10-K
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, 2008
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 30, 2008 was approximately $10.8 billion.
On February 23, 2009, 142,862,991 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 23, 2009 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 30.
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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competition within our industry and with producers of competing
energy sources;
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excess production and production capacity;
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our ability to acquire or develop coal reserves in an
economically feasible manner;
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inaccuracies in our estimates of our coal reserves;
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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 collect payments from our customers;
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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, a
subsidiary of Patriot Coal Corporation, to satisfy certain
below-market contracts that we guarantee;
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our ability to manage the market and other risks associated with
certain trading and other asset optimization strategies;
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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,
particulate 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, as
well as other risks of which we are not aware or which we
currently do not believe to be material, 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.
For the year ended December 31, 2008, we sold approximately
139.6 million tons of coal, including approximately
6.1 million tons of coal we purchased from third parties,
fueling approximately 6% of all electricity generated in the
United States. We sell substantially all of our coal to power
plants, steel mills and industrial facilities. At
December 31, 2008, we operated 20 active mines located in
each of the major low-sulfur coal-producing regions of the
United States. The locations of our mines enable us to ship coal
to most of the major coal-fueled power plants, steel mills and
export facilities located in the United States.
Significant federal and state environmental regulations affect
the demand for coal. Existing environmental regulations limiting
the emission of certain impurities caused by coal combustion and
new regulations, including those aimed at curbing the emission
of certain greenhouse gases, have had and are likely to continue
to have a considerable impact on our business. For example,
certain federal and state environmental regulations currently
limit the amount of sulfur dioxide that may be emitted as a
result of combustion. As a result, we focus on mining,
processing and marketing coal with low sulfur content.
Despite these and other regulations, we expect worldwide coal
demand to increase over time, particularly in developing
countries such as China and India where electricity demand is
increasing much faster than in developed parts of the world.
Although the global economic recession has had a significant
impact in certain regions of the world, we expect worldwide
energy demand to increase over the next 20 years. As a
result of its availability, stability and affordability, we
expect coal to satisfy a large portion of that demand.
Domestically, we anticipate that production in certain regions,
particularly the Central Appalachian region, will decrease over
time as reserves are depleted and permitting becomes more
challenging. Although we expect coal exports to decline in 2009,
we expect coal exports to increase gradually over the
intermediate and longer term, as international consumers look
for more stable sources of coal supplies. We also expect
domestic coal consumption to increase over the intermediate and
longer term. We believe that these trends collectively will
exert upward pressure on coal pricing.
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, which we
refer to as ARCO. 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
acquired a leasehold interest in 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 acquired a leasehold interest
in 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.
1
Coal
Characteristics
In general, end users characterize coal of all geological
compositions as steam coal or metallurgical coal. Heat value,
sulfur and ash and moisture content, and volatility in the case
of metallurgical coal, are the most important variables in the
marketing and transportation of coal. These characteristics help
producers determine the best end use of a particular type of
coal. The following is a description of these general coal
characteristics:
Heat Value. In general, the carbon content of
coal supplies most of its heating value, but other factors also
influence the amount of energy it contains per unit of weight.
The heat value of coal is commonly measured in Btus. Coal is
generally classified into four categories, ranging from lignite
through subbituminous and bituminous to anthracite, reflecting
the progressive response of individual deposits of coal to
increasing heat and pressure. Anthracite is coal with the
highest carbon content and, therefore, the highest heat value
nearing 15,000 Btus per pound. Bituminous coal, used primarily
to generate electricity and to make coke for the steel industry,
has a heat value ranging between 10,500 and 15,500 Btus per
pound. Subbituminous coal ranges from 8,300 to 13,000 Btus
per pound and is generally used for electric power generation.
Lignite coal is a geologically young coal which has the lowest
carbon content and a heat value ranging between 4,000 and 8,300
Btus per pound.
Sulfur Content. Federal and state
environmental regulations, including regulations that limit the
amount of sulfur dioxide that may be emitted as a result of
combustion, have affected and may continue to affect the demand
for certain types of coal. The sulfur content of coal can vary
from seam to seam and within a single seam. The chemical
composition and concentration of sulfur in coal affects the
amount of sulfur dioxide produced in combustion. Coal-fueled
power plants can comply with sulfur dioxide emission regulations
by burning coal with low sulfur content, blending coals with
various sulfur contents, purchasing emission allowances on the
open market
and/or using
sulfur-reduction technology.
All of our identified coal reserves have been subject to
preliminary coal seam analysis to test sulfur content. Of these
reserves, approximately 73.4% consist of compliance coal, while
an additional 8.7% could be sold as low-sulfur coal. The balance
is classified as high-sulfur coal. Higher sulfur noncompliance
coal can be burned in plants equipped with sulfur-reduction
technology, such as scrubbers, and in facilities that blend
compliance and noncompliance coal. We expect that all new
coal-fueled power plants built in the United States will use
some type of sulfur-reduction technology and, as such, the
premiums offered for lower sulfur coal may decrease in the
future.
Ash. Ash is the inorganic residue remaining
after the combustion of coal. As with sulfur, ash content varies
from seam to seam. Ash content is an important characteristic of
coal because it impacts boiler performance and electric
generating plants must handle and dispose of ash following
combustion. The composition of the ash, including the proportion
of sodium oxide, and fusion temperature are important
characteristics of coal and help determine the suitability of
the coal to end users. The absence of ash is also important to
the process by which metallurgical coal is transformed into coke
for use in steel production.
Moisture. Moisture content of coal varies by
the type of coal, the region where it is mined and the location
of the coal within a seam. In general, high moisture content
decreases the heat value and increases the weight of the coal,
thereby making it more expensive to transport. Moisture content
in coal, on an as-sold basis, can range from approximately 2% to
over 30% of the coals weight.
Other. Users of metallurgical coal measure
certain other characteristics, including fluidity, swelling
capacity and volatility to assess the strength of coke produced
from a given coal or the amount of coke that certain types of
coal will yield. These characteristics may be important elements
in determining the value of the metallurgical coal we produce
and market.
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
41% of the worlds electricity in 2006, according to the
most recently available data from the International Energy
Agency, which we refer to as the
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IEA. Coal is also used in producing approximately 64% of the
worlds steel supply. Coal reserves can be found in almost
every country in the world, and recoverable coal can be found in
approximately 70 countries.
Coal is traded worldwide and can be transported to demand
centers by ship and by rail. Worldwide coal production
approximated 7.2 billion tons in 2007 and 6.8 billion
tons in 2006, according to the IEA. 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 World Coal Institute, which we refer to as the WCI.
China, Indonesia and South Africa have also historically been
significant exporters, however, growing energy demand in these
areas has resulted in declining coal exports as many of these
countries move toward greater self-sufficiency.
International demand for coal continues to be driven by rapid
growth in electrical power generation capacity in Asia,
particularly in China and India. China and India represented
approximately 44% of total world coal consumption in 2005 and
are expected to account for approximately 57% by 2030, according
to the Energy Information Administration, which we refer to as
the EIA. The increase in international demand has led to
increased demand for coal exports from the United States. During
2008, coal exports for both steam and metallurgical coal
increased significantly as demand for U.S. coal in the
Atlantic Basin increased. This increase was a continuation of a
trend that began in 2007 as demand for coal for both power
generation and steel production exceeded global coal supplies. A
weak U.S. dollar relative to foreign currencies, high
freight rates and supply problems in Australia, South Africa and
Indonesia, when combined, improved the competitiveness of
U.S. coal in several international markets. During the
second half of 2008, as the United States and most international
economies deteriorated, demand for steam and metallurgical coal
declined. We believe these economic challenges will continue to
affect international demand in 2009 and, as a result, we expect
U.S. coal exports to decline from record 2008 levels. Once
global economic conditions improve, we expect U.S. exports
to rebound.
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 increased from 398.1 million tons in 1960 to
approximately 1.1 billion tons in 2008, based on
preliminary information provided by the EIA. According to the
EIA, approximately 98% of coal consumed in the United States in
2008 was from domestic production sources. The following chart
shows historical and projected demand trends for U.S. coal
by consuming sector for the periods indicated, according to the
EIA:
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Actual
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Forecast
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Annual Growth
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Sector
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2001
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2007
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2010
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2020
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2030
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2001-2010
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2010-2020
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2020-2030
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(Tons, in millions)
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Electric power
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964
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1,046
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1,056
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1,110
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1,210
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0.9
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%
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0.5
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%
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0.9
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%
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Other industrial
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65
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56
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60
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56
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57
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(0.8
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)%
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(0.7
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)%
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0.2
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%
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Coke plants
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26
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23
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21
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19
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18
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(2.1
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)%
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(1.0
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)%
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(0.5
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)%
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Residential/commercial
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4
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3
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3
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3
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3
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0.0
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%
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0.0
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%
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0.0
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%
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Coal-to-liquids
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30
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70
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n/a
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n/a
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8.8
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%
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Total U.S. coal consumption
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1,060
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1,129
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1,140
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1,218
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1,358
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0.7
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%
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0.7
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%
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1.1
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%
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Source: EIA Annual Energy Outlook 2009
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 48% of U.S. electricity
generation in 2008 and is projected to grow by more than 20%,
reaching 1.4 billion tons in 2030.
Coal is generally the lowest cost fossil-fuel used for baseload
electric power generation and, historically, has been
considerably less expensive than natural gas or oil. We estimate
that the cost of generating electricity from
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coal is less than one-third of the cost of generating
electricity from other fossil fuels. According to the EIA, the
average delivered cost of coal to electric power generators
during the first ten months of 2008 was $2.05/mm Btus, which was
$14.88/mm Btus less expensive than petroleum liquids and
$7.53/mm Btus less expensive than natural gas. Coal is also
competitive with nuclear power generation, especially on a total
cost per
megawatt-hour
basis. The production of electricity from existing hydroelectric
facilities is inexpensive, but new sources are scarce and its
application is limited by geography and susceptibility to
seasonal and climatic conditions. In 2008, non-hydropower
renewable power generation, such as wind power, accounted for
only 3% of all electricity generated in the United States and is
currently not economically competitive with existing
technologies. The following chart sets forth the breakdown of
U.S. electricity generation by energy source for 2007,
according to the EIA:
Source: EIA Electric Power Annual (Jan. 21, 2009).
Coal consumption patterns are also influenced by the demand for
electricity, governmental regulations affecting power
generation, technological developments and the location,
availability and cost of other energy sources such as nuclear
and hydroelectric power. 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 almost 24% by 2030, despite projected efforts
throughout the United States for industrial, residential and
other consumers 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, which are the minimum
amounts of electric power delivered or required over a given
period of time at a steady rate. Based on estimates compiled by
the EIA, U.S. coal consumption for electric generation is
expected to grow approximately 1.5% per year until 2030. These
amounts assume no future federal or state carbon emissions
legislation is enacted and do not take into account recent
market conditions.
Based on EIA projections, current capacity for electric
generation may not be enough to support projected electricity
demand. The EIA has projected that approximately 223 gigawatts
of new electricity capacity will be needed between 2008 and
2030, with approximately 19% of the new capacity estimated to
come from coal-fired generation. Planned new domestic
coal-fueled electricity generation capacity announcements
approximated 38 gigawatts at December 31, 2008, equating to
more than 120 million tons of additional annual coal
demand, based on information obtained from the National Energy
Technology Laboratory and our internal estimates. We estimate
that, at December 31, 2008, approximately 21 gigawatts of
generating capacity was under construction or in advanced stages
of development in the United States. Because the EIA projections
are based on factors and assumptions contained in its forecasts,
actual amounts of new capacity may differ significantly from
those estimates and if they differ negatively, the amount of new
electricity capacity needed may not grow as the EIA projects.
The proposed plants or expansions are utilizing the full
spectrum of technologies from pulverized coal and circulating
fluidized bed, which permit coal to be more easily burned, and
integrated coal gasification cycle units, which permit coal to
be turned into a gasified product for the easier capture of
carbon in the future. Many projects that are moving forward are
being developed by municipal and regulated utilities due to
their ability to recover costs and prior experience with coal.
4
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 reached
record levels during 2008 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 proposed, including a
coal-to-liquids facility 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 and energy security. 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 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 200 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 nearly 200
years. Annual coal production in the United States has increased
from 434 million tons in 1960 to approximately
1.2 billion tons in 2008 based on information provided by
EIA.
Coal is mined from coal fields through the United States, with
the major production centers located in the western U.S., the
Appalachian region and the Illinois Basin. The quality of coal
varies by region. Heat value, sulfur content and suitability for
production of metallurgical coke are important quality
characteristics and are used to determine the best end use for
the particular coal types.
The western region includes, among other areas, the Powder River
Basin and the Western Bituminous region. According to the EIA,
coal produced in the western United States increased from
408.3 million tons in 1994 to 635.9 million tons in
2008 as competitive mining costs and regulations limiting sulfur
dioxide emissions have increased demand for low-sulfur coal over
this period. The Powder River Basin is located in northeastern
Wyoming and southeastern Montana. Coal from this region is
sub-bituminous coal with low sulfur content ranging from 0.2% to
0.9% and heating values ranging from 8,000 to 9,500 Btu. 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 low sulfur content ranging from 0.4% to 0.8% and
heating values ranging from 10,000 to 12,200 Btu.
The Appalachian region is divided into the north, central and
southern Appalachian regions. According to the EIA, coal
produced in the Appalachian region decreased from
445.4 million tons in 1994 to 389.6 million tons in
2008, primarily as a result of the depletion of economically
attractive reserves, permitting issues and increasing costs of
production. Central Appalachia includes eastern Kentucky,
Tennessee, Virginia and southern West Virginia. Coal mined from
this region generally has a high heat value ranging from 11,400
to 13,200 Btu and a low sulfur content ranging from 0.2% to
2.0%. Northern Appalachia includes Maryland, Ohio, Pennsylvania
and northern West Virginia. Coal from this region generally has
a high heat value ranging from 10,300 to 13,500 Btu and a high
sulfur content ranging from 0.8% to 4.0%.
5
The Illinois basin includes Illinois, Indiana and western
Kentucky and is the major coal production center in the interior
region of the United States. According to the EIA, coal produced
in the interior region decreased from 179.9 million tons in
1994 to 97.5 million tons in 2008. Coal from the Illinois
basin generally has a heat value ranging from 10,100 to 12,600
Btu and has a high sulfur content ranging from 1.0% to 4.3%.
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.
U.S. Coal Exports and Imports. Coal exports
increased from 71.4 million tons in 1994 to
82.6 million tons in 2008. As discussed above, as global
coal consumption 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. We expect this development to continue
over the long-term. However, we anticipate U.S. coal
exports to decline in 2009 from 2008 levels because of the
near-term global economic recession, record low freight rates
and a stronger U.S. dollar relative to foreign currencies.
We believe that the United States will continue to be a swing
supplier of coal to the global marketplace in the near term.
Historically, coal imported from abroad has represented a
relatively small share of total U.S. coal consumption.
According to the EIA, coal imports increased from
8.9 million tons in 1994 to approximately 34.0 million
tons in 2008. 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 do not
expect coal imports into the United States to grow significantly
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 11. In 2008, approximately 79.0% of the coal
that we produced came from surface mining operations.
Surface mining involves removing the topsoil and drilling or
blasting the overburden (earth and rock covering the coal) with
explosives. We then remove the overburden 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 plant life into the natural habitat
and make other improvements that have local community and
environmental benefits.
6
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 11. In 2008, approximately
21.0% 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. 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 2008,
approximately 17.3% of the coal that we produced came from
underground mining operations generally using longwall mining
techniques.
7
The following diagram illustrates a typical underground mining
operation using longwall mining techniques:
Room-and-Pillar
Mining. 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. We currently conduct
retreat mining in certain underground mines at our Cumberland
River and Lone Mountain mining complexes. In 2008, the
quantities of coal we recovered from retreat mining represented
an insignificant portion of our total coal production. Once we
finish mining in an area, we generally abandon that area and
seal it from the rest of the mine. In 2008, approximately 3.3%
of the coal that we produced came from underground mining
operations generally using
room-and-pillar
mining techniques.
8
The following diagram illustrates our typical underground mining
operation using
room-and-pillar
mining techniques:
Coal Preparation and Blending. We generally
crush the coal mined from our Powder River Basin mining
complexes and ship it directly from our mines to the customer.
Typically, no additional preparation is required for a saleable
product. Coal extracted from some of our underground mining
operations, particularly those mining thinner seams in Central
Appalachia, 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 2008, our preparation plants processed approximately 83.9% of
the raw coal we produced in the Central Appalachia region. In
addition, depending on coal quality and customer requirements,
we may blend coal mined from different locations, including coal
produced by third parties, in order to achieve a more suitable
product.
The treatments we employ at our preparation plants depend on the
size of the raw coal. For course material, the separation
process relies on the difference in the density between coal and
waste rock where, for the very fine fractions, the separation
process relies on the difference in surface chemical properties
between coal and the waste minerals. 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 a pre-determined 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 process most coal sizes through centrifuges.
A centrifuge spins coal very quickly, causing water accompanying
the coal to separate.
9
For more information about the locations of our preparation
plants, you should see the section entitled Our Mining
Operations below.
Our
Mining Operations
General. At December 31, 2008, we
operated 20 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. We incorporate by reference the information about
the operating results of each of our segments for the years
ended December 31, 2008, 2007 and 2006 contained in
Note 22 Segment Information to our consolidated
financial statements beginning on
page F-1.
Our operations in the Powder River Basin are located in Wyoming
and include two surface mining complexes (Black Thunder and Coal
Creek). Our operations in the Western Bituminous region are
located in southern Wyoming, Colorado and Utah and include four
underground mining complexes (Dugout Canyon, Skyline, Sufco and
West Elk) and one surface mining complex (Arch of Wyoming) that
includes one active surface mine and four inactive mines. Our
operations in the Central Appalachia region are located in
southern West Virginia, eastern Kentucky and southwestern
Virginia and include four mining complexes
(Coal-Mac,
Cumberland River, Lone Mountain and Mountain Laurel) comprised
of nine underground mines and four surface mines.
In general, we have developed our mining complexes at strategic
locations in close proximity to our preparation plants and rail
or barge shipping facilities. Coal is transported from our
mining complexes to customers by means of railroads, trucks,
barge lines, and ocean-going vessels from terminal facilities.
We currently own or lease under long-term arrangements a
substantial portion of the equipment utilized in our mining
operations. We employ sophisticated preventative maintenance and
rebuild programs and upgrade our equipment to ensure that it is
productive, well-maintained and cost-competitive. Our
maintenance programs also employ procedures designed to enhance
the efficiencies of our operations.
The following map shows the locations of our mining operations:
10
The following table provides a summary of information regarding
our active mining complexes at December 31, 2008, the total
sales associated with these complexes for the years ended
December 31, 2006, 2007 and 2008 and the total reserves
associated with these complexes at December 31, 2008. 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. The information included below the following table
describes in more detail our mining operations, the coal mining
methods used, certain characteristics of our coal and the method
by which we transport coal from our mining operations to our
customers or other third parties.
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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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2006
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2007
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2008
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2008
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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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92.5
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86.2
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88.5
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$
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751.2
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1,250.7
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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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11.5
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148.2
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206.1
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Western Bituminous:
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Arch of Wyoming(4)
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S
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L, HW
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UP
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0.2
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24.0
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19.4
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Dugout Canyon
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U
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LW, CM
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UP
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4.2
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4.0
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4.3
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131.4
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24.7
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Skyline(3)
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U
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LW, CM
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UP
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1.5
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2.4
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3.3
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189.3
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19.9
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Sufco
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U
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LW, CM
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UP
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7.4
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6.7
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7.4
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213.2
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44.9
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West Elk
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U
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LW, CM
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UP
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5.0
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6.2
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5.3
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390.5
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70.9
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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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3.7
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3.9
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3.7
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164.3
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27.8
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Cumberland River
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S(2), U(3)
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U
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L, CM, HW
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NS
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2.6
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2.4
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2.4
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126.3
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23.3
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Lone Mountain
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U(3)
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CM
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NS/CSX
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2.5
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2.4
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2.7
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182.3
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34.1
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Mountain Laurel
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U
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S
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L, LW, CM
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CSX
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1.0
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4.3
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428.4
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90.7
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Totals
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122.5
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125.4
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133.6
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$
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2,749.1
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1,812.5
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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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CM = 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, 2008. 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 and 1.7 million tons in 2006. The amount of
coal that we purchased from third parties and processed through
our loadout facilities was negligible in 2008. 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 6.0 million tons in 2008,
8.4 million tons in 2007 and 8.5 million tons in 2006.
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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 that complex. That complex sold
1.2 million tons in 2007 and 4.0 million tons in 2006.
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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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We have four inactive mines at our
Arch of Wyoming complex that are in the final process of
reclamation and bond release.
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11
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. The
Black Thunder mining complex extracts steam coal from the Upper
Wyodak and Main Wyodak seams. The Black Thunder mining complex
shipped 88.5 million tons of coal in 2008. |
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We control a significant portion of the coal reserves through
federal and state leases. The Black Thunder mining complex had
approximately 1.3 billion tons of proven and probable
reserves at December 31, 2008. The air quality permit for
the Black Thunder mine allows for the mining of coal at a rate
of 135.0 million tons per year. Without the addition of
more coal reserves, the current reserves could sustain current
production levels until 2021 before annual output starts to
significantly decline, although in practice production would
drop in phases extending the ultimate mine life. Several large
tracts of coal adjacent to the Black Thunder mining complex have
been nominated for lease, and other potential large areas of
unleased coal remain available for nomination by us or other
mining operations. The U.S. Department of Interior Bureau
of Land Management, which we refer to as the BLM, will determine
if the tracts will be leased and, if so, the final boundaries
of, and the coal tonnage for, these tracts. |
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The Black Thunder mining complex currently consists of five
active pit areas and two owned loadout facilities. 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 two 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. The Coal Creek
mining complex extracts steam coal from the Wyodak-R1 and
Wyodak-R3 seams. The Coal Creek mining complex shipped
11.5 million tons of coal in 2008. |
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We control a significant portion of the coal reserves through
federal and state leases. The Coal Creek mining complex had
approximately 206.1 million tons of proven and probable
reserves at December 31, 2008. The air quality permit for
the Coal Creek mine allows for the mining of coal at a rate of
50.0 million tons per year. Without the addition of more
coal reserves, the current reserves will sustain current
production levels until 2025 before annual output starts to
significantly decline. One large tract of coal adjacent to the
Coal Creek mining complex has been nominated for lease, and
other potential large areas of unleased coal remain available
for nomination by us or other mining operations. The BLM will
determine if these tracts will be leased and, if so, the final
boundaries of, and the coal tonnage for, these tracts. |
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The Coal Creek 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. |
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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
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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 Arch of Wyoming complex currently consists
of one active surface mine and four inactive mines located on
approximately 58,000 acres that are in the final process of
reclamation and bond release. The Arch of Wyoming mining complex
extracts coal from the Johnson seam. The Arch of Wyoming complex
shipped 0.2 million tons of coal in 2008. |
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We control a significant portion of the coal reserves associated
with this complex through federal, state and private leases. The
active Arch of Wyoming mining operations had approximately
19.4 million tons of proven and probable reserves at
December 31, 2008. The air quality permit for the active
Arch of Wyoming mining operation allows for the mining of coal
at a rate of 2.5 million tons per year. Without the
addition of more coal reserves, the current reserves will
sustain current production levels until 2018 before annual
output starts to significantly decline. |
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The active Arch of Wyoming mining operations currently consist
of one active pit area. We ship all of the coal raw to our
customers via the Union Pacific railroad and by truck. We do not
process the coal mined at this complex. |
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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. The
Dugout Canyon mining complex extracts steam coal from the Rock
Canyon and Gilson seams. The Dugout Canyon mining complex
shipped 4.3 million tons of coal in 2008. |
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We control a significant portion of the coal reserves through
federal and state leases. The Dugout Canyon mining complex had
approximately 24.7 million tons of proven and probable
reserves at December 31, 2008. Without the addition of more
coal reserves, the current reserves will sustain current
production levels until 2013 before annual output starts to
significantly decline. |
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The complex currently consists of a longwall, three 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. The Skyline mining complex extracts steam coal from the
Lower OConner A seam. The Skyline mining complex shipped
3.3 million tons of coal in 2008. |
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We control a significant portion of the coal reserves through
federal leases and smaller portions through county and private
leases. The Skyline mining complex had approximately
19.9 million tons of proven and probable reserves at
December 31, 2008. Without the addition of more coal
reserves, the current reserves will sustain current production
levels until 2011 before annual output starts to significantly
decline. |
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The Skyline complex currently consists of a longwall, a
continuous miner section and a loadout facility. We ship most of
the coal raw to our customers via the Union Pacific railroad or
by highway trucks. We process a portion of the coal mined at
this complex at a nearby preparation plant. 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. The Sufco mining
complex extracts steam coal from the Upper Hiawatha and Lower
Hiawatha seams. The Sufco mining complex shipped
7.4 million tons of coal in 2008. |
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We control a significant portion of the coal reserves through
federal and state leases. The Sufco mining complex had
approximately 44.9 million tons of proven and probable
reserves at December 31, 2008. Without the addition of more
coal reserves, the current reserves will sustain current
production levels until 2014 before annual output starts to
significantly decline. |
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The Sufco 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. |
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West Elk |
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West Elk is an underground mining complex located on
approximately 17,900 acres in Gunnison County, Colorado.
The West Elk mining complex extracts steam coal from the E seam.
In the fourth quarter of 2008, we transitioned our longwall
mining operation from the B seam to the E seam. The West Elk
mining complex shipped 5.3 million tons of coal in 2008. |
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We control a significant portion of the coal reserves through
federal and state leases. The West Elk mining complex had
approximately 70.9 million tons of proven and probable
reserves at December 31, 2008. Without the addition of more
coal reserves, the current reserves will sustain current
production levels until 2019 before annual output starts to
significantly decline. |
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The West Elk complex currently consists of a longwall, three
continuous miner sections and a loadout facility. We ship most
of the coal raw to our customers via the Union Pacific railroad.
We process a portion of the coal mined at this complex at a
nearby preparation plant. The loadout facility can load an
11,000-ton train in less than three hours. |
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Central
Appalachia
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Coal-Mac |
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Coal-Mac is a surface and underground mining complex located on
approximately 46,800 acres in Logan and Mingo Counties,
West Virginia. Surface mining operations at the Coal-Mac mining
complex extract steam coal from the Coalburg and Stockton seams.
Underground mining operations at the Coal-Mac mining complex
extract steam coal from the Coalburg seam. The Coal-Mac mining
complex shipped 3.7 million tons of coal in 2008. |
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We control a significant portion of the coal reserves through
private leases. The Coal-Mac mining complex had approximately
27.8 million tons of proven and probable reserves at
December 31, 2008. Without the addition of more coal
reserves, the current reserves will sustain current production
levels until 2016 before annual output starts to significantly
decline. |
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The complex currently consists of one captive surface mine, 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 12,000-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 10,000-ton train in less than four
hours. |
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Cumberland River |
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Cumberland River is an underground and surface mining complex
located on approximately 17,000 acres in Wise County,
Virginia and Letcher County, Kentucky. Surface mining operations
at the Cumberland River mining complex extract steam coal from
approximately 20 different coal seams from the Imboden seam to
the High Splint No. 14 seam. Underground mining operations
at the Cumberland River mining complex extract steam and
metallurgical coal from the Imboden, Taggart Marker, Middle
Taggart, Upper Taggart, Owl, and Parsons seams. The Cumberland
River mining complex shipped 2.4 million tons of coal in
2008. |
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We control a significant portion of the coal reserves through
private leases. The Cumberland River mining complex had
approximately 23.3 million tons of proven and probable
reserves at December 31, 2008. Without the addition of more
coal reserves, the current reserves will sustain current
production levels until 2017 before annual output starts to
significantly decline. |
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The complex currently consists of four underground mines (three
captive, one contract) operating 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. We
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 |
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railroad. The loadout facility can load a 12,500-ton train in
less than four hours. |
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Lone Mountain |
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Lone Mountain is an underground mining complex located on
approximately 22,000 acres in Harlan County, Kentucky and
Lee County, Virginia. The Lone Mountain mining complex extracts
steam and metallurgical coal from the Kellioka, Darby and Owl
seams. The Lone Mountain mining complex shipped 2.7 million
tons of coal in 2008. |
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We control a significant portion of the coal reserves through
private leases. The Lone Mountain mining complex had
approximately 34.1 million tons of proven and probable
reserves at December 31, 2008. Without the addition of more
coal reserves, the current reserves will sustain current
production levels until 2017 before annual output starts to
significantly decline. |
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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. |
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Mountain Laurel |
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Mountain Laurel is an underground and surface mining complex
located on approximately 38,100 acres in Logan County, West
Virginia. Underground mining operations at the Mountain Laurel
mining complex extract steam and metallurgical coal from the
Cedar Grove and Alma seams. Surface mining operations at the
Mountain Laurel mining complex extract steam coal from a number
of different splits of the Five Block, Stockton and Coalburg
seams. The Mountain Laurel mining complex shipped
4.3 million tons of coal in 2008. |
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We control a significant portion of the coal reserves through
private leases. The Mountain Laurel mining complex had
approximately 90.7 million tons of proven and probable
reserves at December 31, 2008. Without the addition of more
coal reserves, the current reserves will sustain current
production levels until 2017 before annual output starts to
significantly decline. |
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The complex currently consists of one underground mine operating
a longwall and a total of four continuous miner sections, one
contract surface operation, 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. |
Sales,
Marketing and Trading
Overview. Coal prices are influenced by a
number of factors and vary materially 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, coal quality, transportation
costs involved in moving coal from the mine to the point of use,
mine operating costs and the costs and availability of
alternative fuels, such as nuclear energy, natural gas,
hydropower and
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petroleum. For example, higher carbon and lower ash content
generally result in higher prices, and higher sulfur and higher
ash content generally result in lower prices within a given
geographic region.
The cost of coal at the mine is also 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.
Our sales, marketing and trading force is principally based in
St. Louis, Missouri and consists of sales and trading
personnel, transportation and distribution personnel, quality
control personnel and contract administration personnel. In
addition to selling coal produced in our mining complexes, from
time to time, we purchase and sell coal mined by others, some of
which we blend with coal produced from our mines. We focus on
meeting the needs and specifications of our customers rather
than just selling our coal production.
Customers. In 2008, we sold coal to domestic
customers located in 35 different states. The majority of those
customers operate power plants, steel mills and industrial
facilities located throughout 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. For the year
ended December 31, 2008, we derived approximately 24% of
our total coal revenues from sales to our three largest
customers, Tennessee Valley Authority, Ameren Corporation and
TUCO, Inc., and approximately 48% of our total coal revenues
from sales to our ten largest customers. During 2008, we also
exported coal to customers located in 21 countries in North
America, Europe, South America, Africa and Asia. Coal sales
revenue from foreign customers approximated $486.1 million
for 2008, $196.7 million for 2007 and $162.5 million
for 2006. We seek to reduce our exposure to foreign currency
fluctuations by settling all of our coal sales in
U.S. dollars.
Worldwide steel prices increased significantly during the first
half of 2008 due, in part, to shortages of raw materials,
production control particularly in China in advance of the
Beijing Olympics and spreading inflation in many parts of the
globe. As the price of steel increased during the first six
months of 2008, so too did the demand for metallurgical coal. We
produced a higher percentage of metallurgical quality coal
during 2008 than we did in 2007 or 2006 to take advantage of
these favorable price trends. We sold approximately
4.4 million tons of metallurgical quality coal in 2008,
approximately 2.1 million tons of metallurgical quality
coal in 2007 and approximately 2.0 million tons of
metallurgical quality coal in 2006.
Long-Term
Coal Supply Arrangements
As is customary in the coal industry, we enter into fixed price,
fixed volume long-term supply contracts, the terms of which are
more than one year, with many of our customers. Multiple year
contracts usually have specific and possibly different volume
and pricing arrangements for each year of the contract.
Long-term contracts allow customers to secure a supply for their
future needs and provide us with greater predictability of sales
volume and sales prices. In 2008, we sold approximately 76% of
our coal under long-term supply arrangements. Most of our supply
contracts include a fixed price for the term of the agreement or
a pre-determined escalation in price for each year. Some of our
long-term supply agreements may include a variable pricing
system. While most of our sales contracts are for terms of one
to five years, some are as short as one to 11 months and
other contracts have terms longer than 10 years. At
December 31, 2008, the average volume-weighted remaining
term of our long-term contracts was approximately
3.4 years, with remaining terms ranging from one to nine
years. At December 31, 2008, we had a sales backlog,
including a backlog subject to price reopener or extension
provisions, of approximately 311.7 million tons.
We typically sell coal to customers under long-term arrangements
through a request-for-proposal process. The terms of
our coal sales agreements result from competitive bidding and
extensive negotiations with customers. Consequently, the terms
of these contracts vary by customer, including base price
adjustment features,
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price reopener terms, coal quality requirements, quantity
parameters, permitted sources of supply, future regulatory
changes, extension options, force majeure, termination
and assignment provisions. Our long-term supply contracts
generally contain provisions to adjust the base price due to new
statutes, ordinances or regulations, such as the Mine
Improvement and New Emergency Response Act of 2006, which we
refer to as the MINER Act, that affect our costs related to
performance of the agreement. Additionally, some of our
contracts contain provisions that allow for the recovery of
costs affected by modifications or changes in the
interpretations or application of any applicable statute by
local, state or federal government authorities. These provisions
only apply to the base price of coal contained in these supply
contracts. In some circumstances, a significant adjustment in
base price can lead to termination of the contract.
Certain of our contracts contain price re-opener and index
provisions that may allow a party to commence a renegotiation of
the contract price at a pre-determined time. Price re-opener
provisions may automatically set a new price based on prevailing
market price or, in some instances, require us to negotiate a
new price, sometimes between a specified range of prices. In a
limited number of agreements, if the parties do not agree on a
new price, either party has an option to terminate the contract.
Under some of our contracts, we have the right to match lower
prices offered to our customers by other suppliers. In addition,
many of our contracts contain clauses which in some cases may
allow customers to terminate the contract in the event of
certain changes in environmental laws and regulations that
impact their operations.
Quality and volumes for the coal are stipulated in coal sales
agreements. In most cases, the annual pricing and volume
obligations are fixed although in some cases the volume
specified may vary depending on the quality of the coal. Most of
our coal sales agreements contain provisions requiring us to
deliver coal within certain ranges for specific coal
characteristics such as heat content, sulfur, ash and moisture
content. Failure to meet these specifications can result in
economic penalties, suspension or cancellation of shipments or
termination of the contracts.
Our coal sales agreements also typically contain force
majeure provisions allowing temporary suspension of
performance by us, or our customers, during the duration of
events beyond the control of the affected party, including
events such as strikes, adverse mining conditions, mine closures
or serious transportation problems that affect us or
unanticipated plant outages that may affect the buyer. Our
contracts generally provide that in the event a force majeure
circumstance exceeds a certain time period the unaffected
party may have the option to terminate the sale in whole or in
part. Some contracts stipulate that this tonnage can be made up
by mutual agreement or at the discretion of the buyer.
Agreements between our customers and the railroads servicing our
mines may also contain force majeure provisions.
Generally, our coal sales agreements allow our customer to
suspend performance in the event that the railroad fails to
provide its services due to circumstances that would constitute
a force majeure.
In most of our contracts, we have a right of substitution,
allowing us to provide coal from different mines, including
third-party mines, as long as the replacement coal meets quality
specifications and will be sold at the same delivered cost.
Generally, under the terms of our coal supply contracts, we
agree to indemnify or reimburse our customers for damage to
their or their rail carriers equipment while on our
property, other than from their own negligence, and for damage
to our customers equipment due to non-coal materials being
included with our coal before leaving our property.
Trading. In addition to marketing and selling
coal to customers through traditional coal supply arrangements,
we seek to optimize our coal production and leverage our
knowledge of the coal industry through a variety of other
marketing, trading and asset optimization strategies. From time
to time, we may employ strategies to use coal and coal-related
commodities and contracts for those commodities in order to
manage and hedge fixed price coal sales or purchase commitments,
reduce our exposure to the volatility of market prices or
augment the value of our portfolio of traditional assets. These
strategies may include physical coal, as well as a variety of
forward, futures or options contracts, swap agreements or other
financial instruments.
We maintain a system of complementary processes and controls
designed to monitor and manage our exposure to market and other
risks that may arise as a consequence of these strategies. These
processes and
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controls seek to preserve our ability to profit from certain
marketing, trading and asset optimization strategies while
mitigating our exposure to potential losses. You should see the
section entitled Quantitative and Qualitative Disclosures
About Market Risk beginning on page 67 for more
information about the market risks associated with these
strategies at December 31, 2008.
Transportation. We ship our coal to domestic
customers by means of railroad, barges or trucks, or a
combination of these means of transportation. We generally sell
coal used for domestic consumption free on board at the mine or
nearest loading facility. Our domestic customers normally bear
the costs of transporting coal by rail or barge.
We generally sell coal to international customers at the export
terminal, and we are usually responsible for the cost of
transporting coal to the export terminals. We transport our coal
to Atlantic or Pacific coast terminals or terminals along the
Gulf of Mexico for transportation to international customers.
Our international customers are generally responsible for paying
the cost of ocean freight.
We own a 22% 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.
Historically, most domestic electricity generators have arranged
long-term shipping contracts with rail or barge companies to
assure stable delivery costs. Transportation can be a large
component of a purchasers total cost. Although the
purchaser pays the freight, transportation costs still are
important to coal mining companies because the purchaser may
choose a supplier largely based on cost of transportation.
Transportation costs borne by the customer vary greatly based on
each customers proximity to the mine and our proximity to
the loadout facilities. Trucks and overland conveyors haul coal
over shorter distances, while barges, Great Lake carriers and
ocean vessels move coal to export markets and domestic markets
requiring shipment over the Great Lakes and several river
systems.
Most coal mines are served by a single rail company, but much of
the Powder River Basin is served by two rail carriers: the
Burlington Northern Santa Fe Railway and the Union Pacific
Railroad. In the Western Bituminous region, our customers are
largely served by the Union Pacific Railroad. We generally
transport coal produced at our Central Appalachian mining
complexes via the CSX Railway or the Norfolk Southern Railway.
Besides rail deliveries, some customers in the eastern
U.S. rely on a river barge system. 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 load up to six million tons of coal annually for
shipment on the inland waterways.
Competition
The coal industry is intensely competitive. The most important
factors on which we compete are coal quality, delivered costs to
the customer and the reliability of supply. Our principal
domestic competitors include Alpha Natural Resources, Inc.,
CONSOL Energy Inc., Foundation Coal Holdings, Inc., 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.
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Suppliers
Principal supplies used in our business include petroleum-based
fuels, explosives, tires, steel and other raw materials as well
as spare parts and other consumables used in the mining process.
We use third-party suppliers for a significant portion of our
equipment rebuilds and repairs, drilling services and
construction. We use sole source suppliers for certain parts of
our business such as dragline shovel parts and services and
tires. We believe adequate substitute suppliers are available.
For more information about our suppliers, you should see
Risk Factors 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.
Environmental
and Other Regulatory Matters
Federal, state and local authorities regulate the U.S. coal
mining industry with respect to matters such as employee health
and safety and the environment, including protection of air
quality, water quality, wetlands, special status species of
plants and animals, land uses, cultural and historic properties
and other environmental resources identified during the
permitting process. Contemporaneous reclamation is required
during and after mining has been completed. Materials used and
generated by mining operations must also be managed according to
applicable regulations and law. These laws have, and will
continue to have, a significant effect on our production costs
and our competitive position. Future laws, regulations or
orders, as well as future interpretations and more rigorous
enforcement of existing laws, regulations or orders, may require
substantial increases in equipment and operating costs and
delays, interruptions or a termination of operations, the extent
to which we cannot predict. Future laws, regulations or orders
may also cause coal to become a less attractive fuel source,
thereby reducing coals share of the market for fuels and
other energy sources used to generate electricity. As a result,
future laws, regulations or orders may adversely affect our
mining operations, cost structure or our customers demand
for coal.
We endeavor to conduct our mining operations in compliance with
all applicable federal, state and local laws and regulations.
However, due in part to the extensive and comprehensive
regulatory requirements, violations during mining operations
occur from time to time. We cannot assure you that we have been
or will be at all times in complete compliance with such laws
and regulations. 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:
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 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. For example, in order to obtain a federal coal
lease, an environmental impact statement must be prepared to
assist the BLM in determining the potential environmental impact
of lease issuance, including any collateral effects from the
mining, transportation and burning of coal. The authorization,
permitting and implementation requirements imposed by federal,
state and local authorities may be costly and time consuming and
may delay commencement or continuation of mining operations. In
the states where we operate, the applicable laws and regulations
also provide that a mining permit or modification can be
delayed, refused or revoked if officers, directors, shareholders
with specified interests or certain other affiliated entities
with specified interests in the applicant or permittee have, or
are affiliated with another entity that has, outstanding permit
violations. Thus, past or ongoing violations of applicable laws
and regulations could provide a basis to revoke existing permits
and to deny the issuance of additional permits.
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In order to obtain mining permits and approvals from federal and
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 or other
authorized use. 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.
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 regulatory 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. All states in which we
conduct mining operations have achieved primacy and issue
permits in lieu of OSM.
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. We begin the process of
preparing a mining permit application 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
and information derived from the other surveys
and/or
assessments are used to develop the mining and reclamation plans
presented in the permit application. 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 OSMs 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
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produced from surface mines and $0.135 per ton of coal produced
from underground mines. In 2008, we recorded $37.1 million
of expense related to these reclamation fees.
Surety Bonds. Mine operators are often
required by federal
and/or state
laws, including SMCRA, 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 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, 2008, we have self-bonded an aggregate of
$334.6 million and have posted an aggregate of
$241.0 million in surety bonds for reclamation purposes. In
addition, we had approximately $140.0 million of surety
bonds and letters of credit outstanding at December 31,
2008 to secure workers compensation, coal lease and other
obligations.
Mine Safety and Health. 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 aimed
at improving mine safety and health. Collectively, federal and
state safety and health regulation in the coal mining industry
is among the most comprehensive and pervasive systems for the
protection of employee health and safety affecting any segment
of U.S. industry. In reaction to recent mine accidents,
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 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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In 2008, the U.S. House of Representatives approved
additional federal legislation which would have required new
regulations on a variety of mine safety issues such as
underground refuges, mine ventilation and communication systems.
Although the U.S. Senate failed to pass that legislation,
it is possible that similar legislation may be proposed in the
future. Various states, including West Virginia, have also
enacted new laws to address many of the same subjects. The costs
of implementing these new safety and health regulations at the
federal and state level have been, and will continue to be,
substantial. In addition to the cost of implementation, there
are increased penalties for violations which may also be
substantial. Expanded enforcement has resulted 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
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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 2008, we recorded $71.7 million of
expense related to this excise tax.
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 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,
promulgated in 1990, imposed 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 been factored
into the pricing of the coal market.
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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 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
12 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 new 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 then-current 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 still subject to judicial challenge, however, making
its impact difficult to assess. Nonetheless, if the EPAs
current rules are upheld and if the new, more stringent ozone
NAAQS withstand scrutiny, 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
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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, which could
make 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 28 eastern states and
the District of Columbia to reduce emission levels of sulfur
dioxide and nitrous oxide pursuant to 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. 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. In July 2008, in State of North Carolina v.
EPA and consolidated cases, the U.S. Court of Appeals
for the District of Columbia Circuit disagreed with the
EPAs reading of the Clean Air Act and vacated CAIR in its
entirety. In December 2008, the U.S. Court of Appeals for
the District of Columbia Circuit revised its remedy and remanded
the rule to the EPA. The result is that CAIR will be implemented
and will remain in effect at least until the EPA responds to the
remand. Accordingly, new emissions controls that have been
constructed will be operated in 2009 in response to CAIR.
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Mercury. In February 2008, the U.S. 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. Under CAMR, coal-fueled power plants
would have had until 2010 to cut mercury emission levels from 48
tons to 38 tons a year 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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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 operations 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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New Source Review. A number of pending
regulatory changes and court actions will affect the scope of
the EPAs new source review program, which under certain
circumstances requires existing coal-fueled power plants to
install the more stringent air emissions control equipment
required of new plants. The changes to the new source review
program may impact demand for coal nationally, but as the final
form of the requirements after their revision is not yet known,
we are unable to predict the magnitude of the impact.
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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.
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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.
The U.S. Congress has considered various proposals to
reduce greenhouse gas emissions, but to date, none have become
law. 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. Although
Massachusetts v. EPA did not involve the EPAs
authority to regulate greenhouse gas emissions from stationary
sources, such as coal-fueled power plants, the decision is
likely to impact regulation of stationary sources. For example,
a challenge in the U.S. Court of Appeals for the District
of Columbia with respect to the EPAs decision not to
regulate greenhouse gas emissions from power plants and other
stationary sources under the Clean Air Acts new source
performance standards was remanded to the EPA for further
consideration in light of Massachusetts v. EPA. 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. In response to Massachusetts v.
EPA, in July 2008, the EPA issued a notice of proposed
rulemaking requesting public comment on the regulation of
greenhouse gases. If as a result of these actions the EPA were
to set emission limits for carbon dioxide from electric
utilities or steel mills, the demand for coal could decrease.
In the absence of federal legislation or regulation, many states
and regions have adopted greenhouse gas initiatives. In 2002,
the Conference of New England Governors and Eastern Canadian
Premiers adopted a Climate Change Action Plan, calling for
reduction in regional greenhouse gas 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 implementation
of a cap and trade program by 2009 aimed at reducing carbon
dioxide emissions from power plants in the participating states.
Since its inception, several additional northeastern states and
Canadian provinces have joined as participants or observers.
RGGI held its first carbon dioxide allowance auction in
September 2008 and will hold quarterly auctions during the
initial three-year compliance period from January 1, 2009
to December 31, 2011 to allow utilities to buy allowances
to cover their carbon dioxide emissions.
Climate change initiatives are also being considered or enacted
in some western states. In September 2006, California adopted
the Global Warming Solutions Act of 2006, which establishes a
statewide greenhouse gas emissions cap of 1990 levels by 2020
and sets a framework for further reductions after 2020. In
September 2006, California also 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 to 15% below 2005 levels by 2020. Since its
initial launching, a number of additional western states and
Canadian provinces have joined the initiative or have agreed to
participate as observers. The proposed scope of the cap and
trade program pursuant to the Western Climate Initiative
includes fossil fuels, such as coal, production and processing.
As a result, our coal mines could incur direct costs if the
proposals are implemented by Montana and Wyoming, although we
currently do not believe that any such direct costs on our
operations would be material.
Midwestern states have also adopted initiatives to reduce and
monitor greenhouse gas emissions. In November 2007, the
governors of Illinois, Indiana, Iowa, Kansas, Michigan,
Minnesota, Ohio, South Dakota
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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 and regional 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 or at the federal
level, will not affect the future market for coal in those
regions. The permitting of new coal-fueled power plants has also
recently been contested by state regulators and environmental
organizations based on concerns relating to greenhouse gas
emissions. Increased efforts to control greenhouse gas emissions
could result in reduced demand for coal.
Clean Water Act. The federal Clean Water Act
and corresponding state and local laws and regulations affect
coal mining operations by restricting the discharge of
pollutants, including dredged and fill materials, into waters of
the United States. The Clean Water Act provisions and associated
state and federal regulations are complex and subject to
amendments, legal challenges and changes in implementation.
Recent court decisions and regulatory actions have created
uncertainty over Clean Water Act jurisdiction and permitting
requirements that could variously increase or decrease the cost
and time we expend on Clean Water Act compliance.
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 discharges into waters of
the United States. Discharges that exceed the limits specified
under NPDES permits can lead to the imposition of penalties, and
persistent non-compliance could lead to significant penalties,
compliance costs and delays in coal production. In addition, the
imposition of future restrictions on the discharge of certain
pollutants into waters of the United States could increase the
difficulty of obtaining and complying with NPDES permits, which
could impose additional time and cost burdens on our operations.
You should see Item 3 Legal Proceedings
beginning on page 45 for more information about certain
regulatory actions pertaining to our operations.
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Discharges of pollutants into waters that states have designated
as impaired (i.e., as not meeting present water quality
standards) are subject to Total Maximum Daily Load, which we
refer to as TMDL, regulations. The TMDL regulations establish a
process for calculating the maximum amount of a pollutant that a
water body can receive while maintaining state water quality
standards. Pollutant loads are allocated among the various
sources that discharge pollutants into that water body. Mine
operations that discharge into water bodies designated as
impaired will be required to meet new TMDL allocations. The
adoption of more stringent TMDL-related allocations for our coal
mines could require more costly water treatment and could
adversely affect our coal production.
The Clean Water Act also requires states to develop
anti-degradation policies to ensure that non-impaired water
bodies continue to meet water quality standards. The issuance
and renewal of permits for the discharge of pollutants to waters
that have been designated as high quality are
subject to anti-degradation review that may increase the costs,
time and difficulty associated with obtaining and complying with
NPDES permits.
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Dredge and Fill Permits. 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. Under the Clean Water
Act, coal companies are required to obtain a Section 404
permit from the Army Corps of Engineers, which we refer to as
the Corps, prior to conducting such mining activities. The Corps
is authorized to issue general nationwide permits
for specific categories of activities that are similar in nature
and that are determined
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to have minimal adverse effects on the environment. Permits
issued pursuant to Nationwide Permit 21, which we refer to as
NWP 21, generally authorize the disposal of dredged and fill
material from surface coal mining activities into waters of the
United States, subject to certain restrictions. Since March
2007, permits under NWP 21 were reissued for a five-year period
with new provisions intended to strengthen environmental
protections. There must be appropriate mitigation in accordance
with nationwide general permit conditions rather than less
restricted state-required mitigation requirements, and
permitholders must receive explicit authorization from the Corps
before proceeding with proposed mining activities.
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The use of nationwide permits to authorize stream impacts from
mining activities has been the subject of significant
litigation. You should see Item 3 Legal
Proceedings beginning on page 45 for more information about
certain litigation pertaining to our permits.
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 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.
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.
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
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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.
Use of Explosives. Our surface mining
operations are subject to numerous regulations relating to
blasting activities. Pursuant to these regulations, we incur
costs to design and implement blast schedules and to conduct
pre-blast surveys and blast monitoring. In addition, the storage
of explosives is subject to strict regulatory requirements
established by four different federal regulatory agencies. For
example, pursuant to a rule issued by the Department of Homeland
Security in 2007, facilities in possession of chemicals of
interest, including ammonium nitrate at certain threshold
levels, must complete a screening review in order to help
determine whether there is a high level of security risk such
that a security vulnerability assessment and site security plan
will be required.
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.
Employees
General. At February 15, 2009, we
employed a total of approximately 4,300 persons,
approximately 240 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, 2009 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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60
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Mr. Besten has served as our Senior Vice President-Strategic
Development since 2002.
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John T. Drexler
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Mr. Drexler has served as our Senior Vice President and Chief
Financial Officer since April 2008. Mr. Drexler served as our
Vice President-Finance and Accounting from March 2006 to April
2008. From March 2005 to March 2006, Mr. Drexler served as our
Director of Planning and Forecasting. Prior to March 2005, Mr.
Drexler held several other positions within our finance and
accounting department.
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John W. Eaves
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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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Ms. Feldman has served as our Vice President-Human Resources
since 2003. From 1997 to 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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Mr. Jones has served as our Senior Vice President-Law, General
Counsel and Secretary since August 2008. Mr. Jones served as
Vice President-Law, General Counsel and Secretary from 2000 to
August 2008.
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Paul A. Lang
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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
1998 through July 2005.
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Steven F. Leer
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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 past 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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David B. Peugh
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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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Mr. Slone has served as our Vice President-Government, Investor
and Public Affairs since August 2008. Mr. Slone served as our
Vice President-Investor Relations and Public Affairs from 2001
to August 2008.
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David N. Warnecke
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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 27,
2008.
29
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 without charge
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, 63141 Attention: Vice
President-Government, Investor 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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Coal
prices are subject to change and a substantial or extended
decline in prices could materially and adversely 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. The contract prices we may
receive in the future for coal depend upon factors beyond our
control, including the following:
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the domestic and foreign supply and demand for coal;
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the quantity and quality of coal available from competitors;
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competition for production of electricity from non-coal sources,
including the price and availability of alternative fuels, such
as natural gas and oil, and alternative energy sources, such as
nuclear, hydroelectric, wind and solar power;
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domestic air emission standards for coal-fueled power plants and
the ability of coal-fueled power plants to meet these standards
by installing scrubbers or other means;
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adverse weather, climatic or other natural conditions, including
natural disasters;
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domestic and foreign economic conditions, including economic
slowdowns;
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legislative, regulatory and judicial developments, environmental
regulatory changes or changes in energy policy and energy
conservation measures that would adversely affect the coal
industry, such as legislation limiting carbon emissions or
providing for increased funding and incentives for alternative
energy sources;
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the proximity, capacity and cost of transportation
facilities; and
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market price fluctuations for sulfur dioxide emission allowances.
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A substantial or extended decline in the prices we receive for
our future coal sales contracts could materially and adversely
affect us by decreasing our profitability and the value of our
coal reserves.
30
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Our
coal mining operations are subject to operating risks that are
beyond our control, which could result in materially increased
operating expenses and decreased production levels and could
materially and adversely affect our profitability.
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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, adversely
affect production and shipments and increase our operating
costs, all of which could have a material adverse effect on our
results of operations:
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poor mining conditions resulting from geological, hydrologic or
other conditions that may cause instability of highwalls or
spoil piles or cause damage to nearby infrastructure or mine
personnel;
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a major incident at the mine site that causes all or part of the
operations of the mine to cease for some period of time;
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mining, processing and plant equipment failures and unexpected
maintenance problems;
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adverse weather and natural disasters, such as heavy rains or
snow, flooding and other natural events affecting operations,
transportation or customers;
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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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competition
and/or
conflicts with other natural resource extraction activities and
production within our operating areas, such as coalbed methane
extraction or oil and gas development.
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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
shipments 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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Competition
within our industry and with producers of competing energy
sources may materially and adversely affect our ability to sell
coal at favorable prices.
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We compete with numerous other coal producers in various regions
of the United States for domestic sales. International demand
for U.S. coal also affects competition within our industry.
The demand for U.S. coal exports depends upon a number of
factors outside our control, including the overall demand for
electricity in foreign markets, currency exchange rates, ocean
freight rates, port and shipping capacity, the demand for
foreign-priced steel, both in foreign markets and in the
U.S. market, general economic conditions in foreign
countries, technological developments and environmental and
other governmental regulations. Foreign demand for Central
Appalachian coal has increased in recent periods. If foreign
demand for U.S. coal were to decline, this decline could
cause competition among coal producers for the sale of coal in
the United States to intensify, potentially resulting in
significant downward pressure on domestic coal prices.
In addition to competing with other coal producers, we compete
generally with producers of other fuels, such as natural gas and
oil. In recent periods, prices for competing fuels have reached
historically high levels. A decline in the price for these fuels
could cause demand for coal to decrease and adversely affect the
price of our coal. If alternative energy sources, such as wind
or solar, become more cost-competitive on an overall basis,
including capital expenditures and conversion, storage and
transmission costs, demand for coal could decrease and the price
of coal could be materially and adversely affected.
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Excess
production and production capacity in the coal industry could
put downward pressure on coal prices and, as a result,
materially and adversely affect our revenues and
profitability.
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During the mid-1970s and early 1980s, increased demand for coal
attracted new investors to the coal industry, spurred the
development of new mines and resulted in additional production
capacity throughout the industry, all of which led to increased
competition and lower coal prices. Increases in coal prices over
the past
31
several years have encouraged the development of expanded
capacity by coal producers and may continue to do so. Any
resulting overcapacity and increased production could materially
reduce coal prices and therefore materially reduce our revenues
and profitability.
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Decreases
in demand for electricity resulting from economic, weather
changes or other conditions could adversely affect coal prices
and materially and adversely affect our results of
operations.
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Our coal is primarily used as fuel for electricity generation.
Overall economic activity and the associated demands for power
by industrial users can have significant effects on overall
electricity demand. An economic slowdown can significantly slow
the growth of electrical demand and could result in contraction
of demand for coal. Declines in international prices for coal
generally will impact U.S. prices for coal. During the past
several years, international demand for coal has been driven, in
significant part, by fluctuations in demand due to economic
growth in China and India as well as other developing countries.
Significant declines in the rates of economic growth in these
regions could materially affect international demand for
U.S. coal, which may have an adverse effect on
U.S. coal prices.
Weather patterns can also greatly affect electricity demand.
Extreme temperatures, both hot and cold, cause increased power
usage and, therefore, increased generating requirements from all
sources. Mild temperatures, on the other hand, result in lower
electrical demand, which allows generators to choose the sources
of power generation when deciding which generation sources to
dispatch. Any downward pressure on coal prices, due to decreases
in overall demand or otherwise, including changes in weather
patterns, would materially and adversely affect our results of
operations.
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The
use of alternative energy sources for power generation could
reduce coal consumption by U.S. electric power generators, which
could result in lower prices for our coal. Declines in the
prices at which we sell our coal could reduce our revenues and
materially and adversely affect our business and results of
operations.
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In 2008, approximately 85.9% of the tons we sold were to
domestic electric power generators. Domestic electric power
generation accounted for approximately 92.7% of all
U.S. coal consumption in 2007, according to the EIA. The
amount of coal consumed for U.S. electric power generation
is affected by, among other things:
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the location, availability, quality and price of alternative
energy sources for power generation, such as natural gas, fuel
oil, nuclear, hydroelectric, wind and solar power; and
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technological developments, including those related to
alternative energy sources.
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Gas-fueled generation has the potential to displace coal-fueled
generation, particularly from older, less efficient coal-powered
generators. We expect that many of the new power plants needed
to meet increasing demand for electricity generation will be
fueled by natural gas because gas-fired plants are cheaper to
construct and permits to construct these plants are easier to
obtain as natural gas is seen as having a lower environmental
impact than coal-fueled generators. In addition, state and
federal mandates for increased use of electricity from renewable
energy sources could have an impact on the market for our coal.
Several states have enacted legislative mandates requiring
electricity suppliers to use renewable energy sources to
generate a certain percentage of power. There have been numerous
proposals to establish a similar uniform, national standard
although none of these proposals have been enacted to date.
Possible advances in technologies and incentives, such as tax
credits, to enhance the economics of renewable energy sources
could make these sources more competitive with coal. Any
reduction in the amount of coal consumed by domestic electric
power generators could reduce the price of coal that we mine and
sell, thereby reducing our revenues and materially and adversely
affecting our business and results of operations.
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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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Our profitability depends substantially on our ability to mine
and process, in a cost-effective manner, coal reserves that
possess the quality characteristics desired by our customers. As
we mine, our coal reserves decline.
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As a result, our future success depends upon our ability to
acquire additional coal that is economically recoverable. If we
fail to acquire or develop additional coal reserves, our
existing reserves will eventually be depleted. 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 the availability of cash we generate
from our operations or available financing, restrictions under
our existing or future financing arrangements, and competition
from other coal producers, the lack of suitable acquisition or
lease-by-application,
or LBA, opportunities or the inability to acquire coal
properties or LBAs on commercially reasonable terms. If we are
unable to acquire replacement reserves, our future production
may decrease significantly and our operating results may be
negatively affected. In addition, we may not be able to mine
future reserves as profitably as we do at our current operations.
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Inaccuracies
in our estimates of our coal reserves could result in decreased
profitability from lower than expected revenues or higher than
expected costs.
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Our future performance depends on, among other things, the
accuracy of our estimates of our proven and probable coal
reserves. We base our estimates of reserves on engineering,
economic and geological data assembled, analyzed and reviewed by
internal and third-party engineers and consultants. We update
our estimates of the quantity and quality of proven and probable
coal reserves annually to reflect the production of coal from
the reserves, updated geological models and mining recovery
data, the tonnage contained in new lease areas acquired and
estimated costs of production and sales prices. There are
numerous factors and assumptions inherent in estimating the
quantities and qualities of, and costs to mine, coal reserves,
including many factors beyond our control, including the
following:
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quality of the coal;
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geological and mining conditions, which may not be fully
identified by available exploration data
and/or may
differ from our experiences in areas where we currently mine;
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the percentage of coal ultimately recoverable;
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the assumed effects of regulation, including the issuance of
required permits, taxes, including severance and excise taxes
and royalties, and other payments to governmental agencies;
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assumptions concerning the timing for the development of the
reserves; and
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assumptions concerning equipment and productivity, future coal
prices, operating costs, including for critical supplies such as
fuel, tires and explosives, capital expenditures and development
and reclamation costs.
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As a result, estimates of the quantities and qualities of
economically recoverable coal attributable to any particular
group of properties, classifications of reserves based on risk
of recovery, estimated cost of production, and estimates of
future net cash flows expected from these properties as prepared
by different engineers, or by the same engineers at different
times, may vary materially due to changes in the above factors
and assumptions. Actual production recovered from identified
reserve areas and properties, and revenues and expenditures
associated with our mining operations, may vary materially from
estimates. Any inaccuracy in our estimates related to our
reserves could result in decreased profitability from lower than
expected revenues
and/or
higher than expected costs.
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.
Our coal mining operations use significant amounts of steel,
diesel fuel, explosives, 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. In the past several years, we
have
33
experienced shortages of certain large rubber tires we use in
our mining operations. We have mitigated these shortages by
purchasing less efficient large rubber tires at higher costs. In
addition, 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.
In the future, we may be unable to obtain a sufficient quantity
of rubber tires 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.
Our
labor costs could increase if the shortage of skilled coal
mining workers continues.
Efficient coal mining using modern techniques and equipment
requires skilled workers in multiple disciplines such as
electricians, equipment operators, engineers and welders, among
others. 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.
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.
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 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.
Our
ability to collect payments from our customers could be impaired
if their creditworthiness deteriorates.
We have contracts to supply coal to energy trading and brokering
companies under which they purchase the coal for their own
account or resell the coal to end users. Our ability to receive
payment for coal sold and delivered depends on the continued
creditworthiness of our customers. If we determine that a
customer is not creditworthy, we may not be required to deliver
coal under the customers coal sales contract. If this
occurs, we may decide to sell the customers coal on the
spot market, which may be at prices lower than the contracted
price, or we may be unable to sell the coal at all. Furthermore,
the bankruptcy of any of our customers could materially and
adversely affect our financial position. In addition, our
customer base may change with deregulation as utilities sell
their power plants to their non-regulated affiliates or third
parties that may be less creditworthy, thereby increasing the
risk we bear for customer payment default. These new power plant
owners may have credit ratings that are below investment grade,
or may become below investment grade after we enter into
contracts with them. In addition, competition with other coal
suppliers could force us to extend credit to customers and on
terms that could increase the risk of payment default.
A
defect in title or the loss of a leasehold interest in certain
property could limit our ability to mine our coal reserves or
result in significant unanticipated costs.
We conduct a significant part of our coal mining operations on
properties that we lease. A title defect or the loss of a lease
could adversely affect our ability to mine the associated coal
reserves. We may not verify title
34
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.
The
availability and reliability of transportation facilities and
fluctuations in transportation costs could affect the demand for
our coal or impair our ability to supply coal to our
customers.
We depend upon barge, 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.
We may
be unable to realize the benefits we expect to occur as a result
of acquisitions that we undertake.
We continually seek to expand our operations and coal reserves
through acquisitions of other businesses and assets, including
leasehold interests. Certain risks, including those listed
below, could cause us not to realize the benefits we expect to
occur as a result of those acquisitions:
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uncertainties in assessing the value, risks, profitability and
liabilities (including environmental liabilities) associated
with certain businesses or assets;
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the potential loss of key customers, management and employees of
an acquired business;
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the possibility that operating and financial synergies expected
to result from an acquisition do not develop;
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problems arising from the integration of an acquired
business; and
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unanticipated changes in business, industry or general economic
conditions that affect the assumptions underlying the rationale
for a particular acquisition.
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Our
profitability depends upon the long-term coal supply agreements
we have with our customers. Changes in purchasing patterns in
the coal industry could make it difficult for us to extend our
existing long-term coal supply agreements or to enter into new
agreements in the future.
We sell a 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.
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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 17.
The
loss of, or significant reduction in, purchases by our largest
customers could adversely affect our
profitability.
For the year ended December 31, 2008, we derived
approximately 24% of our total coal revenues from sales to our
three largest customers and approximately 48% of our total coal
revenues from sales to our ten largest customers. We expect to
renew, extend or enter into new long-term coal supply agreements
with those and other customers. However, we may be unsuccessful
in obtaining long-term coal supply agreements with those
customers, and those customers may discontinue purchasing coal
from us. If any of those customers, particularly any of our
three largest customers, was to significantly reduce the
quantities of coal it purchases from us, or if we are unable to
sell coal to those customers on terms as favorable to us as the
terms under our current long-term coal supply agreements, our
profitability could suffer significantly. We have limited
protection during adverse economic conditions and may face
economic penalties if we are unable to satisfy certain quality
specifications under our long-term coal supply agreements.
Our long-term coal supply agreements typically contain force
majeure provisions allowing the parties to temporarily
suspend performance during specified events beyond their
control. Most of our long-term coal supply agreements also
contain provisions requiring us to deliver coal that satisfies
certain quality specifications, such as heat value, sulfur
content, ash content, hardness and ash fusion temperature. These
provisions in our long-term coal supply agreements could result
in negative economic consequences to us, including price
adjustments, purchasing replacement coal in a higher-priced open
market, the rejection of deliveries or, in the extreme, contract
termination. Our profitability may be negatively affected if we
are unable to seek protection during adverse economic conditions
or if we incur financial or other economic penalties as a result
of these provisions of our long-term supply agreements.
The
amount of indebtedness we have incurred could significantly
affect our business.
At December 31, 2008, 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 have significant consequences to us, such as:
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limiting our ability to obtain additional financing to fund
growth, such as new LBA acquisitions or other mergers and
acquisitions, working capital, capital expenditures, debt
service requirements or other cash requirements
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exposing us to the risk of increased interest costs if the
underlying interest rates rise;
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limiting our ability to invest operating cash flow in our
business due to existing debt service requirements;
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making it more difficult to obtain surety bonds, letters of
credit or other financing, particularly during weak credit
markets;
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causing a decline in our credit ratings;
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limiting our ability to compete with companies that are not as
leveraged and that may be better positioned to withstand
economic downturns;
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limiting our ability to acquire new coal reserves
and/or plant
and equipment needed to conduct operations; and
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limiting our flexibility in planning for, or reacting to, and
increasing our vulnerability to, changes in our business, the
industry in which we compete and general economic and market
conditions.
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If we further increase our indebtedness, the related risks that
we now face, including those described above, could intensify.
In addition to the principal repayments on our outstanding debt,
we have other demands on our cash resources, including capital
expenditures and operating expenses. Our ability to pay our debt
depends upon our operating performance. In particular, economic
conditions could cause our revenues to decline, and hamper our
ability to repay our indebtedness. If we do not have enough cash
to satisfy our debt service obligations, we may be required to
refinance all or part of our debt, sell assets or reduce our
spending. We may not be able to, at any given time, refinance
our debt or sell assets on terms acceptable to us or at all.
Volatility
and disruptions in the capital and credit markets could
adversely affect our business, including affecting the cost of
new capital, our ability to refinance scheduled debt maturities
and meet other obligations as they come due.
Capital and credit markets can experience extreme volatility and
disruption. This volatility and disruption can exert extreme
downward pressure on stock prices and upward pressure on the
cost of new debt capital and can severely restrict credit
availability. These disruptions can also result in higher
interest rates on publicly issued debt securities and increased
costs under credit facilities. These disruptions could increase
our interest expense and adversely affect our results of
operations and financial position.
Our access to funds under our financing arrangements is
dependent on the ability of the financial institutions that are
parties to those arrangements to meet their funding commitments.
Those financial institutions may not be able to meet their
funding commitments if they experience shortages of capital and
liquidity or if they experience excessive volumes of borrowing
requests within a short period of time.
Longer term volatility and continued disruptions in the capital
and credit markets as a result of uncertainty, changing or
increased regulation of financial institutions, reduced
alternatives or failures of significant financial institutions
could adversely affect our access to the liquidity needed for
our business in the longer term. Such disruptions could require
us to take measures to conserve cash until the markets stabilize
or until alternative credit arrangements or other funding for
our business needs can be arranged.
We may
be unable to comply with restrictions imposed by our credit
facilities and other financing arrangements.
The agreements governing our outstanding financing arrangements
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. 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. As a result, a default under
one or more of our existing or future financing arrangements
could have significant consequences 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 58.
37
Failure
to obtain or renew surety bonds on acceptable terms could affect
our ability to secure reclamation and coal lease obligations
and, therefore, our ability to mine or lease coal.
Federal and state laws require us to obtain surety bonds to
secure performance or payment of certain long-term obligations,
such as mine closure or reclamation costs, federal and state
workers compensation costs, coal leases and other
obligations. We may have difficulty procuring or maintaining our
surety bonds. Our bond issuers may demand higher fees,
additional collateral, including letters of credit or other
terms less favorable to us upon those renewals. Because we are
required by state and federal law to have these bonds in place
before mining can commence or continue, or failure to maintain
surety bonds, letters of credit or other guarantees or security
arrangements would materially and adversely affect our ability
to mine or lease coal. That failure could result from a variety
of factors, including lack of availability, higher expense or
unfavorable market terms, the exercise by third party surety
bond issuers of their right to refuse to renew the surety and
restrictions on availability on collateral for current and
future third party surety bond issuers under the terms of our
financing arrangements.
Our
profitability may be adversely affected if we must satisfy
certain below-market contracts with coal we purchase on the open
market or with coal we produce at our remaining
operations.
We have agreed to guarantee Magnums obligations to supply
coal under certain coal sales contracts that we sold to Magnum.
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, 2008, if we had purchased
the 17.8 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
$305.4 million.
We may
incur losses as a result of certain marketing, trading and asset
optimization strategies.
We seek to optimize our coal production and leverage our
knowledge of the coal industry through a variety of marketing,
trading and other asset optimization strategies. We maintain a
system of complementary processes and controls designed to
monitor and control our exposure to market and other risks as a
consequence of these strategies. These processes and controls
seek to balance our ability to profit from certain marketing,
trading and asset optimization strategies with our exposure to
potential losses. While we employ a variety of risk monitoring
and mitigation techniques, those techniques and accompanying
judgments cannot anticipate every potential outcome or the
timing of such outcomes. In addition, the processes and controls
that we use to manage our exposure to market and other risks
resulting from these strategies involve assumptions about the
degrees of correlation or lack thereof among prices of various
assets or other market indicators. These correlations may change
significantly in times of market turbulence or other unforeseen
circumstances. As a result, we may experience volatility in our
earnings as a result of our marketing, trading and asset
optimization strategies.
Terrorist
attacks and threats, escalation of military activity in response
to such attacks or acts of war may adversely affect our
business.
Terrorist attacks and threats, escalation of military activity
or acts of war have significant effects on general economic
conditions, fluctuations in consumer confidence and spending and
market liquidity. Future terrorist attacks, rumors or threats of
war, actual conflicts involving the United States or its allies,
or military or trade disruptions affecting our customers may
significantly affect our operations and those of our customers.
As a result, we could experience delays or losses in
transportation and deliveries of coal to our customers,
decreased sales of our coal or extended collections from our
customers.
38
Risks
Related to Environmental and Other Regulations
Extensive
environmental regulations, including existing and potential
future regulatory requirements relating to air emissions, affect
our customers and could reduce the demand for coal as a fuel
source and cause coal prices and sales of our coal to materially
decline.
The operations of our customers are subject to extensive
environmental regulation particularly with respect to air
emissions. For example, the federal Clean Air Act and similar
state and local laws extensively regulate the amount of sulfur
dioxide, particulate matter, nitrogen oxides, and other
compounds emitted into the air from electric power plants, which
are the largest end-users of our coal. A series of more
stringent requirements relating to particulate matter, ozone,
haze, mercury, sulfur dioxide, nitrogen oxide and other air
pollutants are expected to be proposed or become effective in
coming years. In addition, concerted conservation efforts that
result in reduced electricity consumption could cause coal
prices and sales of our coal to materially decline.
Considerable uncertainty is associated with these air emissions
initiatives. The content of regulatory requirements in the
U.S. is in the process of being developed, and many new
regulatory initiatives remain subject to review by federal or
state agencies or the courts. Stringent air emissions
limitations are either in place or are likely to be imposed in
the short to medium term, and these limitations will likely
require significant emissions control expenditures for many
coal-fueled power plants. As a result, these power plants may
switch to other fuels that generate fewer of these emissions or
may install more effective pollution control equipment that
reduces the need for low sulfur coal, possibly reducing future
demand for coal and a reduced need to construct new coal-fueled
power plants. The EIAs expectations for the coal industry
assume there will be a significant number of as yet unplanned
coal-fired plants built in the future which may not occur. Any
switching of fuel sources away from coal, closure of existing
coal-fired plants, or reduced construction of new plants could
have a material adverse effect on demand for and prices received
for our coal. Alternatively, less stringent air emissions
limitations, particularly related to sulfur, to the extent
enacted could make low sulfur coal less attractive, which could
also have a material adverse effect on the demand for and prices
received for our coal.
You should see Environmental and Other Regulatory
Matters beginning on page 20 for more information
about the various governmental regulations affecting us.
Our
failure to obtain and renew permits necessary for our mining
operations could negatively affect our business.
Mining companies must obtain numerous permits that impose strict
regulations on various environmental and operational matters in
connection with coal mining. These include permits issued by
various federal, state and local agencies and regulatory bodies.
The permitting rules, and the interpretations of these rules,
are complex, change frequently and are often subject to
discretionary interpretations by the regulators, all of which
may make compliance more difficult or impractical, and may
possibly preclude the continuance of ongoing operations or the
development of future mining operations. The public, including
non-governmental organizations, anti-mining groups and
individuals, have certain statutory rights to comment upon and
submit objections to requested permits and environmental impact
statements prepared in connection with applicable regulatory
processes, and otherwise engage in the permitting process,
including bringing citizens lawsuits to challenge the
issuance of permits, the validity of environmental impact
statements or performance of mining activities. Accordingly,
required permits may not be issued or renewed in a timely
fashion or at all, or permits issued or renewed may be
conditioned in a manner that may restrict our ability to
efficiently and economically conduct our mining activities, any
of which would materially reduce our production, cash flow and
profitability.
Federal
or state regulatory agencies have the authority to order certain
of our mines to be temporarily or permanently closed under
certain circumstances, which could materially and adversely
affect our ability to meet our customers
demands.
Federal or state regulatory agencies have the authority under
certain circumstances following significant health and safety
incidents, such as fatalities, to order a mine to be temporarily
or permanently closed. If this occurred, we may be required to
incur capital expenditures to re-open the mine. In the event
that these agencies
39
order the closing of our mines, our coal sales contracts
generally permit us to issue force majeure notices which
suspend our obligations to deliver coal under these contracts.
However, our customers may challenge our issuances of force
majeure notices. If these challenges are successful, we may
have to purchase coal from third-party sources, if it is
available, to fulfill these obligations, incur capital
expenditures to re-open the mines
and/or
negotiate settlements with the customers, which may include
price reductions, the reduction of commitments or the extension
of time for delivery or terminate customers contracts. Any
of these actions could have a material adverse effect on our
business and results of operations.
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.
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 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.
Extensive
environmental regulations impose significant costs on our mining
operations, and future regulations could materially increase
those costs or limit our ability to produce and sell
coal.
The coal mining industry is subject to increasingly strict
regulation by federal, state and local authorities with respect
to environmental matters such as:
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limitations on land use;
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mine permitting and licensing requirements;
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reclamation and restoration of mining properties after mining is
completed;
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management of materials generated by mining operations;
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the storage, treatment and disposal of wastes;
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remediation of contaminated soil and groundwater;
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air quality standards;
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water pollution;
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protection of human health, plant-life and wildlife, including
endangered or threatened species;
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protection of wetlands;
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40
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the discharge of materials into the environment;
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the effects of mining on surface water and groundwater quality
and availability; and
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the management of electrical equipment containing
polychlorinated biphenyls.
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The costs, liabilities and requirements associated with the laws
and regulations related to these and other environmental matters
may be costly and time-consuming and may delay commencement or
continuation of exploration or production operations. We cannot
assure you that we have been or will be at all times in
compliance with the applicable laws and regulations. Failure to
comply with these laws and regulations may result in the
assessment of administrative, civil and criminal penalties, the
imposition of cleanup and site restoration costs and liens, the
issuance of injunctions to limit or cease operations, the
suspension or revocation of permits and other enforcement
measures that could have the effect of limiting production from
our operations. We may incur material costs and liabilities
resulting from claims for damages to property or injury to
persons arising from our operations. If we are pursued for
sanctions, costs and liabilities in respect of these matters,
our mining operations and, as a result, our profitability could
be materially and adversely affected.
New legislation or administrative regulations or new judicial
interpretations or administrative enforcement of existing laws
and regulations, including proposals related to the protection
of the environment that would further regulate and tax the coal
industry, may also require us to change operations significantly
or incur increased costs. Such changes could have a material
adverse effect on our financial condition and results of
operations. You should see Environmental and Other
Regulatory Matters beginning on page 20 for more
information about the various governmental regulations affecting
us.
If the
assumptions underlying our estimates of reclamation and mine
closure obligations are inaccurate, our costs could be greater
than anticipated.
SMCRA and counterpart state laws and regulations establish
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, engineering studies 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
our original 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. The resulting estimated
reclamation and mine closure obligations could change
significantly if actual amounts change significantly from our
assumptions, which could have a material adverse effect on our
results of operations and financial condition.
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.
41
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
rescind them. Two of our operating subsidiaries intervened in
the suit to protect their interests in being allowed to operate
under the issued permits, and one of them thereafter was
dismissed. On February 13, 2009, the U.S. Court of
Appeals for the Fourth Circuit ruled on appeals from decisions
rendered prior to our intervention, which may have a favorable
impact on our permits. The decision of the Fourth Circuit
remains subject to appeal. 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 45 for more information about the litigation described
above.
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ITEM 1B.
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UNRESOLVED
STAFF COMMENTS.
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None.
Our
Properties
General
At December 31, 2008, we owned or controlled primarily
through long-term leases approximately 99,700 acres of coal
land in West Virginia, 98,300 acres of coal land in
Wyoming, 98,700 acres of coal land in Illinois,
69,800 acres of coal land in Utah, 48,200 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
36,000 acres of our coal land from various state
governments. 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 Our Mining Operations beginning on
page 10 for more information about our mining operations,
mining complexes and transportation facilities.
42
Our Coal
Reserves
We estimate that we owned or controlled approximately
2.8 billion tons of proven and probable recoverable
reserves at December 31, 2008. Our coal reserve estimates
at December 31, 2008 were prepared by our engineers and
geologists and reviewed by Weir International, Inc., a mining
and geological consultant. Our coal reserve estimates are based
on data obtained from our drilling activities and other
available geologic data. Our coal reserve estimates are
periodically updated to reflect past coal production and other
geologic and mining data. Acquisitions or sales of coal
properties will also change these estimates. Changes in mining
methods or the utilization of new technologies may increase or
decrease the recovery basis for a coal seam.
Our coal reserve estimates include reserves that can be
economically and legally extracted or produced at the time of
their determination. In determining whether our reserves meet
this standard, we take into account, among other things, our
potential inability to obtain a mining permit, the possible
necessity of revising a mining plan, changes in estimated future
costs, changes in future cash flows caused by changes in costs
required to be incurred to meet regulatory requirements and
obtaining mining permits, variations in quantity and quality of
coal, and varying levels of demand and their effects on selling
prices. We use various assumptions in preparing our estimates of
our coal reserves. You should see Inaccuracies in our
estimates of our coal reserves could result in decreased
profitability from lower than expected revenues or higher than
expected costs contained under the heading Risk
Factors beginning on page 30 for more information.
The following tables present our estimated assigned and
unassigned recoverable coal reserves at December 31, 2008:
Total
Assigned Reserves
(Tons in
millions)
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Total
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Assigned
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Sulfur Content
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Reserve Control
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Mining Method
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Past Reserve Estimates
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Recoverable
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(lbs. per million Btus)
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As Received
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Under-
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Reserves
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Proven
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Probable
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<1.2
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1.2-2.5
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>2.5
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Btus per lb.(1)
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Leased
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Owned
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Surface
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ground
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2006
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|
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2007
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Wyoming
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1,476
|
|
|
|
1,440
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|
|
|
36
|
|
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|
1,429
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|
|
|
47
|
|
|
|
|
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8,849
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|
|
|
1,461
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|
|
|
15
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|
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1,476
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|
|
|
|
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|
1,655
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1,549
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Utah
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|
89
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|
54
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|
35
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|
82
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|
|
|
7
|
|
|
|
|
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|
|
11,441
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|
|
|
88
|
|
|
|
1
|
|
|
|
|
|
|
|
89
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|
|
|
110
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|
|
103
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Colorado
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71
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|
|
|
55
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|
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|
16
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|
|
|
71
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|
|
|
|
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|
|
|
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11,703
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|
|
|
71
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|
|
|
|
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|
|
|
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|
|
71
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|
|
67
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|
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|
79
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Central App
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176
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|
167
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9
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|
59
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|
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|
117
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|
|
|
|
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|
12,791
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|
|
|
169
|
|
|
|
7
|
|
|
|
77
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|
|
|
99
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|
|
|
216
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|
|
|
169
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Illinois
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Total
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1,812
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|
|
1,716
|
|
|
|
96
|
|
|
|
1,641
|
|
|
|
171
|
|
|
|
|
|
|
|
9,471
|
|
|
|
1,789
|
|
|
|
23
|
|
|
|
1,553
|
|
|
|
259
|
|
|
|
2,048
|
|
|
|
1,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
As received Btus per lb. includes
the weight of moisture in the coal on an as sold basis.
|
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
|
|
|
390
|
|
|
|
294
|
|
|
|
96
|
|
|
|
342
|
|
|
|
48
|
|
|
|
|
|
|
|
9,664
|
|
|
|
299
|
|
|
|
91
|
|
|
|
216
|
|
|
|
174
|
|
Utah
|
|
|
71
|
|
|
|
19
|
|
|
|
52
|
|
|
|
37
|
|
|
|
34
|
|
|
|
|
|
|
|
11,438
|
|
|
|
71
|
|
|
|
|
|
|
|
|
|
|
|
71
|
|
Colorado
|
|
|
30
|
|
|
|
24
|
|
|
|
6
|
|
|
|
28
|
|
|
|
2
|
|
|
|
|
|
|
|
11,458
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
30
|
|
Central App
|
|
|
160
|
|
|
|
120
|
|
|
|
40
|
|
|
|
34
|
|
|
|
105
|
|
|
|
21
|
|
|
|
12,714
|
|
|
|
127
|
|
|
|
33
|
|
|
|
37
|
|
|
|
123
|
|
Illinois
|
|
|
374
|
|
|
|
269
|
|
|
|
105
|
|
|
|
|
|
|
|
|
|
|
|
374
|
|
|
|
11,606
|
|
|
|
56
|
|
|
|
318
|
|
|
|
2
|
|
|
|
372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,025
|
|
|
|
726
|
|
|
|
299
|
|
|
|
441
|
|
|
|
189
|
|
|
|
395
|
|
|
|
11,024
|
|
|
|
583
|
|
|
|
442
|
|
|
|
255
|
|
|
|
770
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
As received Btus per lb. includes
the weight of moisture in the coal on an as sold basis.
|
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
43
to test sulfur content. Of these reserves, approximately 73.4%
consist of compliance coal, or coal which emits 1.2 pounds or
less of sulfur dioxide per million Btus upon combustion, while
an additional 8.7% 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, 2008
was $1.2 billion, consisting of $110.7 million of
prepaid royalties and a net book value of coal lands and mineral
rights of $1.1 billion.
Reserve
Acquisition Process
We acquire a significant portion of the coal we control in the
western United States through LBA process. Under this process,
before a mining company can obtain new coal reserves, the coal
tract must be nominated for lease, and the company must win the
lease through a competitive bidding process. The LBA process can
last anywhere from two to five years from the time the coal
tract is nominated to the time a final bid is accepted by the
BLM. After the LBA is awarded, the company then conducts the
necessary testing to determine what amount can be classified as
reserves.
To initiate the LBA process, companies wanting to acquire
additional coal must file an application with the BLMs
state office indicating interest in a specific coal tract. The
BLM reviews the initial application to determine whether the
application conforms to existing land-use plans for that
particular tract of land and that the application would provide
for maximum coal recovery. The application is further reviewed
by a regional coal team at a public meeting. Based on a review
of the available information and public comment, the regional
coal team will make a recommendation to the BLM whether to
continue, modify or reject the application.
If the BLM determines to continue the application, the company
that submitted the application will pay for a BLM-directed
environmental analysis or an environmental impact statement to
be completed. This analysis or impact statement is subject to
publication and public comment. The BLM may consult with other
governmental agencies during this process, including state and
federal agencies, surface management agencies, Native American
tribes or bands, the U.S. Department of Justice or others
as needed. The public comment period for an analysis or impact
statement typically occurs over a
60-day
period.
After the environmental analysis or environmental impact
statement has been issued and a recommendation has been
published that supports the lease sale of the LBA tract, the BLM
schedules a public competitive lease sale. The BLM prepares an
internal estimate of the fair market value of the coal that is
based on its economic analysis and comparable sales analysis.
Prior to the lease sale, companies interested in acquiring the
lease must send sealed bids to the BLM. The bid amounts for the
lease are payable in five annual installments, with the first
20% installment due when the mining operator submits its initial
bid for an LBA. Before the lease is approved by the BLM, the
company must first furnish to the BLM an initial rental payment
for the first year of rent along with either a bond for the next
20% annual installment payment for the bid amount, or an
application for history of timely payment, in which case the BLM
may waive the bond requirement if the company successfully meets
all the qualifications of a timely payor. The bids are opened at
the lease sale. If the BLM decides to grant a lease, the lease
is awarded to the company that submitted the highest total bid
meeting or exceeding the BLMs fair market value estimate,
which is not published. The BLM, however, is not required to
grant a lease even if it determines that a bid meeting or
exceeding the fair market value of the coal has been submitted.
The winning bidder must also submit a report setting forth the
nature and extent of its coal holdings to the
U.S. Department of Justice for a
30-day
antitrust review of the lease. If the successful bidder was not
the initial applicant, the BLM will refund the initial applicant
certain fees it paid in connection with the application process,
for example the fees associated with the environmental analysis
or environmental impact statement, and the winning bidder will
bear those costs. Coal won through the LBA process and subject
to federal leases are administered by the U.S. Department
of Interior under the Federal Coal Leasing Amendment Act of
1976. In addition, we occasionally add small coal tracts
adjacent to our existing LBAs through an agreed upon lease
modification with the BLM. Once the BLM has issued a lease, the
company must also complete the permitting process before it can
mine the coal. You should see the section entitled
Environmental and Other Regulatory Matters beginning
on page 20 for more information about the permitting
process.
44
Most of our federal coal leases have an initial term of
20 years and are renewable for subsequent
10-year
periods and for so long thereafter as coal is produced in
commercial quantities. These leases require diligent development
within the first ten years of the lease award with a required
coal extraction of 1.0% of the total coal under the lease by the
end of that
10-year
period. At the end of the
10-year
development period, the lessee is required to maintain
continuous operations, as defined in the applicable leasing
regulations. In certain cases a lessee may combine contiguous
leases into a logical mining unit, which we refer to as an LMU.
This allows the production of coal from any of the leases within
the LMU to be used to meet the continuous operation requirements
for the entire LMU. Some of our mines are also subject to coal
leases with applicable state regulatory agencies and have
different terms and conditions that we must adhere to in a
similar way to our federal leases. Under these federal and state
leases, if the leased coal is not diligently developed during
the initial
10-year
development period or if certain other terms of the leases are
not complied with, including the requirement to produce a
minimum quantity of coal or pay a minimum production royalty, if
applicable, the BLM or the applicable state regulatory agency
can terminate the lease prior to the expiration of its term.
Title to
Coal Property
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. You should see 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 contained under the heading Risk
Factors beginning on page 30 for more information.
At December 31, 2008, approximately 16.4% 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.
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 23,900 acres of property to other
coal operators in 2008. We received royalty income of
$6.8 million in 2008 from the mining of approximately
3.1 million tons, $5.6 million in 2007 from the mining
of approximately 2.1 million tons and $5.0 million in
2006 from the mining of approximately 2.4 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.
|
|
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.
45
Permit
Litigation Matters
Two of our operating subsidiaries were 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 were identified in
the suit for having received permits from the Corps. The
lawsuit, brought by the Ohio Valley Environmental Coalition in
September 2005 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.
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. 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. Both of the district court rulings
were appealed to the U.S. Court of Appeals for the Fourth
Circuit.
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
injunctions against 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. The claims against Coal-Mac,
Inc. were thereafter dismissed.
On February, 13, 2009, the Fourth Circuit reversed the District
Courts two orders. The Fourth Circuit held that the
Corps jurisdiction under Section 404 of the Clean
Water Act is limited to the narrow issue of the filling of
jurisdictional waters. The court also held that the Corps
findings of no significant impact under the National
Environmental Policy Act and no significant degradation under
the Clean Water Act are entitled to deference. Such findings
entitle the Corps. to avoid an environmental impact statement,
the absence of which was one subject of the appeal. These
holdings also validated the type of mitigation projects proposed
by some of our operations to minimize impacts and comply with
the relevant statutes. Finally, the Fourth Circuit found that
stream segments, together with the sediment ponds to which they
connect, are unitary waste treatment systems, not
waters of the United States, and that the
Corps had not exceeded its authority in permitting them.
Unless the Fourth Circuit shortens or extends the time, the Ohio
Valley Environmental Coalition will have until March 30,
2009 to petition for rehearing. Any appeal to the
U.S. Supreme Court must be filed by May 14, 2009,
unless a petition for rehearing is filed, in which case the time
runs from the denial of that petition. The Supreme Courts
acceptance of such appeal is discretionary. If no appeal or
petition for rehearing is filed, the order will take effect on
April 6, 2009. If the Fourth Circuit decision stands, then
a backlog of permits pending before the Corps may ease. The
impact on our Mingo Logan permit is not yet entirely clear, but
it could serve to free that permit for use sooner than
anticipated.
West
Virginia Flooding Litigation
Over 2,000 plaintiffs have sued us and more than 100 other
defendants in Wyoming, 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, 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 of Appeals 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 were initially
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 were initiated, to proceed in
phases. On May 2,
46
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 trial court set aside that
verdict and granted judgment in favor of those defendants. The
plaintiffs in that trial group appealed that decision, and on
June 26, 2008, the Supreme Court of Appeals reinstated the
verdict. The court also reversed the January 18, 2007
dismissal of claims involving the Coal River watershed, in which
we are named. Everything was remanded to the Mass Litigation
Panel on September 17, 2008. No trial dates are set.
Clean
Water Act Request for Information
On January 2, 2008, we received a request from the EPA for
certain information related to compliance with effluent
limitations and water quality standards under Section 308
of the Clean Water Act applicable to our eastern mining
complexes located in West Virginia, Virginia and Kentucky. The
request focuses on our compliance with water quality standards
and effluent limitations at numerous outfalls as identified in
the various NPDES permits applicable to our eastern mining
complexes for the period beginning on January 1, 2003
through January 1, 2008. The compliance reporting mechanism
is contained in Discharge Monitoring Reports which are required
to be prepared and submitted quarterly to state environmental
agencies and contain detailed monthly compliance data. In July
2008, the EPA referred the request to the U.S. Department
of Justice. We are complying with the request and continue to
fully cooperate with the EPA and the U.S. Department of
Justice. To date, neither the EPA nor the U.S. Department
of Justice has initiated any enforcement action against us.
|
|
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 2008.
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 23,
2009, our common stock closed at $12.41 on the New York Stock
Exchange. On that date, there were approximately 7,900 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 $48.8 million, or $0.34 per
share, in 2008 and $38.7 million, or $0.27 per share, in
2007. 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 58 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
|
December 31
|
|
|
Dividends per common share
|
|
$
|
0.07
|
|
|
$
|
0.09
|
|
|
$
|
0.09
|
|
|
$
|
0.09
|
|
High
|
|
|
56.15
|
|
|
|
77.40
|
|
|
|
75.41
|
|
|
|
32.58
|
|
Low
|
|
|
32.98
|
|
|
|
41.25
|
|
|
|
27.90
|
|
|
|
10.43
|
|
Close
|
|
|
43.50
|
|
|
|
75.03
|
|
|
|
32.89
|
|
|
|
16.29
|
|
47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
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, 2003;
|
|
|
|
all dividends were reinvested;
|
|
|
|
annual reweighting of the peer groups; and
|
|
|
|
you continued to hold your investment through December 31,
2008.
|
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
|
|
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
Arch Coal, Inc.
|
|
$
|
100
|
|
|
$
|
115
|
|
|
$
|
259
|
|
|
$
|
197
|
|
|
$
|
297
|
|
|
$
|
109
|
|
S&P 400 (Midcap)
|
|
|
100
|
|
|
|
116
|
|
|
|
131
|
|
|
|
145
|
|
|
|
156
|
|
|
|
100
|
|
Industry Peer Group
|
|
|
100
|
|
|
|
176
|
|
|
|
296
|
|
|
|
274
|
|
|
|
495
|
|
|
|
187
|
|
48
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, 2008, we have purchased
3,074,200 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, 2008. Based
on the closing price of our common stock as reported on the New
York Stock Exchange on February 23, 2009, there is
approximately $135.6 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
|
|
|
|
2008
|
|
|
(1)
|
|
|
(2) (3)
|
|
|
(2) (3) (4) (5)
|
|
|
(4) (6) (7)
|
|
|
|
(Amounts in thousands, except per share data)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales revenue
|
|
$
|
2,983,806
|
|
|
$
|
2,413,644
|
|
|
$
|
2,500,431
|
|
|
$
|
2,508,773
|
|
|
$
|
1,907,168
|
|
Change in fair value of coal derivatives and trading activities,
net
|
|
|
55,093
|
|
|
|
7,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
460,389
|
|
|
|
229,617
|
|
|
|
336,667
|
|
|
|
77,857
|
|
|
|
178,046
|
|
Net income
|
|
|
354,330
|
|
|
|
174,929
|
|
|
|
260,931
|
|
|
|
38,123
|
|
|
|
113,706
|
|
Preferred stock dividends
|
|
|
|
|
|
|
(219
|
)
|
|
|
(378
|
)
|
|
|
(15,579
|
)
|
|
|
(7,187
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
|
354,330
|
|
|
|
174,710
|
|
|
|
260,553
|
|
|
|
22,544
|
|
|
|
106,519
|
|
Basic earnings per common share
|
|
|
2.47
|
|
|
|
1.23
|
|
|
|
1.83
|
|
|
|
0.18
|
|
|
|
0.95
|
|
Diluted earnings per common share
|
|
|
2.45
|
|
|
|
1.21
|
|
|
|
1.80
|
|
|
|
0.17
|
|
|
|
0.89
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,978,964
|
|
|
$
|
3,594,599
|
|
|
$
|
3,320,814
|
|
|
$
|
3,051,440
|
|
|
$
|
3,256,535
|
|
Working capital
|
|
|
46,631
|
|
|
|
(35,370
|
)
|
|
|
46,471
|
|
|
|
216,376
|
|
|
|
355,803
|
|
Long-term debt, less current maturities
|
|
|
1,098,948
|
|
|
|
1,085,579
|
|
|
|
1,122,595
|
|
|
|
971,755
|
|
|
|
1,001,323
|
|
Other long-term obligations
|
|
|
491,536
|
|
|
|
420,819
|
|
|
|
391,819
|
|
|
|
382,256
|
|
|
|
800,332
|
|
Stockholders equity
|
|
|
1,728,733
|
|
|
|
1,531,686
|
|
|
|
1,365,594
|
|
|
|
1,184,241
|
|
|
|
1,079,826
|
|
Common Stock Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends per share
|
|
$
|
0.3400
|
|
|
$
|
0.2700
|
|
|
$
|
0.2200
|
|
|
$
|
0.1600
|
|
|
$
|
0.1488
|
|
Shares outstanding at year-end
|
|
|
142,833
|
|
|
|
143,158
|
|
|
|
142,179
|
|
|
|
142,573
|
|
|
|
125,716
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
$
|
679,137
|
|
|
$
|
330,810
|
|
|
$
|
308,102
|
|
|
$
|
254,607
|
|
|
$
|
148,728
|
|
Depreciation, depletion and amortization
|
|
|
292,848
|
|
|
|
242,062
|
|
|
|
208,354
|
|
|
|
212,301
|
|
|
|
166,322
|
|
Capital expenditures
|
|
|
497,347
|
|
|
|
488,363
|
|
|
|
623,187
|
|
|
|
357,142
|
|
|
|
292,605
|
|
Dividend payments
|
|
|
48,847
|
|
|
|
38,945
|
|
|
|
31,815
|
|
|
|
27,639
|
|
|
|
24,043
|
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
139,595
|
|
|
|
135,010
|
|
|
|
134,976
|
|
|
|
140,202
|
|
|
|
123,060
|
|
Tons produced
|
|
|
133,107
|
|
|
|
126,624
|
|
|
|
126,015
|
|
|
|
129,685
|
|
|
|
115,861
|
|
Tons purchased from third parties
|
|
|
6,037
|
|
|
|
8,495
|
|
|
|
10,092
|
|
|
|
11,226
|
|
|
|
12,572
|
|
|
|
|
(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 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.
|
|
(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. 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.
|
49
|
|
|
(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.
|
|
(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, we sold our remaining
investment in Natural Resource Partners in three separate
transactions occurring in March, June and October 2004. We
recognized an aggregate gain of $91.3 million during 2004.
|
|
|
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.
We sell substantially all of our coal to power plants, steel
mills and industrial facilities. The locations of our mines
enable us to ship coal to most of the major coal-fueled power
plants, steel mills and export facilities located in the United
States.
Our three reportable business segments are based on the
low-sulfur U.S. coal producing regions 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 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. 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 we mine from underground
and surface mines in this region typically has a low sulfur
content and varies in heat value. Central Appalachia includes
eastern Kentucky, Tennessee, 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, we may sell a portion of the coal we
produce in the Central Appalachia region as metallurgical coal,
which has high heat content, low expansion pressure, low sulfur
content and various other chemical attributes. As such, the
prices at which we sell metallurgical coal to customers in the
steel industry generally exceed the prices offered by power
plants and industrial users for steam coal.
As discussed under the section entitled The Coal
Industry, worldwide coal demand continued to increase
during 2008, driven by rapid growth in electrical power
generation capacity in Asia, particularly in China and India. In
the United States, we estimate that electricity generation
declined approximately 0.9% in 2008 in response to mild weather
and slowing economic activity, particularly during the second
half of the year. An increase in international electricity
demand had led to increased demand for coal exports from the
United States and, during 2008, coal exports for both steam and
metallurgical coal increased significantly as demand for
U.S. coal in the Atlantic Basin increased. During the
second half of 2008, demand for steam and metallurgical coal
declined as the United States and most international economies
deteriorated. We believe these economic challenges will continue
to affect domestic and international demand in 2009. Despite the
deterioration in coal index pricing during the second half of
2008, our average realized prices for 2008 were significantly
higher than comparable prices for 2007.
In 2009, we expect U.S. power generation to decline more
than 1.0% due to weaker domestic and international economic
conditions. We also expect U.S. coal consumption to decline
in 2009 in response to reduced consumption for electricity
generation, lower metallurgical coal demand resulting from
global steel production cuts and increased use of natural gas by
some electricity generation facilities. As a result of these
50
market pressures, coupled with continued geological challenges,
cost pressures, regulatory hurdles and limited access to
capital, we expect coal production and capital spending levels
across the domestic coal industry will be curtailed. Due to
weakening demand in response to challenging domestic economic
conditions, we have decreased our estimates of the amount of
coal we plan to sell in 2009. In addition, we have decreased our
expected capital expenditures for 2009 and have established
other process improvement initiatives and cost containment
programs.
We estimate that, at December 31, 2008, approximately 21
gigawatts of generating capacity was under construction or in
advanced stages of development in the United States. We expect
these plants to come online in the next several years, with more
than half of these plants to be online by the end of 2010. As
such, we anticipate that 2009 will be a transitional year for
the U.S. coal industry. Over the intermediate and
long-term, we believe coal market fundamentals will be
favorable, benefiting from an overall increase in energy use,
particularly in developing countries such as China and India.
Items Affecting
Comparability of Reported Results
The comparability of our operating results for the years ended
December 31, 2008, 2007 and 2006 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 period from
January 1, 2007 until June 29, 2007, these 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,
these operations contributed coal sales of 4.0 million
tons, revenues of $243.8 million and income from operations
of $19.5 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.
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. In 2006, we
recognized expenses of $8.7 million 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.
West Elk combustion event We idled our West
Elk mine in Colorado in the first quarter of 2006 as a result of
a combustion-related event that occurred in October 2005. We
estimate that the idling resulted in $30.0 million in lost
profits during the first quarter of 2006. We also recognized
insurance recoveries related to the event of $41.9 million
during the year ended December 31, 2006.
Results
of Operations
Year
Ended December 31, 2008 Compared to Year Ended
December 31, 2007
Summary. Our results during 2008 when compared
to 2007 were influenced primarily by stronger market conditions,
particularly in the first half of 2008, the impact of our coal
trading activities and the elimination of the valuation
allowance against deferred tax assets, offset in part by an
upward pressure on commodity costs and higher depreciation,
depletion and amortization costs.
51
Revenues. The following table summarizes
information about coal sales during the year ended
December 31, 2008 and compares it with the information for
the year ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
Increase
|
|
|
|
2008
|
|
|
2007
|
|
|
Amount
|
|
|
%
|
|
|
|
(Amounts in thousands, except per ton data and
percentages)
|
|
|
Coal sales
|
|
$
|
2,983,806
|
|
|
$
|
2,413,644
|
|
|
$
|
570,162
|
|
|
|
23.6
|
%
|
Tons sold
|
|
|
139,595
|
|
|
|
135,010
|
|
|
|
4,585
|
|
|
|
3.4
|
%
|
Coal sales realization per ton sold
|
|
$
|
21.37
|
|
|
$
|
17.88
|
|
|
$
|
3.49
|
|
|
|
19.5
|
%
|
Coal sales increased in 2008 from 2007 due to higher price
realizations across all segments, a greater percentage of
metallurgical coal sales in Central Appalachia and higher sales
volumes. 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
beginning on page 53.
Expenses, costs and other. The following table
summarizes expenses, costs, changes in fair value of coal
derivatives and coal trading activities, net, and other
operating income, net for the year ended December 31, 2008
and compares it with the information for the year ended
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31
|
|
|
in Net Income
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars in thousands)
|
|
|
Cost of coal sales
|
|
$
|
2,183,922
|
|
|
$
|
1,888,285
|
|
|
$
|
(295,637
|
)
|
|
|
(15.7
|
)%
|
Depreciation, depletion and amortization
|
|
|
292,848
|
|
|
|
242,062
|
|
|
|
(50,786
|
)
|
|
|
(21.0
|
)
|
Selling, general and administrative expenses
|
|
|
107,121
|
|
|
|
84,446
|
|
|
|
(22,675
|
)
|
|
|
(26.9
|
)
|
Change in fair value of coal derivatives and coal trading
activities, net
|
|
|
(55,093
|
)
|
|
|
(7,292
|
)
|
|
|
47,801
|
|
|
|
655.5
|
|
Other operating income, net
|
|
|
(5,381
|
)
|
|
|
(23,474
|
)
|
|
|
(18,093
|
)
|
|
|
(77.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,523,417
|
|
|
$
|
2,184,027
|
|
|
$
|
(339,390
|
)
|
|
|
(15.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales. Our cost of coal sales
increased from 2007 to 2008 primarily due to higher taxes,
royalties and other costs that are sensitive to sales prices
($83.8 million), an increase in transportation costs
primarily due to increased barge and export sales
($68.1 million), the increase in sales volumes and higher
per-ton production costs in the Powder River Basin. We have
provided more information about the results of our operating
segments under the heading Operating segment results
beginning on page 53.
Depreciation, depletion and amortization. The
increase in depreciation, depletion and amortization expense
from 2007 to 2008 is due primarily to the costs of capital
improvement and mine development projects that we capitalized in
2007 and 2008. We have provided more information about our
operating segments under the heading Operating segment
results beginning on page 53 and our capital spending
in the section entitled Liquidity and Capital
Resources beginning on page 58.
Selling, general and administrative
expenses. The increase in selling, general and
administrative expenses from 2007 to 2008 is due primarily to
increases in employee compensation costs of approximately
$13.0 million, primarily incentive compensation, industry
group dues of approximately $5.0 million and an increase in
corporate expenses, including professional fees and travel costs.
Change in fair value of coal derivatives and coal trading
activities, net. Net gains in 2008 relate to the
net impact of our coal trading activities and the change in fair
value of other coal derivatives that have not been designated as
hedge instruments in a hedging relationship. Our coal trading
function enabled us to take advantage of price movements in the
coal markets primarily during the first half of 2008.
Other operating income, net. The decrease in
net income from changes in other operating income, net in 2008
compared to 2007 is due primarily to a gain in 2007 of
$8.9 million on the disposition of the Mingo
52
Logan-Ben Creek property and gains in 2007 of $8.4 million
related to the sale of non-core reserves in the Powder River
Basin and Central Appalachia.
Operating segment results. The following table
shows results by operating segment for the year ended
December 31, 2008 and compares it with the information for
the year ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
Increase (Decrease)
|
|
|
|
2008
|
|
|
2007
|
|
|
Amount
|
|
|
%
|
|
|
|
(Amounts in thousands, except
|
|
|
|
per ton data and percentages)
|
|
|
Powder River Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
102,558
|
|
|
|
99,145
|
|
|
|
3,413
|
|
|
|
3.4
|
%
|
Coal sales realization per ton
sold(1)
|
|
$
|
11.30
|
|
|
$
|
10.59
|
|
|
$
|
0.71
|
|
|
|
6.7
|
%
|
Operating margin per ton
sold(2)
|
|
$
|
1.02
|
|
|
$
|
1.23
|
|
|
$
|
(0.21
|
)
|
|
|
(17.1
|
)%
|
Western Bituminous
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
20,606
|
|
|
|
19,362
|
|
|
|
1,244
|
|
|
|
6.4
|
%
|
Coal sales realization per ton
sold(1)
|
|
$
|
27.46
|
|
|
$
|
24.73
|
|
|
$
|
2.73
|
|
|
|
11.0
|
%
|
Operating margin per ton
sold(2)
|
|
$
|
5.69
|
|
|
$
|
5.11
|
|
|
$
|
0.58
|
|
|
|
11.4
|
%
|
Central Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
16,431
|
|
|
|
16,503
|
|
|
|
(72
|
)
|
|
|
(0.4
|
)%
|
Coal sales realization per ton
sold(1)
|
|
$
|
66.73
|
|
|
$
|
47.87
|
|
|
$
|
18.86
|
|
|
|
39.4
|
%
|
Operating margin per ton
sold(2)
|
|
$
|
17.53
|
|
|
$
|
3.89
|
|
|
$
|
13.64
|
|
|
|
350.6
|
%
|
|
|
|
(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,
2008, transportation costs per ton were $0.03 for the Powder
River Basin, $4.54 for the Western Bituminous region and $4.02
for Central Appalachia. 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.
|
|
(2)
|
|
Operating margin per ton is
calculated as 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 was higher in 2008 when compared to 2007 due
primarily to planned production cutbacks in 2007 in response to
weak market conditions. Increases in sales prices during 2008
when compared with 2007 reflect higher pricing on contract and
market index-priced tons, partially offset by the effect of
lower sulfur dioxide emission allowance prices. On a per-ton
basis, operating margins in 2008 decreased from 2007 due to an
increase in per-ton costs, which offset the contribution of
higher sales prices. The increase in per-ton costs resulted
primarily from higher diesel fuel and explosives prices, higher
sales-sensitive costs, costs related to planned repair and
maintenance projects and higher labor costs.
Western Bituminous In the Western Bituminous
region, sales volume increased during 2008 when compared with
2007, driven largely by increased demand in the region. Higher
sales prices during 2008 when compared with 2007 resulted from
higher contract pricing from the roll off of lower-priced legacy
contracts and the effect of market-based sales in 2008. Higher
sales prices resulted in higher per-ton operating margins for
2008 compared to 2007, partially offset by an increase in
transportation costs, depreciation, depletion and amortization
and sales-sensitive costs.
In the Western Bituminous Region, we transitioned to a new coal
seam at our West Elk mining complex in Colorado in December
2008. We have experienced adverse geologic conditions that have
affected production in the new seam and that have reduced the
quality of the coal produced. We expect the problems to diminish
as we move through the panel and expect the greatest impact on
production to occur in the first quarter of 2009.
Central Appalachia Our sales volumes in
Central Appalachia were flat during 2008 when compared with 2007
and were affected by the commencement of production at our
Mountain Laurel complex at the beginning
53
of the fourth quarter of 2007, which offset the impact of the
disposition of the Mingo Logan-Ben Creek facility in the second
quarter of 2007. Higher realized prices in 2008 reflect the
increase in metallurgical coal sales volumes and higher overall
pricing on metallurgical and steam coal sales. We sold
4.4 million tons into metallurgical markets in 2008
compared to 2.1 million tons in 2007, and because
metallurgical coal generally commands a higher price than steam
coal, the increase had a beneficial impact on our average
realizations in 2008 when compared to 2007. Operating margins
per ton in 2008 increased from 2007 due to the increase in sales
prices, net of the impact of higher sales-sensitive costs, and a
decrease in other cash costs per ton sold. Our costs of
production at Mountain Laurel are lower than our average for the
region, which resulted in lower cash costs per ton sold,
exclusive of sales-sensitive costs, in 2008 compared to 2007.
These margin improvements were partially offset by the effect of
higher depreciation, depletion and amortization costs, primarily
from Mountain Laurel.
Net interest expense. The following table
summarizes our net interest expense for the year ended
December 31, 2008 and compares it with the information for
the year ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31
|
|
|
in Net Income
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars in thousands)
|
|
|
Interest expense
|
|
$
|
(76,139
|
)
|
|
$
|
(74,865
|
)
|
|
$
|
(1,274
|
)
|
|
|
(1.7
|
)%
|
Interest income
|
|
|
11,854
|
|
|
|
2,600
|
|
|
|
9,254
|
|
|
|
355.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(64,285
|
)
|
|
$
|
(72,265
|
)
|
|
$
|
7,980
|
|
|
|
11.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During 2008, we incurred slightly lower interest costs on
borrowings when compared with 2007 as a result of a reduction in
our average borrowing rate during 2008. This decrease was offset
by a decrease in the amount of interest cost that we capitalized
in 2008 when compared to 2007. We capitalized interest costs of
$11.7 million during 2008 and $18.0 million during
2007. For more information on our borrowing facilities and
ongoing capital improvement and development projects, see
Liquidity and Capital Resources beginning on
page 58.
Interest income increased as a result of $10.3 million of
interest on a black lung excise tax refund we filed in the
fourth quarter of 2008. Under law changes related to the
Emergency Economic Stabilization Act, we were able to file for a
refund of $11.0 million for years that had previously been
statutorily closed.
Other non-operating expense. Amounts reported
as non-operating consist of income or expense resulting from our
financing activities other than interest, including the
amortization of previously-deferred amounts from the termination
of hedge accounting related to interest rate swaps.
Income taxes. Our effective income tax rate is
sensitive to changes in estimates of annual profitability and
percentage depletion. The following table summarizes our income
taxes for the year ended December 31, 2008 and compares it
with information for the year ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease
|
|
|
Year Ended December 31
|
|
in Net Income
|
|
|
2008
|
|
2007
|
|
$
|
|
%
|
|
|
(Dollars in thousands)
|
|
Provision for (benefit from) income taxes
|
|
$
|
41,774
|
|
|
$
|
(19,850
|
)
|
|
$
|
61,624
|
|
|
|
310.4
|
%
|
In 2008, our income taxes were impacted by higher profitability,
reductions in our valuation allowance against net operating loss
and alternative minimum tax credit carryforwards and changes in
our effective tax rate when compared with 2007. Income taxes
include a $58.0 million reduction in 2008 and a
$38.7 million reduction in 2007 in our valuation allowance
against net operating loss and alternative minimum tax credit
carryforwards that reduced our income taxes. Our effective rate
increased from 2007 to 2008, exclusive of the effect of change
in the valuation allowance, primarily as a result of the impact
of percentage depletion.
54
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 recognized 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.
Revenues. The following table summarizes
information about coal sales for the year ended
December 31, 2007 and compares it with information for the
year ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
Increase (Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
Amount
|
|
|
%
|
|
|
|
(Amounts in thousands, except
|
|
|
|
per ton data and percentages)
|
|
|
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 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
beginning on page 56.
Expenses, costs and other. The following table
summarizes expenses, costs and other operating income, net for
the year ended December 31, 2007 and compares it with
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
|
)
|
Change in fair value of coal derivatives and coal trading
activities, net
|
|
|
(7,292
|
)
|
|
|
|
|
|
|
7,292
|
|
|
|
NA
|
|
Other operating income, net
|
|
|
(23,474
|
)
|
|
|
(29,800
|
)
|
|
|
(6,326
|
)
|
|
|
(21.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 beginning on page 56.
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 58.
55
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.
Change in fair value of coal derivatives and coal trading
activities, net. Net gains in 2007 relate to the
net impact of our coal trading activities and the change in fair
value of other coal derivatives that have not been designated as
hedge instruments in a hedging relationship.
Other operating income, net. The decrease 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; 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.
|
Operating segment results. The following table
shows results by operating segment for the year ended
December 31, 2007 and compares it with information for the
year ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
Increase (Decrease)
|
|
|
|
2007
|
|
|
2006
|
|
|
Amount
|
|
|
%
|
|
|
|
(Amounts in thousands, except
|
|
|
|
per ton data and percentages)
|
|
|
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 coal sales revenues less cost of coal sales and
depreciation, depletion and amortization divided by tons sold.
|
56
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.
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 it with information for the
year ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
Decrease in Net Income
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars 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 58.
57
Other non-operating expense. The following
table summarizes our other non-operating expense for the year
ended December 31, 2007 and compares it with information
for the year ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
|
|
|
|
Year Ended December 31
|
|
|
in Net Income
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars 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
expense includes
mark-to-market
adjustments related to certain swap activity that did 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 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.
Liquidity
and Capital Resources
Credit
crisis and economic environment
The crisis in domestic and international financial markets has
had a significant adverse impact on a number of financial
institutions. Since the beginning of the crisis, our ability to
issue commercial paper up to the maximum amount allowed under
the program has been constrained. The ongoing uncertainty in the
financial markets may have an impact in the future on: the
market values of certain securities and commodities; the
financial stability of our customers and counterparties;
availability under our lines of credit; the cost and
availability of insurance and financial surety programs, and
pension plan funding requirements. At this point in time,
however, our liquidity has not been materially affected. In
response to the current credit markets, we strengthened our
liquidity position by building a cash balance of
$70.6 million as of December 31, 2008 and by
diversifying our borrowings among our lines of credit. While we
expect our ability to issue commercial paper will be affected by
the current credit markets, we believe we have sufficient
liquidity under our credit facilities to satisfy working capital
requirements and fund capital expenditures, if needed. We had
available borrowing capacity of $641.4 million under our
lines of credit at December 31, 2008 in addition to our
cash on hand. Management will continue to closely monitor our
own liquidity, credit markets and counterparty credit risk.
Management cannot predict with any certainty the impact to our
liquidity of any further disruption in the credit environment.
Liquidity
and capital resources
Our primary sources of cash include sales of our coal production
to customers, borrowings under our credit facilities or other
financing arrangements, 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. The borrowings under these
arrangements are classified as current if the underlying credit
facilities expire within one year or if, based on cash
projections and management plans, we do not have the intent to
replace them on a long-term basis. Such plans are subject to
change based on our cash needs.
58
We believe that cash generated from operations and borrowings
under our credit facilities or other financing arrangements will
be sufficient to meet working capital requirements, anticipated
capital expenditures and scheduled debt payments for at least
the next several years. We manage our exposure to changing
commodity prices for our non-trading, long-term coal contract
portfolio through the use of long-term coal supply agreements.
We enter into fixed price, fixed volume supply contracts with
terms greater than one year with customers with whom we have
historically had limited collection issues. At December 31,
2008, our expected unpriced production approximated
14 million to 18 million tons in 2009, 55 million
to 65 million tons in 2010 and 95 million to
105 million tons in 2011. 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. In response to the economic
environment, we have decreased our 2009 capital spending plans
and have established other process improvement initiatives and
cost containment programs in order to reduce costs.
Our secured revolving credit facility allows for up to
$800.0 million of borrowings and expires June 23,
2011. We had borrowings outstanding under the revolving credit
facility of $205.0 million at December 31, 2008 and
$160.0 million at December 31, 2007. 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, 2008 was 2.70%. 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 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, 2008. While these financial
covenant requirements may restrict the amount of unused capacity
available to us for borrowings and letters of credit, as of
December 31, 2008, we were not restricted by financial
covenants.
We are party to an accounts receivable securitization program
whereby eligible trade receivables are sold, without recourse,
to a multi-seller, asset-backed commercial paper conduit. During
2008, we entered into an amendment to our accounts receivable
securitization program that increased the size of the program
from $150.0 million to $175.0 million. The credit
facility supporting the borrowings under the program is subject
to renewal annually and expires on May 21, 2009. Under the
terms of the program, eligible trade receivables consist of
trade receivables generated by our operating subsidiaries.
Actual borrowing capacity is based on the allowable amounts of
accounts receivable as defined under the terms of the agreement.
Outstanding borrowings under the program were approximately
$68.6 million at December 31, 2008 and
$90.8 million at December 31, 2007. 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 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
2.68% at December 31, 2008. 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
59
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 had commercial paper outstanding of $65.7 million at
December 31, 2008 and $75.0 million at
December 31, 2007. Our commercial paper placement program
provides 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
$100.0 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 a revolving credit facility that is subject to
renewal annually with a maturity date of April 30, 2009. As
of December 31, 2008, the weighted-average interest rate of
our outstanding commercial paper was 2.46% and maturity dates
ranged from two to 92 days. The current credit market has
affected our ability to issue commercial paper up to the maximum
amount allowed under the program, but we believe that the
availability under our lines of credit is sufficient to satisfy
our liquidity needs.
Our subsidiary, Arch Western Finance LLC, has outstanding an
aggregate principal amount of $950.0 million of 6.75% senior
notes due on July 1, 2013. The senior notes are guaranteed
by Arch Western Resources LLC and certain of its subsidiaries
and are secured by an intercompany note from Arch Western
Resources, LLC to Arch Coal, Inc. The indenture under which the
senior notes were issued contains certain restrictive covenants
that limit Arch Western Resources, LLCs ability to, among
other things, incur additional debt, sell or transfer assets and
make certain investments.
We have filed a universal shelf registration statement on
Form S-3
with the SEC 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.
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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
679,137
|
|
|
$
|
330,810
|
|
|
$
|
308,102
|
|
Investing activities
|
|
|
(527,545
|
)
|
|
|
(424,995
|
)
|
|
|
(688,005
|
)
|
Financing activities
|
|
|
(86,023
|
)
|
|
|
96,742
|
|
|
|
121,925
|
|
Cash provided by operating activities was $679.1 million,
an increase of $348.3 million in 2008 compared to 2007,
primarily as a result of our increased profitability during 2008.
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 used in investing activities for 2008 was
$527.5 million, $102.5 million more than was used in
investing activities for 2007, primarily the result of proceeds
received from asset sales in 2007, as discussed below. 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
60
opportunistically. During 2007 and 2008, we made the third and
fourth of five annual payments of $122.2 million on the
Little Thunder federal coal lease in Wyoming. Additionally, in
2008, we spent approximately $86.5 million on the
construction of a new loadout facility at our Black Thunder mine
in Wyoming and $132.1 million for the transition to a new
reserve area at our West Elk mining complex in Colorado,
including the cost of purchasing a new longwall and other mining
equipment. We completed the work on the loadout facility and
transitioned to the new seam at West Elk in the fourth quarter
of 2008. Proceeds from asset sales were $70.3 million
during 2007, compared to $1.1 million in 2008. Our proceeds
from asset sales in 2007 included $43.5 million related to
the sale of the Mingo Logan-Ben Creek complex and
$26.0 million from the sale of non-core reserves in the
Powder River Basin and Central Appalachia. Cash inflows from
investing activities in 2007 also 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.
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.
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, development of
the new reserve area at the West Elk mining complex in Colorado,
payments for a replacement longwall at our Sufco mining complex
in Utah and costs to construct the new loadout at our Black
Thunder mining complex. The Mountain Laurel longwall commenced
production on October 1, 2007. In 2006, 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 used in financing activities was $86.0 million during
2008 compared to cash provided by financing activities of
$96.7 million during 2007. We borrowed, net of repayments,
$13.5 million under our commercial paper program and lines
of credit during 2008, $120.0 million less than during
2007. During the third quarter of 2008, Standard and Poors
Rating Services raised our corporate credit rating to
BB from BB-. At December 31, 2008,
debt amounted to $1,312.4 million, or 43% of capital
employed, compared to $1,303.2 million, or 46% of capital
employed, at December 31, 2007. Based on the level of
consolidated indebtedness and prevailing interest rates at
December 31, 2008, debt service obligations for 2009, which
include the maturities of principal and interest payments, are
estimated to be $279.2 million.
During 2008, other financing cash flows included the repurchase
of 1.5 million shares of common stock under our share
repurchase program at an average price of $35.62 per share.
During 2008, we paid dividends of $48.8 million, an
increase of $9.9 million when compared to 2007, due to an
increase in the dividend rate from $0.06 per share to $0.07 per
share in April 2007 and from $0.07 per share to $0.09 per share
in April 2008.
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 spent $43.9 million during
2006 under a share repurchase program authorized by the board of
directors in September 2006. We increased our dividend rate in
April 2006 and 2007 and as a result, dividends paid increased
$7.1 million.
61
Ratio of
Earnings to Fixed Charges
The following table sets forth our ratios of earnings to
combined fixed charges and preference dividends for the periods
indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Ratio of earnings to combined fixed charges and preference
dividends(1)
|
|
|
4.90
|
x
|
|
|
2.36
|
x
|
|
|
3.84
|
x
|
|
|
N/A
|
|
|
|
2.52x
|
|
|
|
|
(1)
|
|
Earnings consist of income from
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.
|
Contractual
Obligations
The following is a summary of our significant contractual
obligations as of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
2009
|
|
|
2010-2011
|
|
|
2012-2013
|
|
|
After 2013
|
|
|
Total
|
|
|
|
(Dollars in thousands)
|
|
|
Long-term debt, including related interest
|
|
$
|
279,195
|
|
|
$
|
271,050
|
|
|
$
|
1,046,188
|
|
|
$
|
|
|
|
$
|
1,596,433
|
|
Operating leases
|
|
|
33,806
|
|
|
|
60,783
|
|
|
|
43,511
|
|
|
|
38,265
|
|
|
|
176,365
|
|
Coal lease rights
|
|
|
152,895
|
|
|
|
59,369
|
|
|
|
19,875
|
|
|
|
23,302
|
|
|
|
255,441
|
|
Coal purchase obligations
|
|
|
184,019
|
|
|
|
102,354
|
|
|
|
123,931
|
|
|
|
284,630
|
|
|
|
694,934
|
|
Unconditional purchase obligations
|
|
|
173,146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
173,146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations
|
|
$
|
823,061
|
|
|
$
|
493,556
|
|
|
$
|
1,233,505
|
|
|
$
|
346,197
|
|
|
$
|
2,896,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our maturities of debt in 2009 include amounts borrowed that are
supported by credit facilities that have a term of less than one
year and amounts borrowed under credit facilities with terms
longer than one year that we do not intend to refinance on a
long-term basis, based on cash projections. The related interest
on long-term debt was calculated using rates in effect at
December 31, 2008 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, the remaining $122.2 million payment due under
the Little Thunder lease in Wyoming will be paid in 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 to supply ongoing customer sales commitments.
Unconditional purchase obligations include open purchase orders
and other purchase commitments, which have not been recognized
as a liability. The commitments in the table above relate to
contractual 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
$258.9 million for 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. Asset retirement obligations are
recorded at fair value when incurred and accretion expense is
recognized through the expected date of settlement. Determining
the fair value of asset retirement obligations involves a number
of estimates, as discussed in the section entitled
Critical Accounting Policies beginning on
page 64, including the
62
timing of payments to satisfy the 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 plans and
workers compensation obligations. The timing of
contributions to our pension plans varies based on a number of
factors, including changes in the fair value of plan assets and
actuarial assumptions. You should see the section entitled
Critical Accounting Policies beginning on
page 64 for more information about these assumptions. In
order to achieve a desired funded status, we expect to make
contributions of $25.9 million to our pension plans in
2009. This estimate is based on current funding regulations,
which are currently under review for potential modification to
provide funding relief to companies that sponsor pension plans.
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 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, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Workers
|
|
|
|
|
|
|
|
|
|
Reclamation
|
|
|
Lease
|
|
|
Compensation
|
|
|
|
|
|
|
|
|
|
Obligations
|
|
|
Obligations
|
|
|
Obligations
|
|
|
Other
|
|
|
Total
|
|
|
|
(Dollars in thousands)
|
|
|
Self bonding
|
|
$
|
334,632
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
334,632
|
|
Surety bonds
|
|
|
240,755
|
|
|
|
51,963
|
|
|
|
12,700
|
|
|
|
14,955
|
|
|
|
320,373
|
|
Letters of credit
|
|
|
|
|
|
|
|
|
|
|
47,738
|
|
|
|
12,261
|
|
|
|
59,999
|
|
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. Patriot Coal Corporation
acquired Magnum in July 2008, and, as a result, Magnum will be
required to post letters of credit in our favor for the full
amount of the reclamation obligation on or before February 2011.
At December 31, 2008, we had approximately
$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, 2008, the cost of purchasing
14.1 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 $200.7 million,
and the cost of purchasing 3.7 million tons of coal to
supply the assigned and guaranteed contracts over their duration
would exceed the sales price under the contracts by
approximately $104.7 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 $6.1 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
63
guarantees. 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
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 $51.8 million at December 31, 2008. 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.
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:
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.
The fair values of the majority of our derivative instruments
are obtained from either quoted prices in active markets, quoted
prices in
over-the-counter
markets or direct broker quotes. 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, 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 years ended December 31, 2008 and 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.
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, 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
64
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.
Accretion expense is recognized on the obligation through the
expected settlement date. Accretion expense was
$19.6 million in 2008 and $18.6 million in 2007. 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.
Adjustments to the liability resulting from changes in estimates
were an increase in the liability of $18.9 million in 2008
and a decrease in the liability of $0.9 million in 2007.
Any difference between the recorded amount of the liability and
the actual cost of reclamation will be recognized 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, 2008, we had recorded asset retirement
obligation liabilities of $258.9 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, 2008, we estimate that the aggregate
undiscounted cost of final mine closure is approximately
$666.0 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, the provisions of Statement No. 123R apply to all
awards granted or modified after the adoption date. For awards
that were granted prior to, but not vested as of, the adoption
of Statement No. 123R, we determined unrecognized
compensation cost based on the same estimate of the grant-date
fair value and the same recognition method used previously under
Statement No. 123, which will be reflected in income in
periods after adoption. We use the Black-Scholes option pricing
model for option valuations and a lattice model for valuations
of share-based awards with performance and market conditions
that are paid out in stock.
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 or more than the maximum amount that can be
deducted for federal income tax purposes. We contributed cash of
$2.6 million in 2008 and $2.7 million in 2007 to the
plans. 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.
The calculation of our net periodic benefit costs (pension
expense) and benefit obligation (pension liability) associated
with our defined benefit pension plans requires the use of a
number of assumptions that we deem to be critical
accounting estimates. Changes in these assumptions can
result in different pension expense and liability amounts, and
actual experience can differ from the assumptions.
|
|
|
|
|
The expected long-term rate of return on plan assets is an
assumption reflecting the average rate of earnings expected on
the funds invested or to be invested to provide for the benefits
included in the projected benefit obligation. We establish the
expected long-term rate of return at the beginning of each
fiscal year based upon historical returns and projected returns
on the underlying mix of invested assets. The pension
plans investment targets are 65% equity, 30% fixed income
securities and 5% cash.
|
65
|
|
|
|
|
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 2008
and 2007. These long-term rate of return assumptions are less
than the plans actual
life-to-date
returns. Any difference between the actual experience and the
assumed experience is recorded in other comprehensive income and
amortized into earnings in the future. The impact of lowering
the expected long-term rate of return on plan assets 0.5% for
2008 would have been an increase in expense of approximately
$1.1 million.
|
|
|
|
|
|
The discount rate represents our estimate of the interest rate
at which pension benefits could be effectively settled. Assumed
discount rates are used in the measurement of the projected,
accumulated and vested benefit obligations and the service and
interest cost components of the net periodic pension cost. In
estimating that rate, Statement No. 87 requires rates of return
on high-quality fixed-income debt instruments. We utilize a bond
portfolio model that includes bonds that are rated
AA or higher with maturities that match the expected
benefit payments under the plan. The discount rate used to
determine pension expense was 6.5% for 2008 and 5.9% for 2007.
The impact of lowering the discount rate 0.5% for 2008 would
have been an increase in expense of approximately
$2.2 million.
|
The differences generated from 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 2008,
we changed our discount rate to 6.85%.
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. Our
current funding policy is to fund the cost of all postretirement
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.
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 6.5% for 2008 and 5.9% for
2007. Had the discount rate been lowered by 0.5% in 2008, we
would have incurred additional expense of $0.7 million.
For the measurement of our year-end other postretirement
obligation for 2008 and postretirement expense for 2009, we
changed our discount rate to 6.85%.
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. We initially
recognize the effects of a tax position when it is more than
50 percent likely, based on the technical merits, that the
position will be sustained upon examination, including
resolution of the related appeals or litigation processes, if
any. Our determination of whether or not a tax position has met
the recognition threshold considers the facts, circumstances,
and information available at the reporting date. A valuation
allowance may be recorded to reflect the amount of future tax
benefits that management believes are not likely to be realized.
We reassess our ability to realize our deferred tax assets
annually in the fourth quarter or when circumstances indicate
that the ability to realize deferred tax assets has changed. In
determining the appropriate valuation allowance, we take into
account expected future taxable income and available tax
planning strategies. If future taxable income is lower than
expected or if expected tax planning strategies are not
available as anticipated, we may record additional valuation
allowance through income tax expense in the period such
determination is made.
66
Accounting
Standards Issued and Not Yet Adopted
In February 2008, the FASB issued Staff Position
FAS 157-2,
Effective Date of FASB Statement No. 157, which we
refer to as FSP
FAS 157-2,
which delays the effective date of Statement No. 157 for
nonfinancial assets and nonfinancial liabilities, except for
those items that are recognized or disclosed at fair value in
the financial statements on a recurring basis. For the items
within the scope of Statement No. 157, FSP
FAS 157-2
is effective for financial statements issued for fiscal years
and interim periods beginning after November 15, 2008. We
are assessing the potential impact of Statement No. 157 on
the applicable fair value measurements and will adopt FSP
FAS 157-2
prospectively on January 1, 2009.
In December 2007, the FASB issued Statement of Financial
Accounting Standards No. 160, Noncontrolling Interests
in Consolidated Financial Statements, an amendment of ARB
No. 51, which we refer to as Statement No. 160.
Statement No. 160 requires that a noncontrolling interest
(minority interest) in a consolidated subsidiary be displayed in
the consolidated balance sheet as a separate component of
equity. The amount of net income attributable to the
noncontrolling interest will be included in consolidated net
income on the face of the consolidated statement of income for
all periods presented. Earnings per share will continue to be
calculated based on income attributable to the controlling
interest. Noncontrolling interests in our subsidiaries were
$9.2 million and $8.3 million at December 31,
2008 and 2007, respectively. Statement No. 160 also
includes expanded disclosure requirements regarding the
interests of the parent and its noncontrolling interest.
Statement No. 160 is effective for fiscal years beginning
on or after December 15, 2008. Early adoption is not
allowed. We do not expect that the adoption of Statement
No. 160 will have a material impact on our financial
position or results of operations.
|
|
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.
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, 2008, our
expected unpriced production approximated 14 million to
18 million tons in 2009, 55 million to 65 million
tons in 2010 and 95 million to 105 million tons in
2011.
We are exposed to commodity price risk in our coal trading
activities, 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, swap and put and call
option contracts at December 31, 2008. With respect to our
coal trading positions, a 10% decrease in forward coal prices
would cause a $0.9 million decrease in the fair value of
these positions. The timing of the estimated future realization
of the value of our trading portfolio is 88% in 2009 and 12% in
2010.
We are also exposed to the risk of fluctuations in cash flows
related to our purchase of diesel fuel. We use approximately
50 million gallons of diesel fuel annually in our
operations. We enter into forward physical purchase contracts,
as well as heating oil swaps and options, to reduce volatility
in the price of diesel fuel for our operations. At
December 31, 2008, we had protected the price of
approximately 68% of our forecasted diesel purchases for 2009,
85% of which was accomplished through the use of the derivative
instruments noted above. At December 31, 2007, we had
protected approximately 23% of our forecasted purchases for
2008. 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,
with any ineffectiveness recognized immediately in income. At
December 31, 2008, a $0.25 per gallon decrease in the price
of heating oil would result in an approximate $6.4 million
increase in our expense in 2009 resulting from heating oil
derivatives, which would be offset by a decrease in the cost of
our physical diesel purchases.
67
We are exposed to market risk associated with interest rates due
to our existing level of indebtedness. At December 31,
2008, $967.0 million of our outstanding debt had fixed
interest rates, primarily our 6.75% Senior Notes, and
$339.3 million of outstanding borrowings have interest
rates that fluctuate based on changes in the respective market
rates. A one percentage point increase in the interest rates
related to these borrowings would result in an annualized
increase in interest expense of $3.4 million, based on
borrowing levels at December 31, 2008.
|
|
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, 2008. 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, 2008 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-3 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 2009 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, 2008, Outstanding
Equity Awards at December 31, 2008, Option
Exercises and Stock Vested for the Year Ended December 31,
2008, Pension Benefits, Nonqualified
Deferred Compensation, Potential Payments Upon
Termination of Employment or
Change-in-Control
and Director Compensation for the Year Ended
December 31, 2008 appearing in the section entitled
Executive and Director Compensation in our proxy
statement to be distributed to stockholders in connection with
the 2009 annual meeting.
68
|
|
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 2009 annual meeting.
Securities
Authorized for Issuance Under Equity Compensation
Plans
The Arch Coal, Inc. 1997 Stock Incentive Plan, which has been
approved by our stockholders, is the sole plan under which we
are authorized to issue shares of our common stock to employees.
The following table shows the number of shares of common stock
to be issued upon vesting of restricted stock units or exercise
of options outstanding at December 31, 2008, the weighted
average exercise price of options, and the number of shares of
common stock remaining available for future issuance at
December 31, 2008, excluding shares to be issued upon
exercise of outstanding options. No warrants or rights had been
issued under the plan as of December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
2,997,804
|
|
|
$
|
29.10
|
|
|
|
3,058,129
|
|
Equity compensation plans not approved by security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,997,804
|
|
|
$
|
29.10
|
|
|
|
3,058,129
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 2009 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 2009 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.
69
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
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F-2
|
|
|
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F-4
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|
|
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F-5
|
|
|
|
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F-6
|
|
|
|
|
F-7
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|
|
|
|
F-8
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|
|
|
|
F-9
|
|
|
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|
F-40
|
|
F-1
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders Arch Coal, Inc.
We have audited the accompanying consolidated balance sheets of
Arch Coal, Inc. (the Company) as of December 31, 2008 and
2007, and the related consolidated statements of income,
stockholders equity, and cash flows for each of the three
years in the period ended December 31, 2008. Our audits
also included the financial statement 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, 2008
and 2007, and the consolidated results of its operations and
cash flows for each of the three years in the period ended
December 31, 2008, 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.
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, 2008, 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 23, 2009,
expressed an unqualified opinion thereon.
St. Louis, Missouri
February 23, 2009
F-2
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders Arch Coal, Inc.
We have audited Arch Coal, Incs (the Companys)
internal control over financial reporting as of
December 31, 2008, based on criteria established in
Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(the 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, 2008, 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, 2008 and
2007, and the related consolidated statements of income,
stockholders equity, and cash flows for each of the three
years in the period ended December 31, 2008, of Arch Coal,
Inc., and our report dated February 23, 2009, expressed an
unqualified opinion thereon.
St. Louis, Missouri
February 23, 2009
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, 2008.
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
|
|
John T. Drexler
Senior Vice President and Chief
Financial Officer
|
F-4
CONSOLIDATED
STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except per share data)
|
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
|
|
$
|
2,983,806
|
|
|
$
|
2,413,644
|
|
|
$
|
2,500,431
|
|
COSTS, EXPENSES AND OTHER
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales
|
|
|
2,183,922
|
|
|
|
1,888,285
|
|
|
|
1,909,822
|
|
Depreciation, depletion and amortization
|
|
|
292,848
|
|
|
|
242,062
|
|
|
|
208,354
|
|
Selling, general and administrative expenses
|
|
|
107,121
|
|
|
|
84,446
|
|
|
|
75,388
|
|
Change in fair value of coal derivatives and coal trading
activities, net
|
|
|
(55,093
|
)
|
|
|
(7,292
|
)
|
|
|
|
|
Other operating income, net
|
|
|
(5,381
|
)
|
|
|
(23,474
|
)
|
|
|
(29,800
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,523,417
|
|
|
|
2,184,027
|
|
|
|
2,163,764
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
460,389
|
|
|
|
229,617
|
|
|
|
336,667
|
|
Interest expense, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(76,139
|
)
|
|
|
(74,865
|
)
|
|
|
(64,364
|
)
|
Interest income
|
|
|
11,854
|
|
|
|
2,600
|
|
|
|
3,725
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(64,285
|
)
|
|
|
(72,265
|
)
|
|
|
(60,639
|
)
|
Other non-operating expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses resulting from early debt extinguishment and
termination of hedge accounting for interest rate swaps
|
|
|
|
|
|
|
(1,919
|
)
|
|
|
(4,836
|
)
|
Other non-operating expense
|
|
|
|
|
|
|
(354
|
)
|
|
|
(2,611
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,273
|
)
|
|
|
(7,447
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
396,104
|
|
|
|
155,079
|
|
|
|
268,581
|
|
Provision for (benefit from) income taxes
|
|
|
41,774
|
|
|
|
(19,850
|
)
|
|
|
7,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
354,330
|
|
|
$
|
174,929
|
|
|
$
|
260,931
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER COMMON SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per common share
|
|
$
|
2.47
|
|
|
$
|
1.23
|
|
|
$
|
1.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per common share
|
|
$
|
2.45
|
|
|
$
|
1.21
|
|
|
$
|
1.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
|
143,604
|
|
|
|
142,518
|
|
|
|
142,770
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average shares outstanding
|
|
|
144,416
|
|
|
|
144,019
|
|
|
|
144,812
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared per common share
|
|
$
|
0.34
|
|
|
$
|
0.27
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-5
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
70,649
|
|
|
$
|
5,080
|
|
Trade accounts receivable
|
|
|
215,053
|
|
|
|
229,965
|
|
Other receivables
|
|
|
43,419
|
|
|
|
19,724
|
|
Inventories
|
|
|
191,568
|
|
|
|
177,785
|
|
Prepaid royalties
|
|
|
43,780
|
|
|
|
22,055
|
|
Deferred income taxes
|
|
|
52,918
|
|
|
|
18,789
|
|
Coal derivative assets
|
|
|
43,173
|
|
|
|
7,743
|
|
Other
|
|
|
45,818
|
|
|
|
40,004
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
706,378
|
|
|
|
521,145
|
|
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
Coal lands and mineral rights
|
|
|
1,818,657
|
|
|
|
1,690,176
|
|
Plant and equipment
|
|
|
2,031,561
|
|
|
|
1,729,501
|
|
Deferred mine development
|
|
|
762,746
|
|
|
|
672,496
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,612,964
|
|
|
|
4,092,173
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(1,909,881
|
)
|
|
|
(1,628,535
|
)
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
2,703,083
|
|
|
|
2,463,638
|
|
Other assets:
|
|
|
|
|
|
|
|
|
Prepaid royalties
|
|
|
66,918
|
|
|
|
105,106
|
|
Goodwill
|
|
|
46,832
|
|
|
|
40,032
|
|
Deferred income taxes
|
|
|
294,682
|
|
|
|
296,559
|
|
Equity investments
|
|
|
87,761
|
|
|
|
82,950
|
|
Other
|
|
|
73,310
|
|
|
|
85,169
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
569,503
|
|
|
|
609,816
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,978,964
|
|
|
$
|
3,594,599
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
186,322
|
|
|
$
|
150,026
|
|
Coal derivative liabilities
|
|
|
10,757
|
|
|
|
|
|
Accrued expenses and other current liabilities
|
|
|
249,203
|
|
|
|
188,875
|
|
Current maturities of debt and short-term borrowings
|
|
|
213,465
|
|
|
|
217,614
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
659,747
|
|
|
|
556,515
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
1,098,948
|
|
|
|
1,085,579
|
|
Asset retirement obligations
|
|
|
255,369
|
|
|
|
219,991
|
|
Accrued pension benefits
|
|
|
73,486
|
|
|
|
8,528
|
|
Accrued postretirement benefits other than pension
|
|
|
58,163
|
|
|
|
59,181
|
|
Accrued workers compensation
|
|
|
30,107
|
|
|
|
41,071
|
|
Other noncurrent liabilities
|
|
|
74,411
|
|
|
|
92,048
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
2,250,231
|
|
|
|
2,062,913
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par value, authorized
10,000 shares, issued and outstanding 0 and 85 shares
at December 31, 2008 and 2007, respectively
|
|
|
|
|
|
|
1
|
|
Common stock, $0.01 par value, authorized
260,000 shares, issued 144,345 and 143,158 shares at
December 31, 2008 and 2007, respectively
|
|
|
1,447
|
|
|
|
1,436
|
|
Paid-in capital
|
|
|
1,381,496
|
|
|
|
1,358,695
|
|
Treasury stock, 1,512 shares at December 31, 2008, at
cost
|
|
|
(53,848
|
)
|
|
|
|
|
Retained earnings
|
|
|
478,734
|
|
|
|
173,186
|
|
Accumulated other comprehensive loss
|
|
|
(79,096
|
)
|
|
|
(1,632
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
1,728,733
|
|
|
|
1,531,686
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
3,978,964
|
|
|
$
|
3,594,599
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-6
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS EQUITY
Three Years Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2006
|
|
$
|
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
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
354,330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
354,330
|
|
Pension, postretirement and other post-employment benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,907
|
)
|
|
|
(31,907
|
)
|
Net amount reclassified to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(684
|
)
|
|
|
(684
|
)
|
Unrealized losses on available-for- sale securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(349
|
)
|
|
|
(349
|
)
|
Net amount reclassified to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,005
|
|
|
|
1,005
|
|
Unrealized losses on derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(44,128
|
)
|
|
|
(44,128
|
)
|
Net amount reclassified to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,401
|
)
|
|
|
(1,401
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
276,866
|
|
Dividends:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common ($0.34 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(48,769
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(48,769
|
)
|
Preferred ($2.50 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12
|
)
|
Issuance of 261 shares of common stock under the stock
incentive plan restricted stock and restricted stock
units
|
|
|
|
|
|
|
2
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of 405 shares of common stock upon conversion of
preferred stock
|
|
|
(1
|
)
|
|
|
4
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock redemption
|
|
|
|
|
|
|
|
|
|
|
(24
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(25
|
)
|
Issuance of 521 shares of common stock under the stock
incentive plan stock options including income tax
benefits
|
|
|
|
|
|
|
5
|
|
|
|
6,314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,319
|
|
Employee stock-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
16,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,516
|
|
Purchase of 1,512 shares of common stock under stock
repurchase program
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(53,848
|
)
|
|
|
|
|
|
|
(53,848
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2008
|
|
$
|
|
|
|
$
|
1,447
|
|
|
$
|
1,381,496
|
|
|
$
|
478,734
|
|
|
$
|
|
|
|
$
|
(53,848
|
)
|
|
$
|
(79,096
|
)
|
|
$
|
1,728,733
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-7
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
354,330
|
|
|
$
|
174,929
|
|
|
$
|
260,931
|
|
Adjustments to reconcile net income to cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
292,848
|
|
|
|
242,062
|
|
|
|
208,354
|
|
Prepaid royalties expensed
|
|
|
36,227
|
|
|
|
11,962
|
|
|
|
9,045
|
|
Net (gain) loss on dispositions of property, plant and equipment
|
|
|
(243
|
)
|
|
|
(17,769
|
)
|
|
|
649
|
|
Gain on investment in Knight Hawk Holdings, LLC
|
|
|
|
|
|
|
|
|
|
|
(10,309
|
)
|
Employee stock-based compensation
|
|
|
12,618
|
|
|
|
5,777
|
|
|
|
9,080
|
|
Other non-operating expense
|
|
|
|
|
|
|
2,273
|
|
|
|
7,447
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(9,871
|
)
|
|
|
10,254
|
|
|
|
(49,265
|
)
|
Inventories
|
|
|
(13,783
|
)
|
|
|
(55,471
|
)
|
|
|
(39,783
|
)
|
Coal derivative assets and liabilities
|
|
|
(41,183
|
)
|
|
|
(8,532
|
)
|
|
|
|
|
Accounts payable, accrued expenses and other current liabilities
|
|
|
21,823
|
|
|
|
(59,634
|
)
|
|
|
(115,123
|
)
|
Deferred income taxes
|
|
|
15,222
|
|
|
|
(31,825
|
)
|
|
|
20,505
|
|
Accrued postretirement benefits other than pension
|
|
|
4,202
|
|
|
|
3,733
|
|
|
|
8,662
|
|
Asset retirement obligations
|
|
|
16,437
|
|
|
|
21,609
|
|
|
|
10,967
|
|
Accrued workers compensation
|
|
|
(528
|
)
|
|
|
971
|
|
|
|
(2,898
|
)
|
Other
|
|
|
(8,962
|
)
|
|
|
30,471
|
|
|
|
(10,160
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
679,137
|
|
|
|
330,810
|
|
|
|
308,102
|
|
INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(497,347
|
)
|
|
|
(488,363
|
)
|
|
|
(623,187
|
)
|
Proceeds from dispositions of property, plant and equipment
|
|
|
1,135
|
|
|
|
70,296
|
|
|
|
777
|
|
Additions to prepaid royalties
|
|
|
(19,764
|
)
|
|
|
(19,713
|
)
|
|
|
(20,062
|
)
|
Purchases of investments/advances to affiliates
|
|
|
(7,466
|
)
|
|
|
(5,540
|
)
|
|
|
(45,533
|
)
|
Consideration paid related to prior business acquisitions
|
|
|
(6,800
|
)
|
|
|
|
|
|
|
|
|
Reimbursement of deposit on equipment
|
|
|
2,697
|
|
|
|
18,325
|
|
|
|
|
|
|
|
|
|