SECURITIES
AND EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
(Mark
One)
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þ
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
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For
the fiscal year ended December 31,
2007
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OR
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¨
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
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For
the transition period from
to
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Commission
File No. 1-32423
ALPHA
NATURAL RESOURCES, INC.
(Exact
name of registrant as specified in its charter)
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Delaware
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02-0733940
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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
Alpha Place, P.O. Box 2345, Abingdon, Virginia
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24212
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(Address
of principal executive offices)
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(Zip
Code)
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Registrant's
telephone number, including area code:
(276) 619-4410
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, $0.01 par value
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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 whether the registrant is a well-known seasoned issuer, as defined
in Rule 405 of the Securities Act. Yes þ No ¨
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 ¨ 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, and (2) has been subject to such
filing requirements for the past 90 days. Yes þ No ¨
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 registrant's 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. þ
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer (as defined in Exchange Act
Rule 12b-2).
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þ Large
accelerated filer
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¨ Accelerated
filer
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¨ Non-accelerated
filer
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Indicate
by check mark whether the registrant is a shell company (as defined in Exchange
Act Rule 12b-2). Yes ¨ No þ
The
aggregate market value of the Common Stock held by non-affiliates of the
registrant on June 29, 2007, was approximately $1,362,111,527 based on the
last sales price reported that date on the New York Stock Exchange of $20.79 per
share. In determining this figure, the registrant has assumed that all of its
directors and executive officers are affiliates. Such assumptions should not be
deemed to be conclusive for any other purpose.
Common
Stock, $0.01 par value, outstanding as of February
22, 2008 – 66,077,847 shares.
DOCUMENTS
INCORPORATED BY REFERENCE
Part III
incorporates certain information by reference from the registrant's definitive
proxy statement for the 2008 annual meeting of stockholders (the “Proxy
Statement”), which will be filed no later than 120 days after the close of
the registrant's fiscal year ended December 31, 2007.
CAUTIONARY
NOTE REGARDING FORWARD LOOKING STATEMENTS
This
report includes statements of our expectations, intentions, plans and beliefs
that constitute “forward-looking statements” within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934 and are intended to come within the safe harbor
protection provided by those sections. These statements, which involve risks and
uncertainties, relate to analyses and other information that are based on
forecasts of future results and estimates of amounts not yet determinable and
may also relate to our future prospects, developments and business strategies.
We have used the words “anticipate,” “believe,” “could,” “estimate,” “expect,”
“intend,” “may,” “plan,” “predict,” “project,” “should” and similar terms and
phrases, including references to assumptions, in this report to identify
forward-looking statements. These forward-looking statements are made based on
expectations and beliefs concerning future events affecting us and are subject
to uncertainties and factors relating to our operations and business
environment, all of which are difficult to predict and many of which are beyond
our control, that could cause our actual results to differ materially from those
matters expressed in or implied by these forward-looking
statements.
The
following factors are among those that may cause actual results to differ
materially from our forward-looking statements:
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worldwide
market demand for coal, electricity and
steel;
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future
economic or capital market
conditions;
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inherent
risks of coal mining beyond our
control;
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environmental
laws, including those directly affecting our coal mining and production,
and those affecting our customers' coal
usage;
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regulatory
and court decisions;
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competition
in coal markets;
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the
geological characteristics of Central and Northern Appalachian coal
reserves;
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·
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availability
of skilled employees and other employee workforce
factors;
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weather
conditions or catastrophic weather-related
damage;
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·
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our
production capabilities;
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·
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the
consummation of financing, acquisition or disposition transactions and the
effect thereof on our business;
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·
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our
ability to successfully integrate the operations we have acquired and/or
developed with our existing operations, as well as our ability to
successfully integrate operations we may acquire and/or develop in the
future;
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·
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our
plans and objectives for future operations and expansion or
consolidation;
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our
relationships with, and other conditions affecting, our
customers;
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·
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timing
of changes in customer coal
inventories;
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·
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changes
in, renewal of and acquiring new long-term coal supply
arrangements;
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·
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railroad,
barge, truck and other transportation performance and
costs;
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availability
of mining and processing equipment and
parts;
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·
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our
assumptions concerning economically recoverable coal reserve
estimates;
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·
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our
ability to mine properties due to defects in title on leasehold
interest;
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future
legislation and changes in regulations, governmental policies or
taxes;
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·
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changes
in postretirement benefit
obligations;
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·
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our
liquidity, results of operations and financial
condition;
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·
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decline
in coal prices;
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·
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forward
sales and purchase contracts not accounted for as a hedge and are being
marked to market;
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indemnification
of certain obligations not being
met;
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continued
funding of the road construction
business;
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disruption
in coal supplies;
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the
ability to comply with new safety and health
regulations;
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unfavorable
government intervention in, or nationalization of, foreign
investments;
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our
third-party suppliers may not deliver coal we purchase;
and
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·
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other
factors, including the other factors discussed in Item 1A, “Risk
Factors” of this report.
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When
considering these forward-looking statements, you should keep in mind the
cautionary statements in this report and the documents incorporated by
reference. We do not undertake any responsibility to release publicly any
revisions to these forward-looking statements to take into account events or
circumstances that occur after the date of this report. Additionally, we do not
undertake any responsibility to update you on the occurrence of any
unanticipated events which may cause actual results to differ from those
expressed or implied by the forward-looking statements contained in this
report.
2007
ANNUAL REPORT ON FORM 10-K
PART I
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Item 1.
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Overview
We are a
leading Appalachian coal supplier. We produce, process and sell steam and
metallurgical coal from eight regional business units, which, as of December 31,
2007, are supported by 32 active underground mines, 26 active surface mines and
11 preparation plants located throughout Virginia, West Virginia, Kentucky, and
Pennsylvania, as well as a road construction business in West Virginia and
Virginia that recovers coal. We are also actively involved in the purchase and
resale of coal mined by others, the majority of which we blend with coal
produced from our mines, allowing us to realize a higher overall margin for the
blended product than we would be able to achieve selling these coals
separately.
Steam
coal, which is primarily purchased by large utilities and industrial customers
as fuel for electricity generation, accounted for approximately 62% of our 2007
coal sales volume. The majority of our steam coal sales volume in 2007 consisted
of high Btu (above 12,500 Btu content per pound), low sulfur (sulfur content of
1.5% or less) coal, which typically sells at a premium to lower-Btu,
higher-sulfur steam coal. Metallurgical coal, which is used primarily to make
coke, a key component in the steel making process, accounted for approximately
38% of our 2007 coal sales volume. Metallurgical coal generally sells at a
premium over steam coal because of its higher quality and its value in the
steelmaking process as the raw material for coke. We believe that the use of the
coal we sell will grow as demand for power and steel increases.
During
2007, we sold a total of 28.5 million tons of steam and metallurgical coal
and generated coal revenues of $1,639.2 million, EBITDA of
$233.8 million and net income of $27.7 million. We define and
reconcile EBITDA and explain its importance in Note 3 under “Selected
Financial Data.” Our coal sales during 2007 consisted of 24.4 million tons of
produced and processed coal, including 1.7 million tons purchased from
third parties and processed at our processing plants or loading facilities prior
to resale, and 4.1 million tons of purchased coal that we resold without
processing. Approximately 64% of the purchased coal in 2007 was blended with
coal produced from our mines prior to resale. Approximately 38% of our sales
revenue in 2007 was derived from sales made outside the United States, primarily
in Canada, Egypt, Belgium, Italy, Hungary, and Brazil.
As of
December 31, 2007, we owned or leased 617.5 million tons of proven and probable
coal reserves. Of our total proven and probable reserves, approximately 82% are
low sulfur reserves, with approximately 57% having sulfur content below 1%.
Approximately 89% of our total proven and probable reserves have a high Btu
content which creates more energy per unit when burned compared to coals with
lower Btu content. We believe that our total proven and probable reserves will
support current production levels for more than 20 years.
As
discussed in Note 24 to our financial statements, we have one reportable
segment -- Coal Operations -- which consists of our coal extracting,
processing and marketing operations, as well as our purchased coal sales
function and certain other coal-related activities, including our recovery of
coal incidental to our road construction operations. Our equipment and part
sales and equipment repairs operations, terminal services, coal analysis
services, leasing of mineral rights, and the non-coal recovery portion of
our road construction operations described below under “-- Other
Operations” are not included in our Coal Operations segment.
History
In 2002,
ANR Holdings, LLC (“ANR Holdings”) was formed by First Reserve Fund IX,
L.P. and ANR Fund IX Holdings, L.P. (referred to as the “First Reserve
Stockholders” or collectively with their affiliates, “First Reserve”) and our
management to serve as the top-tier holding company of the Alpha Natural
Resources organization. On February 11, 2005, Alpha Natural Resources, Inc.
succeeded to the business of ANR Holdings in a series of transactions that we
refer to collectively as the “Internal Restructuring,” and on February 18,
2005, Alpha Natural Resources, Inc. completed an initial public offering of its
common stock. When we use the terms “Alpha,” “we,” “our,” “the Company” and
similar terms in this report, we mean (1) prior to our Internal
Restructuring, ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. (a
subsidiary of First Reserve Fund IX, L.P. prior to our Internal
Restructuring) and subsidiaries on a combined basis and (2) after our
Internal Restructuring, Alpha Natural Resources, Inc. and its consolidated
subsidiaries. Alpha Natural Resources, Inc. was formed under the laws of the
State of Delaware on November 29, 2004.
On
December 13, 2002, the First Reserve Stockholders, who then owned 100% of
the membership interests of ANR Holdings, acquired the majority of the Virginia
coal operations of Pittston Coal Company (our “Predecessor”), a subsidiary of
the Brink's Company (formerly known as The Pittston Company), through
wholly-owned subsidiaries of ANR Holdings for $62.9 million.
On
January 31, 2003, wholly owned subsidiaries of ANR Holdings acquired
Coastal Coal Company, LLC for $67.8 million, and on March 11, 2003,
ANR Holdings and its subsidiaries acquired the U.S. coal production and
marketing operations of American Metals and Coal International, Inc. (“AMCI”)
for $121.3 million. Of the consideration for the U.S. AMCI
acquisition, $69.0 million was provided in the form of an approximate 44%
membership interest in ANR Holdings issued to the owners of AMCI, which together
with the issuances of an approximate 1% membership interest to Madison Capital
Funding, LLC and Alpha Coal Management reduced the First Reserve Stockholders
membership interest in ANR Holdings to approximately 55%.
On
November 17, 2003, we acquired the assets of Mears Enterprises, Inc.
(“Mears”) for $38.0 million.
On
April 1, 2004, we acquired substantially all of the assets of Moravian Run
Reclamation Co., Inc. for five thousand dollars in cash and the assumption by us
of certain liabilities, including four active surface mines and two additional
surface mines under development, operating in close proximity to and serving
many of the same customers as our AMFIRE business unit located in
Pennsylvania.
On
May 10, 2004, we acquired a coal preparation plant and railroad loading
facility located in Portage, Pennsylvania and related equipment and coal
inventory from Cooney Bros. Coal Company for $2.5 million in cash and an
adjacent coal refuse disposal site from a Cooney family trust for
$0.3 million in cash.
On
October 13, 2004, our AMFIRE business unit entered into a coal mining lease
with Pristine Resources, Inc., a subsidiary of International Steel Group Inc.,
for the right to deep mine a substantial area of the Upper Freeport Seam in
Pennsylvania.
On
February 11, 2005, we succeeded to the business and became the indirect
parent entity of ANR Holdings in connection with the Internal Restructuring and,
on February 18, 2005, we completed an initial public offering of our common
stock (the “IPO”).
On
April 14, 2005, we sold the assets of our Colorado mining subsidiary,
National King Coal LLC, and related trucking subsidiary, Gallup Transportation
and Transloading Company, LLC (collectively, “NKC”) to an unrelated third party
for cash in the amount of $4.4 million, plus an amount in cash equal to the
fair market value of NKC's coal inventory, and the assumption by the buyer of
certain liabilities of NKC.
On
October 26, 2005, we acquired the Nicewonder Coal Group's coal reserves and
operations in southern West Virginia and southwestern Virginia (“Nicewonder
Acquisition”). The Nicewonder Acquisition, consisted of the purchase of the
outstanding capital stock of White Flame Energy, Inc., Twin Star Mining, Inc.
and Nicewonder Contracting, Inc., the equity interests of Powers Shop, LLC and
Buchanan Energy, LLC and substantially all of the assets of Mate Creek Energy of
W. Va., Inc. and Virginia Energy Company, and the business of Premium Energy,
Inc. by merger. We paid an aggregate purchase price of $328.2 million in
the Nicewonder Acquisition. The operations we acquired from the Nicewonder
Coal Group constitute our eighth business unit, Callaway Natural
Resources.
On May 1,
2006, we acquired certain coal mining operations in eastern Kentucky from
Progress Fuels Corp, a subsidiary of Progress Energy (“Progress Acquisition”)
for $28.8 million, including adjustments for working capital. The Progress
Acquisition consisted of the purchase of the outstanding capital stock of
Diamond May Coal Co. and Progress Land Corp. and the assets of Kentucky May Coal
Co., Inc. The operations acquired are adjacent to our Enterprise business unit
and have been integrated with Enterprise.
On
December 28, 2006, our subsidiary, Palladian Lime, LLC (“Palladian”) acquired a
94% ownership interest in Gallatin Materials LLC (“Gallatin”), a start-up lime
manufacturing business in Verona, Kentucky. The consideration for
acquisition consisted of (i) cash capital contributions of $10.3 million, (ii) a
committed subordinated debt facility of up to $8.8 million provided to Gallatin
by Palladian, of which $3.8 million was funded as of December 31, 2007 and (iii)
a letter of credit procured for Gallatin’s benefit under our current senior
credit facility in the amount of $2.6 million to cover project cost
overruns. The first of two planned rotary pre-heater lime kilns is expected
to be in production in the first quarter 2008 and will produce lime to be sold
primarily to coal-burning utilities as a scrubbing agent for removing sulfur
dioxide from flue gas, helping them to meet increasingly stringent air quality
standards under the federal Clean Air Act. The lime will also be sold to steel
producers for use as flux in electric arc and basic oxygen furnaces. The
minority owners were granted restricted member interests in Gallatin, which vest
based on performance criteria approximately three years from the closing date
and which, if earned in their entirety, would reduce our ownership to 77.5%.
Approximately $22.3 million was spent on capital expenditures by Gallatin during
2007. As of December 31, 2007, Gallatin borrowed $18.5 million for
project financing.
On June
29, 2007, we paid $43.9 million for the acquisition of certain coal mining
assets in western West Virginia from Arch Coal, Inc. known as Mingo
Logan. The Mingo Logan purchase consists of coal reserves, one active
deep mine and a load-out and processing plant, which is managed by our Callaway
business unit.
Mining
Methods
We
produce coal using two mining methods: underground room and pillar mining using
continuous mining equipment, and surface mining.
Underground Mining.
Underground mines in the United States are typically operated using one of two
different methods: room and pillar mining or longwall mining. In 2007,
approximately 56% of our coal production volume from mines operated by our
subsidiaries' employees and contractors came from underground mining operations
using the room and pillar method with continuous mining equipment. In room and
pillar mining, rooms are cut into the coal bed leaving a series of pillars, or
columns of coal, to help support the mine roof and control the flow of air.
Continuous mining equipment is used to cut the coal from the mining face.
Generally, openings are driven 20 feet wide, and the pillars are generally
rectangular in shape, measuring 35-50 feet wide by 35-80 feet long. As
mining advances, a grid-like pattern of entries and pillars is formed. Shuttle
cars or continuous haulage units are used to transport coal from the continuous
miner to the conveyor belt for transport to the surface. When mining advances to
the end of a panel, retreat mining may begin. In retreat mining, coal is mined
from the pillars that were created in advancing the panel, allowing the roof to
cave. When retreat mining is completed to the mouth of the panel, the mined
panel is abandoned. The room and pillar method is often used to mine smaller
coal blocks or thin or non-contiguous seams, and resource recovery ranges from
30% to 70%, with higher recovery rates applicable where retreat mining is
combined with room and pillar mining.
The other
underground mining method commonly used in the United States is the longwall
mining method, which we do not currently use at any of our mines. In longwall
mining, a rotating drum is trammed mechanically across the face of coal, and a
hydraulic system supports the roof of the mine while it advances through the
coal. Chain conveyors then move the loosened coal to an underground mine
conveyor system for delivery to the surface. Our Central Appalachian reserves
often include non-contiguous seams of coal that can be extracted at a lower cost
using continuous mining as opposed to the more capital intensive longwall
method.
Surface Mining. Surface
mining is used when coal is found close to the surface. In 2007, approximately
44% of our coal production volume from mines operated by our subsidiaries'
employees and contractors came from surface mines. This method involves the
removal of overburden (earth and rock covering the coal) with heavy earthmoving
equipment and explosives, loading out the coal, replacing the overburden and
topsoil after the coal has been excavated and reestablishing vegetation and
plant life and making other improvements that have local community and
environmental benefit. Overburden is typically removed at our mines using large,
hydraulic operated excavators, rubber-tired diesel loaders and dozers. Resource
recovery for surface mining is typically 90% or more.
Coal
Characteristics
In
general, coal of all geological compositions is characterized by end use as
either steam coal or metallurgical coal. Heat value, sulfur and ash content, and
volatility, in the case of metallurgical coal, are the most important variables
in the profitable marketing and transportation of coal. These characteristics
determine the best end use of a particular type of coal. We mine, process,
market and transport bituminous coal, characteristics of which are described
below.
Heat Value. The heat value of
coal is commonly measured in British thermal units, or “Btus.” A Btu is the
amount of heat needed to raise the temperature of one pound of water by one
degree Fahrenheit. Alpha exclusively mines bituminous coal, a “soft” black coal
with a heat content that ranges from 9,500 to 15,000 Btus per pound. This coal
is located primarily in Appalachia, Arizona, the Midwest, Colorado and Utah and
is the type most commonly used for electric power generation in the United
States. Bituminous coal is also used for metallurgical and industrial steam
purposes. Of our estimated 617.5 million tons of proven and probable
reserves, approximately 89% has a heat content above 12,500 Btus per
pound.
Sulfur Content. Sulfur
content can vary from seam to seam and sometimes within each seam. When coal is
burned, it produces sulfur dioxide, the amount of which varies depending on the
chemical composition and the concentration of sulfur in the coal. Low sulfur
coals are coals which have a sulfur content of 1.5% or less. Approximately 82%
of our proven and probable reserves are low sulfur coal.
High
sulfur coal can be burned in plants equipped with sulfur-reduction technology,
such as scrubbers, which can reduce sulfur dioxide emissions by 50% to 90%.
Plants without scrubbers can burn high sulfur coal by blending it with lower
sulfur coal or by purchasing emission allowances on the open market, allowing
the user to emit a predetermined amount of sulfur dioxide. Some older coal-fired
plants have been retrofitted with scrubbers, although most have shifted to lower
sulfur coals as their principal strategy for complying with Phase II of the
Clean Air Act's Acid Rain regulations. We expect that any new coal-fired
generation plant built in the United States will use clean coal-burning
technology.
Ash & Moisture
Content. Ash is the inorganic residue remaining after the combustion of
coal. As with sulfur content, ash content varies from seam to seam. Ash content
is an important characteristic of coal because electric generating plants must
handle and dispose of ash following combustion. The absence of ash is also
important to the process by which metallurgical coal is transformed into coke
for use in steel production. Moisture content of coal varies by the type of
coal, the region where it is mined and the location of 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, as sold, can range from approximately 5% to 30% of the coal's
weight.
Coking Characteristics. The
coking characteristics of metallurgical coal are typically measured by the
coal's fluidity, ARNU and volatility. Fluidity and ARNU tests measure the
expansion and contraction of coal when it is heated under laboratory conditions
to determine the strength of coke that could be produced from a given coal.
Typically, higher numbers on these tests indicate higher coke strength.
Volatility refers to the loss in mass, less moisture, when coal is heated in the
absence of air. The volatility of metallurgical coal determines the percentage
of feed coal that actually becomes coke, known as coke yield. Coal with a lower
volatility produces a higher coke yield and is more highly valued than coal with
a higher volatility, all other metallurgical characteristics being
equal.
Mining
Operations
We
currently have eight regional business units, operating in Virginia, West
Virginia, Pennsylvania, and Kentucky. As of December 31, 2007, these
business units include 11 preparation plants, each of which receive, blend,
process and ship coal that is produced from one or more of our 58 active mines
(some of which are operated by third parties under contracts with us), using two
mining methods, underground room and pillar and surface mining. Our underground
mines generally consist of one or more single or dual continuous miner sections
which are made up of the continuous miner, shuttle cars or continuous haulage,
roof bolters, and various ancillary equipment. Our surface mines are a
combination of mountain top removal, contour, highwall miner, and auger
operations using truck/loader - excavator equipment fleets along with large
production tractors. Most of our preparation plants are modern heavy media
plants that generally have both coarse and fine coal cleaning circuits. We
employ preventive maintenance and rebuild programs to ensure that our equipment
is modern and well-maintained. During 2007, most of our preparation plants also
processed coal that we purchased from third party producers before reselling it
to our customers. Within each regional business unit, mines have been developed
at strategic locations in close proximity to our preparation plants and rail
shipping facilities. Coal is transported from our regional business units to
customers by means of railroads, trucks, barge lines, and ocean-going vessels
from terminal facilities.
The
following table provides location and summary information regarding our eight
regional business units and the preparation plants and active mines associated
with these business units as of December 31, 2007:
Regional
Business Units
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Number
and Type of
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||||||||||||||||
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Mines
as of
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||||||||||||||||
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December
31, 2007
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||||||||||||||||
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Preparation
plant(s) as of
|
Under-
|
2007
Production
of Saleable Tons
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Regional
Business Unit
|
Location
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December
31, 2007
|
ground
|
Surface
|
Total
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Railroad
|
(in
000's)(1)
|
|||||||||
|
Paramont
|
Virginia
|
Toms
Creek
|
6
|
4
|
10
|
NS
|
5,112
|
|||||||||
|
Dickenson-Russell
|
Virginia
|
McClure
River and Moss#3
|
4
|
1
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5
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CSX,
NS
|
2,143
|
|||||||||
|
Kingwood
|
West
Virginia
|
Whitetail
|
2
|
--
|
2
|
CSX
|
1,630
|
|||||||||
|
Brooks
Run North
|
West
Virginia
|
Erbacon
|
2
|
1
|
3
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CSX
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2,149
|
|||||||||
|
Brooks
Run South
|
West
Virginia
|
Litwar
and Kepler
|
11
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--
|
11
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NS
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2,841
|
|||||||||
|
AMFIRE
|
Pennsylvania
|
Clymer
and Portage
|
5
|
14
|
19
|
NS
|
3,157
|
|||||||||
|
Enterprise
|
Kentucky
|
Roxana
|
1
|
3
|
4
|
CSX
|
2,768
|
|||||||||
|
Callaway
|
West
Virginia/ Virginia
|
Black
Bear
|
1
|
3
|
4
|
NS
|
4,403
|
|||||||||
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Total
|
32
|
26
|
58
|
24,203
|
||||||||||||
| (1 | ) |
Includes
coal purchased from third-party producers that was processed at our
subsidiaries' preparation plants in
2007.
|
CSX Railroad = CSX
Norfolk Southern Railroad =
NS
The coal production
and processing capacity of our mines and processing plants is influenced by a
number of factors including reserve availability, labor availability, and
environmental permit timing and preparation plant capacity.
The following
provides a brief description of our business units as of December 31,
2007.
Virginia
/ Kentucky Operations
Paramont. Our Paramont
business unit produces coal from six underground mines using continuous miners
and the room and pillar mining method. Three of the underground mines are
operated by independent contractors. The coal from these mining operations is
transported by truck to the Toms Creek preparation plant operated by Paramont,
or the McClure River or Moss #3 preparation plants operated by
Dickenson-Russell. At the preparation plant, the coal is cleaned, blended and
loaded onto rail for shipment to customers. Paramont also operates four
truck/loader surface mines. One of these surface mines is operated by
independent contractors. The coal produced by the surface mines is transported
to one of our preparation plants or raw coal loading docks where it is blended
and loaded onto rail for shipment to customers. During 2007, Paramont purchased
approximately 126,000 tons of coal from third parties that was blended with
Paramont's coal and shipped to our customers. As of December 31, 2007, the
Paramont business unit was operating at a capacity to ship approximately five
and one half million tons per year.
Dickenson-Russell. Our
Dickenson-Russell business unit produces coal from four underground mines using
continuous miners and the room and pillar mining method. The coal is transported
by truck to the McClure River or Moss #3 preparation plants operated by
Dickenson-Russell or the Toms Creek preparation plant operated by Paramont where
it is cleaned, blended and loaded on rail or truck for shipment to customers.
The Dickenson-Russell business unit also operates a fine coal recovery dredge
operation where fine coals that were previously discarded by the coal cleaning
process are recovered, cleaned, and blended with other coals for sale. During
2007, Dickenson-Russell purchased approximately 70,000 tons of coal from third
parties that was blended with Dickenson-Russell's coal and shipped to our
customers. As of December 31, 2007, the Dickenson-Russell business unit was
operating at a capacity to ship approximately two million tons per
year.
Enterprise. Our Enterprise
business unit produces coal from one underground mine, using continuous miners
and the room and pillar mining method. The underground mine is staffed and
operated by Enterprise employees. The coal from this underground mine is
transported by truck to the Roxana coal preparation plant operated by Enterprise
where it is cleaned, blended and loaded onto rail for shipment to customers.
Enterprise also has three truck/loader surface mines, two of which are operated
by independent contractors. The coal produced by the surface mine is transported
to the Roxana preparation plant and Pioneer load-out facility where it is
blended and loaded onto rail for shipment to customers. During 2007, Enterprise
purchased approximately 118,000 tons of coal from third parties that was blended
with Enterprise's coal and shipped to our customers. As of December 31, 2007,
the Enterprise business unit was operating at a capacity to ship approximately
three million tons per year. The Progress Acquisition was included in the
Enterprise operations beginning May 2006.
West
Virginia Operations
Kingwood. Our Kingwood
business unit produces coal from two underground mines using continuous miners
and the room and pillar mining method. One mine is staffed and operated by our
Kingwood employees and one is operated by an independent contractor. The coal is
belted to the Whitetail preparation plant operated by Kingwood where it is
cleaned and loaded onto rail or truck for shipment to customers. During
2007, Kingwood purchased approximately 156,000 tons of coal from third parties
that was blended with Kingwood's coal and shipped to our customers. As of
December 31, 2007, the Kingwood business unit was operating at a capacity to
ship approximately one and one-half million tons per year.
Brooks Run North. Our Brooks Run North
business unit produces coal from two underground mines using continuous miners
and the room and pillar mining method. The Brooks Run North operation is staffed
and operated by Brooks Run North employees. The coal is transported by truck to
the Erbacon preparation plant operated by Brooks Run North where it is cleaned,
blended and loaded onto rail for shipment to customers. The Brooks Run North
business unit has one surface mine operated by Brooks Run North
employees. As of December 31, 2007, the Brooks Run North business
unit was operating at a capacity to ship approximately two million tons per
year.
Brooks Run South. Our Brooks Run South
business unit produces coal from eleven underground mines using continuous
miners and the room and pillar mining method. Three of the underground mines are
operated by our employees, and the others are operated by independent
contractors. The coal is transported by truck or rail to the Litwar and Kepler
preparation plants operated by Brooks Run South or the Moss #3 plant
operated by Dickenson-Russell, where it is cleaned, blended and loaded onto rail
for shipment to customers. During 2007, the Brooks Run South business
unit purchased approximately 942,000 tons of coal from third parties that was
blended with other coals and shipped to our customers. As of December 31, 2007,
the Brooks Run South business unit was operating at a capacity to ship
approximately three and one-quarter million tons per year.
Callaway. Our Callaway business unit
produces coal from three surface mining operations operated by our Callaway
employees and one underground mine operated by our subsidiary Cobra Natural
Resources, LLC (Cobra) using continuous miners and the room and pillar mining
method. Callaway also recovers coal from the road construction
business operated by our subsidiary Nicewonder Contracting, Inc. (NCI).
Coal from the three surface mines and NCI is transported by truck to the Black
Bear preparation plant or the Ben Creek or Mate Creek loadouts operated by Cobra
or the Virginia Energy loadout operated by Callaway where the coal is cleaned,
blended, and loaded onto rail for shipment to customers. Coal from the
underground mine is belted to the Black Bear preparation plant where it is
cleaned and then loaded into railcars at the Ben Creek loadout for shipment to
our customers. Callaway purchased approximately 138,000 tons of coal from third
parties in 2007. As of December 31, 2007, the Callaway business unit
was operating at a capacity to ship approximately five million tons per year,
including coal recovered by NCI as part of its road construction
business.
Pennsylvania
Operations
AMFIRE. Our AMFIRE business
unit produces coal from five underground mines using continuous miners and the
room and pillar mining method. All of the underground mining operations at
AMFIRE are staffed and operated by AMFIRE employees. The underground coal is
delivered directly by truck to the customer, or to the Clymer or Portage coal
preparation plants or raw coal loading docks where it is cleaned, blended and
loaded onto rail or truck for shipment to customers. AMFIRE also operates
fourteen truck/loader surface mines, eight of which are operated by independent
contractors. The surface mined coal is delivered directly by truck to the
customer or transported to the Clymer or Portage coal preparation plants or raw
coal loading docks where it is blended and loaded onto rail or truck for
shipment to customers. During 2007, AMFIRE purchased approximately 75,000 tons
of coal from third parties that was blended with AMFIRE's coal and shipped to
our customers. As of December 31, 2007, the AMFIRE business unit was operating
at a capacity to ship approximately three and one-quarter million tons per
year.
Marketing,
Sales and Customer Contracts
Our
marketing and sales force, which is principally based in Abingdon, Virginia,
included 41 employees as of December 31, 2007, and consists of sales managers,
distribution/traffic managers and administrative personnel. In addition to
selling coal produced in our eight regional business units, we are also actively
involved in the purchase and resale of coal mined by others, the majority of
which we blend with coal produced from our mines. We have coal supply
commitments with a wide range of electric utilities, steel manufacturers,
industrial customers and energy traders and brokers. Our overall sales
philosophy is to focus first on the customer's individual needs and
specifications, as opposed to simply selling our production inventory. By
offering coal of both steam and metallurgical grades to provide specific
qualities of heat content, sulfur and ash, and other characteristics relevant to
our customers, we are able to serve a diverse customer base. This diversity
allows us to adjust to changing market conditions and provides us with the
ability to sustain high sales volumes and sales prices for our coal. Many of our
larger customers are well-established public utilities and steel
manufacturers who have been customers of ours or our Predecessor and
acquired companies for decades.
We sold a
total of 28.5 million tons of coal in 2007, consisting of 24.4 million tons of
produced and processed coal and 4.1 million tons of purchased coal that we
resold without processing. Of our total purchased coal sales of 5.8 million tons
in 2007, approximately 3.7 million tons were blended prior to resale, meaning
the coal was mixed with coal produced from our mines prior to resale, which
generally allows us to realize a higher overall margin for the blended product
than we would be able to achieve selling these coals separately. Approximately
1.7 million tons of our 2007 purchased coal sales were processed by us, meaning
we washed, crushed or blended the coal at one of our preparation plants or
loading facilities prior to resale. We sold a total of 29.1 million tons of coal
in 2006, consisting of 24.7 million tons of produced and processed coal and 4.4
million tons of purchased coal that we resold without processing. Of our total
purchased coal sales of 5.8 million tons in 2006, approximately 3.9 million tons
were blended prior to resale. Approximately 1.4 million tons of our
2006 purchased coal sales were processed by us. We sold a total of 26.7 million
tons of coal in 2005, consisting of 20.6 million tons of produced and processed
coal and 6.1 million tons of purchased coal that we resold without processing.
Of our total purchased coal sales of 7.6 million tons in 2005, approximately 5.0
million tons were blended prior to resale. Approximately 1.5 million tons of our
2005 purchased coal sales were processed by us. The breakdown of tons
sold by market served for 2007, 2006 and 2005 is set forth in the table
below:
|
Steam
Coal Sales (1)
|
Metallurgical
Coal Sales
|
|||||||||
|
Year
|
Tons
|
%
of Total Sales
|
Tons
|
%
of Total Sales
|
||||||
|
(In
millions, except percentages)
|
||||||||||
|
2007
|
17.5
|
62
|
%
|
11.0
|
38
|
%
|
||||
|
2006
|
19.1
|
66
|
%
|
10.0
|
34
|
%
|
||||
|
2005
|
16.7
|
62
|
%
|
10.0
|
38
|
%
|
||||
| (1 | ) |
Steam
coal sales include sales to utility and industrial customers. Sales of
steam coal to industrial customers, who we define as consumers of steam
coal who do not generate electricity for sale to third parties, accounted
for approximately 3%, 4% and 3% of total sales in 2007, 2006 and 2005,
respectively.
|
| (2 | ) |
Our
sales of steam coal during 2007, 2006 and 2005 were made primarily to
large utilities and industrial customers in the Eastern region of the
United States, and our sales of metallurgical coal during those years were
made primarily to steel companies in the Northeastern and Midwestern
regions of the United States and in countries in Europe, Asia and South
America.
|
We sold
coal to over 100 different customers in 2007. Our top ten customers in 2007
accounted for approximately 42% of 2007 revenues and our largest customer during
2007 accounted for approximately 8% of 2007 revenues. The following table
provides information regarding our exports (including to Canada) in 2007, 2006
and 2005 by revenues and tons sold:
|
Year
|
Export
Tons Sold
|
Export
Tons Sold as a Percentage of Total Coal Sales
|
Export
Sale Revenues (1)
|
Export
Sales Revenue as a Percentage of Total Revenues
|
||||||
|
(In
millions, except percentages)
|
||||||||||
|
2007
|
7.8
|
27
|
%
|
$
|
705.4
|
38
|
%
|
|||
|
2006
|
7.2
|
25
|
%
|
$
|
668.8
|
35
|
%
|
|||
|
2005
|
8.4
|
31
|
%
|
$
|
737.1
|
45
|
%
|
|||
| (1 | ) |
Export
sale revenues in 2007, 2006 and 2005 include approximately $1.2 million,
$0.7 million and $0.6 million, respectively, in equipment export sales
from our Maxxim Rebuild business. All other export sale revenues are coal
revenues and freight and handling
revenues.
|
Our
export shipments during 2007, 2006 and 2005 serviced customers in 14, 18 and 16
countries, respectively, across North America, Europe, South America, Asia and
Africa. Canada was our largest export market in 2007, with sales to Canada
accounting for approximately 15% of export revenues and 6% of total revenues.
Canada was our largest export market in 2006 and 2005, with sales to Canada
accounting for approximately 17% and 15% of export revenues, respectively, and
6% and 7% of total revenues, respectively. All of our sales are made
in U.S. dollars, which reduces foreign currency risk. A portion of our sales are
subject to seasonal fluctuation, with sales to certain customers being curtailed
during the winter months due to the freezing of lakes that we use to transport
coal to those customers.
As is
customary in the coal industry, when market conditions are appropriate and
particularly in the steam coal market, we enter into long-term contracts
(exceeding one year in duration) with many of our customers. These arrangements
allow customers to secure a supply for their future needs and provide us with
greater predictability of sales volume and sales prices. A significant majority
of our steam coal sales are shipped under long-term contracts. The majority of
the metallurgical coal sales contracts we entered into during 2005 and 2006 were
long-term contracts. During 2007, approximately 81% and 44% of our steam and
metallurgical coal sales volume, respectively, was delivered pursuant to
long-term contracts and during 2006, approximately 63% and 45% of our steam and
metallurgical coal sales volume, respectively, was delivered pursuant to
long-term contracts.
At
December 31, 2007, 95% of our planned 2008 production was committed and
priced and less than 1% was committed and unpriced, with approximately 1.2
million tons uncommitted. Committed steam coal prices for 2008 average $48.64
per ton and met coal prices average $81.27 per ton. At December 31,
2007, we had commitments to purchase 3.5 million tons of coal during
2008.
The terms
of our contracts result from bidding and negotiations with customers.
Consequently, the terms of these contracts typically vary significantly in many
respects, including price adjustment features, provisions permitting
renegotiation or modification of coal sale prices, coal quality requirements,
quantity parameters, flexibility and adjustment mechanisms, permitted sources of
supply, treatment of environmental constraints, options to extend and force
majeure, suspension, termination and assignment provisions, and provisions
regarding the allocation between the parties of the cost of complying with
future governmental regulations.
Distribution
We employ
transportation specialists who negotiate freight and terminal agreements with
various providers, including railroads, trucks, barge lines, and terminal
facilities. Transportation specialists also coordinate with customers, mining
facilities and transportation providers to establish shipping schedules that
meet the customer's needs. Our produced and processed coal is loaded from our
eleven preparation plants and in certain cases directly from our mines. The coal
we purchase is loaded in some cases directly from mines and preparation plants
operated by third parties or from an export terminal. Virtually all of our coal
is transported from the mine to our preparation plants by truck or rail, and
then from the preparation plant to the customer by means of railroads, trucks,
barge lines and ocean-going vessels from terminal facilities. Rail shipments
constituted approximately 59% of total shipments of coal volume produced and
processed coal from our mines to the preparation plant to the customer in 2007.
The balance was shipped from our preparation plants, loadout facilities or mines
via truck. In 2007, approximately 5% of our coal sales were delivered to our
customers through transport on the Great Lakes, approximately 16% was moved
through the Norfolk Southern export facility at Norfolk, Virginia, approximately
6% was moved through the coal export terminal at Newport News, Virginia operated
by Dominion Terminal Associates, and less than 1% was moved through the export
terminals at Baltimore, Maryland and New Orleans, LA. We own a 32.5% interest in
the coal export terminal at Newport News, Virginia operated by Dominion Terminal
Associates. See “Other Operations.”
Competition
With
respect to our U.S. customers, we compete with numerous coal producers in
the Appalachian region and with a large number of western coal producers in the
markets that we serve. Competition from coal with lower production costs shipped
east from western coal mines has resulted in increased competition for coal
sales in the Appalachian region. We face limited competition from imports for
our domestic customers. As of September 2007, 3% of total U.S. coal
consumption in 2007 was imported. Excess industry capacity, which has occurred
in the past, tends to result in reduced prices for our coal. The most important
factors on which we compete are delivered coal price, coal quality and
characteristics, transportation costs from the mine to the customer and the
reliability of supply. Demand for coal and the prices that we will be able to
obtain for our coal are closely linked to coal consumption patterns of the
domestic electric generation industry, which has accounted for approximately 93%
of 2007 domestic coal consumption as of September 2007. These coal consumption
patterns are influenced by factors beyond our control, including the demand for
electricity, which is significantly dependent upon summer and winter
temperatures in the United States, environmental and other government
regulations, technological developments and the location, availability, quality
and price of competing fuels for power such as natural gas, nuclear, fuel oil
and alternative energy sources such as hydroelectric power. Demand for our low
sulfur coal and the prices that we will be able to obtain for it will also be
affected by the price and availability of high sulfur coal, which can be
marketed in tandem with emissions allowances in order to meet Clean Air Act
requirements.
Demand
for our metallurgical coal and the prices that we will be able to obtain for
metallurgical coal will depend to a large extent on the demand for U.S. and
international steel, which is influenced by factors beyond our control,
including overall economic activity and the availability and relative cost of
substitute materials. In the export metallurgical market, during 2007 and 2006,
we largely competed with producers from Australia, Canada, and other
international producers of metallurgical coal.
Our
business is seasonal, with operating results varying from quarter to quarter. We
generally experience lower sales and hence build coal inventory during the
winter months primarily due to the freezing of lakes that we use to transport
coal to some of our customers.
In
addition to competition for coal sales in the United States and internationally,
we compete with other coal producers, particularly in the Appalachian region,
for the services of experienced coal industry employees at all levels of our
mining operations.
Other
Operations
We have
other operations and activities in addition to our normal coal production,
processing and sales business, including:
Road Construction Business.
NCI operates a road construction business under a contract with the State of
West Virginia Department of Transportation. Pursuant to the contract, NCI is
building approximately 11 miles of rough grade road in West Virginia over the
next two to three years and, in exchange, NCI will be compensated by West
Virginia based on the number of cubic yards of material excavated and/or filled
to create a road bed, as well as for certain other cost components. As the road
is constructed any coal recovered is sold by NCI as part of its coal
operations. The Company also has other minor road construction
projects in conjunction with other surface mining operations.
Maxxim Rebuild. We own Maxxim
Rebuild Co., LLC, a mining equipment company with facilities in Kentucky and
Virginia. This business largely consists of repairing and reselling equipment
and parts used in surface mining and in supporting preparation plant operations.
Maxxim Rebuild had revenues of $29.2 million for 2007, of which
approximately 87% was generated by services provided to our other subsidiaries
and approximately 13% was generated by sales to external customers, including
$1.2 million to export customers.
Dominion Terminal Associates.
Through our subsidiary Alpha Terminal Company, LLC, we hold a 32.5% interest in
Dominion Terminal Associates, a 22 million-ton annual capacity coal export
terminal located in Newport News, Virginia. The terminal, constructed in 1982,
provides the advantages of unloading/transloading equipment with ground storage
capability, providing producers with the ability to custom blend export products
without disrupting mining operations. During 2007, we shipped a total of 1.8
million tons of coal to our customers through the terminal. We make periodic
cash payments in respect of the terminal for operating expenses, which are
partially offset by payments we receive for transportation incentive payments
and for renting our unused storage space in the terminal to third parties. Our
cash payments for expenses for the terminal in 2007 were $4.1 million,
partially offset by payments received in 2007 of $2.7 million. The terminal
is held in a partnership with subsidiaries of three other companies, Dominion
Energy (20%), Arch Coal (17.5%) and Peabody Energy (30%). We and our
other interested partners were pursuing an investment of approximately $35.0 for
the construction of a new import facility at the terminal. During
2007, the previously indicated demand by electric utilities for import coals
shifted, with the result that there is insufficient demand to warrant the
project. Consequently, the project has been deferred.
Gallatin Materials LLC. On December 28,
2006, our subsidiary, Palladian Lime, LLC (“Palladian”) acquired a 94% ownership
interest in Gallatin Materials LLC (“Gallatin”), a start-up lime manufacturing
business in Verona, Kentucky by assuming liabilities in the amount of $3.6
million consisting of a note payable in the amount of $1.8 million and
accounts payable and accrued expenses in the amount of $1.7 million. The
liabilities assumed were allocated to fair value of assets acquired consisting
mainly of intangible assets. In addition, Palladin agreed to and
made (i) cash capital contributions of $10.3 million, of which $3.3 million
was funded as of December 31, 2006, (ii) a committed subordinated debt
facility of up to $8.8 million provided to Gallatin by Palladian, of which $3.8
million was funded as of December 31, 2007 and (iii) a letter of credit procured
for Gallatin’s benefit under our current senior credit facility in the amount of
$2.6 million to cover project cost overruns. The first of two planned rotary
pre-heater lime kilns is expected to be in production in the first quarter 2008
and will produce lime to be sold primarily to coal-burning utilities as a
scrubbing agent for removing sulfur dioxide from flue gas, helping them to meet
increasingly stringent air quality standards under the federal Clean Air Act.
The lime will also be sold to steel producers for use as flux in electric arc
and basic oxygen furnaces. The minority owners were granted restricted member
interests in Gallatin, which vest based on performance criteria approximately
three years from the closing date and which, if earned in their entirety, would
reduce our ownership to 77.5%. Approximately $22.3 million was spent on capital
expenditures by Gallatin during 2007. As of December 31, 2007,
Gallatin borrowed $18.5 million for project financing.
Gallatin will
produce two basic qualities of lime. High calcium lime is used by both the steel
industry as a fluxing agent in both electric arc and basic oxygen furnaces and
the utility industry as a scrubbing agent for flue gas
desulphurization. Gallatin’s medium magnesium lime is only used by
the steel industry as a fluxing agent.
Miscellaneous. We engage in
the sale of certain non-strategic assets such as timber, gas and oil rights as
well as the leasing and sale of non-strategic surface properties and reserves.
We also provide coal and environmental analysis services.
Employee
and Labor Relations
Approximately
96% of our coal production in 2007 came from mines operated by union-free
employees, and as of December 31, 2007, over 94% of 3,640 employees were
union-free. We believe our employee relations are good, and there have been no
material work stoppages at any of our properties in the past ten
years.
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, permitting and licensing
requirements, air quality standards, water pollution, plant and wildlife
protection, the reclamation and restoration of mining properties after mining
has been completed, the discharge of materials into the environment, surface
subsidence from underground mining, and the effects of mining on groundwater
quality and quantities. These requirements have had, and will
continue to have, a significant effect on our production costs and our
competitive position. More stringent future requirements may impose
substantial increases in equipment and operating costs to us and delays,
interruptions, or a termination of operations, the extent of which cannot be
predicted. We intend to respond to any such future regulatory requirements at
the appropriate time by implementing necessary modifications to facilities or
operating procedures. Future requirements, such as those related to greenhouse
gas emissions, may also cause coal to become a less attractive fuel source,
thereby reducing coal's share of the market for fuels used to generate
electricity. Any such requirements may adversely affect our mining operations,
cost structure, revenues, or the ability of our customers to use
coal.
We strive
to conduct our mining operations in compliance with all applicable federal,
state, and local laws and regulations. However, because of extensive and
comprehensive regulatory requirements along with changing interpretations of
these requirements, violations occur from time to time. Since our
inception in 2002, none of the assessed violations or associated monetary
penalties has been material to our operations. Nonetheless, we expect that
future liability under or compliance with environmental, health and safety
requirements could have a material effect on our operations or competitive
position. Under some circumstances, substantial fines and penalties, including
revocation or suspension of mining permits, could be imposed under the laws
described below. Monetary sanctions and, in severe circumstances, criminal
sanctions could be imposed for failure to comply with these laws.
As of
December 31, 2007, we had accrued $91.2 million for reclamation liabilities
and mine closures, including $8.2 million of current
liabilities.
Climate Change. One major
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.
Considerable and increasing government attention in the United States and other
countries is being paid to reducing greenhouse gas emissions, including
emissions from coal-fired power plants. Congress is actively considering
legislation to reduce greenhouse gas emissions in the United States, and there
are a number of state and regional initiatives underway. Efforts to
reduce greenhouse gas emissions could adversely affect the price and demand for
coal.
The
United States has not ratified the Kyoto Protocol to the 1992 Framework
Convention on Global Climate Change (the “Protocol”), which became effective for
many countries in 2005 and establishes a binding set of emission targets for
greenhouse gases. However, the United States is actively participating in
various international initiatives to reduce greenhouse gas emissions, including
negotiations for a new international climate treaty to replace the Protocol.
Under the current schedule, the new treaty would be agreed to in late
2009.
In
addition to possible future U.S. treaty obligations, regulation of
greenhouse gases in the United States could occur pursuant to federal
legislation, regulatory changes under the Clean Air Act, state initiatives, or
otherwise. At the federal level, Congress is actively considering numerous
climate change bills, including bills that would establish nationwide
cap-and-trade programs to reduce greenhouse gas emissions. Most
prominently, in 2007 the Lieberman-Warner America's Climate Security Act passed
the Senate Environment and Public Works Committee," and this bill or similar
legislation is expected to be taken up by the full Senate during
2008.
To date,
the U.S. Environmental Protection Agency (“EPA”) has not regulated carbon
dioxide emissions. In 2007, however, the U.S. Supreme Court ruled in
Massachusetts v. Environmental
Protection Agency that the Clean Air Act gives EPA the authority to
regulate vehicle tailpipe emissions of greenhouse gases and that EPA had not yet
articulated a reasonable basis for not issuing such regulation. A
similar lawsuit, currently pending before the U.S. Court of Appeals for the
District of Columbia Circuit, challenges EPA’s failure in 2006 to regulate
carbon dioxide in its new source performance standards covering power plants and
industrial boilers. These lawsuits could result in the issuance of a
court order requiring the EPA to set emission limitations for carbon dioxide
from stationary sources such as power plants.
State and
regional climate change initiatives may take effect before federal action. Ten
Northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New
Hampshire, New Jersey, New York, Rhode Island, and Vermont) have entered the
Regional Greenhouse Gas Initiative (“RGGI”) Agreement, calling for a ten percent
reduction of carbon dioxide emissions by 2018, with state programs to be
launched by January 1, 2009. Participating states are developing their state
rules pursuant to a model rule issued by RGGI. Another group of Northeastern
states (Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York, and
Vermont), joined by New York City, have brought a court action seeking to
declare carbon dioxide emissions from power plants to be a public
nuisance. A decision is pending before the U.S. Court of Appeals for
the Second Circuit. Climate change developments are also taking place on the
west coast. In September 2006, California adopted greenhouse gas legislation
that prohibits long-term base-load generation from having a greenhouse gas
emissions rate greater than that of a combined cycle natural gas generator and
that allows for long-term deals with generators that sequester carbon emissions.
In January 2007, the California Public Utility Commission adopted regulations
implementing the new legislation and establishing the greenhouse gas emission
standard at 1,100 pounds of carbon dioxide per megawatt-hour. In
February 2007, Arizona, California, New Mexico, Oregon and Washington, later
joined by Montana, Utah, and two Canadian provinces, announced the Western
Regional Climate Action Initiative to develop a regional target to reduce
greenhouse gas emissions and to devise a market-based program to meet the
target.
Implementation
of these or any other climate change standards or initiatives will likely
require additional controls on coal-fired power plants and industrial boilers
and may even cause some users of our coal to switch from coal to a lower carbon
fuel or more generally reduce the demand for coal-fired electricity generation.
This could result in an indeterminate decrease in price and demand for coal
nationally.
Mining Permits and Approvals.
Numerous governmental permits or approvals are required for mining
operations. The permitting process requires us to present data to
federal, state or local authorities pertaining to the effects or impacts that
any of our proposed production, processing of coal, or other activities may have
upon the environment. The authorization, permitting and/or implementation
requirements imposed by the permits or authorizations may be costly, time and
resource consuming, and may delay commencement or continuation of our
operations. Also, past or ongoing violations of federal and state mining laws
could provide a basis to revoke existing permits and/or deny or cause delay in
the issuance of additional permits if an officer, director or a stockholder with
a 10% or greater interest in an affiliated entity has violated federal or state
mining laws or if that person is in a position to control another entity that
has outstanding permit violations.
Typically,
our necessary permit applications are submitted several months, or even years,
before we plan to begin mining a new area. Although some permits or
authorizations may take six months or longer to obtain, in the past we have
generally obtained our mining permits without significant delay. However, as
there have been a growing number of court challenges filed against agency
decisions to issue coal mining permits, we cannot be sure that difficulty in
obtaining timely permits in the future will not occur.
Surface Mining Control and
Reclamation Act. The Surface Mining
Control and Reclamation Act of 1977 (“SMCRA”), which is administered by the
Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes
mining, environmental protection and reclamation standards for all aspects of
surface mining as well as many aspects of deep mining. Mine operators must
obtain SMCRA permits and permit renewals from the OSM, or from the applicable
state agency if the state agency has obtained primacy. States in which we have
active mining operations have achieved primacy.
SMCRA
permit provisions and performance standards include a complex set of
requirements which include, but are not limited to the
following: reclamation performance bonds, coal prospecting; mine plan
development; topsoil removal, storage 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 drainage control; mine drainage and mine discharge control and
treatment; post mining land use development; re-vegetation: compliance with many
other major environmental statutes, including the Clean Air Act; Clean Water
Act; Resource Conservation and Recovery Act (“RCRA”) and Comprehensive
Environmental Response, Compensation and Liability Act (“CERCLA” or
“Superfund”). Also, the Abandoned Mine Land Fund, which was created
by SMCRA, requires a fee on all coal produced. In 2007 and 2006, we recorded
$5.0 million of expenses for this reclamation tax each year.
Surety Bonds. Mine operators
are often required by federal and/or state laws to assure, usually through the
use of surety bonds, payment of certain long-term obligations including, but not
limited to, mine closure or reclamation costs, federal and state workers'
compensation costs, coal leases and other miscellaneous obligations. We have a
committed bonding facility with Travelers Casualty and Surety Company of
America, pursuant to which Travelers has agreed, subject to certain conditions,
to issue surety bonds on our behalf in a maximum amount of $150.0 million.
We also have a committed bonding facility with the Chubb Group of Insurance
Companies, pursuant to which Chubb has agreed, subject to certain conditions, to
issue surety bonds on our behalf in a maximum amount of $50.0 million. In 2007,
we added a third facility with Safeco Insurance Company of America whereas they
have agreed, subject to certain conditions, to issue surety bonds on our behalf
in a maximum amount of $35.0 million. As of December 31, 2007, we have
posted an aggregate of $142.5 million in reclamation bonds and
$10.2 million of other types of bonds under these facilities.
Clean Air Act. The Clean Air
Act and comparable state laws that regulate air emissions affect coal mining
operations both directly and indirectly. Direct impacts on coal mining and
processing operations include Clean Air Act permitting requirements and/or
emission control requirements relating to particulate matter which may include
controlling fugitive dust. The Clean Air Act 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-fired power plants. As many
of these regulatory programs are still under development or are subject to
judicial challenge, it is not always possible to determine their impact on coal
demand nation wide. In addition to the greenhouse gas issues
discussed above, the air emissions programs that may affect our operations,
directly or indirectly, include, but are not limited to, the
following:
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Acid Rain.
Title IV of the Clean Air Act required a two-phase reduction of
sulfur dioxide emissions by electric utilities. Phase II became
effective in 2000 and applies to all coal-fired power plants generating
greater than 25 Megawatts. Generally, the affected electricity generators
have sought to meet these requirements by switching to lower sulfur fuels,
installing pollution control devices, reducing electricity generating
levels or purchasing sulfur dioxide emission allowances. Because the Acid
Rain program is a mature program, we believe that the impact of this
regulation has been factored into the demand for coal nationally.
Accordingly, we do not believe that the Acid Rain program standing alone
will continue to impact the demand for coal
nationally.
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Fine Particulate
Matter. The Clean Air Act requires EPA to set standards, referred
to as National Ambient Air Quality Standards (“NAAQS”), for certain
pollutants. Areas that are not in compliance (referred to as
“non-attainment areas”) with these standards must take steps to reduce
emissions levels. For example, NAAQS currently exist for particulate
matter with an aerodynamic diameter less than or equal to 10 microns, or
PM10, and for fine particulate matter with an aerodynamic diameter less
than or equal to 2.5 microns, or PM2.5. EPA designated all or part of 225
counties in 20 states as well as the District of Columbia as
non-attainment areas with respect to the PM2.5 NAAQS. Individual states
must identify the sources of emissions and develop emission reduction
plans. These plans may be state-specific or regional in scope. Under the
Clean Air Act, individual states have up to twelve years from the date of
designation to secure emissions reductions from sources contributing to
the problem. Meeting the new PM2.5 standard may require reductions of
nitrogen oxide and sulfur dioxide emissions that are separate and distinct
from the reductions that may be required under any other program. Future
regulation and enforcement of the new PM2.5 standard will affect many
power plants, especially coal-fired plants and all plants in
“non-attainment” areas. The combination of these actions may impact demand
for coal nationally, but we are unable to predict the magnitude of the
impact.
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Ozone. EPA has recently
proposed a range of reductions to the existing ozone NAAQS. In 2008, EPA
plans to promulgate a revised ozone NAAQS. If the ozone NAAQS is reduced,
significant additional emissions control expenditures may be required at
coal-fired power plants to meet the revised ozone NAAQS. Nitrogen oxides,
which are a by-product of coal combustion, are classified as an ozone
precursor. Accordingly, we expect that there may be additional emissions
control requirements necessary on new and expanded coal-fired power plants
and industrial boilers in the years ahead. The combination of
these actions may impact demand for coal nationally, but we are unable to
predict the magnitude of the
impact.
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NOx SIP Call. In 1998,
EPA established the NOx SIP Call program to reduce the transport of ozone
on prevailing winds from the Midwest and South to states in the Northeast,
which said they could not meet federal air quality standards because of
migrating pollution. The program was designed to reduce nitrous oxide
emissions by one million tons per year in 22 eastern states and the
District of Columbia, which were required to submit revised State
Implementation Plans (“SIPs”) in 2005. Coal fired power plants installed
and continue to install additional control measures, such as selective
catalytic reduction devices, in order to comply with the NOx SIP Call.
Since affected companies have already invested in the controls necessary
to comply with this rule, we believe that the impact of the NOx SIP Call
has been factored in to the demand for coal
nationally.
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Clean Air Interstate
Rule. In 2005, EPA issued the Clean Air Interstate Rule
(“CAIR”) requiring power plants in 29 eastern states and the District
of Columbia to reduce emission levels of sulfur dioxide and nitrogen
oxide. CAIR requires states to regulate power plants under a cap and trade
program similar to the system now in effect for acid deposition control.
When fully implemented, CAIR is expected to reduce regional sulfur dioxide
emissions by over 70% and nitrogen oxides emissions by over 60% from 2003
levels. CAIR may require many coal-fired electricity generation 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. CAIR may
impact demand for coal nationally, but we are unable to predict the
magnitude of the impact.
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Clean Air Mercury Rule.
In 2005, EPA issued the Clean Air Mercury Rule to to establish mercury
emissions limits from new and existing coal-fired power plants and create
a market-based cap-and-trade program that is expected to reduce nationwide
utility emissions of mercury in two phases. In February 2008, a federal
court of appeals vacated the Clean Air Mercury Rule as insufficiently
stringent. EPA’s response to the court’s decision and other
federal and state limitations on mercury emissions from power plants may
adversely affect the demand for coal. In 2006, also EPA proposed a federal
plan to directly regulate mercury emissions from coal-fired power plants
where certain states have not provided their own plans. The combination of
these actions may impact demand for coal nationally, but we are unable to
predict the magnitude of the
impact.
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Regional Haze. EPA has
initiated a regional haze program designed to protect and to improve
visibility at and around national parks, national wilderness areas and
international parks. Each state affected by this EPA program was required
to submit to EPA by December 17, 2007, a Regional Haze SIP to achieve the
goals of the program. Few states met the December deadline, but most
affected states are planning on submitting their Regional Haze SIP by the
first quarter of 2008. The program may require coal-fired power plants to
install additional control measures designed to limit haze-causing
emissions, such as sulfur dioxide, nitrogen oxides, volatile organic
chemicals and particulate matter. The regional haze program may impact
demand for coal nationally, but we are unable to predict the magnitude of
the impact.
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New Source Review. A
number of pending regulatory changes and court actions will affect the
scope of EPA’s new source review program, which under certain
circumstances requires existing coal-fired 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 known, we are unable to predict the magnitude
of the impact.
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State Initiatives. The
Clean Air Act generally authorizes states to issue air emissions
regulations more stringent than the federal regulations. In
addition to the federal programs, several states have proposed or adopted
legislation or regulations limiting air emissions, such as sulfur dioxide,
nitrogen oxide, and mercury, from coal-fired power plants.
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Clean Water Act. The Clean
Water Act and comparable state laws that regulate waste water discharges and
certain dredge and fill activities waters of the United States (“Jurisdictional
Waters”) may affect coal mining operations both directly and indirectly. The
Clean Water Act requirements that may directly or indirectly affect our
operations include, but are not limited to, the following:
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Wastewater Discharges.
Section 402 of the Clean Water Act establishes in-stream water
quality criteria and treatment standards for wastewater discharge through
the National Pollutant Discharge Elimination System (“NPDES”). Many of our
operations are required to obtain NPDES permits, and regular monitoring
and compliance with reporting requirements and performance standards are
preconditions for the issuance and renewal of NPDES permits. The
imposition of future restrictions on the discharge of certain pollutants
into waters of the United States could affect the permitting process,
increase the costs and difficulty of obtaining and complying with NPDES
permits and could adversely affect our coal production. Any
more stringent discharge limits placed on ash handling facilities or other
operations at coal-fired power plants also could adversely affect the
price and demand for coal.
In
2007, the USEPA filed a lawsuit against a major coal company for alleged
violations of the Clean Water Act that lead to a settlement in which the
company recently agreed to pay a $20 million penalty. As a
result of this lawsuit it is anticipated that the NPDES compliance of all
coal companies will come under greater scrutiny.
The Clean Water Act also empowers states to
develop and enforce “in stream” water quality standards, establish “total
maximum daily load” limitations for stream segments designated as
impaired, and adopt anti-degradation restrictions for high quality
waters. Under each of these programs, our discharges and those
of coal-fired power plants could be subject to substantially more
stringent discharge limits. In particular, some of our
operations currently discharge effluents into stream segments that have
been designated as impaired and the adoption of new TMDL related effluent
limitations for our coal mines could require more costly water treatment
and could adversely affect our coal
production.
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Dredge and Fill
Permits. Certain of our activities involving road building,
placement of excess material, and mine development require a Section 404
dredge and fill permit from the Army Corps of Engineers (“COE”) and a
Section 401 certification or its equivalent from the state in which the
mining activities are proposed. In recent years, the Section
404 permitting process has faced various challenges, and is subject to
ongoing challenges, in the courts. These challenges have
resulted in increased costs and delays in the permitting process. Pending
decisions to active challenges could cause additional increases in the
costs, time and difficulty associated with obtaining and complying with
the permits, and could, as a result, adversely affect our coal
production.
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Mine Safety and Health.
Stringent health and safety standards have been in effect since Congress enacted
the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health
Act of 1977 significantly expanded the enforcement of safety and health
standards and imposed safety and health standards on all aspects of mining
operations. In addition to federal regulatory programs, all of the states in
which we operate also have state programs for mine safety and health regulation
and enforcement. Collectively, federal and state safety and health regulation in
the coal mining industry is perhaps the most comprehensive and pervasive system
for protection of employee health and safety affecting any segment of
U.S. industry. In reaction to the recent mine accidents in West Virginia,
state and federal legislatures and regulatory authorities have increased
scrutiny of mine safety matters and passed more stringent laws governing mining.
For example, in 2006, Congress enacted the Mine Improvement and New Emergency
Response Act (“MINER Act”), which imposed additional burdens on coal operators,
including (i) obligations related to (a) the 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, (b) establishing additional requirements for mine rescue
teams, and (c) promptly notifying federal authorities in the event of a certain
events, (ii) increased penalties for violations of the applicable federal laws
and regulations, and (iii) the requirement that new standards be implemented
regarding the manner in which closed areas of underground mines are sealed, and
(iv) other matters. Various states also have enacted their own new laws and
regulations addressing many of these same subjects. While existing and proposed
regulations have a significant effect on our operating costs, our
U.S. competitors are subject to the same degree of regulation.
Under the
Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act
of 1977, as amended in 1981, each coal mine operator must secure payment of
federal black lung benefits to claimants who are current and former employees
and to a trust fund for the payment of benefits and medical expenses to
claimants who last worked in the coal industry prior to July 1, 1973. The
trust fund is funded by an excise tax on production of up to $1.10 per ton
for deep-mined coal and up to $0.55 per ton for surface- mined coal,
neither amount to exceed 4.4% of the gross sales price. The excise tax does not
apply to coal shipped outside the United States. In 2007, we recorded
$13.3 million of expense related to this excise tax.
Coal Industry Retiree Health Benefit
Act of 1992. Unlike many companies in the coal business, we do not have
any liability under the Coal Industry Retiree Health Benefit Act of 1992 (the
“Coal Act”), which requires the payment of substantial sums to provide lifetime
health benefits to union-represented miners (and their dependents) who retired
before 1992, because liabilities under the Coal Act that had been imposed on our
Predecessor or acquired companies were retained by the sellers and, if
applicable, their parent companies, in the applicable acquisition agreements. We
should not be liable for these liabilities retained by the sellers unless they
and, if applicable, their parent companies, fail to satisfy their obligations
with respect to Coal Act claims and retained liabilities covered by the
acquisition agreements.
Endangered Species Act. The
federal Endangered Species Act (“ESA”) and counterpart state legislation protect
species threatened with possible extinction. A number of species indigenous to
the areas in which we operate are protected under the ESA and compliance with
ESA requirements could have the effect of prohibiting or delaying us from
obtaining mining permits and may include restrictions on timber harvesting, road
building and other mining or agricultural activities in areas containing the
affected species or their habitats. However, based on the species that have been
identified to date and the current application of applicable laws and
regulations, we do not believe there are any species protected under the ESA
that would materially and adversely affect our ability to obtain permits and
mine coal from our properties in accordance with current mining plans. The U. S.
Fish and Wildlife Service is working closely with OSM and State regulatory
agencies to insure that species subject to the ESA are protected from
mining-related impacts. Should more stringent ESA protective measures be
applied, then we could experience increased operating costs or difficulty in
obtaining future mining permits.
Resource Conservation and Recovery
Act (“RCRA”). Currently, certain coal mine wastes, such as overburden and
coal cleaning wastes, are exempted from RCRA. However, if mining
operations are subjected to RCRA in the future, compliance with RCRA
requirements could affect coal mining operations by establishing additional
requirements for the treatment, storage, and disposal of wastes generated by
coal mining activities.
EPA has
determined that national non-hazardous waste regulations under RCRA Subtitle D
are needed for coal combustion wastes disposed in surface impoundments and
landfills and used as mine-fill, and OSM is currently developing these
regulations. The agency also concluded that 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 waste, 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.
Federal and State Superfund
Statutes. Superfund and similar state laws may affect coal mining and
hard rock operations by creating liability for investigation and remediation in
response to releases of hazardous substances into the environment and for
damages to natural resources. Under Superfund, joint and several liabilities may
be imposed on waste generators, site owners or operators and others regardless
of fault. In addition, although unlikely due to the stringent nature of the
current SMCRA regulations, mining operations may have reporting obligations
under the Emergency Planning and Community Right to Know Act and the Superfund
Amendments and Reauthorization Act. The Company has received no
Superfund-related notices for any of its operations.
Davis-Bacon
Act. The State of West Virginia adopted in major part the
Davis-Bacon Act of 1931. Due to our road construction business with
the State of West Virginia, we may be required to pay wages that comply with the
Davis-Bacon Act. Generally, the Davis-Bacon Act stipulates that every
contract in excess of $2,000, to which the United States or the District of
Columbia is a party, for construction, alteration, and/or repair, including
painting and decorating, of public buildings or public works of the United
States or the District of Columbia within the geographical limits of the States
of the Union or the District of Columbia, and which requires or involves the
employment of mechanics and/or laborers shall contain a provision stating the
minimum wages to be paid various classes of laborers and mechanics which shall
be based upon the wages that will be determined by the Secretary of Labor to be
prevailing for the corresponding classes of laborers and mechanics employed on
projects of a character similar to the contract work in the city, town, village,
or other civil subdivision of the State in which the work is to be
performed.
In
December 2004, prior to our Nicewonder Acquisition in October 2005, the
Affiliated Construction Trades Foundation brought an action against the West
Virginia Department of Transportation, Division of Highways (“WVDOH”) and
Nicewonder Contracting, Inc. ("NCI"), which became our wholly-owned indirect
subsidiary after the Nicewonder Acquisition, in the United States District Court
in the Southern District of West Virginia. The plaintiff sought a declaration
that the contract between NCI and the State of West Virginia related to NCI's
road construction project was illegal as a violation of applicable West Virginia
and federal competitive bidding and prevailing wage laws. The plaintiff also
sought an injunction prohibiting performance of the contract but has not sought
monetary damages.
On
September 5, 2007, the Court ruled that WVDOH and the Federal Highway
Administration (who is now a party to the suit) could not exempt a contractor,
like NCI, from paying the prevailing wages as required by the Davis-Bacon Act.
Although the Court has not yet decided what remedy it will impose, we expect a
ruling before mid-2008. We anticipate that the most likely remedy is
a directive that the contract be renegotiated for such payment. If that
renegotiation occurs, WVDOH has committed to agree and NCI has a contractual
right to insist, that additional costs resulting from the order will be
reimbursed by WVDOH and as such neither NCI nor the Company believe, at this
time, that they have any monetary expense from this ruling. As of December 31,
2007, the Company recorded a $6.1 million long-term receivable for the recovery
of these costs from WVDOH and a long-term liability for the obligations under
the ruling.
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Item 1A.
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A
substantial or extended decline in coal prices could reduce our revenues and the
value of our coal reserves.
Our
results of operations are substantially dependent upon the prices we receive for
our coal. The prices we receive for coal depend upon factors beyond our control,
including:
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the
supply of and demand for domestic and foreign
coal;
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the
demand for electricity;
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domestic
and foreign demand for steel and the continued financial viability of the
domestic and/or foreign steel
industry;
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interruptions
due to transportation delays;
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domestic
and foreign governmental regulations and
taxes;
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air
emission standards for coal-fired power
plants;
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regulatory,
administrative, and judicial
decisions;
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the
price and availability of alternative fuels, including the effects of
technological developments;
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the
effect of worldwide energy conservation measures;
and
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the
proximity to, capacity of, and cost of transportation and port
facilities.
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Declines
in the prices we receive for our coal could adversely affect our operating
results and our ability to generate the cash flows we require to improve our
productivity and invest in our operations.
Our coal mining
production and delivery is subject to conditions and events beyond our control,
which could result in higher operating expenses and/or decreased production and
sales and adversely affect our operating results.
A
majority of our coal mining operations are conducted in underground mines and
the balance of our operations is at surface mines. The level of our production
at these mines is subject to operating conditions and events beyond our control
that could disrupt operations, affect production and the cost of mining at
particular mines for varying lengths of time and have a significant impact on
our operating results. Adverse operating conditions and events that we or our
Predecessor have experienced in the past include:
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enactments
of new safety regulations or changes in interpretations of current
regulations.
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delays
and difficulties in acquiring, maintaining or renewing necessary permits
or mining or surface rights;
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the
termination of material contracts by state or other governmental
authorities;
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changes
or variations in geologic conditions, such as the thickness of the coal
deposits and the amount of rock embedded in or overlying the coal
deposit;
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mining
and processing equipment failures and unexpected maintenance
problems;
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limited
availability of mining and processing equipment and parts from
suppliers;
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the
proximity to, capacity of, and cost of transportation
facilities;
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adverse
weather and natural disasters, such as heavy rains and
flooding;
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accidental
mine water discharges;
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the
unavailability of qualified labor;
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strikes
and other labor-related interruptions;
and
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unexpected
mine safety accidents, including fires and explosions from methane and
other sources.
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If any of
these conditions or events occur in the future at any of our mines or affect
deliveries of our coal to customers, they may increase our cost of mining and
delay or halt production at particular mines or sales to our customers either
permanently for varying lengths of time, which could adversely affect our
operating results. For example, Hurricanes Katrina and Rita, which struck the
Gulf Coast in August and September 2005, resulted in delayed shipments of our
coal to our customers.
Any
change in coal consumption patterns by steel producers or North American
electric power generators resulting in a decrease in the use of coal by those
consumers could result in lower prices for our coal, which would reduce our
revenues and adversely impact our earnings and the value of our coal
reserves.
Steam
coal accounted for approximately 62% and 66% of our coal sales volume during
2007 and 2006, respectively. The majority of our sales of steam coal for 2007
and 2006 were to U.S. and Canadian electric power generators. The amount of coal
consumed for U.S. and Canadian electric power generation is affected primarily
by the overall demand for electricity, the location, availability, quality and
price of competing fuels for power such as natural gas, nuclear, fuel oil and
alternative energy sources such as hydroelectric power, technological
developments, and environmental and other governmental regulations. We expect
many new power plants will be built to produce electricity during peak periods
of demand, when the demand for electricity rises above the “base load demand,”
or minimum amount of electricity required if consumption occurred at a steady
rate. However, we also expect that many of these new power plants will be fired
by natural gas because they are cheaper to construct than coal-fired plants and
because natural gas is a cleaner burning fuel. In addition, the increasingly
stringent requirements of the Clean Air Act may result in more electric power
generators shifting from coal to natural gas-fired power plants. Any reduction
in the amount of coal consumed by North American electric power generators could
reduce the price of steam coal that we mine and sell, thereby reducing our
revenues and adversely impacting our earnings and the value of our coal
reserves.
We
produce metallurgical coal that is used in both the U.S. and foreign steel
industries. Metallurgical coal accounted for approximately 38% and 34% of our
coal sales volume during 2007 and 2006, respectively. In recent years,
U.S. steel producers have experienced a substantial decline in the prices
received for their products, due at least in part to a heavy volume of foreign
steel imported into the United States. Any deterioration in conditions in the
U.S. steel industry would reduce the demand for our metallurgical coal and
could impact the collectibility of our accounts receivable from U.S. steel
industry customers. In addition, the U.S. steel industry increasingly
relies on electric arc furnaces or pulverized coal processes to make steel.
These processes do not use coke. If this trend continues, the amount of
metallurgical coal that we sell and the prices that we receive for it could
decrease, thereby reducing our revenues and adversely impacting our earnings and
the value of our coal reserves. If the demand and pricing for metallurgical coal
in international markets decreases in the future, the amount of metallurgical
coal that we sell and the prices that we receive for it could decrease, thereby
reducing our revenues and adversely impacting our earnings and the value of our
coal reserves.
Demand
for our coal changes seasonally and could have an adverse effect on the timing
of our cash flows and our ability to service our existing and future
indebtedness.
Our
business is seasonal, with operating results varying from quarter to quarter. We
have historically experienced lower sales during winter months primarily due to
the freezing of lakes that we use to transport coal to some of our customers. As
a result, our first quarter may be negatively impacted. Lower than expected
sales by us during this period could have an adverse affect on the timing of our
cash flows and therefore our ability to service our obligations with respect to
our existing and future indebtedness.
A
decline in demand for metallurgical coal would limit our ability to sell our
high quality steam coal as higher-priced metallurgical coal and could affect the
economic viability of certain of our mines that have higher operating
costs.
Portions
of our coal reserves possess quality characteristics that enable us to mine,
process and market them as either metallurgical coal or high quality steam coal,
depending on the prevailing conditions in the metallurgical and steam coal
markets. We decide whether to mine, process and market these coals as
metallurgical or steam coal based on management's assessment as to which market
is likely to provide us with a higher margin. We consider a number of factors
when making this assessment, including the difference between the current and
anticipated future market prices of steam coal and metallurgical coal, the lower
volume of saleable tons that results from producing a given quantity of reserves
for sale in the metallurgical market instead of the steam market, the increased
costs incurred in producing coal for sale in the metallurgical market instead of
the steam market, the likelihood of being able to secure a longer-term sales
commitment by selling coal into the steam market and our contractual commitments
to deliver different types of coals to our customers. A decline in the
metallurgical market relative to the steam market could cause us to shift coal
from the metallurgical market to the steam market, thereby reducing our revenues
and profitability.
Most of
our metallurgical coal reserves possess quality characteristics that enable us
to mine, process and market them as high quality steam coal. However, some of
our mines operate profitably only if all or a portion of their production is
sold as metallurgical coal to the steel market. If demand for metallurgical coal
declined to the point where we could earn a more attractive return marketing the
coal as steam coal, these mines may not be economically viable and may be
subject to closure. Such closures would lead to accelerated reclamation costs,
as well as reduced revenue and profitability.
Acquisitions that
we have completed since our formation, as well as acquisitions that we may
undertake in the future, involve a number of risks, any of which could cause us
not to realize the anticipated benefits.
Since our
formation and the acquisition of our Predecessor in December 2002, we have
completed six significant acquisitions and several smaller acquisitions and
investments. We continually seek to expand our operations and coal reserves
through acquisitions. If we are unable to successfully integrate the companies,
businesses or properties we are able to acquire, our profitability may decline
and we could experience a material adverse effect on our business, financial
condition or results of operations. Acquisition transactions involve various
inherent risks, including:
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uncertainties
in assessing the value, strengths, and potential profitability of, and
identifying the extent of all weaknesses, risks, contingent and other
liabilities (including environmental or mine safety liabilities) of,
acquisition candidates;
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the
potential loss of key customers, management and employees of an acquired
business;
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the
ability to achieve identified operating and financial synergies
anticipated to result from an
acquisition;
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problems
that could arise from the integration of the acquired business;
and
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unanticipated
changes in business, industry, market, or general economic conditions that
affect the assumptions underlying our rationale for pursuing the
acquisition.
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Any one or
more of these factors could cause us not to realize the benefits anticipated to
result from an acquisition.
Moreover,
any acquisition opportunities we pursue could materially affect our liquidity
and capital resources and may require us to incur indebtedness, seek equity
capital or both. For instance, in connection with the Nicewonder Acquisition in
October 2005, we issued and subsequently repaid $221.0 million principal
amount of promissory installment notes of one of our indirect, wholly-owned
subsidiaries, we issued 2,180,233 shares of our common stock valued at
approximately $53.2 million, and we entered into a new $525.0 million
credit facility, a portion of the net proceeds of which we used to pay the cash
purchase price and acquisition expenses and the first installment of principal
due on the promissory notes. In addition, future acquisitions could result in
our assuming more long-term liabilities relative to the value of the acquired
assets than we have assumed in our previous acquisitions.
The
inability of the sellers of our Predecessor and acquired companies to fulfill
their indemnification obligations to us under our acquisition agreements could
increase our liabilities and adversely affect our results of operations and
financial position.
In the
acquisition agreements we entered into with the sellers of our Predecessor and
acquired companies, including the acquisition agreements we entered into related
to the Nicewonder and Progress acquisitions, the respective sellers and, in some
of our acquisitions, their parent companies, agreed to retain responsibility for
and indemnify us against damages resulting from certain third-party claims or
other liabilities, such as workers' compensation liabilities, black lung
liabilities, postretirement medical liabilities and certain environmental or
mine safety liabilities. The failure of any seller and, if applicable, its
parent company, to satisfy their obligations with respect to claims and retained
liabilities covered by the acquisition agreements could have an adverse effect
on our results of operations and financial position if claimants successfully
assert that we are liable for those claims and/or retained liabilities. The
obligations of the sellers and, in some instances, their parent companies, to
indemnify us with respect to their retained liabilities will continue for a
substantial period of time, and in some cases indefinitely. The sellers'
indemnification obligations with respect to breaches of their representations
and warranties in the acquisition agreements will terminate upon expiration of
the applicable indemnification period (generally 18-24 months from the
acquisition date for most representations and warranties, and from two to five
years from the acquisition date for environmental representations and
warranties), are subject to deductible amounts and will not cover damages in
excess of the applicable coverage limit. The assertion of third-party claims
after the expiration of the applicable indemnification period or in excess of
the applicable coverage limit, or the failure of any seller to satisfy its
indemnification obligations with respect to breaches of its representations and
warranties, could have an adverse effect on our results of operations and
financial position. See “-- If our assumptions regarding our likely future
expenses related to benefits for non-active employees are incorrect, then
expenditures for these benefits could be materially higher than we have
predicted.”
Our
inability to continue or expand the existing road construction and mining
business of the Nicewonder Companies could adversely affect the expected
benefits from the Nicewonder Acquisition.
One of
our subsidiaries acquired the business of Nicewonder Contracting, Inc. (“NCI”)
pursuant to the Nicewonder acquisition. NCI operates a road construction
business under a contract with the State of West Virginia. Pursuant to the
contract, NCI is building approximately 11 miles of rough grade highway in
West Virginia over the next two to three years and, in exchange, NCI will be
compensated by West Virginia based on the number of cubic yards of material
excavated and/or filled to create a road bed, as well as for certain other cost
components. In the course of the road construction, NCI will recover any coal
encountered and sell the coal to its customers, subject to certain costs,
including coal loading, transportation, coal royalty payments and applicable
taxes and fees.
The State
of West Virginia has only approved funding for a portion of this
road construction. If West Virginia does not fund the remaining sections of
the highway project, it would adversely affect NCI's earnings. Even if West
Virginia funds the remainder of this project through the next two to three
years, we are uncertain whether the state will fund any similar projects in the
future. In addition, we had no experience conducting and completing road
projects prior to the Nicewonder Acquisition and we will continue to rely on the
expertise of the NCI employees to operate the project, and will rely on such
employees to operate any other road projects we may undertake.
The
Affiliated Construction Trades Foundation brought an action against the West
Virginia Department of Transportation, Division of Highways (“WVDOH”) and our
wholly-owned indirect subsidiary Nicewonder Contracting, Inc. ("NCI") in the
United States District Court in the Southern District of West Virginia. The
plaintiff sought a declaration that the contract between NCI and the State of
West Virginia related to NCI's road construction project was illegal as a
violation of applicable West Virginia and federal competitive bidding and
prevailing wage laws. The plaintiff also sought an injunction prohibiting
performance of the contract but has not sought monetary damages.
On
September 5, 2007, the Court ruled that WVDOH and the Federal Highway
Administration (who is now a party to the suit) could not exempt a contractor,
like NCI, from paying the prevailing wages as required by the Davis-Bacon Act.
Although the Court has not yet decided what remedy it will impose, we expect a
ruling before mid-2008. We anticipate that the most likely remedy is a
directive that the contract be renegotiated for such payment. If that
renegotiation occurs, WVDOH has committed to agree and NCI has a contractual
right to insist, that additional costs resulting from the order will be
reimbursed by WVDOH and as such neither NCI nor the Company believe, at this
time, that they will have any monetary expense from this ruling. As of December
31, 2007, the Company recorded a $6.1 million long-term receivable for the
recovery of these costs from WVDOH and a long-term liability for the obligations
under the ruling.
If the
plaintiffs are successful, the litigation could make the road construction
project considerably less advantageous to NCI or restrict or prohibit NCI from
completing the project.
The
loss of, or significant reduction in, purchases by our largest customers could
adversely affect our revenues and profitability.
Our
largest customer during 2007 accounted for approximately 8% of our total
revenues. We derived approximately 42% of our 2007 total revenues from sales to
our ten largest customers. These customers may not continue to purchase coal
from us under our current coal supply agreements, or at all. If these customers
were to significantly reduce their purchases of coal from us or if we were
unable to sell coal to them on terms as favorable to us as the terms under our
current agreements, our revenues and profitability could suffer
materially.
Changes
in purchasing patterns in the coal industry may make it difficult for us to
extend existing supply contracts or enter into new long-term supply contracts
with customers, which could adversely affect the capability and profitability of
our operations.
We sell a
significant portion of our coal under long-term coal supply agreements, which
are contracts with a term greater than 12 months. The execution of a
satisfactory long-term coal supply agreement is frequently the basis on which we
undertake the development of coal reserves required to be supplied under the
contract. We believe that approximately 67% of our 2007 sales volume was sold
under long-term coal supply agreements. At December 31, 2007, our long-term coal
supply agreements had remaining terms of up to 10 years and an average
remaining term of approximately two years. When our current contracts with
customers expire or are otherwise renegotiated, our customers may decide to
purchase fewer tons of coal than in the past or on different terms, including
pricing terms less favorable to us. As of December 31, 2007, approximately 5%
and 67%, respectively, of our planned production for 2008 and 2009 was
uncommitted. We may not be able to enter into coal supply agreements to sell
this production on terms, including pricing terms, as favorable to us as our
existing agreements. For additional information relating to our long-term coal
supply contracts, see “Business -- Marketing, Sales and Customer
Contracts.”
As
electric utilities continue to adjust to frequently changing regulations,
including the Acid Rain regulations of the Clean Air Act, the Clean Air Mercury
Rule, the Clean Air Interstate Rule and the possible deregulation of their
industry, they are becoming increasingly less willing to enter into long-term
coal supply contracts and instead are purchasing higher percentages of coal
under short-term supply contracts. The industry shift away from long-term supply
contracts could adversely affect us and the level of our revenues. For example,
fewer electric utilities will have a contractual obligation to purchase coal
from us, thereby increasing the risk that we will not have a market for our
production. The prices we receive in the spot market may be less than the
contractual price an electric utility is willing to pay for a committed supply.
Furthermore, spot market prices tend to be more volatile than contractual
prices, which could result in decreased revenues.
Certain
provisions in our long-term supply contracts may reduce the protection these
contracts provide us during adverse economic conditions or may result in
economic penalties upon our failure to meet specifications.
Price
adjustment, “price reopener” and other similar provisions in long-term supply
contracts may reduce the protection from short-term coal price volatility
traditionally provided by these contracts. Price reopener provisions are
particularly common in international metallurgical coal sales contracts. Some of
our coal supply contracts contain provisions that allow for the price to be
renegotiated at periodic intervals. Price reopener provisions may automatically
set a new price based on the prevailing market price or, in some instances,
require the parties to agree on a new price, sometimes between a pre-set “floor”
and “ceiling.” In some circumstances, failure of the parties to agree on a price
under a price reopener provision can lead to termination of the contract. Any
adjustment or renegotiation leading to a significantly lower contract price
could result in decreased revenues. Accordingly, supply contracts with terms of
one year or more may provide only limited protection during adverse market
conditions.
Coal
supply agreements also typically contain force majeure provisions allowing
temporary suspension of performance by us or the customer during the duration of
specified events beyond the control of the affected party. Most of our coal
supply agreements contain provisions requiring us to deliver coal meeting
quality thresholds for certain characteristics such as Btu, sulfur content, ash
content, grindability and ash fusion temperature. Failure to meet these
specifications could result in economic penalties, including price adjustments,
the rejection of deliveries or termination of the contracts. Moreover, some of
our agreements where the customer bears transportation costs permit the customer
to terminate the contract if the transportation costs borne by them increase
substantially. In addition, some of these contracts allow our customers to
terminate their contracts in the event of changes in regulations affecting our
industry that increase the price of coal beyond specified limits.
Due to
the risks mentioned above with respect to long-term supply contracts, we may not
achieve the revenue or profit we expect to achieve from these sales
commitments.
Disruption
in supplies of coal produced by contractors and other third parties could
temporarily impair our ability to fill customers' orders or increase our
costs.
In
addition to marketing coal that is produced by our subsidiaries' employees, we
utilize contractors to operate some of our mines. Operational difficulties at
contractor-operated mines, changes in demand for contract miners from other coal
producers, and other factors beyond our control could affect the availability,
pricing, and quality of coal produced for us by contractors. For example, during
2005, production at our contractor operations ran approximately 25% behind plan,
primarily due to shortages in the supply of labor. As a result of
this shortfall, we were forced to purchase coal at a higher cost than planned so
we could meet commitments to customers. To meet customer
specifications and increase efficiency in fulfillment of coal contracts, we also
purchase and resell coal produced by third parties from their controlled
reserves. The majority of the coal that we purchase from third parties is
blended with coal produced from our mines prior to resale and we also process
(which includes washing, crushing or blending coal at one of our preparation
plants or loading facilities) a portion of the coal that we purchase from third
parties prior to resale. We sold 5.8 million tons of coal purchased from
third parties during 2007, representing approximately 20% of our total sales
during 2007. We believe that approximately 64% of our purchased coal sales in
2007 were blended with coal produced from our mines prior to resale, and
approximately 6% of our total sales in 2007 consisted of coal purchased from
third parties that we processed before resale. The availability of specified
qualities of this purchased coal may decrease and prices may increase as a
result of, among other things, changes in overall coal supply and demand levels,
consolidation in the coal industry and new laws or regulations. Disruption in
our supply of contractor-produced coal and purchased coal could temporarily
impair our ability to fill our customers' orders or require us to pay higher
prices in order to obtain the required coal from other sources. Any increase in
the prices we pay for contractor-produced coal or purchased coal could increase
our costs and therefore lower our earnings. Although increases in market prices
for coal generally benefit us by allowing us to sell coal at higher prices,
those increases also increase our costs to acquire purchased coal, which lowers
our earnings.
Competition
within the coal industry may adversely affect our ability to sell coal, and
excess production capacity in the industry could put downward pressure on coal
prices.
We
compete with numerous other coal producers in various regions of the United
States for domestic and international sales. 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. Recent increases in coal prices could encourage the
development of expanded capacity by new or existing coal producers. Any
resulting overcapacity could reduce coal prices and therefore reduce our
revenues.
Coal with
lower production costs shipped east from western coal mines and from offshore
sources has resulted in increased competition for coal sales in the Appalachian
region. In addition, coal companies with larger mines that utilize the long-wall
mining method typically have lower mine operating costs than we do and may be
able to compete more effectively on price, particularly if the current favorable
market weakens. This competition could result in a decrease in our market share
in this region and a decrease in our revenues.
Demand
for our low sulfur coal and the prices that we can obtain for it are also
affected by, among other things, the price of emissions allowances. Decreases in
the prices of these emissions allowances could make low sulfur coal less
attractive to our customers. In addition, more widespread installation by
electric utilities of technology that reduces sulfur emissions (which could be
accelerated by increases in the prices of emissions allowances), may make high
sulfur coal more competitive with our low sulfur coal. This competition could
adversely affect our business and results of operations.
We also
compete in international markets against coal produced in other countries.
Measured by tons sold, exports accounted for approximately 27% of our sales in
2007. The demand for U.S. coal exports is dependent upon a number of
factors outside of our control, including the overall demand for electricity in
foreign markets, currency exchange rates, the demand for foreign-produced steel
both in foreign markets and in the U.S. market (which is dependent in part
on tariff rates on steel), general economic conditions in foreign countries,
technological developments, and environmental and other governmental
regulations. For example, if the value of the U.S. dollar were to rise
against other currencies in the future, our coal would become relatively more
expensive and less competitive in international markets, which could reduce our
foreign sales and negatively impact our revenues and net income. In addition, if
the amount of coal exported from the United States were to decline, this decline
could cause competition among coal producers in the United States to intensify,
potentially resulting in additional downward pressure on domestic coal
prices.
Fluctuations
in transportation costs and the availability or reliability of transportation
could affect the demand for our coal or temporarily impair our ability to supply
coal to our customers.
Transportation
costs represent a significant portion of the total cost of coal for our
customers. Increases in transportation costs, such as those experienced in
recent years could make coal a less competitive source of energy or could make
our coal production less competitive than coal produced from other
sources. On the other hand, significant decreases in transportation
costs could result in increased competition from coal producers in other parts
of the country. For instance, coordination of the many eastern loading
facilities, the large number of small shipments, terrain and labor issues all
combine to make shipments originating in the eastern United States inherently
more expensive on a per-mile basis than shipments originating in the western
United States.
Historically,
high coal transportation rates from the western coal producing areas into
Central Appalachian markets limited the use of western coal in those markets.
More recently, however, lower rail rates from the western coal producing areas
to markets served by eastern U.S. producers have created major competitive
challenges for eastern producers. This increased competition could have a
material adverse effect on our business, financial condition and results of
operations.
We depend
upon railroads, trucks, beltlines, ocean vessels and barges to deliver coal to
our customers. Disruption of these transportation services due to
weather-related problems, mechanical difficulties, strikes, lockouts,
bottlenecks, terrorist attacks, and other events could temporarily impair our
ability to supply coal to our customers, resulting in decreased
shipments. For example, certain shipments of our coal to customers
were delayed by hurricanes in the Gulf Coast in 2005. Decreased
performance levels over longer periods of time could cause our customers to look
to other sources for their coal needs, negatively affecting our revenues and
profitability.
In 2007,
59% of our produced and processed coal volume was transported from the
preparation plant to the customer by rail. In the past, we have experienced a
general deterioration in the reliability of the service provided by rail
carriers, which increased our internal coal handling costs. If there are
continued disruptions of the transportation services provided by the railroad
companies we use and we are unable to find alternative transportation providers
to ship our coal, our business could be adversely affected.
We have
investments in mines, loading facilities, and ports that in most cases are
serviced by a single rail carrier. Our operations that are serviced by a single
rail carrier are particularly at risk to disruptions in the transportation
services provided by that rail carrier, due to the difficulty in arranging
alternative transportation. If a single rail carrier servicing our operations
does not provide sufficient capacity, revenue from these operations and our
return on investment could be adversely impacted. In
addition, our coal is transported from our mines to our loading facilities by
trucks owned and operated by third parties. The states of West
Virginia and Kentucky enforce weight limits on coal trucks on their public
roads. It is possible that other states in which our coal is transported by our
contract carriers could undertake similar actions to increase enforcement
of weight limits. Such stricter enforcement actions could result in
shipment delays and increased costs. An increase in transportation costs could
have an adverse effect on our ability to increase or to maintain production on a
profit-making basis and could therefore adversely affect revenues and
earnings.
Our
business will be adversely affected if we are unable to develop or acquire
additional coal reserves that are economically recoverable.
Our
profitability depends substantially on our ability to mine coal reserves
possessing quality characteristics desired by our customers in a cost-effective
manner. As of December 31, 2007, we owned or leased 617.5 million tons
of proven and probable coal reserves that we believe will support current
production levels for more than 20 years, which is less than the publicly
reported amount of proven and probable coal reserves and reserve lives (based on
current publicly reported production levels) of the other large publicly traded
coal companies. We have not yet applied for the permits required, or developed
the mines necessary, to mine all of our reserves. Permits are becoming
increasingly more difficult and expensive to obtain and the review process
continues to lengthen. In addition, we may not be able to mine all of our
reserves as profitably as we do at our current operations.
Because
our reserves are depleted as we mine our coal, our future success and growth
depend, in part, upon our ability to acquire additional coal reserves that are
economically recoverable. If we are unable to replace or increase our coal
reserves on acceptable terms, our production and revenues will decline as our
reserves are depleted. Exhaustion of reserves at particular mines also may have
an adverse effect on our operating results that is disproportionate to the
percentage of overall production represented by such mines. Our ability to
acquire additional coal reserves through acquisitions in the future also could
be limited by restrictions under our existing or future debt agreements,
competition from other coal companies for attractive properties, or the lack of
suitable acquisition candidates.
We
face numerous uncertainties in estimating our recoverable coal reserves, and
inaccuracies in our estimates could result in decreased profitability from lower
than expected revenues or higher than expected costs.
Forecasts
of our future performance are based on, among other things, estimates of our
recoverable coal reserves. We base our estimates of reserve information on
engineering, economic and geological data assembled and analyzed by our internal
engineers and which is periodically reviewed by third-party consultants. There
are numerous uncertainties inherent in estimating the quantities and qualities
of, and costs to mine, recoverable reserves, including many factors beyond our
control. Estimates of economically recoverable coal reserves and net cash flows
necessarily depend upon a number of variable factors and assumptions, any one of
which may, if incorrect, result in an estimate that varies considerably from
actual results. These factors and assumptions include:
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future
mining technology improvements;
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the
effects of regulation by governmental
agencies;
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geologic
and mining conditions, which may not be fully identified by available
exploration data and may differ from our experiences in areas we currently
mine. As a result, actual coal tonnage recovered from identified reserve
areas or properties, and costs associated with our mining operations, may
vary from estimates. Any inaccuracy in our estimates related to our
reserves could result in decreased profitability from lower than expected
revenues or higher than expected costs; and
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future
coal prices, operating costs, capital expenditures, severance and excise
taxes, royalties and development and reclamation
costs.
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Defects
in title of any leasehold interests in our properties could limit our ability to
mine these properties or result in significant unanticipated costs.
We
conduct a significant part of our mining operations on properties that we lease.
Title to most of our leased properties and mineral rights is not thoroughly
verified until a permit to mine the property is obtained, and in some cases
title with respect to leased properties is not verified at all. Our right to
mine some of our reserves may be materially adversely affected by defects in
title or boundaries. In order to obtain leases or mining contracts to conduct
our mining operations on property where these defects exist, we may in the
future have to incur unanticipated costs or could even lose our right to mine,
which could adversely affect our profitability.
Mining
in Central and Northern Appalachia is more complex and involves more regulatory
constraints than mining in other areas of the United States, which could affect
our mining operations and cost structures in these areas.
The
geological characteristics of Central and Northern Appalachian coal reserves,
such as depth of overburden and coal seam thickness, make them complex and
costly to mine. As mines become depleted, replacement reserves may not be
available when required or, if available, may not be capable of being mined at
costs comparable to those characteristic of the depleting mines. In addition, as
compared to mines in other regions, permitting, licensing and other
environmental and regulatory requirements are more costly and time consuming to
satisfy. These factors could materially adversely affect the mining operations
and cost structures of, and our customers' ability to use coal produced by, our
mines in Central and Northern Appalachia.
Our
work force could become increasingly unionized in the future, which could
adversely affect the stability of our production and reduce our
profitability.
Approximately
96% of our 2007 coal production came from mines operated by union-free
employees. As of December 31, 2007, over 92% of our 3,640 employees are
union-free. However, our subsidiaries' employees have the right at any time
under the National Labor Relations Act to form or affiliate with a union. Any
further unionization of our subsidiaries' employees, or the employees of
third-party contractors who mine coal for us, could adversely affect the
stability of our production and reduce our profitability.
Our
unionized and/or union-free hourly work force could strike in the future,
which could disrupt production and shipments of our coal and increase
costs.
One of
our Virginia subsidiaries has two contracts with the United Mine Workers of
America (“UMWA”) that cover approximately 270 employees. One of our
West Virginia subsidiaries has a Bituminous Coal Operators Association (“BCOA”)
contract with the UMWA covering approximately 22 UMWA
employees. Also, the other West Virginia subsidiary, that is idle,
has a BCOA wage agreement with the UMWA that could be terminated by our
subsidiary or the UMWA with notice but since it is idle, no employees are
affected at this time. However, if the operation becomes active again, these
employees could be affected.
As is the
case with our union-free operations, the UMWA represented employees could
strike, which would adversely affect our production, increase our costs, and
disrupt shipments of coal to our customers.
Our
ability to collect payments from our customers could be impaired if their
creditworthiness deteriorates.
Our
ability to receive payment for coal sold and delivered depends on the continued
creditworthiness of our customers. Our customer base is changing with
deregulation as utilities sell their power plants to their non-regulated
affiliates or third parties that may be less creditworthy, thereby increasing
the risk we bear on payment default. These new power plant owners may have
credit ratings that are below investment grade. In addition, competition with
other coal suppliers could force us to extend credit to customers and on terms
that could increase the risk we bear on payment default.
We have
contracts to supply coal to energy trading and brokering companies under which
those companies sell coal to end users. If the creditworthiness of the energy
trading and brokering companies declines, this would increase the risk that we
may not be able to collect payment for all coal sold and delivered to or on
behalf of these energy trading and brokering companies.
The
government extensively regulates our mining operations, which imposes
significant costs on us, and future regulations could increase those costs or
limit our ability to produce and sell coal.
The coal
mining industry is subject to increasingly strict regulation by federal, state
and local authorities with respect to matters such as:
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employee
health and safety;
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mandated
benefits for retired coal miners;
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mine
permitting and licensing requirements;
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reclamation
and restoration of mining properties after mining is
completed;
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air
quality standards;
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water
pollution;
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plant
and wildlife protection;
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the
discharge of materials into the environment;
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surface
subsidence from underground mining; and
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the
effects of mining on groundwater quality and availability.
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The
costs, liabilities and requirements associated with these regulations may be
costly and time consuming and may delay commencement or continuation of
exploration or production operations. Failure to comply with these regulations
may result in the assessment of administrative, civil and criminal penalties,
the imposition of cleanup and site restoration costs and liens, the issuance of
injunctions to limit or cease operations, the suspension or revocation of
permits and other enforcement measures that could have the effect of limiting
production from our operations. We may also incur costs and liabilities
resulting from claims for damages to property or injury to persons arising from
our operations. If we are pursued for these sanctions, costs and liabilities,
our mining operations and, as a result, our profitability could be adversely
affected.
The
possibility exists that new legislation and/or regulations and orders may be
adopted that may materially adversely affect our mining operations, our cost
structure and/or our customers' ability to use coal. For example, in reaction to
mine accidents during 2005, in West Virginia, state and federal legislatures and
regulatory authorities have increased scrutiny of mine safety matters and passed
more stringent laws governing mining. In 2006, Congress enacted the
MINER Act, which imposed additional burdens on coal operators, including (i)
obligations related to (a) the 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,
(b) insuring the availability of mine rescue teams, and (c) promptly notifying
federal authorities in the event of a certain events,(ii) increased penalties
for violations of the applicable federal laws and regulations, and (iii) the
requirement that new standards be implemented regarding the manner in which
closed areas of underground mines are sealed and (iv) other
matters. In 2007, the implementation of the MINER Act continued
through to the regulatory process. For example, new penalty
regulations with the effect of significantly increasing regular penalty amounts
and special assessment were passed. Further, regulations were
implemented relating to mine seal requirements increasing cost of
compliance. The outlook for 2008 includes a possibility that
additional new federal legislation known as the S-MINER Act could be passed that
would increase the cost structure and materially adversely affect our mining
operations. The legislation would, for example,
require: a) technological advancements and improvements at expedited
rates; b) require mining plan and ventilation changes, as well as affect the
materials used for ventilation purposes; c) impose additional requirements for
compliance with examinations for hazardous conditions; d) impose more stringent
industrial hygiene requirements; e) impose requirements for changing to more
costly belt conveyor materials; f) impose additional requirements for sealing
areas; and g) increase the maximum assessed penalty amounts currently authorized
and penalty payment obligations. Various states also have enacted
their own new laws and regulations addressing many of these same
subjects. In 2007, the State of West Virginia, for example, enacted
legislation that imposes additional burdens on coal operators, including, among
other things, a) the prohibition of the use of belt air unless approval is
obtained; b) imposing additional design requirements for seals; c) mandating
education and certification programs for miners; and d) continuing its advance
for the imposition of additional technological improvements recommended by a
task force. Our
compliance with these or any new mine health and safety regulations could
increase our mining costs. New legislation or administrative regulations (or new
judicial interpretations or administrative enforcement of existing laws and
regulations), including proposals related to the protection of the environment
that would further regulate and tax the coal industry, may also require us or
our customers to change operations significantly or incur increased
costs.
These
regulations, if proposed and enacted in the future, could have a material
adverse effect on our financial condition and results of
operations.
Extensive
environmental regulations affect our customers and could reduce the demand for
coal as a fuel source and cause our sales to decline.
Our
operations and those of our customers are subject to extensive environmental
regulation relating to air emissions, water discharges, generation and disposal
of waste materials, and permitting of operations. These requirements
are a significant part of the costs of our respective businesses, and our costs
relating to environmental matters are increasing as environmental regulation
becomes more stringent.
In
particular, The Clean Air Act and similar state and local laws extensively
regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, and
other compounds emitted into the air from electric power plants, which are the
largest end-users of our coal. A series of more stringent
requirements are expected to become effective in coming years, including EPA’s
Clean Air Interstate Rule that focuses on sulfur dioxide and nitrogen oxides
from coal-fired power plants, and increased regulation relating to particulate
matter, ozone, haze, mercury and other air pollutants.
One major
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. Future
regulation of greenhouse gases in the United States could occur pursuant to
future U.S. treaty obligations, such as the projected new treaty to replace
the Kyoto Protocol, new legislation that for example may establish a carbon tax
or cap-and-trade program, or otherwise. State and regional climate change
initiatives, such as the Regional Greenhouse Gas Initiative of eastern states,
the Western Regional Climate Action Initiative, and recently enacted California
legislation, may take effect before federal action.
Considerable
uncertainty is associated with these air emissions initiatives. The content of
new treaties or legislation is not yet determined, and many of the new
regulatory initiatives remain subject to review by the agencies or the courts.
These more stringent air emissions limitations, however, such regulations will
require significant emissions control expenditures for many coal-fired power
plants and could have the effect of making coal-fired plants unprofitable. Any
switching of fuel sources away from coal, closure of existing coal-fired plants,
or reduced construction of new plants could have a material effect on demand for
and prices received for our coal. The majority of our coal supply agreements
contain provisions that allow a purchaser to terminate its contract if
legislation is passed that either restricts the use or type of coal permissible
at the purchaser's plant or results in specified increases in the cost of coal
or its use to comply with applicable ambient air quality standards. As a result,
these generators may switch to other fuels that generate less of these emissions
or install more effective pollution control equipment, possibly reducing future
demand for coal and the construction of coal-fired power plants.
Also, see
Item 1, “Environmental and Other Regulatory Matters” for a discussion of
environmental issues potentially affecting our operations.
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. Our Predecessor and acquired companies also
utilized certain hazardous materials and generated similar wastes. We may be
subject to claims under federal and state statutes and/or common law doctrines
for toxic torts, natural resource damages and other damages as well as for the
investigation and clean up of soil, surface water, groundwater, and other media.
Such claims may arise, for example, out of current or former conditions at sites
that we own or operate currently, as well as at sites that we or our Predecessor
and acquired companies owned or operated in the past, and at contaminated sites
that have always been owned or operated by third parties. Our liability for such
claims may be joint and several, so that we may be held responsible for more
than our share of the contamination or other damages, or even for the entire
share. We have not been subject to claims arising out of contamination at our
facilities, and are not aware of any such contamination, but may incur such
liabilities in the future.
We
maintain extensive coal slurry impoundments at a number of our mines. Such
impoundments are subject to extensive regulation. Slurry impoundments maintained
by other coal mining operations have been known to fail, causing extensive
damage to the environment and natural resources, as well as liability for
related personal injuries and property damages. 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.
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.
Also, see
Item 1, “Environmental and Other Regulatory Matters” for discussion related to
“Superfund,” and “RCRA.”
We
may be unable to obtain and renew permits necessary for our operations, which
would reduce our production, cash flow and profitability.
Mining
companies must obtain numerous permits that impose strict regulations on various
environmental and safety matters in connection with coal mining. These include
permits issued by various federal and state agencies and regulatory bodies. The
permitting rules are complex and may change over time, making our ability to
comply with the applicable requirements more difficult or impractical, possibly
precluding the continuance of ongoing operations or the development of future
mining operations. The public, including non-governmental organizations such as
anti-mining groups and individuals, have certain rights by statutes to comment
upon, submit objections to, and otherwise engage in the permitting process,
including bringing citizens’ lawsuits to challenge such permits or 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 conduct our
mining activities. Such inefficiencies would likely reduce our
production, cash flow, and profitability.
Permits
under Section 404 of the Clean Water Act are required for coal companies to
conduct dredging or filling activities in jurisdictional waters for the purpose
of creating slurry ponds, water impoundments, refuse areas, valley fills or
other mining activities. The Army Corps of Engineers (the “COE”) is empowered to
issue “nationwide” permits for specific categories of filling activity that are
determined to have minimal environmental adverse effects in order to save the
cost and time of issuing individual permits under Section 404. Nationwide
Permit 21 authorizes the disposal of dredge-and-fill material from mining
activities into the waters of the United States. On October 23, 2003,
several citizens groups sued the COE in the U.S. District Court for the
Southern District of West Virginia seeking to invalidate “nationwide” permits
utilized by the COE and the coal industry for permitting most in-stream
disturbances associated with coal mining, including excess spoil valley fills
and refuse impoundments. Although the lower court enjoined the issuance of
Nationwide 21 permits, that decision was overturned by the Fourth Circuit Court
of Appeals, which concluded that the COE complied with the Clean Water Act in
promulgating this permit. Although we had no operations that were immediately
impacted or interrupted, the lower court's decision required us to convert
certain current and planned applications for Nationwide 21 permits to
applications for individual permits. A similar lawsuit was filed on
January 27, 2005 in the U.S. District Court for the Eastern District
of Kentucky and remains pending, and other lawsuits may be filed in other states
where we operate. Although it is not possible to predict the results of the
Kentucky litigation, it could adversely affect our Kentucky
operations.
Due
to political and economic uncertainties in Venezuela, our investment in Excelven
Pty Ltd could be at risk for loss.
In 2004,
we acquired a 24.5% interest in Excelven Pty Ltd, which, through its
subsidiaries, controls the rights to the Las Carmelitas mining venture in
Venezuela and the related Palmarejo export port facility on Lake Maracaibo in
Venezuela. The project is challenged by political risk. In particular, the
Venezuelan government has expressed an interest in increasing government
ownership in Venezuelan natural resources. The project is currently in the
developmental stage. Any future deterioration in the political environment in
Venezuela or the government’s denial of the AoR permit could lead to a potential
impairment adjustment. In addition, such political and economic
uncertainties could also lead to events such as civil
unrest, work stoppages or the nationalization or other expropriation of private
enterprises by the Venezuelan government, which could result in a loss of
all or a portion of our investment in Excelven, which is approximately $4.9
million to date. In 2007, Excelven
made a decision to close the export port facility, and we recorded a charge of
$1.2 million related to our ownership of this venture, reflecting our share of
the equity losses of this entity.
Our
mining operations consume significant quantities of commodities. If commodity
prices increase significantly or rapidly, it could impact our cost of
production.
Coal
mines consume large quantities of commodities such as steel, copper, rubber
products and liquid fuels, such as diesel fuel. Some commodities, such as steel,
are needed to comply with roof control plans required by regulation. The prices
we pay for these products are strongly impacted by the global commodities
market. A rapid or significant increase in cost of some commodities could impact
our mining costs because we have limited ability to negotiate lower prices, and,
in some cases, do not have a ready substitute for these
commodities.
We
have reclamation and mine closure obligations. If the assumptions underlying our
accruals are inaccurate, we could be required to expend greater amounts than
anticipated.
The
Surface Mining Control and Reclamation Act establish operational, reclamation
and closure standards for all aspects of surface mining as well as most aspects
of deep mining. We accrue for the costs of current mine disturbance and of final
mine closure, including the cost of treating mine water discharge where
necessary. Estimates of our total reclamation and mine-closing liabilities are
based upon permit requirements and our experience. The amounts recorded are
dependent upon a number of variables, including the estimated future retirement
costs, estimated proven reserves, assumptions involving profit margins,
inflation rates, and the assumed credit-adjusted risk-free interest rates.
Furthermore, these obligations are unfunded. If these accruals are insufficient
or our liability in a particular year is greater than currently anticipated, our
future operating results could be adversely affected.
- 22
-
Our ability
to operate our company effectively could be impaired if we fail to attract and
retain key personnel.
Our
ability to operate our business and implement our strategies depends, in part,
on the efforts of our executive officers and other key employees. In addition,
our future success will depend on, among other factors, our ability to attract
and retain other qualified personnel. The loss of the services of any of our
executive officers or other key employees or the inability to attract or retain
other qualified personnel in the future could have a material adverse effect on
our business or business prospects.
A shortage of
skilled labor in the Appalachian region could pose a risk to achieving improved
labor productivity and competitive costs and could adversely affect our
profitability.
Efficient
coal mining using modern techniques and equipment requires skilled laborers,
preferably with at least a year of experience and proficiency in multiple mining
tasks. In recent years, a shortage of trained coal miners in the Appalachian
region has caused us to operate certain units without full staff, which
decreases our productivity and increases our costs. If the shortage of
experienced labor continues or worsens, it could have an adverse impact on our
labor productivity and costs and our ability to expand production in the event
there is an increase in the demand for our coal, which could adversely affect
our profitability.
Forward
sales and forward purchase contracts that are not accounted for as a hedge
could cause earnings volatility in our statement of income for a given
period.
We
participate in forward purchase and forward sales contracts that are considered
derivative instruments under SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities (“SFAS 133”). SFAS 133
requires all derivative financial instruments to be reported on the balance
sheet at fair value. Changes in fair value are recognized either in earnings or
equity, depending on whether the transaction qualifies for hedge accounting, and
if so, the nature of the underlying exposure being hedged and how effective the
derivatives are at offsetting price movements in the underlying
exposure.
Certain of
our forward coal purchase and sales contracts that are considered derivative
instruments do not qualify under the “normal purchase and normal sales”
exception under SFAS 133. Transactions that do not qualify for this exception
are required to be marked to market and currently do not qualify for hedge
accounting. Accordingly, changes in fair value have been recognized in earnings.
During 2007, we decreased coal revenue related to mark to market unrealized
losses on open over the counter (“OTC”) coal sales contracts in the amount of
$8.3 million and decreased cost of sales related to mark to market unrealized
gains on open OTC coal purchase contracts by $17.2 million. The net
impact of these mark-to-market adjustments resulted in an increase to pretax
earnings of $8.9 million.
At December
31, 2007, we had unrealized gains (losses) on open sales and purchase contracts
in the amount of ($2.1 million) and $11.3 million, respectively. These assets
and liabilities are recorded in prepaid expenses and other current assets and
accrued expenses and other current liabilities, respectively, on the balance
sheet with periodic changes in fair value recorded to the income
statement. Since the Company intends to take delivery or provide
delivery of coal under these contracts, the unrealized gains and losses
recorded as of December 31, 2007 will reverse into the income statement in
future periods. The reversal of the unrealized gains related to forward
purchase contracts will result in higher costs of sales in future periods when
we ultimately take delivery of the coal under these contracts. The reversal of
the unrealized losses related to sales contracts will result in higher coal
revenues in future periods when we satisfy our commitments under these
contracts. Due to market price fluctuations, we could experience
significant earnings volatility related to these derivative coal
contracts.
We use
significant quantities of diesel fuel in our operations and are also exposed to
risk in the market price for diesel fuel. We have entered into swap agreements
and diesel put options to reduce the volatility in the price of diesel fuel for
our operations; however, if these instruments are not effective to protect
against volatility, we could incur higher expenses for diesel fuel and therefore
lower earnings. In addition, the diesel fuel swap agreements and put options are
not designated as a hedge and therefore the changes in the fair value for these
derivative instrument contracts are required to be marked to market and recorded
in cost of sales, which may also result in earnings volatility. During 2007, we
entered into diesel fuel swaps and put options each for approximately 2.7
million gallons or 10% of the Company's anticipated 2008 diesel fuel usage.
These diesel fuel swaps and put options use the NYMEX New York Harbor #2
heating oil as the underlying commodity reference price. The fair
value of these diesel fuel swap agreements and put options are an asset of less
than $0.1 million and $0.2 million, respectively, as of December 31,
2007.
Our
amount of indebtedness could harm our business by limiting our available cash
and our access to additional capital and could force us to sell material assets
or take other actions to attempt to reduce our indebtedness.
Our
financial performance could be affected by our amount of indebtedness. At
December 31, 2007, we had $446.9 million of indebtedness outstanding,
representing 53.8% of our total capitalization. This indebtedness consisted of
$175.0 million principal of our Senior Notes, a $233.1 million term loan
under our current credit facility and $38.8 million of other indebtedness,
including $0.7 million of capital lease obligations extending through March
2009, $18.5 million principal amount for the Gallatin project financing and
$18.9 million payable to an insurance premium finance company. In addition,
under our current credit facility, we had $82.2 million of letters of
credit outstanding at December 31, 2007.
This
level of indebtedness could have important consequences to our business. For
example, it could:
|
·
|
increase
our vulnerability to general adverse economic and industry
conditions;
|
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|
·
|
make
it more difficult to self-insure and obtain surety bonds or letters of
credit;
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|
·
|
limit
our ability to enter into new long-term sales contracts;
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|
·
|
make
it more difficult for us to pay interest and satisfy our debt obligations,
including our obligations with respect to the notes;
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|
·
|
require
us to dedicate a substantial portion of our cash flow from operations to
payments on our indebtedness, thereby reducing the availability of our
cash flow to fund working capital, capital expenditures, acquisitions and
other general corporate activities;
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|
·
|
limit
our ability to obtain additional financing to fund future working capital,
capital expenditures, research and development, debt service requirements
or other general corporate requirements;
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·
|
limit
our flexibility in planning for, or reacting to, changes in our business
and in the coal industry;
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|
·
|
place
us at a competitive disadvantage compared to less leveraged competitors;
and
|
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|
·
|
limit
our ability to borrow additional funds.
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If our
cash flows and capital resources are insufficient to fund our debt service
obligations or our requirements under our other long-term liabilities, we may be
forced to sell assets, seek additional capital or seek to restructure or
refinance our indebtedness. These alternative measures may not be successful and
may not permit us to meet our scheduled debt service obligations, including our
obligations with respect to the notes, or our requirements under our other long
term liabilities. In the absence of such operating results and resources, we
could face substantial liquidity problems and might be required to sell material
assets or operations to attempt to meet our debt service and other obligations.
Our current credit facility and the indenture under which the Senior Notes were
issued restrict our ability to sell assets and use the proceeds from the sales.
We may not be able to consummate those sales or to obtain the proceeds which we
could realize from them and these proceeds may not be adequate to meet any debt
service obligations then due. Furthermore, substantially all of our material
assets secure our indebtedness under our current credit
facility.
Despite
our current leverage, we may still be able to incur substantially more debt.
This could further exacerbate the risks associated with our significant
indebtedness.
We may be
able to incur substantial additional indebtedness in the future under the terms
of our credit facility and the indenture governing the Senior Notes.
Our current credit facility provides for a revolving line of credit of up
to $275.0 million, of which $192.8 million was available as of
December 31, 2007. The addition of new debt to our current debt levels
could increase the related risks that we now face. For example, the spread over
the variable interest rate applicable to loans under our credit facility is
dependent on our leverage ratio, and it would increase if our leverage ratio
increases. Additional drawings under our revolving line of credit could also
limit the amount available for letters of credit in support of our bonding
obligations, which we will require as we develop and acquire new
mines.
The covenants
in our credit facility and the indenture governing the senior notes impose
restrictions that may limit our operating and financial
flexibility.
Our
current credit facility and the indenture governing the Senior Notes contain a
number of significant restrictions and covenants that limit our ability and our
subsidiaries' ability to, among other things, incur additional indebtedness or
enter into sale and leaseback transactions, pay dividends, make redemptions and
repurchases of certain capital stock, make loans and investments, create liens,
engage in transactions with affiliates and merge or consolidate with other
companies or sell substantially all of our assets.
These
covenants could adversely affect our ability to finance our future operations or
capital needs or to execute preferred business strategies. In addition, if we
violate these covenants and are unable to obtain waivers from our lenders, our
debt under these agreements would be in default and could be accelerated by our
lenders. If our indebtedness is accelerated, we may not be able to repay our
debt or borrow sufficient funds to refinance it. Even if we were able to obtain
new financing, it may not be on commercially reasonable terms, on terms that are
acceptable to us, or at all. If our debt is in default for any reason, our
business, financial condition and results of operations could be materially and
adversely affected.
Failure
to obtain or renew surety bonds on acceptable terms could affect our ability to
secure reclamation and coal lease obligations, which could adversely affect our
ability to mine or lease coal.
Federal
and state laws require us to obtain surety bonds to secure payment of certain
long-term obligations such as mine closure or reclamation costs, federal and
state workers' compensation costs, coal leases and other obligations. These
bonds are typically renewable annually. Surety bond issuers and holders may not
continue to renew the bonds or may demand additional collateral or other less
favorable terms upon those renewals. The ability of surety bond issuers and
holders to demand additional collateral or other less favorable terms has
increased as the number of companies willing to issue these bonds has decreased
over time. Our failure to maintain, or our inability to acquire, surety bonds
that are required by state and federal law would affect our ability to secure
reclamation and coal lease obligations, which could adversely affect our ability
to mine or lease coal. That failure could result from a variety of factors
including, without limitation:
|
·
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lack
of availability, higher expense or unfavorable market terms of new
bonds;
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·
|
restrictions
on availability of collateral for current and future third-party surety
bond issuers under the terms of our credit facility or the indenture
governing our senior notes; and
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|
·
|
the
exercise by third-party surety bond issuers of their right to refuse to
renew the surety.
|
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Failure
to maintain capacity for required letters of credit could limit our available
borrowing capacity under our credit facility, limit our ability to obtain or
renew surety bonds and negatively impact our ability to obtain additional
financing to fund future working capital, capital expenditure or other general
corporate requirements.
At
December 31, 2007, we had $82.2 million of letters of credit in place,
of which $72.0 million served as collateral for reclamation surety bonds
and $10.2 million secured miscellaneous obligations. Our credit facility
provides for revolving commitments of up to $275.0 million, all of which
can be used to issue additional letters of credit. In addition, obligations
secured by letters of credit may increase in the future. Any such increase would
limit our available borrowing capacity under our current or future credit
facilities and could negatively impact our ability to obtain additional
financing to fund future working capital, capital expenditure or other general
corporate requirements. Moreover, if we do not maintain sufficient borrowing
capacity under our revolving credit facility for additional letters of credit,
we may be unable to obtain or renew surety bonds required for our mining
operations.
If
our assumptions regarding our likely future expenses related to benefits for
non-active employees are incorrect, then expenditures for these benefits could
be materially higher than we have predicted.
At the
times that we acquired the assets of our Predecessor and acquired companies, the
Predecessor and acquired operations were subject to long-term liabilities under
a variety of benefit plans and other arrangements with active and inactive
employees. We assumed a portion of these long-term obligations and are
continuing to incur additional costs from our operations for postretirement,
workers' compensation and black lung liabilities. The current and non-current
accrued portions of these long-term obligations, as reflected in our
consolidated financial statements as of December 31, 2007, included
$54.7 million of postretirement medical obligations and $10.5 million
of self-insured workers' compensation and black lung obligations. These
obligations have been estimated based on assumptions that are described in the
notes to our consolidated financial statements included elsewhere in this annual
report. However, if our assumptions are incorrect, we could be required to
expend greater amounts than anticipated.
Several
states in which we operate consider changes in workers' compensation laws from
time to time, which, if enacted, could adversely affect us. In addition, if any
of the sellers from whom we acquired our operations fail to satisfy their
indemnification obligations to us with respect to postretirement claims and
retained liabilities, then we could be required to expend greater amounts than
anticipated. The inability of the sellers of our Predecessor and acquired
companies to fulfill their indemnification obligations to us under our
acquisition agreements could increase our liabilities and adversely affect our
results of operations.” Moreover, under certain acquisition agreements, we
agreed to permit responsibility for black lung claims related to the sellers'
former employees who are employed by us for less than one year after the
acquisition to be determined in accordance with law (rather than specifically
assigned to one party or the other in the agreements). We believe that the
sellers remain liable as a matter of law for black lung benefits for their
former employees who work for us for less than one year; however, an adverse
ruling on this issue could increase our exposure to black lung benefit
liabilities.
Terrorist
attacks and threats, escalation of military activity in response to such attacks
or acts of war may negatively affect our business, financial condition and
results of operations.
Terrorist
attacks and threats, escalation of military activity in response to such attacks
or acts of war may negatively affect our business, financial condition, and
results of operations. Our business is affected by general economic conditions,
fluctuations in consumer confidence and spending, and market liquidity, which
can decline as a result of numerous factors outside of our control, such as
terrorist attacks and acts of war. Future terrorist attacks against
U.S. targets, rumors or threats of war, actual conflicts involving the
United States or its allies, or military or trade disruptions affecting our
customers may materially adversely affect our operations and those of our
customers. As a result, there could be delays or losses in transportation and
deliveries of coal to our customers, decreased sales of our coal and extension
of time for payment of accounts receivable from our customers. Strategic targets
such as energy-related assets may be at greater risk of future terrorist attacks
than other targets in the United States. In addition, disruption or significant
increases in energy prices could result in government-imposed price controls. It
is possible that any of these occurrences, or a combination of them, could have
a material adverse effect on our business, financial condition and results of
operations.
If
we are unable to accurately estimate the overall risks or costs when we bid on a
road construction contract which is ultimately awarded to us, we may achieve a
lower than anticipated profit or incur a loss on the
contract.
A larger
percentage of our road construction revenues and contract backlog are typically
derived from fixed unit price contracts. Fixed unit price contracts require us
to perform the contract for a fixed unit price irrespective of our actual costs.
As a result, we realize a profit on these contracts only if we successfully
estimate our costs and then successfully control actual costs and avoid cost
overruns. If our cost estimates for a contract are inaccurate, or if we do not
execute the contract within our cost estimates, then cost overruns may cause us
to incur losses or cause the contract not to be as profitable as we
expected. Also, if we do not recover the amounts of coal estimated on
our construction projects, profitability on our constructions contracts could be
less than projected. This, in turn, could negatively affect our cash flow,
earnings and financial position.
The costs
incurred and gross profit realized on those contracts can vary, sometimes
substantially, from the original projections due to a variety of factors,
including, but not limited to:
|
·
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onsite
conditions that differ from those assumed in the original
bid;
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·
|
delays
caused by weather conditions;
|
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·
|
contract
modifications creating unanticipated costs not covered by change
orders;
|
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·
|
changes
in availability, proximity and costs of materials, including diesel fuel,
explosives, and parts and supplies for our
equipment;
|
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·
|
coal
recovery which impacts the allocation of cost to road
construction;
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·
|
availability
and skill level of workers in the geographic location of a
project;
|
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·
|
our
suppliers' or subcontractors' failure to
perform;
|
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·
|
mechanical
problems with our machinery or
equipment;
|
|
·
|
citations
issued by a governmental authority, including the Occupational Safety and
Health Administration and the Mine Safety and Health
Administration;
|
|
·
|
difficulties
in obtaining required governmental permits or
approvals;
|
|
·
|
changes
in applicable laws and regulations;
and
|
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·
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claims
or demands from third parties alleging damages arising from our
work.
|
|
Item
1B.
|
None.
|
Item
2.
|
Coal
Reserves
We
estimate that, as of December 31, 2007, we owned or leased total proven and
probable coal reserves of approximately 617.5 million tons. We believe that
our total proven and probable reserves will support current production levels
for more than 20 years. “Reserves” are defined by SEC Industry Guide 7 as
that part of a mineral deposit which could be economically and legally extracted
or produced at the time of the reserve determination. “Proven (Measured)
Reserves” are defined by SEC Industry Guide 7 as reserves for which
(1) quantity is computed from dimensions revealed in outcrops, trenches,
workings or drill holes; grade and/or quality are computed from the results of
detailed sampling and (2) the sites for inspection, sampling and
measurement are spaced so closely and the geologic character is so well defined
that size, shape, depth and mineral content of reserves are well-established.
“Probable reserves” are defined by SEC Industry Guide 7 as reserves for which
quantity and grade and/or quality are computed from information similar to that
used for proven (measured) reserves, but the sites for inspection,
sampling, and measurement are farther apart or are otherwise less adequately
spaced. The degree of assurance, although lower than that for proven
(measured) reserves, is high enough to assume continuity between points of
observation.
Information
about our reserves consists of estimates based on engineering, economic and
geological data assembled and analyzed by our internal engineers, geologists and
finance associates. We periodically update our reserve estimates to reflect past
coal production, new drilling information and other geological or mining data,
and acquisitions or sales of coal properties. Coal tonnages are categorized
according to coal quality, mining method, permit status, mineability and
location relative to existing mines and infrastructure. In accordance with
applicable industry standards, proven reserves are those for which reliable data
points are spaced no more than 2,640 feet apart. Probable reserves are
those for which reliable data points are spaced 2,640 feet to
7,920 feet apart. Further scrutiny is applied using geological criteria and
other factors related to profitable extraction of the coal. These criteria
include seam height, roof and floor conditions, yield and
marketability.
We
periodically retain outside experts to independently verify our estimates of our
coal reserves. Prior to the initial public offering, we retained a
third party consultant to perform reserve estimates in November
2004. We have also retained a consultant to verify reserves for all
the major acquisitions since November 2004, which include the Callaway, Progress
Fuels, and Mingo Logan Ben’s Creek Complex acquisitions. These
reviews include the preparation of reserve maps and the development of estimates
by certified professional geologists based on data supplied by us and using
standards accepted by government and industry, including the methodology
outlined in U.S. Circular 891. Reserve estimates were developed using
criteria to assure that the basic geologic characteristics of the reserve (such
as minimum coal thickness and wash recovery, interval between deep mineable
seams and mineable area tonnage for economic extraction) were in reasonable
conformity with existing and recently completed operation capabilities on our
properties.
As with
most coal-producing companies in Appalachia, the great majority of our coal
reserves are subject to leases from third-party landowners. These leases convey
mining rights to the coal producer in exchange for a percentage of gross sales
in the form of a royalty payment to the lessor, subject to minimum payments.
Four percent of our reserve holdings are owned and require no royalty or per-ton
payment to other parties. The average royalties paid by us for coal reserves
from our producing properties was $3.19 per ton in 2007, representing 4.4% of
our 2007 coal revenue.
Although
our coal leases have varying renewal terms and conditions, they generally last
for the economic life of the reserves. According to our current mine plans, any
leased reserves assigned to a currently active operation will be mined during
the tenure of the applicable lease. Because the great majority of our leased or
owned properties and mineral rights are covered by detailed title abstracts
prepared when the respective properties were acquired by predecessors in title
to us and our current lessors, we generally do not thoroughly verify title to,
or maintain title insurance policies on, our leased or owned properties and
mineral rights.
The
following table provides the “quality” (sulfur content and average Btu content
per pound) of our coal reserves as of December 31, 2007.
|
Recoverable
Reserves
Proven
&
|
Sulfur
Content
|
Average
Btu
|
|||||||||||||
|
Regional
Business Unit
|
State
|
Probable
(1)
|
<1%
|
1.0%-1.5%
|
>1.5%
|
>12,500
|
<12,500
|
||||||||
|
(In millions of
tons)
|
|||||||||||||||
|
Paramont/
Alpha Land and Reserves (2)
|
Virginia
|
159.1
|
116.0
|
33.2
|
9.9
|
148.6
|
10.5
|
||||||||
|
Dickenson-Russell
|
Virginia
|
36.7
|
36.7
|
--
|
--
|
36.7
|
--
|
||||||||
|
Kingwood
|
West
Virginia
|
30.4
|
--
|
19.6
|
10.8
|
30.4
|
--
|
||||||||
|
Brooks
Run North
|
West
Virginia
|
46.3
|
11.6
|
34.7
|
--
|
32.0
|
14.3
|
||||||||
|
Brooks
Run South (3)
|
West
Virginia
|
88.6
|
87.1
|
1.5
|
--
|
88.6
|
--
|
||||||||
|
AMFIRE
|
Pennsylvania
|
70.1
|
12.5
|
21.6
|
36.0
|
61.5
|
8.6
|
||||||||
|
Enterprise/Enterprise
Land & Reserve, Inc (4)
|
Kentucky
|
164.1
|
60.5
|
49.9
|
53.7
|
140.8
|
23.3
|
||||||||
|
Callaway
(5)
|
West
Virginia and Virginia
|
22.2
|
22.2
|
--
|
--
|
12.9
|
9.3
|
||||||||
|
Totals
|
617.5
|
346.6
|
160.5
|
110.4
|
551.5
|
66.0
|
|||||||||
|
Percentages
|
56
|
%
|
26
|
%
|
18
|
%
|
89
|
%
|
11
|
%
|
|||||
| (1 | ) |
Recoverable
reserves represent the amount of proven and probable reserves that can
actually be recovered taking into account all mining and preparation
losses involved in producing a saleable product using existing methods
under current law. The reserve numbers set forth in the table exclude
reserves for which we have leased our mining rights to third parties.
Reserve information reflects a moisture factor of approximately 6.5%. This
moisture factor represents the average moisture present on our delivered
coal.
|
|
| (2 | ) |
Includes
proven and probable reserves in Virginia controlled by our subsidiary
Alpha Land and Reserves, LLC. Alpha Land and Reserves, LLC subleases a
portion of the mining rights to its proven and probable reserves in
Virginia to our subsidiary Paramont Coal Company Virginia,
LLC.
|
|
| (3 | ) |
Includes
proven and probable reserve in West Virginia controlled by our
subsidiaries Brooks Run South and Riverside Mining
Company.
|
|
| (4 | ) |
Includes
proven and probable reserves in Kentucky controlled by our subsidiary
Enterprise Land & Reserve Inc obtained from the Progress Energy
acquisition.
|
|
| (5 | ) |
Includes
proven and probable reserves controlled in West Virginia by Cobra Natural
Resource obtained from the Mingo Logan Ben Creek Complex
acquisition.
|
The
following table summarizes, by regional business unit, the tonnage of our coal
reserves that is assigned to our operating mines, our property interest in those
reserves and whether the reserves consist of steam or metallurgical coal, as of
December 31, 2007.
|
Recoverable
Reserves
Proven
&
|
Total Tons |
Total
Tons
|
|||||||||||||||||
|
Regional
Business Unit
|
State
|
Probable
(1)
|
Assigned
(2)
|
Unassigned
(2)
|
Owned
|
Leased
|
Coal Type
(3)
|
||||||||||||
|
(In
millions of tons)
|
|||||||||||||||||||
|
Paramont/
Alpha Land and Reserves (4)
|
Virginia
|
159.1 | 47.7 | 111.4 | -- | 159.1 |
Steam
and Metallurgical
|
||||||||||||
|
Dickenson-Russell
|
Virginia
|
36.7 | 36.7 | -- | -- | 36.7 |
Steam
and Metallurgical
|
||||||||||||
|
Kingwood
|
West
Virginia
|
30.4 | 19.1 | 11.3 | -- | 30.4 |
Steam
and Metallurgical
|
||||||||||||
|
Brooks
Run North
|
West
Virginia
|
46.3 | 28.7 | 17.6 | 2.3 | 44.0 |
Steam
and Metallurgical
|
||||||||||||
|
Brooks
Run South (5)
|
West
Virginia
|
88.6 | 41.4 | 47.2 | 1.1 | 87.5 |
Steam
and Metallurgical
|
||||||||||||
|
AMFIRE.
|
Pennsylvania
|
70.1 | 54.9 | 15.2 | 3.1 | 67.0 |
Steam
and Metallurgical
|
||||||||||||
|
Enterprise/Enterprise
Land and Reserve Inc (6)
|
Kentucky
|
164.1 | 15.8 | 148.3 | 20.1 | 144.0 |
Steam
|
||||||||||||
|
Callaway
(7)
|
West
Virginia and Virginia
|
22.2 | 18.3 | 3.9 | 0.7 | 21.5 |
Steam
and Metallurgical
|
||||||||||||
|
Totals
|
617.5 | 262.6 | 354.9 | 27.3 | 590.2 | ||||||||||||||
|
Percentages
|
43 | % | 57 | % | 4 | % | 96 | % | |||||||||||
| (1 | ) |
Recoverable
reserves represent the amount of proven and probable reserves that can
actually be recovered taking into account all mining and preparation
losses involved in producing a saleable product using existing methods
under current law. The reserve numbers set forth in the table exclude
reserves for which we have leased our mining rights to third parties.
Reserve information reflects a moisture factor of approximately 6.5%. This
moisture factor represents the average moisture present on our delivered
coal.
|
|
|
|
| (2 | ) |
Assigned
reserves represent recoverable coal reserves that can be mined without a
significant capital expenditure for mine development, whereas unassigned
reserves will require significant capital expenditures to mine the
reserves.
|
|
|
|
| (3 | ) |
Almost
all of our reserves that we currently market as metallurgical coal also
possess quality characteristics that would enable us to market them as
steam coal.
|
|
|
|
| (4 | ) |
Includes
proven and probable reserves in Virginia controlled by our subsidiary
Alpha Land and Reserves, LLC. Alpha Land and Reserves, LLC subleases a
portion of the mining rights to its proven and probable reserves in
Virginia to our subsidiary Paramont Coal Company Virginia,
LLC.
|
| (5 | ) |
Includes
proven and probable reserve in West Virginia controlled by our
subsidiaries Brooks Run South and Riverside Mining
Company
|
| (6 | ) |
Includes
proven and probable reserves in Kentucky controlled by our subsidiary
Enterprise Land & Reserve Inc obtained from the Progress Energy
acquisition.
|
| (7 | ) |
Includes
proven and probable reserves controlled by Cobra Natural Resource obtained
from the Mingo Logan Ben Creek Complex
acquisition.
|
The following map
shows the locations of Alpha's properties as of December 31, 2007 for each of
our eight regional business units:
See Item 1,
“Business”, for additional information regarding our coal operations and
properties.
|
Item 3.
|
General. We are a party to a
number of legal proceedings incident to our normal business activities. While we
cannot predict the outcome of these proceedings, we do not believe that any
liability arising from these matters individually or in the aggregate should
have a material impact upon our consolidated cash flows, results of operations
or financial condition.
Nicewonder Litigation. In
December 2004, prior to our Nicewonder Acquisition in October 2005, the
Affiliated Construction Trades Foundation brought an action against the West
Virginia Department of Transportation, Division of Highways (“WVDOH”) and
Nicewonder Contracting, Inc. ("NCI"), which became our wholly-owned indirect
subsidiary after the Nicewonder Acquisition, in the United States District Court
in the Southern District of West Virginia. The plaintiff sought a declaration
that the contract between NCI and the State of West Virginia related to NCI's
road construction project was illegal as a violation of applicable West Virginia
and federal competitive bidding and prevailing wage laws. The plaintiff also
sought an injunction prohibiting performance of the contract but has not sought
monetary damages.
On
September 5, 2007, the Court ruled that WVDOH and the Federal Highway
Administration (who is now a party to the suit) could not exempt a contractor,
like NCI, from paying the prevailing wages as required by the Davis-Bacon Act.
Although the Court has not yet decided what remedy it will impose, we expect a
ruling before mid-2008. We anticipate that the most likely remedy is
a directive that the contract be renegotiated for such payment. If that
renegotiation occurs, WVDOH has committed to agree and NCI has a contractual
right to insist, that additional costs resulting from the order will be
reimbursed by WVDOH and as such neither NCI nor the Company believe, at this
time, that they have any monetary expense from this ruling. As of December 31,
2007, the Company recorded a $6.1 million long-term receivable for the recovery
of these costs from WVDOH and a long-term liability for the obligations under
the ruling.
There
were no matters submitted to a vote of security holders through a solicitation
of proxies or otherwise during the fourth quarter ended December 31,
2007.
PART II
The
initial public offering of our common stock commenced on February 15, 2005.
The Company's common stock has been listed on the New York Stock Exchange since
that time under the symbol “ANR.” There was no public market for our common
stock prior to this date.
Price
range of our common stock
Trading
in our common stock commenced on the New York Stock Exchange on
February 15, 2005 under the symbol “ANR.” The following table sets forth,
for the periods indicated, the high and low sales prices per share of our common
stock reported in the New York Stock Exchange consolidated tape.
|
2007
|
High
|
Low
|
||||||
|
First
Quarter
|
$ | 15.66 | $ | 12.45 | ||||
|
Second
Quarter
|
20.79 | 15.61 | ||||||
|
Third
Quarter
|
23.23 | 16.52 | ||||||
|
Fourth
Quarter
|
33.84 | 23.68 | ||||||
|
2006
|
High
|
Low
|
||||||
|
First
Quarter
|
$ | 23.53 | $ | 19.37 | ||||
|
Second
Quarter
|
26.58 | 17.95 | ||||||
|
Third
Quarter
|
19.92 | 14.55 | ||||||
|
Fourth
Quarter
|
16.76 | 14.23 | ||||||
As of
December 31, 2007, there were approximately 240 registered holders of record of
our common stock, including 199 unvested restricted stock positions. The
transfer agent and registrar for our common stock is Computershare Trust
Company, N.A.
Dividend
Policy
We do not
presently pay dividends on our common stock.
Stock
Performance Graph
The
following stock performance graph compares the cumulative total return to
stockholders on a quarterly basis on our common stock with the cumulative total
return to stockholders on a quarterly basis on two indices, the Russell 3000
Index and the Russell 3000 Coal Index. The graph assumes that:
|
·
|
you
invested $100 in our common stock and in each index at the closing price
on February 15, 2005;
|
|
·
|
all
dividends were reinvested; and
|
|
·
|
you
continued to hold your investment through December 31,
2007.
|
You are
cautioned against drawing any conclusions from the data contained in this graph,
as past results are not necessarily indicative of future
performance. The indices used are included for comparative purposes
only and do not indicate an opinion of management that such indices are
necessarily an appropriate measure of the relative performance of our
stock.
|
Item 6.
|
The
following table presents selected financial and other data about us for the most
recent five fiscal periods. The selected financial data as of December 31, 2007,
2006, and 2005 and for the years then ended have been derived from the audited
consolidated financial statements and related footnotes of Alpha Natural
Resources, Inc. and subsidiaries included in this annual report. The selected
historical financial data as of December 31, 2004 and for the year then ended
have been derived from the combined financial statements of ANR Fund IX
Holdings, L.P. and Alpha NR Holding, Inc. and subsidiaries (the owners of a
majority of the membership interests of ANR Holdings prior to the Internal
Restructuring) and the related notes, which are not included in this annual
report. The selected historical financial data as of December 31, 2003 and for
the year then ended have been derived from the audited combined balance sheet of
ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. and subsidiaries not
included in this annual report. You should read the following table in
conjunction with the financial statements, the related notes to those financial
statements, and “Management's Discussion and Analysis of Financial Condition and
Results of Operations.”
The
results of operations for the historical periods included in the following table
are not necessarily indicative of the results to be expected for future periods.
In addition, see Item 1A “Risk Factors” of this report for a discussion of
risk factors that could impact our future results of operations.
|
Alpha
Natural Resources, Inc and Subsidiaries
|
ANR
FUND IX Holdings, L.P. and Alpha NR Holding, Inc. and
Subsidiaries
|
||||||||||||||
|
Year
Ended December 31, 2007
|
Year
Ended December 31, 2006
|
Year
Ended December 31, 2005
|
Year
Ended December 31, 2004
|
|
Year
Ended December 31, 2003
|
||||||||||
|
(In
thousands, except per share and per ton amounts)
|
|||||||||||||||
|
Statement
of Operations Data:
|
|
|
|
||||||||||||
|
Revenues:
|
|
|
|
||||||||||||
|
Coal revenues
|
$
|
1,639,247
|
$
|
1,687,553
|
$
|
1,413,174
|
$
|
1,079,981
|
$
|
694,596
|
|||||
|
Freight
and handling revenues
|
205,086
|
188,366
|
185,555
|
141,100
|
73,800
|
||||||||||
| Other revenues |
33,241
|
34,743
|
27,926
|
28,347
|
13,453
|
||||||||||
|
Total
revenues
|
1,877,574
|
1,910,662
|
1,626,655
|
1,249,428
|
781,849
|
||||||||||
|
Costs
and expenses:
|
|||||||||||||||
|
Cost of coal sales (exclusive of items shown separately
below)
|
1,354,335
|
1,352,450
|
1,184,092
|
920,359
|
626,265
|
||||||||||
|
Freight and handling costs
|
205,086
|
188,366
|
185,555
|
141,100
|
73,800
|
||||||||||
|
Cost of other revenues
|
25,817
|
22,982
|
23,675
|
22,994
|
12,488
|
||||||||||
|
Depreciation, depletion and amortization
|
159,579
|
140,851
|
73,122
|
55,261
|
35,385
|
||||||||||
| Selling, general and administrative expenses (exclusive | |||||||||||||||
| of depreciation and amortization shown separately above) |
58,605
|
67,952
|
88,132
|
40,607
|
21,926
|
||||||||||
|
Total
costs and expenses
|
1,803,422
|
1,772,601
|
1,554,576
|
1,180,321
|
769,864
|
||||||||||
|
Income from operations
|
74,152
|
138,061
|
72,079
|
69,107
|
11,985
|
||||||||||
|
Other
income (expense):
|
|||||||||||||||
|
Interest
expense
|
(40,215
|
)
|
(41,774
|
)
|
(29,937
|
)
|
(20,041
|
)
|
(7,848
|
)
|
|||||
|
Interest
income
|
2,340
|
839
|
1,064
|
531
|
103
|
||||||||||
|
Miscellaneous
income (expense)
|
(93
|
)
|
523
|
91
|
722
|
574
|
|||||||||
|
Total
other income (expense), net
|
(37,968
|
)
|
(40,412
|
)
|
(28,782
|
)
|
(18,788
|
)
|
(7,171
|
)
|
|||||
|
Income from continuing operations before income taxes and minority
interest
|
36,184
|
97,649
|
43,297
|
50,319
|
4,814
|
||||||||||
|
Income
tax expense (benefit)
|
8,629
|
(30,519
|
)
|
18,953
|
5,150
|
898
|
|||||||||
|
Minority
interest
|
(179
|
)
|
--
|
2,918
|
22,781
|
1,164
|
|||||||||
|
Income from continuing operations
|
27,734
|
128,168
|
21,426
|
22,388
|
2,752
|
||||||||||
|
Loss
from discontinued operations
|
--
|
--
|
(213
|
)
|
(2,373
|
)
|
(490
|
)
|
|||||||
|
Net
income
|
$
|
27,734
|
$
|
128,168
|
$
|
21,213
|
$
|
20,015
|
$
|
2,262
|
|||||
| Earnings per share data: | |||||||||||||||
| Net income (loss) per share, as adjusted (1) | |||||||||||||||
| Basic and diluted: | |||||||||||||||
| Income from continuing operations | $ | 0.43 | $ | 2.00 | $ | 0.38 | $ | 1.52 | $ | 0.19 | |||||
| Loss from discontinued operations | -- | -- | -- | (0.16 | ) | (0.04 | ) | ||||||||
| Net income per basic and diluted share | $ | 0.43 | $ | 2.00 | $ | 0.38 | $ | 1.36 | $ | 0.15 | |||||
| Pro forma net income (loss) per share (2) | |||||||||||||||
| Basic and diluted: | |||||||||||||||
| Income from continuing operations | $ | 0.35 | $ | 0.25 | |||||||||||
| Loss from discontinued operations | -- | (0.07 | ) | ||||||||||||
| Net income per basic and diluted share | $ | 0.35 | $ | 0.18 | |||||||||||
|
Alpha Natural
Resources, Inc and Subsidiaries
|
ANR
FUND IX Holdings, L.P. and Alpha NR Holding, Inc. and
Subsidiaries
|
||||||||||||||
|
Year
Ended December 31, 2007
|
Year
Ended December 31, 2006
|
Year
Ended December 31, 2005
|
Year
Ended December 31, 2004
|
Year
Ended December 31, 2003
|
|||||||||||
|
(in
thousands, except per ton amounts)
|
|||||||||||||||
|
Balance
sheet data (at period end):
|
|||||||||||||||
|
Cash
and cash equivalents
|
$ | 54,365 | $ | 33,256 | $ | 39,622 | $ | 7,391 | $ | 11,246 | |||||
|
Operating
and working capital
|
157,147 | 116,464 | 35,074 | 56,257 | 32,714 | ||||||||||
|
Total
assets
|
1,210,914 | 1,145,793 | 1,013,658 | 477,121 | 379,336 | ||||||||||
|
Notes
payable and long-term debt, including current portion
|
446,913 | 445,651 | 485,803 | 201,705 | 84,964 | ||||||||||
|
Stockholders'
equity and partners' capital
|
380,836 | 344,049 | 212,765 | 45,933 | 86,367 | ||||||||||
|
Statement
of cash flows data:
|
|||||||||||||||
|
Net
cash provided by (used in):
|
|||||||||||||||
|
Operating
activities
|
$ | 225,741 | $ | 210,081 | $ | 149,643 | $ | 106,776 | $ | 54,104 | |||||
|
Investing
activities
|
(165,203 | ) | (160,046 | ) | (339,387 | ) | (86,202 | ) | (100,072 | ) | |||||
|
Financing
activities
|
(39,429 | ) | (56,401 | ) | 221,975 | (24,429 | ) | 48,770 | |||||||
|
Capital expenditures
|
(126,381 | ) | (131,943 | ) | (122,342 | ) | (72,046 | ) | (27,719 | ) | |||||
|
Other
data
|
|||||||||||||||
|
Production:
|
|||||||||||||||
|
Produced/processed
|
24,203 | 24,827 | 20,602 | 19,069 | 17,199 | ||||||||||
|
Purchased
|
4,189 | 4,090 | 6,284 | 6,543 | 3,938 | ||||||||||
|
Total
|
28,392 | 28,917 | 26,886 | 25,612 | 21,137 | ||||||||||
|
Tons
Sold:
|
|||||||||||||||
|
Steam
|
17,565 | 19,050 | 16,674 | 15,836 | 14,809 | ||||||||||
|
Met
|
10,980 | 10,029 | 10,023 | 9,490 | 6,804 | ||||||||||
|
Total
|
28,545 | 29,079 | 26,697 | 25,326 | 21,613 | ||||||||||
|
Coal
sales realization/ton:
|
|||||||||||||||
|
Steam
|
$ | 48.28 | $ | 49.05 | $ | 41.33 | $ | 32.66 | $ | 27.14 | |||||
|
Met
|
$ | 72.07 | $ | 75.09 | $ | 72.24 | $ | 59.31 | $ | 37.35 | |||||
|
Total
|
$ | 57.43 | $ | 58.03 | $ | 52.93 | $ | 42.64 | $ | 32.14 | |||||
|
Cost
of coal sales/ton
|
$ | 47.45 | $ | 46.51 | $ | 44.35 | $ | 36.34 | $ | 28.98 | |||||
|
Coal
margin/ton
|
$ | 9.98 | $ | 11.52 | $ | 8.58 | $ | 6.30 | $ | 3.16 | |||||
|
EBITDA,
as adjusted (3)
|
$ | 233,817 | $ | 279,435 | $ | 145,197 | $ | 119,327 | $ | 47,663 | |||||
| (1 | ) |
Basic
earnings per share is computed by dividing net income or loss by the
weighted average number of shares of common stock outstanding during the
periods. Diluted earnings per share is computed by dividing net income or
loss by the weighted average number of shares of common stock and dilutive
common stock equivalents outstanding during the periods. Common stock
equivalents include the number of shares issuable on exercise of
outstanding options less the number of shares that could have been
purchased with the proceeds from the exercise of the options based on the
average price of common stock during the period. Due to the Internal
Restructuring on February 11, 2005 and initial public offering of
common stock completed on February 18, 2005, the calculation of
earnings per share for 2005, 2004, and 2003 reflects certain adjustments,
as described below.
|
|
|
The
numerator for purposes of computing basic and diluted net income (loss)
per share, as adjusted, includes the reported net income (loss) and a pro
forma adjustment for income taxes to reflect the pro forma income taxes
for ANR Fund IX Holdings, L.P.'s portion of reported pre-tax income
(loss), which would have been recorded if the issuance of the shares of
common stock received by the FR Affiliates in exchange for their ownership
in ANR Holdings in connection with the Internal Restructuring had occurred
as of January 1, 2003. For purposes of the computation of basic and
diluted net income (loss) per share, as adjusted, the pro forma adjustment
for income taxes only applies to the percentage interest owned by ANR
Fund IX Holding, L.P., the non-taxable FR Affiliate. No pro forma
adjustment for income taxes is required for the percentage interest owned
by Alpha NR Holding, Inc., the taxable FR Affiliate, because income taxes
have already been recorded in the historical results of operations.
Furthermore, no pro forma adjustment to reported net income (loss) is
necessary subsequent to February 11, 2005 because we are
subject to income taxes.
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|||
|
The
denominator for purposes of computing basic net income (loss) per share,
as adjusted, reflects the retroactive impact of the common shares received
by the FR Affiliates in exchange for their ownership in ANR Holdings in
connection with the Internal Restructuring on a weighted-average
outstanding share basis as being outstanding as of January 1, 2003.
The common shares issued to the minority interest owners of ANR Holdings
in connection with the Internal Restructuring, including the immediately
vested shares granted to management, have been reflected as being
outstanding as of February 11, 2005 for purposes of computing the
basic net income (loss) per share, as adjusted. The unvested shares
granted to management on February 11, 2005 that vest monthly over the
two-year period from January 1, 2005 to December 31, 2006 are
included in the basic net income (loss) per share, as adjusted,
computation as they vest on a weighted-average outstanding share basis
starting on February 11, 2005. The 33,925,000 new shares issued in
connection with the initial public offering have been reflected as being
outstanding since February 14, 2005, the date of the initial public
offering, for purposes of computing the basic net income (loss) per share,
as adjusted.
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|||
|
The
unvested shares issued to management are considered options for purposes
of computing diluted net income (loss) per share, as adjusted. Therefore,
for diluted purposes, all remaining unvested shares granted to management
are added to the denominator subsequent to February 11, 2005 using
the treasury stock method, if the effect is dilutive. In addition, the
treasury stock method is used for outstanding stock options, if dilutive,
beginning with the November 10, 2004 grant of options to management
to purchase units in ACM that were automatically converted into options to
purchase up to 596,985 shares of Alpha Natural Resources, Inc. common
stock at an exercise price of $12.73 per
share.
|
The
computations of basic and diluted net income (loss) per share, as adjusted for
2005, 2004, and 2003 are set forth below:
|
Year
Ended December 31,
|
||||||||||||
|
2005
|
2004
|
2003
|
||||||||||
|
(in
thousands, except per share amounts)
|
||||||||||||
|
Numerator:
|
||||||||||||
|
Reported
income from continuing operations
|
$ | 21,426 | $ | 22,388 | $ | 2,752 | ||||||
|
Deduct:
Income tax effect of ANR Fund IX Holdings, L.P. income from continuing
operations prior to Internal Restructuring
|
(91 | ) | (1,149 | ) | (138 | ) | ||||||
|
Income
from continuing operations, as adjusted
|
21,335 | 21,239 | 2,614 | |||||||||
|
Reported
loss from discontinued operations
|
(213 | ) | (2,373 | ) | (490 | ) | ||||||
|
Add:
Income tax effect of ANR Fund IX Holdings, L.P. loss from discontinued
operations prior to Internal Restructuring
|
2 | 149 | 27 | |||||||||
|
Loss
from discontinued operations, as adjusted
|
(211 | ) | (2,224 | ) | (463 | ) | ||||||
|
Net
income, as adjusted
|
$ | 21,124 | $ | 19,015 | $ | 2,151 | ||||||
|
Denominator:
|
||||||||||||
|
Weighted
average shares-- basic
|
55,664,081 | 13,998,911 | 13,998,911 | |||||||||
|
Dilutive
effect of stock options and restricted stock grants
|
385,465 | -- | -- | |||||||||
|
Weighted
average shares-- diluted
|
56,049,546 | 13,998,911 | 13,998,911 | |||||||||
|
Net
income per share, as adjusted-- basic and diluted:
|
||||||||||||
|
Income
from continuing operations, as adjusted
|
$ | 0.38 | $ | 1.52 | $ | 0.19 | ||||||
|
Loss
from discontinued operations, as adjusted
|
-- | (0.16 | ) | (0.04 | ) | |||||||
|
Net
income per share, as adjusted
|
$ | 0.38 | $ | 1.36 | $ | 0.15 | ||||||
| (2 | ) |
Pro
forma net income (loss) per share gives effect to the following
transactions as if each of these transactions had occurred on
January 1, 2004: the Nicewonder Acquisition and related debt
refinancing in October 2005, the Internal Restructuring and initial public
offering in February 2005, the issuance in May 2004 of $175.0 million
principal amount of 10% senior notes due 2012, and the entry into a
$175.0 million revolving credit facility in May
2004.
|
|
| (3 | ) |
EBITDA
is defined as net income (loss) plus interest expense, income tax expense
(benefit), depreciation, depletion and amortization, less interest income.
EBITDA, as adjusted, is EBITDA, further adjusted for minority interest
prior to our internal restructuring. EBITDA and EBITDA, as adjusted, are
non-GAAP measures used by management to measure operating performance, and
management also believes it is a useful indicator of our ability to meet
debt service and capital expenditure requirements. Because EBITDA and
EBITDA, as adjusted, are not calculated identically by all companies, our
calculation may not be comparable to similarly titled measures of other
companies.
|
EBITDA
and EBITDA, as adjusted, are calculated as follows (unaudited, in
thousands):