e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2009
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
of incorporation or organization)
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(I.R.S. Employer
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 whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such
filed). 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)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). 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, 2009 was approximately $2.2 billion.
On February 22, 2010, 162,474,101 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 22, 2010 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. 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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the deferral of contracted shipments of coal by 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, 2009 (which includes fourth
quarter sales only from the former Jacobs Ranch mine complex,
which we acquired on October 1, 2009), we sold approximately
126.1 million tons of coal, including approximately
7.5 million tons of coal we purchased from third parties,
fueling approximately 12.7% of all coal-based electricity
generated in the United States. We sell substantially all of our
coal to power plants, steel mills and industrial facilities. At
December 31, 2009, we operated 19 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 on 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. We expect United States coal exports to increase in
2010, driven primarily by improving metallurgical coal demand.
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. On October 1, 2009, we acquired Rio Tintos
Jacobs Ranch mine complex in the Powder River Basin of Wyoming
which included 345 million tons of low-cost, low-sulfur
coal reserves and integrated it into the Black Thunder mine.
1
Coal
Characteristics
In general, end users characterize coal as steam coal or
metallurgical coal. Heat value, sulfur, ash, moisture content,
and volatility in the case of metallurgical coal, are 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-dioxide emission reduction technology.
All of our identified coal reserves have been subject to
preliminary coal seam analysis to test sulfur content. Of these
reserves, approximately 79.3% consist of compliance coal, while
an additional 6.1% could be sold as low-sulfur coal. The balance
is classified as high-sulfur coal. Higher sulfur coal can be
burned in plants equipped with sulfur-dioxide emission reduction
technology, such as scrubbers, and in facilities that blend
compliance and noncompliance coal.
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. The upheaval in
the global financial markets experienced in late 2008 spread to
the global energy markets, affecting energy demand throughout
2009. According to the Energy Information Administration (EIA),
global energy markets continue to adjust to highly uncertain
conditions precipitated by the commodity (oil and other energy
fuels) price collapse in 2008. Even as energy demand faltered
and the world debated the effects of reliance on all forms of
fossil fuels, coal remained (and remains) a major contributor to
global energy supplies because of its availability, stability
and affordability.
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According to the International Energy Agency (IEA), coal
provided approximately 41.5% of the worlds electricity in
2007 and it is also used in producing approximately 70% 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, and as such its distribution network
is varied and economical, creating viable energy supply
alternatives for developed and developing nations alike.
Coal is traded worldwide and can be transported to demand
centers by ship, rail, barge, and truck. Worldwide coal
production approximated 6.3 billion tonnes in 2007 and
6.7 billion tonnes in 2008, according to the IEA. China
remains the largest producer of coal in the world. It produced
nearly 2.8 billion tonnes in 2008, according to the IEA,
followed by the USA at approximately 1 billion tonnes and
India at nearly 490 million tonnes. The National Bureau of
Statistics of China reports that 2.7 billion tonnes of coal
have been produced domestically through November of 2009.
Historically, Australia has been the worlds largest coal
exporter, exporting more than 252 million tonnes in 2008,
according to the World Coal Institute (WCI). Indonesia, Russia,
Colombia, and South Africa have also historically been
significant exporters. Indonesia in particular has seen
substantial growth in its coal exports in the last few years;
however, its growing domestic energy demand may result in a
decrease in exports as it moves toward greater self-sufficiency.
China too has reduced its level of total exports as domestic
requirements became paramount and has become a large net
importer.
International demand for coal continues to be driven by growth
in electrical power generation capacity, most significantly in
China and India going forward. China and India represented
approximately 48% of total world coal consumption in 2006 and
are expected to account for approximately 59% by 2030, according
to the EIA. Increased international demand led to a substantial
rise in the demand for coal exports from the United States
during 2008 as the demand for coal for both power generation and
steel production, coupled with supply issues around the globe,
strained global coal supplies. The situation altered in 2009 as
weakened global energy demand caused demand for U.S. export
coal to decline. As global economic conditions improve and
regions return to growth, we expect the demand for
U.S. coal 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 or processing facilities. Coal consumption in the
United States increased from 398.1 million tons in 1960 to
approximately 1.0 billion tons in 2009, according to the
EIAs Short Term Energy Outlook. Although full-year data
for 2009 is not yet available, the global downturn affected
U.S. coal consumption. In 2009, coal consumption in the
U.S. was affected not only by lower total electricity
generation but also by increases in generation from other
electricity sources including natural gas and hydropower.
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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2002
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2009
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2011
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2020
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2030
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2009-2030
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(Tons, in millions)
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Electric power
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978
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936
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998
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1,073
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1,147
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0.9
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%
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Other industrial
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61
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47
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51
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53
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52
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0.5
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%
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Coke plants
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24
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16
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20
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20
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17
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0.3
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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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0.4
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%
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Coal-to-liquids
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32
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57
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n/a
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Total U.S. coal consumption
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1,067
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999.5
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1,072
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1,181
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1,276
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1.1
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%
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Source:
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EIA Annual Energy Outlook 2010
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EIA Short Term Energy Outlook (February 2010)
According to the EIA, coal accounted for approximately 45% of
U.S. electricity generation in 2009, and based on projected
19% growth in electricity demand, coal consumption is projected
to grow by more than 20% by 2030, reaching 1.2 billion
tons. (These amounts assume no future federal or state carbon
emissions legislation
3
is enacted and do not take into account recent market
conditions.) Historically, coal has been considerably less
expensive than natural gas or oil.
We estimate that the cost of generating electricity from coal is
significantly lower than the cost of generating electricity from
other fossil fuels. According to the EIA, the average delivered
cost of coal to electric power generators for 2009 was $2.21/mm
Btus, which was $7.16/mmBtu less expensive than petroleum
liquids and $2.40/mmBtu lower than natural gas. Coal is also
competitive with existing nuclear power generation, 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 2009, renewable power
generation (excluding hydro), such as wind power and biomass,
accounted for only 4% of all electricity generated in the United
States and is currently not a reliable source for baseload
electric power. The following chart shows the breakdown of
U.S. electricity generation by energy source for 2009,
according to the EIA:
Source: EIA Short Term Energy Outlook (February 2010).
The EIA has projected that approximately 108 gigawatts of new
electricity capacity (net of retirements) will be needed between
2008 and 2030, with approximately 14% of the new capacity
estimated to come from coal fueled generation. 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, to integrated gasification combined cycle
(IGCC) units, which permit coal to be turned into a
gasified product for the easier capture of carbon dioxide in the
future. Many projects that are moving forward are being
developed by municipal and regulated utilities due to their
ability to recover costs, in addition to their prior experience
with coal.
The other major market for coal is the steel industry. Coal is
essential for iron and steel production. According to the WCI,
approximately 70% of all steel is produced from iron made in
coal fired blast furnaces. The steel industry uses metallurgical
coal, which is distinguishable from other types of coal by 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 during 2009
fell from their record highs of the previous year due to the
effects of the worldwide economic recession. Historically,
volatile oil and gas prices and global energy security concerns
have increased 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-
4
sulfur diesel fuel, gasoline and other oil products, such as
plastics and solvents. Currently, there are only a limited
number of projects moving forward because of lower oil and
natural gas prices.
U.S. Coal Production. The United States is the
second largest coal producer in the world, exceeded only by
China. According to the EIA, there is over 200 billion tons
of recoverable coal in the U.S. The U.S. Department of
Energy estimates that current domestic recoverable coal reserves
could supply enough electricity to satisfy domestic demand for
approximately 200 years. Annual coal production in the
United States has increased from 434 million tons in 1960
to approximately 1.0 billion tons in 2009 based on
information provided by the Mine Safety and Health
Administration.
Coal is mined from coal fields throughout 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 an estimated 629 million
tons in 2009, as competitive mining costs and regulations
limiting sulfur dioxide emissions have continued the 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 Colorado,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 an estimated 342 million
tons in 2009 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%. Southern Appalachia primarily covers Alabama and
generally has a heat content ranging from 11300 to 12300 Btu and
a sulfur content ranging from 0.7% - 3.0%.
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 103.3 million tons in 2009. 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. Although down
from the previous year, U.S. exports began to increase in
the second half of 2009, supported by recovering global
economies and continued growth in Chinese and Indian steel
markets in particular. This is a trend we expect to continue.
Because of this, we believe that the United States will continue
to be an increasingly important swing supplier of coal to the
global marketplace in the near term.
5
Historically, coal imported from abroad has represented a
relatively small share of total U.S. coal consumption, and
this remained the case in 2009. According to the EIA, coal
imports increased from 8.9 million tons in 1994 to
approximately 22.8 million tons in 2009, which represented
a fall from the 34 million tons imported in 2008. The drop
was primarily related to the decline in demand for power
generation as well as weaker domestic coal prices. 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 import
growth to be significant as more and more global coal will
likely be directed to Asia.
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 below
under Our Mining Operations General. In
2009, approximately 80% of the coal that we produced came from
surface mining operations.
Surface mining involves removing the topsoil then drilling and
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.
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 Our
6
Mining Operations General. In 2009,
approximately 20% of the coal that we produced came from
underground mining operations.
Our underground mines are typically operated using one or both
of two different mining 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 2009,
approximately 17% of the coal that we produced came from
underground mining operations generally using longwall mining
techniques.
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 2009, 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 2009, approximately 3% of
the coal that we produced came from underground mining
operations generally using
room-and-pillar
mining techniques.
7
The following diagram illustrates our typical underground mining
operation using
room-and-pillar
mining techniques:
Coal Preparation and Blending. We 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
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 2009, our
preparation plants processed approximately 80% to 90% 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.
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, 2009, we
operated 19 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
8
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, 2009, 2008 and
2007 contained in Note 23 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). 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 and
preparation plants at strategic locations in close proximity to
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:
The following table provides a summary of information regarding
our active mining complexes at December 31, 2009, the total
sales associated with these complexes for the years ended
December 31, 2007, 2008 and 2009 and the total reserves
associated with these complexes at December 31, 2009. 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
9
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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2007
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2008
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2009
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2009
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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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86.2
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88.5
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81.2
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$
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996.6
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1,521.6
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Coal Creek
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S
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D, S
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UP/BN
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10.2
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11.5
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9.8
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148.1
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197.1
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Western Bituminous:
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Arch of Wyoming
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S
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L
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UP
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0.2
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0.1
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23.8
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14.8
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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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4.0
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4.3
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3.2
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137.0
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19.8
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Skyline
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U
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LW, CM
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UP
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2.4
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3.3
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2.8
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160.1
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19.2
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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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6.7
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7.4
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6.6
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210.4
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66.2
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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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6.2
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5.3
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4.0
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432.2
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74.9
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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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3.9
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3.7
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2.9
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169.3
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26.7
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Cumberland River
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S(1), U(2)
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U
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L, CM, HW
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NS
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2.4
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2.4
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1.6
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130.2
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22.7
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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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2.4
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2.7
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2.2
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185.7
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30.6
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Mountain Laurel
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U
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S(2)
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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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4.4
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437.1
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86.4
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Totals
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125.4
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133.6
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118.8
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$
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3,030.5
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2,080
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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, 2009. 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. The amount of coal that we purchased from third
parties and processed through our loadout facilities was
negligible in 2008 and 2009. 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
7.3 million tons in 2009, 6.0 million tons in 2008 and
8.4 million tons in 2007.
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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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Powder
River Basin
Black Thunder. Black Thunder is a surface
mining complex located on approximately 33,800 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 81.2 million tons
of coal in 2009.
We control a significant portion of the coal reserves through
federal and state leases. The Black Thunder mining complex had
approximately 1.5 billion tons of proven and probable
reserves at December 31, 2009. The air quality permit for
the Black Thunder mine allows for the mining of coal at a rate
of 190.0 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
10
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.
The Black Thunder mining complex currently consists of seven
active pit areas and three 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.
Coal Creek. 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 9.8 million tons of coal in 2009.
We control a significant portion of the coal reserves through
federal and state leases. The Coal Creek mining complex had
approximately 197 million tons of proven and probable
reserves at December 31, 2009. 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 tract of coal adjacent to the Coal
Creek mining complex has been nominated for lease, and other
potential 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.
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. 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
Arch of Wyoming. 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
0.1 million tons of coal in 2009.
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
14.8 million tons of proven and probable reserves at
December 31, 2009. 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.
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.
Dugout Canyon. Dugout Canyon mine is an
underground mining complex located on approximately
18,200 acres in Carbon County, Utah. The Dugout Canyon
mining complex has extracted steam coal from the Rock Canyon and
Gilson seams. The Dugout Canyon mining complex shipped
3.2 million tons of coal in 2009.
We control a significant portion of the coal reserves through
federal and state leases. The Dugout Canyon mining complex had
approximately 19.8 million tons of proven and probable
reserves at December 31, 2009. The coal seam currently
being mined will sustain current production levels until
approximately mid-2012, at which point we will need to
transition to another coal seam to continue mining.
11
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.
Skyline. 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 2.8 million tons of coal in 2009.
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
19.2 million tons of proven and probable reserves at
December 31, 2009. The reserve area currently being mined
will sustain current production levels through 2011, at which
point we will need to transition to a new reserve area in order
to continue mining.
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.
Sufco. Sufco is an underground mining complex
located on approximately 27,550 acres in Sevier County,
Utah. The Sufco mining complex extracts steam coal from the
Upper Hiawatha seam. The Sufco mining complex shipped
6.6 million tons of coal in 2009.
We control a significant portion of the coal reserves through
federal and state leases. The Sufco mining complex had
approximately 66.2 million tons of proven and probable
reserves at December 31, 2009. The coal seam currently
being mined will sustain current production levels through 2020,
at which point we will need to transition to a new coal seam in
order to continue mining.
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.
West Elk. 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. The West Elk mining complex shipped
4.0 million tons of coal in 2009.
We control a significant portion of the coal reserves through
federal and state leases. The West Elk mining complex had
approximately 74.9 million tons of proven and probable
reserves at December 31, 2009. Without the addition of more
coal reserves, the current reserves will sustain current
production levels through 2019 before annual output starts to
significantly decline.
The West Elk complex currently consists of a longwall, two
continuous miner sections and a loadout facility. We ship most
of the coal raw to our customers via the Union Pacific railroad.
In 2009, we processed a small portion of the coal mined at this
complex at a nearby preparation plant. In 2010, a new coal
preparation plant with supporting coal handling facilities will
be constructed to process coal at the West Elk mine site. The
loadout facility can load an 11,000-ton train in less than three
hours.
Central
Appalachia
Coal-Mac. 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 primarily 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 2.9 million tons
of coal in 2009.
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We control a significant portion of the coal reserves through
private leases. The Coal-Mac mining complex had approximately
26.7 million tons of proven and probable reserves at
December 31, 2009. Without the addition of more coal
reserves, the current reserves will sustain current production
levels until 2018 before annual output starts to significantly
decline.
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 all 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 about four hours.
Cumberland River. 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 1.6 million tons of coal in 2009.
We control a significant portion of the coal reserves through
private leases. The Cumberland River mining complex had
approximately 22.7 million tons of proven and probable
reserves at December 31, 2009. Without the addition of more
coal reserves, the current reserves will sustain current
production levels until 2017 before annual output starts to
significantly decline.
The complex currently consists of four underground mines (two
captive, two contract) operating four continuous miner sections,
two captive surface operations, one captive highwall miner, 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 railroad.
The loadout facility can load a 12,500-ton train in less than
four hours.
Lone Mountain. 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 2.2 million tons of coal in 2009.
We control a significant portion of the coal reserves through
private leases. The Lone Mountain mining complex had
approximately 30.6 million tons of proven and probable
reserves at December 31, 2009. Without the addition of more
coal reserves, the current reserves will sustain current
production levels until 2020 before annual output starts to
significantly decline.
The complex currently consists of three underground mines
operating a total of seven continuous miner sections. We convey
coal mined in Kentucky to Virginia before we process it through
a 1,200-ton-per-hour preparation plant. We then ship the coal to
our customers via the Norfolk Southern or CSX railroad. The
loadout facility can load a 12,500-ton unit train in less than
four hours.
Mountain Laurel. Mountain Laurel is an
underground and surface mining complex located on approximately
38,280 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 4.4 million tons
of coal in 2009.
We control a significant portion of the coal reserves through
private leases. The Mountain Laurel mining complex had
approximately 86.4 million tons of proven and probable
reserves at December 31, 2009. Without
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the addition of more coal reserves, the current reserves will
sustain current production levels until 2017 before annual
output starts to significantly decline.
The complex currently consists of one underground mine operating
a longwall and a total of four continuous miner sections, two
contract surface operations, 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 and
hydropower. 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 primary 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 and
a Western Bituminous mine. 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 function 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 2009, we sold coal to domestic
customers located in 39 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, 2009, we derived approximately 23% of
our total coal revenues from sales to our three largest
customers Tennessee Valley Authority, Ameren
Corporation and Pacificorp and approximately 48% of
our total coal revenues from sales to our 10 largest customers.
During 2009, we also exported coal to customers located
throughout countries in North America, Europe, South America,
and Asia. Coal sales revenue from foreign customers approximated
$194.4 million for 2009, $486.1 million for 2008 and
$196.7 million for 2007. We do not have foreign currency
exposure for our international sales as all sales are
denominated and settled in U.S. dollars.
Beginning in the third quarter of 2008, worldwide steel prices
plummeted and steel production on a global basis was
significantly curtailed. In particular, steel demand collapsed
in the United States, Western Europe and Eastern Europe. These
are the principal geographic regions where our metallurgical
products are sold. As a result, we produced a smaller percentage
of metallurgical quality coal during 2009 than we did in 2008.
We sold approximately 2.1 million tons of metallurgical
quality coal in 2009, 4.4 million tons of metallurgical
quality coal in 2008 and approximately 2.1 million tons of
metallurgical quality coal in 2007.
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
14
contracts allow customers to secure a supply for their future
needs and provide us with greater predictability of sales volume
and sales prices. In 2009, we sold approximately 72% of our coal
under long-term supply arrangements. The majority 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, 2009, the average volume-weighted remaining
term of our long-term contracts was approximately
3.1 years, with remaining terms ranging from one to eight
years. At December 31, 2009, we had a sales backlog,
including a backlog subject to price re-opener or extension
provisions, of approximately 357.5 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 negotiations with customers.
Consequently, the terms of these contracts vary by customer,
including base price adjustment features, price re-opener terms,
coal quality requirements, quantity parameters, permitted
sources of supply, future regulatory changes, extension options,
force majeure, termination, damages 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 or the
customer consumption requirements. 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 purchase or 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 equivalent delivered
cost.
15
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 volumes
and/or
prices associated with our 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 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 for more
information about the market risks associated with these
strategies at December 31, 2009.
Transportation. We ship our coal to domestic
customers by means of railroad, barges, vessels 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, barge or vessel.
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, a
partnership that 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 or by truck
delivery. 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.
16
Competition
The coal industry is intensely competitive. The most important
factors on which we compete are coal quality, delivered costs to
the customer and reliability of supply. Our principal domestic
competitors include Alpha Natural Resources, Inc., CONSOL Energy
Inc., Massey Energy Company, Patriot Coal Corporation, Peabody
Energy Corp. and Cloud Peak Energy. 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 natural
gas, nuclear energy, 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.
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 explosives and fuel, and preferred
suppliers for other parts at our business such as dragline and
shovel parts and related services. 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.
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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.
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.
On December 12, 2008, OSM finalized a rulemaking regarding
the interpretation of the stream buffer zone provisions of SMCRA
which confirmed that excess spoil from mining and refuse from
coal preparation could be placed in permitted areas of a mine
site that constitute waters of the United States. On
November 30, 2009, OSM announced another rulemaking that
would reinterpret the regulations finalized eleven months
earlier. We cannot predict how the regulations may change or how
they may affect coal production.
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
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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 produced from surface mines and $0.135 per ton of coal
produced from underground mines. In 2009, we recorded
$32.7 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, 2009, we have self-bonded an aggregate of
approximately $352.0 million and have posted an aggregate
of approximately $297.3 million in surety bonds for
reclamation purposes. In addition, we had approximately
$153.5 million of surety bonds and letters of credit
outstanding at December 31, 2009 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 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 2009, we recorded $64.9 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 is
likely, such as EPAs proposal published on
December 8, 2009 to revise the national ambient air quality
standard for oxides of sulfur and a similar proposal announced
on January 6, 2010 for ozone. Regulation of additional
emissions such as carbon dioxide or other greenhouse gases as
proposed or determined by EPA on October 27, October 30 and
December 15, 2009 may eventually be applied to
stationary sources such as coal-fueled power plants and
industrial boilers (see discussion of Climate Change, below).
This application 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
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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.
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In addition, EPA announced on January 6, 2010 a proposal to
adopt a new, more stringent primary ambient air quality standard
for ozone and to change the way in which the secondary standard
is calculated. Should these 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 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 which the agency predicts will take approximately two
years.
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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.
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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. On December 24, 2009, the EPA announced that it
had recommended to the Office of Management and Budget an
Information Collection Request that would require all US power
plants with coal or oil-fired generating units to submit
emissions information. With this information the EPA intends to
propose standards for all air toxic emissions, including
mercury, for coal and oil-fired units by March 10, 2011.
The EPA hopes to make these new standards final by
November 16, 2011. 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.
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. On December 15, 2009, EPA
published a formal determination that six greenhouse gases,
including carbon dioxide and methane, endanger both the public
health and welfare of current and future generations. In the
same Federal Register rulemaking, EPA found that emission of
greenhouse gases from new motor vehicles and their engines
contribute to greenhouse gas pollution. 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,
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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. On
October 27, 2009, the EPA announced how it will establish
thresholds for phasing-in and regulating greenhouse gas
emissions under various provisions of the Clean Air Act. Three
days later, on October 30, 2009, the EPA published a final
rule in the Federal Register that requires the reporting of
greenhouse gas emissions from all sectors of the American
economy, although reporting of emissions from underground coal
mines and coal suppliers as originally proposed has been
deferred pending further review. 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. These 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 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-
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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 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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Notwithstanding the additional environmental protections
designed in the 2007 NWP 21, on July 15, 2009, the Corps
proposed to immediately suspend the use of the NWP 21 in six
Appalachian states, including West Virginia, Kentucky and
Virginia where the Company conducts operations. In addition, in
the same notice, the Corps proposed to modify the NWP 21
following the receipt and review of public comments to prohibit
its further use in the same states during the remaining term of
the permit which is March 12, 2012. The Corps is now
reviewing the more than 21,000 public comments it has received.
The agency has not announced when it is expected to complete its
review and reach a final decision.
Regardless of the outcome of the Corps decision about any
continuing use of NWP 21, it does not prevent the Companys
operations from seeking an individual permit under
§ 404 of the CWA, nor does it restrict an operation
from utilizing another version of the nationwide permit
authorized for small underground coal mines that must construct
fills as part of their mining operations.
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 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.
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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 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 11, 2010, we
employed a total of approximately 4,601 persons,
approximately 152 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 22, 2010 and their positions and offices during
the last five years:
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Position
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C. Henry Besten, Jr.
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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.
and CoaLogix.
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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.
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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 Business Roundtable, the BRT, the University of
the Pacific and Washington University 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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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
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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
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.
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 biomass 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.
27
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.
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.
Certain
of our customers have deferred, and other customers may in the
future seek to defer, contracted shipments of coal, which could
affect our results of operations and liquidity.
As the ongoing global economic recession has caused the price
of, and demand for, coal to decline, certain of our thermal and
metallurgical coal customers have delayed shipments, or
requested deferrals, pursuant to our existing long-term coal
supply agreements. Other customers similarly may seek to delay
shipments or request deferrals under existing agreements. In the
current economic environment, the spot market for coal may not
provide an acceptable alternative to sell our uncommitted tons.
We currently are evaluating customer deferrals and are in
negotiations with a number of the customers that have made such
requests. There is no assurance that we will be able to resolve
existing and potential deferrals on favorable terms, or at all.
Competition
within our industry and with producers of competing energy
sources may materially and adversely affect our ability to sell
coal at favorable prices.
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 been
volatile. A decline in the
28
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.
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.
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 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.
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.
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.
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.
In 2009, approximately 94% 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 biomass 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
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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.
Our
inability to acquire additional coal reserves or our inability
to develop coal reserves in an economically feasible manner may
adversely affect our business.
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. 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.
Inaccuracies
in our estimates of our coal reserves could result in decreased
profitability from lower than expected revenues or higher than
expected costs.
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
30
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. 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. Because of the shortage of trained coal miners in recent
years, we have occasionally operated certain facilities without
full staff and have at times 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 we were to experience a
shortage of skilled labor, 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.
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A
defect in title or the loss of a leasehold interest in certain
property could limit our ability to mine our coal reserves or
result in significant unanticipated costs.
We conduct a significant part of our coal mining operations on
properties that we lease. A title defect or the loss of a lease
could adversely affect our ability to mine the associated coal
reserves. We may not verify title to our leased properties or
associated coal reserves until we have committed to developing
those properties or coal reserves. We may not commit to develop
property or coal reserves until we have obtained necessary
permits and completed exploration. As such, the title to
property that we intend to lease or coal reserves that we intend
to mine may contain defects prohibiting our ability to conduct
mining operations. Similarly, our leasehold interests may be
subject to superior property rights of other third parties. In
order to conduct our mining operations on properties where these
defects exist, we may incur unanticipated costs. In addition,
some leases require us to produce a minimum quantity of coal and
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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a requirement that we devote significant management attention
and resources to integrating acquired businesses and 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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Delays or unexpected difficulties in the integration process
could adversely affect our business, financial results and
financial condition. Even if we are able to integrate acquired
businesses and assets successfully, this integration may not
result in the realization for the full benefits of synergies,
cost savings and operational efficiencies that we expect or the
achievement of these benefits within a reasonable period of
time. In addition, we may not have discovered prior to acquiring
them all known and unknown factors regarding acquired businesses
or assets that could produce unintended and unexpected
consequences for us. Undiscovered factors
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could result in us incurring financial liabilities, which could
be material, and in us not achieving the expected benefits from
the acquisitions within our desired time frames, if at all.
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.
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 the section
entitled Long-Term Coal Supply Arrangements.
The
loss of, or significant reduction in, purchases by our largest
customers could adversely affect our
profitability.
For the year ended December 31, 2009, we derived
approximately 23% 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, 2009, we had consolidated indebtedness of
approximately $1.8 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
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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.
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We may
be unable to comply with restrictions imposed by our credit
facilities and other financing arrangements.
The agreements governing our outstanding 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 the section entitled Liquidity and Capital
Resources.
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, 2009, if we had purchased
the 15.6 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
$476.2 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
35
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.
Risks
Related to Environmental, Other Regulations and
Legislation
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 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
36
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 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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37
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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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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.
|
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 the section entitled
Environmental and Other Regulatory Matters 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. We are required to record new obligations as
liabilities at fair value under generally accepted accounting
principles. 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.
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
38
well as for the investigation and clean up of soil, surface
water, groundwater, and other media. Such claims may arise, for
example, out of conditions at sites that we currently own or
operate, as well as at sites that we previously owned or
operated, or may acquire. Our liability for such claims may be
joint and several, so that we may be held responsible for more
than our share of the contamination or other damages, or even
for the entire share.
We maintain extensive coal refuse areas and slurry impoundments
at a number of our mining complexes. Such areas and impoundments
are subject to extensive regulation. Slurry impoundments have
been known to fail, releasing large volumes of coal slurry into
the surrounding environment. Structural failure of an
impoundment can result in extensive damage to the environment
and natural resources, such as bodies of water that the coal
slurry reaches, as well as liability for related personal
injuries and property damages, and injuries to wildlife. Some of
our impoundments overlie mined out areas, which can pose a
heightened risk of failure and of damages arising out of
failure. If one of our impoundments were to fail, we could be
subject to substantial claims for the resulting environmental
contamination and associated liability, as well as for fines and
penalties.
Drainage flowing from or caused by mining activities can be
acidic with elevated levels of dissolved metals, a condition
referred to as acid mine drainage, which we refer to
as AMD. The treating of AMD can be costly. Although we do not
currently face material costs associated with AMD, it is
possible that we could incur significant costs in the future.
These and other similar unforeseen impacts that our operations
may have on the environment, as well as exposures to hazardous
substances or wastes associated with our operations, could
result in costs and liabilities that could materially and
adversely affect us.
Judicial
rulings that restrict how we may dispose of mining wastes could
significantly increase our operating costs, discourage customers
from purchasing our coal and materially harm our financial
condition and operating results.
To dispose of mining overburden generated by our surface mining
operations, we often need to obtain permits to construct and
operate valley fills and surface impoundments. Some of these
permits are Clean Water Act § 404 permits issued by
the Army Corps of Engineers. Two of our operating subsidiaries
were identified in an existing lawsuit, which challenged the
issuance of such permits and asked that the Corps be ordered to
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 for more information about the
litigation described above.
Changes
in the legal and regulatory environment could limit our business
activities, increase our operating costs, or result in
litigation.
The conduct of our businesses is subject to various laws and
regulations administered by federal, state and local
governmental agencies in the United States. These laws and
regulations may change, sometimes dramatically, as a result of
political, economic or social events. Such regulatory
environment changes may include changes in: accounting
standards; taxation requirements; and competition laws. Changes
in laws, regulations or governmental policy and the related
interpretations may alter the environment in which we do
business and, therefore, may impact our results or increase our
costs or liabilities.
In particular, mining companies are entitled a tax deduction for
percentage depletion, which may allow for depletion deductions
in excess of the basis in the mineral reserves. The deduction is
currently being reviewed by
39
the federal government for repeal. If repealed, it could have a
material impact on our financial position and future tax
payments.
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ITEM 1B.
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UNRESOLVED
STAFF COMMENTS.
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None.
Our
Properties
General
At December 31, 2009, we owned or controlled primarily
through long-term leases approximately 100,100 acres of
coal land in West Virginia, 107,800 acres of coal land in
Wyoming, 98,900 acres of coal land in Illinois,
72,100 acres of coal land in Utah, 46,200 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 133,700 acres of our coal
land from the federal government and approximately
28,000 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 for more
information about our mining operations, mining complexes and
transportation facilities.
Our Coal
Reserves
We estimate that we owned or controlled approximately
3.9 billion tons of proven and probable recoverable
reserves at December 31, 2009. Our coal reserve estimates
at December 31, 2009 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.
40
The following tables present our estimated assigned and
unassigned recoverable coal reserves at December 31, 2009:
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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|
2007
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2008
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Wyoming
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1,733
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|
|
1,703
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|
30
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|
1,626
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|
|
|
107
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|
|
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8,832
|
|
|
|
1,720
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|
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|
13
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1,733
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|
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1,549
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1,476
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Montana
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Utah
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|
105
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|
|
|
61
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|
44
|
|
|
|
97
|
|
|
|
8
|
|
|
|
|
|
|
|
11,415
|
|
|
|
103
|
|
|
|
2
|
|
|
|
|
|
|
|
105
|
|
|
|
103
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|
|
|
89
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|
Colorado
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|
75
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|
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|
59
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|
|
|
16
|
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
11,341
|
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
75
|
|
|
|
79
|
|
|
|
71
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Central App
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|
167
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|
|
|
157
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|
|
|
10
|
|
|
|
59
|
|
|
|
107
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|
|
|
1
|
|
|
|
12,803
|
|
|
|
159
|
|
|
|
8
|
|
|
|
74
|
|
|
|
93
|
|
|
|
169
|
|
|
|
176
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|
Illinois
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|
|
|
|
|
|
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|
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|
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|
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|
|
|
|
|
|
|
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|
|
|
|
|
|
|
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|
|
|
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|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total
|
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|
2,080
|
|
|
|
1,980
|
|
|
|
100
|
|
|
|
1,857
|
|
|
|
222
|
|
|
|
1
|
|
|
|
9,371
|
|
|
|
2,057
|
|
|
|
23
|
|
|
|
1,807
|
|
|
|
273
|
|
|
|
1,900
|
|
|
|
1,812
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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(1)
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As received Btus per lb. includes
the weight of moisture in the coal on an as sold basis.
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Total
Unassigned Reserves
(Tons in
millions)
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|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
498
|
|
|
|
406
|
|
|
|
92
|
|
|
|
449
|
|
|
|
49
|
|
|
|
|
|
|
|
9,557
|
|
|
|
405
|
|
|
|
93
|
|
|
|
323
|
|
|
|
175
|
|
Montana
|
|
|
717
|
|
|
|
595
|
|
|
|
122
|
|
|
|
717
|
|
|
|
|
|
|
|
|
|
|
|
8,582
|
|
|
|
717
|
|
|
|
|
|
|
|
717
|
|
|
|
|
|
Utah
|
|
|
66
|
|
|
|
17
|
|
|
|
49
|
|
|
|
32
|
|
|
|
34
|
|
|
|
|
|
|
|
11,436
|
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
66
|
|
Colorado
|
|
|
30
|
|
|
|
24
|
|
|
|
6
|
|
|
|
28
|
|
|
|
2
|
|
|
|
|
|
|
|
11,458
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
30
|
|
Central App
|
|
|
170
|
|
|
|
121
|
|
|
|
49
|
|
|
|
37
|
|
|
|
95
|
|
|
|
38
|
|
|
|
12,724
|
|
|
|
133
|
|
|
|
37
|
|
|
|
39
|
|
|
|
131
|
|
Illinois
|
|
|
374
|
|
|
|
270
|
|
|
|
104
|
|
|
|
|
|
|
|
|
|
|
|
374
|
|
|
|
11,592
|
|
|
|
56
|
|
|
|
318
|
|
|
|
2
|
|
|
|
372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,855
|
|
|
|
1,433
|
|
|
|
422
|
|
|
|
1,263
|
|
|
|
180
|
|
|
|
412
|
|
|
|
9,979
|
|
|
|
1,407
|
|
|
|
448
|
|
|
|
1,081
|
|
|
|
774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 to test sulfur content. Of these
reserves, approximately 79.3% consist of compliance coal, or
coal which emits 1.2 pounds or less of sulfur dioxide per
million Btus upon combustion, while an additional 6.1% 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, 2009
was $1.7 billion, consisting of $107.7 million of
prepaid royalties and a net book value of coal lands and mineral
rights of $1.6 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
41
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.
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.
42
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 for more information.
At December 31, 2009, approximately 11.9% 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 20,400 acres of property to other
coal operators in 2009. We received royalty income of
$6.3 million in 2009 from the mining of approximately
2.2 million tons, $6.8 million in 2008 from the mining
of approximately 3.1 million tons and $5.6 million in
2007 from the mining of approximately 2.1 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.
Permit
Litigation Matters
Surface mines at our Mingo Logan and Coal-Mac mining operations
were identified in an existing lawsuit brought by the Ohio
Valley Environmental Coalition (OVEC) in the U.S. District
Court for the Southern District of West Virginia as having been
granted Clean Water Act § 404 permits by the Army
Corps of Engineers, allegedly in violation of the Clean Water
Act and the National Environmental Policy Act.
The lawsuit, brought by OVEC in September 2005, originally was
filed against the Corps for permits it had issued to four
subsidiaries of a company unrelated to us or our operating
subsidiaries. The suit claimed that the Corps had issued permits
to the subsidiaries of the unrelated company that did not comply
with the National Environmental Policy Act and violated the
Clean Water Act.
The court ruled on the claims associated with 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
43
of sediment from the valley fills into sediment control ponds
constructed in-stream to control that sediment must themselves
be permitted under a different provision of the Clean Water Act,
§ 402, and meet the effluent 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.
Before the court entered its first order, the plaintiffs were
permitted to amend their complaint to challenge the Coal-Mac and
Mingo Logan permits. 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 were on
appeal. The claims against Coal-Mac were thereafter dismissed.
On February, 13, 2009, the Fourth Circuit reversed the District
Court. 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 preparing an
environmental impact statement, the absence of which was one
issue on appeal. These holdings also validated the type of
mitigation projects proposed by 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.
The Ohio Valley Environmental Coalition sought rehearing before
the entire appellate court which was denied on May 29, and
the decision was given legal effect on June 24. An appeal
to the U.S. Supreme Court was then filed on August 26,
2009. The Supreme Courts acceptance of such appeal is
discretionary.
Mingo Logan filed a motion for summary judgment with the
district court on July 17, 2009, asking that judgment be
entered in its favor because no outstanding legal issues
remained for decision as a result of the Fourth Circuits
February decision.
Additional information can be obtained from the
U.S. District Court for the Southern District of
West Virginia.
Potential
EPA Prohibitions related to water discharges from the Spruce
Permit
By letter of September 3, 2009, the EPA asked the Corps of
Engineers to suspend, revoke or modify the existing permit it
issued in January 2007 to Mingo Logan under Section 404 of
the Clean Water Act, claiming that new information and
circumstances have arisen which justify reconsideration of the
permit. By letter of September 30, 2009, the Corps of
Engineers advised the EPA that it would not reconsider its
decision to issue the permit. By letter of October 16,
2009, the EPA advised the Corps that it has reason to
believe that the Mingo Logan mine will have
unacceptable adverse impacts to fish and wildlife
resources and that it intends to issue a public notice of
a proposed determination to restrict or prohibit discharges of
fill material that already are approved by the Corps
permit. The EPA has not yet issued that public notice. Mingo
Logan and the EPA continue to engage in discussions as to
modifications to the permit or mine plan that would avoid
further action by the EPA.
West
Virginia Flooding Litigation
Over 2,000 plaintiffs 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 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,
would be handled pursuant to the courts mass litigation
rules. As a result of that 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.
44
On May 2, 2006, following the Mullins/Ocean 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 were named. Everything was remanded
to the Mass Litigation Panel (the Panel) on
September 17, 2008.
The parties were ordered to mediate the case, and a confidential
global settlement was reached on December 10, 2009. The
Panel has scheduled a hearing for March 23, 2010 to
finalize the settlement.
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 address any identified compliance issues at our
eastern mining complexes. To date, neither the EPA nor the
U.S. Department of Justice has initiated any enforcement
action against us.
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 22,
2010, our common stock closed at $22.44 on the New York Stock
Exchange. On that date, there were approximately 7,450 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 $54.9 million, or $0.36 per
share, in 2009 and $48.9 million, or $0.34 per share, in
2008. 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 the section entitled Liquidity and Capital
Resources 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
|
December 31
|
|
|
Dividends per common share
|
|
$
|
0.09
|
|
|
$
|
0.09
|
|
|
$
|
0.09
|
|
|
$
|
0.09
|
|
High
|
|
|
20.63
|
|
|
|
19.94
|
|
|
|
24.10
|
|
|
|
25.86
|
|
Low
|
|
|
11.77
|
|
|
|
12.52
|
|
|
|
13.01
|
|
|
|
19.41
|
|
Close
|
|
|
13.37
|
|
|
|
15.37
|
|
|
|
22.13
|
|
|
|
22.25
|
|
45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
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, 2004;
|
|
|
|
all dividends were reinvested;
|
|
|
|
annual reweighting of the peer groups; and
|
|
|
|
you continued to hold your investment through December 31,
2009.
|
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.
Comparison
of 5 Year Cumulative Total Return*
Among Arch Coal, Inc., The S&P Midcap 400 Index and
Industry Peer Group
* $100 invested on 12/31/04 in
stock or index, including reinvestment of dividends.
Fiscal year ending December 31.
Copyright©
2010 S&P, a division of The McGraw-Hill Companies Inc. All
rights reserved.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12/04
|
|
12/05
|
|
12/06
|
|
12/07
|
|
12/08
|
|
12/09
|
Arch Coal, Inc.
|
|
|
100.00
|
|
|
|
224.97
|
|
|
|
170.95
|
|
|
|
257.78
|
|
|
|
94.40
|
|
|
|
131.65
|
|
S&P Midcap 400
|
|
|
100.00
|
|
|
|
112.55
|
|
|
|
124.17
|
|
|
|
134.08
|
|
|
|
85.50
|
|
|
|
117.46
|
|
Industry Peer Group
|
|
|
100.00
|
|
|
|
168.67
|
|
|
|
155.05
|
|
|
|
285.81
|
|
|
|
112.05
|
|
|
|
230.96
|
|
46
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, 2009, 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, 2009. Based
on the closing price of our common stock as reported on the New
York Stock Exchange on February 22, 2010, there is approximately
$245 million of our common stock that may yet be purchased under
this program.
|
|
ITEM 6.
|
SELECTED
FINANCIAL DATA.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(1)
|
|
|
|
|
|
(2)
|
|
|
(3) (4)
|
|
|
(3) (4) (5)
|
|
|
|
(Amounts in thousands, except per share data)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales revenue
|
|
$
|
2,576,081
|
|
|
$
|
2,983,806
|
|
|
$
|
2,413,644
|
|
|
$
|
2,500,431
|
|
|
$
|
2,508,773
|
|
Change in fair value of coal derivatives and trading activities,
net
|
|
|
12,056
|
|
|
|
55,093
|
|
|
|
7,292
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
123,714
|
|
|
|
461,270
|
|
|
|
230,631
|
|
|
|
338,095
|
|
|
|
78,502
|
|
Net income attributable to Arch Coal
|
|
|
42,169
|
|
|
|
354,330
|
|
|
|
174,929
|
|
|
|
260,931
|
|
|
|
38,123
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
(219
|
)
|
|
|
(378
|
)
|
|
|
(15,579
|
)
|
Basic earnings per common share
|
|
|
0.28
|
|
|
|
2.47
|
|
|
|
1.23
|
|
|
|
1.83
|
|
|
|
0.18
|
|
Diluted earnings per common share
|
|
|
0.28
|
|
|
|
2.45
|
|
|
|
1.21
|
|
|
|
1.80
|
|
|
|
0.17
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
4,840,596
|
|
|
$
|
3,978,964
|
|
|
$
|
3,594,599
|
|
|
$
|
3,320,814
|
|
|
$
|
3,051,440
|
|
Working capital
|
|
|
55,055
|
|
|
|
46,631
|
|
|
|
(35,370
|
)
|
|
|
46,471
|
|
|
|
216,376
|
|
Long-term debt, less current maturities
|
|
|
1,540,223
|
|
|
|
1,098,948
|
|
|
|
1,085,579
|
|
|
|
1,122,595
|
|
|
|
971,755
|
|
Other long-term obligations
|
|
|
544,578
|
|
|
|
482,651
|
|
|
|
412,484
|
|
|
|
384,498
|
|
|
|
376,363
|
|
Arch Coal stockholders equity
|
|
|
2,115,106
|
|
|
|
1,728,733
|
|
|
|
1,531,686
|
|
|
|
1,365,594
|
|
|
|
1,184,241
|
|
Common Stock Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends per share
|
|
$
|
0.3600
|
|
|
$
|
0.3400
|
|
|
$
|
0.2700
|
|
|
$
|
0.2200
|
|
|
$
|
0.1600
|
|
Shares outstanding at year-end
|
|
|
162,441
|
|
|
|
142,833
|
|
|
|
143,158
|
|
|
|
142,179
|
|
|
|
142,573
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
$
|
382,980
|
|
|
$
|
679,137
|
|
|
$
|
330,810
|
|
|
$
|
308,102
|
|
|
$
|
254,607
|
|
Depreciation, depletion and amortization, including amortization
of acquired sales contracts, net
|
|
|
321,231
|
|
|
|
292,848
|
|
|
|
242,062
|
|
|
|
208,354
|
|
|
|
212,301
|
|
Capital expenditures
|
|
|
323,150
|
|
|
|
497,347
|
|
|
|
488,363
|
|
|
|
623,187
|
|
|
|
357,142
|
|
Net proceeds from the issuance of long term debt and the sale of
common stock
|
|
|
896,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments made to acquire Jacobs Ranch
|
|
|
(768,819
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend payments
|
|
|
54,969
|
|
|
|
48,847
|
|
|
|
38,945
|
|
|
|
31,815
|
|
|
|
27,639
|
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
126,116
|
|
|
|
139,595
|
|
|
|
135,010
|
|
|
|
134,976
|
|
|
|
140,202
|
|
Tons produced
|
|
|
119,568
|
|
|
|
133,107
|
|
|
|
126,624
|
|
|
|
126,015
|
|
|
|
129,685
|
|
Tons purchased from third parties
|
|
|
7,477
|
|
|
|
6,037
|
|
|
|
8,495
|
|
|
|
10,092
|
|
|
|
11,226
|
|
|
|
|
(1)
|
|
On October 1, 2009, we
purchased the Jacobs Ranch mining complex in the Powder River
Basin from Rio Tinto Energy America for a purchase price of
$768.8 million. To finance the acquisition, the Company
sold 19.55 million shares of its common stock and
$600.0 million in aggregate principal amount of senior
unsecured notes. The net proceeds received from the issuance of
common stock were $326.5 million and the net proceeds
received from the issuance of the 8.75% senior unsecured
notes were $570.3 million.
|
|
(2)
|
|
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.
|
|
(3)
|
|
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
|
47
|
|
|
|
|
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.
|
|
(4)
|
|
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.
|
|
(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.
|
|
|
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. We may also export coal, particularly the metallurgical
coal that is used in the steel industry. Rapid economic
expansion in China, India and other parts of Southeast Asia has
significantly increased the demand for steel and, therefore,
metallurgical coal in recent years.
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 content, 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 Colorado, 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 content. 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 content 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.
We estimate that the U.S. power generation market declined
approximately 4% in 2009 in response to weak domestic and
international economic conditions, as well as an unseasonably
mild summer in most of the U.S. U.S. coal consumption
declined significantly, primarily as a result of weak industrial
demand in geographic regions that traditionally rely more
heavily on coal-fueled electricity generation as well as low
natural gas prices that induced power generation customers to
switch from coal to natural gas. As a result of these market
pressures, coupled with continued geological challenges in
certain regions, cost pressures, regulatory hurdles and limited
access to capital, coal production and capital spending across
the domestic coal industry have been curtailed.
In response to weakened demand caused by challenging domestic
and international economic conditions, we curtailed production
in all operating regions. In the Powder River Basin, we idled a
second dragline and
48
associated equipment in the second quarter of 2009. In the
Western Bituminous region, we reduced production at our West Elk
mine in response to declining demand from power generation and
industrial customers for Western Bituminous coal and elevated
levels of lower-quality, mid-ash coal produced at the mine
resulting from intermittent sandstone intrusions. As a result of
the curtailment, we laid off 61 employees and discontinued
the use of 38 contractors in the second quarter of 2009. In
Central Appalachia, we reduced production by slowing the rate of
advance of equipment, by shortening or eliminating shifts at
several mining complexes, and by idling an underground mine and
certain surface mining equipment at our Cumberland River mining
complex, which included the layoff of 85 employees in the
second quarter of 2009. In addition, we decreased our 2009
capital expenditures from 2008 levels and implemented other
process improvement initiatives and cost containment programs.
Trends on the domestic and international front may benefit
domestic coal markets in 2010 and beyond. We believe that the
continuing strength in metallurgical coal markets that occurred
in the fourth quarter of 2009 will drive growth for the industry
during 2010 both domestically and
internationally and will likely have an effect on
steam coal markets. In the steam coal markets, domestic
electricity generation increased towards the end of 2009, fueled
by a cold winter and an improving economy. In international coal
markets, China became a significant coal importer in 2009 and
Indias coal imports also increased expanding
by more than 25% in a single year. In fact, we estimate that by
2012, China, India and Brazils net coal imports could grow
as much as 250 million short tons of coal, which would
represent 25% of total seaborne supply. We believe these factors
will result in a positive movement in market pricing in the
second half of 2010.
Items Affecting
Comparability of Reported Results
The comparability of our operating results for the years ended
December 31, 2009, 2008 and 2007 is affected by the
following significant items:
Equity and Debt Offerings During the third
quarter of 2009, we sold 19.55 million shares of our common
stock at a price of $17.50 per share and issued
$600.0 million in aggregate principal amount,
8.75% senior unsecured notes due 2016 at an initial issue
price of 97.464%. The net proceeds received from the issuance of
common stock were $326.5 million and the net proceeds
received from the issuance of the 8.75% senior unsecured
notes were $570.3 million. See further discussion of these
transactions in Liquidity and Capital Resources. We
used the net proceeds from these transactions primarily to
finance the purchase of the Jacobs Ranch mining complex, as
discussed below.
Purchase of Jacobs Ranch mining operations On
October 1, 2009, we consummated the purchase of the Jacobs
Ranch mining operations for a purchase price of
$768.8 million. The acquired operations included
approximately 345 million tons of coal reserves located
adjacent to our Black Thunder mining complex. We expect to
achieve significant operating efficiencies by combining the two
operations. Roughly one half of our estimated synergies
represent operational cost savings, while others relate to
administrative cost reductions as well as enhanced coal-blending
optimization opportunities. We are also using one of the idled
Black Thunder draglines on the new property.
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. 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 could no longer be sourced from our
operations and $4.9 million of employee-related payments.
49
Results
of Operations
Year
Ended December 31, 2009 Compared to Year Ended
December 31, 2008
Summary. Our results during 2009 when compared
to 2008 were influenced primarily by lower sales volumes due to
weak market conditions, a decrease in gains from our coal
trading activities, a reduction in 2008 in our valuation
allowance against deferred tax assets and higher interest
expense.
Revenues. The following table summarizes
information about coal sales during the year ended
December 31, 2009 and compares it with the information for
the year ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
Decrease
|
|
|
|
2009
|
|
|
2008
|
|
|
Amount
|
|
|
%
|
|
|
|
(Amounts in thousands, except per ton data and
percentages)
|
|
|
Coal sales
|
|
$
|
2,576,081
|
|
|
$
|
2,983,806
|
|
|
$
|
(407,725
|
)
|
|
|
(13.7
|
)%
|
Tons sold
|
|
|
126,116
|
|
|
|
139,595
|
|
|
|
(13,479
|
)
|
|
|
(9.7
|
)%
|
Coal sales realization per ton sold
|
|
$
|
20.43
|
|
|
$
|
21.37
|
|
|
$
|
(0.94
|
)
|
|
|
(4.4
|
)%
|
Coal sales decreased in 2009 from 2008 primarily due to lower
sales volumes in all operating regions, driven by weak market
conditions. Average sales prices during 2009 were lower than
during 2008 due primarily to a decrease in metallurgical sales
volumes in our Central Appalachia region, which offset the
impact of generally higher base pricing on steam 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.
Costs, expenses and other. The following table
summarizes costs, expenses and other components of operating
income for the year ended December 31, 2009 and compares it
with the information for the year ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31
|
|
|
in Net Income
|
|
|
|
2009
|
|
|
2008
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars in thousands)
|
|
|
Cost of coal sales
|
|
$
|
2,070,715
|
|
|
$
|
2,183,922
|
|
|
|
113,207
|
|
|
|
5.2
|
%
|
Depreciation, depletion and amortization
|
|
|
301,608
|
|
|
|
293,553
|
|
|
|
(8,055
|
)
|
|
|
(2.7
|
)
|
Amortization of acquired sales contracts, net
|
|
|
19,623
|
|
|
|
(705
|
)
|
|
|
(20,328
|
)
|
|
|
N/A
|
|
Selling, general and administrative expenses
|
|
|
97,787
|
|
|
|
107,121
|
|
|
|
9,334
|
|
|
|
8.7
|
|
Change in fair value of coal derivatives and coal trading
activities, net
|
|
|
(12,056
|
)
|
|
|
(55,093
|
)
|
|
|
(43,037
|
)
|
|
|
(78.1
|
)
|
Costs related to acquisition of Jacobs Ranch
|
|
|
13,726
|
|
|
|
|
|
|
|
(13,726
|
)
|
|
|
(100.0
|
)
|
Other operating income, net
|
|
|
(39,036
|
)
|
|
|
(6,262
|
)
|
|
|
32,774
|
|
|
|
523.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,452,367
|
|
|
$
|
2,522,536
|
|
|
$
|
70,169
|
|
|
|
2.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales. Our cost of coal sales
decreased in 2009 from 2008 due to the lower sales volumes
across all operating segments and a decrease in transportation
costs due to a decrease in barge and export sales. We have
provided more information about our operating segments under the
heading Operating segment results.
Depreciation, depletion and amortization. When
compared with 2008, higher depreciation and amortization costs
in 2009 resulted from the acquisition of the Jacobs Ranch mining
complex on October 1, 2009 and the amortization of
development costs related to the seam at the West Elk mine where
we commenced longwall production in the fourth quarter of 2008,
partially offset by the impact of lower volume levels on
depletion and amortization costs calculated on a
units-of-production
method. We have provided more information about our operating
segments under the heading Operating segment results
and our capital spending in the section entitled Liquidity
and Capital Resources.
50
Amortization of acquired sales contracts,
net. The increase in the amortization of acquired
sales contracts, net is the result of the acquisition of the
Jacobs Ranch mining operation. The majority of the fair value of
sales contracts acquired of $58.4 million will be amortized
by the end of 2011.
Selling, general and administrative
expenses. The decrease in selling, general and
administrative expenses from 2008 to 2009 is due primarily to a
decrease in incentive compensation costs of $8.7 million
and a decrease of $4.6 million in costs associated with our
deferred compensation plan, where amounts recognized are
impacted by changes in the value of our common stock and changes
in the value of the underlying investments. Partially offsetting
the effect of the decrease in compensation-related costs were an
increase in legal and other professional fees of
$2.4 million and the $1.5 million expense in 2009 of
our five-year pledge to a company participating in the research
and development of technologies for capturing carbon dioxide
emissions.
Change in fair value of coal derivatives and coal trading
activities, net. Net gains 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 the significant price
movements in the coal markets during 2008.
Costs related to acquisition of Jacobs
Ranch. Costs we incurred during 2009 related to
the acquisition of the Jacobs Ranch mining complex were expensed
under new accounting rules we adopted in 2009.
Other operating income, net. The net increase
is primarily the result of an increase in net income from
bookouts (the offsetting of coal sales and purchase contracts)
and contract settlements.
Operating segment results. The following table
shows results by operating segment for the year ended
December 31, 2009 and compares it with the information for
the year ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
Increase (Decrease)
|
|
|
|
2009
|
|
|
2008
|
|
|
Amount
|
|
|
%
|
|
|
|
(Amounts in thousands, except
|
|
|
|
per ton data and percentages)
|
|
|
Powder River Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
96,083
|
|
|
|
102,557
|
|
|
|
(6,474
|
)
|
|
|
(6.3
|
)%
|
Coal sales realization per ton
sold(1)
|
|
$
|
12.43
|
|
|
$
|
11.30
|
|
|
$
|
1.13
|
|
|
|
10.0
|
%
|
Operating margin per ton
sold(2)
|
|
$
|
0.79
|
|
|
$
|
1.02
|
|
|
$
|
(0.23
|
)
|
|
|
(22.5
|
)%
|
Western Bituminous
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
16,747
|
|
|
|
20,606
|
|
|
|
(3,859
|
)
|
|
|
(18.7
|
)%
|
Coal sales realization per ton
sold(1)
|
|
$
|
29.11
|
|
|
$
|
27.46
|
|
|
$
|
1.65
|
|
|
|
6.0
|
%
|
Operating margin per ton
sold(2)
|
|
$
|
1.55
|
|
|
$
|
5.69
|
|
|
$
|
(4.14
|
)
|
|
|
(72.8
|
)%
|
Central Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
13,286
|
|
|
|
16,432
|
|
|
|
(3,146
|
)
|
|
|
(19.1
|
)%
|
Coal sales realization per ton
sold(1)
|
|
$
|
59.58
|
|
|
$
|
66.72
|
|
|
$
|
(7.14
|
)
|
|
|
(10.7
|
)%
|
Operating margin per ton
sold(2)
|
|
$
|
6.22
|
|
|
$
|
17.53
|
|
|
$
|
(11.31
|
)
|
|
|
(64.5
|
)%
|
|
|
|
(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,
2009, transportation costs per ton were $0.11 for the Powder
River Basin, $3.18 for the Western Bituminous region and $2.89
for Central Appalachia. 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.
|
|
(2)
|
|
Operating margin per ton is
calculated as coal sales revenues less cost of coal sales and
depreciation, depletion and amortization, including amortization
of acquired sales contracts, divided by tons sold.
|
Powder River Basin The decrease in sales
volume in the Powder River Basin in 2009 when compared with 2008
is due to a decline in demand stemming from weak market
conditions. At the Black Thunder mining
51
complex, in response to these conditions, we reduced production
and idled one dragline in the fourth quarter of 2008 and another
dragline in May 2009, along with the related support equipment.
This reduction was partially offset by the impact of the
acquisition of the Jacobs Ranch mining operations on
October 1, 2009. Increases in sales prices during 2009,
when compared with 2008, primarily reflect higher pricing from
contracts committed during 2008, when market conditions were
more favorable, partially offset by the effect of lower pricing
on market-index priced tons and the effect of lower sulfur
dioxide allowance pricing. On a per-ton basis, operating margins
in 2009 decreased compared to 2008 due to an increase in per-ton
costs. The increase in annual per-ton costs, despite our cost
containment efforts, resulted primarily from the effect of
spreading fixed costs over lower volume levels; however, our
per-ton operating costs improved in the fourth quarter of 2009,
as a result of synergies achieved from the acquisition of the
Jacobs Ranch mining operation.
Western Bituminous In the Western Bituminous
region, we sold fewer tons in 2009 than in 2008 due to the weak
market conditions as well as quality issues at the West Elk
mining complex. In the first half of 2009, we encountered
sandstone intrusions at the West Elk mining complex that
resulted in a higher ash content in the coal produced, and
declining coal demand had an impact on our efforts to market
this coal. As a result of the weak market demand for this coal,
we reduced our production levels at the mine. To address any
ongoing quality issues, we are building a preparation plant at
the mine for an estimated cost of $25 million to
$30 million. We expect the construction of the prep plant
to be completed in the second half of 2010. The detrimental
impact on our per-ton realizations of selling coal with a higher
ash content offset the beneficial impact of the roll-off of
lower-priced legacy contracts in 2008. Lower per-ton operating
margins during 2009 were the result of the West Elk quality
issues and the lower production levels, however, per-ton costs
decreased in the fourth quarter as the longwall advanced into
more favorable geology, as expected, improving our margins.
Central Appalachia The decrease in sales
volumes in 2009, when compared with 2008, is due to the weaker
market demand in 2009. In response to the weakened demand, we
reduced our production in Central Appalachia by slowing the rate
of advance of equipment, by shortening or eliminating shifts at
several mining complexes, and by idling an underground mine and
certain surface mining equipment at our Cumberland River mining
complex in the second quarter of 2009. Economic conditions have
also adversely impacted demand and pricing for metallurgical
coal, and lower per-ton realizations in 2009 compared to 2008
resulted from a decrease in our metallurgical coal sales volumes
and pricing. We sold 2.1 million tons into metallurgical
markets in 2009 compared to 4.4 million tons in 2008.
Because metallurgical coal generally commands a higher price
than steam coal, the decrease had a detrimental impact on our
average per-ton realizations. In addition to the lower per-ton
realizations in 2009, our operating margins were also impacted
by an increase in operating costs per ton in 2009 from 2008, due
primarily to the lower production levels and the effect of
spreading fixed costs over fewer tons.
Net interest expense. The following table
summarizes our net interest expense for the year ended
December 31, 2009 and compares it with the information for
the year ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease
|
|
|
|
Year Ended December 31
|
|
|
in Net Income
|
|
|
|
2009
|
|
|
2008
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars in thousands)
|
|
|
Interest expense
|
|
$
|
(105,932
|
)
|
|
$
|
(76,139
|
)
|
|
$
|
(29,793
|
)
|
|
|
(39.1
|
)%
|
Interest income
|
|
|
7,622
|
|
|
|
11,854
|
|
|
|
(4,232
|
)
|
|
|
(35.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(98,310
|
)
|
|
$
|
(64,285
|
)
|
|
$
|
(34,025
|
)
|
|
|
(52.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The increase in interest expense in 2009 compared to 2008 is
primarily due to the issuance of the 8.75% senior notes in
July, 2009 and a decrease in capitalized interest costs.
Interest costs capitalized were $0.8 million during 2009,
compared with $11.7 million during 2008. For more
information on our borrowing facilities and ongoing capital
improvement and development projects, see the section entitled
Liquidity and Capital Resources.
During 2009 and 2008, we recorded interest income of
$6.1 million and $10.3 million, respectively, related
to a black lung excise tax refund recorded in the fourth quarter
of 2008.
52
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, 2009 and compares it
with information for the year ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
|
|
|
Year Ended December 31
|
|
in Net Income
|
|
|
2009
|
|
2008
|
|
$
|
|
%
|
|
|
(Dollars in thousands)
|
|
Provision for (benefit from) income taxes
|
|
$
|
(16,775
|
)
|
|
$
|
41,774
|
|
|
$
|
58,549
|
|
|
|
140.2
|
%
|
In 2009, our income taxes were impacted by decreased
profitability. The income tax provision in 2008 included a
$58.0 million reduction in our valuation allowance against
net operating loss and alternative minimum tax credit
carryforwards that reduced our income tax provision.
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.
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.
Costs, expenses and other. The following table
summarizes costs, expenses, and other components of operating
income 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
|
|
|
293,553
|
|
|
|
243,695
|
|
|
|
(49,858
|
)
|
|
|
(20.5
|
)
|
Amortization of acquired sales contracts, net
|
|
|
(705
|
)
|
|
|
(1,633
|
)
|
|
|
(928
|
)
|
|
|
(56.8
|
)
|
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
|
|
|
(6,262
|
)
|
|
|
(24,488
|
)
|
|
|
(18,226
|
)
|
|
|
(74.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,522,536
|
|
|
$
|
2,183,013
|
|
|
$
|
(339,523
|
)
|
|
|
(15.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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-
53
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.
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 and our capital spending in the section entitled
Liquidity and Capital Resources.
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
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
|
|
|
102,557
|
|
|
|
99,145
|
|
|
|
3,412
|
|
|
|
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
|
|
|
16,432
|
|
|
|
16,503
|
|
|
|
(71
|
)
|
|
|
(0.4
|
)%
|
Coal sales realization per ton
sold(1)
|
|
$
|
66.72
|
|
|
$
|
47.87
|
|
|
$
|
18.85
|
|
|
|
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, including amortization
of acquired sales contracts, divided by tons sold.
|
54
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.
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 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 the
section entitled Liquidity and Capital Resources.
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.
55
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.
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. We had available borrowing
capacity of $740 million under our lines of credit at
December 31, 2009. We also had $61 million of cash and
cash equivalents on hand at December 31, 2009. Management
will continue to closely monitor our 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 are coal sales 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 or business 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 facility, 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.
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. 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 and weakening coal markets,
we decreased our 2009 capital spending plans and established
other process improvement initiatives and cost containment
programs in order to reduce costs. In fiscal 2009, capital
expenditures were $323 million, which included reserve
acquisitions of more than $145 million, compared to capital
expenditures of $497 million in 2008.
56
On July 31, 2009, we sold 17 million shares of our
common stock at a public offering price of $17.50 per share
pursuant to an automatically effective shelf registration
statement on
Form S-3
and prospectus previously filed and issued $600 million in
aggregate principal amount of 8.75% senior unsecured notes
due 2016 at an initial issue price of 97.464% of face amount in
accordance with Rule 144A and Regulation S under the
Securities Act of 1933, as amended. On August 6, 2009, we
issued an additional 2.55 million shares of our common
stock under the same terms and conditions to cover
underwriters over-allotments. Total net proceeds from
these transactions were $896.8 million. We used the net
proceeds from these transactions primarily to finance the
purchase of the Jacobs Ranch mining complex.
Interest is payable on the 8.75% senior notes on February 1
and August 1 of each year, commencing February 1, 2010. At
any time on or after August 1, 2013, we may redeem some or
all of the notes. The redemption price, reflected as a
percentage of the principal amount, is: 104.375% for notes
redeemed between August 1, 2013 and July 31, 2014;
102.188% for notes redeemed between August 1, 2014 and
July 31, 2015; and 100% for notes redeemed on or after
August 1, 2015.
The notes are guaranteed by most of our subsidiaries, except for
Arch Western and its subsidiaries and Arch Receivable Company,
LLC. If the Company fails to meet an interest coverage ratio
test as defined in the indenture, the ability of the Company and
its subsidiaries to incur additional debt; pay dividends and
make distributions or repurchase stock; make investments; create
liens; issue and sell capital stock of subsidiaries; sell
assets; enter into restrictions affecting the ability of
restricted subsidiaries to make distributions, loans or advances
to the Company; engage in transactions with affiliates; enter
into sale and leasebacks; and merge or consolidate or transfer
and sell assets would be limited.
We entered into a registration rights agreement (the
Registration Rights Agreement) in connection with
the senior notes. Pursuant to the Registration Rights agreement,
we must make reasonable best efforts to cause and file a
registration statement to become effective with the SEC by
July 31, 2010 and complete the exchange of the
8.75% senior notes by September 14, 2010. Should those
events not occur within the specified time frame, the interest
rate would be increased by one-quarter of one percent per annum
for the first 90 days following such period. Such interest
rate would increase by an additional one-quarter of one percent
per annum thereafter up to a maximum aggregate increase of one
percent per annum. Once any of the required events occur, the
interest rate will revert to the rate specified in the indenture.
On August 27, 2009, we entered into an amendment to our
secured revolving credit facility. The amendment extended the
maturity of the credit facility from June 23, 2011 to
March 31, 2013 and increased our borrowing capacity from
$800.0 million to $860.0 million until June 23,
2011, when it will then decrease to $762.5 million. New
banks may join the credit facility after June 23, 2011,
subject to an aggregate maximum borrowing amount of
$800.0 million. The amendment also increased the required
maximum leverage ratio. We had borrowings outstanding under the
revolving credit facility of $120.0 million at
December 31, 2009 and $205.0 million at
December 31, 2008. 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,
2009 was 3.49%. 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 and its subsidiaries.
Financial covenants contained in our revolving credit facility,
as amended, 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 in the facility) 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 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. We were
in compliance with all financial covenants at December 31,
2009.
We are party to a $175.0 million accounts receivable
securitization program whereby eligible trade receivables are
sold, without recourse, to a multi-seller, asset-backed
commercial paper conduit. The credit
57
facility supporting the borrowings under the program is subject
to renewal annually and expires March 31, 2010. 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.
We had borrowings outstanding under the program of
$84.0 million at December 31, 2009 and
$68.6 million outstanding at December 31, 2008. The
weighted average interest rate of borrowings outstanding at
December 31, 2009 was 1.06%. We also had letters of credit
outstanding under the securitization program of $64.5 million as
of December 31, 2009. 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. 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. 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 $49.5 million at
December 31, 2009 and $65.7 million at
December 31, 2008. 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 line of credit that is subject to renewal
annually and expires April 30, 2010. 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 credit facilities 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. The
redemption price of the notes, reflected as a percentage of the
principal amount, is: 102.250% for notes redeemed prior to
July 1, 2010; 101.125% for notes redeemed between
July 1, 2010 and June 30, 2011 and 100% for notes
redeemed on or after July 1, 2011.
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, 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 related 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
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Dollars in thousands)
|
|
|
Cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
382,980
|
|
|
$
|
679,137
|
|
|
$
|
330,810
|
|
Investing activities
|
|
|
(1,130,382
|
)
|
|
|
(527,545
|
)
|
|
|
(424,995
|
)
|
Financing activities
|
|
|
737,891
|
|
|
|
(86,023
|
)
|
|
|
96,742
|
|
58
Cash provided by operating activities decreased in 2009 compared
to 2008, primarily as a result of a decrease in our
profitability in 2009 when compared with 2008s record
profitability, due to weak coal markets as discussed in
Results of Operations. Cash provided by operating
activities was $348.3 million more in 2008 compared to
2007, primarily as a result of our record profitability during
2008.
We used $602.8 million more cash in investing activities in
2009 compared to the amount used in 2008, primarily due to the
acquisition of the Jacobs Ranch mining operations for
$768.8 million, partially offset by a $174.2 million
reduction in capital expenditures. During 2009, in addition to
the last payment of $122.0 million on the Little Thunder
federal coal lease, we spent approximately $19.0 million on
additional longwall equipment at the West Elk mining complex in
Colorado and approximately $38.0 million on a new shovel
and haul trucks at the Black Thunder mine in Wyoming. During
2008, in addition to a payment of $122.0 million on the
Little Thunder lease, we spent approximately $86.5 million
on the construction of the loadout facility at our Black Thunder
mine in Wyoming and approximately $132.1 million for the
transition to the new reserve area at our West Elk mining
complex. We completed the work on the loadout facility and
transitioned to the new seam at West Elk in the fourth quarter
of 2008.
In 2007, in addition to a payment on the Little Thunder coal
lease, 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. 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 of deposits 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 provided by financing activities was $737.9 million
during 2009 compared to cash used in financing activities of
$86.0 million during 2008, as a result of the sale of
common stock and issuance of debt that we discussed previously.
As a result of these transactions, we were able to reduce
outstanding borrowings under our revolving credit facility. We
paid financing costs of $29.7 million in conjunction with
the issuance of the 8.75% senior notes, and the amendments
to our credit facilities discussed previously. In 2007, we
borrowed $120.0 million more, on a net basis, under our
commercial paper program and lines of credit than we did in
2008. We also paid dividends of $55.0 million in 2009,
compared with $48.8 million in 2008 and $38.9 million
in 2007. In 2008, we repurchased 1.5 million shares of
common stock under our share repurchase program at an average
price of $35.62 per share.
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
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Ratio of earnings to combined fixed charges and preference
dividends(1)
|
|
|
1.26x
|
|
|
|
4.91
|
x
|
|
|
2.37
|
x
|
|
|
3.86
|
x
|
|
|
N/A
|
|
|
|
|
(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.
|
59
Contractual
Obligations
The following is a summary of our significant contractual
obligations as of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
2010
|
|
|
2011-2012
|
|
|
2013-2014
|
|
|
After 2015
|
|
|
Total
|
|
|
|
(Dollars in thousands)
|
|
|
Long-term debt, including related interest
|
|
$
|
384,866
|
|
|
$
|
233,250
|
|
|
$
|
1,087,063
|
|
|
$
|
683,125
|
|
|
$
|
2,388,304
|
|
Operating leases
|
|
|
33,435
|
|
|
|
58,941
|
|
|
|
44,853
|
|
|
|
30,277
|
|
|
|
167,506
|
|
Coal lease rights
|
|
|
55,266
|
|
|
|
93,530
|
|
|
|
49,468
|
|
|
|
31,951
|
|
|
|
230,215
|
|
Coal purchase obligations
|
|
|
110,833
|
|
|
|
117,317
|
|
|
|
141,574
|
|
|
|
226,882
|
|
|
|
596,606
|
|
Unconditional purchase obligations
|
|
|
92,339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
92,339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations
|
|
$
|
676,739
|
|
|
$
|
503,038
|
|
|
$
|
1,322,958
|
|
|
$
|
972,235
|
|
|
$
|
3,474,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our maturities of debt in 2010 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, 2009 for the remaining term of outstanding
borrowings.
Coal lease rights represent non-cancelable royalty lease
agreements, as well as lease bonus payments due.
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
$310.4 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, including the 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 for more information
about these assumptions. In order to achieve a desired funded
status, we expect to make contributions of $16.6 million to
our pension plans in 2010. 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
60
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, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Workers
|
|
|
|
|
|
|
|
|
|
Reclamation
|
|
|
Lease
|
|
|
Compensation
|
|
|
|
|
|
|
|
|
|
Obligations
|
|
|
Obligations
|
|
|
Obligations
|
|
|
Other
|
|
|
Total
|
|
|
|
(Dollars in thousands)
|
|
|
Self bonding
|
|
$
|
351,909
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
351,909
|
|
Surety bonds
|
|
|
297,335
|
|
|
|
63,814
|
|
|
|
12,700
|
|
|
|
12,412
|
|
|
|
386,261
|
|
Letters of credit
|
|
|
|
|
|
|
|
|
|
|
51,463
|
|
|
|
13,027
|
|
|
|
64,490
|
|
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, 2009, we had $91.6 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, 2009, the cost of purchasing
13.0 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 $423.4 million,
and the cost of purchasing 2.6 million tons of coal to
supply the assigned and guaranteed contracts over their duration
would exceed the sales price under the contracts by
approximately $52.8 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 $2.6 million of lease
payments. We do not believe that it is probable that we would
have to purchase replacement coal or fulfill our obligations
under the lease guarantees. 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 $41.8 million at December 31, 2009. 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
61
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
The Company generally utilizes derivative instruments to manage
exposures to commodity prices. Additionally, the Company may
hold certain coal derivative instruments for trading purposes.
Derivative financial instruments are recognized in the balance
sheet at fair value. Certain coal contracts may meet the
definition of a derivative instrument, but because they provide
for the physical purchase or sale of coal in quantities expected
to be used or sold by the Company over a reasonable period in
the normal course of business, they are not recognized on the
balance sheet.
Certain derivative instruments are designated as the hedge
instrument in a hedging relationship. In a fair value hedge, we
hedge the risk of changes in the fair value of a firm
commitment, typically a fixed-price coal sales contract. Changes
in both the hedged firm commitment and the fair value of a
derivative used as a hedge instrument in a fair value hedge are
recorded in earnings. In a cash flow hedge, we hedge the risk of
changes in future cash flows related to a forecasted purchase or
sale. Changes in the fair value of the derivative instrument
used as a hedge instrument in a cash flow hedge are recorded in
other comprehensive income. Amounts in other comprehensive
income are reclassified to earnings when the hedged transaction
affects earnings and are classified in a manner consistent with
the transaction being hedged.
Any ineffective portion of a hedge is recognized immediately in
earnings. Ineffectiveness was insignificant for the years ended
December 31, 2009 and 2008.
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 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 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. In 2009, we added
$75.1 million to our liability for asset retirement
obligations as a result of the acquisition of the Jacobs Ranch
mining complex.
Accretion expense is recognized on the obligation through the
expected settlement date. Accretion expense was
$23.4 million in 2009 and $19.6 million in 2008. 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
62
current experience. Adjustments to the liability resulting from
changes in estimates were a decrease in the liability of
$43.7 million in 2009 and an increase in the liability of
$18.9 million in 2008. The 2009 decrease resulted from the
impact of the Jacobs Ranch acquisition on the mining sequence in
the existing pit configuration. 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,
2009, our balance sheet reflected asset retirement obligation
liabilities of $310.4 million, including amounts classified
as a current liability. As of December 31, 2009, we
estimate the aggregate undiscounted cost of final mine closures
to be approximately $722.2 million.
Goodwill
Goodwill represents the excess of the purchase price over the
fair value assigned to the net tangible and identifiable
intangible assets acquired in a business combination. Goodwill
is not amortized but is tested for impairment annually as of the
beginning of the fourth quarter, or when circumstances indicate
a possible impairment may exist. Impairment testing is performed
at a reporting unit level, which is our Black Thunder mining
complex. An impairment loss generally would be recognized when
the carrying amount of the reporting unit exceeds the fair value
of the reporting unit, with the fair value of the reporting unit
determined using a discounted cash flow (DCF) analysis. A number
of significant assumptions and estimates are involved in the
application of the DCF analysis to forecast operating cash
flows, including the discount rate, the internal rate of return,
and projections of selling prices and costs to produce.
Management considers historical experience and all available
information at the time the fair values of its reporting units
are estimated.
Stock-Based
Compensation
The compensation cost of all stock-based awards is determined
based on the grant-date fair value of the award, and is
recognized in income over the requisite service period
(typically the vesting period of the award). The remaining
unrecognized compensation cost of grants that were not vested at
January 1, 2006, was determined based on the same estimate
of the grant-date fair value and the same recognition method
used previously, and is also reflected in income over the
remaining service period after that date. The grant-date fair
value of option awards is determined using a Black-Scholes
option pricing model. For awards paid out in a combination of
cash and stock, the cash portion of the plan is accounted for as
a liability, based on the estimated payout under the awards. The
stock portion is recorded utilizing the grant-date fair value of
the award, based on a lattice model valuation. Compensation cost
for an award with performance conditions is accrued if it is
probable that the conditions will be met.
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
$18.8 million in 2009 and $2.6 million in 2008 to the
plans. The actuarially-determined funded status of the defined
benefit plans is reflected 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.
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The expected long-term rate of return on plan assets is an
assumption reflecting the average rate of earnings expected on
the funds invested or to be invested to provide for the benefits
included in the projected benefit obligation. We establish the
expected long-term rate of return at the beginning of each
fiscal year based upon historical returns and projected returns
on the underlying mix of invested assets. The pension
plans investment targets are 65% equity, 30% fixed income
securities and 5% cash.
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63
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Investments are rebalanced on a periodic basis approximate these
targeted guidelines. The long-term rate of return assumption
used to determine pension expense was 8.5% for 2009 and 2008.
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
2009 would have been an increase in expense of approximately
$1.0 million.
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The discount rate represents our estimate of the interest rate
at which pension benefits could be effectively settled. Assumed
discount rates are used in the measurement of the projected,
accumulated and vested benefit obligations and the service and
interest cost components of the net periodic pension cost. In
estimating that rate, rates of return on high-quality
fixed-income debt instruments are required. We utilize a bond
portfolio model that includes bonds that are rated
AA or higher with maturities that match the expected
benefit payments under the plan. The discount rate used to
determine pension expense was 5.97% for 2009 and 6.85% for 2008.
The impact of lowering the discount rate 0.5% for 2009 would
have been an increase in expense of approximately
$2.2 million.
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The differences generated from changes in assumed discount rates
and returns on plan assets are amortized into earnings over a
five-year period, which represents the average amount of time
before participants vest in their benefits.
For the measurement of our 2009 year-end pension obligation
and pension expense for 2010, we used a discount rate of 5.97%.
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.
During 2009, we notified participants of the retiree medical
plan of a plan change increasing the retirees
responsibility for medical costs. 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 our overall defined benefit plans policy and
require 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. The plan
change referenced above resulted in a remeasurement of the
postretirement benefit obligation, which included a decrease in
the discount rate from 6.85% to 5.68%. The remeasurement
resulted in a decrease in the liability of $21.0 million,
with a corresponding increase to other comprehensive income, and
will result in future reductions in costs under the plan.
Had the discount rate been lowered by 0.5% in 2009, we would
have incurred additional expense of $0.7 million.
For the measurement of our year-end other postretirement
obligation for 2009 and postretirement expense for 2010, we used
a discount rate of 5.67%.
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,
64
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.
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ITEM 7A.
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QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
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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 current production levels, we have
expected uncommitted volumes of 5 million to 8 million
tons in 2010, with an additional 13 million tons committed
but not yet priced. In 2011, we have expected uncommitted
volumes of 70 million to 80 million tons, with an
additional 20 million tons committed but not yet priced. In
2012, we have expected uncommitted volumes of 100 million
to 110 million tons, with an additional 20 million
tons committed but not yet priced.
We are exposed to commodity price risk in our coal trading
activities, which represents the potential future 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, 2009. With
respect to our coal trading portfolio at December 31, 2009,
the potential for loss of future earnings resulting from
changing coal prices was insignificant. The timing of the
estimated future realization of the value of the trading
portfolio is 62% in 2010 and 38% in 2011.
We monitor and manage market price risk for our trading
activities with a variety of tools, including Value at Risk
(VaR), position limits, escalating management alerts for mark to
market monitoring and loss limits, scenario analysis,
sensitivity analysis and review of daily changes in market
dynamics. Management believes that presenting high, low, end of
year and average VaR is the best available method to give
investors insight into the level of commodity risk of our
trading positions. Illiquid positions, such as long-dated trades
that are not quoted by brokers or exchanges, are not included in
VaR.
While presenting VaR will provide a similar framework for
discussing risk across companies, VaR estimates from two
independent sources are rarely calculated in the same way.
Without a thorough understanding of how each VaR model was
calculated, it would be difficult to compare two different VaR
calculations from different sources.
VaR is a statistical one-tail confidence interval and down side
risk estimate that relies on recent history to estimate how the
value of the portfolio of positions will change if markets
behave in the same way as they have in the recent past. The
level of confidence is 95%. The time across which these possible
value changes are being estimated is through the end of the next
business day. A closed-form delta-neutral method used throughout
the finance and energy sectors is employed to calculate this
VaR. VaR is back tested to verify usefulness.
On average, portfolio value should not fall more than VaR on 95
out of 100 business days. Conversely, portfolio value declines
of more than VaR should be expected, on average, 5 out of 100
business days. When more value than VaR is lost due to market
price changes, VaR is not representative of how much value
beyond VaR will be lost.
During 2009, VaR ranged from under $0.1 million to
$0.8 million. The linear mean of each daily VaR was
$0.3 million. The final VaR at December 31, 2009 was
$0.1 million. During 2008, VaR ranged from
$0.3 million to $4.2 million. The linear mean of each
daily VaR was $2.1 million. The final VaR at
December 31, 2008 was $0.5 million.
65
We are also exposed to the risk of fluctuations in cash flows
related to our purchase of diesel fuel. The Company purchases
approximately 50 to 60 million gallons of diesel fuel
annually in its operations, including the effect of the
acquisition of the Jacobs Ranch operations. To reduce the
volatility in the price of diesel fuel for its operations, the
Company uses forward physical diesel purchase contracts, as well
as heating oil swaps and purchased call options. At
December 31, 2009, the Company had protected the price of
approximately 55% of its expected purchases for fiscal year
2010, the majority which was accomplished through the use of the
derivative instruments noted above. Since the changes in the
price of heating oil are highly correlated to changes in the
price of the hedged diesel fuel purchases, the heating oil swaps
and purchased call options qualify for cash flow hedge
accounting. Accordingly, changes in the fair value of the
derivatives are recorded through other comprehensive income,
with any ineffectiveness recognized immediately in income. At
December 31, 2009, a $0.25 per gallon decrease in the price
of heating oil would result in an approximate $8.5 million
increase in our expense in 2010 resulting from heating oil
derivatives, which would be offset by a decrease in the cost of
our physical diesel purchases.
We are exposed to market risk associated with interest rates due
to our existing level of indebtedness. At December 31,
2009, $1.6 billion of our outstanding debt had fixed
interest rates, primarily our 8.75% Senior Notes and our
6.75% Senior Notes. At December 31, 2009,
$253.5 million of our 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 $2.5 million, based on
borrowing levels at December 31, 2009.
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ITEM 8.
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FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA.
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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.
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ITEM 9.
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CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
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None.
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ITEM 9A.
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CONTROLS
AND PROCEDURES.
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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, 2009. 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, 2009 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.
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ITEM 9B.
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OTHER
INFORMATION.
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None.
PART III
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ITEM 10.
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DIRECTORS,
EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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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
66
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 2010 annual meeting.
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ITEM 11.
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EXECUTIVE
COMPENSATION.
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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, 2009, Outstanding
Equity Awards at December 31, 2009, Option
Exercises and Stock Vested for the Year Ended December 31,
2009, Pension Benefits, Nonqualified
Deferred Compensation, Potential Payments Upon
Termination of Employment or
Change-in-Control
and Director Compensation for the Year Ended
December 31, 2009 appearing in the section entitled
Executive and Director Compensation in our proxy
statement to be distributed to stockholders in connection with
the 2010 annual meeting.
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ITEM 12.
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SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
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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 2010 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, 2009, the weighted
average exercise price of options, and the number of shares of
common stock remaining available for future issuance at
December 31, 2009, excluding shares to be issued upon
exercise of outstanding options. No warrants or rights had been
issued under the plan as of December 31, 2009.
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Number of
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Securities Remaining
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Number of
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Available for
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Securities to
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Future Issuance
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be Issued
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Weighted-Average Exercise
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Under Equity
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Upon Exercise
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Price of
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Compensation Plans
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of Outstanding
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Outstanding Options,
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(Excluding Securities
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Options, Warrants
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Warrants
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to be Issued
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Plan Category
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and Rights
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and Rights
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Upon Exercise)
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Equity compensation plans approved by security holders
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3,988,835
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$
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25.17
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2,905,938
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Equity compensation plans not approved by security holders
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Total
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3,988,835
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$
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25.17
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2,905,938
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ITEM 13.
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CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE.
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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 2010 annual meeting.
67
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ITEM 14.
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PRINCIPAL
ACCOUNTING FEES AND SERVICES.
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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 2010 annual
meeting.
PART IV
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ITEM 15.
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EXHIBITS
AND FINANCIAL STATEMENT SCHEDULES.
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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.
68
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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F-5
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F-6
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F-7
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F-8
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F-9
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F-52
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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, 2009 and
2008, and the related consolidated statements of income,
stockholders equity, and cash flows for each of the three
years in the period ended December 31, 2009. 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, 2009
and 2008, and the consolidated results of its operations and
cash flows for each of the three years in the period ended
December 31, 2009, 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, 2009, based on criteria established in
Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated March 1, 2010, expressed
an unqualified opinion thereon.
St. Louis, Missouri
March 1, 2010
F-2
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders Arch Coal, Inc.
We have audited Arch Coal, Inc.s (the Companys)
internal control over financial reporting as of
December 31, 2009, 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, 2009, 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 of Arch Coal, Inc. as of
December 31, 2009 and 2008, and the related consolidated
statements of income, stockholders equity, and cash flows
for each of the three years in the period ended
December 31, 2009, of Arch Coal, Inc., and our report dated
March 1, 2010, expressed an unqualified opinion thereon.
St. Louis, Missouri
March 1, 2010
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, 2009.
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
|
|
John T. Drexler
|
Chairman and Chief
|
|
Senior Vice President and Chief
|
Executive Officer
|
|
Financial Officer
|
F-4
CONSOLIDATED
STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per share data)
|
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
|
|
$
|
2,576,081
|
|
|
$
|
2,983,806
|
|
|
$
|
2,413,644
|
|
COSTS, EXPENSES AND OTHER
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales
|
|
|
2,070,715
|
|
|
|
2,183,922
|
|
|
|
1,888,285
|
|
Depreciation, depletion and amortization
|
|
|
301,608
|
|
|
|
293,553
|
|
|
|
243,695
|
|
Amortization of acquired sales contracts, net
|
|
|
19,623
|
|
|
|
(705
|
)
|
|
|
(1,633
|
)
|
Selling, general and administrative expenses
|
|
|
97,787
|
|
|
|
107,121
|
|
|
|
84,446
|
|
Change in fair value of coal derivatives and coal trading
activities, net
|
|
|
(12,056
|
)
|
|
|
(55,093
|
)
|
|
|
(7,292
|
)
|
Costs related to acquisition of Jacobs Ranch
|
|
|
13,726
|
|
|
|
|
|
|
|
|
|
Other operating income, net
|
|
|
(39,036
|
)
|
|
|
(6,262
|
)
|
|
|
(24,488
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,452,367
|
|
|
|
2,522,536
|
|
|
|
2,183,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
123,714
|
|
|
|
461,270
|
|
|
|
230,631
|
|
Interest expense, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(105,932
|
)
|
|
|
(76,139
|
)
|
|
|
(74,865
|
)
|
Interest income
|
|
|
7,622
|
|
|
|
11,854
|
|
|
|
2,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(98,310
|
)
|
|
|
(64,285
|
)
|
|
|
(72,265
|
)
|
Other non-operating expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses resulting from early debt extinguishment and
termination of hedge accounting for interest rate swaps
|
|
|
|
|
|
|
|
|
|
|
(1,919
|
)
|
Other non-operating expense
|
|
|
|
|
|
|
|
|
|
|
(354
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,273
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
25,404
|
|
|
|
396,985
|
|
|
|
156,093
|
|
Provision for (benefit from) income taxes
|
|
|
(16,775
|
)
|
|
|
41,774
|
|
|
|
(19,850
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
42,179
|
|
|
|
355,211
|
|
|
|
175,943
|
|
Less: Net income attributable to noncontrolling interest
|
|
|
(10
|
)
|
|
|
(881
|
)
|
|
|
(1,014
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Arch Coal, Inc.
|
|
$
|
42,169
|
|
|
$
|
354,330
|
|
|
$
|
174,929
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER COMMON SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per common share
|
|
$
|
0.28
|
|
|
$
|
2.47
|
|
|
$
|
1.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per common share
|
|
$
|
0.28
|
|
|
$
|
2.45
|
|
|
$
|
1.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
|
150,963
|
|
|
|
143,604
|
|
|
|
142,518
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average shares outstanding
|
|
|
151,272
|
|
|
|
144,416
|
|
|
|
144,019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared per common share
|
|
$
|
0.36
|
|
|
$
|
0.34
|
|
|
$
|
0.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-5
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
61,138
|
|
|
$
|
70,649
|
|
Trade accounts receivable
|
|
|
190,738
|
|
|
|
215,053
|
|
Other receivables
|
|
|
40,632
|
|
|
|
43,419
|
|
Inventories
|
|
|
240,776
|
|
|
|
191,568
|
|
Prepaid royalties
|
|
|
21,085
|
|
|
|
43,780
|
|
Deferred income taxes
|
|
|
|
|
|
|
52,918
|
|
Coal derivative assets
|
|
|
18,807
|
|
|
|
43,173
|
|
Other
|
|
|
113,606
|
|
|
|
45,818
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
686,782
|
|
|
|
706,378
|
|
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
Coal lands and mineral rights
|
|
|
2,417,151
|
|
|
|
1,818,657
|
|
Plant and equipment
|
|
|
2,261,929
|
|
|
|
2,031,561
|
|
Deferred mine development
|
|
|
832,976
|
|
|
|
762,746
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,512,056
|
|
|
|
4,612,964
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(2,145,870
|
)
|
|
|
(1,909,881
|
)
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
3,366,186
|
|
|
|
2,703,083
|
|
Other assets:
|
|
|
|
|
|
|
|
|
Prepaid royalties
|
|
|
86,622
|
|
|
|
66,918
|
|
Goodwill
|
|
|
113,701
|
|
|
|
46,832
|
|
Deferred income taxes
|
|
|
354,869
|
|
|
|
294,682
|
|
Equity investments
|
|
|
87,268
|
|
|
|
87,761
|
|
Other
|
|
|
145,168
|
|
|
|
73,310
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
787,628
|
|
|
|
569,503
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
4,840,596
|
|
|
$
|
3,978,964
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
128,402
|
|
|
$
|
186,322
|
|
Coal derivative liabilities
|
|
|
2,244
|
|
|
|
10,757
|
|
Deferred income taxes
|
|
|
5,901
|
|
|
|
|
|
Accrued expenses and other current liabilities
|
|
|
227,716
|
|
|
|
249,203
|
|
Current maturities of debt and short-term borrowings
|
|
|
267,464
|
|
|
|
213,465
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
631,727
|
|
|
|
659,747
|
|
Long-term debt
|
|
|
1,540,223
|
|
|
|
1,098,948
|
|
Asset retirement obligations
|
|
|
305,094
|
|
|
|
255,369
|
|
Accrued pension benefits
|
|
|
68,266
|
|
|
|
73,486
|
|
Accrued postretirement benefits other than pension
|
|
|
43,865
|
|
|
|
58,163
|
|
Accrued workers compensation
|
|
|
29,110
|
|
|
|
30,107
|
|
Other noncurrent liabilities
|
|
|
98,243
|
|
|
|
65,526
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
2,716,528
|
|
|
|
2,241,346
|
|
Redeemable noncontrolling interest
|
|
|
8,962
|
|
|
|
8,885
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value, authorized
260,000 shares, issued 163,953 and 144,345 shares at
December 31, 2009 and 2008, respectively
|
|
|
1,643
|
|
|
|
1,447
|
|
Paid-in capital
|
|
|
1,721,230
|
|
|
|
1,381,496
|
|
Treasury stock, 1,512 shares at December 31, 2009 and
2008, at cost
|
|
|
(53,848
|
)
|
|
|
(53,848
|
)
|
Retained earnings
|
|
|
465,934
|
|
|
|
478,734
|
|
Accumulated other comprehensive loss
|
|
|
(19,853
|
)
|
|
|
(79,096
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
2,115,106
|
|
|
|
1,728,733
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
4,840,596
|
|
|
$
|
3,978,964
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-6
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS EQUITY
Three Years Ended December 31,
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
Common
|
|
|
Paid-In
|
|
|
Retained
|
|
|
Stock at
|
|
|
Comprehensive
|
|
|
|
|
|
|
|
|
|
Stock
|
|
|
Stock
|
|
|
Capital
|
|
|
Earnings
|
|
|
Cost
|
|
|
Loss
|
|
|
Total
|
|
|
|
|
|
|
(In thousands, except per share data)
|
|
|
|
|
|
BALANCE AT JANUARY 1, 2007
|
|
$
|
2
|
|
|
$
|
1,426
|
|
|
$
|
1,345,188
|
|
|
$
|
38,147
|
|
|
$
|
|
|
|
$
|
(19,169
|
)
|
|
$
|
1,365,594
|
|
|
|
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Arch Coal, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174,929
|
|
|
|
|
|
|
|
17,537
|
|
|
|
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 attributable to Arch Coal, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
354,330
|
|
|
|
|
|
|
|
(77,464
|
)
|
|
|
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
|
|
|
|
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Arch Coal, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,169
|
|
|
|
|
|
|
|
|
|
|
|
42,169
|
|
|
|
|
|
Pension, postretirement and other post-employment benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,176
|
|
|
|
12,176
|
|
|
|
|
|
Net amount reclassified to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
718
|
|
|
|
718
|
|
|
|
|
|
Unrealized losses on available-for- sale securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(86
|
)
|
|
|
(86
|
)
|
|
|
|
|
Unrealized losses on derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,436
|
|
|
|
2,436
|
|
|
|
|
|
Net amount reclassified to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43,999
|
|
|
|
43,999
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,169
|
|
|
|
|
|
|
|
59,243
|
|
|
|
101,412
|
|
|
|
|
|
Dividends on common shares ($0.36 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(54,969
|
)
|
|
|
|
|
|
|
|
|
|
|
(54,969
|
)
|
|
|
|
|
Issuance of 19,550 common shares
|
|
|
|
|
|
|
196
|
|
|
|
326,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
326,452
|
|
|
|
|
|
Issuance of 45 shares of common stock under the stock
incentive plan restricted stock and restricted stock
units
|
|
|
|
|
|
|
0
|
|
|
|
0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0
|
|
|
|
|
|
Issuance of 13 shares of common stock under the stock
incentive plan stock options including income tax
benefits
|
|
|
|
|
|
|
0
|
|
|
|
84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84
|
|
|
|
|
|
Employee stock-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
13,394
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,394
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2009
|
|
$
|
|
|
|
$
|
1,643
|
|
|
$
|
1,721,230
|
|
|
$
|
465,934
|
|
|
$
|
(53,848
|
)
|
|
$
|
(19,853
|
)
|
|
$
|
2,115,106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated
financial statements.
F-7
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
42,179
|
|
|
$
|
355,211
|
|
|
$
|
175,943
|
|
Adjustments to reconcile net income to cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
301,608
|
|
|
|
293,553
|
|
|
|
243,695
|
|
Amortization of acquired sales contracts, net
|
|
|
19,623
|
|
|
|
(705
|
)
|
|
|
(1,633
|
)
|
Prepaid royalties expensed
|
|
|
29,746
|
|
|
|
36,227
|
|
|
|
11,962
|
|
Net (gain) loss on dispositions of property, plant and equipment
|
|
|
310
|
|
|
|
(243
|
)
|
|
|
(17,769
|
)
|
Employee stock-based compensation
|
|
|
13,394
|
|
|
|
12,618
|
|
|
|
5,777
|
|
Other non-operating expense
|
|
|
|
|
|
|
|
|
|
|
2,273
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
47,794
|
|
|
|
(9,871
|
)
|
|
|
10,254
|
|
Inventories
|
|
|
(28,518
|
)
|
|
|
(13,783
|
)
|
|
|
(55,471
|
)
|
Coal derivative assets and liabilities
|
|
|
32,266
|
|
|
|
(41,183
|
)
|
|
|
(8,532
|
)
|
Accounts payable, accrued expenses and other current liabilities
|
|
|
(44,764
|
)
|
|
|
21,823
|
|
|
|
(59,634
|
)
|
Deferred income taxes
|
|
|
(34,668
|
)
|
|
|
15,222
|
|
|
|
(31,825
|
)
|
Accrued postretirement benefits other than pension
|
|
|
4,142
|
|
|
|
4,202
|
|
|
|
3,733
|
|
Asset retirement obligations
|
|
|
18,741
|
|
|
|
16,437
|
|
|
|
21,609
|
|
|