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, 2007
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
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(State or other jurisdiction
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(I.R.S. Employer
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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
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(Address of principal executive
offices)
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(Zip code)
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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
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Common Stock, $.01 par value
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New York Stock Exchange
Chicago Stock Exchange
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Preferred Share Purchase Rights
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New York Stock Exchange
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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, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the Exchange Act. (Check one):
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Large accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller reporting
company o
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(Do not check if a smaller reporting company)
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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 29, 2007 was approximately $5.0 billion.
On February 25, 2008, 143,954,798 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 24, 2008 are incorporated by reference into
Part III of this
Form 10-K.
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
anticipates, believes,
could, estimates, expects,
intends, may, plans,
predicts, projects, seeks,
should, will or other comparable words
and phrases. Forward-looking statements by their nature address
matters that are, to different degrees, uncertain. We believe
that the factors that could cause our actual results to differ
materially include the factors that we describe under the
heading Risk Factors beginning on page 23.
Those risks and uncertainties include but are not limited to the
following:
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market demand for coal and electricity;
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geologic conditions, weather and other inherent risks of coal
mining that are beyond our control;
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availability and price of mining and other industrial supplies;
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availability of skilled employees and other workforce factors;
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disruptions in the quantities of coal produced by our contract
mine operators;
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our ability to acquire or develop coal reserves in an
economically feasible manner;
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defects in title or the loss of a leasehold interest;
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railroad, barge, truck and other transportation performance and
costs;
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our ability to successfully integrate the operations that we
acquire;
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our ability to secure new coal supply arrangements or to renew
existing coal supply arrangements;
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our relationships with, and other conditions affecting, our
customers;
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our ability to service our outstanding indebtedness;
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our ability to comply with the restrictions imposed by our
credit facility and other financing arrangements;
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the availability and cost of surety bonds;
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failure by Magnum Coal Company, which we refer to as Magnum, to
satisfy certain below-market contracts that we guarantee;
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terrorist attacks, military action or war;
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environmental laws, including those directly affecting our coal
mining operations and those affecting our customers coal
usage;
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our ability to obtain and renew mining permits;
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future legislation and changes in regulations, governmental
policies and taxes, including those aimed at reducing emissions
of elements such as mercury, sulfur dioxides, nitrogen oxides,
particular matter or greenhouse gases;
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the accuracy of our estimates of reclamation and other mine
closure obligations;
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the existence of hazardous substances or other environmental
contamination on property owned or used by us; and
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the availability of future permits authorizing the disposition
of certain mining waste.
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These factors should not be construed as exhaustive and should
be read in conjunction with the other cautionary statements
included in this document. These risks and 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.
Glossary
of Selected Mining Terms
Certain terms that we use in this document 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.
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Assigned reserves |
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Recoverable reserves designated for mining by a specific
operation. |
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Btu |
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A measure of the energy required to raise the temperature of one
pound of water one degree of Fahrenheit. |
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Compliance coal |
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Coal which, when burned, emits 1.2 pounds or less of sulfur
dioxide per million Btus, requiring no blending or other sulfur
dioxide reduction technologies in order to comply with the
requirements of the Clean Air Act. |
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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. |
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Dragline |
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A large machine used in surface mining 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. |
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Longwall mining |
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One of two major underground coal mining methods, generally
employing two rotating drums pulled mechanically back and forth
across a long face of coal. |
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Low-sulfur coal |
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Coal which, when burned, emits 1.6 pounds or less of sulfur
dioxide per million Btus. |
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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. |
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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. |
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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. |
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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. |
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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. |
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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. |
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Room-and-pillar
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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. |
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Unassigned reserves |
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Recoverable 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, 2007, we operated 18 active mines located
in each of the major low-sulfur coal-producing regions of the
United States. Federal and state environmental regulations
affect the demand for certain types of coal by limiting the
amount of sulfur dioxide that may be emitted as a result of
combustion. Due to these regulations, we believe demand for
low-sulfur coal exceeds demand for other types of coal.
Consequently, we focus on mining, processing and marketing coal
with low sulfur content. At December 31, 2007, we estimate
that our proven and probable coal reserves had an average heat
value of approximately 10,000 Btus and an average sulfur content
of approximately 0.71%. As such, we estimate that approximately
75.4% of our proven and probable coal reserves consists of
compliance coal.
We sell substantially all of our coal to power plants, steel
mills and industrial facilities. For the year ended
December 31, 2007, we sold approximately 135.0 million
tons of coal, including approximately 8.6 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-fueled power plants in the United States. The following
chart shows the breakdown of our coal production by region for
2007, expressed as a percentage of the total tons we produced:
2007 Coal
Production, by Region
% of Total Tons
In 2007, we sold approximately 73.6% of our coal under contracts
with a term of more than one year. At December 31, 2007,
the average volume-weighted remaining term of our long-term
contracts was approximately 3.8 years, with remaining terms
ranging from one to ten years. At December 31, 2007, we had
a sales backlog, including a backlog subject to price reopener
or extension provisions, of approximately 377.5 million
tons.
We believe that rapid economic expansion in developing nations,
particularly China and India, has increased global demand for
coal. We expect coal exports from the United States to increase
in response to growing global coal demand, particularly as some
of the traditional coal export nations experience mine, port,
rail and labor challenges. We estimate that higher domestic
demand for coal and higher U.S. coal exports will
positively influence domestic coal demand. Additionally, we
expect decreased production, particularly in the Central
Appalachian region of the United States, to adversely impact
domestic coal supply in the coming years. We anticipate
continuing demand growth and weaker coal supplies 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, 2007, our
expected unpriced production approximated 15 million to
25 million tons in 2008, 85 million to 95 million
tons in 2009 and 95 million to 105 million tons in
2010.
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 Inc. 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 mine in Colorado
and a 65% interest in Canyon Fuel Company, which operates three
mines in Utah. In October 1998, 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 acquired 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.
In December 2005, we sold the stock of Hobet Mining, Inc.,
Apogee Coal Company and Catenary Coal Company and their four
associated mining complexes (Hobet 21, Arch of West Virginia,
Samples and Campbells Creek) and approximately
455.0 million tons of coal reserves in Central Appalachia
to Magnum.
The Coal
Industry
Global Coal Supply and Demand. Because of its
availability, stability and affordability, coal is a major
contributor to the global energy supply, providing approximately
40% of the worlds electricity, according to the World Coal
Institute, which we refer to as the WCI. Coal is also used in
producing approximately 64% of the worlds steel supply,
according to the WCI. Coal reserves can be found in almost every
country in the world, and approximately 50 countries are
currently mining coal.
Coal is traded worldwide and can be transported to demand
centers by ship and by rail. Worldwide coal production
approximated 5.9 billion tons in 2006 and 5.4 billion
tons in 2005, according to the WCI. China produces more coal
than any other country in the world. Historically, Australia has
been the worlds largest coal exporter, exporting more than
200 million tons in each of the last three years, according
to the WCI. China, Indonesia and South Africa have also
historically been significant exporters in the global coal
markets, however, growing demand in China has resulted in
declining coal exports and increasing coal imports. These trends
have caused China to become a less significant seaborne coal
supply source. In 2007, coal supply from other regions was
similarly affected because of mine disruptions, train
derailments and port congestion.
Growing demand for coal for power generation in many Asian
countries has begun to strain global coal supplies. Seaborne
coal trade increased 4.6% to approximately 806.9 million
metric tons in 2007, according to SSY Consultancy &
Research, Ltd. Seaborne trade into Asia increased approximately
9.1%, while European trade decreased approximately 4.3%. Demand
in China is expected to grow rapidly, as the demand for
electricity and the need for steel used in construction and
automobile production increase.
U.S. Coal Consumption. In the United
States, coal is used primarily by power plants 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 1.2 billion tons in 2007, based on
information provided by the Energy Information Administration,
which we refer to as the EIA.
Throughout the United States, coal has long been favored as a
fuel to produce electricity because of its cost advantage and
its availability. Since 1970, the use of coal to generate
electricity in the United States has nearly tripled in response
to growing electricity demand. According to the EIA, coal
accounted for approximately 50% of U.S. electricity
generation in 2007 and is projected to account for approximately
55% in 2030. By comparison, generation from natural gas is
expected to peak at approximately 21% in 2018 before slowly
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declining. The following chart shows U.S. electricity
generation by fuel source from 1980 through 2007 and the
projected generation through 2030:
Electricity
Generation by Fuel, 1980-2030
(in billion kilowatthours)
Source: EIA
According to the National Mining Association, which we refer to
as the NMA, coal is the lowest-cost fossil fuel used in
producing electricity. We estimate that the cost of generating
electricity from coal is less than one-third of the cost of
generating electricity from other fuels. According to the EIA,
the average delivered cost of coal to electric power generators
during the first ten months of 2007 was $1.77 /mm Btus,
which was $6.39 /mm Btus less expensive than residual fuel
oil and $5.28 /mm Btus less expensive than natural gas.
The EIA projects that power plants will increase their demand
for coal as demand for electricity increases. The EIA estimates
that electricity demand will increase by at least 40% by 2030,
despite continuing efforts throughout the United States to
become more energy efficient. Coal consumption has generally
grown at the pace of electricity growth because coal-fueled
electricity generation is used in most cases to meet baseload
requirements. We estimate that coal consumption for power
generation increased approximately 1.7% in 2007 as a result of
average economic growth and more favorable weather than in 2006.
Historically, demand for electricity has generally grown in
proportion to U.S. economic growth, as measured by gross
domestic product. In 2007, real gross domestic product increased
2.2%, according to the U.S. Department of Commerce.
Demand for coal is broadly influenced by weather. Weather
patterns requiring greater use of air-conditioning or heating
translate into greater demand for coal-based electricity
generation. According to the EIA, coal stockpiles at power
plants represented an approximate
53-day
supply at the end of 2007, compared to coal stockpiles
representing an approximate
50-day
supply at the end of 2006. We believe that some domestic power
plants seek to protect against future supply disruptions by
maintaining higher stockpile levels.
We believe that demand growth from new coal-fueled power plants
represents an important element to the long-term outlook for
coal. We estimate that roughly 25 gigawatts of new domestic
coal-fueled electricity generation capacity is currently under
construction or in advanced permitting stages, equating to more
than 85 million tons of new incremental annual coal demand,
based on information obtained from the National Energy
Technology Laboratory, which we refer to as the NETL, and our
internal estimates. We expect all or a significant majority of
these plants to be built over the next five years. The NETL also
estimates that, at
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December 31, 2007, approximately 17 gigawatts of generating
capacity was under construction or in advanced stages of
development in 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 mercury, sulfur dioxide, nitrogen oxide and
particulate matter will be introduced into the power generation
industry. We believe these technological advancements will help
coal retain its role as a key fuel for electric power generation
well into the future.
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. As
such, the price offered by steel makers for metallurgical coal
is generally higher than the price offered by power plants and
industrial users for steam coal. Rapid economic expansion in
China, India and other parts of southeast Asia has significantly
increased the demand for steel in recent years.
Prices for oil and natural gas in the United States have reached
record levels because of increasing demand and tensions
regarding international supply. Historically high oil and gas
prices and global energy security concerns have increased
government and private sector interest in converting coal into
liquid fuel, a process known as liquefaction. Liquid fuel
produced from coal can be refined further to produce
transportation fuels, such as low-sulfur diesel fuel, gasoline
and other oil products, such as plastics and solvents. Several
coal-to-liquids
projects are in the process of development, including a
coal-to-liquids
facility proposed by a
coal-conversion
company in which we own an equity interest. We also expect
advances in technologies designed to convert coal into
electricity through coal gasification processes and to capture
and sequester carbon dioxide emissions from electricity
generation and other sources. These technologies have garnered
greater attention in recent years due to developing concerns
about the impact of carbon dioxide on the global climate. 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. The United States
produces approximately one-fifth of the worlds coal
production and is the second largest coal producer in the world,
exceeded only by China. Coal in the United States represents
approximately 94% of the domestic fossil energy reserves with
over 250 billion tons of recoverable coal, according to the
U.S. Geological Survey. The U.S. Department of Energy
estimates that current domestic recoverable coal reserves could
supply enough electricity to satisfy domestic demand for more
than 200 years. Coal production in the United States has
increased from 434 million tons in 1960 to approximately
1.2 billion tons in 2007 based on information provided by
EIA.
Western regionThe western region includes, among other
areas, 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. In addition, 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 some existing coal plants to accommodate lower Btu
coal. The Western Bituminous region includes western Colorado,
eastern Utah and southern Wyoming. 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
618.3 million tons in 2007 as regulations limiting sulfur
dioxide emissions have increased demand for low-sulfur coal over
this period.
Appalachian regionThe 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
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tons in 1994 to 379.6 million tons in 2007, primarily as a
result of the depletion of economically attractive reserves,
permitting issues and increasing costs of production.
Interior regionThe 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. We anticipate that Illinois
basin coal will play an increasingly vital role in the
U.S. 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
150.2 million tons in 2007.
U.S. Coal Exports and Imports. Coal
exports decreased from 71.4 million tons in 1994 to
58.6 million tons in 2007. As discussed above, as global
consumption for coal has increased in recent years, countries
such as China, Indonesia, South Africa and Russia have decided
to retain a greater percentage of their coal production for
domestic consumption. This development, together with port
congestion in Australia, historically the largest coal exporter
in the world, and a weak U.S. dollar, has caused
U.S. coal to become more attractive in global markets. We
expect this trend to continue as global coal consumption
continues to increase.
Historically, coal imported from abroad has represented a
negligible share of total U.S. coal consumption. According
to the EIA, coal imports increased from 8.9 million tons in
1994 to 36.3 million tons in 2007. Coal is imported into
the United States primarily from Colombia, Indonesia 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 expect coal imports into the
United States to decrease due to increasing demand in Europe.
Coal
Mining Methods
The geological characteristics of our coal reserves largely
determine the coal mining method we employ. We use 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 9. In 2007, approximately 80% of the coal
that we produced 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 loadout facility. We reclaim disturbed areas as part of
our normal mining activities. After final coal removal, 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.
5
The following diagram illustrates a typical dragline 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 9. In 2007, approximately
20% of the coal that we produced 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 using mechanical shearers to extract
coal from long rectangular blocks of medium to thick seams.
Ultimate seam recovery using longwall mining techniques can
exceed 75%. In longwall mining, we use continuous miners to
develop access to these long rectangular coal blocks.
Hydraulically powered supports temporarily hold up the roof of
the mine while a rotating drum mechanically advances across the
face of the coal seam, cutting the coal from the face. 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 2007, approximately 17% of the coal that
we produced came from underground mining operations generally
using longwall mining techniques.
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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 miners to cut the coal 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, coal is mined from the pillars as
workers retreat. As retreat mining occurs, the roof is allowed
to collapse in a controlled fashion. Once we finish mining in an
area, we generally abandon that area and seal it from the rest
of the mine. In 2007, approximately 3% of the coal that we
produced came from underground mining operations generally using
room-and-pillar
mining techniques.
The following diagram illustrates our typical underground mining
operation using
room-and-pillar
mining techniques:
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Coal Preparation. Coal extracted from the
ground, particularly at our underground mining operations,
contains impurities, such as rock, shale and clay, and occurs in
a wide range of particle sizes. 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 2007, our
preparation plants processed approximately 83% of the raw coal
we produced in the Central Appalachia region. For more
information about our preparation plants, you should see the
section entitled Our Mining Operations below.
The treatments we employ depend on the properties of the
extracted coal and its intended use. To remove impurities, we
crush raw coal and classify it into various sizes. For the
largest size fractions, we use dense media vessel 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 shale. We treat
intermediate sized particles with dense medium cyclones, in
which a liquid is spun at high speeds to separate coal from
rock. Fine coal is treated in spirals, in which the differences
in density between coal and rock allow them, when suspended in
water, to be separated. Ultra fine coal is recovered in column
flotation cells utilizing the differences in surface chemistry
between coal and rock. By injecting stable air bubbles through a
suspension of ultra fine coal and rock, the coal particles
adhere to the bubbles and rise to the surface of the column
where they are removed. To minimize the moisture content in
coal, we may process certain coal through a centrifuge. A
centrifuge spins coal very quickly, causing water accompanying
the coal to separate.
Our
Mining Operations
At December 31, 2007, we operated 18 active mines at 11
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:
8
The following table provides a summary of information regarding
our mining complexes at December 31, 2007, the total sales
associated with these complexes for the years ended
December 31, 2005, 2006 and 2007 and the total reserves
associated with these complexes at December 31, 2007. The
amount disclosed below for the total cost of property, plant and
equipment of each mining complex does not include the costs of
the coal reserves that we have assigned to an individual complex:
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Total Cost
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of Property,
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Plant and
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Equipment
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Captive
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Contract
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Mining
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Tons Sold(2)
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at December 31,
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Assigned
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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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2005
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2006
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2007
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2007
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Reserves
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(Million tons)
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($ in millions)
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(Million tons)
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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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87.6
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92.5
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86.2
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$
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598.8
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1,314.6
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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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10.2
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143.0
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214.4
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Western Bituminous:
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Arch of Wyoming(4)
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UP
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24.5
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19.6
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Dugout Canyon
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U
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LW, C
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UP
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4.9
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4.2
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4.0
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122.0
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29.0
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Skyline(3)
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U
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LW, C
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UP
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1.5
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2.4
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154.2
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22.8
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Sufco
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U
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LW, C
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UP
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7.5
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7.4
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6.7
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229.0
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51.3
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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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5.9
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5.0
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6.2
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253.8
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78.8
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Central Appalachia:
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Coal-Mac
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S
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U
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L, E
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NS/CSX
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3.2
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3.7
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3.9
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141.1
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30.9
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Cumberland River
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S(2), U(3)
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U
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L, C, HW
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NS
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2.3
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2.6
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2.4
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122.6
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21.0
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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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2.6
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2.5
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2.4
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167.1
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34.7
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Mountain Laurel
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U
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LW, C
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CSX
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1.0
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399.1
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83.0
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Totals
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114.0
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122.5
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125.4
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$
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2,355.2
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1,900.1
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S = Surface mine
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D = Dragline
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UP = Union Pacific Railroad
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U = Underground mine
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L = Loader/truck
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CSX = CSX Transportation
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S = Shovel/truck
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BN = Burlington Northern Santa Fe Railway
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E = Excavator/truck
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NS = Norfolk Southern Railroad
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LW = Longwall
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C = Continuous miner
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HW = Highwall miner
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(1)
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Amounts in parentheses indicate the
number of captive and contract mines at the mining complex at
December 31, 2007. Captive mines are mines that we own and
operate on land owned or leased by us. Contract mines are mines
that other operators mine for us under contracts on land owned
or leased by us.
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(2)
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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 0.2 million
tons in 2007, 1.7 million tons in 2006 and 2.2 million
tons in 2005. We have not 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. Tons of coal
sold that we purchased from third parties but did not process
through our loadout facilities approximated 8.4 million
tons in 2007, 8.5 million tons in 2006 and 8.8 million
tons in 2005.
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In December 2005, we sold 100% of
the stock of Hobet Mining, Inc., 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. In June 2007, we sold the Mingo
Logan-Ben Creek mining complex and associated reserves to Alpha
Natural Resources. We have not included any information in the
table above related to those complexes. Those complexes sold
1.2 million tons in 2007, 4.0 million tons in 2006 and
17.4 million tons in 2005.
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(3)
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In 2006, we resumed mining at our
Coal Creek and Skyline complexes. We had idled the Coal Creek
complex in 2000 and the Skyline complex in 2004.
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(4)
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The inactive surface mines at the
Arch of Wyoming complex are in the final process of reclamation
and bond release.
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9
Powder River Basin. Our operations in the
Powder River Basin are located in Wyoming and include two
surface mining complexes. During 2007, these complexes sold
approximately 96.4 million tons of compliance coal. 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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Black Thunder is a surface mining complex located on
approximately 24,300 acres in Campbell County, Wyoming. We
control a significant portion of the coal reserves through
federal and state leases. The complex currently consists of six
active pit areas, one owned loadout facility and one leased
loadout facility. We ship all of the coal raw to our customers
via the Burlington Northern Santa Fe and Union Pacific
railroads. We do not process the coal mined at this complex.
Each of the loadout facilities can load a 15,000-ton train in
less than three hours. |
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Coal Creek |
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Coal Creek is a surface mining complex located on approximately
7,400 acres in Campbell County, Wyoming. We control a
significant portion of the coal reserves through federal and
state leases. The complex currently consists of two active pit
areas and a loadout facility. We ship all of the coal raw to our
customers via the Burlington Northern Santa Fe and Union Pacific
railroads. We do not process the coal mined at this complex. The
loadout facility can load a 15,000-ton 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 mining complexes
and one surface mining complex that includes four inactive
surface mines. During 2007, the mining complexes in the Western
Bituminous region sold approximately 19.3 million tons of
compliance coal. We control approximately 459.9 million
tons of proven and probable coal reserves in the Western
Bituminous region.
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Arch of Wyoming |
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Arch of Wyoming is a surface mining complex located in Carbon
County, Wyoming. The complex currently consists of four inactive
surface mines located on approximately 29,900 acres that
are in the final process of reclamation and bond release. In
2006, we began preliminary development of a new mining area
located on approximately 30,100 acres. We control a
significant portion of the coal reserves associated with this
complex through federal, state and private leases. During 2007,
we produced a minimal amount of coal attributable to the
development of the new mining area. |
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Dugout Canyon |
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Dugout Canyon mine is an underground mining complex located on
approximately 18,200 acres in Carbon County, Utah. We
control a significant portion of the coal reserves through
federal and state leases. The complex currently consists of a
longwall, two continuous miner sections and a truck loadout
facility. We ship all of the coal to our customers via the Union
Pacific railroad or by highway trucks. We wash a portion of the
coal we produce at a 400-ton-per-hour preparation plant. The
loadout facility can load approximately 20,000 tons of coal per
day into highway trucks. Coal shipped by rail is loaded through
a third-party facility capable of loading an 11,000-ton train in
less than three hours. |
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Skyline |
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Skyline is an underground mining complex located on
approximately 12,400 acres in Carbon and Emery Counties,
Utah. We control a significant portion of the coal reserves
through federal leases and smaller portions through county and
private leases. The complex |
10
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currently consists of a longwall, a continuous miner section and
a loadout facility. We ship all of the coal raw to our customers
via the Union Pacific railroad or by highway trucks. We do not
process the coal mined at this complex. The loadout facility can
load a 12,000-ton train in less than four hours. |
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Sufco |
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Sufco is an underground mining complex located on approximately
25,200 acres in Sevier County, Utah. We control a
significant portion of the coal reserves through federal and
state leases. The complex currently consists of a longwall,
three continuous miner sections and a loadout facility located
approximately 80 miles from the mine. We ship all of the
coal raw to our customers via the Union Pacific railroad or by
highway trucks. We do not process the coal mined at this
complex. The loadout facility can load an 11,000-ton train in
less than three hours. |
|
West Elk |
|
West Elk is an underground mining complex located on
approximately 17,900 acres in Gunnison County, Colorado. We
control a significant portion of the coal reserves through
federal and state leases. The complex currently consists of a
longwall, three continuous miner sections and a loadout
facility. We ship all of the coal raw to our customers via the
Union Pacific railroad. We do not process the coal mined at this
complex. The loadout facility can load an 11,000-ton train in
less than three hours. |
Central Appalachia. Our operations in the
Central Appalachia region are located in southern West Virginia,
eastern Kentucky and southwestern Virginia and include four
mining complexes comprised of nine underground mines and three
surface mines. During 2007, these operations sold approximately
9.7 million tons of low-sulfur coal. Metallurgical coal
accounted for 1.7 million tons of total coal sales from
these operations in 2007. We control approximately
338.0 million tons of proven and probable coal reserves in
Central Appalachia.
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Coal-Mac |
|
Coal-Mac is a surface and underground mining complex located on
approximately 46,800 acres in Logan and Mingo Counties,
West Virginia. We control a significant portion of the coal
reserves through private leases. The complex currently consists
of two surface mines (one captive and one contract), one
contract underground mine, a preparation plant and two loadout
facilities, which we refer to as Holden 22 and Ragland. We ship
coal trucked to the Ragland loadout facility directly to our
customers via the Norfolk Southern railroad. The Ragland loadout
facility can load a 15,000-ton train in less than four hours. We
ship coal trucked to the Holden 22 loadout facility directly to
our customers via the CSX railroad. We wash a portion of the
coal transported to the Holden 22 loadout facility at an
adjacent 600-ton-per-hour preparation plant. The Holden 22
loadout facility can load a 12,000-ton train in less than four
hours. |
|
Cumberland River |
|
Cumberland River is an underground and surface mining complex
located on approximately 16,700 acres in Wise County,
Virginia and Letcher County, Kentucky. We control a significant
portion of the coal reserves through private leases. The complex
currently consists of four underground mines (three captive, one
contract) operating a total of five continuous miner sections,
two captive surface operations, two highwall miners (one
captive, one contract), a preparation plant and a loadout
facility. We ship approximately one-third of the coal raw to our
customers via the Norfolk Southern railroad. We |
11
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process the remaining two-thirds of the coal through a
500-ton-per-hour
preparation plant before shipping it to our customers via the
Norfolk Southern railroad. The loadout facility can load a
12,500-ton train in less than four hours. |
|
Lone Mountain |
|
Lone Mountain complex is an underground mining complex located
on approximately 21,400 acres in Harlan County, Kentucky
and Lee County, Virginia. We control a significant portion of
the coal reserves through private leases. The complex currently
consists of three underground mines operating a total of seven
continuous miner sections. We convey coal mined in Kentucky to
Virginia before we process it through a
1,200-ton-per-hour
preparation plant. We then ship the coal to our customers via
the Norfolk Southern or CSX railroad. The loadout facility can
load a 12,500-ton unit train in less than four hours. |
|
Mountain Laurel |
|
Mountain Laurel is an underground mining complex located on
approximately 30,000 acres in Logan County, West Virginia.
In 2007, we began preliminary development of a new surface
mining area adjacent to our underground mine. We control a
significant portion of the coal reserves through private leases.
The complex currently consists of a longwall, four continuous
miner sections, a preparation plant and a loadout facility. We
process all of the coal through a
2,100-ton-per-hour
preparation plant before shipping the coal to our customers via
the CSX railroad. The loadout facility can load a 15,000-ton
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, 2007, 2006 and 2005 contained in
Note 22 Segment Information to our consolidated
financial statements beginning on
page F-1.
Transportation
We ship our coal to customers by means of railroad, barges or
trucks, or a combination of these means of transportation. We
also ship our coal to Atlantic coast terminals or terminals
along the Gulf of Mexico for transportation to domestic and
international customers. As is customary in the industry, once
the coal is loaded onto the rail car, barge, truck or vessel,
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 and trucks 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 for
shipment on the inland waterways.
In addition, we 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 along the
Atlantic coast of the United States.
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
12
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 for certain of our Central
Appalachia mines, is generally more expensive than surface
mining, which is the mining method we use in the Powder River
Basin and 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, we assign contract shipments to one or more
mining complexes within a region capable of sourcing that coal.
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 2007, we sold approximately
73.6% of our coal under long-term supply arrangements. At
December 31, 2007, the average volume-weighted remaining
term of our long-term contracts was approximately
3.8 years, with remaining terms ranging from one to ten
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.
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., Magnum Coal Company, Massey Energy Company, Patriot Coal
Corporation, Peabody Energy Corp. and Rio Tinto
Energy North America. Some of these coal producers
are larger than we are 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
also compete with companies that produce coal from one or more
foreign countries, such as Colombia, Indonesia 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 relating to
these alternative fuels, such as safety and environmental
considerations, affect the overall demand for coal as a fuel.
13
Geographic
Data
We market our coal principally to power plants, steel mills and
industrial facilities located in the United States. Coal sales
to foreign customers approximated $196.7 million for 2007,
$162.5 million for 2006 and $166.0 million for 2005.
Safety
and Environmental Regulations
Our operations, like operations of other coal companies, are
subject to regulation, primarily by federal and state
authorities, on matters such as: air quality standards;
reclamation and restoration activities involving our mining
properties; mine permits and other licensing requirements; water
pollution; employee health and safety; the discharge of
materials into the environment; management of materials
generated by mining operations; storage of petroleum products;
protection of wetlands and endangered plant and wildlife
protection. Many of these regulations require registration,
permitting, compliance, monitoring and self-reporting and may
impose civil and criminal penalties for non-compliance.
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 over time. The possibility exists that new legislation or
regulations may be adopted or that the enforcement of existing
laws could become more stringent, causing coal to become a less
attractive fuel source and reducing the percentage of
electricity generated from coal. Future legislation or
regulation or more stringent enforcement of existing laws may
have a significant impact on our mining operations or our
customers ability to use coal.
While it is not possible to accurately 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 workers
compensation benefits, coal leases and other miscellaneous
obligations. Compliance with these laws has substantially
increased the cost of coal mining for 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 business:
Clean Air Act. The federal Clean Air Act and
similar state and local laws that regulate air emissions affect
coal mining directly and indirectly. Direct impacts on coal
mining and processing operations include Clean Air Act
permitting requirements
and/or
emissions control requirements relating to particulate matter
which may include controlling fugitive dust. The Clean Air Act
also indirectly affects coal mining operations by extensively
regulating the emissions of fine particulate matter measuring
2.5 micrometers in diameter or smaller, sulfur dioxide, nitrogen
oxides, mercury and other compounds emitted by coal-fueled power
plants and industrial boilers, which are the largest end-users
of our coal. Continued tightening of the already stringent
regulation of emissions and regulation of additional emissions
such as carbon dioxide or other greenhouse gases from
coal-fueled power plants and industrial boilers could eventually
reduce the demand for coal.
Clean Air Act requirements that may directly or indirectly
affect our operations include the following:
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Acid Rain. Title IV of the Clean Air Act
imposes a two-phase reduction of sulfur dioxide emissions by
electric utilities. Phase II became effective in 2000 and
applies to all coal-fueled power plants with a capacity of more
than 25-megawatts. Generally, the affected power plants have
sought to comply with these requirements by switching to lower
sulfur fuels, installing pollution control devices, reducing
electricity generating levels or purchasing or trading sulfur
dioxide emissions allowances. Although we cannot accurately
predict the future effect of this Clean Air Act provision on our
operations, we believe that implementation of Phase II has
resulted in, and will continue to result in, an upward pressure
on the price of lower sulfur coals as coal-fueled power plants
continue to comply with the more stringent restrictions of
Title IV.
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Fine Particulate Matter. The Clean Air Act
requires the U.S. Environmental Protection Agency, which we
refer to as EPA, to set national ambient air quality standards,
which we refer to as NAAQS, for
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certain pollutants associated with the combustion of coal,
including sulfur dioxide, particulate matter, nitrogen oxides
and ozone. Areas that are not in compliance with these
standards, referred to as non-attainment areas, must take steps
to reduce emissions levels. For example, NAAQS currently exist
for particulate matter measuring 10 micrometers in diameter or
smaller (PM10) and for fine particulate matter measuring 2.5
micrometers in diameter or smaller (PM2.5). The EPA designated
all or part of 225 counties in 20 states as well as the
District of Columbia as non-attainment areas with respect to the
PM2.5 NAAQS. Those designations have been challenged. Individual
states must identify the sources of emissions and develop
emission reduction plans. These plans may be state-specific or
regional in scope. Under the Clean Air Act, individual states
have up to twelve years from the date of designation to secure
emissions reductions from sources contributing to the problem.
Future regulation and enforcement of the new PM2.5 standard will
affect many power plants, especially coal-fueled power plants,
and all plants in non-attainment areas.
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Ozone. Significant additional emission control
expenditures will be required at coal-fueled power plants to
meet the current NAAQS for ozone. Nitrogen oxides, which are a
byproduct of coal combustion, are classified as an ozone
precursor. As a result, emissions control requirements for new
and expanded coal-fueled power plants and industrial boilers
will continue to become more demanding in the years ahead. For
example, in 2004, the EPA designated counties in 32 states
as non-attainment areas under the new standard. These states had
until June 2007 to develop plans, referred to as state
implementation plans, or SIPs, for pollution control measures
that allow them to comply with the standards. The EPA described
the action that states must take to reduce ground-level ozone in
a final rule promulgated in November 2005. The rule is subject
to judicial challenge, however, making its impact difficult to
assess. In July 2007, the EPA proposed to make the current
standard more stringent. If the EPAs current rules are
upheld and the EPA finalizes a more stringent ozone NAAQS,
additional emission control expenditures will likely be required
at coal-fueled power plants.
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NOx SIP Call. The NOx SIP Call program was
established by the EPA in October 1998 to reduce the transport
of ozone on prevailing winds from the Midwest and South to
states in the Northeast, which said that they could not meet
federal air quality standards because of migrating pollution.
The program is designed to reduce nitrous oxide emissions by one
million tons per year in 22 eastern states and the District of
Columbia. Phase II reductions were required by May 2007. As
a result of the program, many power plants have been or will be
required to install additional emission control measures, such
as selective catalytic reduction devices. Installation of
additional emission control measures will make it more costly to
operate coal-fueled power plants, thereby making coal a less
attractive fuel.
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Clean Air Interstate Rule. The EPA finalized
the Clean Air Interstate Rule, which we refer to as CAIR, in
March 2005. CAIR calls for power plants in 29 eastern states and
the District of Columbia to reduce emission levels of sulfur
dioxide and nitrous oxide. The rule requires states to regulate
power plants under a cap and trade program similar to the system
now in effect for acid deposition control and to that proposed
by the Clean Skies Initiative. When fully implemented, the rule
is expected to reduce regional sulfur dioxide emissions by over
70% and nitrogen oxides emissions by over 60% from 2003 levels.
The stringency of the cap may require some coal-fueled power
plants to install additional pollution control equipment, such
as wet scrubbers, which could decrease the demand for low-sulfur
coal at these plants and thereby potentially reduce market
prices for low-sulfur coal. Emissions are permanently capped and
cannot increase. The rule is also subject to judicial challenge,
which makes its impact difficult to assess.
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Mercury. In February 2008, the United States
Court of Appeals for the District of Columbia Circuit vacated
the EPAs Clean Air Mercury Rule, which we refer to as
CAMR, and remanded it to the EPA for reconsideration. The EPA is
reviewing the court decision and evaluating its impacts. Before
the court decision, some states had either adopted CAMR or
adopted state-specific rules to regulate mercury emissions from
power plants that are more stringent than CAMR. CAMR, as
promulgated, would have permanently capped and reduced mercury
emissions from coal-fueled power plants by establishing mercury
emissions limits from new and existing coal-fueled power plants
and creating a market-based
cap-and-trade
program that was expected to reduce nationwide emissions of
mercury in two phases.
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Under CAMR, coal-fueled power plants would have had 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. Regardless of how the EPA responds on reconsideration
or how states implement their state-specific mercury rules,
rules imposing stricter limitations on mercury emissions from
power plants will likely be promulgated and implemented. Any
such rules may adversely affect the demand for coal.
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Carbon Dioxide. In February 2003, a number of
states notified the EPA that they planned to sue the agency to
force it to set new source performance standards for electric
utility emissions of carbon dioxide and to tighten existing
standards for sulfur dioxide and particulate matter for utility
emissions. In April 2007, the U.S. Supreme Court rendered
its decision in Massachusetts v. EPA, finding that
the EPA has authority under the Clean Air Act to regulate carbon
dioxide emissions from automobiles and can decide against
regulation only if the EPA determines that carbon dioxide does
not significantly contribute to climate change and does not
endanger public health or the environment. The EPAs final
regulations in response to the decision are not expected until
December 2008. In other actions, following the
Massachusetts v. EPA decision, the U.S. Court
of Appeals for the District of Columbia Circuit remanded to the
EPA new source performance standards for utility and industrial
boilers promulgated in 2006 for further proceedings in light of
the Massachusetts v. EPA decision. In June 2006, the
U.S. Court of Appeals for the Second Circuit heard oral
argument in a public nuisance action filed by eight states
(Connecticut, Delaware, Maine, New Hampshire, New Jersey, New
York, and Vermont) and New York City to curb carbon dioxide
emissions from power plants. The parties have filed
post-argument briefs on the impact of the
Massachusetts v. EPA decision, and a decision is
currently pending. If as a result of these actions the EPA were
to set emission limits for carbon dioxide from electric
utilities, the amount of coal our customers purchase from us
could decrease.
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Regional Haze. The EPA has initiated a
regional haze program designed to protect and improve visibility
at and around national parks, national wilderness areas and
international parks, particularly those located in the southwest
and southeast United States. This program may result in
additional emissions restrictions from new coal-fueled power
plants whose operation may impair visibility at and around
federally protected areas. This program may also require certain
existing coal-fueled power plants to install additional control
measures designed to limit haze-causing emissions, such as
sulfur dioxide, nitrogen oxides, volatile organic chemicals and
particulate matter. These limitations could affect the future
market for coal.
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Surface Mining Control and Reclamation
Act. The Surface Mining Control and Reclamation
Act, which we refer to as SMCRA, establishes mining,
environmental protection, reclamation and closure standards for
all aspects of surface mining as well as many aspects of
underground mining. Mining operators must obtain SMCRA permits
and permit renewals from the Office of Surface Mining, which we
refer to as OSM, or from the applicable state agency if the
state agency has obtained primacy. A state agency may achieve
primacy if the state regulatory agency develops a mining
regulatory program that is no less stringent than the federal
mining regulatory program under SMCRA.
SMCRA permit provisions include a complex set of requirements
which include, among other things, coal prospecting; mine plan
development; topsoil or growth medium removal and replacement;
selective handling of overburden materials; mine pit backfilling
and grading; disposal of excess spoil; protection of the
hydrologic balance; subsidence control for underground mines;
surface runoff and drainage control; establishment of suitable
post mining land uses; and revegetation.
The mining permit application preparation process is initiated
by collecting baseline data to adequately characterize the
pre-mining environmental conditions of the permit area. This
work is typically conducted by third-party consultants with
specialized expertise and includes surveys
and/or
assessments of the following: cultural and historical resources;
geology; soils; vegetation; aquatic organisms; wildlife;
potential for threatened, endangered or other special status
species; surface and ground water hydrology; climatology;
riverine and riparian habitat; and wetlands. The geologic data
is used to define and characterize the rock structures that will
be encountered during the mining process. The geologic data and
information derived from the other surveys
and/or
assessments are used to develop the mining and reclamation plans
presented in the permit application.
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The mining and reclamation plans address the provisions and
performance standards of the states equivalent SMCRA
regulatory program, and are also used to support applications
for other authorizations
and/or
permits required to conduct coal mining activities. Also
included in the permit application is information used for
documenting surface and mineral ownership, variance requests,
access roads, bonding information, mining methods, mining
phases, other agreements that may relate to coal, other
minerals, oil and gas rights, water rights, permitted areas, and
ownership and control information required to determine
compliance with Office of Surface Minings Applicant
Violator System, including the mining and compliance history of
officers, directors and principal owners of the entity.
Once a permit application is prepared and submitted to the
regulatory agency, it goes through an administrative
completeness review and a thorough technical review. Also,
before a SMCRA permit is issued, a mine operator must submit a
bond or otherwise secure the performance of all reclamation
obligations. After the application is submitted, a public notice
or advertisement of the proposed permit is required to be given,
which begins a notice period that is followed by a public
comment period before a permit can be issued. It is not uncommon
for a SMCRA mine permit application to take over a year to
prepare, depending on the size and complexity of the mine, and
anywhere from six months to two years or even longer for the
permit to be issued. The variability in time frame required to
prepare the application and issue the permit can be attributed
primarily to the various regulatory authorities discretion
in the handling of comments and objections relating to the
project received from the general public and other agencies.
Also, it is not uncommon for a permit to be delayed as a result
of litigation related to the specific permit or another related
companys permit.
In addition to the bond requirement for an active or proposed
permit, the Abandoned Mine Land Fund, which was created by
SMCRA, requires a fee on all coal produced. The proceeds of the
fee are used to restore mines closed or abandoned prior to
SMCRAs adoption in 1977. The current fee is $0.315 per ton
of coal produced from surface mines and $0.135 per ton of coal
produced from underground mines. In 2007, we recorded
$38.0 million of expense related to these reclamation fees.
Mining Permits and Approvals. Numerous
governmental permits or approvals are required for mining
operations. When we apply for these permits and approvals, we
may be required to prepare and present data to federal, state or
local authorities data pertaining to the effect or impact that
any proposed production or processing of coal may have upon the
environment. The authorization, permitting and implementation
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
or modification can be delayed, 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 or even years 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.
Surety Bonds. Mine operators are often
required by federal
and/or state
laws to assure, usually through the use of surety bonds, payment
of certain long-term obligations including mine closure or
reclamation costs, federal and state workers compensation
costs, coal leases and other miscellaneous obligations. Although
surety bonds are usually noncancelable during their term, many
of these bonds are renewable on an annual basis. The costs of
these bonds have fluctuated in recent years while the market
terms of surety bonds have generally become more unfavorable to
mine operators. These changes in the terms of the bonds have
been accompanied at
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times by a decrease in the number of companies willing to issue
surety bonds. In order to address some of these uncertainties,
we use self-bonding to secure performance of certain obligations
in Wyoming. As of December 31, 2007, we have self-bonded an
aggregate of $306.4 million and have posted an aggregate of
$263.0 million in surety bonds and $0.5 million in
cash bonds for reclamation purposes. In addition, we had
approximately $134.0 million of surety bonds and letters of
credit outstanding at December 31, 2007 to secure
workers compensation, coal lease and other obligations.
Clean Water Act. The Clean Water Act of 1972
and comparable state laws that regulate waters of the United
States can affect our mining operations directly and indirectly.
One of the direct impacts on coal mining and processing
operations is the Clean Water Act permitting requirements
relating to the discharge of pollutants into waters of the
United States. Indirect impacts of the Clean Water Act include
discharge limits placed on coal-fueled power plant ash handling
facilities discharges. Continued litigation of Clean Water
Act issues could eventually reduce the demand for coal.
Clean Water Act requirements that may directly or indirectly
affect our operations include the following:
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Wastewater Discharge. Section 402 of the
Clean Water Act creates a process for establishing effluent
limitations for discharges to streams that are protective of
water quality standards through the National Pollutant Discharge
Elimination System, which we refer to as the NPDES, or an
equally stringent program delegated to a state regulatory
agency. Regular monitoring, reporting and compliance with
performance standards are preconditions for the issuance and
renewal of NPDES permits that govern the discharge into waters
of the United States. The imposition of future restrictions on
the discharge of certain pollutants into waters of the United
States could affect the permitting process, increase the costs
and difficulty of obtaining and complying with NPDES permits and
could adversely affect our coal production.
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Under the Clean Water Act, states must conduct an
anti-degradation review before approving permits for the
discharge of pollutants to waters that have been designated as
high quality. A states anti-degradation regulations would
prohibit the diminution of water quality in these streams. In
general, waters discharged from coal mines to high quality
streams may be required to meet new high quality
standards. This could cause increases in the costs, time and
difficulty associated with obtaining and complying with NPDES
permits, and could adversely affect our coal production.
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Dredge and Fill Permits Act. Many mining
activities, such as the development of refuse impoundments,
fresh water impoundments, refuse fills, valley fills, and other
similar structures, may result in impacts to waters of the
United States, including wetlands, streams and, in certain
instances, man-made conveyances that have a hydrologic
connection to such streams or wetlands. Prior to conducting such
mining activities, coal companies are required to obtain a
Section 404 permit, referred to as a dredge or fill permit,
from the Army Corps of Engineers, which we refer to as the
Corps. The Corps is authorized to issue two types of
Section 404 permits: a general permit, referred to as a
nationwide permit, for surface mining activities and an
individual permit. The Corps may issue nationwide permits for
any category of activities involving the discharge of dredge or
fill material if the Corps determines that such activities are
similar in nature and will cause only minimal adverse
environmental effects individually or cumulatively. Generally,
the Corps has used nationwide permits to authorize impacts to
waters of the United States from mining activities because the
process is a more streamlined permitting approach and consumes
less Corps resources.
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The use of the nationwide permit to authorize stream impacts
from mining activities was successfully challenged in October
2003 in federal court in southern West Virginia, but was later
overturned at the court of appeals. During the appeal period
only, the Corps was enjoined (only in the southern district of
West Virginia) from using the nationwide permit to authorize
dredge and fill activities for mining impacts. As a precaution
to mitigate the uncertainty surrounding the use of the
nationwide permit in these areas, we converted certain ongoing
permits, pending applications, and planned applications from
nationwide permits to individual permits. This precautionary
step was taken to minimize the potential for future production
interruptions.
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You should see Item 3 Legal Proceedings
beginning on page 33 for more information about certain
litigation pertaining to our permits.
Mine Health and Safety Laws. Stringent safety
and health standards have been imposed by federal legislation
since Congress adopted the Mine Safety and Health Act of 1969.
The Mine Safety and Health Act of 1977 significantly expanded
the enforcement of safety and health standards and imposed
comprehensive safety and health standards on all aspects of
mining operations. In addition to federal regulatory programs,
all of the states in which we operate also have programs for
mine safety and health regulation and enforcement. In reaction
to several mine accidents in recent years, federal and state
legislatures and regulatory authorities have increased scrutiny
of mine safety matters and passed more stringent laws governing
mining. For example, in 2006, Congress enacted the Mine
Improvement and New Emergency Response Act of 2006, which we
refer to as the MINER Act. The MINER Act imposes additional
obligations on coal operators including, among other things, the
following:
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development of new emergency response plans that address
post-accident communications, tracking of miners, breathable
air, lifelines, training and communication with local emergency
response personnel;
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establishment of additional requirements for mine rescue teams;
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notification of federal authorities in the event of certain
events;
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increased penalties for violations of the applicable federal
laws and regulations; and
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requirement that standards be implemented regarding the manner
in which closed areas of underground mines are sealed.
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Various states, including West Virginia, have also enacted new
laws to address many of the same subjects. The full financial
impact of the new regulations is not yet known. However, the
cost of implementation of the new safety and health regulations
at the federal and state level may be substantial. In addition
to the cost of implementation, there are increased penalties for
violations which may also be substantial. Expanded enforcement
could result in a proliferation of litigation regarding
citations and orders issued as a result of the regulations.
Under the Black Lung Benefits Revenue Act of 1977 and the Black
Lung Benefits Reform Act of 1977, each coal mine operator must
secure payment of federal black lung benefits to claimants who
are current and former employees and to a trust fund for the
payment of benefits and medical expenses to claimants who last
worked in the coal industry prior to July 1, 1973. The
trust fund is funded by an excise tax on production of up to
$1.10 per ton for coal mined in underground operations and up to
$0.55 per ton for coal mined in surface operations. These
amounts may not exceed 4.4% of the gross sales price. This
excise tax does not apply to coal shipped outside the United
States. In 2007, we recorded $65.0 million of expense
related to this excise tax.
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 trigger 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.
Resource Conservation and Recovery Act. The
Resource Conservation and Recovery Act, which we refer to as
RCRA, may affect coal mining operations by establishing
requirements for the proper management, handling, transportation
and disposal of hazardous wastes. Currently, certain coal mine
wastes, such as overburden and coal
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cleaning wastes, are exempted from hazardous waste management.
Subtitle C of RCRA exempted fossil fuel combustion wastes from
hazardous waste regulation until the EPA completed a report to
Congress and made a determination on whether the wastes should
be regulated as hazardous. In a 1993 regulatory determination,
the EPA addressed some high volume-low toxicity coal combustion
products generated at electric utility and independent power
producing facilities, such as coal ash. In May 2000, the EPA
concluded that coal combustion products do not warrant
regulation as hazardous waste under RCRA. The EPA is retaining
the hazardous waste exemption for these wastes. However, the EPA
has determined that national non-hazardous waste regulations
under RCRA Subtitle D are needed for coal combustion products
disposed in surface impoundments and landfills and used as
mine-fill. The Office of Surface Mining and EPA have recently
proposed regulations regarding the management of coal combustion
products. The EPA also concluded beneficial uses of these
wastes, other than for mine-filling, pose no significant risk
and no additional national regulations are needed. As long as
this exemption remains in effect, it is not anticipated that
regulation of coal combustion waste will have any material
effect on the amount of coal used by electricity generators.
Most state hazardous waste laws also exempt coal combustion
products, and instead treat it as either a solid waste or a
special waste. Any costs associated with handling or disposal of
hazardous wastes would increase our customers operating
costs and potentially reduce their ability to purchase coal. In
addition, contamination caused by the past disposal of ash can
lead to material liability.
Climate Change. One by-product of burning coal
is carbon dioxide, which is considered a greenhouse gas and is a
major source of concern with respect to global warming. In
November 2004, Russia ratified the Kyoto Protocol to the 1992
Framework Convention on Global Climate Change, which establishes
a binding set of emission targets for greenhouse gases. With
Russias accedence, the Kyoto Protocol became binding on
all those countries that had ratified it in February 2005. To
date, the United States has refused to ratify the Kyoto
Protocol. Although the targets vary from country to country, if
the United States were to ratify the Kyoto Protocol our nation
would be required to reduce greenhouse gas emissions to 93% of
1990 levels from 2008 to 2012. Canada, which accounted for
approximately 3.4% of our sales volume in 2007, ratified the
Kyoto Protocol in 2002. Under the Kyoto Protocol, Canada will be
required to cut greenhouse gas emissions to 6% below 1990 levels
in 2008 to 2012, either in direct reductions in emissions or by
obtaining credits through market mechanisms. This requirement
could result in reduced demand for our coal by Canadian power
plants.
Future regulation of greenhouse gases in the United States could
occur pursuant to future U.S. treaty obligations, statutory
or regulatory changes under the Clean Air Act, federal or state
adoption of a greenhouse gas regulatory scheme, or otherwise. In
2002, the Conference of New England Governors and Eastern
Canadian Premiers adopted a Climate Change Action Plan, calling
for reduction in regional greenhouse emissions to 1990 levels by
2010, and a further reduction of at least 10% below 1990 levels
by 2020. 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 signed onto RGGI in July
2006. The RGGI final model rule was issued in August 2006, and
the participating states are developing their state rules.
Climate change developments are also taking place in western
states. In September 2006, California adopted greenhouse gas
legislation that prohibits long-term baseload generators from
having a greenhouse gas emissions rate greater than that of
combined cycle natural gas generator and that allows for
long-term deals with generators that sequester carbon emissions.
In January 2007, the California Public Utility Commission
adopted interim greenhouse gas standards requiring all new
long-term power contracts to serve baseload capacity in
California to have emissions no higher than a combined-cycle gas
turbine plant. In February 2007, the governors of Arizona,
California, New Mexico, Oregon and Washington launched the
Western Climate Initiative in an effort to develop a regional
strategy for addressing climate change. The goal of the Western
Climate Initiative is to identify, evaluate and implement
collective and cooperative methods of reducing greenhouse gases
in the region. In the spring of 2007, the governor of Utah and
the premiers of British Columbia and Manitoba joined the
initiative, and other states and provinces participate as
observers.
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In January 2007, eight midwestern states (Illinois, Indiana,
Iowa, Michigan, Minnesota, Missouri, Ohio and Wisconsin) agreed
to support a voluntary registry for greenhouse gases. In
November 2007, the governors of Illinois, Indiana, Iowa, Kansas,
Michigan, Minnesota, Ohio, South Dakota and Wisconsin and the
premier of Manitoba signed the Midwestern Greenhouse Gas
Reduction Accord to develop and implement steps to reduce
greenhouse gas emissions. These and other state climate change
rules will likely require additional controls on coal-fueled
power plants and industrial boilers and may even cause some
users of coal to switch from coal to a lower carbon fuel. There
can be no assurance at this time that a carbon dioxide cap and
trade program, a carbon tax or other regulatory regime, if
implemented by the states in which our customers operate, will
not affect the future market for coal in those regions.
Increased efforts to control greenhouse gas emissions could
result in reduced demand for coal.
Endangered Species. The Endangered Species Act
and other related federal and state statutes protect species
threatened or endangered with possible extinction. Protection of
threatened, endangered and other special status 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
or other related laws or regulations. 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. We have been able to continue our operations within the
existing spatial, temporal and other restrictions associated
with special status species. Should more stringent protective
measures be applied to threatened, endangered or other special
status species or to their critical habitat, then we could
experience increased operating costs or difficulty in obtaining
future mining permits. The federal government is currently
considering whether to add polar bears to the list of endangered
species. If the polar bear is listed as an endangered species,
then that action could result in regulation of carbon dioxide
emissions to address global warming. Limits on emissions of
carbon dioxide could result in coal becoming a less attractive
fuel source and could reduce the amount of coal our customers
purchase from us.
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 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 25, 2008, we employed a total of approximately
4,030 persons, approximately 220 of whom are
represented by the Scotia Employees Association. We believe that
our relations with all employees are good.
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Executive
Officers
The following is a list of our executive officers, their ages as
of February 25, 2008 and their positions and offices during
the last five years:
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Age
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Position
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C. Henry Besten, Jr.
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59
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Mr. Besten has served as our Senior Vice
President-Strategic Development since 2002.
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John W. Eaves
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50
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Mr. Eaves has served as our President and Chief Operating
Officer since April 2006. Mr. Eaves has also been a
director since February 2006. From 2002 to April 2006,
Mr. Eaves served as our Executive Vice President and Chief
Operating Officer. Mr. Eaves also serves on the board of
directors of ADA-ES, Inc.
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Sheila B. Feldman
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53
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Ms. Feldman has served as our Vice President-Human
Resources 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 U.S. 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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51
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Mr. Jones has served as our Vice President-Law, General
Counsel and Secretary since 2000.
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Paul A. Lang
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47
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Mr. Lang has served as our Senior Vice President-Operations
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.
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Steven F. Leer
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55
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Mr. Leer has served as our Chairman and Chief Executive
Officer since April 2006. 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.
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Robert J. Messey
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62
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Mr. Messey has served as our Senior Vice President and
Chief Financial Officer since 2000. Mr. Messey also serves
on the board of directors of Baldor Electric Company and
Stereotaxis, Inc.
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David B. Peugh
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53
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Mr. Peugh has served as our Vice President-Business
Development since 1995
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Deck S. Slone
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44
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Mr. Slone has served as our Vice President-Investor
Relations and Public Affairs since 2001.
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David N. Warnecke
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52
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Mr. Warnecke has served as our Vice President-Marketing and
Trading since August 2005. From June 2005 until March 2007,
Mr. Warnecke served as President of our Arch Coal Sales
Company, Inc. subsidiary, and from April 2004 until June 2005,
Mr. Warnecke served as Executive Vice President of Arch
Coal Sales Company, Inc. Prior to June 2004, Mr. Warnecke
was Senior Vice President-Sales, Trading and Transportation of
Arch Coal Sales Company, Inc.
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We submitted our most recent chief executive officer
certification to the New York Stock Exchange on May 23,
2007.
22
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.
Risks
Related to Our Business
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A
substantial or extended decline in coal prices could negatively
affect our profitability and the value of our coal
reserves.
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Our profitability and the value of our coal reserves depend upon
the prices we receive for our coal. In turn, the prices we
receive for our coal depend upon factors beyond our control,
including the following:
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the supply of and demand for domestic and foreign coal;
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the demand for electricity and steel;
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domestic and foreign governmental regulations and taxes,
including those establishing air emission standards for
coal-fueled power plants;
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regulatory, administrative and judicial decisions, including
those affecting future mining permits;
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the proximity, capacity and cost of transportation facilities;
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the availability and price of alternative fuels, such as natural
gas, and alternative energy sources, such as hydroelectric, wind
and solar power;
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technological developments, including those intended to convert
coal to liquid or gas and those aimed at capturing and
sequestering carbon; and
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the effects of worldwide energy conservation measures.
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Declines in the prices we receive for our coal could adversely
affect our profitability and the value of our coal reserves.
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Certain
conditions and events beyond our control could negatively impact
our coal mining operations, our production or our operating
costs.
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We mine coal at underground and surface mining operations.
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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delays and difficulties in acquiring, maintaining or renewing
necessary permits or mining or surface rights;
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23
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changes or 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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adverse weather and natural disasters, such as heavy rains or
snow and flooding;
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shortage of qualified labor;
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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.
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If any of these conditions or events occurs, particularly at our
Black Thunder mining complex, 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 costs of mining and other industrial supplies, including
steel-based supplies, diesel fuel and rubber tires, or the
inability to obtain a sufficient quantity of those supplies,
could negatively affect our operating costs or disrupt or delay
our production.
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Our coal mining operations use significant amounts of steel,
diesel fuel, rubber tires and other mining and industrial
supplies. 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 mining complex. 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 mining and
other industrial supplies, particularly steel-based supplies,
diesel fuel and rubber tires, increase, our operating costs
could be negatively affected. In addition, if we are unable to
procure these supplies, our coal mining operations may be
disrupted or we could experience a delay or halt in our
production.
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Our
labor costs could increase if the shortage of skilled coal
mining workers continues.
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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 or purchased from other third parties could
temporarily impair our ability to fill customer orders or
increase our operating costs.
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We use independent contractors to mine coal at certain of our
mining complexes, including select operations at our Coal-Mac
and Cumberland River mining complexes. In addition, we purchase
coal from third parties that we sell to our customers.
Operational difficulties at contractor-operated mines or mines
operated by third parties from whom we purchase coal, changes in
demand for contract miners from other coal producers
24
and other factors beyond our control could affect the
availability, pricing, and quality of coal produced for or
purchased by us. Disruptions in the quantities of coal produced
for or purchased by us 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.
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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. 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.
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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
require us to pay 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.
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We depend upon barge, ship, 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.
25
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We may
be unable to realize the benefits we expect to occur as a result
of acquisitions that we undertake.
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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.
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We sell a portion of our coal under long-term coal supply
agreements, which we define as contracts with terms 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 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 A substantial
or extended decline in coal prices could negatively affect our
profitability and the value of our coal reserves, 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 13.
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The
loss of, or significant reduction in, purchases by our largest
customers could adversely affect our
profitability.
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For the year ended December 31, 2007, we derived
approximately 25.3% of our total coal revenues from sales to our
three largest customers, Tennessee Valley Authority, Ameren
Corporation and Intermountain Power Agency, and approximately
49.5% of our total coal revenues from sales to our ten largest
customers. At December 31, 2007, we had coal supply
agreements with those ten customers that expire at various times
from 2008 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.
26
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.
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At December 31, 2007, we had consolidated indebtedness of
approximately $1.3 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.
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 significantly affect:
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our ability to satisfy debt covenants and debt service, lease
payment and other obligations;
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our ability to generate cash flow from operations or to obtain
additional financing;
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our credit ratings;
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our flexibility in planning for, or reacting to, changes in our
business and the industry in which we compete; and
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our competitiveness when compared to competitors with less debt.
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We may
be unable to comply with restrictions imposed by our credit
facilities and other financing arrangements.
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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. For more information about
some of the restrictions contained in our credit facilities,
leases and other financial arrangements, you should see
Liquidity and Capital Resources beginning on
page 46.
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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.
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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
27
could affect our ability to secure reclamation and coal lease
obligations and, therefore, our ability to mine or lease coal.
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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.
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We have agreed to guarantee Magnums obligations to supply
coal under certain coal sales contracts that we sold to Magnum.
In addition, we have agreed to purchase coal from Magnum in
order to satisfy our obligations under certain other contracts
that have not yet been transferred to Magnum, the longest of
which extends to the year 2017. 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. At December 31, 2007, if we had purchased
the 20.4 million tons of coal required under these
contracts over their duration at market prices then in effect,
we would have incurred a loss of approximately
$363.1 million.
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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.
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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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Governmental
regulations impose significant costs on us and our customers,
and future regulations could increase those costs or limit our
ability to produce and sell coal.
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Governmental regulations, including those related to the matters
listed below, have significant effects on the coal mining
industry:
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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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air quality standards;
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water pollution;
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the discharge of materials into the environment;
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management of materials generated by mining operations;
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surface subsidence from underground mining;
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statutorily mandated benefits for current and retired coal
miners;
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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.
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28
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.
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 our business or our
customers, may also require us or our customers to change
operations significantly or incur increased costs. These
regulations, if enacted in the future, could have a material
adverse effect on our business, financial condition and results
of operations.
You should see Safety and Environmental Regulations
beginning on page 14 for more information about the various
governmental regulations affecting us.
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Our
failure to obtain and renew permits necessary for our mining
operations could negatively affect our business.
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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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The
characteristics of coal may make it difficult for coal users to
comply with various environmental standards related to coal
combustion or utilization. As a result, coal users may switch to
other fuels, which could affect the volume of our sales and the
price of our products.
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Coal contains impurities, including but not limited to sulfur,
mercury, chlorine, carbon and other elements or compounds, many
of which are released into the air when coal is burned. Stricter
environmental regulations of emissions from coal-fueled power
plants could increase the costs of using coal thereby reducing
demand for coal as a fuel source and the volume and price of our
coal sales. Stricter regulations could make coal a less
attractive fuel alternative in the planning and building of
power plants in the future.
Proposed reductions in emissions of mercury, sulfur dioxides,
nitrogen oxides, particulate matter or greenhouse gases may
require the installation of costly emission control technology
or the implementation of other measures, including trading of
emission allowances and switching to other fuels. For example,
in order to meet the federal Clean Air Act limits for sulfur
dioxide emissions from power plants, coal users may need to
install scrubbers, use sulfur dioxide emission allowances (some
of which they may purchase), blend high sulfur coal with
low-sulfur coal or switch to other fuels. Reductions in mercury
emissions required by certain states will likely require some
power plants to install new equipment, at substantial cost, or
discourage the use of certain coals containing higher levels of
mercury. Recent and new proposals calling for reductions in
emissions of carbon dioxide and other greenhouse gases could
significantly increase the cost of operating existing
coal-fueled power
29
plants and could inhibit construction of new coal-fueled power
plants. Existing or proposed legislation focusing on emissions
enacted by the United States or individual states could make
coal a less attractive fuel alternative for our customers and
could impose a tax or fee on the producer of the coal. If our
customers decrease the volume of coal they purchase from us or
switch to alternative fuels as a result of existing or future
environmental regulations aimed at reducing emissions, our
operations and financial results could be adversely impacted.
|
|
|
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.
|
|
|
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
30
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 Item 3
Legal Proceedings beginning on page 33 for more
information about the litigation described above.
|
|
ITEM 1B.
|
UNRESOLVED
STAFF COMMENTS.
|
None.
At December 31, 2007, we owned or controlled primarily
through long-term leases approximately 99,700 acres of coal
land in West Virginia, 100,300 acres of coal land in
Wyoming, 98,700 acres of coal land in Illinois,
61,100 acres of coal land in Utah, 47,300 acres of
coal land in Kentucky, 21,800 acres of coal land in New
Mexico and 18,500 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 114,200 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 are subject to
readjustment
and/or
extension and to earlier termination for failure to meet
diligent development requirements. Certain of our 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
92,900 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 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, 2007. Recoverable reserves include
only saleable coal and do not 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 our estimated assigned and
unassigned recoverable coal reserves at December 31, 2007:
Total
Assigned Reserves
(Tons in
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assigned
|
|
|
|
|
|
|
|
|
Sulfur Content
|
|
|
|
|
|
Reserve Control
|
|
|
Mining Method
|
|
|
Past Reserve Estimates
|
|
|
|
Recoverable
|
|
|
|
|
|
|
|
|
(lbs. per million Btus)
|
|
|
As Received
|
|
|
|
|
|
|
|
|
|
|
|
Under-
|
|
|
|
|
|
|
|
|
|
Reserves
|
|
|
Proven
|
|
|
Probable
|
|
|
<1.2
|
|
|
1.2-2.5
|
|
|
>2.5
|
|
|
Btus per lb.(1)
|
|
|
Leased
|
|
|
Owned
|
|
|
Surface
|
|
|
ground
|
|
|
2005
|
|
|
2006
|
|
|
Wyoming
|
|
|
1,549
|
|
|
|
1,508
|
|
|
|
41
|
|
|
|
1,504
|
|
|
|
45
|
|
|
|
|
|
|
|
8,856
|
|
|
|
1,534
|
|
|
|
15
|
|
|
|
1,549
|
|
|
|
|
|
|
|
1,748
|
|
|
|
1,655
|
|
Utah
|
|
|
103
|
|
|
|
60
|
|
|
|
43
|
|
|
|
91
|
|
|
|
12
|
|
|
|
|
|
|
|
11,399
|
|
|
|
102
|
|
|
|
1
|
|
|
|
|
|
|
|
103
|
|
|
|
108
|
|
|
|
110
|
|
Colorado
|
|
|
79
|
|
|
|
60
|
|
|
|
19
|
|
|
|
79
|
|
|
|
|
|
|
|
|
|
|
|
11,695
|
|
|
|
78
|
|
|
|
1
|
|
|
|
|
|
|
|
79
|
|
|
|
74
|
|
|
|
67
|
|
Central App
|
|
|
169
|
|
|
|
160
|
|
|
|
9
|
|
|
|
59
|
|
|
|
109
|
|
|
|
1
|
|
|
|
12,816
|
|
|
|
162
|
|
|
|
7
|
|
|
|
74
|
|
|
|
95
|
|
|
|
243
|
|
|
|
216
|
|
Illinois
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,900
|
|
|
|
1,788
|
|
|
|
112
|
|
|
|
1,733
|
|
|
|
166
|
|
|
|
1
|
|
|
|
9,465
|
|
|
|
1,876
|
|
|
|
24
|
|
|
|
1,623
|
|
|
|
277
|
|
|
|
2,186
|
|
|
|
2,048
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
As received Btus per lb. includes
the weight of moisture in the coal on an as sold basis.
|
31
Total
Unassigned Reserves
(Tons in
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unassigned
|
|
|
|
|
|
|
|
|
Sulfur Content
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recoverable
|
|
|
|
|
|
|
|
|
(lbs. per million Btus)
|
|
|
As Received
|
|
|
Reserve Control
|
|
|
Mining Method
|
|
|
|
Reserves
|
|
|
Proven
|
|
|
Probable
|
|
|
<1.2
|
|
|
1.2-2.5
|
|
|
>2.5
|
|
|
Btus per lb.(1)
|
|
|
Leased
|
|
|
Owned
|
|
|
Surface
|
|
|
Underground
|
|
|
Wyoming
|
|
|
398
|
|
|
|
301
|
|
|
|
97
|
|
|
|
351
|
|
|
|
47
|
|
|
|
|
|
|
|
9,653
|
|
|
|
307
|
|
|
|
91
|
|
|
|
224
|
|
|
|
174
|
|
Utah
|
|
|
35
|
|
|
|
16
|
|
|
|
19
|
|
|
|
31
|
|
|
|
4
|
|
|
|
|
|
|
|
10,842
|
|
|
|
34
|
|
|
|
1
|
|
|
|
|
|
|
|
35
|
|
Colorado
|
|
|
49
|
|
|
|
39
|
|
|
|
10
|
|
|
|
47
|
|
|
|
2
|
|
|
|
|
|
|
|
11,597
|
|
|
|
48
|
|
|
|
1
|
|
|
|
|
|
|
|
49
|
|
Central App
|
|
|
169
|
|
|
|
121
|
|
|
|
48
|
|
|
|
46
|
|
|
|
100
|
|
|
|
23
|
|
|
|
12,779
|
|
|
|
137
|
|
|
|
32
|
|
|
|
41
|
|
|
|
128
|
|
Illinois
|
|
|
376
|
|
|
|
270
|
|
|
|
106
|
|
|
|
|
|
|
|
|
|
|
|
376
|
|
|
|
11,605
|
|
|
|
58
|
|
|
|
318
|
|
|
|
2
|
|
|
|
374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,027
|
|
|
|
747
|
|
|
|
280
|
|
|
|
475
|
|
|
|
153
|
|
|
|
399
|
|
|
|
11,016
|
|
|
|
584
|
|
|
|
443
|
|
|
|
267
|
|
|
|
760
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
As received Btus per lb. includes
the weight of moisture in the coal on an as sold basis.
|
At December 31, 2007, approximately 16% 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. 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 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 75.4% consist of compliance coal, or
coal which emits 1.2 pounds or less of sulfur dioxide per
million Btus upon combustion, while an additional 6.6% could be
sold as low-sulfur coal. The balance is classified as
high-sulfur coal. Most of our reserves are suitable for the
domestic steam coal markets. A substantial portion of the
low-sulfur and compliance coal reserves at the Cumberland River,
Lone Mountain and Mountain Laurel mining complexes may also be
used as metallurgical coal.
The carrying cost of our coal reserves at December 31, 2007
was $1.2 billion, consisting of $127.2 million of
prepaid royalties and a net book value of coal lands and mineral
rights of $1.1 billion.
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 24,900 acres of property to other
coal operators in 2007. We received royalty income of
$5.6 million in 2007 from the mining of approximately
2.1 million tons, $5.0 million in 2006 from the mining
of approximately 2.4 million tons and $7.1 million in
2005 from the mining of approximately 3.0 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.
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
32
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 2008.
|
|
ITEM 3.
|
LEGAL
PROCEEDINGS.
|
We are involved in various claims and legal actions arising in
the ordinary course of business, including employee injury
claims. After conferring with counsel, it is the opinion of
management that the ultimate resolution of 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.
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 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.
Plaintiffs were later allowed to amend their complaint to add
challenges to permits issued to our Coal-Mac, Inc. and Mingo
Logan Coal Company subsidiaries, but those claims have not
advanced. Rather, the court proceeded first on the earlier
challenge to four permits of companies unrelated to us.
The court proceeded to rule on the challenges to those four
permits in orders of March 23 and June 13, 2007. In the
first of those orders, the court rescinded the four permits,
finding that the Corps had inadequately assessed the likely
impact of valley fills on headwater streams and had relied on
inadequate or unproven mitigation to offset those impacts. That
ruling could require the Corps to prepare environmental impact
statements on those permits, which would slow the permit
process. The ruling could, as a practical matter, affect our
Coal-Mac and other future permits, but the Corps has already
done an environmental impact statement on the Mingo Logan
permit. In the second order, the court entered a declaratory
judgment that discharges of sediment from the valley fills into
sediment control ponds constructed in-stream to control that
sediment must themselves be permitted and meet the limits
imposed on discharges from these ponds. Unless reversed, that
ruling will likely complicate the ability to construct sediment
ponds in steep-sloped areas where in-stream locations are
frequently the only practicable ones. Both of the district court
rulings are on appeal to the Fourth Circuit Court of Appeals,
and a decision is expected from that court in 2008.
While the court was considering the challenge to the four
permits unrelated to our operating subsidiaries, the plaintiffs
were permitted to add challenges to our Coal-Mac, Inc. and Mingo
Logan Coal Company subsidiaries. Plaintiffs sought preliminary
inunctions as to both operations, but later reached agreements
with our operating subsidiaries that have allowed mining to
progress in limited areas while the district courts
rulings are on appeal.
West
Virginia Flooding Litigation
Over 3,000 plantiffs have sued us and more than 180 other
defendants in Wyoming, McDowell, Fayette, Kanawha, Raleigh,
Boone and Mercer Counties, West Virginia 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,
33
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, following the Mullins/Oceana phase I trial, in
which we were not involved, the jury returned a verdict against
the two non-settling defendants. However, the court set aside
that verdict and granted judgment in favor of the defendants.
The plaintiffs in that trial group have appealed that decision,
and we, along with other defendants, have filed an amicus brief
in that appeal. We were previously named in cases involving the
Coal River watershed; however, on January 18, 2007, the
court dismissed the plaintiffs claims involving that
watershed for failure to state a claim. This ruling has also
been appealed. We are also named in the remaining Upper
Guyandotte watershed trial group. A trial date has not yet been
set for that group.
|
|
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 2007.
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 25,
2008, our common stock closed at $54.90 on the New York Stock
Exchange. On that date, there were approximately
8,200 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 $38.7 million, or $0.27 per
share, in 2007 and $31.4 million, or $0.22 per share, in
2006. 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. You
should see Liquidity and Capital Resources beginning
on page 46 for more information about restrictions on our
ability to declare dividends.
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
|
December 31
|
|
|
Dividends per common share
|
|
$
|
0.06
|
|
|
$
|
0.07
|
|
|
$
|
0.07
|
|
|
$
|
0.07
|
|
High
|
|
|
33.79
|
|
|
|
42.59
|
|
|
|
37.00
|
|
|
|
45.22
|
|
Low
|
|
|
27.18
|
|
|
|
30.33
|
|
|
|
27.76
|
|
|
|
32.99
|
|
Close
|
|
|
30.69
|
|
|
|
34.80
|
|
|
|
33.74
|
|
|
|
44.93
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
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 two indices: a peer group, consisting of CONSOL
Energy, Inc., Foundation Coal Holdings, Inc., Massey Energy
Company and Peabody Energy Corp., and the Standard &
Poors (S&P) 400 (Midcap) Index. The graph assumes
that:
|
|
|
|
|
you invested $100 in Arch Coal common stock and in each index at
the closing price on December 31, 2002;
|
|
|
|
all dividends were reinvested;
|
|
|
|
annual reweighting of the peer groups; and
|
|
|
|
you continued to hold your investment through December 31,
2007.
|
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 common stock.
5-Year
Total Stockholder Return
Arch Coal, Inc. v. S&P 400 (Midcap) Index and Industry
Peer Group
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2002
|
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
Arch Coal, Inc.
|
|
$
|
100
|
|
|
$
|
146
|
|
|
$
|
168
|
|
|
$
|
377
|
|
|
$
|
287
|
|
|
$
|
432
|
|
S&P 400 (Midcap)
|
|
|
100
|
|
|
|
136
|
|
|
|
158
|
|
|
|
178
|
|
|
|
196
|
|
|
|
212
|
|
Industry Peer Group
|
|
|
100
|
|
|
|
163
|
|
|
|
286
|
|
|
|
482
|
|
|
|
447
|
|
|
|
806
|
|
35
Issuer
Purchases of Equity Securities
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. As of December 31, 2007, we have purchased
1,562,400 shares of our common stock under this program. We
did not purchase any shares of our common stock under this
program during the quarter ended December 31, 2007. Based
on the closing price of our common stock as reported on the New
York Stock Exchange on February 25, 2008, there is
approximately $682.8 million of our common stock that may
yet be purchased under this program.
|
|
ITEM 6.
|
SELECTED
FINANCIAL DATA.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(1)
|
|
|
(2) (3)
|
|
|
(2) (3) (4) (5)
|
|
|
(4) (6) (7)
|
|
|
(4) (7) (8)
|
|
|
|
(Amounts in thousands, except per share data)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales revenue
|
|
$
|
2,413,644
|
|
|
$
|
2,500,431
|
|
|
$
|
2,508,773
|
|
|
$
|
1,907,168
|
|
|
$
|
1,435,488
|
|
Income from operations
|
|
|
229,617
|
|
|
|
336,667
|
|
|
|
77,857
|
|
|
|
178,046
|
|
|
|
40,371
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of accounting change
|
|
|
174,929
|
|
|
|
260,931
|
|
|
|
38,123
|
|
|
|
113,706
|
|
|
|
20,340
|
|
Cumulative effect of accounting change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,654
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
174,929
|
|
|
|
260,931
|
|
|
|
38,123
|
|
|
|
113,706
|
|
|
|
16,686
|
|
Preferred stock dividends
|
|
|
(219
|
)
|
|
|
(378
|
)
|
|
|
(15,579
|
)
|
|
|
(7,187
|
)
|
|
|
(6,589
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
174,710
|
|
|
$
|
260,553
|
|
|
$
|
22,544
|
|
|
$
|
106,519
|
|
|
$
|
10,097
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per common share before cumulative effect of
accounting change
|
|
$
|
1.23
|
|
|
$
|
1.83
|
|
|
$
|
0.18
|
|
|
$
|
0.95
|
|
|
$
|
0.13
|
|
Diluted earnings per common share before cumulative effect of
accounting change
|
|
|
1.21
|
|
|
|
1.80
|
|
|
|
0.17
|
|
|
|
0.89
|
|
|
|
0.13
|
|
Basic earnings per common share
|
|
|
1.23
|
|
|
|
1.83
|
|
|
|
0.18
|
|
|
|
0.95
|
|
|
|
0.10
|
|
Diluted earnings per common share
|
|
|
1.21
|
|
|
|
1.80
|
|
|
|
0.17
|
|
|
|
0.89
|
|
|
|
0.10
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,594,599
|
|
|
$
|
3,320,814
|
|
|
$
|
3,051,440
|
|
|
$
|
3,256,535
|
|
|
$
|
2,387,649
|
|
Working capital
|
|
|
(35,370
|
)
|
|
|
46,471
|
|
|
|
216,376
|
|
|
|
355,803
|
|
|
|
237,007
|
|
Long-term debt, less current maturities
|
|
|
1,085,579
|
|
|
|
1,122,595
|
|
|
|
971,755
|
|
|
|
1,001,323
|
|
|
|
700,022
|
|
Other long-term obligations
|
|
|
420,819
|
|
|
|
391,819
|
|
|
|
382,256
|
|
|
|
800,332
|
|
|
|
722,954
|
|
Stockholders equity
|
|
|
1,531,686
|
|
|
|
1,365,594
|
|
|
|
1,184,241
|
|
|
|
1,079,826
|
|
|
|
688,035
|
|
Common Stock Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends per share
|
|
$
|
0.2700
|
|
|
$
|
0.2200
|
|
|
$
|
0.1600
|
|
|
$
|
0.1488
|
|
|
$
|
0.1152
|
|
Shares outstanding at year-end
|
|
|
143,158
|
|
|
|
142,179
|
|
|
|
142,741
|
|
|
|
125,716
|
|
|
|
106,410
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
$
|
330,810
|
|
|
$
|
308,102
|
|
|
$
|
254,607
|
|
|
$
|
148,728
|
|
|
$
|
162,361
|
|
Depreciation, depletion and amortization
|
|
|
242,062
|
|
|
|
208,354
|
|
|
|
212,301
|
|
|
|
166,322
|
|
|
|
158,464
|
|
Capital expenditures
|
|
|
488,363
|
|
|
|
623,187
|
|
|
|
357,142
|
|
|
|
292,605
|
|
|
|
132,427
|
|
Dividend payments
|
|
|
38,945
|
|
|
|
31,815
|
|
|
|
27,639
|
|
|
|
24,043
|
|
|
|
17,481
|
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
135,010
|
|
|
|
134,976
|
|
|
|
140,202
|
|
|
|
123,060
|
|
|
|
100,634
|
|
Tons produced
|
|
|
126,624
|
|
|
|
126,015
|
|
|
|
129,685
|
|
|
|
115,861
|
|
|
|
93,966
|
|
Tons purchased from third parties
|
|
|
8,495
|
|
|
|
10,092
|
|
|
|
11,226
|
|
|
|
12,572
|
|
|
|
6,602
|
|
|
|
|
(1)
|
|
On June 29, 2007, we sold
select assets and related liabilities associated with our Mingo
Logan-Ben Creek mining complex in West Virginia for
$43.5 million. We recognized a net gain of
$8.9 million in 2007 resulting from the sale.
|
|
(2)
|
|
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 idling resulted in $30.0 million of lost profits during
the first quarter of 2006, in
|
36
|
|
|
|
|
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.
|
|
(3)
|
|
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.
|
|
(4)
|
|
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 reflect the split.
|
|
(5)
|
|
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.
|
|
(6)
|
|
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.
|
|
(7)
|
|
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.
|
|
(8)
|
|
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
We are one of the largest coal producers in the United States.
For the year ended December 31, 2007, we sold approximately
135.0 million tons of coal, including approximately
8.6 million tons of coal we purchased from third parties,
fueling approximately 6% of all electricity generated in the
United States. Since federal and state environmental regulations
limit the amount of sulfur dioxide that power plants may emit,
we believe demand for low sulfur coal exceeds demand for other
types of coal. As a result, we focus on mining, processing and
marketing bituminous and sub-bituminous coal with low sulfur
content for sale to domestic power plants, steel mills and
industrial facilities.
In 2007, we estimate that U.S. coal consumption rose by
approximately 2% to 1.2 billion tons, according to
estimates provided by the EIA. Conversely, according to the EIA,
domestic coal production declined by approximately 1.5% in 2007.
In 2008, we expect continued growth in electricity demand,
although at lower levels than in 2007 given the forecast for
slower U.S. economic growth. In addition, we expect
strengthening global demand for coal to increase U.S. coal
exports, particularly as traditional coal export countries, such
as Australia, China and South Africa, experience mine, port,
rail and labor challenges. We estimate that higher domestic coal
demand and higher coal exports, together with decreased
production particularly in the Central Appalachia region of the
United States, will adversely affect the availability of
domestic coal in the coming years and result in upward pressure
on domestic coal prices. As such, 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, 2007, our expected unpriced production
approximated 15 million to 25 million tons in 2008,
85 million to 95 million tons in 2009 and
95 million to 105 million tons in 2010.
The locations of our mines enable us to ship coal to most of the
major coal-fired power plants in the United States. 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.
37
The Powder River Basin is located in northeastern Wyoming and
southeastern Montana. The coal we mine from surface operations
in this region has a very low sulfur content and a low heat
value compared to the other regions in which we operate. 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. Because Powder River Basin coal is
generally lower in heat value, some power plants must blend it
with higher Btu coal or retrofit existing coal plants to
accommodate Powder River Basin coal. The Western Bituminous
region includes western Colorado, eastern Utah and southwestern
Wyoming. Coal we mine from underground mines in this region
typically has a low sulfur content and varies in heat value.
Central Appalachia includes eastern Kentucky, Virginia and
southern West Virginia. Coal we mine from both surface and
underground mines in this region generally has a high heat value
and low sulfur content. In addition, a portion of the coal we
produce in the Central Appalachia region consists of
metallurgical coal. We are typically able to sell metallurgical
coal to customers in the steel industry at prices that exceed
the price we are able to sell steam coal to power plants and
industrial facilities because metallurgical coal has high heat
content, low expansion pressure, low sulfur content and various
other chemical attributes.
In 2007, we continued the efforts we had begun in prior periods
aimed at positioning our operations for increasing global and
domestic coal demand. During the first half of 2007, we
installed a replacement longwall at our Sufco mining complex in
Utah. In addition, we began construction of a new loadout
facility at our Black Thunder mining complex in Wyoming. This
facility, which we have strategically located in relation to the
direction of our mining activities, will replace the facility
that we currently lease from a third party under an agreement
set to expire within the next year. In 2007, we also continued
development of a new reserve area at our West Elk mining complex
in Colorado and commenced production at our Mountain Laurel
mining complex in Central Appalachia. Coal produced at our
lower-cost Mountain Laurel mining complex will replace the coal
we have historically produced at the higher-cost Mingo Logan-Ben
Creek mining complex that we sold to a subsidiary of Alpha
Natural Resources at the end of the first half of 2007. We also
expect that the opening of the Mountain Laurel complex will
enable us to take advantage of increasing global metallurgical
coal demand.
Items Affecting
Comparability of Reported Results
The comparability of our operating results for the years ended
December 31, 2007, 2006 and 2005 is affected by the
following significant items:
Sale of Mingo Logan-Ben Creek mining complex
On June 29, 2007, we sold selected assets and related
liabilities associated with our Mingo Logan-Ben Creek mining
complex in West Virginia to a subsidiary of Alpha Natural
Resources, Inc. for $43.5 million. During the year ended
December 31, 2007, our Ben Creek operations contributed
coal sales of 1.2 million tons, revenues of
$75.1 million and income from operations of
$9.1 million. During the year ended December 31, 2006,
our Ben Creek operations contributed coal sales of
4.0 million tons, revenues of $243.8 million and
income from operations of $19.5 million. During the year
ended December 31, 2005, our Ben Creek operations
contributed coal sales of 4.7 million tons, revenues of
$261.5 million, and income from operations of
$15.2 million. We recognized a net gain of
$8.9 million in the year ended December 31, 2007
resulting from this transaction, net of accrued losses of
$12.5 million on firm commitments to purchase coal through
2008 to supply below-market sales contracts that can no longer
be sourced from our operations and $4.9 million of
employee-related payments. We recorded the gain as a component
of other operating income, net.
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. The three
subsidiaries were Hobet Mining, Inc., Apogee Coal Company and
Catenary Coal Company, which included the Hobet 21, Arch of West
Virginia, Samples and Campbells Creek mining complexes. For the
year ended December 31, 2005, these complexes sold
12.7 million tons of coal, had revenues of
$509.8 million and incurred a loss from operations of
$8.3 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
38
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.
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 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 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 September
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. We are recognizing the deferred gain over the
term of the lease.
West Elk combustion event A
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.
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. Prior to
2006, 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.
Results
of Operations
Year
Ended December 31, 2007 Compared to Year Ended
December 31, 2006
Summary. Our results during 2007 when compared
to 2006 were affected primarily by changes in our regional sales
mix; weaker market conditions; higher depreciation, depletion
and amortization, higher cash costs in the Powder River Basin;
the net effect of the insurance proceeds we recorded in 2006
related to the West Elk idling and the effect of the idling in
the first quarter of 2006; and an increase in interest expense.
In response to the soft market conditions, we reduced production
volume targets in all operating segments in 2007.
Revenues. The following table summarizes
information about coal sales during the year ended
December 31, 2007 and compares those results to the
comparable information for the year ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
Increase (Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
Amount
|
|
|
%
|
|
|
|
(Amounts in thousands, except per ton data)
|
|
|
Coal sales
|
|
$
|
2,413,644
|
|
|
$
|
2,500,431
|
|
|
$
|
(86,787
|
)
|
|
|
(3.5
|
)%
|
Tons sold
|
|
|
135,010
|
|
|
|
134,976
|
|
|
|
34
|
|
|
|
|
|
Coal sales realization per ton sold
|
|
$
|
17.88
|
|
|
$
|
18.53
|
|
|
$
|
(0.65
|
)
|
|
|
(3.5
|
)%
|
Coal sales. Coal sales decreased from 2006 to
2007 primarily due to changes in our segment mix, despite flat
overall sales volume. An increase in Powder River Basin sales
volumes and a decrease in Central Appalachia sales volumes
resulted in a lower average sales price because Powder River
Basin coal has a lower average sales
39
price per ton than Central Appalachia coal. We have provided
more information about the tons sold and the coal sales
realizations per ton by operating segment under the heading
Operating segment results on page 41.
Expenses, costs and other. The following table
summarizes expenses, costs and other operating income, net for
the year ended December 31, 2007 and compares those results
to the comparable information for the year ended
December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31
|
|
|
in Net Income
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Cost of coal sales
|
|
$
|
1,888,285
|
|
|
$
|
1,909,822
|
|
|
$
|
21,537
|
|
|
|
1.1
|
%
|
Depreciation, depletion and amortization
|
|
|
242,062
|
|
|
|
208,354
|
|
|
|
(33,708
|
)
|
|
|
(16.2
|
)
|
Selling, general and administrative expenses
|
|
|
84,446
|
|
|
|
75,388
|
|
|
|
(9,058
|
)
|
|
|
(12.0
|
)
|
Other operating income, net
|
|
|
(30,766
|
)
|
|
|
(29,800
|
)
|
|
|
966
|
|
|
|
3.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,184,027
|
|
|
$
|
2,163,764
|
|
|
$
|
(20,263
|
)
|
|
|
(0.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales. Cost of coal sales
decreased from 2006 to 2007 primarily due to the effect of the
change in our segment mix, as the Powder River Basins
production costs per ton are lower than costs for our other
regions. We also purchased fewer tons to satisfy contracts we
retained after the sale to Magnum. This decrease was partially
offset by higher unit costs in the Powder River Basin, primarily
reflecting higher commodity and supplies costs, and higher unit
costs in the Western Bituminous region. Higher unit costs in the
Western Bituminous region were primarily due to the impact of
insurance proceeds we recognized in 2006 related to the West Elk
combustion-related event, which more than offset the impact of
the idling in the first quarter of 2006. We have provided more
information about our operating segments under the heading
Operating segment results on page 41.
Depreciation, depletion and amortization. The
increase in depreciation, depletion and amortization expense
from 2006 to 2007 is due primarily to the costs of ongoing
capital improvement and mine development projects that we
capitalized in 2006 and 2007 and a decrease in the amortization
of deferred gains on acquired sales contracts. We have provided
additional information concerning our capital spending in the
section entitled Liquidity and Capital Resources
beginning on page 46.
Selling, general and administrative
expenses. The increase in selling, general and
administrative expenses from 2006 to 2007 is primarily due to an
increase in the expense associated with our deferred
compensation plans, which results from changes in the value of
our common stock, as well as other employee compensation costs.
Other operating income, net. The increase in
other operating income, net in 2007 compared to 2006 is due
primarily to the following:
|
|
|
|
|
an $8.9 million gain on the 2007 sale of the Ben Creek
complex discussed previously;
|
|
|
|
a $6.0 million gain on the sale of non-core reserves in the
Powder River Basin and a $2.4 million gain on the sale of
non-core reserves in Central Appalachia, both in 2007;
|
|
|
|
unrealized gains of $5.0 million in 2007 on coal
derivatives entered into for trading purposes; and
|
|
|
|
expenses of $8.7 million during 2006 related to the Magnum
transaction.
|
These increases in other operating income are partially offset
by:
|
|
|
|
|
a decrease of $15.2 million related to realized and
unrealized gains in 2006 associated with sulfur dioxide emission
allowance put options and swaps;
|
|
|
|
a gain of $10.3 million in 2006 on the acquisition of our
interest in Knight Hawk Holdings, LLC, representing the
difference between the fair value of coal reserves we
surrendered for the interest and their carrying value; and
|
|
|
|
a decrease of $3.3 million in the amount of income from
equity investments.
|
40
Operating segment results. The following table
shows results by operating segment for the year ended
December 31, 2007 and compares those amounts to the
comparable information for the year ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
Increase (Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
Amount
|
|
|
%
|
|
|
|
(Amounts in thousands, except per ton data)
|
|
|
Powder River Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
99,145
|
|
|
|
96,246
|
|
|
|
2,899
|
|
|
|
3.0
|
%
|
Coal sales realization per ton sold(1)
|
|
$
|
10.59
|
|
|
$
|
10.82
|
|
|
$
|
(0.23
|
)
|
|
|
(2.1
|
)%
|
Operating margin per ton sold(2)
|
|
$
|
1.23
|
|
|
$
|
2.15
|
|
|
$
|
(0.92
|
)
|
|
|
(42.8
|
)%
|
Western Bituminous
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
19,362
|
|
|
|
18,122
|
|
|
|
1,240
|
|
|
|
6.8
|
%
|
Coal sales realization per ton sold(1)
|
|
$
|
24.73
|
|
|
$
|
22.42
|
|
|
$
|
2.31
|
|
|
|
10.3
|
%
|
Operating margin per ton sold(2)
|
|
$
|
5.11
|
|
|
$
|
6.86
|
|
|
$
|
(1.75
|
)
|
|
|
(25.5
|
)%
|
Central Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
16,503
|
|
|
|
20,608
|
|
|
|
(4,105
|
)
|
|
|
(19.9
|
)%
|
Coal sales realization per ton sold(1)
|
|
$
|
47.87
|
|
|
$
|
46.90
|
|
|
$
|
0.97
|
|
|
|
2.1
|
%
|
Operating margin per ton sold(2)
|
|
$
|
3.89
|
|
|
$
|
2.95
|
|
|
$
|
0.94
|
|
|
|
31.9
|
%
|
|
|
|
(1)
|
|
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,
2007, transportation costs per ton billed to customers were
$0.03 for the Powder River Basin, $3.17 for the Western
Bituminous region and $1.82 for Central Appalachia.
Transportation costs per ton billed to customers for the year
ended December 31, 2006 were $0.02 for the Powder River
Basin, $2.91 for the Western Bituminous region and $1.54 for
Central Appalachia.
|
|
(2)
|
|
Operating margin per ton is
calculated as the result of coal sales revenues less cost of
coal sales and depreciation, depletion and amortization divided
by tons sold.
|
Powder River Basin Sales volume in the Powder
River Basin increased slightly in 2007 over 2006 levels due to
increased shipments from the Coal Creek mine, which was
restarted during 2006, and higher volumes of brokerage activity.
These volumes were partially offset by a decrease at the Black
Thunder mining complex due to planned volume reductions in
response to the weaker market conditions in 2007, as well as
weather-related shipment challenges and an unplanned belt outage
that occurred in the first quarter of 2007. Decreases in sales
prices during 2007 when compared with 2006 primarily reflect the
higher volumes from the Coal Creek mining complex, which has a
lower price due to its lower heat content, and lower sulfur
dioxide emission allowance adjustments. On a per-ton basis,
operating margins in 2007 decreased from 2006 due in part to the
decrease in per-ton coal sales prices and an increase in per-ton
costs. The increase in per-ton costs resulted primarily from
higher diesel fuel prices and higher labor, tire and leasing
costs.
Western Bituminous In the Western Bituminous
region, sales volume increased during 2007 when compared with
2006, reflecting a full year of production at the West Elk and
Skyline mining complexes. The West Elk mining complex was idle
during the first quarter of 2006 after the combustion-related
event in the fourth quarter of 2005, and the Skyline longwall
commenced mining in a new reserve area in the second quarter of
2006. These increases were partially offset by the lower volumes
from planned volume reductions in response to the weaker market
conditions in 2007. Higher sales prices during 2007 represent
higher base pricing resulting from the roll-off of lower-priced
legacy contracts. Operating margins per ton for 2007 decreased
from 2006 primarily due to the impact of insurance proceeds we
recognized in 2006 related to the West Elk combustion-related
event and higher depreciation, depletion and amortization costs
resulting from the impact of the installation of a new longwall
at the Sufco mining complex. These factors offset the impact of
the improved per-ton coal sales prices. The $41.9 million
of insurance proceeds we recognized in 2006 offset the estimated
$30.0 million adverse effect of the idling in the first
quarter of 2006.
41
Central Appalachia Our sales volumes in
Central Appalachia decreased during 2007 when compared with 2006
primarily due to higher volumes of coal shipped during 2006
associated with sales contracts we retained after the sale of
certain Central Appalachia operations in 2005 to Magnum and the
sale of the Ben Creek operations at the end of the second
quarter of 2007. The commencement of production at the Mountain
Laurel complex at the beginning of the fourth quarter of 2007
partially offset these effects. The higher realized prices in
2007 reflect the decrease in the volumes sold under the
lower-priced contracts we retained after the sale to Magnum.
Operating margins per ton for 2007 increased from 2006 due to
the lower volumes sold under the contracts retained after the
Magnum sale and the commencement of production at the low-cost
Mountain Laurel complex. The tons sold under the retained
contracts are purchased from Magnum at an amount equal to the
contracted sales price, which diluted our per-ton margins in
2006. Difficult geologic conditions in certain locations,
particularly at our Mingo Logan-Ben Creek complex, and higher
depreciation, depletion and amortization costs partially offset
the positive impact on operating margin.
Net interest expense. The following table
summarizes our net interest expense for the year ended
December 31, 2007 and compares that information to the
comparable information for the year ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease
|
|
|
|
Year Ended December 31
|
|
|
in Net Income
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
(Amounts in thousands)
|
|
|
|
|
|
Interest expense
|
|
$
|
(74,865
|
)
|
|
$
|
(64,364
|
)
|
|
$
|
(10,501
|
)
|
|
|
(16.3
|
)%
|
Interest income
|
|
|
2,600
|
|
|
|
3,725
|
|
|
|
(1,125
|
)
|
|
|
(30.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(72,265
|
)
|
|
$
|
(60,639
|
)
|
|
$
|
(11,626
|
)
|
|
|
(19.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The increase in interest expense during 2007 compared to the
year-ago period resulted primarily from an increase in
outstanding borrowings under our various lines of credit, which
was partially offset by an increase in capitalized interest. We
capitalized $18.0 million of interest during the year ended
December 31, 2007 and $14.8 million during the year
ended December 31, 2006. For more information on our
ongoing capital improvement and development projects, you should
see Liquidity and Capital Resources beginning on
page 46.
Other non-operating expense. The following
table summarizes our other non-operating expense for the year
ended December 31, 2007 and compares that information to
the comparable information for the year ended December 31,
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
|
|
|
|
Year Ended December 31
|
|
|
in Net Income
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
|
%
|
|
|
|
(Amounts in thousands)
|
|
|
Other non-operating expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses resulting from early debt extinguishment and
termination of hedge accounting for interest rate swaps
|
|
$
|
(1,919
|
)
|
|
$
|
(4,836
|
)
|
|
$
|
2,917
|
|
|
|
60.3
|
%
|
Other non-operating expense
|
|
|
(354
|
)
|
|
|
(2,611
|
)
|
|
|
2,257
|
|
|
|
86.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(2,273
|
)
|
|
$
|
(7,447
|
)
|
|
$
|
5,174
|
|
|
|
69.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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. All
deferred amounts have now been recognized. Other non-operating
income includes mark-to-market adjustments related to certain
swap activity that does not qualify for hedge accounting. No
swaps were outstanding at December 31, 2007.
Income taxes. Our effective tax rate is
sensitive to changes in estimates of annual profitability and
percentage depletion deductions. The income tax benefit of
$19.9 million in 2007 compared with our income tax
provision of $7.7 million in 2006 results from lower
pre-tax income in 2007 and the benefit of a reduction
42
in our valuation allowance against deferred tax assets of
$38.7 million compared with higher pre-tax income in 2006
offset by a valuation allowance reduction of $49.1 million.
Year
Ended December 31, 2006 Compared to Year Ended
December 31, 2005
Summary. Our results for 2006 reflect higher
margins driven primarily by increased price realizations 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 weaker market
conditions at the end of 2006. 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 mining complex in Wyoming,
which restarted production in 2006, and our Skyline longwall
mining complex in Utah, which commenced mining in a new reserve
area in 2006.
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
|
|
|
Amount
|
|
|
%
|
|
|
|
(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 realizations per ton by operating segment
under the heading Operating segment results on page
45.
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 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 segments
under the heading Operating segment results on page
45.
43
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 certain Central Appalachia operations
in 2005. We have provided additional information concerning our
capital spending during 2006 in the section entitled
Liquidity and Capital Resources beginning on
page 46.
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 38 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 between years 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 between periods (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, representing the
difference between the fair value of coal reserves we
surrendered for the interest and their carrying value;
|
|
|
|
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.
|
44
Operating segment results. The following table
shows results by operating segment for the year ended
December 31, 2006 and compares those amounts to the
comparable information for the year ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
Increase (Decrease)
|
|
|
|
2006
|
|
|
2005
|
|
|
Amount
|
|
|
%
|
|
|
|
(Amounts in thousands, except per ton data)
|
|
|
Powder River Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
96,246
|
|
|
|
91,471
|
|
|
|
4,775
|
|
|
|
5.2
|
%
|
Coal sales realization per ton sold(1)
|
|
$
|
10.82
|
|
|
$
|
8.20
|
|
|
$
|
2.62
|
|
|
|
32.0
|
%
|
Operating margin per ton sold(2)
|
|
$
|
2.15
|
|
|
$
|
0.95
|
|
|
$
|
1.20
|
|
|
|
126.3
|
%
|
Western Bituminous
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
18,122
|
|
|
|
18,199
|
|
|
|
(77
|
)
|
|
|
(0.4
|
)%
|
Coal sales realization per ton sold(1)
|
|
$
|
22.42
|
|
|
$
|
19.01
|
|
|
$
|
3.41
|
|
|
|
17.9
|
%
|
Operating margin per ton sold(2)
|
|
$
|
6.86
|
|
|
$
|
3.27
|
|
|
$
|
3.59
|
|
|
|
109.8
|
%
|
Central Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
20,608
|
|
|
|
30,532
|
|
|
|
(9,924
|
)
|
|
|
(32.5
|
)%
|
Coal sales realization per ton sold(1)
|
|
$
|
46.90
|
|
|
$
|
42.73
|
|
|
$
|
4.17
|
|
|
|
9.8
|
%
|
Operating margin per ton sold(2)
|
|
$
|
2.95
|
|
|
$
|
(0.59
|
)
|
|
$
|
3.54
|
|
|
|
600.0
|
%
|
|
|
|
(1)
|
|
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 $1.54 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.
|
|
(2)
|
|
Operating margin per ton is
calculated as the result of coal sales revenues less cost of
coal sales and depreciation, depletion and amortization divided
by tons sold.
|
Powder River Basin Sales volume increased in
the Powder River Basin as a result of the restart of the Coal
Creek mining complex in the second quarter of 2006 and rail
service that improved during 2006 when compared to 2005. The
increase in coal sales prices in 2006 in the Powder River Basin
resulted from higher contract pricing when compared to 2005, due
primarily to the expiration of lower-priced legacy contracts. On
a per-ton basis, operating margins in 2006 increased
significantly from 2005 primarily due to the increase in per-ton
coal sales realizations, partially offset by increased
production taxes and coal royalties that 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 In the Western Bituminous
region, the effect of an extended longwall move at the Dugout
Canyon mining complex offset a portion of the 1.5 million
tons sold from our Skyline mining complex, which commenced
production in a new reserve area in the second quarter of 2006.
The increase in coal sales prices in the Western Bituminous
region in 2006 resulted from higher contract pricing when
compared to 2005, due primarily to the expiration of
lower-priced legacy contracts. 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 the idling of the West Elk complex in the first
quarter of 2006, an extended longwall move at our Dugout Canyon
mining complex, higher coal royalties and production taxes,
which we pay as a percentage of sales, and higher repair and
supplies costs.
Central Appalachia Our sales volumes in
Central Appalachia decreased as a result of the sale of
operations to Magnum described previously. The increase in our
coal sales prices in Central Appalachia in 2006 resulted from
higher contract pricing when compared to 2005, due primarily to
the expiration of lower-priced legacy contracts. The sale to
Magnum of certain operations with lower-priced legacy contracts
also helped to improve
45
our average coal sales price per ton. Operating margins per ton
in 2006 increased significantly from 2005 primarily as a result
of the sale to Magnum, due to operating losses at these
operations in 2005.
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 (Decrease)
|
|
|
|
Year Ended December 31
|
|
|
in Net 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 amount 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 46. 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.
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
|
|
|
|
Year Ended December 31
|
|
|
in Net 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.
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, accounts receivable securitization
or commercial paper programs. We believe that cash generated
from operations,
46
borrowing under our credit facilities and sales of assets will
be sufficient to meet working capital requirements, anticipated
capital expenditures and scheduled debt payments for at least
the next several years. Our ability to satisfy debt service
obligations, to fund planned capital expenditures, to make
acquisitions, to repurchase our common shares 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.
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
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Amounts in thousands)
|
|
|
Cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
330,810
|
|
|
$
|
308,102
|
|
|
$
|
254,607
|
|
Investing activities
|
|
|
(424,995
|
)
|
|
|
(688,005
|
)
|
|
|
(291,543
|
)
|
Financing activities
|
|
|
96,742
|
|
|
|
121,925
|
|
|
|
(25,730
|
)
|
Cash provided by operating activities increased
$22.7 million in 2007 compared to 2006, despite a decrease
in earnings, primarily as a result of transactions in 2006
related to our sale of certain Central Appalachia operations to
Magnum on December 31, 2005. We made payments of
$50.2 million in 2006 related to that transaction,
involving the purchase of coal and certain operating expenses
pursuant to the purchase agreement. In addition, we purchased
coal in 2006 to satisfy below-market contracts that we could not
source from our remaining operations.
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 the effect of
certain transactions with Magnum discussed above.
Cash used in investing activities in 2007 was
$263.0 million less than in 2006, primarily due to a
$134.8 million decrease in capital expenditures, an
increase of $69.5 million in proceeds from asset sales, and
a decrease of $36.4 in payments to acquire equity interests in
other companies that are 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 may also acquire
coal reserves opportunistically. During 2006 and 2007, we made
the second and third of five annual payments of
$122.2 million on the Little Thunder federal coal lease. In
addition, during 2007, we acquired additional property and
reserves of approximately $97.4 million. Of the remaining
capital spending in 2007, major projects included the completion
of development at the Mountain Laurel complex in Central
Appalachia, ongoing development of a new reserve area at the
West Elk mining complex in Colorado, payments for the
replacement longwall now in service at our Sufco mining complex
in Utah and costs to construct the Black Thunder mining
complexs new loadout. The Mountain Laurel longwall
commenced production on October 1, 2007. In the prior year,
in addition to spending on the Mountain Laurel development, we
also had spending related to the restart of the Coal Creek
mining complex and the commencement of mining in a new reserve
area at our Skyline mining complex.
Cash inflows from investing activities in 2007 included a
recovery of $18.3 million from the lease of equipment in
the Powder River Basin. We had previously made deposits to
purchase the equipment, primarily in the fourth quarter of 2006.
Our proceeds from asset sales in 2007 included
$43.5 million related to the sale of the Ben Creek complex
and $26.0 million from the sale of non-core reserves in the
Powder River Basin and Central Appalachia.
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
47
Powder River Basin operations related to the restart of the Coal
Creek mining complex and progress payments related to the
purchase of a replacement longwall at our Sufco mining complex
resulted in an increase in capital expenditures in 2006 compared
to 2005. 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 anticipate that capital expenditures during 2008 will range
from approximately $445 million to $505 million,
including reserve additions of approximately $135 million
to $165 million. Reserve additions in 2008 will include the
fourth of five payments of $122.2 million for the Little
Thunder coal lease. The 2008 estimate also includes capital
expenditures related to development work at certain of our
mining operations, including the development of a new seam, with
a new longwall, at the West Elk mining complex and continuing
work on the new loadout at Black Thunder. We anticipate that we
will fund these capital expenditures with available cash, cash
generated from operations and existing credit facilities.
Cash provided by financing activities decreased
$25.2 million in 2007 compared to 2006. The decrease
results primarily from a decrease in borrowings on the revolving
credit facility and other lines of credit, including those under
the accounts receivable securitization and commercial paper
programs, offset by a decrease in shares we repurchased during
2007 when compared with 2006. We had available borrowing
capacity of approximately $640.0 million under our lines of
credit at December 31, 2007. 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. We increased our
dividend rate in April 2006 and 2007 and as a result, dividends
paid increased $7.1 million.
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. 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 also spent $43.9 million
during 2006 under the share repurchase program.
At December 31, 2007, debt amounted to
$1,303.2 million, or 46% of capital employed, compared to
$1,173.8 million, or 46% of capital employed, at
December 31, 2006. Based on the level of consolidated
indebtedness and prevailing interest rates at December 31,
2007, debt service obligations for 2008, which include the
maturities of principal and interest payments, are estimated to
be $284.4 million.
On August 15, 2007, we entered into a commercial paper
placement program to provide short-term financing at rates that
are generally lower than the rates available under our revolving
credit facility. Under the program, as amended, we may sell up
to $75.0 million in interest-bearing or discounted
short-term unsecured debt obligations with maturities of no more
than 270 days. The commercial paper placement program is
supported by an unsecured $75.0 million revolving credit
facility with a maturity date of June 7, 2008. As of
December 31, 2007, we had $75.0 million outstanding
under the agreement with a weighted-average interest rate of
5.08% and maturity dates ranging from two to 81 days.
Our revolving credit facility allows for up to
$800.0 million of borrowings and matures June 23,
2011. We had borrowings outstanding under the revolving credit
facility of approximately $160.0 million December 31,
2007 and $103.0 million at December 31, 2006.
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, as
amended. The weighted average interest rate of borrowings
outstanding at December 31, 2007 was 6.30%.
Our revolving 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
48
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,
2007.
We have a receivable securitization program of
$150.0 million. Under the terms of the program, eligible
trade receivables consist of trade receivables generated by our
operating subsidiaries. Outstanding borrowings under the program
were approximately $90.8 million at December 31, 2007
and $89.2 million at December 31, 2006. 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. The average
cost of borrowing under the securitization program was
approximately 5.79% at December 31, 2007. 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, 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.
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.
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:
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Year Ended December 31
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2007
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2006
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2005
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2004
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2003
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Ratio of earnings to combined fixed charges and preference
dividends(1)
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2.40
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x
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3.93
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x
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N/A
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2.57
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x
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1.14x
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(1)
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Earnings consist of income (loss)
from continuing operations before income taxes and are adjusted
to include only distributed income from affiliates accounted for
on the equity method and fixed charges (excluding capitalized
interest). Fixed charges consist of interest incurred on
indebtedness, the portion of operating lease rentals deemed
representative of the interest factor and the amortization of
debt expense. Combined fixed charges and preference dividends
exceeded earnings by $13.1 million for the year ended
December 31, 2005.
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49
Contractual
Obligations
The following is a summary of our significant contractual
obligations as of December 31, 2007:
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Payments Due by Period
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2008
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2009-2010
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2011-2012
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After 2012
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Total
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(Amounts in thousands)
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Long-term debt, including related interest
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$
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284,355
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$
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132,750
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$
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251,966
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$
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982,063
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$
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1,651,134
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Operating leases
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30,612
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57,472
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41,838
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43,981
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173,903
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Coal lease rights
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145,802
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179,083
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36,052
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18,833
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379,770
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Coal purchase obligations
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313,712
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200,313
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102,566
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296,887
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913,478
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Unconditional purchase obligations
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236,978
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10,376
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247,354
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Total contractual obligations
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$
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1,011,459
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$
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579,994
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$
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432,422
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$
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1,341,764
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$
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3,365,639
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Interest on long-term debt was calculated using rates in effect
at December 31, 2007 for the remaining term of outstanding
borrowings.
Coal lease rights represent non-cancelable royalty lease
agreements, as well as federal lease bonus payments due. In
particular, remaining payments due under the Little Thunder
lease in Wyoming will be paid in two equal annual installments
of $122.2 million in 2008 and 2009.
Our coal purchase obligations include purchase obligations in
the over-the-counter market, as well as unconditional purchase
obligations with coal suppliers. Additionally, they include coal
purchase obligations incurred with the sale of certain Central
Appalachia operations in 2005 and the sale of the Mingo
Logan-Ben Creek complex in 2007 to supply ongoing customer sales
commitments.
Unconditional purchase obligations include open purchase orders,
which have not been recognized as a liability. The commitments
in the table above relate to commitments for the purchase of
materials and supplies, payments for services and capital
expenditures.
The table above excludes our asset retirement obligations. Our
consolidated balance sheet reflects a liability of
$224.5 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 52, 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 52 for more information about these assumptions. We
expect to make contributions of $2.5 million to our pension
plans in 2008. You should see the notes to our consolidated
financial statements for more information about the amounts we
have recorded for workers compensation and pension and
postretirement benefit obligations.
Off-Balance
Sheet Arrangements
In the normal course of business, we are a party to certain
off-balance sheet arrangements. These arrangements include
guarantees, indemnifications, financial instruments with
off-balance sheet risk, such as bank letters of credit and
performance or surety bonds. Liabilities related to these
arrangements are not reflected in
50
our consolidated balance sheets, and we do not expect any
material adverse effects on our financial condition, results of
operations or cash flows to result from these off-balance sheet
arrangements.
We use a combination of surety bonds, corporate guarantees
(e.g., self bonds) and letters of credit to secure our financial
obligations for reclamation, workers compensation, coal
lease obligations and other obligations as follows as of
December 31, 2007:
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Workers
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Reclamation
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Lease
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Compensation
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Obligations
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Obligations
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Obligations
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Other
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Total
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(Amounts in thousands)
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Self bonding
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$
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306,385
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$
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$
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$
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$
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306,385
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Surety bonds
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262,995
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45,239
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14,600
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15,507
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338,341
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Letters of credit
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46,352
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12,261
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58,613
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We have agreed to continue to provide surety bonds and letters
of credit for the reclamation 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 a specified period of time, then Magnum must post
a letter of credit in our favor in the amount of the
obligations. At December 31, 2007, we had
$92.0 million of surety bonds related to properties sold to
Magnum, which are included in the table.
Magnum also acquired certain coal supply contracts with
customers who have not consented to the assignment of the
contract to Magnum. We have committed to purchase coal from
Magnum to sell to those customers at the same price we are
charging the customers for the sale. In addition, certain
contracts have been assigned to Magnum, but we have guaranteed
Magnums performance under the contracts. The longest of
the coal supply contracts extends to the year 2017. 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
contracts from our existing operations. At market prices
effective at December 31, 2007, the cost of purchasing
15.4 million tons of coal to supply the contracts that have
not been assigned over their duration would exceed the sales
price under the contracts by approximately $265.7 million,
and the cost of purchasing 5.0 million tons of coal to
supply the assigned and guaranteed contracts over their duration
would exceed the sales price under the contracts by
approximately $97.4 million. We have also guaranteed
Magnums performance under certain operating leases, the
longest of which extends through 2011. If we were required to
perform under our guarantees of the operating lease agreements,
we would be required to make $10.3 million of lease
payments. We do not believe that it is probable that we would
have to purchase replacement coal or fulfill our obligations
under the lease guarantees and therefore, no liability has been
recorded for these potential losses as of December 31,
2007. 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 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
$61.0 million at December 31, 2007, of which none is
recorded as a liability in 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 audited by the Internal Revenue
Service, which we refer to as the IRS. We do not believe that we
are bound by the outcome
51
of this audit. We have begun 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. The outcome of
the negotiations is uncertain, however, any change that impacts
us related to an IRS negotiation may result in a non-cash
decrease in deferred income tax assets that could fall within a
range of zero to $25.0 million.
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 our 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 the majority of our 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 expected cash flows used to determine the
asset retirement obligation. At December 31, 2007, we had
recorded asset retirement obligation liabilities of
$224.5 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, 2007, we
estimate that the aggregate undiscounted cost of final mine
closure is approximately $538.0 million.
Stock-Based
Compensation
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
52
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.
Derivative
Financial Instruments
We use derivative financial instruments to manage exposures to
commodity prices and interest rates. We also enter into
over-the-counter coal positions for trading purposes. All
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. The
amount of ineffectiveness recognized in other operating (income)
expense, net relating to our heating oil derivatives was a gain
of $1.4 million for the year ended December 31, 2007.
Ineffectiveness was insignificant for the year ended
December 31, 2006.
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.
Employee
Benefit Plans
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
$2.7 million in cash to the plans during the year ended
December 31, 2007 and $19.3 million in cash and stock
to the plans during the year ended December 31, 2006. 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.
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.
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.
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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
8.5% for 2007 and 8.25% for 2006. 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
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53
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return on plan assets 0.5% for 2007 would have been an increase
in expense of approximately $1.0 million.
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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 5.9% for 2007 and 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. The impact of
lowering the discount rate 0.5% for 2007 would have been an
increase in expense of approximately $2.4 million.
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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 2007
(and pension expense for 2008), we changed our discount rate to
6.5%.
We also currently provide certain postretirement medical and
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 benefit 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
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 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.
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 5.9% for 2007 and 5.8% for
2006. Had the discount rate been lowered by 0.5% in 2007, we
would have incurred additional expense of $0.6 million.
For the measurement of our year-end other postretirement
obligation for 2007 and postretirement expense for 2008, we
changed our discount rate to 6.5%. During 2007, the
postretirement benefit plans were amended to improve benefits to
participants. As a result of the amendment, annual retiree
contribution increases have been limited so as not to exceed 25%
of the previous years total contribution. Prior to the
amendment, all medical cost increases were passed on to the
retirees and had no impact on the plan.
Income
Taxes
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
54
strategies are not available as anticipated, we may record
additional valuation allowance through income tax expense in the
period such determination is made.
As of January 1, 2007, we adopted 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. Upon
adoption of FIN 48, we increased our liability for
unrecognized tax benefits by $1.0 million, including
interest and penalties of $0.2 million, which was recorded
as a reduction of the beginning balance of retained earnings.
Accounting
Standards Issued and Not Yet Adopted
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. Statement No. 157 is effective
prospectively for fiscal years beginning after November 15,
2007, and interim periods within that fiscal year. We do not
expect the impact of adoption will be material.
|
|
ITEM 7A.
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
|
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.
We manage our commodity price risk for our non-trading,
long-term coal contract portfolio through the use of long-term
coal supply agreements, and to a limited extent, through the use
of derivative instruments. At December 31, 2007, our
expected unpriced production approximated 15 million to
25 million tons in 2008, 85 million to 95 million
tons in 2009 and 95 million to 105 million tons in
2010.
We are exposed to commodity price risk in our trading of coal,
which represents the potential loss that could be caused by an
adverse change in the market value of coal. Our coal trading
portfolio included forward and option contracts at
December 31, 2007. We had no positions entered into for
trading purposes as of December 31, 2006. With respect to
our coal trading positions, a $0.50 decrease in Powder River
Basin coal prices and a $2 decrease in Central Appalachia coal
prices would cause a $2.9 million decrease in the fair
value of these positions. The timing of the estimated future
realization of the value of our trading portfolio is 30% in
2008, 68% in 2009 and 2% in 2010.
We are also exposed to the risk of fluctuations in cash flows
related to our purchase of diesel fuel. We use approximately
45 million gallons of diesel fuel annually in our
operations. 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, and in doing so had
protected approximately 23% of our forecasted purchases for 2008
at December 31, 2007. At December 31, 2006, we had
protected approximately 68% of our forecasted purchases for
2007. 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. At
December 31, 2007, a $0.25 per gallon decrease in the price
of heating oil would result in a $2.2 million increase in
our expense in 2008 resulting from heating oil derivatives,
which would be offset by a decrease in the cost of our physical
diesel purchases.
We are exposed to market risk associated with interest rates due
to our existing level of indebtedness. At December 31,
2007, $977.4 million of our outstanding debt had fixed
interest rates, primarily our 6.75% Senior Notes, and
$325.8 million of outstanding borrowings had interest rates
that fluctuated based on changes in the respective market rates.
A one percentage point increase in the interest rates related to
these borrowings would
55
result in an annualized increase in interest expense of
$3.3 million, based on borrowing levels at
December 31, 2007.
|
|
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, 2007. 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, 2007 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-4,
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 headings
Code of Conduct, Director Biographies
and Board Meetings and Committees appearing in the
section entitled Corporate Governance Practices and
the information appearing in the section entitled
Section 16(a) Beneficial Ownership Reporting
Compliance in our proxy statement to be distributed to
stockholders in connection with the 2008 annual meeting.
|
|
ITEM 11.
|
EXECUTIVE
COMPENSATION.
|
We incorporate by reference the information under the headings
Compensation Discussion and Analysis, Summary
Compensation Table, Grants of Plan-Based Awards for
the Year Ended December 31, 2007, Outstanding
Equity Awards at December 31, 2007, Option
Exercises and Stock Vested for the Year Ended December 31,
2007, Pension Benefits, Nonqualified
Deferred Compensation, Potential Payments Upon
Termination of Employment or
Change-in-Control
and Director Compensation for the Year Ended
December 31, 2007 appearing in the section entitled
Executive and Director Compensation in our proxy
statement to be distributed to stockholders in connection with
the 2008 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
sections entitled Security Ownership of Directors and
Executive Officers and Security Ownership of Certain
Beneficial Owners in our proxy statement to be distributed
to stockholders in connection with the 2008 annual meeting.
56
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, 2007, the weighted average exercise price of
those options, and the number of shares of common stock
remaining available for future issuance at December 31,
2007, excluding shares to be issued upon exercise of outstanding
options. No warrants or rights had been issued under the plan as
of December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
to be Issued
|
|
Plan Category
|
|
and Rights
|
|
|
and Rights
|
|
|
Upon Exercise)
|
|
|
Equity compensation plans approved by security holders
|
|
|
2,849,963
|
|
|
$
|
18.19
|
|
|
|
3,943,297
|
|
Equity compensation plans not approved by security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,849,963
|
|
|
$
|
18.19
|
|
|
|
3,943,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
Practices in our proxy statement to be distributed to
stockholders in connection with the 2008 annual meeting.
|
|
ITEM 14.
|
PRINCIPAL
ACCOUNTING FEES AND SERVICES.
|
We incorporate by reference the information in the section
entitled Ratification of the Appointment of Independent
Public Accounting Firm in our proxy statement to be
distributed to stockholders in connection with the 2008 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.
57
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-4
|
|
|
|
|
F-5
|
|
|
|
|
F-6
|
|
|
|
|
F-7
|
|
|
|
|
F-8
|
|
|
|
|
F-9
|
|
Financial Statement Schedule
|
|
|
F-39
|
|
F-1
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of Arch Coal, Inc.
We have audited Arch Coal, Incs internal control over
financial reporting as of December 31, 2007, 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 included in the accompanying
Managements Report on Internal Control Over Financial
Reporting. Our responsibility is to express an opinion on 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, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A 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 authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
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, Arch Coal, Inc. maintained, in all material
respects, effective internal control over financial reporting as
of December 31, 2007, based on the COSO criteria.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets as of December 31, 2007 and
2006, and the related consolidated statements of income,
stockholders equity, and cash flows for each of the three
years in the period ended December 31, 2007 of Arch Coal,
Inc. and our report dated February 28, 2008, expressed an
unqualified opinion thereon.
St. Louis, Missouri
February 28, 2008
F-2
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of Arch Coal, Inc.
We have audited the accompanying consolidated balance sheets of
Arch Coal, Inc. (the Company) as of December 31, 2007 and
2006, and the related consolidated statements of income,
stockholders equity, and cash flows for each of the three
years in the period ended December 31, 2007. Our audits
also included the financial statement schedule listed in the
Index at 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. at December 31, 2007
and 2006, and the consolidated results of their operations and
their cash flows for each of the three years in the period ended
December 31, 2007, 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,
presents fairly in all material respects the information set
forth therein.
As discussed in Note 1 to the consolidated financial
statements, the Company changed its methods of accounting for
share-based payments and 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. As discussed in
Note 1 to the consolidated financial statements, the
Company changed its method of accounting for uncertainty in
income taxes effective January 1, 2007.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), Arch
Coal, Inc.s internal control over financial reporting as
of December 31, 2007, 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 28, 2008, expressed an unqualified
opinion thereon.
St. Louis, Missouri
February 28, 2008
F-3
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.
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, 2007.
The Companys independent registered public accounting
firm, Ernst & Young LLP, has issued an audit report on
the Companys internal control over financial reporting.
|
|
|
Steven F. Leer
Chairman and Chief
Executive Officer
|
|
Robert J. Messey
Senior Vice President and Chief
Financial Officer
|
F-4
CONSOLIDATED
STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per share data)
|
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
|
|
$
|
2,413,644
|
|
|
$
|
2,500,431
|
|
|
$
|
2,508,773
|
|
COSTS, EXPENSES AND OTHER
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales
|
|
|
1,888,285
|
|
|
|
1,909,822
|
|
|
|
2,174,007
|
|
Depreciation, depletion and amortization
|
|
|
242,062
|
|
|
|
208,354
|
|
|
|
212,301
|
|
Selling, general and administrative expenses
|
|
|
84,446
|
|
|
|
75,388
|
|
|
|
91,568
|
|
Other operating (income) expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of Powder River Basin assets
|
|
|
|
|
|
|
|
|
|
|
(46,547
|
)
|
Gain on sale of Central Appalachian operations
|
|
|
|
|
|
|
|
|
|
|
(7,528
|
)
|
Other operating (income) expense, net
|
|
|
(30,766
|
)
|
|
|
(29,800
|
)
|
|
|
7,115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,184,027
|
|
|
|
2,163,764
|
|
|
|
2,430,916
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
229,617
|
|
|
|
336,667
|
|
|
|
77,857
|
|
Interest expense, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(74,865
|
)
|
|
|
(64,364
|
)
|
|
|
(72,409
|
)
|
Interest income
|
|
|
2,600
|
|
|
|
3,725
|
|
|
|
9,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(72,265
|
)
|
|
|
(60,639
|
)
|
|
|
(63,120
|
)
|
Other non-operating expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses resulting from early debt extinguishment and
termination of hedge accounting for interest rate swaps
|
|
|
(1,919
|
)
|
|
|
(4,836
|
)
|
|
|
(7,740
|
)
|
Other non-operating expense
|
|
|
(354
|
)
|
|
|
(2,611
|
)
|
|
|
(3,524
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,273
|
)
|
|
|
(7,447
|
)
|
|
|
(11,264
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
155,079
|
|
|
|
268,581
|
|
|
|
3,473
|
|
Provision for (benefit from) income taxes
|
|
|
(19,850
|
)
|
|
|
7,650
|
|
|
|
(34,650
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
174,929
|
|
|
|
260,931
|
|
|
|
38,123
|
|
Preferred stock dividends
|
|
|
(219
|
)
|
|
|
(378
|
)
|
|
|
(15,579
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
174,710
|
|
|
$
|
260,553
|
|
|
$
|
22,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER COMMON SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per common share
|
|
$
|
1.23
|
|
|
$
|
1.83
|
|
|
$
|
0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per common share
|
|
$
|
1.21
|
|
|
$
|
1.80
|
|
|
$
|
0.17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
|
142,518
|
|
|
|
142,770
|
|
|
|
127,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average shares outstanding
|
|
|
144,019
|
|
|
|
144,812
|
|
|
|
129,940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared per common share
|
|
$
|
0.27
|
|
|
$
|
0.22
|
|
|
$
|
0.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-5
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except per share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
5,080
|
|
|
$
|
2,523
|
|
Trade accounts receivable
|
|
|
229,965
|
|
|
|
212,185
|
|
Other receivables
|
|
|
19,724
|
|
|
|
48,588
|
|
Inventories
|
|
|
177,785
|
|
|
|
129,826
|
|
Prepaid royalties
|
|
|
22,055
|
|
|
|
6,743
|
|
Deferred income taxes
|
|
|
18,789
|
|
|
|
51,802
|
|
Other
|
|
|
47,747
|
|
|
|
35,610
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
521,145
|
|
|
|
487,277
|
|
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
Coal lands and mineral rights
|
|
|
1,690,176
|
|
|
|
1,587,303
|
|
Plant and equipment
|
|
|
1,729,501
|
|
|
|
1,626,984
|
|
Deferred mine development
|
|
|
672,496
|
|
|
|
550,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,092,173
|
|
|
|
3,764,672
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(1,628,535
|
)
|
|
|
(1,521,604
|
)
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
2,463,638
|
|
|
|
2,243,068
|
|
Other assets:
|
|
|
|
|
|
|
|
|
Prepaid royalties
|
|
|
105,106
|
|
|
|
112,667
|
|
Goodwill
|
|
|
40,032
|
|
|
|
40,032
|
|
Deferred income taxes
|
|
|
296,559
|
|
|
|
263,759
|
|
Equity investments
|
|
|
82,950
|
|
|
|
80,213
|
|
Other
|
|
|
85,169
|
|
|
|
93,798
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
609,816
|
|
|
|
590,469
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,594,599
|
|
|
$
|
3,320,814
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
150,026
|
|
|
$
|
198,875
|
|
Accrued expenses
|
|
|
188,875
|
|
|
|
190,746
|
|
Current maturities of debt and short-term borrowings
|
|
|
217,614
|
|
|
|
51,185
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
556,515
|
|
|
|
440,806
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
1,085,579
|
|
|
|
1,122,595
|
|
Accrued postretirement benefits other than pension
|
|
|
59,181
|
|
|
|
49,817
|
|
Asset retirement obligations
|
|
|
219,991
|
|
|
|
205,530
|
|
Accrued workers compensation
|
|
|
41,071
|
|
|
|
43,655
|
|
Other noncurrent liabilities
|
|
|
100,576
|
|
|
|
92,817
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
2,062,913
|
|
|
|
1,955,220
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par value, 10,000 shares
authorized; issued and outstanding shares 85 and 144, at
December 31, 2007 and 2006, respectively; $50 liquidation
preference
|
|
|
1
|
|
|
|
2
|
|
Common stock, $0.01 par value, authorized
260,000 shares, issued 143,158 and 142,179 shares,
respectively
|
|
|
1,436
|
|
|
|
1,426
|
|
Paid-in capital
|
|
|
1,358,695
|
|
|
|
1,345,188
|
|
Retained earnings
|
|
|
173,186
|
|
|
|
38,147
|
|
Accumulated other comprehensive loss
|
|
|
(1,632
|
)
|
|
|
(19,169
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
1,531,686
|
|
|
|
1,365,594
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
3,594,599
|
|
|
$
|
3,320,814
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-6
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS EQUITY
Three Years Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
|
|
|
|
|
|
Treasury
|
|
|
Other
|
|
|
|
|
|
|
Preferred
|
|
|
Common
|
|
|
Paid-In
|
|
|
Earnings
|
|
|
Unearned
|
|
|
Stock at
|
|
|
Comprehensive
|
|
|
|
|
|
|
Stock
|
|
|
Stock
|
|
|
Capital
|
|
|
(Deficit)
|
|
|
Compensation
|
|
|
Cost
|
|
|
Loss
|
|
|
Total
|
|
|
|
(In thousands, except per share data)
|
|
|
BALANCE AT January 1, 2005
|
|
$
|
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 shares of treasury stock as contribution to
pension plan
|
|
|
|
|
|
|
3
|
|
|
|
12,872
|
|
|
|
|
|
|
|
|
|
|
|
3,857
|
|
|
|
|
|
|
|
16,732
|
|
Issuance of 3,038 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 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 shares of treasury stock and 182 shares
of common stock to pension plan
|
|
|
|
|
|
|
3
|
|
|
|
15,407
|
|
|
|
|
|
|
|
|
|
|
|
1,190
|
|
|
|
|
|
|
|
16,600
|
|
Issuance of 127 shares of common stock under the stock
incentive plan restricted stock and restricted stock
units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of 30 shares of common stock upon conversion of
preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of two for one stock split
|
|
|
|
|
|
|
716
|
|
|
|
|
|
|
|
(716
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of 661 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 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
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174,929
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174,929
|
|
Pension, postretirement and other post-employment benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,070
|
|
|
|
11,070
|
|
Net amount reclassified to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,490
|
|
|
|
2,490
|
|
Unrealized losses on available-for- sale securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,815
|
)
|
|
|
(2,815
|
)
|
Unrealized gains on derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,584
|
|
|
|
1,584
|
|
Net amount reclassified to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,208
|
|
|
|
5,208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
192,466
|
|
Dividends:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common ($0.27 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(38,696
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(38,696
|
)
|
Preferred ($2.50 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(219
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(219
|
)
|
Issuance of 186 shares of common stock under the stock
incentive plan restricted stock and restricted stock
units
|
|
|
|
|
|
|
2
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of 283 shares of common stock upon conversion of
preferred stock
|
|
|
(1
|
)
|
|
|
3
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of 510 shares of common stock under the stock
incentive plan stock options including income tax
benefits
|
|
|
|
|
|
|
5
|
|
|
|
7,734
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,739
|
|
Employee stock-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
5,777
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,777
|
|
Effect of adoption of FIN 48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(975
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(975
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2007
|
|
$
|
1
|
|
|
$
|
1,436
|
|
|
$
|
1,358,695
|
|
|
$
|
173,186
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(1,632
|
)
|
|
$
|
1,531,686
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-7
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
174,929
|
|
|
$
|
260,931
|
|
|
$
|
38,123
|
|
Adjustments to reconcile net income to cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
242,062
|
|
|
|
208,354
|
|
|
|
212,301
|
|
Prepaid royalties expensed
|
|
|
11,962
|
|
|
|
9,045
|
|
|
|
14,252
|
|
Net (gain) loss on dispositions of property, plant and equipment
|
|
|
(17,769
|
)
|
|
|
649
|
|
|
|
(82,168
|
)
|
Gain on investment in Knight Hawk Holdings, LLC
|
|
|
|
|
|
|
(10,309
|
)
|
|
|
|
|
Employee stock-based compensation
|
|
|
5,777
|
|
|
|
9,080
|
|
|
|
12,937
|
|
Other non-operating expense
|
|
|
2,273
|
|
|
|
7,447
|
|
|
|
11,264
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
10,254
|
|
|
|
(49,265
|
)
|
|
|
(48,432
|
)
|
Inventories
|
|
|
(55,471
|
)
|
|
|
(39,783
|
)
|
|
|
(38,368
|
)
|
Accounts payable and accrued expenses
|
|
|
(59,634
|
)
|
|
|
(115,123
|
)
|
|
|
108,536
|
|
Income taxes
|
|
|
(31,825
|
)
|
|
|
20,505
|
|
|
|
(33,513
|
)
|
Accrued postretirement benefits other than pension
|
|
|
3,733
|
|
|
|
8,662
|
|
|
|
28,660
|
|
Asset retirement obligations
|
|
|
21,609
|
|
|
|
10,967
|
|
|
|
6,498
|
|
Accrued workers compensation
|
|
|
971
|
|
|
|
(2,898
|
)
|
|
|
(9,705
|
)
|
Other
|
|
|
|
|
|
|
|
|
|
|
14,701
|
|
Other
|
|
|
21,939
|
|
|
|
(10,160
|
)
|
|
|
19,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
330,810
|
|
|
|
308,102
|
|
|
|
254,607
|
|
INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(488,363
|
)
|
|
|
(623,187
|
)
|
|
|
(357,142
|
)
|
Proceeds from dispositions of property, plant and equipment
|
|
|
70,296
|
|
|
|
777
|
|
|
|
117,048
|
|
Additions to prepaid royalties
|
|
|
(19,713
|
)
|
|
|
(20,062
|
)
|
|
|
(28,164
|
)
|
Purchases of investments/advances to affiliates
|
|
|
(5,540
|
)
|
|
|
(45,533
|
)
|
|
|
(23,285
|
)
|
Reimbursement of deposit on equipment
|
|
|
18,325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities
|
|
|
(424,995
|
)
|
|
|
(688,005
|
)
|
|
|
(291,543
|
)
|
FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds from commercial paper and net borrowings on lines
of credit
|
|
|
133,476
|
|
|
|
192,300
|
|
|
|
(25,000
|
)
|
Net proceeds from (payments on) other debt
|
|
|
(2,696
|
)
|
|
|
442
|
|
|
|
(2,376
|
)
|
Debt financing costs
|
|
|
(202
|
)
|
|
|
(2,171
|
)
|
|
|
(2,662
|
)
|
Dividends paid
|
|
|
(38,945
|
)
|
|
|
(31,815
|
)
|
|
|
(27,639
|
)
|
Purchases of treasury stock
|
|
|
|
|
|
|
(43,876
|
)
|
|
|
|
|
Issuance of common stock under incentive plans
|
|
|
5,109
|
|
|
|
7,045
|
|
|
|
31,947
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) financing activities
|
|
|
96,742
|
|
|
|
121,925
|
|
|
|
(25,730
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents
|
|
|
2,557
|
|
|
|
(257,978
|
)
|
|
|
(62,666
|
)
|
Cash and cash equivalents, beginning of year
|
|
|
2,523
|
|
|
|
260,501
|
|
|
|
323,167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of year
|
|
$
|
5,080
|
|
|
$
|
2,523
|
|
|
$
|
260,501
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOW INFORMATION:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for interest
|
|
$
|
69,866
|
|
|
$
|
59,116
|
|
|
$
|
69,839
|
|
Cash received during the year for income taxes
|
|
$
|
(2,145
|
)
|
|
$
|
(8,921
|
)
|
|
$
|
(5,518
|
)
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-8
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
Basis
of Presentation
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 located 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.
The Company owns a 99% membership 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.
On June 29, 2007, the Company sold select assets and
related liabilities associated with its Mingo Logan-Ben Creek
mining complex in West Virginia. See further discussion in
Note 2, Property Transactions.
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 three of its
subsidiaries and their Central Appalachian mining operations.
See further discussion in Note 2, Property
Transactions.
Accounting
Pronouncements Adopted
On January 1, 2007, the Company adopted Financial
Accounting Standards Board (FASB) 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. Under
FIN 48, a company can recognize the benefit of an income
tax position only if it is more likely than not (greater than
50%) that the tax position will be sustained upon tax
examination, based solely on the technical merits of the tax
position.
Upon adoption of FIN 48, the Company increased its
liability for unrecognized tax benefits by $1.0 million,
including interest and penalties of $0.2 million, which was
recorded as a reduction of the beginning balance of retained
earnings. Total unrecognized tax benefits were $3.2 million
at the adoption date, all of which would affect the effective
tax rate if recognized. The Company will continue to recognize
interest and penalties related to income tax matters in income
tax expense.
Accounting
Estimates
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.
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 Companys allowance for uncollectible receivables
reflects the amounts of its trade accounts receivable and other
receivables that are not expected to be collected, based on past
collection history, the economic
F-9
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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. The
allowance deducted from the balance of receivables was
$0.2 million and $3.2 million at December 31,
2007 and 2006, respectively.
Inventories
Coal and supplies inventories are valued at the lower of average
cost or market. Coal inventory costs include labor, supplies,
equipment costs, transportation costs prior to title transfer to
customers and operating overhead. Prior to the adoption of
Emerging Issues Task Force Issue
No. 04-6,
Accounting for Stripping Costs in the Mining Industry
(EITF 04-6),
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. As a result of
the adoption of
EITF 04-6
on January 1, 2006, stripping costs incurred during the
production phase of the mine are considered variable production
costs and are included in the cost of inventory extracted during
the period the stripping costs are incurred. 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.
Investments
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 and deferred taxes.
Prepaid
Royalties
Rights to leased coal lands are often acquired through royalty
payments. Where royalty payments represent prepayments
recoupable against future production, they are recorded as a
prepaid asset, with amounts expected to be recouped within one
year classified as current. As mining occurs on these leases,
the prepayment is charged to cost of coal sales.
Coal
Supply Agreements
Acquisition costs allocated to coal supply agreements (sales
contracts) are capitalized and amortized over the tons of coal
shipped during the term of the contract. Value is allocated to
coal supply agreements based on discounted cash flows
attributable to the difference between the contract price and
the prevailing market price at the date of acquisition. The net
book value of the Companys above-market coal supply
agreements was $3.5 million and $3.8 million at
December 31, 2007 and 2006, respectively. These amounts are
recorded in other current assets and other assets in the
accompanying Consolidated Balance Sheets. The net book value of
the below-market coal supply agreements was $1.3 million
and $3.2 million at December 31, 2007 and 2006,
respectively. These amounts are recorded in accrued expenses and
other noncurrent liabilities in the accompanying Consolidated
Balance Sheets. Amortization expense on all above-market coal
supply agreements was $0.3 million, $1.0 million and
$8.0 million in 2007, 2006 and 2005, respectively.
Amortization income on all below-market coal supply agreements
was $1.9 million, $11.8 million and $16.0 million
in 2007, 2006 and 2005, respectively.
Exploration
Costs
Costs related to locating coal deposits and evaluating the
economic viability of such deposits are expensed as incurred.
F-10
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Property,
Plant and Equipment
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,
2007, 2006 and 2005, interest costs of $18.0 million,
$14.8 million and $4.2 million, respectively, were
capitalized. Expenditures that 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.
Costs may include construction permits and licenses; mine
design; construction of access roads, shafts, slopes and main
entries; and removing overburden to access reserves in a new
pit. Additionally, deferred mine development includes the costs
associated with asset retirement obligations.
Coal
Lands and Mineral Rights
Amounts paid to acquire the Companys coal reserves are
capitalized and depleted over the life of proven and probable
reserves. A significant portion of the Companys coal
reserves are controlled through leasing arrangements. The cost
of 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
$1.0 billion and $954.2 million at December 31,
2007 and 2006, 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 second
and third installments of $122.2 million in 2006 and 2007,
with the two remaining annual payments to be paid in 2008 and
2009. These payments are capitalized as the cost of the
underlying mineral reserves.
Impairment
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
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 when
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
F-11
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
Deferred
Financing Costs
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 $20.2 million and $24.8 million at
December 31, 2007 and 2006, respectively. These amounts are
recorded in other assets in the accompanying Consolidated
Balance Sheets. Amounts classified as current were
$4.7 million and $4.6 million at December 31,
2007 and 2006, respectively. These amounts are recorded in other
current assets in the accompanying Consolidated Balance Sheets.
Revenue
Recognition
Coal sales revenues include sales to customers of coal produced
at Company operations and coal purchased from third parties. The
Company recognizes revenue from coal sales at the time risk of
loss passes to the customer 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; income from equity
investments; gains and losses from dispositions of long-term
assets; and 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 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 11,
Asset Retirement Obligations.
Derivative
Financial Instruments
The Company generally has used derivative financial instruments
to manage exposures to commodity prices and interest rates.
Additionally, the Company may hold certain coal derivative
financial instruments for trading purposes.
All derivative financial instruments are recognized in the
balance sheet at fair value. Changes in fair value are
recognized in earnings if the derivatives 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. The Company formally
documents the relationships between hedging instruments and the
respective 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.
Any ineffective portion of a cash flow hedges change in
fair value is recognized immediately in earnings. The amount of
ineffectiveness recognized in other operating (income) expense,
net in the accompanying
F-12
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Consolidated Statements of Income relating to our heating oil
derivatives was a gain of $1.4 million for the year ended
December 31, 2007. The amount of ineffectiveness relating
to interest rate swaps recognized in other non-operating expense
in the accompanying Consolidated Statements of Income was a loss
of $1.0 million for the year ended December 31, 2005.
Ineffectiveness was insignificant for the year ended
December 31, 2006.
Income
Taxes
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. A valuation
allowance is established if it is more likely than not that a
deferred tax asset will not be realized. In determining the
appropriate valuation allowance, the Company considers projected
realization of tax benefits based on expected levels of future
taxable income, available tax planning strategies and its
overall deferred tax position.
Benefit
Plans
The Company has non-contributory defined benefit pension plans
covering certain of its salaried and hourly employees. Benefits
are generally based on the employees age and compensation.
The Company also currently provides certain postretirement
medical and life insurance coverage for eligible employees.
Costs of providing benefits are determined on an actuarial basis
and accrued over the employees period of active service.
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 12 and 13 for additional disclosures
relating to these obligations.
The Company has an obligation under the Coal Industry Retiree
Health Benefit Act of 1992 (Benefit Act), which
provides for the funding of medical and death benefits for
certain retired members of the United Mine Workers of America
(UMWA) through premiums paid by assigned operators
(former employers), transfers in 1993 and 1994 from an
overfunded pension trust established for the benefit of retired
UMWA members, and transfers from the Abandoned Mine Lands Fund
(funded by a federal tax on coal production) commencing in 1995.
The Company treats its obligation under the Benefit Act as a
participation in a multi-employer plan and records expense as
premiums are paid.
Stock-Based
Compensation
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
adoption date forward. 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. The effects of
F-13
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
adoption on retained earnings, net income and the Consolidated
Statement of Cash Flows for the year ended December 31,
2006 were insignificant. See further discussion in Note 16,
Stock Based Compensation and Other Incentive Plans.
Accounting
Standards Issued and Not Yet Adopted
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
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 FASB
deferred the effective date of Statement No. 157 for one
year for nonfinancial assets and liabilities that are recognized
or disclosed at fair value in the financial statements on a
nonrecurring basis. The Company does not expect adoption of
Statement No. 157 to have a material impact on the
Companys financial position or results of operations.
In February 2007, the FASB issued Statement of Financial
Accounting Standards No. 159, The Fair Value Option for
Financial Liabilities Including an amendment of FASB
Statement No. 115 (Statement No. 159).
Statement No. 159 permits entities to choose to measure
many financial instruments and certain other items at fair
value. The objective is to improve financial reporting by
providing entities with the opportunity to mitigate volatility
in reported earnings caused by measuring related assets and
liabilities differently without having to apply complex hedge
accounting provisions. Statement No. 159 is effective
prospectively for fiscal years beginning after November 15,
2007. The Company does not expect adoption of Statement
No. 159 to have a material impact on the Companys
financial position or results of operations.
On September 28, 2007, the Company purchased coal reserves
and surface rights in Illinois for $38.9 million. This
property is adjacent to other properties owned by the Company
and includes approximately 157 million tons of recoverable
coal reserves. Of the total recoverable tons, approximately
134 million tons are owned, with the remainder controlled
under long-term leases.
On June 29, 2007, the Company sold select assets and
related liabilities associated with its Mingo Logan-Ben Creek
mining complex in West Virginia for $43.5 million. For the
years ended December 31, 2007, 2006 and 2005, the
Companys Mingo Logan-Ben Creek operations contributed coal
sales of 1.2 million, 4.0 million and 4.7 million
tons, revenues of $75.1 million, $243.8 million and
$261.5 million and income from operations of
$9.1 million, $19.5 million and $15.2 million,
respectively.
The Company recognized a net gain of $8.9 million in the
year ended December 31, 2007 resulting from the sale of the
Mingo Logan-Ben Creek complex. That amount has been reflected in
other operating (income) expense, net in the accompanying
Consolidated Statements of Income. This gain is net of accrued
losses of $12.5 million on firm commitments to purchase
coal through 2008 to supply below-market sales contracts that
can no longer be sourced from the Companys operations and
$4.9 million of employee-related payments, which were paid
prior to December 31, 2007.
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, Inc., 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 year ended December 31, 2005,
collectively, these subsidiaries sold 12.7 million tons of
coal, had revenues of $509.8 million and incurred losses
from operations of $8.3 million. 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 UMWA
contract.
F-14
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 13, 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. As of
December 31, 2007 and 2006, the Company had a current
receivable due from Magnum of $1.1 million and
$8.5 million, respectively, 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 20,
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 its coal reserves for a similar block
of 60.0 million tons of coal reserves held by 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 September 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 19, Leases.
During the years ended December 31, 2007, 2006 and 2005,
gains (losses) on other dispositions of property, plant and
equipment were $8.9 million, $(0.6) million and
$28.2 million, respectively. Included in the gain for 2007
was a gain of $8.4 million on the sales of non-strategic
reserves in the Powder River Basin and Central Appalachia.
Included in the gain for 2005 was a gain of $9.0 million on
the sale of surface land rights at
F-15
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
|
|
3.
|
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, 2005
|
|
$
|
(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
|
|
|
|