we did not previously
own from ITOCHU Corporation. Since the acquisition, we own all
of the ownership interests of Canyon Fuel and consolidate Canyon
Fuel in our financial statements. The results of operations of
the Canyon Fuel mines are included in our Western Bituminous
segment.
Results of Operations
|
|
|
Year Ended
December 31, 2006 Compared to Year Ended December 31,
2005 |
The following discussion summarizes our operating results for
the year ended December 31, 2006 and compares those results
to our operating results for the year ended December 31,
2005.
Revenues. The following table summarizes information
about coal sales during the year ended December 31, 2006
and compares those results to the comparable information for the
year ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 | |
|
Increase (Decrease) | |
|
|
| |
|
| |
|
|
2006 | |
|
2005 | |
|
$ | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Amounts in thousands, except per ton data) | |
Coal sales
|
|
$ |
2,500,431 |
|
|
$ |
2,508,773 |
|
|
$ |
(8,342 |
) |
|
|
(0.3 |
)% |
Tons sold
|
|
|
134,976 |
|
|
|
140,202 |
|
|
|
(5,226 |
) |
|
|
(3.7 |
) |
Coal sales realization per ton sold
|
|
$ |
18.53 |
|
|
$ |
17.89 |
|
|
$ |
0.64 |
|
|
|
3.6 |
% |
Coal sales remained relatively flat during 2006 when compared to
2005. Higher contract prices in all three of our segments
partially offset lower volumes resulting primarily from the sale
of certain Central Appalachia operations in the fourth quarter
of 2005. A higher percentage of Powder River Basin sales, which
have a lower average sales price per ton than our other regions,
caused the average overall sales price to increase only
slightly. We have provided more information about the tons sold
and the coal sales prices per ton by operating segment below.
The following table shows the number of tons sold by operating
segment during the year ended December 31, 2006 and
compares those amounts to the comparable information for the
year ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase | |
|
|
Tons Sold | |
|
(Decrease) | |
|
|
| |
|
| |
|
|
2006 | |
|
2005 | |
|
Tons | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Amounts in thousands) | |
Powder River Basin
|
|
|
96,246 |
|
|
|
91,471 |
|
|
|
4,775 |
|
|
|
5.2 |
% |
Western Bituminous
|
|
|
18,122 |
|
|
|
18,199 |
|
|
|
(77 |
) |
|
|
(0.4 |
) |
Central Appalachia
|
|
|
20,608 |
|
|
|
30,532 |
|
|
|
(9,924 |
) |
|
|
(32.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
134,976 |
|
|
|
140,202 |
|
|
|
(5,226 |
) |
|
|
(3.7 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volume increased in the Powder River Basin as a result of
the restart of the Coal Creek mine in the second quarter of 2006
and rail service that improved during 2006 when compared to
2005. In the Western Bituminous region, the effect of an
extended longwall move at the Dugout Canyon mine offset a
portion of the 1.5 million tons sold from our Skyline mine,
which commenced production in a new reserve
48
area in the second quarter of 2006. Our volumes in Central
Appalachia decreased as a result of the sale of operations to
Magnum described previously.
The following table shows the coal sales price per ton by
operating segment during the year ended December 31, 2006
and compares those amounts to the comparable information for the
year ended December 31, 2005. Coal sales prices per ton
exclude certain transportation costs that we pass through to our
customers. We use these financial measures because we believe
the amounts as adjusted better represent the coal sales prices
we achieved within our operating segments. Since other companies
may calculate coal sales prices per ton differently, our
calculation may not be comparable to similarly titled measures
used by those companies. For the year ended December 31,
2006, transportation costs per ton billed to customers were
$0.02 for the Powder River Basin, $2.91 for the Western
Bituminous region and $1.49 for Central Appalachia.
Transportation costs per ton billed to customers for the year
ended December 31, 2005 were $0.08 for the Powder River
Basin, $3.10 for the Western Bituminous region and $1.48 for
Central Appalachia.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended | |
|
|
|
|
December 31 | |
|
Increase | |
|
|
| |
|
| |
|
|
2006 | |
|
2005 | |
|
$ | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
Powder River Basin
|
|
$ |
10.82 |
|
|
$ |
8.20 |
|
|
$ |
2.62 |
|
|
|
32.0 |
% |
Western Bituminous
|
|
|
22.42 |
|
|
|
19.01 |
|
|
|
3.41 |
|
|
|
17.9 |
|
Central Appalachia
|
|
|
46.90 |
|
|
|
42.73 |
|
|
|
4.17 |
|
|
|
9.8 |
|
The increase in our coal sales prices in 2006 resulted from
higher contract pricing within all of our segments when compared
to 2005, due primarily to the expiration of lower-priced legacy
contracts. As discussed previously, we continue to replace sales
contracts that we signed in periods when market prices of coal
were lower than current market prices. In Central Appalachia,
the divestiture described previously of certain operations with
lower-priced legacy contracts also helped to improve our average
coal sales price per ton.
Expenses, costs and other. The following table summarizes
expenses, costs and other operating income and expenses, net for
the year ended December 31, 2006 and compares those results
to the comparable information for the year ended
December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) | |
|
|
Year Ended December 31 | |
|
in Net Income | |
|
|
| |
|
| |
|
|
2006 | |
|
2005 | |
|
$ | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Amounts in thousands) | |
Cost of coal sales
|
|
$ |
1,909,822 |
|
|
$ |
2,174,007 |
|
|
$ |
264,185 |
|
|
|
12.2 |
% |
Depreciation, depletion and amortization
|
|
|
208,354 |
|
|
|
212,301 |
|
|
|
3,947 |
|
|
|
1.9 |
|
Selling, general and administrative expenses
|
|
|
75,388 |
|
|
|
91,568 |
|
|
|
16,180 |
|
|
|
17.7 |
|
Gain on sale of Powder River Basin assets
|
|
|
|
|
|
|
(46,547 |
) |
|
|
(46,547 |
) |
|
|
(100.0 |
) |
Gain on sale of Central Appalachia operations
|
|
|
|
|
|
|
(7,528 |
) |
|
|
(7,528 |
) |
|
|
(100.0 |
) |
Other operating (income) expense, net
|
|
|
(29,800 |
) |
|
|
7,115 |
|
|
|
36,915 |
|
|
|
518.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
2,163,764 |
|
|
$ |
2,430,916 |
|
|
$ |
267,152 |
|
|
|
11.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales. Our cost of coal sales decreased from
2005 to 2006 primarily due to the sale of certain Central
Appalachia operations described above. This decrease was
partially offset by increased sales
49
volume, particularly in the Powder River Basin, and higher
costs, primarily production taxes and coal royalties, which we
pay as a percentage of coal sales. We have provided more
information about our operating margins by segment below.
Depreciation, depletion and amortization. The decrease in
depreciation, depletion and amortization from 2005 to 2006 is
due primarily to the sale of certain Central Appalachia
operations described above. Capital improvements associated with
development projects largely offset the decrease resulting from
the sale of Central Appalachia operations. We have provided
additional information concerning our capital spending during
2006 in the section entitled Liquidity and Capital
Resources beginning on page 56.
Selling, general and administrative expenses. Selling,
general and administrative expenses decreased in 2006 compared
to 2005 due primarily to a decrease of $6.7 million related
to deferred compensation, a decrease of $8.3 million
related to incentive compensation awards, and the establishment
of a charitable foundation in 2005 of $5.0 million.
Gain on sale. You should see Items Affecting
Comparability of Reported Results beginning on
page 46 for more information about the gains on the sale of
our Powder River Basin assets and Central Appalachia operations.
Other operating (income) expense, net. The increase in
net income in 2006 compared to 2005 from changes in other
operating (income) expense is due primarily to the following:
|
|
|
|
|
a decrease of $31.1 million in the amount of realized and
unrealized losses associated with sulfur dioxide emission
allowance put options and swaps; |
|
|
a decrease of $13.9 million in the net expense related to
bookouts (the netting of coal sales and purchase contracts with
the same counterparty); |
|
|
a gain of $10.3 million in 2006 on the acquisition of our
interest in Knight Hawk Holdings, LLC; |
|
|
an increase of $6.2 million in the amount of income from
equity investments; and |
|
|
a $16.0 million expense in 2005 related to settlement of
certain disputes with a landowner. |
These increases in other operating income are partially offset
by:
|
|
|
|
|
a decrease of $28.8 million in gains from sales of
property, plant and equipment; |
|
|
expenses of $8.7 million during 2006 related to the Magnum
transaction; and |
|
|
a decrease of $4.9 million in the amount of deferred gain
associated with the sale of our interest in Natural Resource
Partners, L.P., which we recognize over the terms of our leases
with Natural Resource Partners L.P., some of which were
transferred to Magnum. |
Operating margins. Our operating margins (reflected below
on a per-ton basis) include all mining costs, which consist of
all amounts classified as cost of coal sales (except
pass-through transportation costs discussed in
Revenues above) and all depreciation, depletion and
amortization attributable to mining operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended | |
|
|
|
|
December 31 | |
|
Increase | |
|
|
| |
|
| |
|
|
2006 | |
|
2005 | |
|
$ | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
Powder River Basin
|
|
$ |
2.15 |
|
|
$ |
0.95 |
|
|
$ |
1.20 |
|
|
|
126.3 |
% |
Western Bituminous
|
|
|
6.86 |
|
|
|
3.27 |
|
|
|
3.59 |
|
|
|
109.8 |
|
Central Appalachia
|
|
|
2.95 |
|
|
|
(0.59 |
) |
|
|
3.54 |
|
|
|
600.0 |
|
50
Powder River Basin On a per-ton basis, operating
margins in 2006 increased significantly from 2005 primarily due
to the increase in per-ton coal sales realizations discussed
previously. The effect of the higher realizations were partially
offset by increased production taxes and coal royalties, which
we pay as a percentage of coal sales realizations, higher repair
and maintenance activity and higher diesel, tire and explosives
costs during 2006 compared to 2005.
Western Bituminous Operating margins per ton in 2006
increased from 2005 primarily due to higher per ton sales prices
and insurance recoveries related to the West Elk thermal event
of $41.9 million, partially offset by higher costs
resulting from an extended longwall move at our Dugout Canyon
mine, higher coal royalties and production taxes, which we pay
as a percentage of sales, and higher repair and supplies costs.
Central Appalachia Operating margins per ton in 2006
increased significantly from 2005 primarily as a result of the
sale of certain operations at the end of 2005, discussed
previously, which operated at a loss in 2005, and higher coal
sales realizations.
Net interest expense. The following table summarizes our
net interest expense for the year ended December 31, 2006
and compares that information to the comparable information for
the year ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase | |
|
|
Year Ended | |
|
(Decrease) in Net | |
|
|
December 31 | |
|
Income | |
|
|
| |
|
| |
|
|
2006 | |
|
2005 | |
|
$ | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Amounts in thousands) | |
Interest expense
|
|
$ |
(64,364 |
) |
|
$ |
(72,409 |
) |
|
$ |
8,045 |
|
|
|
11.1 |
% |
Interest income
|
|
|
3,725 |
|
|
|
9,289 |
|
|
|
(5,564 |
) |
|
|
(59.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
(60,639 |
) |
|
$ |
(63,120 |
) |
|
$ |
2,481 |
|
|
|
3.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
The decrease in interest expense during 2006 compared to 2005
resulted primarily from an increase in the amounts of interest
capitalized in connection with certain major long-term
development projects described in more detail in the section
entitled Liquidity and Capital Resources beginning
on page 56. We capitalized $14.8 million of interest
during 2006 and $4.2 million during 2005. The decrease in
interest income is due to a decrease in short-term investments,
which we liquidated, in part, to fund our capital improvement
and development projects. For more information on our ongoing
capital improvement and development projects, you should see the
section entitled Liquidity and Capital Resources
beginning on page 56.
51
Other non-operating expense. The following table
summarizes our other non-operating expense for the year ended
December 31, 2006 and compares that information to the
comparable information for the year ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended | |
|
Increase in Net | |
|
|
December 31 | |
|
Income | |
|
|
| |
|
| |
|
|
2006 | |
|
2005 | |
|
$ | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Amounts in thousands) | |
Other non-operating expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses resulting from early debt extinguishment and
termination of hedge accounting for interest rate swaps
|
|
$ |
(4,836 |
) |
|
$ |
(7,740 |
) |
|
$ |
2,904 |
|
|
|
37.5 |
% |
Other non-operating expense
|
|
|
(2,611 |
) |
|
|
(3,524 |
) |
|
|
913 |
|
|
|
25.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
(7,447 |
) |
|
$ |
(11,264 |
) |
|
$ |
3,817 |
|
|
|
33.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts reported as non-operating consist of income or expense
resulting from our financing activities other than interest. As
described above, our results of operations include expenses
related to the termination of hedge accounting and resulting
amortization of amounts that had previously been deferred. Other
non-operating income includes
mark-to-market
adjustments related to certain swap activity that does not
qualify for hedge accounting.
Income taxes. Our effective tax rate is sensitive to
changes in estimates of annual profitability and percentage
depletion deductions. The income tax provision of
$7.7 million in 2006 compared with the income tax benefit
of $34.7 million in 2005 is primarily the result of
increases in pre-tax income in 2006, offset by a
$49.1 million decrease in our valuation allowance against
deferred tax assets in 2006, compared to a $6.1 million
decrease in our valuation allowance in 2005.
|
|
|
Year Ended
December 31, 2005 Compared to Year Ended December 31,
2004 |
The following discussion summarizes our operating results for
the year ended December 31, 2005 and compares those results
to our operating results for the year ended December 31,
2004.
Revenues. The following table summarizes information
about coal sales during the year ended December 31, 2005
and compares those results to the comparable information for the
year ended December 31, 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase | |
|
|
Year Ended December 31 | |
|
(Decrease) | |
|
|
| |
|
| |
|
|
2005 | |
|
2004 | |
|
$ | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Amounts in thousands, except per ton data) | |
Coal sales
|
|
$ |
2,508,773 |
|
|
$ |
1,907,168 |
|
|
$ |
601,605 |
|
|
|
31.5 |
% |
Tons sold
|
|
|
140,202 |
|
|
|
123,060 |
|
|
|
17,142 |
|
|
|
13.9 |
|
Coal sales realization per ton sold
|
|
$ |
17.89 |
|
|
$ |
15.50 |
|
|
$ |
2.39 |
|
|
|
15.4 |
% |
Coal sales. The increase in our coal sales resulted from
a combination of increased volumes, higher pricing, and the
acquisitions of Triton in the Powder River Basin on
August 20, 2004 and the remaining 35% interest in Canyon
Fuel in the Western Bituminous region on July 31, 2004. Our
per ton realizations increased due primarily to higher contract
prices in all three segments. On a consolidated basis, the
increase in per ton realization was partially offset by the
change in mix of sales volumes among our
52
operating regions. As reflected in the table below, Central
Appalachia volumes (which have the highest average realization)
were relatively flat in 2005, while volumes from lower
realization regions (the Powder River Basin and Western
Bituminous region) increased from 2004.
The following table shows the number of tons sold by operating
segment during the year ended December 31, 2005 and
compares those amounts to the comparable information for the
year ended December 31, 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons Sold | |
|
Increase | |
|
|
| |
|
| |
|
|
2005 | |
|
2004 | |
|
Tons | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Amounts in thousands) | |
Powder River Basin
|
|
|
91,471 |
|
|
|
81,857 |
|
|
|
9,614 |
|
|
|
11.7 |
% |
Western Bituminous
|
|
|
18,199 |
|
|
|
11,195 |
|
|
|
7,004 |
|
|
|
62.6 |
|
Central Appalachia
|
|
|
30,532 |
|
|
|
30,008 |
|
|
|
524 |
|
|
|
1.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
140,202 |
|
|
|
123,060 |
|
|
|
17,142 |
|
|
|
13.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
In 2005, all of our operating segments benefited from an overall
increase in demand, while volumes in the Powder River Basin and
the Western Bituminous region also benefited from the
acquisitions described above compared to 2004.
The following table shows the coal sales price per ton by
operating segment during the year ended December 31, 2005
and compares those amounts to the comparable information for the
year ended December 31, 2004. Coal sales prices per ton
exclude certain transportation costs that we pass through to our
customers. We use these financial measures because we believe
the amounts as adjusted better represent the coal sales prices
we achieved within our operating segments. As other companies
may calculate coal sales prices per ton differently, our
calculation may not be comparable to similarly titled measures
used by those companies. Transportation costs per ton billed to
customers for the year ended December 31, 2005 were $0.08
for the Powder River Basin, $3.10 for the Western Bituminous
region and $1.48 for Central Appalachia. For the year ended
December 31, 2004, transportation costs per ton billed to
customers were $0.05 for the Powder River Basin, $2.12 for the
Western Bituminous region and $1.46 for Central Appalachia.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended | |
|
|
|
|
December 31 | |
|
Increase | |
|
|
| |
|
| |
|
|
2005 | |
|
2004 | |
|
$ | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
Powder River Basin
|
|
$ |
8.20 |
|
|
$ |
7.07 |
|
|
$ |
1.13 |
|
|
|
16.0 |
% |
Western Bituminous
|
|
|
19.01 |
|
|
|
15.67 |
|
|
|
3.34 |
|
|
|
21.3 |
|
Central Appalachia
|
|
|
42.73 |
|
|
|
36.08 |
|
|
|
6.65 |
|
|
|
18.4 |
|
In the Powder River Basin, our coal sales prices increased due
to higher base pricing and above-market pricing on certain
contracts acquired with our Triton acquisition, as well as
higher sulfur dioxide quality premiums resulting from an
increase in sulfur dioxide emission allowance prices. Our coal
sales prices in Central Appalachia increased in 2005, as both
contract and spot market prices were higher than in 2004.
Additionally, we received higher sales prices on our
metallurgical coal sales in 2005 compared to 2004. The Western
Bituminous regions coal sales prices increased due to
higher contract pricing.
53
Expenses, costs and other. The following table summarizes
expenses, costs and other operating income and expenses, net for
the year ended December 31, 2005 and compares those results
to the comparable information for the year ended
December 31, 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) | |
|
|
Year Ended December 31 | |
|
in Net Income | |
|
|
| |
|
| |
|
|
2005 | |
|
2004 | |
|
$ | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Amounts in thousands) | |
Cost of coal sales
|
|
$ |
2,174,007 |
|
|
$ |
1,638,646 |
|
|
$ |
(535,361 |
) |
|
|
(32.7 |
)% |
Depreciation, depletion and amortization
|
|
|
212,301 |
|
|
|
166,322 |
|
|
|
(45,979 |
) |
|
|
(27.6 |
) |
Selling, general and administrative expenses
|
|
|
91,568 |
|
|
|
57,975 |
|
|
|
(33,593 |
) |
|
|
(57.9 |
) |
Gain on sale of Powder River Basin assets
|
|
|
(46,547 |
) |
|
|
|
|
|
|
46,547 |
|
|
|
100.0 |
|
Gain on sale of Central Appalachia operations
|
|
|
(7,528 |
) |
|
|
|
|
|
|
7,528 |
|
|
|
100.0 |
|
Gain on sale of investment in Natural Resource Partners
L.P.
|
|
|
|
|
|
|
(91,268 |
) |
|
|
(91,268 |
) |
|
|
(100.0 |
) |
Other operating (income) expense, net
|
|
|
7,115 |
|
|
|
(42,553 |
) |
|
|
(49,668 |
) |
|
|
(116.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
2,430,916 |
|
|
$ |
1,729,122 |
|
|
$ |
(701,794 |
) |
|
|
(40.6 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales. The increase in cost of coal sales is
primarily due to the acquisitions of Triton in the Powder River
Basin and the remaining 35% interest in Canyon Fuel in the
Western Bituminous region, along with an increase in
sales-sensitive taxes and royalties and higher diesel fuel,
explosives and utilities costs.
Depreciation, depletion and amortization. The increase in
depreciation, depletion and amortization is due primarily to the
property additions resulting from the acquisitions during the
third quarter of 2004 and to higher capital expenditures during
2005.
Selling, general and administrative expenses. Selling,
general and administrative expenses increased during 2005 due
primarily to $14.9 million of expense we recognized for
performance-contingent phantom stock awards to certain
employees. In addition, when comparing 2005 to 2004, costs
increased as a result of higher contract services, including
legal and professional fees ($5.2 million), employee
severance expense ($1.3 million), the establishment of a
charitable foundation during the fourth quarter of 2005
($5.0 million) and executive deferred compensation expense
($4.6 million).
Other operating (income) expense, net. Gains on sales of
assets other than those noted above were $28.2 million in
2005, compared to $6.7 million in 2004. This increase was
partially offset by the elimination of administrative fees from
Canyon Fuel subsequent to our acquisition of the remaining 35%
interest during the third quarter of 2004 which resulted in
$4.8 million of income in 2004, reduced bookout income,
related to the netting of coal sales and purchase contracts with
the same counterparty, of $9.4 million compared to the
prior year and a $6.5 million decrease in 2005 compared to
2004 of previously-deferred gains from our sales of limited
partnership units in Natural Resource Partners L.P. in 2003 and
2004. These deferred gains are being recognized over the terms
of our leases with Natural Resource Partners L.P. These
increases in other operating income, net were offset by a
$16.0 million settlement with a landowner, as well as an
expense of $19.7 million recognized to reflect the change
in fair
54
value of sulfur dioxide emission allowance swaps and put options
and coal swaps which are derivatives but do not qualify for
hedge accounting treatment.
Operating margins. Our operating margins (reflected below
on a per-ton basis) include all mining costs, which consist of
all amounts classified as cost of coal sales (except
pass-through transportation costs discussed in
Revenues above) and all depreciation, depletion and
amortization attributable to mining operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended | |
|
Increase | |
|
|
December 31 | |
|
(Decrease) | |
|
|
| |
|
| |
|
|
2005 | |
|
2004 | |
|
$ | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
Powder River Basin
|
|
$ |
0.95 |
|
|
$ |
0.86 |
|
|
$ |
0.09 |
|
|
|
10.5 |
% |
Western Bituminous
|
|
|
3.27 |
|
|
|
0.76 |
|
|
|
2.51 |
|
|
|
330.3 |
|
Central Appalachia
|
|
|
(0.59 |
) |
|
|
1.17 |
|
|
|
(1.76 |
) |
|
|
(150.4 |
) |
Powder River Basin On a per-ton basis, higher coal
sales prices in the Powder River Basin were partially offset by
higher operating costs, primarily due to higher production taxes
and coal royalties, diesel fuel costs, depreciation, depletion
and amortization costs and higher repairs and maintenance costs.
Additionally, average costs were higher due to the integration
of the North Rochelle mine into our Black Thunder mine in the
third quarter of 2004. These costs would have been largely
offset by increased productivity had rail service not adversely
impacted volumes during the year.
Western Bituminous On a per-ton basis, higher coal
sales prices were partially offset by the effect of the West Elk
thermal event discussed under Items Affecting
Comparability of Reported Results on page 46.
Central Appalachia On a per-ton basis, higher coal
sales prices were partially offset by increased costs for coal
purchases, increased labor costs, production taxes and coal
royalties, costs for operating supplies and diesel fuel, as well
as the increased preparation costs for metallurgical coal
discussed above. Additionally, during 2005 our Mingo Logan mine
moved into less favorable geological conditions than during
2004, resulting in higher per-ton costs.
Net interest expense. The following table summarizes our
net interest expense for the year ended December 31, 2005
and compares that information to the comparable information for
the year ended December 31, 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase | |
|
|
Year Ended | |
|
(Decrease) in Net | |
|
|
December 31 | |
|
Income | |
|
|
| |
|
| |
|
|
2005 | |
|
2004 | |
|
$ | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Amounts in thousands) | |
Interest expense
|
|
$ |
(72,409 |
) |
|
$ |
(62,634 |
) |
|
$ |
(9,775 |
) |
|
|
(15.6 |
)% |
Interest income
|
|
|
9,289 |
|
|
|
6,130 |
|
|
|
3,159 |
|
|
|
51.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
(63,120 |
) |
|
$ |
(56,504 |
) |
|
$ |
(6,616 |
) |
|
|
(11.7 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
The increase in interest expense results from a higher amount of
average borrowings in 2005 as compared to the same period in
2004. In addition, we recognized $1.4 million of interest
expense associated with state tax assessments. The increase in
interest income resulted primarily from interest on short-term
investments.
55
Other non-operating expense. The following table
summarizes our other non-operating expense for the year ended
December 31, 2005 and compares that information to the
comparable information for the year ended December 31, 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase | |
|
|
Year Ended | |
|
(Decrease) in Net | |
|
|
December 31 | |
|
Income | |
|
|
| |
|
| |
|
|
2005 | |
|
2004 | |
|
$ | |
|
% | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Amounts in thousands) | |
Other non-operating income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses resulting from early debt extinguishment and
termination of hedge accounting for interest rate
swaps
|
|
$ |
(7,740 |
) |
|
$ |
(9,010 |
) |
|
$ |
1,270 |
|
|
|
14.1 |
% |
Other non-operating income (expense)
|
|
|
(3,524 |
) |
|
|
1,044 |
|
|
|
(4,568 |
) |
|
|
(437.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
(11,264 |
) |
|
$ |
(7,966 |
) |
|
$ |
(3,298 |
) |
|
|
(41.4 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts reported as non-operating consist of income or expense
resulting from our financing activities other than interest. As
described above, our results of operations include expenses
related to the termination of hedge accounting and resulting
amortization of amounts that had previously been deferred. Other
non-operating income includes
mark-to-market
adjustments related to certain swap activity that does not
qualify for hedge accounting.
Income taxes. Our effective tax rate is sensitive to
changes in estimates of annual profitability and percentage
depletion. The increase in the income tax benefit of
$34.7 million in 2005 as compared to $0.1 million in
2004 is primarily the result of the taxable income from
non-mining sources from the sale of the Natural Resource
Partners L.P. limited partnership units in the first quarter of
2004. The benefit for 2005 is the result of our taxable income
and the effect of percentage depletion on our results.
Liquidity and Capital Resources
Our primary sources of cash include sales of our coal production
to customers, borrowings under our credit facilities, sales of
assets and debt and equity offerings related to significant
transactions. Excluding any significant mineral reserve
acquisitions, we generally satisfy our working capital
requirements and fund capital expenditures and debt-service
obligations with cash generated from operations or borrowings
under our credit facilities or accounts receivable
securitization program. Our ability to satisfy debt service
obligations, to fund planned capital expenditures, to make
acquisitions and to pay dividends will depend upon our future
operating performance, which will be affected by prevailing
economic conditions in the coal industry and financial, business
and other factors, some of which are beyond our control.
56
The following is a summary of cash provided by or used in each
of the indicated types of activities during the past three years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
| |
|
|
(Amounts in thousands) | |
Cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$ |
308,102 |
|
|
$ |
254,607 |
|
|
$ |
148,728 |
|
Investing activities
|
|
|
(688,005 |
) |
|
|
(291,543 |
) |
|
|
(597,294 |
) |
Financing activities
|
|
|
121,925 |
|
|
|
(25,730 |
) |
|
|
517,192 |
|
Cash provided by operating activities increased
$53.5 million in 2006 compared to 2005 primarily as a
result of an increase in net income which was offset by an
increased investment in working capital and payments resulting
from our sale of certain Central Appalachia operations on
December 31, 2005. Specifically, we made payments to Magnum
of $50.2 million in 2006 pursuant to the purchase agreement
related to that transaction. The payment related to the purchase
of coal and certain operating expenses. In addition, at
December 31, 2005, we accrued losses of $65.4 million
related to commitments to purchase coal in 2006 to satisfy
below-market contracts that we could not source from our
remaining operations.
Cash provided by operating activities increased during 2005
compared to 2004 primarily as a result of improved performance
at our operations in addition to a decreased investment in
working capital. While trade accounts receivable and inventory
represented the largest use of funds, increasing by
$86.8 million in 2005 compared to an increase of
$44.0 million in 2004, those increases were offset by an
increase in accounts payable and accrued expenses of more than
$108.5 million in 2005 compared to a decrease of
$6.8 million in 2004. In addition, we received
$14.7 million during the second quarter of 2005 related to
payment of receivables for settled audit years from the Internal
Revenue Service.
Cash used in investing activities in 2006 was
$396.5 million higher than in 2005, due to increased
capital expenditures and the purchase of equity-method
investments, as well as a decrease of $116.3 million in
proceeds from dispositions of property, plant and equipment. In
2006, we made the second of five annual payments of
$122.2 million on the Powder River Basins Little
Thunder federal coal lease, which will continue through 2009.
Costs related to the development of the Mountain Laurel complex
in West Virginia, higher spending at our Powder River Basin
operations related to the restart of the Coal Creek mine and
costs related to the purchase of a replacement longwall at the
Canyon Fuel operations in the Western Bituminous region resulted
in an increase in capital expenditures in 2006 compared to the
prior year period. We also spent $40.0 million during 2006
to acquire equity interests in other companies that will be
accounted for on the equity method.
We make capital expenditures to improve and replace existing
mining equipment, expand existing mines, develop new mines and
improve the overall efficiency of mining operations. We
anticipate that capital expenditures during 2007 will be between
approximately $240 million and $280 million, excluding
reserve additions. This estimate includes capital expenditures
related to development work at certain of our mining operations,
including the Mountain Laurel complex in West Virginia, work on
a new loadout at Black Thunder, and the final expenditures for a
new longwall at the SUFCO mine. This estimate assumes no other
acquisitions, significant expansions of our existing mining
operations or additions to our reserve base. In addition to
these expenditures, we will make another $122.2 million
installment for the Little
57
Thunder coal lease. We anticipate that we will fund these
capital expenditures with available cash, existing credit
facilities and cash generated from operations.
Cash used in investing activities in 2005 was
$305.8 million lower than in 2004, due to acquisitions in
July 2004 of the 35% of the Canyon Fuel membership interest not
previously owned by us and the North Rochelle operations
from Triton in August 2004, offset by partially higher capital
expenditures and payments to affiliates and to purchase equity
investments of $23.3 million in 2005. Offsetting uses of
cash were proceeds from the sales of land and equipment of
$117.0 million, including $84.6 million related to the
sale of the Powder River Basin assets, compared to
$7.4 million in 2004. In 2004, proceeds of
$111.4 million were received from the sale of limited
partnership units in Natural Resource Partners L.P.
Capital expenditures of $357.1 million in 2005 increased
$64.5 million, fueled by increases in capital spending at
the Central Appalachia operations of approximately
$150.1 million, offset by a decrease in payments made on
the Little Thunder lease. The increase in Central Appalachia
operations includes the development and construction of the
Mountain Laurel mining complex, where expenditures of
$88.3 million in 2005 represented an increase of
approximately $83.0 million over 2004. We financed the
Canyon Fuel acquisition with a $22.0 million five-year note
and approximately $90.0 million of cash on hand. We
financed the Triton acquisition with borrowings under the
revolving credit facility of $22.0 million, a term loan in
the amount of $100.0 million and with cash on hand.
Cash provided by financing activities in 2006 was
$121.9 million compared to a use of cash of
$25.7 million in 2005. The increase results primarily from
borrowings on the revolving credit facility and other credit
facilities, including those under the accounts receivable
securitization program discussed below, of $192.3 million,
compared to net payments of $25.0 million during 2005. The
increase in borrowings was to fund our higher capital
expenditures, including the Little Thunder federal coal lease
noted above. We also had $58.3 million of letters of credit
outstanding under the securitization program at
December 31, 2006. The average cost of borrowing under the
securitization program was approximately 5.36% at
December 31, 2006. We had available borrowing capacity of
$695.5 million under our credit facilities at
December 31, 2006. Financing activities in 2006 also
included cash received of $7.0 million from the issuance of
common stock under our employee stock incentive plans, a
decrease of $24.9 million from 2005. We spent
$43.9 million during 2006 under a share repurchase program
authorized by the board of directors in September 2006. The
program, which replaces a program adopted in 2001, provides for
the purchase of up to 14.0 million shares of common stock.
Cash used in financing activities during 2005 consists primarily
of net payments on our revolving credit facility of
$25.0 million, net payments on our long-term debt of
$2.4 million and dividend payments of $27.6 million,
offset partially by $31.9 million in proceeds from the
issuance of common stock under our employee stock incentive
plan. Cash provided by financing activities in 2004 consists
primarily of proceeds from the issuance of senior notes of
$261.9 million and proceeds from the issuance of common
stock through a public offering of $230.5 million described
below. Additionally, financing activities in 2004 also include
net borrowings under our revolving credit facility of
$25.0 million, proceeds of $37.0 million from the
issuance of common stock under our employee stock incentive plan
and dividend payments of $24.0 million.
58
We believe that cash generated from operations, borrowing under
our credit facilities, sales of assets and debt and equity
offerings will be sufficient to meet working capital
requirements, anticipated capital expenditures and scheduled
debt payments for at least the next several years.
On June 23, 2006, we amended our credit facility to change
the pricing grid upon which the interest rate on borrowings
under the credit facility is determined and to extend the
maturity date from December 22, 2009 to June 23, 2011.
As amended, borrowings under the credit facility bear interest
at a floating rate based on LIBOR determined by reference to our
leverage ratio, as calculated in accordance with the credit
agreement. In addition, the amendment to the credit facility
increased the maximum amount of borrowings available to us from
$700.0 million to $800.0 million and also revised
certain negative covenants and other provisions to provide us
with greater flexibility to pursue strategic investments. On
October 3, 2006, we entered into a further amendment to the
credit facility to eliminate the dollar limitation on the amount
of payments we are permitted to make annually with respect to
our outstanding capital stock and instead to limit our ability
to make those payments by requiring us to comply with certain
specified financial ratios, calculated in accordance with the
credit agreement, at the time such payments are made. Our credit
facility is secured by substantially all of our assets, as well
as our ownership interests in substantially all of our
subsidiaries, except our ownership interests in Arch Western
Resources, LLC and its subsidiaries.
Financial covenants contained in our revolving credit facility
consist of a maximum leverage ratio, a maximum senior secured
leverage ratio and a minimum interest coverage ratio. The
leverage ratio requires that we not permit the ratio of total
net debt (as defined in the facility) at the end of any calendar
quarter to EBITDA (as defined in the facility) for the four
quarters then ended to exceed a specified amount. The interest
coverage ratio requires that we not permit the ratio of EBITDA
(as defined) at the end of any calendar quarter to interest
expense for the four quarters then ended to be less than a
specified amount. The senior secured leverage ratio requires
that we not permit the ratio of total net senior secured debt
(as defined) at the end of any calendar quarter to EBITDA (as
defined) for the four quarters then ended to exceed a specified
amount. We were in compliance with all financial covenants at
December 31, 2006.
On June 23, 2006, we amended our receivable securitization
program to increase the program from $100.0 million to
$150.0 million and change the fees on amounts funded under
the program to rates based on our leverage ratio. Under the
terms of the accounts receivable securitization program,
eligible trade receivables consist of trade receivables
generated by our operating subsidiaries. Although the
participants in the program bear the risk of non-payment of
purchased receivables, we have agreed to indemnify the
participants with respect to various matters. The participants
under the program will be entitled to receive payments
reflecting a specified discount on amounts funded under the
program, including drawings under letters of credit, calculated
on the basis of the base rate or commercial paper rate, as
applicable. We will pay facility fees, program fees and letter
of credit fees (based on amounts of outstanding letters of
credit) at rates that vary with our leverage ratio.
Under the program, we are subject to certain affirmative,
negative and financial covenants customary for financings of
this type, including restrictions related to, among other
things, liens, payments, merger or consolidation and amendments
to the agreements underlying the receivables pool. The
administrator may terminate the program upon the occurrence of
certain events that are customary for facilities of this type
(with customary grace periods, if applicable), including, among
other things, breaches of covenants,
59
inaccuracies of representations and warranties, bankruptcy and
insolvency events, changes in the rate of default or delinquency
of the receivables above specified levels, a change of control
and material judgments. A termination event would permit the
administrator to terminate the program and enforce any and all
rights, subject to cure provisions, where applicable.
Additionally, the program contains cross-default provisions,
which would allow the administrator to terminate the program in
the event of non-payment of other material indebtedness when due
and any other event which results in the acceleration of the
maturity of material indebtedness.
At December 31, 2006, debt amounted to
$1,173.8 million, or 46% of capital employed, compared to
$982.4 million, or 45% of capital employed, at
December 31, 2005. Based on the level of consolidated
indebtedness and prevailing interest rates at December 31,
2006, debt service obligations for 2007, which include the
maturities of principal and interest expense, are estimated to
be $119.5 million.
We filed a shelf registration statement on
Form S-3 with the
SEC on March 14, 2006 that allows us to offer and sell from
time to time an unlimited amount of unsecured debt securities
consisting of notes, debentures, and other debt securities,
common stock, preferred stock, warrants, and/or units. Related
proceeds could be used for general corporate purposes, including
repayment of other debt, capital expenditures, possible
acquisitions and any other purposes that may be stated in any
prospectus supplement.
On October 28, 2004, we completed a public offering of
14,375,000 shares of our common stock, including the
underwriters full over-allotment option, at a price of
$16.93 per share. We used the net proceeds of the offering,
totaling $230.5 million after the underwriters
discount and expenses, to repay borrowings under our revolving
credit facility incurred to finance our acquisition of Triton
and the first annual payment for the Little Thunder federal coal
lease. We used the remaining proceeds for general corporate
purposes, including the development of the Mountain Laurel
longwall mine in Central Appalachia.
On October 22, 2004, two subsidiaries of Arch Western, as
co-obligors, issued $250 million of
63/4% senior
notes due 2013 at a price of 104.75% of par. The net proceeds of
the offering were used to repay and retire the outstanding
indebtedness under Arch Westerns $100.0 million term
loan maturing in 2007, to repay indebtedness under our revolving
credit facility and for general corporate purposes.
Ratio of Earnings to Fixed Charges
The following table sets forth our ratios of earnings to
combined fixed charges and preference dividends for the periods
indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Ratio of earnings to combined fixed charges and preference
dividends
|
|
|
3.99 |
x |
|
|
(1 |
) |
|
|
2.54 |
x |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(1) |
Ratio of earnings to combined fixed charges and preference
dividends is computed on a total enterprise basis including our
consolidated subsidiaries, plus our share of significant
affiliates accounted for on the equity method that are 50% or
greater owned or whose indebtedness has been directly or
indirectly guaranteed by us. Earnings consist of income (loss)
from continuing operations before income taxes and are adjusted
to include fixed charges (excluding capitalized interest). Fixed
charges consist of interest incurred on indebtedness, the
portion of operating lease rentals deemed representative of the |
60
|
|
|
interest factor and the
amortization of debt expense. Preference dividends are the
amount of pre-tax earnings required to pay dividends on our
outstanding preferred stock and Arch Western Resources,
LLCs preferred membership interest. Combined fixed charges
and preference dividends exceeded earnings by $0.8 million
for the year ended December 31, 2005, $2.9 million for
the year ended December 31, 2003 and $22.3 million for
the year ended December 31, 2002.
|
Contractual Obligations
The following is a summary of our significant contractual
obligations as of December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period | |
|
|
| |
|
|
2007 | |
|
2008-2009 | |
|
2010-2011 | |
|
After 2011 | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Amounts in thousands) | |
Long-term debt, including related interest
|
|
$ |
51,185 |
|
|
$ |
8,314 |
|
|
$ |
155,400 |
|
|
$ |
958,881 |
|
|
$ |
1,173,780 |
|
Operating leases
|
|
|
28,042 |
|
|
|
50,015 |
|
|
|
41,820 |
|
|
|
19,947 |
|
|
|
139,824 |
|
Royalty leases
|
|
|
149,078 |
|
|
|
292,629 |
|
|
|
43,061 |
|
|
|
21,861 |
|
|
|
506,629 |
|
Unconditional purchase obligations
|
|
|
436,711 |
|
|
|
84,109 |
|
|
|
|
|
|
|
|
|
|
|
520,820 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations
|
|
$ |
665,016 |
|
|
$ |
435,067 |
|
|
$ |
240,281 |
|
|
$ |
1,000,689 |
|
|
$ |
2,341,053 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty leases represent non-cancelable royalty lease
agreements, as well as federal lease bonus payments due under
the Little Thunder lease. Remaining payments due under the
Little Thunder lease will be paid in three equal annual
installments of $122.2 million in years 2007 through 2009.
Unconditional purchase obligations represent amounts committed
for purchases of materials and supplies, payments for services,
purchased coal, and capital expenditures.
Our consolidated balance sheet reflects a liability of
$216.6 million for the fair value of asset retirement
obligations that arise from SMCRA and similar state statutes,
which require that mine property be restored in accordance with
specified standards and an approved reclamation plan. The
determination of the fair value of asset retirement obligations
involves a number of estimates, as discussed in the section
entitled Critical Accounting Policies beginning on
page 65, including the timing of payments to satisfy asset
retirement obligations. The timing of payments to satisfy asset
retirement obligations is based on numerous factors, including
mine closure dates. You should see the notes to our consolidated
financial statements for more information about our asset
retirement obligations.
The table above also excludes certain other obligations
reflected in our consolidated balance sheet, including estimated
funding for pension and postretirement benefit obligations, for
which the timing of payments may vary based on changes in the
fair value of plan assets (for pension obligations) and
actuarial assumptions and payments under our self-insured
workers compensation program. You should see the section
entitled Critical Accounting Policies beginning on
page 65 for more information about these assumptions. We
expect to make contributions of $1.7 million to our pension
plans in 2007. You should see the notes to our consolidated
financial statements for more information about the amounts we
have recorded for workers compensation and pension and
postretirement benefit obligations.
61
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to certain
off-balance sheet arrangements. These arrangements include
guarantees, indemnifications, financial instruments with
off-balance sheet risk, such as bank letters of credit and
performance or surety bonds. Liabilities related to these
arrangements are not 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.
We use a combination of surety bonds, corporate guarantees
(e.g., self bonds) and letters of credit to secure our financial
obligations for reclamation, workers compensation,
postretirement benefits, coal lease obligations and other
obligations as follows as of December 31, 2006:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Workers | |
|
|
|
|
|
|
Reclamation | |
|
Lease | |
|
Compensation | |
|
|
|
|
|
|
Obligations | |
|
Obligations | |
|
Obligations | |
|
Other | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Amounts in thousands) | |
Self bonding
|
|
$ |
265,222 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
265,222 |
|
Surety bonds
|
|
|
247,681 |
|
|
|
33,017 |
|
|
|
14,700 |
|
|
|
8,811 |
|
|
|
304,209 |
|
Letters of credit
|
|
|
|
|
|
|
|
|
|
|
45,145 |
|
|
|
14,682 |
|
|
|
59,827 |
|
We have agreed to continue to provide surety bonds and letters
of credit for the reclamation, workers compensation and
retiree healthcare obligations of the properties we sold to
Magnum in order to facilitate an orderly transition. Magnum is
required to reimburse us for costs related to the surety bonds
and letters of credit until it can replace these items. If the
surety bonds and letters of credit related to the reclamation
obligations are not replaced by Magnum within two years of the
transaction, then Magnum must post a letter of credit in our
favor in the amounts of the obligations. Letters of credit
related to workers compensation obligations were replaced
by Magnum during the fourth quarter of 2006. At
December 31, 2006, we had $92.0 million of surety
bonds related to properties sold to Magnum.
In addition, we have agreed to guarantee the performance of
Magnum with respect to certain coal sales contracts sold to
Magnum, the longest of which extends to the year 2017, and
certain operating leases, the longest of which ends in 2011.
Under the coal sales contracts, the customers must approve the
assignment of the contracts to Magnum. Until the contracts are
assigned, we are purchasing the coal from Magnum to sell to
these customers at the same price it is charging the customers
for the sale. One customer agreed to the assignment in the
second quarter of 2006, under the agreement that we would
continue to guarantee Magnums performance until the end of
2006. If Magnum is unable to supply the coal for these coal
sales contracts, then we would be required to purchase coal on
the open market or supply the contract from our existing
operations. If we were required to purchase coal to supply the
contracts over their duration at market prices effective at
December 31, 2006, the cost of the purchased coal would
exceed the sales price under the contracts by
$97.1 million. If we were required to perform under our
guarantee of the operating lease agreements, we would be
required to make $15.3 million of lease payments. We
believe that it is remote that we would be required to perform
under these guarantees. However, if we would have to perform
under these guarantees, it could potentially have a material
adverse effect on our business, results of operations and
financial condition.
In connection with the acquisition of the coal operations of
Atlantic Richfield Company, which we refer to as ARCO, and the
simultaneous combination of the acquired ARCO operations and our
Wyoming operations into the Arch Western joint venture, we
agreed to indemnify the other member of Arch
62
Western against certain tax liabilities in the event that such
liabilities arise prior to June 1, 2013 as a result of
certain actions taken, including the sale or other disposition
of certain properties of Arch Western, the repurchase of certain
equity interests in Arch Western by Arch Western or the
reduction under certain circumstances of indebtedness incurred
by Arch Western in connection with the acquisition. If we were
to become liable, the maximum amount of potential future tax
payments was $173.7 million at December 31, 2006, of
which none is recorded as a liability on our financial
statements. Since the indemnification is dependent upon the
initiation of activities within our control and we do not intend
to initiate such activities, it is remote that we will become
liable for any obligation related to this indemnification.
However, if such indemnification obligation were to arise, it
could potentially have a material adverse effect on our
business, results of operations and financial condition.
In addition, tax reporting applied to this transaction by the
other member of Arch Western was being audited by the Internal
Revenue Service, which we refer to as the IRS. We do not believe
that we are bound by the outcome of this audit. Nevertheless, we
anticipate that following the conclusion of the audit of the
other member, we will soon begin negotiations with the IRS as to
adjustments, if any, of Arch Westerns tax reporting. The
outcome of these negotiations when settled could result in
adjustments to the basis of the partnership assets, and it is
possible we may be required to adjust our deferred income taxes
associated with our investment in Arch Western. Given the
uncertainty of how an adverse outcome would affect our deferred
income tax position, coupled with potential offsetting tax
positions that we may be able to take, we are not able to
reasonably determine the resulting outcome of this issue.
However, any change that impacts us related to an IRS
negotiation may result in a non-cash decrease in deferred income
tax assets associated with our investment in Arch Western and
could fall within a range of zero to $41.0 million.
Contingencies
Reclamation. SMCRA and similar state statutes require
that mine property be restored in accordance with specified
standards and an approved reclamation plan. We accrue for the
costs of reclamation in accordance with the provisions of
Statement No. 143. These costs relate to reclaiming the pit
and support acreage at surface mines and sealing portals at
underground mines. Other costs of reclamation common to surface
and underground mining are related to reclaiming refuse and
slurry ponds, eliminating sedimentation and drainage control
structures, and dismantling or demolishing equipment or
buildings used in mining operations. The establishment of the
asset retirement obligation liability is based upon permit
requirements and requires various estimates and assumptions,
principally associated with costs and productivities.
We review our entire environmental liability periodically and
make necessary adjustments, including permit changes and
revisions to costs and productivities, to reflect current
experience. Our management believes it is making adequate
provisions for all expected reclamation and other associated
costs.
Permit Litigation Matters.
Two of our operating subsidiaries have been identified in an
existing lawsuit as having been granted Clean Water Act
§404 permits by the Corps allegedly in violation of the
Clean Water Act and the National Environmental Policy Act.
Surface mines at our Mingo Logan and Coal-Mac mining complexes
have been identified in the suit for having received permits
from the Corps. The lawsuit, brought by the Ohio Valley
Environmental Coalition in the U.S. District Court for the
Southern District of
63
West Virginia, had originally been filed against the Corps for
permits it had issued to coal operations owned by subsidiaries
of a company unrelated to us or our operating subsidiaries.
The existing suit claims that the Corps had issued permits to
the coal operations belonging to the unrelated company that do
not comply with the National Environmental Policy Act and
violate the Clean Water Act. At the time the plaintiffs
attempted to supplement their complaint to add the permit issued
by the Corps to our operating subsidiaries, the lawsuit had been
tried to completion and was awaiting a decision by the court.
The motions to supplement the complaint and add the newly issued
permits name only the Corps as the defendant and ask that the
Corps be ordered to rescind the permits.
Our operating subsidiaries are seeking to intervene in the suit
to protect their interests in being allowed to operate under the
issued permits. They have requested that the court dismiss the
motions to supplement as improperly attempting to join the facts
and legal theories of our permits with the existing case. Their
motions are now before the court for decision.
While the outcome of this litigation is subject to
uncertainties, based on our preliminary evaluation of the issues
and the potential impact on us, we believe these matters will be
resolved without a material adverse effect on our financial
condition or results of operations or liquidity.
West Virginia Flooding Litigation. We have been served,
among others, including a former subsidiary whom we have agreed
to defend, in 15 separate complaints filed and served in
Wyoming, McDowell, Fayette, Kanawha, Raleigh, Boone and Mercer
Counties, West Virginia. These cases collectively include
approximately 3,100 plaintiffs who are seeking to recover from
more than 180 defendants for property damage and personal
injuries arising out of flooding that occurred in southern West
Virginia on or about July 8, 2001. The plaintiffs have sued
coal, timber, oil and gas, and land companies under the theory
that mining, construction of haul roads and removal of timber
caused natural surface waters to be diverted in an unnatural
way, thereby causing damage to the plaintiffs. The West Virginia
Supreme Court has ruled that these cases, along with other flood
damage cases not involving us, will be handled pursuant to the
courts mass litigation rules. As a result of this ruling,
the cases have been transferred to the Circuit Court of Raleigh
County in West Virginia to be handled by a panel consisting of
three circuit court judges. Trials, by watershed, have begun and
are proceeding in phases. On May 2, 2006, the jury returned
a verdict concerning certain preliminary matters against the
two, non-settling defendants in the first phase of the first
watershed, in which we were not involved. We were previously
named in cases involving the Coal River watershed. On
January 18, 2007, the court dismissed the plaintiffs
claims. The plaintiffs have four months from the entry of the
order to appeal. We are also named in the Tug Fork and remaining
Upper Guyandotte watershed trial groups. These groups will also
proceed to trial in phases. A trial date has not yet been set.
While the outcome of this litigation is subject to
uncertainties, based on our preliminary evaluation of the issues
and the potential impact on us, we believe this matter will be
resolved without a material adverse effect on our financial
condition, results of operations or liquidity.
We are a party to numerous other claims and lawsuits and are
subject to numerous other contingencies with respect to various
matters. We provide for costs related to contingencies,
including environmental, legal and indemnification matters, when
a loss is probable and the amount is reasonably determinable.
After conferring with counsel, it is the opinion of management
that the ultimate resolution of
64
these claims, to the extent not previously provided for, will
not have a material adverse effect on our consolidated financial
condition, results of operations or liquidity.
Critical Accounting Policies
We prepare our financial statements in accordance with
accounting principles that are generally accepted in the United
States. The preparation of these financial statements requires
management to make estimates and judgments that affect the
reported amounts of assets, liabilities, revenues and expenses
as well as the disclosure of contingent assets and liabilities.
Management bases its estimates and judgments on historical
experience and other factors that are believed to be reasonable
under the circumstances. Additionally, these estimates and
judgments are discussed with our audit committee on a periodic
basis. Actual results may differ from the estimates used under
different assumptions or conditions. We have provided a
description of all significant accounting policies in the notes
to our consolidated financial statements. We believe that of
these significant accounting policies, the following may involve
a higher degree of judgment or complexity:
|
|
|
Asset Retirement
Obligations |
Our asset retirement obligations arise from SMCRA and similar
state statutes, which require that mine property be restored in
accordance with specified standards and an approved reclamation
plan. Significant reclamation activities include reclaiming
refuse and slurry ponds, reclaiming the pit and support acreage
at surface mines, and sealing portals at deep mines. Our asset
retirement obligations are initially recorded at fair value, or
the amount at which the obligations could be settled in a
current transaction between willing parties. This involves
determining the present value of estimated future cash flows on
a mine-by-mine basis based upon current permit requirements and
various estimates and assumptions, including estimates of
disturbed acreage and reclamation costs and assumptions
regarding productivity. We estimate disturbed acreage based on
approved mining plans and related engineering data. Since we
plan to use internal resources to perform reclamation
activities, our estimate of reclamation costs involves
estimating third-party profit margins, which we base on our
historical experience with contractors that perform certain
types of reclamation activities. We base productivity
assumptions on historical experience with the equipment that we
expect to utilize in the reclamation activities. In order to
determine fair value, we must also discount our estimates of
cash flows to their present value. We base our discount rate on
the rates of treasury bonds with maturities similar to expected
mine lives, adjusted for our credit standing.
On at least an annual basis, we review our entire reclamation
liability and make necessary adjustments for permit changes as
granted by state authorities, changes in the timing of
reclamation activities, and revisions to cost estimates and
productivity assumptions, to reflect current experience. Any
difference between the actual cost of reclamation and the fair
value will be recorded as a gain or loss when the obligation is
settled. We expect our actual cost to reclaim our properties
will be less than the amount reflected as an asset retirement
obligation. At December 31, 2006, we had recorded asset
retirement obligation liabilities of $216.6 million,
including amounts classified as a current liability. While the
precise amount of these future costs cannot be determined with
certainty, as of December 31, 2006, we estimate that the
aggregate undiscounted cost of final mine closure is
approximately $528.4 million.
65
As of January 1, 2006, we adopted Statement of Financial
Accounting Standards No. 123 (revised 2004), Share-Based
Payment, which we refer to as Statement No. 123R, which
requires all public companies to measure compensation cost in
the income statement for all share-based payments (including
employee stock options) at fair value. We adopted Statement
No. 123R using the modified-prospective method. Under this
method, compensation cost for share-based payments to employees
is based on their grant-date fair value from the beginning of
the fiscal period in which the recognition provisions are first
applied. Measurement and recognition of compensation cost for
awards that were granted prior to, but not vested as of, the
date Statement No. 123R was adopted are based on the same
estimate of the grant-date fair value and the same recognition
method used previously under Statement No. 123. We use the
Black-Scholes option pricing model for options and a lattice
model at the grant date for the portion of share-based payments
with performance and market conditions that is paid out in stock
to determine the fair value. As of December 31, 2006, a $1
increase in our stock price would have resulted in additional
expense of $0.1 million for the year ended
December 31, 2006.
|
|
|
Derivative Financial
Instruments |
We use derivative financial instruments to manage exposures to
commodity prices and interest rates. Derivative financial
instruments are recognized in the balance sheet at fair value.
Changes in fair value are recognized in earnings if they are not
eligible for hedge accounting or other comprehensive income if
they qualify for cash flow hedge accounting. Amounts in other
comprehensive income are reclassified to earnings when the
hedged transaction affects earnings. Any ineffective portion of
a cash flow hedges change in fair value is recognized
immediately in earnings.
We formally document all relationships between hedging
instruments and hedged items, as well as our risk management
objectives for undertaking various hedge transactions. We
evaluate the effectiveness of our hedging relationships both at
the hedge inception and on an ongoing basis.
We have non-contributory defined benefit pension plans covering
certain of our salaried and hourly employees. Benefits are
generally based on the employees age and compensation. We
fund the plans in an amount not less than the minimum statutory
funding requirements nor more than the maximum amount that can
be deducted for federal income tax purposes. We contributed
$19.3 million in cash and stock to the plans during the
year ended December 31, 2006 and contributed
$20.0 million in cash and stock to the plans during the
year ended December 31, 2005. We account for our defined
benefit plans in accordance with Statement of Financial
Accounting Standards No. 87, Employers Accounting
for Pensions, as amended by Statement of Financial
Accounting Standards No. 158, Employers Accounting
for Defined Benefit Pension and Other Postretirement Plans,
which we refer to as Statement No. 87 and Statement
No. 158. Statement No. 158 requires that the
actuarially-determined funded status of the plans be recorded in
the balance sheet, which resulted in an increase to accumulated
other comprehensive loss of $11.9 million at
December 31, 2006.
In June 2006, the disposition of certain Central Appalachia
operations in 2005 resulted in withdrawals that constituted a
settlement of our pension benefit obligation for which we
recognized expense of $3.2 million.
66
The calculation of our net periodic benefit costs (pension
expense) and benefit obligation (pension liability) associated
with our defined benefit pension plans requires the use of a
number of assumptions that we deem to be critical
accounting estimates. Changes in these assumptions can
result in different pension expense and liability amounts, and
actual experience can differ from the assumptions.
|
|
|
|
|
The expected long-term rate of return on plan assets is an
assumption reflecting the average rate of earnings expected on
the funds invested or to be invested to provide for the benefits
included in the projected benefit obligation. We establish the
expected long-term rate of return at the beginning of each
fiscal year based upon historical returns and projected returns
on the underlying mix of invested assets. The pension
plans investment targets are 65% equity, 30% fixed income
securities and 5% cash. Investments are rebalanced on a periodic
basis to stay within these targeted guidelines. The long-term
rate of return assumption used to determine pension expense was
8.25% for 2006 and 8.5% 2005. These long-term rate of return
assumptions are less than the plans actual
life-to-date returns.
Any difference between the actual experience and the assumed
experience is recorded in other comprehensive income and
amortized into earnings in the future. The impact of lowering
the expected long-term rate of return on plan assets 0.5% for
2006 would have been an increase in expense of approximately
$1.0 million. |
|
|
|
The discount rate represents our estimate of the interest rate
at which pension benefits could be effectively settled. Assumed
discount rates are used in the measurement of the projected,
accumulated and vested benefit obligations and the service and
interest cost components of the net periodic pension cost. In
estimating that rate, Statement No. 87 requires rates of
return on high-quality fixed-income debt instruments. We utilize
a bond portfolio model that includes bonds that are rated
AA or higher with maturities that match the expected
benefit payments under the plan. The discount rate used to
determine pension expense was 5.8% for the first six months of
2006 and 6.4% for the last six months of 2006, as a result of a
remeasurement of the plan obligation related to the settlement
event discussed above, and 6.0% for 2005. The impact of lowering
the discount rate 0.5% for 2006 would have been an increase in
expense of approximately $1.4 million. |
The differences generated in changes in assumed discount rates
and returns on plan assets are amortized into earnings over a
five-year period.
For the measurement of our year-end pension obligation for 2006
(and pension expense for 2007), we increased our long-term rate
of return assumption from 8.25% to 8.50% and changed our
discount rate to 5.90%.
We also currently provide certain postretirement medical/life
insurance coverage for eligible employees. Generally, covered
employees who terminate employment after meeting eligibility
requirements are eligible for postretirement coverage for
themselves and their dependents. The salaried employee
postretirement medical/life plans are contributory, with retiree
contributions adjusted periodically, and contain other
cost-sharing features such as deductibles and coinsurance. The
postretirement medical plan for retirees who were members of the
United Mine Workers of America is not contributory. Our current
funding policy is to fund the cost of all postretirement
medical/life insurance benefits as they are paid. We account for
our other postretirement benefits in accordance with Statement
of Financial Accounting Standards No. 106,
Employers Accounting for Postretirement Benefits Other
Than Pensions, as amended by
67
Statement No. 158. Statement No. 158 requires that the
actuarially-determined funded status of the plans be recorded in
the balance sheet.
In 2005, the disposition of the Central Appalachia operations to
Magnum constituted a settlement of our postretirement benefit
obligation for which we recognized a loss of $59.2 million.
The only remaining participants in the postretirement benefit
plan have their benefits capped at current levels.
Actuarial assumptions are required to determine the amounts
reported as obligations and costs related to the postretirement
benefit plan. The discount rate assumption reflects the rates
available on high-quality fixed-income debt instruments at
year-end and is calculated in the same manner as discussed above
for the pension plan. The discount rate used to calculate the
postretirement benefit expense was 5.8% for 2006 and 6.0% for
2005. Had the discount rate been lowered by 0.5% in 2006, we
would have incurred additional expense of $0.9 million.
For the measurement of our year-end other postretirement
obligation for 2006 and postretirement expense for 2007, we
changed our discount rate to 5.9%. Because postretirement costs
for remaining participants are capped at current levels, future
changes in healthcare costs have no future effect on the plan
benefits.
On December 31, 2006, we adopted Statement No. 158,
which requires that an employer recognize the overfunded or
underfunded status of a defined benefit postretirement plan
(other than a multiemployer plan) as an asset or liability in
its balance sheet and to recognize changes in the funded status
though comprehensive income when they occur.
We provide for deferred income taxes for temporary differences
arising from differences between the financial statement and tax
basis of assets and liabilities existing at each balance sheet
date using enacted tax rates expected to be in effect when the
related taxes are expected to be paid or recovered. A valuation
allowance may be recorded to reflect the amount of future tax
benefits that management believes are not likely to be realized.
In determining the appropriate valuation allowance, we take into
account expected 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 additional valuation
allowance through income tax expense in the period such
determination is made.
Accounting Standards Issued and Not Yet Adopted
In July 2006, the FASB issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes, which we
refer to as FIN 48. FIN 48 prescribes a recognition
threshold and measurement attributes for the financial statement
recognition and measurement of a tax position taken or expected
to be taken in a tax return. While we expect there will be some
impact of recognizing tax positions previously unrecognized
under Statement of Financial Accounting Standards No. 5,
Accounting for Contingencies, we are still analyzing
FIN 48 to determine what the impact of adoption will be as
of the implementation date of January 1, 2007.
In September 2006, the FASB issued Statement of Financial
Accounting Standards No. 157, Fair Value
Measurements, which we refer to as Statement No. 157.
Statement No. 157 defines fair value, establishes a
framework for measuring fair value and expands disclosures about
fair value measurements. Statement No. 157 applies under
other accounting pronouncements that require or permit fair
value measurements.
68
Statement No. 157 is effective prospectively for fiscal
years beginning after November 15, 2007, and interim
periods within that fiscal year. We are still analyzing
Statement No. 157 to determine what the impact of adoption
will be.
|
|
ITEM 7A. |
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK. |
We manage our commodity price risk for our non-trading,
long-term coal contract portfolio through the use of long-term
coal supply agreements, rather than through the use of
derivative instruments. At December 31, 2006, based on
current expectations of production over the next three years, we
expect production available for repricing of approximately
11 million to 16 million tons in 2007, 75 million
to 85 million tons in 2008 and 110 million to
120 million tons in 2009.
We are exposed to price risk related to the value of sulfur
dioxide emission allowances that are a component of quality
adjustment provisions in many of our coal supply contracts. We
have purchased put options and entered into swap contracts to
reduce volatility in the price of sulfur dioxide emission
allowances. These contracts serve to protect us from any
possible downturn in the price of sulfur dioxide emission
allowances. The put option agreements grant us the right to sell
a certain quantity of sulfur dioxide emission allowances at a
specified price on a specified date. The swap agreements fix the
price we receive for sulfur dioxide emission allowances by
allowing us to receive a fixed sulfur dioxide allowance price
and pay a floating sulfur dioxide allowance price. We may also
purchase call options to mitigate the risk of changes in the
fair value of a contract that contains a fixed price for sulfur
dioxide emission allowances.
We are also exposed to the risk of fluctuations in cash flows
related to our purchase of diesel fuel. We enter into forward
physical purchase contracts and heating oil swaps and options to
reduce volatility in the price of diesel fuel for our
operations. The swap agreements essentially fix the price paid
for diesel fuel by requiring us to pay a fixed heating oil price
and receive a floating heating oil price. The call options
protect against increases in diesel fuel by granting us the
right to participate in increases in heating oil prices. The
changes in the floating heating oil price highly correlate to
changes in diesel fuel prices. Accordingly, the derivatives
qualify for hedge accounting and the changes in the fair value
of the derivatives are recorded through other comprehensive
income.
We are exposed to market risk associated with interest rates due
to our existing level of indebtedness. At December 31,
2006, substantially all of our outstanding debt bore interest at
fixed rates. In the past, we have utilized interest rate swap
agreements to modify the interest characteristics of our
floating-rate debt. We had no swaps outstanding as of
December 31, 2006.
The discussion below presents the sensitivity of the market
value of our financial instruments to selected changes in market
rates and prices. The range of changes reflects our view of
changes that are reasonably possible over a one-year period.
Market values are the present value of projected future cash
flows based on the market rates and prices chosen. The major
accounting policies for these instruments are described in the
notes to our consolidated financial statements.
With respect to our sulfur dioxide emission allowance put option
and swap positions, as well as our heating oil swap positions, a
change in price of the underlying products impacts our net
financial instrument position. At December 31, 2006, a $100
decrease in the price of sulfur dioxide emission allowances
would result in a $0.4 million increase in the fair value
of the financial position of our sulfur dioxide emission
69
allowance put option and swap agreements, and a $100 increase
would result in a $0.2 million increase in the fair value
of the call options. At December 31, 2006, a $0.05 per
gallon increase in the price of heating oil would result in a
$0.9 million increase in the fair value of the financial
position of our heating oil swap agreements.
|
|
ITEM 8. |
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. |
The consolidated financial statements and consolidated financial
statement schedule of Arch Coal, Inc. and subsidiaries are
included in this Annual Report on
Form 10-K
beginning on page F-1.
|
|
ITEM 9. |
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE. |
None.
|
|
ITEM 9A. |
CONTROLS AND PROCEDURES. |
We performed an evaluation under the supervision and with the
participation of our management, including our chief executive
officer and chief financial officer, of the effectiveness of the
design and operation of our disclosure controls and procedures
as of December 31, 2006. Based on that evaluation, our
management, including our chief executive officer and chief
financial officer, concluded that the disclosure controls and
procedures were effective as of such date. There were no changes
in internal control over financial reporting that occurred
during our fiscal quarter ended December 31, 2006 that have
materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
We incorporate by reference the report of independent registered
public accounting firm and managements report on internal
control over financial reporting included on pages F-2 and F-5,
respectively, of this Annual Report on
Form 10-K.
|
|
Item 9B. |
OTHER INFORMATION. |
None.
PART III
|
|
ITEM 10. |
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. |
We incorporate by reference the information under the heading
Code of Conduct appearing in the section entitled
Corporate Governance, the information under the
headings Nominees for a Three-Year Term That Will Expire
in 2010, Directors Whose Terms Will Expire in
2008, Directors Whose Term Will Expire in 2009
and Board Meetings and Committees Audit
Committee appearing in the section entitled Election
of Directors and the information appearing under the
heading Section 16(a) Beneficial Ownership Reporting
Compliance appearing in the section entitled
Ownership of Arch Coal Common Stock in our proxy
statement to be distributed to stockholders in connection with
the 2007 annual meeting. You should also see the list of our
executive officers and related information under Executive
Officers beginning on page 25.
We submitted our most recent chief executive officer
certification to the New York Stock Exchange on May 1, 2006.
70
|
|
ITEM 11. |
EXECUTIVE COMPENSATION. |
We incorporate by reference the information under the heading
Director Compensation appearing in the section
entitled Election of Directors and the information
under the headings Compensation Discussion and
Analysis, Summary Compensation Table,
Grants of Plan-Based Awards for the Year Ended
December 31, 2006, Outstanding Equity Awards at
December 31, 2006, Option Exercises and Stock
Vested for the Year Ended December 31, 2006,
Pension Benefits, Nonqualified Deferred
Compensation and Potential Payments Upon Termination
of Employment or Change-in-Control appearing in the
section entitled Compensation of Executive Officers
in our proxy statement to be distributed to stockholders in
connection with the 2007 annual meeting.
|
|
ITEM 12. |
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS. |
We incorporate by reference the information appearing under the
headings Ownership by Directors and Executive
Officers and Ownership by Others appearing in
the section entitled Ownership of Arch Coal Common
Stock in our proxy statement to be distributed to
stockholders in connection with the 2007 annual meeting.
Securities Authorized for Issuance Under Equity Compensation
Plans
The Arch Coal, Inc. 1997 Stock Incentive Plan, which has been
approved by our stockholders, is the sole plan under which we
are authorized to issue shares of our common stock to employees.
The following table shows the number of shares of common stock
to be issued upon exercise of options outstanding at
December 31, 2006, the weighted average exercise price of
those options, and the number of shares of common stock
remaining available for future issuance at December 31,
2006, excluding shares to be issued upon exercise of outstanding
options. No warrants or rights had been issued under the plan as
of December 31, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of | |
|
|
|
|
|
|
Securities Remaining | |
|
|
Number of | |
|
|
|
Available for | |
|
|
Securities to | |
|
|
|
Future Issuance | |
|
|
be Issued | |
|
Weighted-Average Exercise | |
|
Under Equity | |
|
|
Upon Exercise | |
|
Price of | |
|
Compensation Plans | |
|
|
of Outstanding | |
|
Outstanding Options, | |
|
(Excluding Securities | |
|
|
Options, Warrants | |
|
Warrants and | |
|
to be Issued | |
Plan Category |
|
and Rights | |
|
Rights | |
|
Upon Exercise) | |
|
|
| |
|
| |
|
| |
Equity compensation plans approved by security holders
|
|
|
2,273,200 |
|
|
$ |
10.5816 |
|
|
|
5,219,092 |
|
Equity compensation plans not approved by security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,273,200 |
|
|
$ |
10.5816 |
|
|
|
5,219,092 |
|
|
|
|
|
|
|
|
|
|
|
|
|
ITEM 13. |
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE. |
We incorporate by reference the information under the headings
Overview and Director Independence
appearing in the section entitled Corporate
Governance in our proxy statement to be distributed to
stockholders in connection with the 2007 annual meeting.
71
|
|
ITEM 14. |
PRINCIPAL ACCOUNTING FEES AND SERVICES. |
We incorporate by reference the information under the heading
Independent Registered Public Accounting Firm
appearing in the section entitled Additional
Information in our proxy statement to be distributed to
stockholders in connection with the 2007 annual meeting.
PART IV
|
|
ITEM 15. |
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
The consolidated financial statements and consolidated financial
statement schedule of Arch Coal, Inc. and subsidiaries are
included in this Annual Report on
Form 10-K
beginning on page F-1.
You should see the exhibit index for a list of exhibits included
in this Annual Report on
Form 10-K.
72
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements of Arch Coal, Inc. and
subsidiaries and reports of independent registered public
accounting firm follow.
Index to Consolidated Financial Statements
|
|
|
|
|
F-2 |
|
|
F-5 |
|
|
F-6 |
|
|
F-7 |
|
|
F-8 |
|
|
F-9 |
|
|
F-10 |
|
|
F-11 |
|
|
F-51 |
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of Arch Coal, Inc.
We have audited managements assessment, included in the
accompanying Managements Report on Internal Control over
Financial Reporting, that Arch Coal, Inc. (the
Company) maintained effective internal control over
financial reporting as of December 31, 2006, based on
criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria).
Arch Coal Inc.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. Our responsibility is to express an opinion
on managements assessment and an opinion on the
effectiveness of the Companys 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, evaluating
managements assessment, testing and evaluating the design
and operating effectiveness of internal control, 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 companys internal control over financial reporting is a
process designed 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 companys
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 authorization 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
Companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, 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.
In our opinion, managements assessment that Arch Coal,
Inc. maintained effective internal control over financial
reporting as of December 31, 2006, is fairly stated, in all
material respects, based on the COSO criteria. Also, in our
opinion Arch Coal, Inc. maintained, in all material respects,
effective internal control over financial reporting as of
December 31, 2006, based on the COSO criteria.
F-2
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Arch Coal, Inc. and subsidiaries
as of December 31, 2006 and 2005, and the related
consolidated statements of income, stockholders equity,
and cash flows for each of the three years in the period ended
December 31, 2006, of Arch Coal, Inc. and our report dated
February 26, 2007, expressed an unqualified opinion thereon.
|
|
|
|
|
|
St. Louis, Missouri |
|
February 26, 2007 |
F-3
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Arch Coal, Inc.
We have audited the accompanying consolidated balance sheets of
Arch Coal, Inc. and subsidiaries (the Company) as of
December 31, 2006 and 2005, and the related consolidated
statements of income, stockholders equity, and cash flows
for each of the three years in the period ended
December 31, 2006. Our audits also included the financial
statement schedule listed in item 15. These financial
statements and schedule are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements and schedule 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, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Arch Coal, Inc. and subsidiaries at
December 31, 2006 and 2005, and the consolidated results of
their operations and their cash flows for each of the three
years in the period ended December 31, 2006, in conformity
with U.S. generally accepted accounting principles. Also,
in our opinion, the related financial statement schedule, when
considered in relation to the basic financial statements taken
as a whole, present fairly, in all material respects, the
information set forth therein.
As discussed in Note 1 to the consolidated financial
statements, the Company changed its method of accounting for
share-based payments effective January 1, 2006. As
discussed in Note 1 to the consolidated financial
statements, the Company changed its method of accounting for
stripping costs effective January 1, 2006. As discussed in
Note 1 to the consolidated financial statements, the
Company changed its method of accounting for pension and other
postretirement benefits effective December 31, 2006.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of Arch Coal, Inc.s internal control over
financial reporting as of December 31, 2006, based on
criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission, and our report dated
February 26, 2007, expressed an unqualified opinion thereon.
|
|
|
|
|
|
St. Louis, Missouri |
|
February 26, 2007 |
F-4
MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL
REPORTING
The management of Arch Coal, Inc. (the Company) is
responsible for establishing and maintaining adequate internal
control over financial reporting, as defined in Securities
Exchange Act
Rule 13a-15(f).
Under the supervision and with the participation of the
Companys management, including its principal executive
officer and principal financial officer, the Company conducted
an evaluation of the effectiveness of its internal control over
financial reporting based on the criteria set forth in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on its evaluation, management concluded that
the Companys internal control over financial reporting is
effective as of December 31, 2006.
Managements assessment of the effectiveness of the
Companys internal control over financial reporting as of
December 31, 2006 has been audited by Ernst &
Young LLP, an independent registered public accounting firm, as
stated in their report, which is included on page F-2.
|
|
|
Steven F. Leer
Chairman and Chief
Executive Officer |
|
Robert J. Messey
Senior Vice President and Chief
Financial Officer |
F-5
REPORT OF MANAGEMENT
The management of Arch Coal, Inc. (the Company) is
responsible for the preparation of the consolidated financial
statements and related financial information in this annual
report. The financial statements are prepared in accordance with
accounting principles generally accepted in the United States
and necessarily include some amounts that are based on
managements informed estimates and judgments, with
appropriate consideration given to materiality.
The Company maintains a system of internal accounting controls
designed to provide reasonable assurance that financial records
are reliable for purposes of preparing financial statements and
that assets are properly accounted for and safeguarded. The
concept of reasonable assurance is based on the recognition that
the cost of a system of internal accounting controls should not
exceed the value of the benefits derived. The Company has a
professional staff of internal auditors who monitor compliance
with and assess the effectiveness of the system of internal
accounting controls.
The Audit Committee of the Board of Directors, comprised of
independent directors, meets regularly with management, the
internal auditors, and the independent auditors to discuss
matters relating to financial reporting, internal accounting
control, and the nature, extent and results of the audit effort.
The independent auditors and internal auditors have full and
free access to the Audit Committee, with and without management
present.
|
|
|
Steven F. Leer
Chairman and Chief
Executive Officer |
|
Robert J. Messey
Senior Vice President and Chief
Financial Officer |
F-6
CONSOLIDATED STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands, except per share data) | |
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
|
|
$ |
2,500,431 |
|
|
$ |
2,508,773 |
|
|
$ |
1,907,168 |
|
COSTS, EXPENSES AND OTHER
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales
|
|
|
1,909,822 |
|
|
|
2,174,007 |
|
|
|
1,638,646 |
|
|
Depreciation, depletion and amortization
|
|
|
208,354 |
|
|
|
212,301 |
|
|
|
166,322 |
|
|
Selling, general and administrative expenses
|
|
|
75,388 |
|
|
|
91,568 |
|
|
|
57,975 |
|
|
Other operating (income) expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of units of Natural Resource Partners, LP
|
|
|
|
|
|
|
|
|
|
|
(91,268 |
) |
|
|
Gain on sale of Powder River Basin assets
|
|
|
|
|
|
|
(46,547 |
) |
|
|
|
|
|
|
Gain on sale of Central Appalachian operations
|
|
|
|
|
|
|
(7,528 |
) |
|
|
|
|
|
|
Other (income) expense, net
|
|
|
(29,800 |
) |
|
|
7,115 |
|
|
|
(42,553 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
2,163,764 |
|
|
|
2,430,916 |
|
|
|
1,729,122 |
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
336,667 |
|
|
|
77,857 |
|
|
|
178,046 |
|
Interest expense, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(64,364 |
) |
|
|
(72,409 |
) |
|
|
(62,634 |
) |
|
Interest income
|
|
|
3,725 |
|
|
|
9,289 |
|
|
|
6,130 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(60,639 |
) |
|
|
(63,120 |
) |
|
|
(56,504 |
) |
Other non-operating income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses resulting from early debt extinguishment and
termination of hedge accounting for interest rate swaps
|
|
|
(4,836 |
) |
|
|
(7,740 |
) |
|
|
(9,010 |
) |
|
Other non-operating income (expense)
|
|
|
(2,611 |
) |
|
|
(3,524 |
) |
|
|
1,044 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,447 |
) |
|
|
(11,264 |
) |
|
|
(7,966 |
) |
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
268,581 |
|
|
|
3,473 |
|
|
|
113,576 |
|
Provision for (benefit from) income taxes
|
|
|
7,650 |
|
|
|
(34,650 |
) |
|
|
(130 |
) |
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
260,931 |
|
|
|
38,123 |
|
|
|
113,706 |
|
Preferred stock dividends
|
|
|
(378 |
) |
|
|
(15,579 |
) |
|
|
(7,187 |
) |
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$ |
260,553 |
|
|
$ |
22,544 |
|
|
$ |
106,519 |
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER COMMON SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per common share
|
|
$ |
1.83 |
|
|
$ |
0.18 |
|
|
$ |
0.95 |
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per common share
|
|
$ |
1.80 |
|
|
$ |
0.17 |
|
|
$ |
0.89 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-7
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(In thousands, except | |
|
|
share and per share data) | |
ASSETS |
Current assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
2,523 |
|
|
$ |
260,501 |
|
|
Trade accounts receivable
|
|
|
212,185 |
|
|
|
179,220 |
|
|
Other receivables
|
|
|
48,588 |
|
|
|
40,384 |
|
|
Inventories
|
|
|
129,826 |
|
|
|
130,720 |
|
|
Prepaid royalties
|
|
|
6,743 |
|
|
|
2,000 |
|
|
Deferred income taxes
|
|
|
51,802 |
|
|
|
88,461 |
|
|
Other
|
|
|
35,610 |
|
|
|
28,278 |
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
487,277 |
|
|
|
729,564 |
|
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
|
Coal lands and mineral rights
|
|
|
1,587,303 |
|
|
|
1,475,429 |
|
|
Plant and equipment
|
|
|
1,626,984 |
|
|
|
1,270,775 |
|
|
Deferred mine development
|
|
|
550,385 |
|
|
|
417,879 |
|
|
|
|
|
|
|
|
|
|
|
3,764,672 |
|
|
|
3,164,083 |
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(1,521,604 |
) |
|
|
(1,334,457 |
) |
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
2,243,068 |
|
|
|
1,829,626 |
|
Other assets:
|
|
|
|
|
|
|
|
|
|
Prepaid royalties
|
|
|
112,667 |
|
|
|
106,393 |
|
|
Goodwill
|
|
|
40,032 |
|
|
|
40,032 |
|
|
Deferred income taxes
|
|
|
263,759 |
|
|
|
223,856 |
|
|
Equity investments
|
|
|
80,213 |
|
|
|
8,498 |
|
|
Other
|
|
|
93,798 |
|
|
|
113,471 |
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
590,469 |
|
|
|
492,250 |
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
3,320,814 |
|
|
$ |
3,051,440 |
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
Current liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
198,875 |
|
|
$ |
256,883 |
|
|
Accrued expenses
|
|
|
190,746 |
|
|
|
245,656 |
|
|
Current portion of debt
|
|
|
51,185 |
|
|
|
10,649 |
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
440,806 |
|
|
|
513,188 |
|
Long-term debt
|
|
|
1,122,595 |
|
|
|
971,755 |
|
Accrued postretirement benefits other than pension
|
|
|
49,817 |
|
|
|
41,326 |
|
Asset retirement obligations
|
|
|
205,530 |
|
|
|
166,728 |
|
Accrued workers compensation
|
|
|
43,655 |
|
|
|
53,803 |
|
Other noncurrent liabilities
|
|
|
92,817 |
|
|
|
120,399 |
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
1,955,220 |
|
|
|
1,867,199 |
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
|
Preferred stock, $.01 par value, 10,000,000 shares
authorized, issued and outstanding 143,771 and
150,508 shares, respectively, $50 liquidation preference
|
|
|
2 |
|
|
|
2 |
|
|
Common stock, $.01 par value, authorized
260,000,000 shares, issued 142,179,254 and
142,741,368 shares, respectively
|
|
|
1,426 |
|
|
|
719 |
|
|
Paid-in capital
|
|
|
1,345,188 |
|
|
|
1,367,470 |
|
|
Retained earnings (deficit)
|
|
|
38,147 |
|
|
|
(164,181 |
) |
|
Unearned compensation
|
|
|
|
|
|
|
(9,947 |
) |
|
Less treasury stock, at cost, 168,400 shares in 2005
|
|
|
|
|
|
|
(1,190 |
) |
|
Accumulated other comprehensive loss
|
|
|
(19,169 |
) |
|
|
(8,632 |
) |
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
1,365,594 |
|
|
|
1,184,241 |
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$ |
3,320,814 |
|
|
$ |
3,051,440 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-8
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
Three Years Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated | |
|
|
|
|
|
|
|
|
|
|
Retained | |
|
|
|
Treasury | |
|
Other | |
|
|
|
|
Preferred | |
|
Common | |
|
Paid-In | |
|
Earnings | |
|
Unearned | |
|
Stock at | |
|
Comprehensive | |
|
|
|
|
Stock | |
|
Stock | |
|
Capital | |
|
(Deficit) | |
|
Compensation | |
|
Cost | |
|
Loss | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands, except share and per share data) | |
BALANCE AT January 1, 2004
|
|
$ |
29 |
|
|
$ |
536 |
|
|
$ |
988,476 |
|
|
$ |
(255,936 |
) |
|
$ |
|
|
|
$ |
(5,047 |
) |
|
$ |
(40,023 |
) |
|
$ |
688,035 |
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
113,706 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
113,706 |
|
|
|
Minimum pension liability adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,221 |
|
|
|
1,221 |
|
|
|
Unrealized gains on available-for-sale securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,081 |
|
|
|
2,081 |
|
|
|
Net amount reclassified to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,524 |
|
|
|
8,524 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
125,532 |
|
|
Dividends:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common ($0.1488 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16,856 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16,856 |
) |
|
|
Preferred ($2.50 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,187 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,187 |
) |
|
Issuance of 14,375,000 shares of common stock pursuant to
public offering
|
|
|
|
|
|
|
72 |
|
|
|
230,455 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
230,527 |
|
|
Issuance of 1,000,000 shares of common stock as
contribution to pension plan
|
|
|
|
|
|
|
5 |
|
|
|
15,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,440 |
|
|
Issuance of 298,380 shares of common stock under the stock
incentive plan restricted stock units
|
|
|
|
|
|
|
1 |
|
|
|
4,246 |
|
|
|
|
|
|
|
(4,247 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee stock-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,417 |
|
|
|
|
|
|
|
|
|
|
|
2,417 |
|
|
Issuance of 3,316,358 shares of common stock under the
stock incentive plan stock options, including income
tax benefits
|
|
|
|
|
|
|
17 |
|
|
|
41,901 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2004
|
|
|
29 |
|
|
|
631 |
|
|
|
1,280,513 |
|
|
|
(166,273 |
) |
|
|
(1,830 |
) |
|
|
(5,047 |
) |
|
|
(28,197 |
) |
|
|
1,079,826 |
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,123 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,123 |
|
|
|
Minimum pension liability adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,751 |
) |
|
|
(2,751 |
) |
|
|
Unrealized gains on available-for-sale securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,498 |
|
|
|
8,498 |
|
|
|
Unrealized gains on derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,646 |
|
|
|
22,646 |
|
|
|
Net amount reclassified to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,828 |
) |
|
|
(8,828 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
57,688 |
|
|
Dividends:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common ($0.16 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,452 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,452 |
) |
|
|
Preferred ($2.50 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,053 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,053 |
) |
|
Preferred stock conversion
|
|
|
(27 |
) |
|
|
66 |
|
|
|
9,487 |
|
|
|
(9,526 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of 546,000 shares of treasury stock as
contribution to pension plan
|
|
|
|
|
|
|
3 |
|
|
|
12,872 |
|
|
|
|
|
|
|
|
|
|
|
3,857 |
|
|
|
|
|
|
|
16,732 |
|
|
Issuance of 3,037,722 shares of common stock under the
stock incentive plan stock options, including income
tax benefits
|
|
|
|
|
|
|
15 |
|
|
|
43,564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43,579 |
|
|
Employee stock-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
140 |
|
|
|
|
|
|
|
12,781 |
|
|
|
|
|
|
|
|
|
|
|
12,921 |
|
|
Issuance of 680,092 shares of common stock under the stock
incentive plans
|
|
|
|
|
|
|
4 |
|
|
|
20,894 |
|
|
|
|
|
|
|
(20,898 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2005
|
|
|
2 |
|
|
|
719 |
|
|
|
1,367,470 |
|
|
|
(164,181 |
) |
|
|
(9,947 |
) |
|
|
(1,190 |
) |
|
|
(8,632 |
) |
|
|
1,184,241 |
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
260,931 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
260,931 |
|
|
|
Minimum pension liability adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,941 |
|
|
|
14,941 |
|
|
|
Unrealized losses on available-for-sale securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,834 |
) |
|
|
(8,834 |
) |
|
|
Unrealized losses on derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,384 |
) |
|
|
(14,384 |
) |
|
|
Net amount reclassified to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,689 |
|
|
|
9,689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
262,343 |
|
|
Dividends:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common ($0.22 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,448 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,448 |
) |
|
|
Preferred ($2.50 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(378 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(378 |
) |
|
Contribution of 168,400 shares of treasury stock and
181,600 of common stock to pension plan
|
|
|
|
|
|
|
3 |
|
|
|
15,407 |
|
|
|
|
|
|
|
|
|
|
|
1,190 |
|
|
|
|
|
|
|
16,600 |
|
|
Issuance of 126,474 shares of common stock under the stock
incentive plan restricted stock and restricted stock
units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of 31,320 shares of common stock upon conversion
of preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of two for one stock split
|
|
|
|
|
|
|
716 |
|
|
|
|
|
|
|
(716 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of 660,892 shares of common stock under the stock
incentive plan stock options
|
|
|
|
|
|
|
4 |
|
|
|
7,039 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,043 |
|
|
Employee stock-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
9,080 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,080 |
|
|
Purchase of 1,562,400 shares of common stock under stock
repurchase program
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(43,877 |
) |
|
|
|
|
|
|
(43,877 |
) |
|
Retirement of treasury stock
|
|
|
|
|
|
|
(16 |
) |
|
|
(43,861 |
) |
|
|
|
|
|
|
|
|
|
|
43,877 |
|
|
|
|
|
|
|
|
|
|
Effect of adoption of EITF 04-6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(26,061 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(26,061 |
) |
|
Effect of adoption of Statement No. 158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11,949 |
) |
|
|
(11,949 |
) |
|
Effect of adoption of Statement No. 123R
|
|
|
|
|
|
|
|
|
|
|
(9,947 |
) |
|
|
|
|
|
|
9,947 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2006
|
|
$ |
2 |
|
|
$ |
1,426 |
|
|
$ |
1,345,188 |
|
|
$ |
38,147 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(19,169 |
) |
|
$ |
1,365,594 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-9
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
260,931 |
|
|
$ |
38,123 |
|
|
$ |
113,706 |
|
Adjustments to reconcile net income to cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
208,354 |
|
|
|
212,301 |
|
|
|
166,322 |
|
|
Prepaid royalties expensed
|
|
|
9,045 |
|
|
|
14,252 |
|
|
|
13,889 |
|
|
Gain on sale of units of Natural Resource Partners, LP
|
|
|
|
|
|
|
|
|
|
|
(91,268 |
) |
|
Net (gain) loss on dispositions of property, plant and
equipment
|
|
|
649 |
|
|
|
(82,168 |
) |
|
|
(6,668 |
) |
|
Gain on investment in Knight Hawk Holdings, LLC
|
|
|
(10,309 |
) |
|
|
|
|
|
|
|
|
|
Employee stock-based compensation
|
|
|
9,080 |
|
|
|
12,937 |
|
|
|
|
|
|
Net distributions from equity investments
|
|
|
|
|
|
|
|
|
|
|
17,678 |
|
|
Other non-operating expense
|
|
|
7,447 |
|
|
|
11,264 |
|
|
|
7,966 |
|
|
Changes in operating assets and liabilities (see Note 24)
|
|
|
(166,935 |
) |
|
|
28,377 |
|
|
|
(54,725 |
) |
|
Other
|
|
|
(10,160 |
) |
|
|
19,521 |
|
|
|
(18,172 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
308,102 |
|
|
|
254,607 |
|
|
|
148,728 |
|
INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(623,187 |
) |
|
|
(357,142 |
) |
|
|
(292,605 |
) |
|
Payments for acquisitions, net of cash acquired
|
|
|
|
|
|
|
|
|
|
|
(387,751 |
) |
|
Proceeds from dispositions of property, plant and equipment
|
|
|
777 |
|
|
|
117,048 |
|
|
|
7,428 |
|
|
Proceeds from sale of units of Natural Resource Partners, LP
|
|
|
|
|
|
|
|
|
|
|
111,447 |
|
|
Additions to prepaid royalties
|
|
|
(20,062 |
) |
|
|
(28,164 |
) |
|
|
(33,813 |
) |
|
Advances to affiliates/purchases of investments
|
|
|
(45,533 |
) |
|
|
(23,285 |
) |
|
|
(2,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities
|
|
|
(688,005 |
) |
|
|
(291,543 |
) |
|
|
(597,294 |
) |
FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net borrowings (payments) on revolver and lines of credit
|
|
|
192,300 |
|
|
|
(25,000 |
) |
|
|
25,000 |
|
|
Net borrowings (payments) on long-term debt
|
|
|
442 |
|
|
|
(2,376 |
) |
|
|
(302 |
) |
|
Proceeds from issuance of senior notes
|
|
|
|
|
|
|
|
|
|
|
261,875 |
|
|
Debt financing costs
|
|
|
(2,171 |
) |
|
|
(2,662 |
) |
|
|
(12,806 |
) |
|
Dividends paid
|
|
|
(31,815 |
) |
|
|
(27,639 |
) |
|
|
(24,043 |
) |
|
Purchases of treasury stock
|
|
|
(43,876 |
) |
|
|
|
|
|
|
|
|
|
Issuance of common stock under incentive plans and proceeds from
sale of common stock
|
|
|
7,045 |
|
|
|
31,947 |
|
|
|
267,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) financing activities
|
|
|
121,925 |
|
|
|
(25,730 |
) |
|
|
517,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents
|
|
|
(257,978 |
) |
|
|
(62,666 |
) |
|
|
68,626 |
|
|
|
Cash and cash equivalents, beginning of year
|
|
|
260,501 |
|
|
|
323,167 |
|
|
|
254,541 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of year
|
|
$ |
2,523 |
|
|
$ |
260,501 |
|
|
$ |
323,167 |
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOW INFORMATION:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for interest
|
|
$ |
59,116 |
|
|
$ |
69,839 |
|
|
$ |
53,558 |
|
|
Cash paid (received) during the year for income taxes
|
|
$ |
(8,921 |
) |
|
$ |
(5,518 |
) |
|
$ |
13,350 |
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The consolidated financial statements include the accounts of
Arch Coal, Inc. and its subsidiaries and controlled entities
(the Company). The Companys primary business
is the production of steam and metallurgical coal from surface
and underground mines throughout the United States, for sale to
utility, industrial and export markets. The Companys mines
are located in southern West Virginia, eastern Kentucky,
Virginia, Wyoming, Colorado and Utah. All subsidiaries (except
as noted below) are wholly-owned. Intercompany transactions and
accounts have been eliminated in consolidation.
On May 15, 2006, the Company completed a two-for-one stock
split of the Companys common stock in the form of a 100%
stock dividend. All share and per share amounts for the years
ended December 31, 2005 and 2004 have been retroactively
restated for the split.
The Company owns a 99% ownership interest in a joint venture
named Arch Western Resources, LLC (Arch Western)
which operates coal mines in Wyoming, Colorado and Utah. The
Company also acts as the managing member of Arch Western.
As of and for the period ended July 31, 2004, the
membership interests in the Utah coal operations, Canyon Fuel
Company, LLC (Canyon Fuel), were owned 65% by Arch
Western and 35% by a subsidiary of ITOCHU Corporation. Through
July 31, 2004, the Companys 65% ownership of Canyon
Fuel was accounted for on the equity method in the consolidated
financial statements as a result of certain super-majority
voting rights in the joint venture agreement. Income from Canyon
Fuel through July 31, 2004 is reflected in the accompanying
Consolidated Statements of Income in other (income) expense, net
(see additional discussion in Note 5,
Investments). On July 31, 2004, the Company
acquired the remaining 35% of Canyon Fuel. See Note 2,
Business Combinations for further discussion.
On December 31, 2005, the Company entered into a Purchase
and Sale Agreement (the Purchase Agreement) with
Magnum Coal Company (Magnum). Pursuant to the
Purchase Agreement, the Company sold the stock of four of its
active Central Appalachian mining operations. See further
discussion in Note 3, Dispositions.
|
|
|
Accounting Pronouncements
Adopted |
On December 31 2006, the Company adopted Statement of
Financial Accounting Standards No. 158, Employers
Accounting for Defined Benefit Pension and Other Postretirement
Plans (Statement No. 158). Statement
No. 158 requires that an employer recognize the overfunded
or underfunded status of a defined benefit postretirement plan
(other than a multiemployer plan) and other postemployment
benefits determined on an actuarial basis as an asset or
liability in its balance sheet and to recognize changes in the
funded status though comprehensive income when they occur.
Statement No. 158 also requires an employer to measure the
funded status of a plan as of the date of its year-end balance
sheet. See Notes 13 and 14 for additional disclosures
relating to these obligations.
F-11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table reflects the incremental effect of applying
Statement No. 158 on individual line items in the
accompanying Consolidated Balance Sheet at December 31,
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
|
|
December 31, 2006 |
|
|
Balances Prior to |
|
|
|
Balances After |
|
|
Adoption of |
|
|
|
Adoption of |
|
|
Statement No. 158 |
|
Adjustments |
|
Statement No. 158 |
|
|
|
|
|
|
|
|
|
(In thousands) |
Other assets noncurrent
|
|
$ |
15,427 |
|
|
$ |
(15,427 |
) |
|
$ |
|
|
Deferred income taxes noncurrent
|
|
|
257,296 |
|
|
|
6,463 |
|
|
|
263,759 |
|
Total assets
|
|
|
3,329,778 |
|
|
|
(8,964 |
) |
|
|
3,320,814 |
|
Accrued benefit liability current
|
|
|
5,483 |
|
|
|
(973 |
) |
|
|
4,510 |
|
Accrued postretirement benefits other than pension
noncurrent
|
|
|
42,567 |
|
|
|
7,250 |
|
|
|
49,817 |
|
Accrued benefit liability noncurrent
|
|
|
36,415 |
|
|
|
(20,742 |
) |
|
|
15,673 |
|
Total liabilities
|
|
|
1,952,235 |
|
|
|
2,985 |
|
|
|
1,955,220 |
|
Accumulated other comprehensive loss
|
|
|
(7,220 |
) |
|
|
(11,949 |
) |
|
|
(19,169 |
) |
Total stockholders equity
|
|
|
1,377,543 |
|
|
|
(11,949 |
) |
|
|
1,365,594 |
|
On January 1, 2006, the Company adopted the Emerging Issues
Task Force Issue
No. 04-6,
Accounting for Stripping Costs in the Mining Industry
(EITF 04-6).
EITF 04-6 applies
to stripping costs incurred in the production phase of a mine
for the removal of overburden or waste materials for the purpose
of obtaining access to coal that will be extracted. Under
EITF 04-6,
stripping costs incurred during the production phase of the mine
are variable production costs that are included in the cost of
inventory extracted during the period the stripping costs are
incurred. Historically, the Company had classified stripping
costs associated with the tons of coal uncovered and not yet
extracted (pit inventory) at its surface mining operations as
coal inventory. The effect of adopting
EITF 04-6 was a
reduction of $40.7 million and $2.0 million of
inventory and deferred development costs, respectively, with a
corresponding decrease to retained earnings, net of tax, of
$26.1 million. This accounting change creates volatility in
the Companys results of operations, as cost increases or
decreases related to fluctuations in pit inventory can only be
attributed to tons extracted from the pit. During the year ended
December 31, 2006, decreases in pit inventory resulted in
net income that was $10.6 million higher than it would have
been under the Companys previous methodology of accounting
for pit inventory, an impact of $0.07 per diluted share.
As of January 1, 2006, the Company adopted Statement of
Financial Accounting Standards No. 123 (revised 2004),
Share-Based Payment (Statement
No. 123R), which requires all public companies to
measure compensation cost in the statement of income for all
share-based payments (including employee stock options) at fair
value. Prior to the adoption of Statement No. 123R, the
Company accounted for its stock options under the intrinsic
value method prescribed by Accounting Principles Board Opinion
No. 25, Accounting for Stock Issued to Employees
(APB 25) and related interpretations, as
permitted by Statement of Financial Accounting Standards
No. 123, Accounting for Stock-Based Compensation, as
amended by Statement of Financial Accounting Standards
No. 148, Accounting for Stock-Based
Compensation Transition and Disclosure
(Statement No. 123). The Company adopted
Statement No. 123R using the modified-prospective method.
Under this method, compensation cost for share-based payments to
employees is based on their grant-date fair value from the
beginning of the fiscal period in which the recognition
provisions are first applied. Measurement and recognition of
compensation cost for awards that were
F-12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
granted prior to, but not vested as of, the date Statement
No. 123R was adopted are based on the same estimate of the
grant-date fair value and the same recognition method used
previously under Statement No. 123. The Company uses the
Black-Scholes option pricing model for its options and a lattice
model for share-based payments with performance and market
conditions to determine the fair value. Statement No. 123R
also requires the benefits of tax deductions in excess of
recognized compensation cost to be reported as a financing cash
flow, rather than as an operating cash flow. The effects of
adoption on retained earnings, net income and the statement of
cash flows for the year ended December 31, 2006 were
insignificant. See further discussion in Note 17,
Stock Based Compensation and Other Incentive Plans.
Prior to the adoption of Statement No. 123R, the Company
accounted for its stock options under the intrinsic value method
prescribed by APB 25 and related interpretations as
permitted by Statement No. 123. The following table
reflects the pro forma disclosure of net income available to
common stockholders and earnings per common share as required by
Statement No. 123. Had compensation expense for stock
option grants been determined based on the fair value at the
grant dates for years ended December 31, 2005 and 2004, the
Companys net income available to common stockholders and
earnings per common share would have been as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended | |
|
|
December 31 | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
|
(In thousands, except | |
|
|
per share data) | |
Net income available to common stockholders, as reported
|
|
$ |
22,544 |
|
|
$ |
106,519 |
|
Add:
|
|
|
|
|
|
|
|
|
|
Stock-based employee compensation included in reported net
income, net of related tax effects
|
|
|
12,768 |
|
|
|
1,837 |
|
Deduct:
|
|
|
|
|
|
|
|
|
|
Total stock-based employee compensation expense determined under
fair value based method for all awards, net of related tax
effects
|
|
|
(16,894 |
) |
|
|
(7,302 |
) |
|
|
|
|
|
|
|
Pro forma net income available to common stockholders
|
|
$ |
18,418 |
|
|
$ |
101,054 |
|
|
|
|
|
|
|
|
Earnings per common share:
|
|
|
|
|
|
|
|
|
Basic earnings per common share as reported
|
|
$ |
0.18 |
|
|
$ |
0.95 |
|
Basic earnings per common share pro forma
|
|
|
0.14 |
|
|
|
0.90 |
|
Diluted earnings per common share as reported
|
|
|
0.17 |
|
|
|
0.89 |
|
Diluted earnings per common share pro forma
|
|
|
0.14 |
|
|
|
0.85 |
|
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States
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. Actual results could
differ from those estimates.
F-13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
Cash and Cash
Equivalents |
Cash and cash equivalents are stated at cost. Cash equivalents
consist of highly-liquid investments with an original maturity
of three months or less when purchased.
|
|
|
Allowance for
Uncollectible Receivables |
The Company maintains allowances to reflect the amounts of its
trade accounts receivable and other receivables which are not
expected to be collected, based on past collection history, the
economic environment and specified risks identified in the
receivables portfolio. Receivables are considered past due if
the full payment is not received by the contractual due date.
Allowances recorded at December 31, 2006 and 2005 were
$3.2 million and $1.8 million, respectively.
Coal and supplies inventories are valued at the lower of average
cost or market. Coal inventory costs include labor, supplies,
equipment costs and operating overhead.
Investments and ownership interests are accounted for under the
equity method of accounting if the Company has the ability to
exercise significant influence, but not control, over the
entity. The Company reflects its share of the entitys
income in other (income) expense, net in its Consolidated
Statements of Income. Marketable equity securities held by the
Company that do not qualify for equity method accounting are
classified as available-for-sale and are recorded at their fair
value on the balance sheet with a corresponding entry to other
comprehensive income.
Rights to leased coal lands are often acquired through royalty
payments. Where royalty payments represent prepayments
recoupable against production, they are recorded as a prepaid
asset, and amounts expected to be recouped within one year are
classified as a current asset. As mining occurs on these leases,
the prepayment is charged to cost of coal sales.
Acquisition costs allocated to coal supply agreements (sales
contracts) are capitalized and amortized on the basis of coal to
be shipped over the term of the contract. Value is allocated to
coal supply agreements based on discounted cash flows
attributable to the difference between the above or below-market
contract price and the then-prevailing market price. The net
book value of the Companys above-market coal supply
agreements was $3.8 million and $4.8 million at
December 31, 2006 and 2005, respectively. These amounts are
recorded in other assets in the accompanying Consolidated
Balance Sheets. The net book value of all below-market coal
supply agreements was $3.2 million and $15.0 million
at December 31, 2006 and 2005, respectively. This amount is
recorded in other noncurrent liabilities in the accompanying
Consolidated Balance Sheets. Amortization expense on all
above-market coal supply agreements was $1.0 million,
$8.0 million and $3.8 million in 2006, 2005 and 2004,
respectively.
F-14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Amortization income on all below-market coal supply agreements
was $11.8 million, $16.0 million and $4.1 million
in 2006, 2005 and 2004, respectively.
Costs related to locating coal deposits and evaluating the
economic viability of such deposits are expensed as incurred.
|
|
|
Property, Plant and
Equipment |
Plant and equipment are recorded at cost. Interest costs
applicable to major asset additions are capitalized during the
construction period. During the years ended December 31,
2006, 2005 and 2004, interest costs of $14.8 million,
$4.2 million and $0.2 million were capitalized.
Expenditures which extend the useful lives of existing plant and
equipment or increase the productivity of the asset are
capitalized. The cost of maintenance and repairs that do not
extend the useful life or increase the productivity of the asset
are expensed as incurred. Plant and equipment are depreciated
principally on the straight-line method over the estimated
useful lives of the assets, which generally range from three to
30 years, except for preparation plants and loadouts.
Preparation plants and loadouts are depreciated using the
units-of-production
method over the estimated recoverable reserves, subject to a
minimum level of depreciation.
|
|
|
Deferred Mine
Development |
Costs of developing new mines or significantly expanding the
capacity of existing mines are capitalized and amortized using
the units-of-production
method over the estimated recoverable reserves that are
associated with the property being benefited. Additionally, the
asset retirement obligation asset has been recorded as a
component of deferred mine development.
|
|
|
Coal Lands and Mineral
Rights |
A significant portion of the Companys coal reserves are
controlled through leasing arrangements. Amounts paid to acquire
such reserves are capitalized and depleted over the life of
those reserves that are proven and probable. Coal lease rights
are depleted using the
units-of-production
method, and the rights are assumed to have no residual value.
The leases are generally long-term in nature (original terms
range from 10 to 50 years), and substantially all of the
leases contain provisions that allow for automatic extension of
the lease term as long as mining continues. The net book value
of the Companys leased coal interests was
$954.2 million and $908.7 million at December 31,
2006 and 2005, respectively.
The Company has entered into various non-cancelable royalty
lease agreements and federal lease bonus payments under which
future minimum payments are due. On September 22, 2004, the
Company was the successful bidder in a federal auction of
certain mining rights in the
5,084-acre Little
Thunder tract in the Powder River Basin of Wyoming. The
Companys lease bonus bid amounted to $611.0 million
for the tract payable in five equal installments. The Company
paid the first installment of $122.2 million in 2004 and
the second in 2006, with the remaining three annual payments to
be paid in fiscal years 2007 through 2009. These payments are
capitalized as the cost of the underlying mineral reserves.
F-15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
If facts and circumstances suggest that a long-lived asset may
be impaired, the carrying value is reviewed for recoverability.
If this review indicates that the carrying amount of the asset
will not be recoverable through projected undiscounted cash
flows related to the asset over its remaining life, then an
impairment loss is recognized by reducing the carrying value of
the asset to its fair value.
Goodwill represents the excess of purchase price and related
costs over the value assigned to the net tangible and
identifiable intangible assets of businesses acquired. In
accordance with Statement of Financial Accounting Standards
No. 142, Goodwill and Other Intangible Assets
(Statement No. 142), goodwill is not
amortized but is tested for impairment annually, or if certain
circumstances indicate a possible impairment may exist.
Impairment testing is performed at a reporting unit level. An
impairment loss generally would be recognized when the carrying
amount of the reporting unit exceeds the fair value of the
reporting unit, with the fair value of the reporting unit
determined using a discounted cash flow analysis.
The Company capitalizes costs incurred in connection with
borrowings or establishment of credit facilities and issuance of
debt securities. These costs are amortized as an adjustment to
interest expense over the life of the borrowing or term of the
credit facility using the interest method. Deferred financing
costs were $24.8 million and $27.4 million at
December 31, 2006 and 2005, respectively. Amounts
classified as current were $4.6 million and
$5.1 million at December 31, 2006 and 2005,
respectively.
Coal sales revenues include sales to customers of coal produced
at Company operations and coal purchased from other companies.
The Company recognizes revenue from coal sales at the time risk
of loss passes to the customer at the Companys mine
locations at contracted amounts. Transportation costs are
included in cost of coal sales and amounts billed by the Company
to its customers for transportation are included in coal sales.
|
|
|
Other Operating (Income)/
Expense, net |
Other operating (income) expense, net in the accompanying
Consolidated Statements of Income reflects income and expense
from sources other than coal sales, including royalties earned
from properties leased to third parties and income from equity
investments; gains and losses from dispositions of long-term
assets; and unrealized gains and losses on derivatives that do
not qualify for hedge accounting.
|
|
|
Asset Retirement
Obligations |
The Companys legal obligations associated with the
retirement of long-lived assets are recognized at fair value at
the time the obligations are incurred. Obligations are incurred
at the time development of a mine commences for underground and
surface mines or construction begins for support facilities,
refuse areas and slurry ponds. The obligations fair value
is determined using discounted cash flow techniques and is
accreted over time to its expected settlement value. Upon
initial recognition of a liability, a
F-16
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
corresponding amount is capitalized as part of the carrying
amount of the related long-lived asset. Amortization of the
related asset is recorded on a
units-of-production
basis over the mines estimated recoverable reserves. See
additional discussion in Note 12, Asset Retirement
Obligations.
|
|
|
Derivative Financial
Instruments |
The Company uses derivative financial instruments to manage
exposures to commodity prices and interest rates. Derivative
financial instruments are recognized in the balance sheet at
fair value. Changes in fair value are recognized in earnings if
they are not eligible for hedge accounting or in other
comprehensive income if they qualify for cash flow hedge
accounting. Amounts in other comprehensive income are
reclassified to earnings when the hedged transaction affects
earnings. Any ineffective portion of a cash flow hedges
change in fair value is recognized immediately in earnings. The
amount of ineffectiveness recognized in other (income) expense,
net in the accompanying Consolidated Statements of Income for
the years ended December 31, 2005 and 2004 was
$1.0 million and $0.2 million, respectively.
Ineffectiveness was insignificant for the year ended
December 31, 2006.
The Company formally documents all relationships between hedging
instruments and hedged items, as well as its risk management
objectives for undertaking various hedge transactions. The
Company evaluates the effectiveness of its hedging relationships
both at the hedge inception and on an ongoing basis.
Deferred income taxes are provided for temporary differences
arising from differences between the financial statement and tax
basis of assets and liabilities existing at each balance sheet
date using enacted tax rates expected to be in effect when the
related taxes are expected to be paid or recovered.
|
|
|
Accounting Standards
Issued and Not Yet Adopted |
In February 2006, the FASB issued Statement of Financial
Accounting Standards No. 155, Accounting for Certain
Hybrid Financial Instruments (Statement
No. 155). Statement No. 155 simplifies the
accounting for certain hybrid financial instruments by
permitting fair value remeasurement for any hybrid financial
instrument that contains an embedded derivative that otherwise
would require bifurcation. Statement No. 155 also clarifies and
amends certain other provisions of Statement of Financial
Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities and Statement of
Financial Accounting Standards No. 140, Accounting for
Transfers and Servicing of Financial Assets and Extinguishment
of Liabilities. Statement No. 155 is effective for all
financial instruments acquired, issued, or subject to a
remeasurement event occurring after January 1, 2007. The
Company does not expect the adoption of this statement to have a
material impact on its financial statements.
In July 2006, the FASB issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes
(FIN 48). FIN 48 prescribes a
recognition threshold and measurement attributes for the
financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return.
FIN 48 is effective for fiscal years beginning after
December 15, 2006. While the Company expects there will be
some impact of recognizing tax positions previously unrecognized
under Statement of Financial
F-17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Accounting Standards No. 5, Accounting for
Contingencies, the Company is still analyzing FIN 48 to
determine what the impact of adoption will be.
In September 2006, the FASB issued Statement of Financial
Accounting Standards No. 157, Fair Value Measurements
(Statement No. 157). Statement No. 157
defines fair value, establishes a framework for measuring fair
value and expands disclosures about fair value measurements and
applies under other accounting pronouncements that require or
permit fair value measurements. Statement No. 157 is
effective prospectively for fiscal years beginning after
November 15, 2007, and interim periods within that fiscal
year. The Company is still analyzing Statement No. 157 to
determine what the impact of adoption will be.
Certain amounts in the prior years financial statements
have been reclassified to conform with the classifications in
the current years financial statements with no effect on
previously-reported net income, stockholders equity or
statements of cash flows.
|
|
|
Canyon Fuel 35%
Acquisition |
On July 31, 2004, the Company purchased the 35% interest in
Canyon Fuel that it did not own from ITOCHU Corporation. The
purchase price, including related costs and fees, of
$112.2 million was funded with cash of $90.2 million
and a five-year, $22.0 million non-interest bearing note.
Net of cash acquired, the fair value of the transaction totaled
$97.4 million. As a result of the acquisition, the Company
owns all of the ownership interests of Canyon Fuel and
consolidates Canyon Fuel in its financial statements. The
results of operations of the Canyon Fuel mines are included in
the Companys Western Bituminous segment.
The purchase accounting allocation related to the acquisition
has been recorded in the accompanying consolidated financial
statements as of, and for the period subsequent to,
July 31, 2004. The following table summarizes the estimated
fair values of the assets acquired and the liabilities assumed
at the date of acquisition (in thousands):
|
|
|
|
|
Accounts receivable
|
|
$ |
7,432 |
|
Materials and supplies
|
|
|
3,751 |
|
Coal inventory
|
|
|
7,434 |
|
Other current assets
|
|
|
6,466 |
|
Property, plant, equipment and mine development
|
|
|
125,881 |
|
Accounts payable and accrued expenses
|
|
|
(10,379 |
) |
Coal supply agreements
|
|
|
(33,378 |
) |
Other noncurrent assets and liabilities, net
|
|
|
(9,823 |
) |
|
|
|
|
Total purchase price, net of cash received of $11.0 million
|
|
$ |
97,384 |
|
|
|
|
|
Amounts allocated to coal supply agreements noted in the table
above represent the liability established for the net
below-market coal supply agreements to be amortized over the
remaining terms of the contracts. The liability is classified as
an other noncurrent liability on the accompanying Consolidated
Balance Sheets. See Note 1, Accounting Policies
for amortization related to coal supply agreements.
F-18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
On August 20, 2004, the Company acquired (1) Vulcan
Coal Holdings, L.L.C., which owned all of the common equity of
Triton Coal Company, LLC (Triton), and (2) all
of the preferred units of Triton for a purchase price of
$382.1 million, including transaction costs and working
capital adjustments. In 2003, Triton was the nations sixth
largest coal producer and operated two mines in the Powder River
Basin: North Rochelle and Buckskin. Following the consummation
of the transaction, the Company completed an agreement to sell
Tritons Buckskin mine to Kiewit Mining Acquisition Company
(Kiewit). The net sales price for this second
transaction was $73.1 million. The total purchase price,
including related costs and fees, was funded with cash on hand,
including the proceeds from the Buckskin sale,
$22.0 million in borrowings under the Companys
existing revolving credit facility and a $100.0 million
term loan at its Arch Western Resources subsidiary. Upon
acquisition, the Company integrated the North Rochelle mine into
its existing Black Thunder mine in the Powder River Basin.
The purchase accounting allocations related to the acquisition
have been recorded in the accompanying consolidated financial
statements as of, and for the periods subsequent to,
August 20, 2004. The following table summarizes the
estimated fair values of the assets acquired and the liabilities
assumed at the date of acquisition (in thousands):
|
|
|
|
|
Accounts receivable
|
|
$ |
14,233 |
|
Materials and supplies
|
|
|
4,161 |
|
Coal inventory
|
|
|
4,875 |
|
Other current assets
|
|
|
2,200 |
|
Property, plant, equipment and mine development
|
|
|
325,194 |
|
Coal supply agreements
|
|
|
8,486 |
|
Goodwill
|
|
|
40,032 |
|
Accounts payable and accrued expenses
|
|
|
(72,326 |
) |
Other noncurrent assets and liabilities, net
|
|
|
(22,135 |
) |
|
|
|
|
Total purchase price, net of cash received of $0.4 million
|
|
$ |
304,720 |
|
|
|
|
|
Amounts allocated to coal supply agreements noted in the table
above represent the value attributed to the net above-market
coal supply agreements to be amortized over the remaining terms
of the contracts. See Note 1, Accounting
Policies for amortization related to coal supply
agreements.
The goodwill amount above arose due to the delay in time between
the execution of the acquisition agreement and the date of
closing because of the Federal Trade Commissions lawsuit
to block the acquisition and is attributable to the loss of
value from the tons mined during this period. Of the amount
allocated to goodwill above, $34.4 million was deductible
for income tax purposes.
F-19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
Pro Forma Financial
Information |
The following unaudited pro forma financial information for the
year ended December 31, 2004 presents the combined results
of operations of the Company, the remaining Canyon Fuel interest
acquired from ITOCHU Corporation and the North Rochelle
operations acquired from Triton on a pro forma basis, as though
the purchases had occurred as of the beginning of the year. The
pro forma financial information does not necessarily reflect the
results of operations that would have occurred had the Company
and the operations acquired from Canyon Fuel and Triton
constituted a single entity during those periods (in thousands,
except per share data):
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
As reported
|
|
$ |
1,907,168 |
|
|
Pro forma
|
|
|
2,156,958 |
|
Net income:
|
|
|
|
|
|
As reported
|
|
|
113,706 |
|
|
Pro forma
|
|
|
103,933 |
|
Net income available to common stockholders:
|
|
|
|
|
|
As reported
|
|
|
106,519 |
|
|
Pro forma
|
|
|
96,746 |
|
Basic earnings per common share:
|
|
|
|
|
|
As reported
|
|
|
0.95 |
|
|
Pro forma
|
|
|
0.87 |
|
Diluted earnings per common share:
|
|
|
|
|
|
As reported
|
|
|
0.89 |
|
|
Pro forma
|
|
|
0.82 |
|
On December 31, 2005, the Company sold the stock of three
subsidiaries and their four associated mining operations and
coal reserves in Central Appalachia to Magnum. The three
subsidiaries were Hobet Mining, Apogee Coal Company and Catenary
Coal Company, which included the Hobet 21, Arch of West
Virginia, Samples and Campbells Creek mining operations.
Included in the sale were a total of 455.0 million tons of
reserves. For the years ended December 31, 2005 and 2004,
collectively, these subsidiaries sold 12.7 million and
14.0 million tons of coal, had revenues of
$509.8 million and $475.1 million and incurred losses
from operations of $8.3 million and $3.8 million,
respectively. As a result of the sale, Magnum acquired all of
the assets and liabilities of the subsidiaries including various
employee liabilities of idle union properties whose former
employees were signatory to a United Mine Workers of America
(UMWA) contract.
F-20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The net book value of the subsidiaries sold was a net liability
of $123.1 million, consisting of the following (in
thousands):
|
|
|
|
|
|
Assets
|
|
|
|
|
Current assets
|
|
$ |
87,300 |
|
Property, plant, equipment
|
|
|
309,100 |
|
Other assets
|
|
|
3,800 |
|
|
|
|
|
|
Total assets
|
|
|
400,200 |
|
|
Liabilities |
Current liabilities
|
|
|
77,700 |
|
Accrued postretirement benefits other than pension
|
|
|
367,800 |
|
Accrued workers compensation
|
|
|
15,400 |
|
Reclamation and mine closure
|
|
|
31,200 |
|
Other noncurrent liabilities
|
|
|
31,200 |
|
|
|
|
|
|
Total liabilities
|
|
|
523,300 |
|
|
|
|
|
Net liabilities
|
|
$ |
123,100 |
|
|
|
|
|
The Company recognized a $7.5 million net gain in the
fourth quarter of 2005 in conjunction with this transaction. The
gain recorded by the Company included accrued losses of
$65.4 million on firm commitments to purchase coal in 2006
to supply below-market sales contracts, which could no longer be
sourced from the Companys operations as a result of the
transaction. As the Company shipped coal to satisfy the
below-market contracts, the liability was relieved against cost
of coal sales. In addition, the Company recognized expenses of
$8.7 million during 2006 related to the finalization of
working capital adjustments to the purchase price, adjustments
to estimated volumes associated with sales contracts acquired by
Magnum and expense related to settlement accounting for pension
plan withdrawals. See further discussion of the settlement in
Note 14, Employee Benefit Plans.
In accordance with the terms of the transaction, the Company
paid $50.2 million to Magnum in 2006 to purchase coal and
to offset certain ongoing operating expenses of Magnum. In
addition, the Company was required under the agreement to manage
working capital for the operations sold to Magnum for a period
of time after the transaction. As of December 31, 2006, the
Company had a current receivable due from Magnum of
$8.5 million, included in other receivables on the
accompanying Consolidated Balance Sheets.
In accordance with the Purchase Agreement, the Company agreed to
various guarantees which are described in Note 22,
Guarantees.
On December 30, 2005, the Company completed a reserve swap
with Peabody Energy Corp. (Peabody) and sold to
Peabody a rail spur, rail loadout and an idle office complex
located in the Powder River Basin for a purchase price of
$84.6 million. In the reserve swap, the Company exchanged
60.0 million tons of coal reserves for a similar block of
60.0 million tons of coal reserves with Peabody in order to
facilitate more efficient mine plans for both companies. Due to
the similarity of the exchanged reserves, the reserves received
were recorded at the net book value of the reserves transferred.
In conjunction with the transactions, the Company will continue
to lease the rail spur and loadout and office facilities through
F-21
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
2008 while it mines adjacent reserves. The Company recognized a
gain of $46.5 million on the transaction, after the
deferral of $7.0 million of the gain, equal to the present
value of the lease payments. The deferred gain will be
recognized over the term of the lease. See further discussion in
Note 20, Leases.
During the years ended December 31, 2006, 2005 and 2004,
gains (losses) on other dispositions of property, plant and
equipment were $(0.6) million, $28.2 million and
$6.7 million, respectively. Included in the gain for 2005
was a gain of $9.0 million on the sale of surface land
rights at the Companys Central Appalachian operations in
West Virginia, a gain of $6.3 million on the assignment of
the Companys rights and obligations on several parcels of
land and a gain of $7.3 million on the sale of a dragline.
Included in the gain for 2004 was the sale of the Companys
rights and obligations on a parcel of land to a third party
resulting in a gain of $5.8 million.
|
|
4. |
Accumulated Other Comprehensive Income |
Other comprehensive income items under Statement of Financial
Accounting Standards No. 130, Reporting Comprehensive
Income, are transactions recorded in stockholders
equity during the year, excluding net income and transactions
with stockholders. Following are the items included in
accumulated other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension, | |
|
|
|
|
|
|
|
|
|
|
Postretirement | |
|
|
|
|
|
|
|
|
Minimum | |
|
and Other | |
|
|
|
Accumulated | |
|
|
|
|
Pension | |
|
Post- | |
|
|
|
Other | |
|
|
Financial | |
|
Liability | |
|
Employment | |
|
Available-for- | |
|
Comprehensive | |
|
|
Derivatives | |
|
Adjustments | |
|
Benefits | |
|
Sale Securities | |
|
Loss | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Balance January 1, 2004
|
|
$ |
(24,159 |
) |
|
$ |
(15,864 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(40,023 |
) |
2004 activity, before tax
|
|
|
13,974 |
|
|
|
2,002 |
|
|
|
|
|
|
|
3,411 |
|
|
|
19,387 |
|
2004 activity, tax effect
|
|
|
(5,450 |
) |
|
|
(781 |
) |
|
|
|
|
|
|
(1,330 |
) |
|
|
(7,561 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2004
|
|
|
(15,635 |
) |
|
|
(14,643 |
) |
|
|
|
|
|
|
2,081 |
|
|
|
(28,197 |
) |
2005 activity, before tax
|
|
|
22,652 |
|
|
|
(4,510 |
) |
|
|
|
|
|
|
13,931 |
|
|
|
32,073 |
|
2005 activity, tax effect
|
|
|
(8,834 |
) |
|
|
1,759 |
|
|
|
|
|
|
|
(5,433 |
) |
|
|
(12,508 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2005
|
|
|
(1,817 |
) |
|
|
(17,394 |
) |
|
|
|
|
|
|
10,579 |
|
|
|
(8,632 |
) |
2006 activity, before tax
|
|
|
(10,437 |
) |
|
|
24,914 |
|
|
|
|
|
|
|
(14,615 |
) |
|
|
(138 |
) |
2006 activity, tax effect
|
|
|
5,742 |
|
|
|
(9,973 |
) |
|
|
|
|
|
|
5,781 |
|
|
|
1,550 |
|
Statement No. 158 adoption
|
|
|
|
|
|
|
4,090 |
|
|
|
(22,502 |
) |
|
|
|
|
|
|
(18,412 |
) |
Statement No. 158 adoption, tax effect
|
|
|
|
|
|
|
(1,637 |
) |
|
|
8,100 |
|
|
|
|
|
|
|
6,463 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2006
|
|
$ |
(6,512 |
) |
|
$ |
|
|
|
$ |
(14,402 |
) |
|
$ |
1,745 |
|
|
$ |
(19,169 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As discussed in Note 1, Accounting Policies
unrealized gains (losses) on derivatives that qualify for hedge
accounting as cash flow hedges are recorded in other
comprehensive income. The unrealized gains and losses on
recording the Companys available-for-sale
securities at fair value are recorded through other
comprehensive income.
On July 31, 2006, the Company acquired a
331/3%
equity interest in Knight Hawk Holdings, LLC (Knight
Hawk), a coal producer in the Illinois Basin, in exchange
for $15.0 million in cash and
F-22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
approximately 30.0 million tons of coal reserves. The
Company recognized a $10.3 million gain on the transaction,
representing the difference between the fair market value of the
reserves surrendered and their carrying value, less the amount
of gain attributable to the ownership interest retained through
the investment. This gain is reflected in other operating
income, net on the accompanying Consolidated Statements of
Income for the year ended December 31, 2006. The
Companys income from its investment in Knight Hawk was
$2.1 million for the year ended December 31, 2006. At
December 31, 2006, the Company had an investment in Knight
Hawk of $41.9 million.
On August 23, 2006, the Company acquired a 25% equity
interest in DKRW Advanced Fuels LLC (DKRW), a
company engaged in developing
coal-to-liquids
facilities. In exchange, the Company agreed to extend
DKRWs existing coal reserve purchase option, to cooperate
with DKRW to secure coal reserves at fair value for two
additional
coal-to-liquids
projects outside of the Carbon Basin, and to invest
$25.0 million in DKRW. The Companys portion of
DKRWs loss was $0.1 million for the year ended
December 31, 2006. At December 31, 2006 the Company
had an investment in DKRW of $24.9 million.
The Company holds a 17.5% general partnership interest in
Dominion Terminal Associates (DTA), which is
accounted for on the equity method. DTA operates a ground
storage-to-vessel coal
transloading facility in Newport News, Virginia used by the
partners to transload coal. Financing for the facility was
provided through $132.8 million of tax-exempt bonds issued
by Peninsula Ports Authority of Virginia (PPAV). DTA
leases the facility from PPAV for amounts sufficient to meet
debt-service requirements. The Company retired its 17.5% share,
or $23.2 million, of the bonds in the fourth quarter of
2005. Under the terms of a throughput and handling agreement
with DTA, each partner is charged its share of cash operating
and debt-service costs in exchange for the right to use the
facilitys loading capacity and is required to make
periodic cash advances to DTA to fund such costs. The
Companys portion of DTAs costs was
$2.0 million, $3.4 million and $2.7 million for
the years ended December 31, 2006, 2005 and 2004,
respectively. At December 31, 2006 and 2005, the Company
had an investment in DTA of $13.4 million and
$8.5 million, respectively.
Through July 31, 2004, the Companys income from its
equity-method investment in Canyon Fuel represented 65% of
Canyon Fuels net income after adjusting for the effect of
purchase adjustments related to its investment in Canyon Fuel.
The Companys investment in Canyon Fuel reflects purchase
adjustments primarily related to the reduction in amounts
assigned to sales contracts, mineral reserves and other
property, plant and equipment. The purchase adjustments are
amortized consistently with the underlying assets of the joint
venture. The Company purchased the remaining 35% interest in
Canyon Fuel on July 31, 2004. The Companys income
from its investment in Canyon Fuel for the seven months ended
July 31, 2004 was $8.4 million.
During the year ended December 31, 2004, the Company sold
its remaining limited partnership units of Natural Resource
Partners L.P. (NRP), representing approximately
12.5% of NRPs outstanding partnership interests, in three
separate transactions occurring in March, June and October.
These sales resulted in proceeds of approximately
$111.4 million and gains of $91.3 million. The
Companys income from the equity investment in NRP was
$2.4 million for the year ended December 31, 2004.
F-23
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
On December 22, 2003, the Company sold 4.8 million
subordinated units and its general partner interest in NRP for a
purchase price of $115.0 million. This sale resulted in a
gain of $70.6 million, of which $42.7 million was
recognized in 2003 and the remainder was deferred. As of
December 31, 2006 and 2005, the Company had deferred gains
from its sales of NRP units totaling $5.5 million and
$8.2 million, respectively. The deferred gains are included
as other current liabilities and other noncurrent liabilities in
the accompanying Consolidated Balance Sheets. Certain leases
with NRP were related to the Companys operations sold as
part of the Magnum transaction. The company recognized a gain of
$5.8 million associated with these leases, which is
included in the gain on the transaction with Magnum. The
remaining deferred gains will be recognized over the remaining
term of the Companys leases with NRP, as follows:
$2.2 million in 2007, $1.1 million in 2008 and a total
of $2.2 million from 2009 through 2012.
The fair value of investments in stock and other equity
interests not accounted for under the equity method of
accounting totaled $6.6 million and $23.8 million at
December 31, 2006 and 2005, respectively.
Inventories consist of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31 | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Coal
|
|
$ |
49,608 |
|
|
$ |
73,284 |
|
Repair parts and supplies
|
|
|
80,218 |
|
|
|
57,436 |
|
|
|
|
|
|
|
|
|
|
$ |
129,826 |
|
|
$ |
130,720 |
|
|
|
|
|
|
|
|
The repair parts and supplies are stated net of an allowance for
slow-moving and obsolete inventories of $15.4 million and
$16.1 million at December 31, 2006 and 2005,
respectively.
The decrease in coal inventories is primarily the result of the
implementation of
EITF 04-6
discussed in Note 1, Accounting Policies as of
January 1, 2006, partially offset by an increase in coal
inventories primarily at the Western Bituminous segments
operations. The increase in repair parts and supplies is
primarily the result of an increase in tire inventories and
higher costs associated with materials and supplies.
|
|
7. |
Derivative Financial Instruments |
|
|
|
Diesel fuel price risk
management |
The Company uses forward physical purchase contracts and heating
oil swaps and purchased call options to reduce volatility in the
price of diesel fuel for its operations. The changes in the
price of heating oil highly correlate to changes in the price of
diesel fuel. Accordingly, the derivatives qualify for hedge
accounting and the changes in the fair value of the derivatives
are recorded through other comprehensive income. At
December 31, 2006, the Company held heating oil swaps and
purchased call options protecting approximately 68% of its
purchases for fiscal year 2007.
F-24
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following is a summary of our heating oil swaps and
purchased call options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 | |
|
December 31, 2005 | |
|
|
| |
|
| |
|
|
Quantity | |
|
|
|
Quantity | |
|
|
|
|
(Gallons) | |
|
Fair Value | |
|
(Gallons) | |
|
Fair Value | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Swaps current asset (liability)
|
|
|
17,100 |
|
|
$ |
(5,523 |
) |
|
|
22,800 |
|
|
$ |
8,096 |
|
Purchased call options current asset
|
|
|
9,900 |
|
|
|
376 |
|
|
|
9,300 |
|
|
|
746 |
|
|
|
|
Sulfur dioxide emission
allowance price risk management |
The Company is exposed to price risk related to the value of
sulfur dioxide emission allowances that are a component of the
quality adjustment provisions in many of its coal supply
agreements. The Company has historically purchased put options
and entered into swap contracts to protect the Company from any
downturn in the price of sulfur dioxide emission allowances. The
Company may also purchase call options to mitigate the risk of
changes in the fair value of a contract that contains a fixed
price for sulfur dioxide emission allowances.
The following is a summary of sulfur dioxide emission allowance
derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 | |
|
December 31, 2005 | |
|
|
| |
|
| |
|
|
Quantity | |
|
Fair Value | |
|
Quantity | |
|
Fair Value | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Swaps current liability
|
|
|
|
|
|
$ |
|
|
|
|
12,000 |
|
|
$ |
(11,949 |
) |
Purchased put options current asset
|
|
|
48,000 |
|
|
|
206 |
|
|
|
48,000 |
|
|
|
239 |
|
Purchased call options current asset
|
|
|
12,000 |
|
|
|
116 |
|
|
|
|
|
|
|
|
|
For all of the outstanding put options at December 31,
2006, the Company elected hedge accounting treatment and the
change in fair value was recorded through other comprehensive
income. All other changes in fair value were recorded in other
operating income, net in the accompanying Consolidated
Statements of Income.
|
|
|
Interest rate risk
management |
In the fourth quarter of 2005, the Company terminated certain
interest rate swap agreements that at one time had been
designated as a hedge of interest rate volatility on floating
rate debt. The amounts that had been deferred in accumulated
other comprehensive income were amortized as additional expense
over the contractual terms of the swap agreements prior to their
termination. For the years ended December 31, 2005 and
2004, the Company recognized $(2.3) million and
$0.9 million, respectively, of unrealized gains (losses)
related to these swaps. In the fourth quarter of 2005, the
Company terminated these swaps. For the years ended
December 31, 2006, 2005 and 2004, the Company recognized
$4.8 million, $7.7 million and $8.3 million of
expense, respectively, related to the amortization of the
balance in other comprehensive income. The remaining balance of
$1.9 million will be amortized from accumulated other
comprehensive income into net income in 2007.
F-25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Accrued expenses included in current liabilities consist of the
following:
|
|
|
|
|
|
|
|
|
|
|
December 31 | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Payroll and employee benefits
|
|
$ |
50,741 |
|
|
$ |
42,697 |
|
Taxes other than income taxes
|
|
|
73,235 |
|
|
|
59,828 |
|
Workers compensation
|
|
|
7,844 |
|
|
|
9,900 |
|
Interest
|
|
|
33,151 |
|
|
|
32,749 |
|
Asset retirement obligations
|
|
|
11,111 |
|
|
|
10,680 |
|
Losses on purchase commitments (see Note 3)
|
|
|
|
|
|
|
65,383 |
|
Due to Magnum (see Note 3)
|
|
|
|
|
|
|
16,000 |
|
Other accrued expenses
|
|
|
14,664 |
|
|
|
8,419 |
|
|
|
|
|
|
|
|
|
|
$ |
190,746 |
|
|
$ |
245,656 |
|
|
|
|
|
|
|
|
Significant components of the provision for (benefit from)
income taxes are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
|
|
|
|
|
|
|
|
(In thousands) |
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
1,213 |
|
|
$ |
(13,703 |
) |
|
$ |
7,583 |
|
|
State
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
1,213 |
|
|
|
(13,703 |
) |
|
|
7,583 |
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
22,700 |
|
|
|
(22,843 |
) |
|
|
(5,412 |
) |
|
State
|
|
|
(16,263 |
) |
|
|
1,896 |
|
|
|
(2,301 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred
|
|
|
6,437 |
|
|
|
(20,947 |
) |
|
|
(7,713 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
7,650 |
|
|
$ |
(34,650 |
) |
|
$ |
(130 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
A reconciliation of the statutory federal income tax expense on
the Companys pretax income to the actual provision for
(benefit from) income taxes follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Income tax expense at statutory rate
|
|
$ |
94,003 |
|
|
$ |
1,216 |
|
|
$ |
39,760 |
|
Percentage depletion allowance
|
|
|
(38,754 |
) |
|
|
(34,752 |
) |
|
|
(22,807 |
) |
State taxes, net of effect of federal taxes
|
|
|
1,576 |
|
|
|
(3,805 |
) |
|
|
1,729 |
|
Change in valuation allowance, affecting provision
|
|
|
(49,129 |
) |
|
|
(6,138 |
) |
|
|
(265 |
) |
Termination of interest rate swaps
|
|
|
|
|
|
|
5,049 |
|
|
|
180 |
|
Favorable tax settlement
|
|
|
|
|
|
|
|
|
|
|
(16,861 |
) |
Other, net
|
|
|
(46 |
) |
|
|
3,780 |
|
|
|
(1,866 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
7,650 |
|
|
$ |
(34,650 |
) |
|
$ |
(130 |
) |
|
|
|
|
|
|
|
|
|
|
F-26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
During 2006, the tax effect of the adoption of
EITF 04-6 was a
$16.7 million benefit was recorded to retained earnings.
Also, compensatory stock options and other equity based
compensation awards were exercised resulting in a tax benefit of
$7.7 million that will be allocated to paid-in capital at
such point in time when a cash tax benefit is recognized.
During 2005, compensatory stock options were exercised resulting
in a tax benefit of $11.6 million that was recorded to
paid-in capital.
During 2004, the IRS completed an audit and review of tax
returns and claims for tax years 1999 through 2002 resulting in
a favorable tax settlement, which includes a $9.7 million
reduction in prior years tax reserves. Also, compensatory
stock options were exercised resulting in a tax benefit of
$5.0 million that was recorded to paid-in capital.
Management believes that the Company has adequately provided for
any income taxes and interest which may ultimately be paid with
respect to all open tax years.
F-27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Significant components of the Companys deferred tax assets
and liabilities that result from carryforwards and temporary
differences between the financial statement basis and tax basis
of assets and liabilities are summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 | |
|
|
| |
|
|
2006 | |
|
2005 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Deferred tax assets:
|
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$ |
179,705 |
|
|
$ |
187,122 |
|
|
Plant and equipment
|
|
|
103,906 |
|
|
|
88,213 |
|
|
Alternative minimum tax credit carryforwards
|
|
|
86,148 |
|
|
|
99,782 |
|
|
Losses on purchase commitments
|
|
|
|
|
|
|
60,499 |
|
|
Reclamation and mine closure
|
|
|
38,314 |
|
|
|
32,563 |
|
|
Workers compensation
|
|
|
20,245 |
|
|
|
21,704 |
|
|
Advance royalties
|
|
|
16,816 |
|
|
|
16,961 |
|
|
Postretirement benefits other than pension
|
|
|
15,689 |
|
|
|
12,942 |
|
|
Other comprehensive income
|
|
|
9,703 |
|
|
|
1,688 |
|
|
Tax-based intangibles
|
|
|
9,514 |
|
|
|
11,574 |
|
|
Other
|
|
|
55,120 |
|
|
|
43,289 |
|
|
|
|
|
|
|
|
|
|
Gross deferred tax assets
|
|
|
535,160 |
|
|
|
576,337 |
|
|
Valuation allowance
|
|
|
(114,034 |
) |
|
|
(163,163 |
) |
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
421,126 |
|
|
|
413,174 |
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
|
Investment in tax partnerships
|
|
|
57,917 |
|
|
|
54,808 |
|
|
Deferred development
|
|
|
28,055 |
|
|
|
16,197 |
|
|
Coal inventory
|
|
|
1,138 |
|
|
|
15,842 |
|
|
Other
|
|
|
18,455 |
|
|
|
14,010 |
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
105,565 |
|
|
|
100,857 |
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax asset
|
|
|
315,561 |
|
|
|
312,317 |
|
|
|
Less current asset
|
|
|
51,802 |
|
|
|
88,461 |
|
|
|
|
|
|
|
|
|
|
|
Long-term deferred tax asset
|
|
$ |
263,759 |
|
|
$ |
223,856 |
|
|
|
|
|
|
|
|
The Company has net operating loss carryforwards for regular
income tax purposes that will expire from 2007 to 2023. The
Company has an alternative minimum tax credit carryforward of
$86.1 million, which has no expiration date and can be used
to offset future regular tax in excess of the alternative
minimum tax.
The Company has recorded a valuation allowance for a portion of
its deferred tax assets that management believes, more likely
than not, will not be realized. The valuation allowa