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,
2008
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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 if 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 (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes þ No ¨
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, a non-accelerated filer, or a smaller reporting company. See
the definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.
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Large
accelerated filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting company o
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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 30, 2008, was approximately $7,350,657,574 based on the
last sales price reported that date on the New York Stock Exchange of $104.29
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 25, 2009 –
70,885,188 shares.
DOCUMENTS
INCORPORATED BY REFERENCE
Part III
incorporates certain information by reference from the registrant's definitive
proxy statement for the 2009 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, 2008.
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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·
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worldwide
market demand for coal, electricity and
steel;
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·
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global
economic, capital market or political conditions, including a prolonged
economic recession in the markets in which we
operate;
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·
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decline
in coal prices;
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·
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our
liquidity, results of operations and financial
condition;
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·
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regulatory
and court decisions;
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·
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competition
in coal markets;
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·
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changes
in environmental laws and regulations, including those directly affecting
our coal mining and production, and those affecting our customers' coal
usage, including potential carbon or greenhouse gas related
legislation;
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·
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changes
in safety and health laws and regulations and the ability to comply with
such changes;
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·
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availability
of skilled employees and other employee workforce factors, such as labor
relations;
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·
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the
inability of our third-party coal suppliers to make timely deliveries and
our customers refusing to receive coal under agreed contract
terms;
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·
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ongoing
instability and volatility in worldwide financial
markets;
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·
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future
legislation and changes in regulations, governmental policies or
taxes;
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·
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inherent
risks of coal mining beyond our
control;
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·
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disruption
in coal supplies;
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·
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the
geological characteristics of Central and Northern Appalachian coal
reserves;
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·
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our
production capabilities and costs;
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·
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our
ability to integrate the operations we have acquired or developed with our
existing operations successfully, as well as those operations that we may
acquire 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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·
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the
consummation of financing transactions, acquisitions or dispositions and
the related effects on our
business;
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·
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our
relationships with, and other conditions affecting, our
customers;
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·
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changes
in customer coal inventories and the timing of those
changes;
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·
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changes
in and renewal or acquisition of new long-term coal supply
arrangements;
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·
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railroad,
barge, truck and other transportation availability, performance and
costs;
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·
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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 obtain, maintain or renew any necessary permits or rights, and
our ability to mine properties due to defects in title on leasehold
interest;
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·
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changes
in postretirement benefit
obligations;
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·
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fair
value of derivative instruments not accounted for as hedges that are being
marked to market;
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·
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indemnification
of certain obligations not being
met;
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·
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continued
funding of the road construction business, related costs, and
profitability estimates;
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·
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restrictive
covenants in our credit facility and the indenture governing our
convertible notes;
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·
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certain
terms of our convertible notes, including any conversions, that may
adversely impact our liquidity;
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·
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weather
conditions or catastrophic weather-related damage;
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.
TABLE
OF CONTENTS
PART I
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Business
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Overview
We are a
leading Appalachian coal supplier. We produce, process and sell steam and
metallurgical (“met”) coal from eight regional business units, which, as of
December 31, 2008, were supported by 34 active underground mines, 27 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 also sell coal produced by
others, the majority of which we process and/or blend with coal produced from
our mines prior to resale, providing us with a higher overall margin for the
blended product than if we had sold the coals separately.
Steam
coal, which is primarily purchased by large utilities and industrial customers
as fuel for electricity generation, accounted for approximately 58% of our 2008
coal sales volume. The majority of our steam coal sales volume in 2008 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
42% of our 2008 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 when and if demand for power and steel
increases.
During
2008, we sold a total of 28.3 million tons of steam and metallurgical coal
and generated coal revenues of $2.2 billion, EBITDA from continuing
operations of $405.5 million and income from continuing operations of
$161.3 million. We define and reconcile EBITDA from continuing operations
and explain its importance in Item 6 under “Selected Financial Data.” Our
coal sales during 2008 consisted of 23.4 million tons of produced and processed
coal, including 1.5 million tons purchased from third parties and processed
at our processing plants or loading facilities prior to resale, and
4.9 million tons of purchased coal that we resold without processing.
Approximately 65% of the purchased coal in 2008 was blended with coal produced
from our mines prior to resale. Approximately 52% of our total revenue in 2008
was derived from sales made outside the United States, primarily in Brazil,
Egypt, Turkey, Russia and Canada.
As of
December 31, 2008, we owned or leased 599.7 million tons of proven and probable
coal reserves. Of our total proven and probable reserves, approximately 83% are
low sulfur reserves, with approximately 60% having sulfur content below 1%.
Approximately 88% 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 22 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 repair
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.
We were
originally formed in 2002, when 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.” 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
February 18, 2005, Alpha Natural Resources, Inc. completed an initial
public offering of its common stock.
Over the
years, we have grown substantially through a series of
acquisitions. In 2004, we acquired substantially all of the assets of
Moravian Run Reclamation Co., Inc., including four active surface mines and two
additional surface mines under development, a coal preparation plant and
railroad loading facility located in Portage, Pennsylvania and an adjacent coal
refuse disposal site, and 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. In October 2005, we acquired the Nicewonder Coal
Group's coal reserves and operations in southern West Virginia and southwestern
Virginia (“Nicewonder Acquisition”), for an aggregate purchase price of
$328.2 million. The operations we acquired in this acquisition
now constitute our eighth business unit, Callaway Natural
Resources. In 2005, we also sold the assets of our Colorado mining
subsidiary, National King Coal LLC, and related trucking subsidiary, Gallup
Transportation and Transloading Company, LLC. In May 2006, we
acquired certain coal mining operations in eastern Kentucky from Progress Fuels
Corp, a subsidiary of Progress Energy, for $28.8 million. These
operations are adjacent to our Enterprise business unit and were integrated with
Enterprise. In June 2007, we paid $43.9 million for the acquisition
of certain coal mining assets in western West Virginia known as Mingo Logan from
Arch Coal, Inc. 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. In September 2008, we sold approximately
17.6 million tons of underground coal reserves in eastern Kentucky that we had
originally acquired as part of the Progress acquisition to a private coal
producer for approximately $13.0 million in cash.
During
our most recent fiscal year, our subsidiary, Alpha Terminal Company, LLC,
increased its equity ownership position in Dominion Terminal Associates (“DTA”)
from 32.5% to 40.6% by making an additional investment of $2.8 million on April
30, 2008. DTA is a 20 million-ton annual capacity coal export
terminal located in Newport News, Virginia. This transaction maintains our
largest ownership stake in the facility, effectively increasing our coal export
and terminaling capacity from approximately 6.5 million tons to approximately
8.0 million tons annually.
On
September 26, 2008, we sold our interest in Gallatin Materials LLC (“Gallatin”),
a start-up lime manufacturing business in Verona, Kentucky, for cash in the
amount of $45.0 million. The proceeds were used in part to repay the
Gallatin loan facility outstanding with NedBank Limited in the amount of $18.2
million. An escrow balance of $4.5 million was established and we
have agreed to indemnify and guarantee the buyer against breaches of
representations and warranties in the sale agreement and contingencies that may
have existed at closing and materialize within one year from the date of the
sale. We recorded a gain on the sale of $13.6 million in the third
quarter of 2008. Our subsidiary, Palladian Lime, LLC (“Palladian”),
had originally acquired our 94% ownership interest in Gallatin in December
2006.
On July
15, 2008, we entered into a definitive merger agreement pursuant to which, and
subject to the terms and conditions thereof, Cliffs Natural Resources Inc.
(formerly known as Cleveland Cliffs Inc.) (“Cliffs”) would acquire all of our
outstanding shares. Under the terms of the agreement, for each share of
our common stock, stockholders would receive 0.95 Cliffs’ common shares and
$22.23 in cash. The proposed merger required approval of each company’s
stockholders, for which special meetings were scheduled to take place on
November 21, 2008. On November 3, 2008, we commenced litigation
against Cliffs by filing an action in the Delaware Court of Chancery to obtain
an order requiring Cliffs to hold its meeting as scheduled. Later in
November 2008, each company’s Board of Directors, after considering various
issues, including the then current macroeconomic environment, uncertainty in the
steel industry, shareholder dynamics and risks and costs of potential
litigation, determined that settlement of the litigation and termination of the
merger agreement was in the best interests of its equity holders. As
a result, on November 17, 2008, we and Cliffs mutually terminated the merger
agreement and settled the litigation. The terms of the settlement
agreement included a $70.0 million payment from Cliffs to us which, net of
transaction costs, resulted in a gain of $56.3 million.
On
December 3, 2008, we announced the permanent closure of the Whitetail Kittanning
Mine, an adjacent coal preparation plant and other ancillary facilities
(“Kingwood”). The mine stopped producing coal in early January 2009
and Kingwood will cease equipment recovery operations by the end of April
2009. The decision resulted from adverse geologic conditions and
regulatory requirements that rendered the coal seam unmineable at this
location. We recorded a charge of $30.2 million, which includes asset
impairment charges of $21.2 million, write off of advance mining royalties of
$3.8 million, which will not be recoverable, severance and other employee
benefit costs of $3.6 million and increased reclamation obligations of $1.9
million in the fourth quarter of 2008.
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 2008,
approximately 57% 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 2008, approximately
43% 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 13,500 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 599.7 million tons of proven and probable
reserves, approximately 88% 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 have a sulfur content of 1.5% or less. Approximately 83% 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, 2008, 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 61 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 2008, 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, 2008:
Regional
Business Units
|
Number
and Type of
|
|||||||||||||||||||
|
Mines
as of
|
|||||||||||||||||||
|
December
31, 2008
|
|||||||||||||||||||
|
Regional
Business Unit
|
Location
|
Preparation
Plants as of December 31, 2008
|
Underground
|
Surface
|
Total
|
Railroad
|
2008
Production of Saleable Tons in (000's) (1)
|
||||||||||||
|
Paramont
|
Virginia
|
Toms
Creek
|
6 | 6 | 12 |
NS
|
4,760 | ||||||||||||
|
Dickenson-Russell
|
Virginia
|
McClure
River and Moss #3
|
5 | - | 5 |
CSX,
NS
|
1,916 | ||||||||||||
|
Kingwood
|
West
Virginia
|
Whitetail
|
2 | - | 2 |
CSX
|
1,405 | ||||||||||||
|
Brooks
Run North
|
West
Virginia
|
Erbacon
|
2 | 1 | 3 |
CSX
|
2,655 | ||||||||||||
|
Brooks
Run South
|
West
Virginia
|
Litwar
and Kepler
|
10 | - | 10 |
NS
|
2,495 | ||||||||||||
|
AMFIRE
|
Pennsylvania
|
Clymer
and Portage
|
5 | 13 | 18 |
NS
|
3,295 | ||||||||||||
|
Enterprise
|
Kentucky
|
Roxana
|
3 | 4 | 7 |
CSX
|
2,419 | ||||||||||||
|
Callaway/Cobra
|
West
Virginia/Virginia
|
Black
Bear
|
1 | 3 | 4 |
NS
|
4,603 | ||||||||||||
|
Total
|
34 | 27 | 61 | 23,548 | |||||||||||||||
|
(1
|
)
|
Includes
coal purchased from third-party producers that was processed at our
subsidiaries' preparation plants in
2008.
|
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, environmental permit timing and preparation plant
capacity.
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 six
truck/loader surface mines. Three of these surface mines are 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 2008, Paramont purchased
approximately 108,000 tons of coal from third parties that was blended with
Paramont's coal and shipped to our customers. As of December 31, 2008, 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 five 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. Dickenson-Russell purchased approximately 69,000 tons of
coal from third parties that was blended with Dickenson-Russell's coal and
shipped to our customers. As of December 31, 2008, 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 three underground mines, using continuous
miners and the room and pillar mining method. One of the underground
mines is operated by independent contractors. The coal from the underground
mines 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 four 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 2008,
Enterprise purchased approximately 181,000 tons of coal from third parties that
was blended with Enterprise's coal and shipped to our customers. As of December
31, 2008, the Enterprise business unit was operating at a capacity to ship
approximately three million tons per year.
West
Virginia Operations
Kingwood. Our Kingwood
business unit produced coal from two underground mines using continuous miners
and the room and pillar mining method. One mine was staffed and operated by our
Kingwood employees and one was operated by an independent contractor. The coal
was belted to the Whitetail preparation plant operated by Kingwood where it was
cleaned and loaded onto rail or truck for shipment to customers. During
2008, Kingwood purchased approximately 191,000 tons of coal from third parties
that was blended with Kingwood's coal and shipped to our customers. In 2008, the
Kingwood business unit shipped approximately 1.4 million tons. On
December 3, 2008, we announced the permanent closure of Kingwood. The
mine stopped producing coal in early January 2009 and Kingwood will cease
equipment recovery operations by the end of April 2009.
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 our 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, 2008, 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 ten underground mines using
continuous miners and the room and pillar mining method. Four 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 2008, the Brooks Run South business
unit purchased approximately 626,000 tons of coal from third parties that was
blended with other coals and shipped to our customers. As of December 31, 2008,
the Brooks Run South business unit was operating at a capacity to ship
approximately three and one-quarter million tons per year.
Callaway/Cobra. 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 148,000 tons of coal from third
parties in 2008. As of December 31, 2008, 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 a rail belt or truck for shipment to customers. AMFIRE also operates
thirteen truck/loader surface mines, six 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 a rail belt or truck for
shipment to customers. During 2008, AMFIRE purchased approximately 170,000 tons
of coal from third parties that was blended with AMFIRE's coal and shipped to
our customers. As of December 31, 2008, 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 28 employees as of December 31, 2008, and consists of sales managers,
distribution/traffic managers, contract administrators 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
marketing efforts are centered on customer needs and
requirements. Our overall sales philosophy is to market coal products
and blends tailored to meet our customer's individual needs and
specifications. Coal products and blends are sourced from Alpha’s
captive production supplemented by third party purchase coal when needed to
better meet customer requirements or enhance overall economics. 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 28.3 million tons of coal in 2008, consisting of 23.4 million tons of
produced and processed coal and 4.9 million tons of purchased coal that we
resold without processing. Of our total purchased coal sales of 6.4 million tons
in 2008, approximately 4.2 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
1.5 million tons of our 2008 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 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. Approximately 1.7 million tons of our
2007 purchased coal sales were processed by us. 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. The breakdown of tons
sold by market served for 2008, 2007 and 2006 is set forth in the table
below:
|
Steam
Coal Sales (1) (2)
|
Metallurgical
Coal Sales (2)
|
|||||||||||||||
|
Year
|
Tons
|
%
of Total Sales Volume
|
Tons
|
%
of Total Sales Volume
|
||||||||||||
|
(In
millions, except percentages)
|
||||||||||||||||
|
2008
|
16.4 | 58 | % | 11.9 | 42 | % | ||||||||||
|
2007
|
17.5 | 62 | % | 11.0 | 38 | % | ||||||||||
|
2006
|
19.1 | 66 | % | 10.0 | 34 | % | ||||||||||
|
(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%, 3% and 4% of total sales in 2008, 2007 and 2006,
respectively.
|
|
|
(2
|
)
|
Our
sales of steam coal during 2008, 2007, and 2006 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 2008. Our top ten customers in 2008
accounted for approximately 53.5% of 2008 revenues and our largest customer
during 2008 accounted for approximately 12.1% of 2008 revenues. The following
table provides information regarding our exports (including to Canada) in 2008,
2007 and 2006 by revenues and tons sold:
|
Year
|
Export
Tons Sold
|
Export
Tons Sold as a Percentage of Total Coal Sales Volume
|
Export
Sales Revenues (1)
|
Export
Sales Revenue as a Percentage of Total Revenues
|
||||||||||||
|
2008
|
8.8 | 31 | % | $ | 1,318.7 | 52 | % | |||||||||
|
2007
|
7.8 | 27 | % | $ | 705.4 | 37 | % | |||||||||
|
2006
|
7.2 | 25 | % | $ | 668.8 | 35 | % | |||||||||
|
(1
|
)
|
Export
sale revenues in 2008, 2007, and 2006 include approximately $1.5 million,
$1.2 million and $0.7 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 2008, 2007 and 2006 serviced customers in 20, 14 and 18
countries, respectively, across North America, Europe, South America, Asia and
Africa. Brazil was our largest export market in 2008, with sales to Brazil
accounting for approximately 14% of export revenues and 7% of total revenues.
Canada was our largest export market in 2007 and 2006, with sales to Canada
accounting for approximately 15% and 17% of export revenues, respectively, and
6% of total revenues for 2007 and 2006. All of our sales are made in
U.S. dollars, which reduces foreign currency risk. Approximately 4% 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 affected 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 2008, approximately 80% and 64% of our steam and
metallurgical coal sales volume, respectively, was delivered pursuant to
long-term contracts and during 2007, approximately 81% and 44% of our steam and
metallurgical coal sales volume, respectively, was delivered pursuant to
long-term contracts.
Our sales
backlog, including backlog subject to price reopener and/or extension
provisions, was approximately 34.7 million tons as of January 16, 2009 and
approximately 36.4 million tons at the beginning of 2008. Of these tons,
approximately 56% and 63% were expected to be filled within one
year.
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, loadout facilities, 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, lake-going vessels and ocean-going vessels
from terminal facilities. Rail shipments constituted approximately 58% of total
shipments of coal volume produced and processed coal from our mines to the
preparation plant to the customer in 2008. The balance was shipped from our
preparation plants, loadout facilities or mines via truck. In 2008,
approximately 4% of our coal sales were delivered to our customers through
transport on the Great Lakes, approximately 19% was moved through the Norfolk
Southern export facility at Norfolk, Virginia, approximately 8% was moved
through the coal export terminal at Newport News, Virginia operated by Dominion
Terminal Associates, and less than 2% was moved through the export terminals at
Baltimore, MD and New Orleans, LA. We own a 40.6% interest in the coal
export terminal at Newport News, VA 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.
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. In 2008, imports accounted for a relatively small percentage of total
U.S coal consumption. As of October 2008, 3% of total U.S. coal
consumption in 2008 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 greater than 93%
of 2008 domestic coal consumption as of October 2008. 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 and commercial and industrial outputs 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 2008 and 2007,
we largely competed with producers from Australia, Canada, and other
international producers of metallurgical coal.
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 one to two 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 $42.0 million for 2008, of which
approximately 85% was generated by services provided to our other subsidiaries
and approximately 15% was generated by sales to external customers, including
$1.5 million to export customers.
Dominion Terminal Associates.
Through our subsidiary Alpha Terminal Company, LLC, we hold a 40.6% interest in
DTA, a 20 million-ton annual capacity coal export terminal located in
Newport News, Virginia. The terminal, constructed in 1984, 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 2008, we shipped a total of 2.3 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 offset by
payments we receive for transportation incentive payments and for renting our
unused storage space in the terminal to third parties. In 2008, we received cash
payments related to the terminal of $6.6 million, partially offset by
payments we made for expenses of $5.7 million. The terminal is held in a
partnership with subsidiaries of two other companies, Arch Coal and Peabody
Energy.
Gallatin. In
December 2006, our subsidiary, Palladian, acquired a 94% ownership interest in
Gallatin, a start-up lime manufacturing business in Verona,
Kentucky. In September 2008, we sold our interest in Gallatin for
cash in the amount of $45.0 million.
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 2008 came from mines operated by union-free
employees, and as of December 31, 2008, over 93% of 3,779 employees were
union-free. We believe our employee relations are good. There have
been no material work stoppages at any of our properties in the past ten
years.
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.
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 discharge of materials into the environment, surface subsidence
from underground mining, and the effects of mining on groundwater and surface
water 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 on us and delays,
interruptions, or a termination of operations, the extent of which cannot be
predicted. We intend to respond to any such future 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 impose substantial cost increases on coal-fired power
plants and industrial boilers, thereby reducing the demand for coal. Any such
requirements may adversely affect our mining operations, cost structure,
revenues, or the ability of our customers to use coal.
Federal
and state laws and regulations also address the reclamation and restoration of
mining properties after mining has been completed. As of December 31, 2008, we
had accrued $98.9 million for reclamation liabilities and mine closures,
including $8.4 million of current liabilities.
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 and criminal sanctions, could be imposed for
failure to comply with these requirements.
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. This consideration is
expected to continue in 2009 under the new Administration, which as identified
climate change legislation as one of its priorities.
To date,
the U.S. Environmental Protection Agency (the “USEPA”) 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 the USEPA the authority to
regulate vehicle tailpipe emissions of greenhouse gases and that the USEPA 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 the USEPA’s
failure in 2006 to regulate carbon dioxide in its new source performance
standards covering power plants and industrial boilers. Consequently,
the USEPA may seek to impose emission limitations for carbon dioxide from
stationary sources such as power plants.
State and
regional climate change initiatives are taking effect before federal action. Ten
Northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New
Hampshire, New Jersey, New York, Rhode Island, and Vermont) have entered into
the Regional Greenhouse Gas Initiative (“RGGI”) Agreement, calling for a ten
percent reduction of carbon dioxide emissions by 2018. RGGI has commenced
auctioning of carbon dioxide allowances for its first control period of 2009 to
2011. Many other greenhouse gas initiatives, including the Western Regional
Climate Action Initiative and recently enacted California legislation, are in
various stages of development.
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 certain officers, directors or
stockholders have violated federal or state mining laws or if any of those
people 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 that 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, imposes a fee on all coal
produced. In 2008, 2007 and 2006, we recorded expenses of $4.3 million, $5.0
million and $5.0 million, respectively, for this reclamation tax.
Mountaintop
Removal (“MTR”) mining is a legal but controversial method of surface
mining. MTR accounted for less than ten percent of our total 2008
coal production. Certain special interest groups have recently waged a public
relations assault upon MTR and have encouraged the introduction of legislation
at the state and federal level to restrict or ban it. Should changes in laws,
regulations or availability of permits severely restrict or ban MTR in the
future, our production and associated profitability could be adversely
impacted.
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. We
further have a facility with Safeco Insurance Company of America whereby 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, 2008, we have
posted an aggregate of $149.0 million in reclamation bonds and
$9.6 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 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 nationwide. 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:
|
·
|
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 by itself will
continue to impact the demand for coal
nationally.
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Fine Particulate
Matter. The Clean Air Act requires the USEPA 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. The USEPA 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. The USEPA’s
revised ozone NAAQS became effective May 27, 2008. As a result,
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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Clean Air Interstate
Rule. In 2005, the USEPA 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. The 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, the CAIR is expected to reduce regional
sulfur dioxide emissions by over 70% and nitrogen oxides emissions by over
60% from 2003 levels. The 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. Following prolonged judicial action, the CAIR is currently in
effect, with the USEPA required to initiate further proceedings to modify
it. Such proceedings, which likely will make the CAIR more
stringent, are likely to take about two years. The CAIR may
impact demand for coal nationally, but we are unable to predict the
magnitude of the impact.
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Regional Haze. The
USEPA 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 USEPA program was
required to submit to the USEPA a Regional Haze SIP to achieve the goals
of the program. Most affected states based their SIPs on the
CAIR. As a result of the ongoing CAIR proceedings, we are
unable to predict the magnitude of the impact of the Regional Haze
Rule.
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New Source Review. A
number of pending regulatory changes and court actions will affect the
scope of the USEPA’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 another major coal company for
alleged exceedances of its Clean Water Act permit
limits. Subsequently, each of Alpha’s operating subsidiaries
conducted an assessment of its NPDES monitoring and reporting practices,
which identified some exceedances of permit limits. In 2008,
each of Alpha’s West Virginia subsidiaries entered into Consent Orders
with the West Virginia Department of Environmental Protection on this
matter, resulting in their agreement to pay penalties totaling $0.7
million.
The
Clean Water Act also empowers states to develop and enforce “in stream”
water quality standards, establish total maximum daily load (“TMDL”)
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. On
February 13, 2009, the U.S. Court of Appeals for the fourth circuit issued
an industry favorable ruling in the OVEC v Aracoma (Chambers) case.
This ruling affirms the legality of in-stream sediment control
structures and should allow the COE to begin clearing up the serious
backlog of 404 permits that are currently pending. Other pending
decisions to active challenges or legislative or policy changes 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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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. 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 implementation 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.
The USEPA
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. It
is anticipated that the recent fly ash spill at the Tennessee Valley Authority’s
Kingston Power Plant will likely result in increased scrutiny by the USEPA and
OSM during this rule-making process. For example, House Natural
Resources Chairman Nick J. Rahall has just recently proposed a bill that would
require coal-ash impoundments to be subject to the same standards as coal slurry
impoundments under SMCRA.
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 liability may
be imposed on waste generators, site owners or operators and others regardless
of fault. In 2008, USEPA notified us that we might be a de minimis contributor to a
Superfund site. 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.
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 any U.S. state 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 any U.S. state
or the District of Columbia within the geographical limits of any U.S. state 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 the WVDOH and the Federal Highway
Administration (who is now a party to the suit) could not, under the
circumstances of this case, enter into a contract not requiring the contractor
to pay 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
the end of the first quarter of 2010. We anticipate that the most
likely remedy is a directive that the contract be renegotiated for such payment.
If that renegotiation occurs, the WVDOH has committed to agree and NCI has a
contractual right to insist, that additional costs resulting from the order will
be reimbursed by the 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, 2008, the Company recorded a $7.9 million long-term receivable for the
recovery of these costs from the WVDOH and a $7.9 million long-term liability
for the obligations under the ruling.
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Risk
Factors
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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 58% and 62% of our coal sales volume during
2008 and 2007, respectively. The majority of our sales of steam coal for 2008
and 2007 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 42% and 38% of our
coal sales volume during 2008 and 2007, respectively. Any
deterioration in conditions in the U.S. steel industry would reduce the
demand for our metallurgical coal and could impact the collectability 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.
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 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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During
2008, the market for coal experienced considerable price volatility. Although
there was an overall increase in the average sales price of our coal in 2008, in
the fourth quarter of 2008, the average realized price per ton decreased from
the peak price level that had been reached in the third quarter of 2008. In
addition, global demand for coal declined significantly in the fourth quarter of
2008.
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.
Ongoing
instability and volatility in the worldwide financial markets have created
uncertainty, which could adversely affect our business and the price of our
common shares.
As widely
reported, financial markets in the United States, Europe and Asia have been
experiencing extreme disruption in recent months, including, among other things,
extreme volatility in security prices, severely diminished liquidity and credit
availability, rating downgrades of certain investments and declining valuations
of others, including real estate. The current tightening of credit in financial
markets could adversely affect our customers’ ability to obtain financing for
operations and could result in a decrease in the demand, the cancellation of
orders for our coal products, or the restructuring of agreements with our coal
customers. In particular, steel producers in several countries have recently
announced price and production cuts. Continuation or worsening of the current
economic conditions, a prolonged global, national or regional economic recession
or other similar events could have a material adverse effect on the demand for
coal and on our sales, margins, and profitability. During this recent period of
intense market disruption, the market price for our common shares has declined
substantially. We continue to monitor economic developments and the
resulting impact on our business and other suppliers and customers
closely. However, we are unable to predict the likely duration and
severity of the current disruption in financial markets and adverse economic
conditions in the U.S. and other countries and the impact these events may have
on our operations and the industry in general.
Extensive
environmental laws and 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
laws and regulations relating to air quality standards, water pollution, plant
and wildlife protection, the discharge of materials into the environment,
surface subsidence from underground mining, the effects of mining on groundwater
and surface water quality and quantities, 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 requirements become more stringent.
In
particular, the Clean Air Act and similar state and local laws and regulations
limit 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.
One major
by-product of burning coal is carbon dioxide, which is 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 potential
U.S. treaty obligations, such as the projected new treaty to replace the
Kyoto Protocol, and new legislation that may establish a carbon tax or
cap-and-trade program. 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. Predicting
the economic effects of climate change legislation is difficult given the
various alternatives proposed and the complexities of the interactions between
economic and environmental issues. Any more stringent air emissions
requirements, however, are likely to impose significant emissions control
expenditures on many coal-fired power plants and industrial boilers and could
have the effect of making them unprofitable. As a result, these generators may
switch to other fuels that generate less of these emissions, possibly reducing
future demand for coal and the construction of coal-fired power plants. 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. In the future, there may be fuel switching away from
coal.
Also, see
Item 1, “Environmental and Other Regulatory Matters” for a discussion of
environmental issues potentially affecting our operations.
The
government also extensively regulates other aspects of 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.
In
addition to environmental requirements, the coal mining industry is subject to
increasingly strict regulation by federal, state and local authorities with
respect to matters such as employee health and safety, mandated benefits for
retired coal miners, and other mine permitting and licensing
requirements.
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 laws, regulations or 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.
During
2008, MSHA continued its regulatory proceedings to implement the MINER Act.
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 laws and regulations could increase our
mining costs and could have a material adverse effect on our financial condition
and results of operations.
Our coal mining
production and delivery is subject to conditions and events beyond our control,
which could result in higher operating expenses and decreased production and
sales and adversely affect our operating results and could result in impairments
to our assets.
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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enactment
of new environmental or health and safety laws or regulations or changes
in interpretations of current
requirements;
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delays
and difficulties in obtaining, 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 or
hurricanes;
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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 or for varying lengths of time, which could adversely affect our
operating results and could result in impairments to our assets.
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.
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. 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. 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 31% of our sales in
2008. 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.
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 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 governmental
regulations;
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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; 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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Any
inaccuracy in our estimates related to our reserves could result in decreased
profitability from lower than expected revenues or higher than expected
costs.
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.
Our
work force could become increasingly unionized in the future and our unionized
or union-free hourly work force could strike, which could adversely affect the
stability of our production and reduce our profitability.
Approximately
96% of our 2008 coal production came from mines operated by union-free
employees. As of December 31, 2008, over 93% of our 3,779 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.
One of
our Virginia subsidiaries has two contracts with the United Mine Workers of
America (“UMWA”) that cover approximately 248 employees. One of our
West Virginia subsidiaries has a Bituminous Coal Operators Association (“BCOA”)
contract with the UMWA covering approximately 17 UMWA
employees. Also, the other West Virginia subsidiary, which 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 disrupt our production, increase our costs, and disrupt
shipments of coal to our customers, which could reduce our
profitability.
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.
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.
We
continually seek to expand our operations and coal reserves through
acquisitions. In the past five years, we have completed six significant
acquisitions and several smaller acquisitions and investments. Our
ability to complete acquisitions is subject to availability of attractive
targets on terms acceptable to us and general market conditions, among other
things. If we are unable to successfully integrate the companies,
businesses or properties that we 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 from an
acquisition in the amounts and on the
timeframe;
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problems
that could arise from the integration of the acquired business, including
the application of our internal control processes to the acquired
business; and
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unanticipated
changes in business, industry, market, or general economic conditions that
differ from 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. In addition, 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. Future
acquisitions could also result in our assuming more long-term liabilities
relative to the value of the acquired assets than we have assumed in our
previous acquisitions.
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. During 2008, approximately 80% and 64% of our steam
and metallurgical coal sales volume, respectively, was delivered pursuant to
long-term contracts. At December 31, 2008, our long-term coal supply agreements
had remaining terms of up to eight 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. For additional information relating to our long-term coal supply
contracts, see “Business -- Marketing, Sales and Customer
Contracts.”
As of
January 16, 2009, approximately 11% and 62%, respectively, of our planned
production for 2009 and 2010 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.
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.
As a
result of the economic slowdown that has resulted in deep cuts in worldwide
steel production and the application of such price adjustment and other similar
provisions in our long-term supply contracts, we had to restructure certain
agreements under mutually acceptable terms with our steel customers in late
2008. A continuation or decline in the current economic conditions would likely
result in an increase in the number of restructured agreements.
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.
The
loss of, or significant reduction in, purchases by our largest customers could
adversely affect our revenues and profitability.
Our
largest customer during 2008 accounted for approximately 12% of our total
revenues. We derived approximately 54% of our 2008 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 reduce their purchases of coal from us significantly 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.
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 results 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. During the
fourth quarter of 2008, steel production worldwide decreased 24% resulting in a
decrease in the demand for metallurgical coal. Any further deterioration in
conditions in the U.S. steel industry could further reduce the demand for
our metallurgical coal. Furthermore, 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 all the production from these
mines had to be sold as steam coal, theses mines may not be economically viable
and subject to closure. Such closures would lead to asset impairment
charges, accelerated reclamation costs, as well as reduced revenue and
profitability.
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 4.9 million tons of coal purchased from
third parties during 2008, representing approximately 17% of our total sales
during 2008. We believe that approximately 65% of our purchased coal sales in
2008 were blended with coal produced from our mines prior to resale, and
approximately 5% of our total sales in 2008 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.
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.
Fair
value of derivative instruments 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 Statement of Financial Accounting Standards
(“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
that is 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 for these forward sales and
forward purchase contracts have been recorded in the income statement and are
reflected in (increase) decrease in fair value of derivatives instruments,
net. During 2008, we had a net decrease in the fair value of these
derivative instruments of $9.3 million consisting of a decrease in fair value of
forward purchase coal contracts in the amount of $14.3 million, partially offset
by an increase in fair value of forward sale coal contracts of $5.0
million.
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 fuel put options to reduce the volatility in the price of diesel fuel
for our operations. These diesel fuel swap agreements and put options
are not designated as a hedge for accounting purposes 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 2008, we entered into diesel fuel swaps and put
options each for approximately 15.6 million gallons or 50% of the Company's
anticipated 2009 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. During 2008, we had a net decrease of $38.0 million
in the fair value of these diesel fuel derivative instruments consisting of a
decrease of $38.0 million in the fair value of swap agreements, an increase in
the fair value of purchased put options of $3.9 million, and a decrease in the
fair value of sold put options of 3.9 million.
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 2008,
58% 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 future
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 our revenues and earnings.
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.
Furthermore,
global financial markets have been experiencing extreme disruption in recent
months, including, among other things, severely diminished liquidity and credit
availability. We continue to monitor these developments and the
resulting impact on our business and our suppliers and customers closely. A
continuation or worsening of the current economic conditions, a prolonged
global, national or regional economic recession or other similar events, is
likely to significantly impact the creditworthiness of our customers and could
increase the risk we bear on payment default.
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, 2008, we owned or leased 599.7 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
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 conditions 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 special interest groups and
individuals, have certain rights under various 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.
In
particular, certain of our activities involving valley fills, ponds or
impoundments, road building, placement of excess material, and other mine
development activities 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 a series of court challenges that have resulted in increased costs and
delays in the permitting process. Future challenges or changes to the
permitting process 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.
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. 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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In
addition, due to the current instability and volatility of the financial
markets, our current surety bond providers may experience difficulties in
providing new surety bonds to us, maintaining existing surety bonds, or
satisfying liquidity requirements under existing surety bond
contracts. In that event, we would be required to find alternative
sources of funding to satisfy our payment obligations, which may require greater
use of our credit facility.
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 (“SMCRA”) establishes operational,
reclamation and closure standards for all aspects of surface mining as well as
deep mining. We accrue for the costs of current mine disturbance and 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.
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 from time to time we generate
limited quantities of hazardous wastes. Our Predecessor and acquired companies
also utilized certain hazardous materials and generated similar wastes. We may
be subject to claims under federal or state statutes 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, sediments, groundwater, and
other natural resources. Such claims may arise 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
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. The recent failure of
the fly ash impoundment at the Tennessee Valley Authority’s Kingston Power
Plant, which is not regulated in the same manner as our slurry impoundments,
could result in additional scrutiny of our impoundments.
These and
other unforeseen environmental impacts that our operations may have, 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
our business.
Also, see
Item 1, “Environmental and Other Regulatory Matters” for discussion related to
“Superfund,” and “RCRA.”
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 actual or
alleged 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 on that property, which could adversely affect our
profitability.
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.
When we
acquired the assets of our Predecessor and acquired companies, those 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, 2008,
included $61.3 million of postretirement medical obligations and $11.3
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
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.
Our
significant 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, 2008, we had $539.1 million of indebtedness outstanding,
representing 43% of our total capitalization. This indebtedness consisted of
$287.5 million principal of our convertible senior notes, a $233.1 million
term loan under our current credit facility and $18.5 million of other
indebtedness, including $0.2 million of capital lease obligations extending
through March 2009, and $18.3 million payable to an insurance premium
finance company. In addition, under our current credit facility, we had
$82.6 million of letters of credit outstanding at December 31,
2008.
This
level of indebtedness could have important consequences to our business. For
example, it could:
|
|
·
|
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;
|
|
|
·
|
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;
|
|
|
·
|
increase
our vulnerability to general adverse economic and industry conditions and
limit our flexibility in planning for, or reacting to, changes in our
business and in the coal industry;
|
|
|
·
|
make
it more difficult to self-insure and obtain surety bonds or letters of
credit;
|
|
|
·
|
limit
our ability to enter into new long-term sales contracts;
and
|
|
|
·
|
place
us at a competitive disadvantage compared to less leveraged
competitors.
|
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 or our
requirements under our other long term liabilities. In the absence of sufficient
cash flows 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 restricts our ability
to sell assets and use the proceeds from the sales. We may not be able to
consummate any such 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.
We
may also be able to incur substantially more debt which 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. Our current credit facility provides for a
revolving line of credit of up to $375.0 million, of which
$292.4 million was available as of December 31, 2008. 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.
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, 2008, we had $82.6 million of letters of credit in place,
of which $73.0 million served as collateral for reclamation surety bonds
and $9.6 million secured miscellaneous obligations. Our credit facility
provides for revolving commitments of up to $375.0 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.
The
terms of our credit facility limit our and our subsidiaries’ ability to take
certain actions, which may adversely affect our business.
Our
credit facility contains a number of significant restrictions and covenants that
limit our ability and our subsidiaries' ability to, among other things, incur
additional indebtedness, 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 this agreement 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.
Certain
terms of our convertible notes may adversely impact our liquidity.
Upon
conversion of our convertible notes, we will be required to pay in cash the
lesser of the principal amount of the converted notes and the sum of a
calculated daily conversion value over an averaging period. As a result, the
conversion of the convertible notes may significantly reduce our
liquidity.
Sales
of additional shares of our common stock, the exercise or granting of additional
stock options or conversion of our convertible notes could cause the price of
our common stock to decline.
Sales of
substantial amounts of our common stock in the open market and the availability
of those shares for sale could adversely affect the price of our common stock.
In addition, future issuances of equity securities, including pursuant to
outstanding options or the conversion of our convertible bonds, could dilute the
interests of our existing stockholders and could cause the market price for our
common stock to decline. We may issue equity securities in the future for a
number of reasons, including to finance our operations and business strategy, to
adjust our ratio of debt to equity, to satisfy our obligations upon the exercise
of outstanding warrants or options or for other reasons.
As of
December 31, 2008, there were:
|
|
·
|
519,984 shares
of common stock issuable upon the exercise of stock options with a
weighted-average exercise price of
17.87;
|
|
|
·
|
17,056
restricted share units issued to directors to be converted to common stock
upon separation of service;
|
|
|
·
|
35,492 shares
to be issued to recipients of performance share awards (based on actual
results) at the end of a performance period which ended on
December 31, 2008;
|
|
|
·
|
292,551 shares
to be issued to recipients of performance share awards (assuming
performance at a target level) at the end of a performance period which
ends on December 31, 2009; and
|
|
|
·
|
122,657 shares
to be issued to recipients of performance share awards (assuming
performance at a target level) at the end of a performance period which
ends on December 31, 2010.
|
The price
of our common stock could also be affected by hedging or arbitrage trading
activity that may exist or develop involving our common stock and our
convertible notes.
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.
Our
inability to continue or expand the Nicewonder existing road construction and
coal recovery business could adversely affect the expected benefits from the
Nicewonder acquisition.
Our
subsidiary, Nicewonder Contracting, Inc. (“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 one to two years and, in exchange, NCI will be
compensated by West Virginia based on the number of cubic yards of material
excavated 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 one to two years, we are
uncertain whether the state will fund any similar projects in the
future.
The
Affiliated Construction Trades Foundation brought an action against the West
Virginia Department of Transportation, Division of Highways (“WVDOH”) and 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 the WVDOH and the Federal Highway
Administration (who is now a party to the suit) could not, under the
circumstances of this case, enter into a contract not requiring the contractor
to pay the prevailing wages as required by the Davis-Bacon
Act. Although the Court has not yet decided what remedy it will
impose, regarding the prevailing wage issue, we expect a ruling before the end
of the first quarter of 2010. We anticipate that the most likely
remedy would be a directive that the contract be renegotiated for such payment.
If that renegotiation occurs, the WVDOH has contractually committed to agree and
NCI has a contractual right to insist, that such additional costs resulting from
such an order will be reimbursed by the WVDOH. Accordingly, we do not
believe that we will have any monetary expense as a result of this ruling. As of
December 31, 2008, the Company recorded a $7.9 million long-term receivable for
the recovery of these costs from the WVDOH and a $7.9 million long-term
liability for the obligations under the ruling.
If the
plaintiff is successful, in its challenge, the resulting judgment could make
completing the remainder of the road construction project considerably less
advantageous to NCI or restrict or prohibit NCI from completing the project,
which could adversely affect our results.
If
we are unable to accurately estimate the overall risks or costs when we bid on a
road construction contract that is ultimately awarded to us, we may achieve a
lower than anticipated profit or incur a loss on the contract.
A large
percentage of our road construction revenues and contract backlog is 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 construction 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:
|
|
·
|
onsite
conditions that differ from those assumed in the original
bid;
|
|
|
·
|
delays
caused by weather conditions;
|
|
|
·
|
contract
modifications creating unanticipated costs not covered by change
orders;
|
|
|
·
|
changes
in availability, proximity and costs of materials, including diesel fuel,
explosives, and parts and supplies for our
equipment;
|
|
|
·
|
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;
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·
|
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;
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|
·
|
changes
in applicable laws and regulations;
and
|
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·
|
claims
or demands from third parties alleging damages arising from our
work.
|
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.
Provisions
in our certificate of incorporation and bylaws and the indenture for our
convertible notes may discourage a takeover attempt even if doing so might be
beneficial to our stockholders.
Provisions
contained in our certificate of incorporation and bylaws could impose
impediments to the ability of a third party to acquire us even if a change of
control would be beneficial to our stockholders. Provisions of our certificate
of incorporation and bylaws impose various procedural and other requirements,
which could make it more difficult for stockholders to effect certain corporate
actions. For example, our certificate of incorporation authorizes our board of
directors to determine the rights, preferences, privileges and restrictions of
unissued series of preferred stock, without any vote or action by our
stockholders. Thus, our board of directors can authorize and issue shares of
preferred stock with voting or conversion rights that could adversely affect the
voting or other rights of holders of our common stock. These provisions may have
the effect of delaying or deterring a change of control of our Company, and
could limit the price that certain investors might be willing to pay in the
future for shares of our common stock.
If a
“fundamental change” (as defined in the indenture for our convertible notes)
occurs, holders of the convertible notes will have the right, at their option,
either to convert their convertible notes or require us to repurchase all or a
portion of their convertible notes. In the event of a “make-whole fundamental
change” (as defined in the indenture for the convertible notes), we also may be
required to increase the conversion rate applicable to any convertible notes
surrendered for conversion. In addition, the indenture for the convertible notes
prohibits us from engaging in certain mergers or acquisitions unless, among
other things, the surviving entity is a U.S. entity that assumes our
obligations under the convertible notes. Our credit facility imposes similar
restrictions on us, including with respect to mergers or consolidations with
other companies and the sale of substantially all of our assets. These
provisions could prevent or deter a third party from acquiring us even where the
acquisition could be beneficial to our stockholders.
We
do not intend to pay cash dividends on our common stock in the foreseeable
future.
We have
never declared or paid a cash dividend, and we currently do not anticipate
paying any cash dividends in the foreseeable future. If we were to
decide in the future to pay dividends, our ability to do so would be dependent
on the ability of our subsidiaries to make cash available to us, by dividend,
debt repayment or otherwise. The ability of our subsidiaries to make
cash available to us is limited by restrictions in our credit
facility.
|
Unresolved
Staff Comments
|
None.
|
Item
2.
|
Coal
Reserves
We
estimate that, as of December 31, 2008, we owned or leased total proven and
probable coal reserves of approximately 599.7 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 the reserved
area lies within 1,320 feet of a reliable data point. Probable reserves are
those for which the reserved area lies between 1,320 feet and 3,960 feet from a
reliable data point. 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 our 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. Of
our reserve holdings, 1.4% 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 $4.04 per ton in 2008, representing 4.0% of our 2008
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, 2008.
|
Recoverable
Reserves Proven & Probable (1)
|
Sulfur
Content
|
Average
BTU
|
||||||||||||
|
Regional
Business Unit
|
State
|
<1%
|
1.0%-1.5%
|
>1.5%
|
>12,500
|
<12,500
|
||||||||
|
Paramont/Alpha
Land and Reserves (2)
|
Virginia
|
188.0 | 140.7 | 38.5 | 8.8 | 178.0 | 10.0 | |||||||
|
Dickenson-Russell
|
Virginia
|
41.3 | 41.3 | 0.0 | 0.0 | 41.3 | 0.0 | |||||||
|
Kingwood
(3)
|
West
Virginia
|
12.3 | 0.0 | 1.0 | 11.3 | 12.3 | 0.0 | |||||||
|
Brooks
Run North
|
West
Virginia
|
40.6 | 18.7 | 21.9 | 0.0 | 33.2 | 7.4 | |||||||
|
Brooks
Run South (4)
|
West
Virginia
|
85.2 | 83.7 | 1.5 | 0.0 | 85.2 | 0.0 | |||||||
|
AMFIRE
|
Pennsylvania
|
69.4 | 9.5 | 31.5 | 28.4 | 45.6 | 23.8 | |||||||
|
Enterprise/Enterprise
Land & Reserve, Inc (5)
|
Kentucky
|
142.7 | 44.9 | 47.0 | 50.8 | 121.3 | 21.4 | |||||||
|
Callaway/Cobra
(6)
|
West
Virginia and Virginia
|
20.2 | 20.2 | 0.0 | 0.0 | 12.7 | 7.5 | |||||||
|
Totals
|
599.7 | 359.0 | 141.4 | 99.3 | 529.6 | 70.1 | ||||||||
|
Percentages
|
60 | % | 23 | % | 17 | % | 88 | % | 12 | % | ||||
|
(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, which varies depending on rank of coal and processing
requirements.
|
|
|
(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
|
)
|
On
December 3, 2008, we announced the permanent closure of Kingwood and the
mine stopped producing coal in early January 2009. Unmineable
reserves were written off at December 31, 2008.
|
|
|
(4
|
)
|
Includes
proven and probable reserve in West Virginia controlled by our
subsidiaries Brooks Run South and Riverside Mining
Company.
|
|
|
(5
|
)
|
Includes
proven and probable reserves in Kentucky controlled by our subsidiary
Enterprise Land & Reserve Inc obtained from the Progress Energy
acquisition.
|
|
|
(6
|
)
|
Includes
proven and probable reserves controlled in West Virginia by Cobra Natural
Resource obtained from the Mingo Logan Ben’s 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, 2008.
|
Recoverable
Reserves Proven & Probable (1)
|
Total
Tons
|
Total
Tons
|
||||||||||||||
|
Regional
Business Unit
|
State
|
Assigned
(2)
|
Unassigned
(2)
|
Owned
|
Leased
|
Coal
Type (3)
|
||||||||||
|
(In
millions of tons)
|
||||||||||||||||
|
Paramont/Alpha
Land and Reserves (4)
|
Virginia
|
188.0 | 59.9 | 128.1 | 0.0 | 188.0 |
Steam
and Metallurgical
|
|||||||||
|
Dickenson-Russell
|
Virginia
|
41.3 | 41.1 | 0.2 | 0.0 | 41.3 |
Steam
and Metallurgical
|
|||||||||
|
Kingwood
(5)
|
West
Virginia
|
12.3 | 1.0 | 11.3 | 0.0 | 12.3 |
Steam
and Metallurgical
|
|||||||||
|
Brooks
Run North
|
West
Virginia
|
40.6 | 24.0 | 16.6 | 2.3 | 38.3 |
Steam
and Metallurgical
|
|||||||||
|
Brooks
Run South (6)
|
West
Virginia
|
85.2 | 38.4 | 46.8 | 1.0 | 84.2 |
Steam
and Metallurgical
|
|||||||||
|
AMFIRE
|
Pennsylvania
|
69.4 | 50.0 | 19.4 | 3.5 | 65.9 |
Steam
and Metallurgical
|
|||||||||
|
Enterprise/Enterprise
Land & Reserve, Inc (7)
|
Kentucky
|
142.7 | 64.3 | 78.4 | 1.7 | 141.0 |
Steam
|
|||||||||
|
Callaway/Cobra
(8)
|
West
Virginia and Virginia
|
20.2 | 16.3 | 3.9 | 0.0 | 20.2 |
Steam
and Metallurgical
|
|||||||||
|
Totals
|
599.7 | 295.0 | 304.7 | 8.5 | 591.2 | |||||||||||
|
Percentages
|
49 | % | 51 | % | 1 | % | 99 | % | ||||||||
|
(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, which varies depending on rank of coal and processing
requirements.
|
|
(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
|
)
|
On
December 3, 2008, we announced the permanent closure of Kingwood, and the
mine stopped producing coal in early January 2009. Unmineable
reserves were written off at December 31, 2008.
|
|
|
(6
|
)
|
Includes
proven and probable reserve in West Virginia controlled by our
subsidiaries Brooks Run South and Riverside Mining Company
|
|
|
(7
|
)
|
Includes
proven and probable reserves in Kentucky controlled by our subsidiary
Enterprise Land & Reserve Inc obtained from the Progress Energy
acquisition.
|
|
|
(8
|
)
|
Includes
proven and probable reserves controlled by Cobra Natural Resource obtained
from the Mingo Logan Ben’s Creek Complex
acquisition.
|
The following map shows the locations
of Alpha's properties as of December 31, 2008 for each of our eight regional
business units:
See
Item 1, “Business”, for additional information regarding our coal
operations and properties.
|
Legal
Proceedings
|
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 WVDOH
and NCI, which became our wholly-owned indirect subsidiary as a result of 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 the WVDOH and the Federal Highway
Administration (which is now a party to the suit) could not, under the
circumstances of this case, enter into a contract that did not require the
contractor to pay 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 the end of the first quarter of 2010. We anticipate
that the most likely remedy is a directive that the contract be renegotiated for
such payment. If that renegotiation occurs, the WVDOH has committed to agree,
and NCI has a contractual right to insist, that additional costs resulting from
the order will be reimbursed by the WVDOH. Accordingly, we do not
believe that we will incur any monetary expense as a result of this ruling. As
of December 31, 2008, we have a $7.9 million long-term receivable for the
recovery of these costs from the WVDOH and a $7.9 million long-term liability
for the potential obligations under the ruling.
Cliffs
Proposed Acquisition
On July
15, 2008, we entered into a definitive merger agreement pursuant to which, and
subject to the terms and conditions thereof, Cliffs would acquire all of our
outstanding shares. Under the terms of the agreement, for each share of
our common stock, stockholders would receive 0.95 Cliffs' common shares and
$22.23 in cash. The proposed merger required approval of each company’s
stockholders, for which special meetings were scheduled to take place on
November 21, 2008. On November 3, 2008, we commenced litigation
against Cliffs by filing an action in the Delaware Court of Chancery to obtain
an order to require Cliffs to hold its meeting as scheduled. Later in
November, each company’s Board of Directors, after considering various issues,
including the then current macroeconomic environment, uncertainty in the steel
industry, shareholder dynamics and risks and costs of potential litigation,
determined that settlement of the litigation and termination of the merger
agreement was in the best interests of its equity holders. As a
result, on November 17, 2008, we and Cliffs mutually terminated the merger
agreement and settled the litigation. The terms of the settlement
agreement included a $70.0 million payment from Cliffs to us which, net of
transaction costs, resulted in a gain of $56.3 million.
|
Submission
of Matters to a Vote of Security
Holders
|
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,
2008.
PART II
|
Market
for Registrant's Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
|
The
initial public offering of our common stock occurred 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.
|
2008
|
High
|
Low
|
|||||
|
First
Quarter
|
$ | 43.48 | $ | 24.11 | |||
|
Second
Quarter
|
104.29 | 41.29 | |||||
|
Third
Quarter
|
104.93 | 43.41 | |||||
|
Fourth
Quarter
|
47.69 | 14.68 | |||||
|
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 | |||||
As of
December 31, 2008, there were approximately 2,437 registered holders of record
of our common stock, including 210 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, and we currently do not anticipate
paying any dividends in the foreseeable future.
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,
2008.
|
You are
cautioned against drawing any conclusions from the data contained in this graph,
as past results are not necessarily indicative of future
performance. The indices used are included for comparative purposes
only and do not indicate an opinion of management that such indices are
necessarily an appropriate measure of the relative performance of our
stock.
|
Company
Name
|
2/15/2005
|
Mar-05
|
Jun-05
|
Sep-05
|
Dec-05
|
Mar-06
|
Jun-06
|
Sep-06
|
Dec-06
|
Mar-07
|
Jun-07
|
Sep-07
|
Dec-07
|
Mar-08
|
Jun-08
|
Sep-08
|
Dec-08
|
|
|
ANR
|
100.00
|
126.36
|
105.25
|
132.40
|
84.66
|
101.99
|
86.47
|
69.46
|
62.71
|
68.88
|
91.63
|
102.38
|
143.15
|
191.45
|
459.63
|
226.66
|
71.35
|
|
|
Russell
3000
|
100.00
|
97.93
|
100.13
|
104.15
|
106.29
|
111.98
|
109.79
|
114.88
|
123.08
|
124.68
|
131.89
|
133.92
|
129.46
|
117.15
|
115.20
|
105.16
|
81.21
|
|
|
Russell
3000 Coal
|
100.00
|
107.24
|
118.35
|
171.33
|
159.53
|
177.61
|
199.53
|
132.57
|
140.33
|
148.87
|
176.40
|
172.69
|
240.01
|
222.73
|
413.76
|
184.22
|
88.53
|
|
|
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, 2008,
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. 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, 2008
|
Year
Ended
December
31, 2007
|
Year
Ended
December
31, 2006
|
Year
Ended
December
31, 2005
|
Year
Ended
December
31, 2004
|
||||||||||||||||
|
(In
thousands, except per share and per ton amount)
|
||||||||||||||||||||
|
Statement
of Operations Data:
|
||||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||
|
Coal
revenues
|
$ | 2,219,291 | $ | 1,647,505 | * | $ | 1,681,434 | * | $ | 1,413,174 | $ | 1,079,981 | ||||||||
|
Freight
and handling revenues
|
279,853 | 205,086 | 188,366 | 185,555 | 141,100 | |||||||||||||||
|
Other
revenues
|
54,980 | 33,241 | ** | 34,743 | 27,926 | 28,347 | ||||||||||||||
|
Total
revenues
|
2,554,124 | 1,885,832 | 1,904,543 | 1,626,655 | 1,249,428 | |||||||||||||||
|
Costs
and expenses:
|
||||||||||||||||||||
|
Cost
of coal sales (exclusive of items shown seperately below)
|
1,729,281 | 1,371,519 | * | 1,346,733 | * | 1,184,092 | 920,359 | |||||||||||||
|
Gain
on sale of coal reserve
|
(12,936 | ) | - | - | - | - | ||||||||||||||
|
(Increase)
decrease in fair value of derivative instruments, net
|
47,265 | (8,925 | ) * | (402 | ) * | - | - | |||||||||||||
|
Freight
and handling costs
|
279,853 | 205,086 | 188,366 | 185,555 | 141,100 | |||||||||||||||
|
Cost
of other revenues
|
40,857 | 22,715 | ** | 22,982 | 23,675 | 22,994 | ||||||||||||||
|
Depreciation,
depletion and amortization
|
171,963 | 159,574 | ** | 140,851 | 73,122 | 55,261 | ||||||||||||||
|
Mine
closure/asset impairment charges
|
30,172 | - | - | - | - | |||||||||||||||
|
Selling,
general, and administrative expenses (exclusive of depreciation and
amortization shown separately above)
|
71,923 | 58,485 | ** | 67,952 | 88,132 | 40,607 | ||||||||||||||
|
Total
costs and expenses
|
2,358,378 | 1,808,454 | 1,766,482 | 1,554,576 | 1,180,321 | |||||||||||||||
|
Income
from operations
|
195,746 | 77,378 | 138,061 | 72,079 | 69,107 | |||||||||||||||
|
Other
income (expense):
|
||||||||||||||||||||
|
Interest
expense
|
(40,398 | ) | (40,366 | ) ** | (41,774 | ) | (29,937 | ) | (20,041 | ) | ||||||||||
|
Interst
income
|
7,352 | 2,266 | ** | 839 | 1,064 | 531 | ||||||||||||||
|
Loss
on early extinguishment of debt
|
(14,702 | ) | - | - | - | - | ||||||||||||||
|
Gain
on termination of Cliffs' merger
|
56,315 | - | - | - | - | |||||||||||||||
|
Miscellaneous
income (expense)
|
(3,829 | ) | (93 | ) | 523 | 91 | 722 | |||||||||||||
|
Total
other income (expense) net
|
4,738 | (38,193 | ) | (40,412 | ) | (28,782 | ) | (18,788 | ) | |||||||||||
|
Income
from continuing operations before income taxes
|
200,484 | 39,185 | 97,649 | 43,297 | 50,319 | |||||||||||||||
|
Income
tax (expense) benefit
|
(39,139 | ) | (9,195 | ) ** | 30,519 | (18,953 | ) | (5,150 | ) | |||||||||||
|
Minority
interest
|
- | - | - | (2,918 | ) | (22,781 | ) | |||||||||||||
|
Income
from continuing operations
|
161,345 | 29,990 | 128,168 | 21,426 | 22,388 | |||||||||||||||
|
Discontinued
operations:
|
||||||||||||||||||||
|
Loss
from discontinued operations
|
(8,273 | ) | (3,000 | ) | - | (213 | ) | (2,373 | ) | |||||||||||
|
Minority interest on the loss from discontinued operations
|
490 | 179 | - | - | - | |||||||||||||||
|
Gain
on sale of discontinued operations
|
13,622 | - | - | - | - | |||||||||||||||
|
Income
tax (expense) benefit
|
(1,647 | ) | 565 | - | - | - | ||||||||||||||
|
Income
(loss) from discontinued operations
|
4,192 | (2,256 | ) | - | (213 | ) | (2,373 | ) | ||||||||||||
|
Net
income
|
$ | 165,537 | $ | 27,734 | $ | 128,168 | $ | 21,213 | $ | 20,015 | ||||||||||
|
*Adjusted
from amounts reported in prior periods to exclude changes in the fair
value of derivative instruments, which are now recorded as a component of
costs and expenses, to conform to current year income statement
presentation. The adjustments have no effect on previously reported income
from operations or net income.
|
||||||||||||||||||||
|
**
Adjusted from amounts reported in prior periods to exclude discontinued
operations related to our sale of Gallatin.
|
||||||||||||||||||||
|
Alpha
Natural Resources, Inc and Subsidiaries
|
ANR
FUND IX Holdings, L.P. and Alpha NR Holding, Inc. and
Subsidiaries
|
|||||||||||||||||||
|
Year
Ended
December
31, 2008
|
Year
Ended
December
31, 2007
|
Year
Ended
December
31, 2006
|
Year
Ended
December
31, 2005
|
Year
Ended
December
31, 2004
|
||||||||||||||||
|
(In
thousands, except per share and per ton amount)
|
||||||||||||||||||||
|
Earnings
Per Share Data:
|
||||||||||||||||||||
|
Net
income (loss) per share, as adjusted (1)
|
||||||||||||||||||||
|
Basic
earnings per share:
|
||||||||||||||||||||
|
Income
from continuing operations
|
$ | 2.36 | $ | 0.46 | $ | 2.00 | $ | 0.38 | $ | 1.52 | ||||||||||
|
Income
(loss) from discontinued operations
|
0.06 | (0.03 | ) | - | - | (0.16 | ) | |||||||||||||
|
Net
income per basic share
|
$ | 2.42 | $ | 0.43 | $ | 2.00 | $ | 0.38 | $ | 1.36 | ||||||||||
|
Diluted
earnings per share:
|
||||||||||||||||||||
|
Income
from continuing operations
|
$ | 2.30 | $ | 0.46 | $ | 2.00 | $ | 0.35 | $ | 0.25 | ||||||||||
|
Income
(loss) from discontinued operations
|
0.06 | (0.03 | ) | - | - | (0.07 | ) | |||||||||||||
|
Net
income per diluted share
|
$ | 2.36 | $ | 0.43 | $ | 2.00 | $ | 0.35 | $ | 0.18 | ||||||||||
|
Pro
forma net Income (loss) per share, as adjusted (2)
|
||||||||||||||||||||
|
Basic
and diluted earnings per share:
|
||||||||||||||||||||
|
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, 2008
|
Year
Ended
December
31, 2007
|
Year
Ended
December
31, 2006
|
Year
Ended
December
31, 2005
|
Year
Ended
December
31, 2004
|
||||||||||||||||
|
(in
thousands, except per share amounts)
|
||||||||||||||||||||
|
Balance
sheet data (at period end):
|
||||||||||||||||||||
|
Cash
and cash equivalents
|
$ | 676,190 | $ | 54,365 | $ | 33,256 | $ | 39,622 | $ | 7,391 | ||||||||||
|
Operating
and working capital
|
729,190 | 157,147 | 116,464 | 35,074 | 56,257 | |||||||||||||||
|
Total
assets
|
1,728,292 | 1,210,914 | 1,145,793 | 1,013,658 | 477,121 | |||||||||||||||
|
Notes
payable and long-term debt, including current portion
|
539,145 | 446,913 | 445,651 | 485,803 | 201,705 | |||||||||||||||
|
Stockholders'
equity and partners' capital
|
725,677 | 380,836 | 344,049 | 212,765 | 45,933 | |||||||||||||||
|
Statement
of cash flows data:
|
||||||||||||||||||||
|
Net
cash provided by (used in):
|
||||||||||||||||||||
|
Operating
activities
|
$ | 458,043 | $ | 225,741 | $ | 210,081 | $ | 149,643 | $ | 106,776 | ||||||||||
|
Investing
activities
|
(77,625 | ) | (165,203 | ) | (160,046 | ) | (339,387 | ) | (86,202 | ) | ||||||||||
|
Financing
activities
|
241,407 | (39,429 | ) | (56,401 | ) | 221,975 | (24,429 | ) | ||||||||||||
|
Capital
expenditures
|
(137,751 | ) | (126,381 | ) | (131,943 | ) | (122,342 | ) | (72,046 | ) | ||||||||||
|
Other
data
|
||||||||||||||||||||
|
Production:
|
||||||||||||||||||||
|
Produced/processed
|
23,548 | 24,203 | 24,827 | 20,602 | 19,069 | |||||||||||||||
|
Purchased
|
4,818 | 4,189 | 4,090 | 6,284 | 6,543 | |||||||||||||||
|
Total
|
28,366 | 28,392 | 28,917 | 26,886 | 25,612 | |||||||||||||||
|
Tons
sold:
|
||||||||||||||||||||
|
Steam
|
16,414 | 17,565 | 19,050 | 16,674 | 15,836 | |||||||||||||||
|
Met
|
11,899 | 10,980 | 10,029 | 10,023 | 9,490 | |||||||||||||||
|
Total
|
28,313 | 28,545 | 29,079 | 26,697 | 25,326 | |||||||||||||||
|
Coal
sales realization/ton:
|
||||||||||||||||||||
|
Steam
|
$ | 51.23 | $ | 48.75 | * | $ | 48.73 | * | $ | 41.33 | $ | 32.66 | ||||||||
|
Met
|
$ | 115.85 | $ | 72.07 | $ | 75.09 | $ | 72.24 | $ | 59.31 | ||||||||||
|
Total
|
$ | 78.38 | $ | 57.72 | * | $ | 57.82 | * | $ | 52.93 | $ | 42.64 | ||||||||
|
Cost
of coal sales/ton (3)
|
$ | 61.08 | $ | 48.05 | * | $ | 46.31 | * | $ | 44.35 | $ | 36.34 | ||||||||
|
Coal
margin/ton (4)
|
$ | 17.30 | $ | 9.67 | * | $ | 11.51 | * | $ | 8.58 | $ | 6.30 | ||||||||
|
EBITDA
from continuing operations, as adjusted for 2005 and 2004
(5)
|
$ | 405,493 | $ | 236,859 | $ | 279,435 | $ | 145,197 | $ | 119,327 | ||||||||||
|
*Adjusted
from amounts reported in prior periods to exclude changes in the fair
value of derivative instruments, which are now recorded as a component of
costs and expenses, to conform to current year income statement
presentation. The adjustments have no effect on previously reported income
from operations or net income.
|
||||||||||||||||||||
|
(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. 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 and 2004 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 ANR Fund IX Holdings, L.P. and Alpha NR
Holding, Inc. (“FR Affiliates”) in exchange for their ownership in ANR
Holdings in connection with the Internal Restructuring had occurred as of
January 1, 2004. 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.
|
|||
|
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, 2004.
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.
|
|||
|
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 and 2004 are set forth below:
|
Year
Ended December 31,
|
||||||||
|
2005
|
2004
|
|||||||
|
(in
thousands, except share and per share amounts)
|
||||||||
|
Numerator:
|
||||||||
|
Reported
income from continuing operations
|
$ | 21,426 | $ | 22,388 | ||||
|
Deduct:
Income tax effect of ANR Fund IX Holdings, L.P. income from continuing
operations prior to Internal Restructuring
|
(91 | ) | (1,149 | ) | ||||
|
Income
from continuing operations, as adjusted
|
21,335 | 21,239 | ||||||
|
Reported
loss from discontinued operations
|
(213 | ) | (2,373 | ) | ||||
|
Add:
Income tax effect of ANR Fund IX Holdings, L.P. loss from discontinued
operations prior to Internal Restructuring
|
2 | 149 | ||||||
|
Loss
from discontinued operations, as adjusted
|
(211 | ) | (2,224 | ) | ||||
|
Net
income, as adjusted
|
$ | 21,124 | $ | 19,015 | ||||
|
Denominator:
|
||||||||
|
Weighted
average shares-- basic
|
55,664,081 | 13,998,911 | ||||||
|
Dilutive
effect of stock options and restricted stock grants
|
385,465 | - | ||||||
|
Weighted
average shares-- diluted
|
56,049,546 | 13,998,911 | ||||||
|
Net
income per share, as adjusted-- basic and diluted:
|
||||||||
|
Income
from continuing operations, as adjusted
|
$ | 0.38 | $ | 1.52 | ||||
|
Loss
from discontinued operations, as adjusted
|
- | (0.16 | ) | |||||
|
Net
income per share, as adjusted
|
$ | 0.38 | $ | 1.36 | ||||
|
(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
|
)
|
Excludes
changes in fair value of derivative instruments, freight & handling
costs, cost of other revenues, DD&A, SG&A, gain on sale of coal
reserves and mine closure cost/asset impairment
charges.
|
|
|
(4
|
)
|
Coal
revenue per ton less cost of coal sales per ton.
|
|
|
(5
|
)
|
EBITDA
from continuing operations is defined as income from continuing operations
plus interest expense, income tax expense (benefit), depreciation,
depletion and amortization, less interest income. EBITDA from continuing
operations, as adjusted, is EBITDA from continuing operations, further
adjusted for minority interest prior to our internal restructuring. EBITDA
from continuing operations and EBITDA from continuing operations, 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 from continuing operations and EBITDA from continuing operations,
as adjusted, are not calculated identically by all companies, our
calculation may not be comparable to similarly titled measures of other
companies.
|
EBITDA
from continuing operations and EBITDA from continuing operations, as adjusted,
are calculated as follows (unaudited, in thousands):
|
2008
|
2007
|
2006
|
2005
|
2004
|
||||||||||||||||
|
Income
from continuing operations
|
$ | 161,345 | $ | 29,990 | $ | 128,168 | $ | 21,213 | $ | 20,015 | ||||||||||
|
Interest
expense
|
40,398 | 40,366 | 41,774 | 29,937 | 20,041 | |||||||||||||||
|
Interest
income
|
(7,352 | ) | (2,266 | ) | (839 | ) | (1,064 | ) | (531 | ) | ||||||||||
|
Income
tax expense (benefit)
|
39,139 | 9,195 | (30,519 | ) | 18,860 | 3,960 | ||||||||||||||
|
Depreciation,
depletion, and amortization
|
171,963 | 159,574 | 140,851 | 73,405 | 56,012 | |||||||||||||||
|
EBITDA
from continuing operations
|
405,493 | 236,859 | 279,435 | 142,351 | 99,497 | |||||||||||||||
|
Minority
interest
|
- | - | - | 2,846 | 19,830 | |||||||||||||||
|
EBITDA
from continuing operations, as adjusted for 2005 and 2004
|
$ | 405,493 | $ | 236,859 | $ | 279,435 | $ | 145,197 | $ | 119,327 | ||||||||||
|
Management's
Discussion and Analysis of Financial Condition and Results of
Operations
|
You
should read the following discussion and analysis in conjunction with our
financial statements and related notes and our “Selected Historical Financial
Data” included elsewhere in this annual report.
Overview
We
produce, process and sell steam and metallurgical (met) coal from eight regional
business units, which, as of December 31, 2008, were supported by 34 active
underground mines, 27 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
also sell coal produced by others, the majority of which we process and/or blend
with coal produced from our mines prior to resale, providing us with a higher
overall margin for the blended product than if we had sold the coals separately.
Our sales of steam coal in 2008 and 2007 accounted for approximately 58% and
62%, respectively, of our annual coal sales volume, and our sales of
metallurgical coal in 2008 and 2007, which generally sells at a premium over
steam coal, accounted for approximately 42% and 38%, respectively, of our annual
coal sales volume. Our sales of steam coal during 2008 and 2007 were made
primarily to large utilities and industrial customers in the Eastern region of
the United States, and our sales of met coal during those years were made
primarily to steel companies in the Northeastern and Midwestern regions of the
United States and in several countries in Europe, Asia and South America.
Approximately 52% of our total revenue in 2008 and 37% of our sales revenue in
2007 was derived from sales made outside the United States, primarily in Brazil,
Egypt, Turkey, Russia and Canada.
In
addition, we generate other revenues from equipment and parts sales, equipment
repair, road construction, rentals, royalties, commissions, coal handling,
terminal and processing fees, and coal and environmental analysis fees. We also
record revenue for freight and handling charges incurred in delivering coal to
our customers, which we treat as being reimbursed by our customers. However,
these freight and handling revenues are offset by equivalent freight and
handling costs and do not contribute to our profitability.
Our
primary expenses are for wages and benefits, supply costs, repair and
maintenance expenditures, cost of purchased coal, royalties, freight and
handling costs, and taxes incurred in selling our coal. Historically, our cost
of coal sales per ton is lower for sales of our produced and processed coal than
for sales of purchased coal that we do not process prior to resale.
We have
one reportable segment, Coal Operations, which includes all of our revenues and
costs from coal production and sales, freight and handling, rentals,
commissions, coal handling and processing operations and coal recovery
incidental to our road construction operations. These revenues and costs
included in our Coal Operations segment are reported by us in our coal revenues
and cost of coal sales, except for the revenues and costs from rentals,
commissions, road construction, and coal handling and processing operations,
which we report in our other revenues and cost of other revenues,
respectively.
Business
Developments
Excelven Pty
Ltd. In December 2008, we recorded an impairment charge of
$4.5 million to write off the total remaining value of our 24.5% interest in
Excelven Pty Ltd. (“Excelven”) because we have exhausted all reasonable efforts
to obtain a mining permit from the Venezuelan government and concluded that it
is no longer reasonable to assume that a permit will be
granted. Excelven, through its subsidiaries, controls the rights to
the Las Carmelitas mining venture in Venezuela.
Kingwood Mining Company,
LLC. On December 3, 2008, we announced the permanent closure
of the Whitetail Kittanning Mine, an adjacent coal preparation plant and other
ancillary facilities. The mine stopped producing coal in early
January 2009 and Kingwood will cease equipment recovery operations by the end of
April 2009. The decision resulted from adverse geologic conditions
and regulatory requirements that rendered the coal seam unmineable at this
location. We recorded a charge of $30.2 million, which includes asset
impairment charges of $21.2 million, write off of advance mining royalties of
$3.8 million, which will not be recoverable, severance and other employee
benefit costs of $3.6 million and increased reclamation obligations of $1.9
million. Beginning with the first quarter of 2009 when the mining
operations at Kingwood cease, we will report the Kingwood’s results of
operations as a discontinued operation.
Cliffs Natural Resources, Inc
Proposed Merger. On July 15, 2008, we entered into a
definitive merger agreement pursuant to which, and subject to the terms and
conditions thereof, Cliffs would acquire all of our outstanding shares.
Under the terms of the agreement, for each share of our common stock,
stockholders would receive 0.95 Cliffs' common shares and $22.23 in cash.
The proposed merger required approval of each company’s stockholders, for which
special meetings were scheduled to take place on November 21,
2008. On November 3, 2008, we commenced litigation against Cliffs by
filing an action in the Delaware Court of Chancery to obtain an order to require
Cliffs to hold its meeting as scheduled. Later in November 2008, each
company’s Board of Directors, after considering various issues, including the
then current macroeconomic environment, uncertainty in the steel industry,
shareholder dynamics and risks and costs of potential litigation, determined
that settlement of the litigation and termination of the merger agreement was in
the best interests of its equity holders. As a result, on November
17, 2008, we and Cliffs mutually terminated the merger agreement and settled the
litigation. The terms of the settlement agreement included a $70.0
million payment from Cliffs to us, which net of transaction costs, resulted in a
gain of $56.3 million.
Progress Acquisition/Kentucky May. On May 1,
2006, we completed the acquisition of certain coal mining operations in eastern
Kentucky, including an estimated 73 million tons of reserves, from Progress
Fuels Corp, a subsidiary of Progress Energy, for $28.8 million, including an
adjustment 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 Alpha's Enterprise business unit and were integrated into
Enterprise. On September 30, 2008, we sold approximately 17.6 million
tons of underground coal reserves acquired in this acquisition to a private coal
producer for approximately $13.0 million in cash. We recognized a
gain of $12.9 million from the sale.
Gallatin Materials LLC. On December 28,
2006, our subsidiary, Palladian, acquired a 94% ownership interest in Gallatin,
a start-up lime manufacturing business in Verona, Kentucky. The
consideration for the 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 senior credit facility in the amount of $2.6 million to cover project
cost overruns. On September 26, 2008, we sold our interest in
Gallatin for cash in the amount of $45.0 million. The proceeds were
used in part to repay the Gallatin loan facility outstanding with NedBank
Limited in the amount of $18.2 million. An escrow balance of $4.5
million was established and we have agreed to indemnify and guarantee the buyer
against breaches of representations and warranties in the sale agreement and
contingencies that may have existed at closing and materialize within one year
from the date of the sale. We recorded a gain on the sale of $13.6
million in the third quarter of 2008. The results of operations for
Gallatin have been reported as discontinued operations.
Mingo Logan
Acquisition. On June 29, 2007, we completed the acquisition of
certain coal mining assets in western West Virginia known as Mingo
Logan from Arch Coal, Inc. for $43.9 million. 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.
Dominion Terminal
Associates. On April 30, 2008, our subsidiary, Alpha Terminal
Company, LLC, increased its equity ownership position in DTA from 32.5% to 40.6%
by making an additional investment of $2.8 million. DTA is a
20 million-ton annual capacity coal export terminal located in Newport
News, Virginia. This transaction maintains our largest ownership stake in the
facility, effectively increasing our coal export and terminaling capacity from
approximately 6.5 million tons to approximately 8.0 million tons
annually.
Common Stock and Convertible Debt
Offering. On April 7, 2008, we completed concurrent public
offerings of 4,181,817 shares of common stock at $41.25 per share and
$287.5 million aggregate principal amount of 2.375% convertible senior
notes due 2015 (the “convertible notes”). The aggregate net proceeds
from the common stock offering and the notes offering were $443.3 million after
commissions and expenses. We used the net proceeds from the offerings
in part to repurchase $175.0 million aggregate principal amount of the 10%
senior notes due 2012, co-issued by ANR LLC and Alpha Natural Resources Capital
Corp. As a result, in the second quarter of 2008, we recorded a loss
relating to the early extinguishment of debt of $14.7 million, consisting of
$10.7 million in tender offer consideration and $4.0 million in write off of
unamortized deferred debt issuance costs. On July 1, 2008, the
convertible notes became convertible at the option of the holders and remained
convertible through September 30, 2008. The notes were convertible
because our common stock exceeded the conversion threshold price of $71.06 per
share (130% of the applicable conversion price of $54.66 per share) for at least
twenty trading days within the thirty consecutive trading days ending June 30,
2008. As a result of the notes becoming convertible, in the second
quarter of 2008, we fully amortized the deferred debt issuance costs in the
amount of $8.9 million incurred with the issuance of the convertible
notes. Because the notes are not currently convertible, the notes are
classified as long-term.
Coal Pricing
Trends, Uncertainties and
Outlook
The
global financial crisis and economic slowdown have precipitated deep cuts in the
worldwide steel production, which caused met coal prices to decrease in the
fourth quarter of 2008 after the coal market experienced record increases in
prices during the second and third quarters of 2008. Given the duress
thatmost sectors of the global economy are suffering, and the impact on energy
demand, our immediate priorities entering 2009 are to maintain margins, preserve
cash flows and our sound financial position, and monitor the creditworthiness of
our suppliers and customers.
Although
steel production worldwide decreased 24% in the final quarter of 2008, we
believe that coke batteries that use metallurgical coals are, in general,
operating at higher capacity levels than steel blast furnaces. Some indicators
in the steel sector have turned favorable in the first weeks of 2009. For
example, steel service center inventories in the U.S. dropped 22% from August
2008 to the end of 2008 and stood at 15-year lows entering 2009, which should
help hasten the return of idle blast furnace capacity as service centers begin
to rebuild depleted inventories.
However,
with end-demand for steel products continuing to be hampered by the global
recession, a great deal of uncertainty remains. Of particular importance for our
remaining planned metallurgical coal production are the upcoming negotiations
for international met coal contracts. Currently we do not have any precise
indication where prices will settle out for the various coking coal qualities as
a result of these negotiations.
Because
of the marked change in market dynamics, certain agreements with our steel
customers that were entered into late in 2008 were restructured recently under
mutually acceptable terms. As of mid-January 2009, our total committed book of
metallurgical coal stood at 4.1 million tons, at an average realization of $108.
In addition, we begin 2009 with nearly 12 million tons, or 90%, of planned
thermal coal production committed and priced for 2009 at an average realization
per ton approximately $19 higher than the average of $51.23 for
2008.
At the
end of December 2008, we made several adjustments to our 2009 mine production
plans in response to weakened market conditions. We also plan to reduce outside
coal purchases and coal produced by third-party contractors, and defer small
expansion projects at several mines.
We are
exposed to market price risk in the normal course of purchasing and selling coal
and in the price paid for diesel fuel. As of December 31, 2008, we
had net unrealized losses on diesel fuel swap and put agreements and forward
purchase coal contracts of $41.9 million and $3.1 million, respectively, and net
unrealized gains on diesel fuel put options and forward sale coal contracts of
$5.2 million and $2.9 million, respectively, all of which met the definition of
a derivative under SFAS 133 and are marked to market. The $41.9
million liability for diesel fuel swaps and put agreements consists of
$25.1 million in accrued expenses and other current liabilities and $16.8
million in other liabilities on the balance sheet. The $3.1 million
liability for the forward purchase coal contracts is in accrued expense and
other current liabilities. The asset of diesel fuel put options and
forward sale coal contracts of $5.2 million and $2.9 million, respectively, are
recorded in prepaid expense and other current assets. Periodic
changes in fair value for these derivative instruments are recorded to the
income statement. Due to market price fluctuations, we could
experience significant earnings volatility related to coal contracts, diesel
fuel swap agreements, and diesel fuel put options that are classified as
derivatives.
Although
we experienced higher mine supply costs in 2008, especially increases in the
cost of diesel fuel and surcharges on steel for mine roof support, costs began
to decline sharply for some major supply categories late in that
year.
For
additional information regarding some of the risks and uncertainties that affect
our business, see Item 1A “Risks Factors.”
Year
Ended December 31, 2008 Compared to Year Ended December 31,
2007
Summary
For the
year ended December 31, 2008, we recorded total revenues of $2,554.1
million compared to $1,885.8 million for the year ended December 31,
2007, an increase of $668.3 million. Net income increased from
$27.7 million in 2007 to $165.5 million in 2008 and income from
continuing operations increased $131.3 million from $30.0 million to
$161.3 million. Coal margin, which we define as coal revenues
less cost of coal sales, divided by coal revenues, increased from 16.8% in 2007
to 22.1% in 2008.
During
the third quarter of 2008, we sold our interest in Gallatin and its operating
results have been reported as discontinued operations for all
periods.
Included
in 2008 income from continuing operations before income taxes were the following
items:
|
|
·
|
$56.3
million net gain on the termination fee we received from Cliffs relating
to the planned merger;
|
|
|
·
|
$47.3
million in unrealized losses related to changes in the fair value of
derivative contracts;
|
|
|
·
|
$30.2
million charge related to the closing of the Whitetail Kittanning mine
complex;
|
|
|
·
|
$14.7
million for a loss on early extinguishment of debt from the repurchase of
our 10% senior notes due 2012;
|
|
|
·
|
$12.9
million gain from the sale of our Kentucky May underground coal
reserves;
|
|
|
·
|
$12.3
million charge related to a coal contract settlement, which was recorded
as a reduction of revenue;
|
|
|
·
|
$8.9
million of non-cash interest expense from the full amortization of debt
issuance costs related to our convertible
notes;
|
|
|
·
|
$8.5
million charge related to our employee appreciation and retention
programs; and
|
|
|
·
|
$4.5
million impairment charge related to our Excelven
investment.
|
Included
in 2007 income from continuing operations before income taxes were the following
items:
|
|
·
|
$8.9
million in unrealized gains related to changes in the fair value of
derivative contracts;
|
|
|
·
|
$2.1
million write off of development costs at an underground mine that was
abandoned;
|
|
|
·
|
$1.4
million credit related to an insurance settlement for damages caused by
Hurricane Katrina; and
|
|
|
·
|
$1.2
million charge related to a loss in equity earnings from our Excelven
investment.
|
Revenues
|
Increase
|
||||||||||||
|
Year
Ended December 31,
|
(Decrease)
|
|||||||||||
|
2008
|
2007
|
$
or Tons
|
%
|
|||||||||
|
(in
thousands, except per ton data)
|
||||||||||||
|
Coal
revenues
|
$
|
2,219,291
|
$
|
1,647,505
|
*
|
$
|
571,786
|
35%
|
||||
|
Freight
and handling revenues
|
279,853
|
205,086
|
74,767
|
36%
|
||||||||
|
Other
revenues
|
54,980
|
33,241
|
**
|
21,739
|
65%
|
|||||||
|
Total
revenues
|
$
|
2,554,124
|
$
|
1,885,832
|
$
|
668,292
|
35%
|
|||||
|
Tons
sold:
|
||||||||||||
|
Steam
|
16,414
|
17,565
|
(1,151
|
)
|
-7%
|
|||||||
|
Metallurgical
|
11,899
|
10,980
|
919
|
8%
|
||||||||
|
Total
|
28,313
|
28,545
|
(232
|
)
|
-1%
|
|||||||
|
Coal
sales realization per ton:
|
||||||||||||
|
Steam
|
$
|
51.23
|
$
|
48.75
|
*
|
$
|
2.48
|
5%
|
||||
|
Metallurgical
|
$
|
115.85
|
$
|
72.07
|
$
|
43.78
|
61%
|
|||||
|
Average
|
$
|
78.38
|
$
|
57.72
|
*
|
$
|
20.66
|
36%
|
||||
|
*Adjusted
from amounts reported in prior periods to exclude changes in the fair
value of derivative instruments, which are now recorded as a component of
costs and expenses, to conform to current year income statement
presentation. The adjustments have no effect on previously reported income
from operations or net income.
|
||||||||||||
|
**
Adjusted from amounts reported in prior periods to exclude discontinued
operations related to our sale of
Gallatin.
|
||||||||||||
Coal revenues. Coal revenues
increased for the year ended December 31, 2008 by $571.8 million or
35%, to $2,219.3 million, as compared to the year ended December 31,
2007. This increase was due primarily to a $20.66 per ton increase in the
average sales price of our coal, partially offset by a decrease of
0.2 million tons sold in 2008. Tons sold decreased from 28.5 million
tons in 2007 to 28.3 million tons in 2008 mainly due to a decrease in steam
tons sold mostly offset by an increase in met tons sold. Our met coal
realization per ton increased by 61% from $72.07 per ton to $115.85 per ton, and
steam coal realization per ton increased by 5% from $48.75 per ton to $51.23 per
ton. Included in our steam coal revenues for 2008 is a charge of
$12.3 million related to a settlement of a liability incurred under the default
provisions of a coal contract, which reduced our steam coal realization per ton
by $0.75. The increase in met coal realizations during 2008 was
mainly attributable to the global demand for hard coking coals caused by
supplier production and logistics issues in Eastern Europe and
Australia. During the fourth quarter of 2008, global demand for coal
significantly declined due to the global economic slowdown. Our sales mix of met
coal and steam coal based on volume in 2008 was 42% and 58%, respectively,
compared with 38% and 62%, respectively, in 2007. In 2008,
approximately 62% of our coal revenues were derived from the sale of
metallurgical coal compared with only 48% in 2007.
Freight and handling
revenues. Freight and handling revenues increased to $279.9 million
for the year ended December 31, 2008, an increase of $74.8 million
compared to the year ended December 31, 2007 due to an increase in freight
costs, arising primarily from vessel freight and fuel surcharges. These revenues
are offset by equivalent costs and do not contribute to our
profitability.
Other revenues. Other revenues
increased for the year ended December 31, 2008 by $21.7 million, or 65%, to
$55.0 million, as compared to the same period for 2007. Revenues from our
road construction operations were $28.1 million, a $7.7 million increase
mainly due to higher revenues from our largest ongoing road construction
project. Coal processing and terminal revenues increased $9.1 million
due to higher volumes. Maxxim Rebuild revenues increased $3.7 million
mainly due to higher equipment sales. Other revenues attributable to
our Coal Operations segment for the years ended December 31, 2008 and
2007 were $9.7 million and $4.6 million,
respectively.
Costs
and expenses
|
Increase
|
|||||||||||||
|
Year
Ended December 31,
|
(Decrease)
|
||||||||||||
|
2008
|
2007
|
$
|
%
|
||||||||||
|
(in
thousands, except per ton data)
|
|||||||||||||
|
Cost
of coal sales (exclusive of items shown separately below)
|
$
|
1,729,281
|
$
|
1,371,519
|
*
|
$
|
357,762
|
26%
|
|||||
|
Gain
on sale of coal reserves
|
(12,936
|
) |
-
|
(12,936
|
)
|
N/A
|
|||||||
|
(Increase)
decrease in fair value of derivative instruments, net
|
47,265
|
(8,925
|
) |
*
|
56,190
|
NM
|
|||||||
|
Freight
and handling costs
|
279,853
|
205,086
|
74,767
|
36%
|
|||||||||
|
Cost
of other revenues
|
40,857
|
22,715
|
**
|
18,142
|
80%
|
||||||||
|
Depreciation,
depletion and amortization
|
171,963
|
159,574
|
**
|
12,389
|
8%
|
||||||||
|
Mine
closure/asset impairment charges
|
30,172
|
-
|
30,172
|
N/A
|
|||||||||
|
Selling,
general and administrative expenses (exclusive of depreciation and
amortization shown separately above)
|
71,923
|
58,485
|
**
|
13,438
|
23%
|
||||||||
|
Total
costs and expenses
|
$
|
2,358,378
|
$
|
1,808,454
|
$
|
549,924
|
30%
|
||||||
|
Cost
of coal sales per ton:
|
|||||||||||||
|
Company
mines
|
$
|
56.01
|
$
|
46.79
|
*
|
$
|
9.22
|
20%
|
|||||
|
Contract
mines (including purchased and processed)
|
$
|
70.87
|
$
|
51.56
|
$
|
19.31
|
37%
|
||||||
|
Total
produced and processed
|
$
|
58.14
|
$
|
47.59
|
*
|
$
|
10.55
|
22%
|
|||||
|
Purchased
and sold without processing
|
$
|
75.13
|
$
|
50.74
|
*
|
$
|
24.39
|
48%
|
|||||
|
Cost
of coal sales per ton
|
$
|
61.08
|
$
|
48.05
|
*
|
$
|
13.03
|
27%
|
|||||
|
*Adjusted
from amounts reported in prior periods to exclude changes in the fair
value of derivative instruments, which are now recorded as a component of
costs and expenses, to conform to current year income statement
presentation. The adjustments have no effect on previously reported income
from operations or net income.
|
|||||||||||||
|
**
Adjusted from amounts reported in prior periods to exclude discontinued
operations related to our sale of
Gallatin.
|
|||||||||||||
Cost of coal sales. Our cost
of coal sales increased by $357.8 million, ($13.03 per ton), from $1,371.5
million, ($48.05 per ton) in the year ended December 31, 2007 to
$1,729.3 million, ($61.08 per ton), in the year ended December 31, 2008.
Our cost of coal sales per ton for our produced and processed coal was $58.14
per ton in 2008 as compared to $47.59 per ton in 2007. This increase is
attributable mainly to increases in the price of coal purchases at our plants,
diesel fuel, labor and benefits, supplies and maintenance and royalties and
severance taxes. The cost of sales per ton of our purchased coal was $75.13
per ton in 2008 and $50.74 per ton in 2007. This increase in costs is mainly due
to market conditions, which exerted upward pricing pressures due to a decrease
in market supply and an increase in market demand, both domestically and
internationally for coal. Approximately 65% of our purchased coal
sold during 2008 was blended with our produced and processed coal prior to
resale.
Gain on sale of coal
reserves. Gain on sale of coal reserves of $12.9 million
relates to the sale of a portion of our Kentucky May underground coal
reserves.
(Increase) decrease in fair
value of derivative instruments, net. The changes in fair value for
certain forward purchase and forward sale coal contracts, diesel fuel swap and
put agreements which are considered derivatives increased total costs and
expenses by $47.3 million in 2008 and decreased total costs and expenses by $8.9
million in 2007. The decrease in fair value of derivative instruments in
2008 included decreases in fair value of diesel fuel swap and put agreements and
decreases in the fair value of forward purchase coal contracts in the amounts of
$38.0 million and $14.3 million, respectively, partially offset by
an increase in fair value of forward sale coal contracts of $5.0 million.
The net unrealized loss on our balance sheet at December 31, 2008 for our
forward purchase and forward sale coal contracts of $0.2 million will reverse
into the income statement in future periods when we ultimately take delivery of
the coal under these contracts and sell it to our customers, resulting in lower
costs of sales in future periods.
Freight and handling costs.
Freight and handling costs increased $74.8 million to $279.9 million
during 2008 as compared to 2007 due to an increase in export tons and freight
costs, arising primarily from vessel freight and fuel surcharges. These costs
were offset by an equivalent amount of freight and handling
revenue.
Cost of other revenues. Cost of other
revenues increased $18.1 million, or 80%, to $40.9 million for the year
ended December 31, 2008 as compared to 2007 due to increases in costs from
our coal processing and terminal operations, our road construction operations,
and Maxxim Rebuild of $7.5 million, $6.8 million, and $4.0 million,
respectively. The increase in costs is primarily related to a
corresponding increase in revenues.
Depreciation, depletion and
amortization. Depreciation, depletion, and amortization increased
$12.4 million, or 8%, to $172.0 million for the year ended
December 31, 2008 as compared to 2007. Depreciation, depletion and
amortization attributable to our Coal Operations segment were
$164.1 million in 2008 and $152.3 million in 2007. Depreciation, depletion
and amortization per ton sold for our produced and processed coal increased from
$6.24 per ton for the year ended December 31, 2007 to $7.00 per
ton in the same period of 2008. The increase was mainly due to our
acquisitions, an increased depletion expense due to higher production at one of
our mines which also had an increase in depletion rate per ton due to a change
in estimated recoverable coal reserves in the third quarter of 2007, and an
increase due to capital additions.
Mine closure/asset impairment
charges. Mine closure/asset impairment charges of $30.2
million relates to our permanent closure of the Whitetail Kittanning Mine in
2009. These charges primarily consist of asset impairment charges of
$21.2 million, write off of advance mining royalties of $3.8 million, which will
not be recoverable, severance and other employee benefit costs of $3.6 million
and an increase in reclamation obligations of $1.9 million.
Selling, general and administrative
expenses. Selling, general and administrative expenses (SG&A)
increased $13.4 million, or 23%, to $71.9 million for the year ended
December 31, 2008 compared to 2007 is primarily due to increases in
share-based compensation expense of $2.6 million, incentive compensation accrual
of $4.8 million, wages and benefits of $3.6 million and travel and entertainment
of $0.6 million. Our SG&A expenses as a percentage of total revenues
decreased from 3.1% in 2007 to 2.8% in 2008.
Interest expense. Interest
expense for 2008 was $40.4 million, remaining flat compared with interest
expense of $40.4 million in 2007. Included in interest expense for
2008 is an $8.9 million non-cash interest expense resulting from the full
amortization of deferred debt issuance costs incurred in connection with the
issuance of our $287.5 million aggregate principal amount of our convertible
notes, which became convertible at the option of the holders beginning July
1, 2008. The increase in interest expense was offset by a significant
reduction in interest rates on our debt as a result of the repayment of $175.0
million outstanding principal amount of our 10% senior notes due
2012.
Interest income. Interest
income increased by $5.1 million for the year ended December 31, 2008 compared
to 2007. The increase is mainly due to a significant increase in our invested
cash from our concurrent public offerings of $287.5 million aggregate principal
amount of our convertible notes and $172.5 million common stock, as well as cash
generated from operations.
Loss on early extinguishment of
debt. Loss on early extinguishment of debt of $14.7 million consists of
$10.7 million in tender offer consideration payment for the repurchase of our
$175.0 million 10% senior notes and the write off of the unamortized deferred
debt issuance costs of $4.0 million.
Net gain on termination of Cliffs’
merger. Net gain on termination of Cliffs’ merger of $56.3
million consists of the $70.0 million fee we received from Cliffs upon
termination of the planned merger less $13.7 million in transaction costs,
including fees paid to our financial advisor, and legal and other professional
fees.
Miscellaneous expense,
net. Miscellaneous expense, net of $3.8 million is primarily
related to the impairment charge of $4.5 million related to our equity
investment in the Excelven joint venture in Venezuela.
Income tax expense (benefit).
Income tax expense from continuing operations for the year ended December
31, 2008 was $39.1 million as compared to income tax expense of $9.2
million for the year ended December 31, 2007. Our effective tax rates from
continuing operations for the year ended December 31, 2008 and 2007 were
19.5% and 23.5%, respectively. The effective tax rate for 2008 was lower than
the statutory federal tax rate due primarily to the tax benefits associated with
percentage depletion and the domestic production activities deduction, partially
offset by state income taxes, and the change in the valuation
allowance.
The
effective tax rate for 2007 was lower than the statutory federal tax rate due
primarily to the tax benefits associated with percentage depletion, partially
offset by state income taxes, change in the valuation allowance, and share-based
compensation charges which are not deductible for tax purposes.
The
effective tax rate for 2008 was lower than the effective tax rate for 2007
mainly due to a benefit from utilization of tax basis on assets sold,
utilization of other deferred tax assets, and an increase in the manufacturing
deduction, offset in part by a smaller benefit from the percentage depletion
deduction.
In the
second quarter of 2008, we recognized a benefit for a portion of the valuation
allowance that existed at the beginning of the year, based on positive evidence
regarding the ability to realize our deferred tax assets in the
future. In the fourth quarter of 2008, due to significant changes in
the economic landscape and our projections of our Alternative Minimum Tax
liability, we reestablished our previous valuation allowance on deferred tax
assets.
We have
concluded that it is more likely than not that our deferred tax assets, net of
valuation allowances, currently recorded will be realized. The amount of the
valuation allowance takes into consideration the Alternative Minimum Tax system
as required by SFAS No. 109, Accounting for Income Taxes,
(“SFAS 109”). We monitor the valuation allowance each quarter and make
adjustments to the allowance as appropriate.
Discontinued
operations. Income from discontinued operations of $4.2 million
consists of losses from the operation of Gallatin of $7.8 million, net of
minority interest, a gain on the sale of our interest in Gallatin of $13.6
million, and an income tax expense of $1.6 million, compared to a loss from
discontinued operations of $2.3 million in 2007.
Year
Ended December 31, 2007 Compared to Year Ended December 31,
2006
Summary
For the
year ended December 31, 2007, we recorded revenues of $1,885.8 million
compared to $1,904.5 million for the year ended December 31, 2006, a
decrease of $18.7 million. Net income decreased from $128.2 million in
2006 to $27.7 million in 2007 and income from operations decreased
$60.7 million to $77.4 million. Included in our 2007
results were a $1.4 million credit related to an insurance settlement for
damages caused by Hurricane Katrina, an unrealized gain related to changes in
mark-to-market valuations of $8.9 million for certain forward purchase and
forward sales contracts which are considered to be derivatives and are recorded
at fair value, a write off of development costs at an underground mine that was
abandoned of $2.1 million, and a charge of $1.2 million related to a loss in
equity earnings from our Venezuelan investment. Included in our 2006
results was a tax benefit from the reversal of a portion of our valuation
allowance for deferred tax assets in the amount of $55.6 million, after-tax
stock-based compensation charges of $12.8 million related to our IPO, as
well as $5.2 million after-tax charge for the buyout of a multi-year legacy coal
supply agreement. Tons sold decreased from 29.1 million tons in
2006 to 28.5 million tons in 2007 mainly due to a decrease in steam tons
sold. Coal margin, which we define as coal revenues less cost of coal sales,
divided by coal revenues, decreased from 19.9% in 2006 to 16.8% in
2007.
Revenues
|
Increase
|
|||||||||||||||
|
Year
Ended December 31,
|
(Decrease)
|
||||||||||||||
|
2007
|
2006
|
$
or Tons
|
%
|
||||||||||||
|
(in
thousands, except per ton data)
|
|||||||||||||||
|
Coal
revenues
|
$ | 1,647,505 | * | $ | 1,681,434 | * | $ | (33,929 | ) | -2 | % | ||||
|
Freight
and handling revenues
|
205,086 | 188,366 | 16,720 | 9 | % | ||||||||||
|
Other
revenues
|
33,241 | ** | 34,743 | (1,502 | ) | -4 | % | ||||||||
|
Total
revenues
|
$ | 1,885,832 | $ | 1,904,543 | $ | (18,711 | ) | -1 | % | ||||||
|
Tons
sold:
|
|||||||||||||||
|
Steam
|
17,565 | 19,050 | (1,485 | ) | -8 | % | |||||||||
|
Metallurgical
|
10,980 | 10,029 | 951 | 9 | % | ||||||||||
|
Total
|
28,545 | 29,079 | (534 | ) | -2 | % | |||||||||
|
Coal
sales realization per ton:
|
|||||||||||||||
|
Steam
|
$ | 48.75 | * | $ | 48.73 | * | $ | 0.02 | 0 | % | |||||
|
Metallurgical
|
$ | 72.07 | $ | 75.09 | $ | (3.02 | ) | -4 | % | ||||||
|
Average
|
$ | 57.72 | * | $ | 57.82 | * | $ | (0.10 | ) | 0 | % | ||||
|
*Adjusted
from amounts reported in prior periods to exclude changes in the fair
value of derivative instruments, which are now recorded as a component of
costs and expenses, to conform to current year income statement
presentation. The adjustments have no effect on previously reported income
from operations or net income.
|
|||||||||||||||
|
**
Adjusted from amounts reported in prior periods to exclude discontinued
operations related to our sale of Gallatin.
|
|||||||||||||||
Coal revenues. Coal revenues
decreased for the year ended December 31, 2007 by $33.9 million or 2%,
to $1,647.5 million, as compared to the year ended December 31, 2006.
This decrease was due primarily to a $0.10 per ton decrease in the average
sales price of our coal and a decrease of 0.5 million tons sold over the
comparable period last year. Tons sold decreased from 29.1 million tons in
2006 to 28.5 million tons in 2007 mainly due to a decrease in steam tons
sold. Met coal revenues per ton decreased by $3.02 to $72.07 per
ton and steam coal revenues per ton increased by $0.02 to an average of
$48.75 per ton. Our sales mix of met coal and steam coal based on volume in
2007 was 38% and 62%, respectively, compared with 34% and 66%, respectively, in
2006.
Freight and handling
revenues. Freight and handling revenues increased to $205.1 million
for the year ended December 31, 2007, an increase of $16.7 million
compared to the year ended December 31, 2006 due to an increase in freight
costs, arising primarily from vessel freight and fuel surcharges. These revenues
are offset by equivalent costs and do not contribute to our
profitability.
Other revenues. Other
revenues decreased for the year ended December 31, 2007 by
$1.5 million, or 4%, to $33.2 million, as compared to the same period
for 2006. Revenues from our road construction operations were $20.4 million, a
$3.6 million decrease mainly due to the completion of a portion of the King
Coal Highway in West Virginia in 2006, partially offset by increased revenue in
our ongoing road construction projects. Maxxim Rebuild revenues also
decreased $1.1 million due to reduced third-party selling
activity. These decreases were partially offset by an increase
in coal processing and terminal operations of $2.8 million. Other
revenues attributable to our Coal Operations segment for the years ended
December 31, 2007 and 2006 were $4.6 million and $2.7 million,
respectively.
Costs
and expenses
|
Increase
|
|||||||||||||||
|
Year
Ended December 31,
|
(Decrease)
|
||||||||||||||
|
2007
|
2006
|
$
|
%
|
||||||||||||
|
(in
thousands, except per ton data)
|
|||||||||||||||
|
Cost
of coal sales (exclusive of items shown separately below)
|
$ | 1,371,519 | * | $ | 1,346,733 | * | $ | 24,786 | 2 | % | |||||
|
(Increase)
decrease in fair value of derivative instruments, net
|
(8,925 | ) * | (402 | ) * | (8,523 | ) |
NM
|
||||||||
|
Freight
and handling costs
|
205,086 | 188,366 | 16,720 | 9 | % | ||||||||||
|
Cost
of other revenues
|
22,715 | ** | 22,982 | (267 | ) | -1 | % | ||||||||
|
Depreciation,
depletion and amortization
|
159,574 | ** | 140,851 | 18,723 | 13 | % | |||||||||
|
Selling,
general and administrative expenses
(exclusive
of depreciation and amortization shown separately above)
|
58,485 | ** | 67,952 | (9,467 | ) | -14 | % | ||||||||
|
Total
costs and expenses
|
$ | 1,808,454 | $ | 1,766,482 | $ | 41,972 | 2 | % | |||||||
|
Cost
of coal sales per ton:
|
|||||||||||||||
|
Company
mines
|
$ | 46.79 | * | $ | 42.82 | * | $ | 3.97 | 9 | % | |||||
|
Contract
mines (including purchased and processed)
|
$ | 51.56 | $ | 52.77 | $ | (1.21 | ) | -2 | % | ||||||
|
Total
produced and processed
|
$ | 47.59 | * | $ | 44.33 | * | $ | 3.26 | 7 | % | |||||
|
Purchased
and sold without processing
|
$ | 50.74 | * | $ | 57.46 | * | $ | (6.72 | ) | -12 | % | ||||
|
Cost
of coal sales per ton
|
$ | 48.05 | * | $ | 46.31 | * | $ | 1.74 | 4 | % | |||||
|
*Adjusted
from amounts reported in prior periods to exclude changes in the fair
value of derivative instruments, which are now recorded as a component of
costs and expenses, to conform to current year income statement
presentation. The adjustments have no effect on previously reported income
from operations or net income.
|
|||||||||||||||
|
**
Adjusted from amounts reported in prior periods to exclude discontinued
operations related to our sale of Gallatin.
|
|||||||||||||||
Cost of coal sales. For the
year ended December 31, 2007, our cost of coal sales increased by
$24.8 million to $1,371.5 million compared to the year ended
December 31, 2006. Our cost of coal sales increased as a result of
increased prices for labor, diesel fuel and other mine supplies, and the
performance and cost of contract mining services. In addition, our costs were
impacted due to lower productivity in 2007 when compared to 2006 mainly due to
an increase in our average surface mine overburden ratio and a decrease in clean
tons per foot in our deep mines. The average cost per ton sold increased 4% from
$46.31 per ton in 2006 to $48.05 per ton in 2007. Our cost of coal
sales as a percentage of coal revenues increased from 80% in 2006 to 83% in
2007. For the years ended December 31, 2007 and 2006 our average cost per
ton for our produced and processed coal sales was $47.59 and $44.33,
respectively. Our average cost per ton for coal that we purchased from third
parties and resold without processing was $50.74 and $57.46,
respectively.
(Increase) decrease in fair value of
derivative instruments, net. The changes in fair value for certain
forward purchase and forward sale coal contracts, which are considered
derivatives, decreased total costs and expenses by $8.9 million in 2007 and $0.4
million in 2006. The increase in fair value of derivative instruments in
2007 included increases in fair value of forward purchase coal contracts in the
amount of $17.2 million, partially offset by a decrease in fair value of forward
sale coal contracts of $8.3 million. The net unrealized gains on our balance
sheet at December 31, 2007 for our forward purchase and forward sale coal
contracts of $9.1 million will reverse into the income statement in future
periods when we ultimately take or provide delivery of the coal under these
contracts, resulting in higher costs of sales in future periods.
Freight and handling costs.
Freight and handling costs increased $16.7 million to $205.1 million
during 2007 as compared to 2006 due to an increase in freight costs, arising
primarily from vessel freight and fuel surcharges. These costs were offset by an
equivalent amount of freight and handling revenue.
Cost of other revenues. Cost
of other revenues decreased $0.3 million, or 1%, to $22.7 million for the
year ended December 31, 2007 as compared to 2006. The decrease
relates to Maxxim Rebuild’s outside sales activities and costs associated with
our road constructions operations, partially offset by higher coal processing
and terminal operation volumes. This decrease in cost for road
construction is due to the completion of a portion of the King Coal Highway in
West Virginia, partially offset by increased activity for ongoing construction
projects.
Depreciation, depletion and
amortization. Depreciation, depletion, and amortization increased
$18.7 million, or 13%, to $159.6 million for the year ended
December 31, 2007 as compared to the same period of 2006. Depreciation,
depletion and amortization attributable to our Coal Operations segment were
$152.3 million in 2007 and $131.9 million in 2006. Depreciation, depletion
and amortization per ton sold for our produced and processed coal increased from
$5.34 per ton for the year ended December 31, 2006 to $6.24 per
ton in the same period of 2007 mainly due to our acquisitions, increase in
depletion due to a change in estimated recoverable coal reserves at one of our
mines, and an increase due to capital additions.
Selling, general and administrative
expenses. Selling, general and administrative expenses (SG&A)
decreased $9.5 million, or 14%, to $58.5 million for the year ended
December 31, 2007 compared to the same period in 2006 and is primarily
due to a decrease in stock-based compensation charges of $12.8 million in 2006
related to our IPO. These charges ended at December 31, 2006. This decrease was
partially offset by an increase in legal and professional fees of $1.9 million
and increases in wages and benefits in the amount of $1.5 million driven by an
increase in wages and benefits and the additional expense related to our key
employee retention plan. Our SG&A expenses as a percentage of
total revenues decreased from 3.6% in 2006 to 3.1% in 2007.
Interest
expense. Interest expense decreased $1.4 million to
$40.4 million due to a decrease in our average amount of debt outstanding
in 2007.
Interest
income. Interest income increased $1.4 million to
$2.3 million. The increase is due to our average cash balance
increase.
Income tax expense
(benefit). Income tax expense from continuing operations for
the year ended December 31, 2007 was $9.2 million as compared to income tax
benefit of $30.5 million for the year ended December 31, 2006. Our
effective tax rates for the year ended December 31, 2007 and 2006 were
23.5% and (31.3%), respectively. The effective tax rate for 2007 was lower than
the statutory federal tax rate due primarily to the tax benefits associated with
percentage depletion, partially offset by state income taxes, change in the
valuation allowance, and share-based compensation charges which are not
deductible for tax purposes.
The
effective tax rate for 2006 was lower than the statutory federal tax rate due
primarily to the reversal of a portion of the valuation allowance for deferred
tax assets, the additional tax benefits associated with percentage depletion,
and the extraterritorial income exclusion - partially offset by non-deductible
stock-based compensation charges associated with the IPO and state income
taxes.
Since our
formation and through the third quarter of 2006, for purposes of evaluating the
need for a valuation allowance on deferred tax assets, we did not weigh
significantly our forecast of future taxable income (subjective evidence) as we
had not yet established an adequate earnings history (defined by us as at least
three years) to provide objective evidence of the ability to generate future
income. Accordingly, we had recorded a valuation allowance against a substantial
portion of our deferred tax asset. As of December 31, 2006, we had a three-year
history of cumulative earnings. As a result, we were able to place a higher
degree of reliance on our projections of future taxable income. Based on the
results of a comprehensive analysis completed in the fourth quarter of 2006, we
concluded that it was more likely than not that a portion of the deferred tax
asset previously reserved through a valuation allowance will be realized. As a
result, we recorded a tax benefit in the fourth quarter 2006 of $55.6
million. Excluding this reversal of the valuation allowance, the effective
tax rate would have been approximately 25.7% for 2006.
Discontinued
operations. Loss from discontinued operations of $2.3 million
consist of losses from the operation of Gallatin of $2.9 million, net of
minority interest and an income tax expense of $0.6 million.
Liquidity
and Capital Resources
Our
primary liquidity and capital resource requirements are to finance the cost of
our coal production and purchases, make capital expenditures, pay income taxes,
and service our debt and reclamation obligations. Our primary sources of
liquidity are cash flow from sales of our produced and purchased coal, other
revenue and borrowings under our credit facility.
On April
7, 2008, we completed concurrent offerings of 4.2 million shares of common stock
and $287.5 million aggregate principal amount of convertible notes. The
aggregate net proceeds from the common stock offering and the notes offering
were $443.3 million after commissions and expenses. We used the net
proceeds in part to repurchase $175.0 million aggregate principal amount of 10%
senior notes due 2012. In addition, we amended our credit facility on
March 28, 2008 to increase the amount available under the revolving line of
credit from $275.0 million to $375.0 million.
At
December 31, 2008, we had available liquidity of $968.6 million subject to
limitations described in our credit facility, including cash of $676.2 million
and $292.4 million available under our credit facility. Our total
indebtedness was $539.1 million at December 31, 2008, an increase of $92.2
million from December 31, 2007. The increase in the indebtedness is primarily
due to the offering of $287.5 million aggregate principal amount of our
convertible notes, as described above, offset by the repurchase of the $175.0
million aggregate principal amount of the 10% senior notes due 2012 and the
repayment of our Gallatin loan facility of $17.5 million. Our cash capital
expenditures for the year ended December 31, 2008 were $137.8 million,
and we expect to invest between $120.0 million and $142.0 million in cash
capital expenditures in 2009.
Based on
the terms of our outstanding insurance premium note payable, capital lease
obligations, and indebtedness as of December 31, 2008, projected 2009
payments of principal on capital lease obligations and indebtedness are
$18.9 million in the aggregate, of which $5.6 million, $5.8 million, $5.6
million and $1.9 million are due in each of the four quarters of 2009,
respectively. Based on our projection of cash to be generated from operations in
2009 and projected availability under our revolving line of credit, we believe
that cash from operations and available borrowings will be sufficient to meet
our working capital requirements, anticipated capital expenditures and debt
repayment requirements during each quarter of 2009.
The
global financial markets have been experiencing extreme disruption in recent
months, including, among other things, extreme volatility in security prices and
severely diminished liquidity and credit availability. We do not
believe we experienced any significant impact on our liquidity as a result of
these conditions during 2008, although the market price for our common shares
has declined substantially. We continue to monitor these developments
and the resulting impact on our business and our suppliers and customers
closely. We are unable to predict the likely duration and severity of
the current disruption in the financial markets, and a continuation or worsening
of the market disruption and economic downturn could impair our ability to
access the capital or credit markets or otherwise obtain financing.
Cash
Flows
Net cash
provided by operating activities, including discontinued operations, during 2008
was $458.0 million, an increase of $232.3 million from the
$225.7 million of net cash provided by operations during 2007. This
increase was driven by an increase in our net income of $137.8 million, an
increase in the change from 2007 to 2008 in non-cash charges and credits
included in net income in the amount of $90.7 million and an increase in cash
provided from changes in operating assets and liabilities of $3.8 million. The
increase in our net income was mainly due to an increase in our coal margin per
ton of $7.63 and a $45.3 million, after-tax, merger termination fee received
from Cliffs. The increase in non-cash charges and credits was
mainly driven by a $56.2 million increase in the change in the fair value of
derivative instruments from 2007 to 2008, and $34.7 million related to mine
closure and asset impairment charges. Net cash used in
operating activities from our discontinued operations during 2008 and 2007 was
$6.9 million and $1.4 million, respectively, which is included within net cash
provided by operating activities in the consolidated statements of cash
flows.
In
connection with the termination of the proposed merger with Cliffs in November
2008, Cliffs paid us a fee of $70.0 million. Net of fees paid to our financial
advisor, legal and other professional fees and expenses, the gain recognized on
the termination fee of the Cliffs proposed merger was approximately $56.3
million. This, in accordance with current accounting principles, is included in
our cash provided by operating activities on our consolidated statements of cash
flows for the year ended December 31, 2008. We have not received any similar
fees in recent prior years and do not anticipate receiving similar fees in the
future.
Net cash
used in investing activities, including discontinued operations, during 2008 was
$77.6 million, a decrease of $87.6 million from the $165.2 million of net
cash used in investing activities during 2007. The decrease was
primarily due to proceeds from the sale of Gallatin in the amount of $45.0
million and a $12.0 million increase in proceeds from the disposal of property,
plant, equipment and investments over the prior year, primarily resulting from
the Kentucky May sale, partially offset by increased capital expenditures of
$11.4 million and a decrease in cash used to acquire Mingo Logan in 2007 of
$43.9 million. Cash used in investing activities from our
discontinued operations during 2008 and 2007 was $4.9 million and $21.0
million, respectively, which was primarily used for capital
expenditures.
Net cash
provided by financing activities, including discontinued operations, during 2008
was $241.4 million, an increase of $280.8 million from the
$39.4 million of net cash used in financing activities during
2007. The increase was primarily due to the concurrent offerings of
our common stock and our convertible notes, which generated net proceeds of
$443.3 million after commissions and expenses, of which a portion was used to
repurchase the $175.0 million aggregate principal amount of 10% senior notes due
2012. Net cash (used in) provided by financing activities from our
discontinued operations during the year ended December 31, 2008 and 2007 were
($12.8) million, which includes the $17.5 million for the repayment of our
Gallatin loan facility, and $28.9 million, respectively.
Net
cash provided by operating activities in 2007 was $225.7 million, an increase of
$15.6 million from $210.1 million in 2006. Excluding the non-cash
deferred income tax benefit of $48.7 million in 2006, the increase in
2007 was due to an increase in non-cash items of $4.3 million and an increase in
cash provided from operating assets and liabilities of $63.0 million, partially
offset by a decrease in net income of $100.4 million.
Net
cash used in investing activities was $165.2 million in 2007, an increase of
$5.2 million from the $160.0 million in 2006. The increase in 2007
was primarily due to an increase in acquisition costs, mostly offset by
decreases in capital expenditures and disposals of property, plant and
equipment.
Net cash
used in financing activities was $39.4 million in 2007, a decrease of $17.0
million from $56.4 million in 2006. The decrease was primarily due to
a decrease in bank overdraft and lower payments on notes payable than
2006.
Credit
Facility and Long-term Debt
As of
December 31, 2008, our total long-term indebtedness, including capital
lease obligations, consisted of the following (in thousands):
|
December
31, 2008
|
||||
|
Term
loan
|
$
|
233,125
|
||
|
2.375%
convertible senior notes due 2015
|
287,500
|
|||
|
Insurance
premium financing
|
18,288
|
|||
|
Capital
lease obligation
|
232
|
|||
|
Total
long-term debt
|
539,145
|
|||
|
Less
current portion
|
18,520
|
|||
|
Long-term
debt net of current portion
|
$
|
520,625
|
||
Our
senior secured credit facility, entered into in October 2005, originally
consisted of a $250.0 million term loan facility and a $275.0 million revolving
credit facility. The term loan will mature in October 2012, and the revolving
credit facility will terminate in October 2010.
On
March 28, 2008, Alpha Natural Resources, Inc. (the “Parent”) and Alpha
Natural Resources, LLC (“ANR LLC”) entered into an amendment to the related
credit agreement to increase the amount available under the revolving credit
portion of the facility from $275.0 million to
$375.0 million. As of December 31, 2008, there was $292.4
million available under the revolving credit facility.
On
March 31, 2008, the Parent and ANR LLC entered into another amendment to
the credit agreement to, among other things, delete the covenant that restricted
the Parent from engaging in any business or activity other than certain
specified activities, remove the Parent from the application of all of the other
negative covenants in the credit facility and to impose on the Parent certain
other restrictive covenants in lieu of the original negative
covenants.
On
October 6, 2008, the Parent and ANR LLC entered into a further amendment to the
credit agreement. This amendment included certain technical
amendments to permit ANR LLC and certain of its affiliates to enter into a
permitted receivables financing, as well as an increase in the limit on annual
capital expenditures from $150 million to $200 million.
As
amended, the credit agreement imposes certain restrictions on ANR LLC and its
restricted subsidiaries, including, subject to certain exceptions, restrictions
on their ability to: incur debt; grant liens; enter into agreements with
negative pledge clauses; provide guarantees in respect of obligations of any
other person; make loans, investments, advances and acquisitions; sell assets;
pay dividends or make distributions, make redemptions and repurchases of capital
stock; make capital expenditures; prepay, redeem or repurchase debt; liquidate
or dissolve; engage in mergers or consolidations; engage in affiliate
transactions; change businesses; change fiscal year; amend certain debt and
other material agreements; issue and sell capital stock of subsidiaries; engage
in sale and leaseback transactions; and restrict distributions from
subsidiaries. The credit agreement also requires ANR LLC to satisfy
two financial performance covenants: a maximum leverage ratio and a
minimum interest coverage ratio, as described below.
The
restrictions imposed on the Parent include restrictive covenants that prohibit
the Parent from: (i) changing its fiscal year, (ii) acquiring capital
stock in any other person other than ANR LLC or granting liens on the capital
stock of ANR LLC, (iii) acquiring any division of or assets constituting a
line of business of any other person or engaging in any line of business and
(iv) incurring any debt, except that the Parent may incur debt as long as
ANR LLC would be in pro forma compliance with the credit agreement’s maximum
leverage ratio and minimum interest coverage ratio financial performance
covenants, which are calculated based on our consolidated financial results. It
also provides that any of the Parent’s debt that would have been permitted under
the credit agreement had it been incurred by ANR LLC will reduce on a
dollar-for-dollar basis the amount of debt that ANR LLC would otherwise be
permitted to incur under the credit agreement.
The
March 31, 2008 amendment to the credit agreement provided a new exception
to the covenant restricting dividends to permit ANR LLC to pay dividends or make
distributions to the Parent (i) to make scheduled payments of interest (and
fees and expenses) then due on our convertible notes or then due in respect of
any “qualified” debt (which means any debt, other than the convertible notes,
that could have been incurred instead by ANR LLC in compliance with the credit
agreement); (ii) to make payments of principal or premium then due in
respect of any “qualified” debt as long as such payments would be permitted
under the credit agreement at that time if ANR LLC or a restricted subsidiary,
rather than the parent, were the obligor of such “qualified” debt and were
making such payments; (iii) to make payments of principal or premium on the
convertible notes not to exceed $20.0 million in the aggregate for the term
of the credit agreement that become due solely as a result of the conversion of
convertible notes (and not as a result of any reason other than conversion, such
as mandatory repurchases of convertible notes in connection with the occurrence
of certain events); and (iv) so long as immediately before and after such
dividends or distributions are paid (1) ANR LLC is in pro forma compliance with
the credit agreement’s maximum leverage ratio and minimum interest coverage
ratio financial performance covenants, and a new maximum senior secured leverage
ratio test, all as described below, (2) the liquidity test described below
is satisfied and (3) no event of default under the credit agreement has occurred
and is continuing, to make payments of principal or premium on the convertible
notes in excess of $20.0 million that become due solely as a result of the
conversion of convertible notes (and not as a result of any reason other than
conversion, such as mandatory repurchases of convertible notes in connection
with the occurrence of certain events).
The
amendment also (i) revised the covenant restricting the lines of business in
which the Parent and its subsidiaries may engage to clarify that any businesses
or activities that are within the mining and/or energy industries generally are
permitted lines of business as long as the core business remains coal mining and
(ii) creates a new exception to the lien covenant to permit the granting of
liens on the capital stock of the ANR LLC’s unrestricted subsidiaries to secure
debt of those subsidiaries.
Borrowings
under the Credit Agreement are subject to mandatory prepayment (1) with 100% of
the net cash proceeds received from asset sales or other dispositions of
property by ANR LLC and its subsidiaries (including insurance and other
condemnation proceedings), subject to certain exceptions and reinvestment
provisions, and (2) with 100% of the net cash proceeds received by ANR LLC and
its subsidiaries from the issuance of debt securities or other incurrence of
debt, excluding certain indebtedness.
Analysis
of Material Debt Covenants
We were
in compliance with all covenants under our credit facility as of December 31,
2008.
The
financial covenants in our credit facility require, among other
things:
|
|
·
|
We
must maintain a maximum leverage ratio, defined as the ratio of
consolidated debt less unrestricted cash and cash equivalents to EBITDA
(as defined in the credit agreement, “Adjusted EBITDA”), of not more than
3.5:1.0 for the period of four fiscal quarters ended on December 31, 2008
and for each period of four fiscal quarters ending on each quarter end
thereafter.
|
|
|
·
|
We
must maintain a minimum interest coverage ratio, defined as the ratio of
Adjusted EBITDA to cash interest expense, of not less than 2.5:1.0 for the
four fiscal quarters ending on the last day of any fiscal
quarter.
|
A breach
of the covenants in the credit facility, including these financial covenants
that are tied to ratios based on Adjusted EBITDA, could result in a default
under the credit facility and the lenders could elect to declare all amounts
borrowed due and payable. Any acceleration under our credit facility
would also result in a default under the indenture governing our convertible
notes.
In order
for ANR LLC to be permitted to pay dividends or make distributions to the Parent
to make payments of principal or premium on the convertible notes in excess of
$20.0 million that become due solely as a result of the conversion of
convertible notes, we must be able to satisfy the following two financial
performance tests both immediately before and immediately after giving effect to
the payment of any such dividend or distribution, in addition to being in
compliance with the maximum leverage and minimum interest coverage ratios
described above:
|
|
·
|
We
must have a maximum senior secured leverage ratio, defined as the ratio of
consolidated debt that is secured by a lien less unrestricted cash and
cash equivalents to Adjusted EBITDA, of 2.5:1.0 or 2.0:1.0 starting
January 1, 2009.
|
|
|
·
|
We
must satisfy a liquidity test, i.e., the sum of the
unused commitments under the credit facility’s revolving line of credit
plus our unrestricted cash and cash equivalents must not be less than
$100.0 million.
|
At
December 31, 2008, our leverage ratio was less than zero, therefore it is not
meaningful, and our interest coverage ratio was 16.13, and the sum of the unused
commitments under the credit facility’s revolving line of credit plus our
unrestricted cash and cash equivalents was $968.6 million. The senior
secured leverage ratio was (0.83), due to our cash and cash equivalent balance
exceeding our term loan amount.
If
certain circumstances exist (as described in the Supplemental Indenture) where
all of our $287.5 million aggregate principal amount of convertible notes were
converted at the option of the holders, we would have adequate liquidity to
satisfy the obligations under the notes and remain in compliance with any
required covenants.
Adjusted
EBITDA is used in our credit agreement to determine compliance with many of the
covenants under the facility. Adjusted EBITDA is defined in our
credit agreement as EBITDA, further adjusted to exclude non-recurring items,
non-cash items and other adjustments permitted in calculating covenant
compliance under our credit facility, as shown in the table below. We
believe that the inclusion of supplementary adjustments to EBITDA applied in
presenting Adjusted EBITDA is appropriate to provide additional information to
investors to demonstrate compliance with our financial covenants.
|
Three
Months Ended March 31, 2008
|
Three
Months Ended June 30, 2008
|
Three
Months Ended September 30, 2008
|
Three
Months Ended December 31, 2008
|
Twelve
Months Ended December 31, 2008
|
||||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
Net
income
|
$ | 25,530 | $ | 74,337 | $ | 69,863 | $ | (4,193 | ) | $ | 165,537 | |||||||||
|
Interest
expense, net
|
10,087 | 17,097 | 8,389 | 6,804 | 42,377 | |||||||||||||||
|
Interest
income
|
(789 | ) | (2,234 | ) | (2,728 | ) | (1,650 | ) | (7,401 | ) | ||||||||||
|
Income
tax expense
|
7,968 | 7,662 | 9,906 | 15,250 | 40,786 | |||||||||||||||
|
Depreciation,
depletion, and amortization
|
44,260 | 44,910 | 42,197 | 41,203 | 172,570 | |||||||||||||||
|
EBITDA
|
87,056 | 141,772 | 127,627 | 57,414 | 413,869 | |||||||||||||||
|
Unrestricted
subsidiary
|
1,328 | 1,131 | 3,504 | 13 | 5,976 | |||||||||||||||
|
Change
in fair value of derivative instruments
|
(16,684 | ) | (6,516 | ) | 34,294 | 36,171 | 47,265 | |||||||||||||
|
Write-off
of assets
|
- | - | - | 25,687 | 25,687 | |||||||||||||||
|
Other
allowance adjustments
|
607 | 131 | 914 | 1,235 | 2,887 | |||||||||||||||
|
Accretion
expense
|
1,852 | 1,855 | 1,846 | 1,947 | 7,500 | |||||||||||||||
|
Amortization
of deferred gains
|
(213 | ) | (205 | ) | (177 | ) | (84 | ) | (679 | ) | ||||||||||
|
Loss
on early extinguishment of debt
|
- | 14,669 | 33 | - | 14,702 | |||||||||||||||
|
Stock-based
compensation charges
|
2,911 | 11,456 | 635 | 1,999 | 17,001 | |||||||||||||||
|
Adjusted
EBITDA
|
$ | 76,857 | $ | 164,293 | $ | 168,676 | $ | 124,382 | $ | 534,208 | ||||||||||
|
Leverage
ratio (1)
|
NM
|
|||||||||||||||||||
|
Interest
coverage ratio (2)
|
16.13 | |||||||||||||||||||
|
(1
|
)
|
Leverage
ratio is defined in our credit facility as total debt divided by Adjusted
EBITDA.
|
|
(2
|
)
|
Interest
coverage ratio is defined in our credit facility as Adjusted EBITDA
divided by cash interest expense.
|
Other
As a
regular part of our business, we review opportunities for, and engage in
discussions and negotiations concerning, the acquisition of coal mining assets
and interests in coal mining companies and related businesses, and acquisitions
of, or combinations with, coal mining companies and related businesses. When we
believe that these opportunities are consistent with our growth plans and our
acquisition criteria, we will make bids or proposals and/or enter into letters
of intent and other similar agreements, which may be binding or nonbinding, that
are customarily subject to a variety of conditions and usually permit us to
terminate the discussions and any related agreement if, among other things, we
are not satisfied with the results of our due diligence investigation. 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. There can be no assurance that additional financing will be available
on terms acceptable to us, or at all.
Contractual
Obligations
The
following is a summary of our significant contractual obligations as of
December 31, 2008 (in thousands):
|
2009
|
2010-2011 | 2012-2013 |
After
2013
|
Total
|
||||||||||||||||
|
Long-term
debt and capital leases (1)
|
$ | 232 | $ | - | $ | 233,125 | $ | 287,500 | $ | 520,857 | ||||||||||
|
Equipment
purchase commitments
|
63,980 | - | - | - | 63,980 | |||||||||||||||
|
Operating
leases
|
1,693 | 2,691 | 2,401 | 6,037 | 12,822 | |||||||||||||||
|
Minimum
royalties
|
10,500 | 21,346 | 17,403 | 30,071 | 79,320 | |||||||||||||||
|
Coal
purchase commitments
|
216,489 | 14,190 | - | - | 230,679 | |||||||||||||||
|
Coal
contract buyout
|
12,980 | 567 | - | - | 13,547 | |||||||||||||||
|
Total
|
$ | 305,874 | $ | 38,794 | $ | 252,929 | $ | 323,608 | $ | 921,205 | ||||||||||
|
(1
|
)
|
Long-term
debt and capital leases include principal amounts due in the years shown.
Cash interest payable on these obligations, with interest rates ranging
between 2.375% and 12.2% on our loans and capital leases, would be
approximately $23.4 million in 2009, $46.7 million in 2010 to 2011,
$27.4 million in 2012 to 2013, and $9.4 million after
2013.
|
Additionally,
we have long-term liabilities relating to asset retirement obligations, workers'
compensation and black lung benefits and postretirement benefits. The table
below reflects the estimated undiscounted cash flows for these obligations (in
thousands):
|
2009
|
2010-2011
|
2012-2013
|
After
2013
|
Total
|
|||||||||||||||
|
Asset
retirement obligation
|
$
|
8,375
|
$
|
23,517
|
$
|
27,382
|
$
|
77,085
|
$
|
136,359
|
|||||||||
|
Postretirement
|
1,081
|
3,840
|
6,349
|
304,676
|
315,946
|
||||||||||||||
|
Workers'
compensation benefits and black lung benefits
|
1,718
|
1,122
|
1,002
|
6,686
|
10,528
|
||||||||||||||
|
Total
|
$
|
11,174
|
$
|
28,479
|
$
|
34,733
|
$
|
388,447
|
$
|
462,833
|
|||||||||
Off-Balance Sheet
Arrangements
In the
normal course of business, we are a party to certain off-balance sheet
arrangements. These arrangements include guarantees and financial instruments
with off-balance sheet risk, such as bank letters of credit and performance or
surety bonds. No liabilities related to these arrangements are reflected in our
consolidated balance sheets, and we do not expect any material adverse effects
on our financial condition, results of operations or cash flows to result from
these off-balance sheet arrangements.
From time
to time, we provide guarantees to financial institutions to facilitate the
acquisition of mining equipment by third parties who mine coal for us. This
arrangement is beneficial to us because it helps insure a continuing source of
coal production.
Federal
and state laws require us to secure payment of certain long-term obligations
such as mine closure and reclamation costs, federal and state workers'
compensation, coal leases and other obligations. We typically secure these
payment obligations by using surety bonds, an off-balance sheet instrument. The
use of surety bonds is less expensive for us than the alternative of posting a
100% cash bond or a bank letter of credit, either of which would require a
greater use of our credit facility. In addition, due to the current instability
and volatility of the financial markets, our current surety bond providers may
experience difficulties in providing new surety bonds to us, maintaining
existing surety bonds, or satisfying liquidity requirements under existing
surety bond contracts. In that event, we would be required to find
alternative sources of funding to satisfy our payment obligations, which may
require greater use of our credit facility. To the extent that
surety bonds may become unavailable, we would seek to secure our reclamation
obligations with letters of credit, cash deposits or other suitable forms of
collateral.
As of
December 31, 2008, 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. We further have a facility with Safeco Insurance
Company of America pursuant to which 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, 2008, we have posted an aggregate of
$149.0 million in reclamation bonds and $9.6 million of other types of
bonds under these facilities and maintained letters of credit totaling
$82.6 million to secure reclamation and other surety bond
obligations.
As part
of the sale of Gallatin on September 26, 2008, an escrow balance of $4.5 million
was established and we have agreed to indemnify and guarantee the buyer against
breaches of representations and warranties in the sale agreement as well as
contingencies that may have existed at closing and materialize within one year
from the date of sale.
Critical
Accounting Policies and Estimates
Our
discussion and analysis of our financial condition, results of operations,
liquidity and capital resources is based upon our consolidated financial
statements, which have been prepared in accordance with U.S. generally
accepted accounting principles (“GAAP”). GAAP requires that we make estimates
and judgments that affect the reported amounts of assets, liabilities, revenues
and expenses, and related disclosure of contingent assets and liabilities. On an
ongoing basis, we evaluate our estimates. We base our estimates on historical
experience and on various other factors and assumptions, including the current
economic environment that we believe are reasonable under the circumstances, the
results of which form the basis for making judgments about the carrying values
of assets and liabilities that are not readily apparent from other sources. We
adjust such estimates and assumptions as facts and circumstances
require. Illiquid credit markets, volatile equity, foreign currency,
and energy markets and declines with the end-demand for steel products due to
the current economic environment have combined to increase the uncertainty
inherent in such estimates and assumptions. As future events and
their effects cannot be determined with precision, actual results may differ
significantly from these estimates. Changes in these estimates
resulting from continuing changes in the economic environment will be reflected
in the financial statements in future periods.
Reclamation. Our asset
retirement obligations arise from the federal Surface Mining Control and
Reclamation Act of 1977 and similar state statutes, which require that mine
property be restored in accordance with specified standards and an approved
reclamation plan. Significant reclamation activities include reclaiming refuse
and slurry ponds, reclaiming the pit and support acreage at surface mines, and
sealing portals at deep mines. We account for the costs of our reclamation
activities in accordance with the provisions of SFAS No. 143, Accounting for Asset Retirement
Obligations (“SFAS 143”). We determine the
future cash flows necessary to satisfy our reclamation obligations on a
mine-by-mine basis based upon current permit requirements and various estimates
and assumptions, including estimates of disturbed acreage, cost estimates, and
assumptions regarding productivity. Estimates of disturbed acreage are
determined based on approved mining plans and related engineering data. Cost
estimates are based upon third-party costs. Productivity assumptions are based
on historical experience with the equipment that is expected to be utilized in
the reclamation activities. In accordance with the provisions of SFAS 143,
our asset retirement obligations are initially recorded at fair value, or the
amount at which obligations could be settled in a current transaction between
willing third parties. In order to determine fair value, we must also estimate a
discount rate and third-party margin. Each is discussed further
below:
|
|
·
|
Discount Rate.
SFAS 143 requires that asset retirement obligations be initially
recorded at fair value. In accordance with the provisions of
SFAS 143, we utilize discounted cash flow techniques to estimate the
fair value of our obligations. We base our discount rate on the rates of
treasury bonds with maturities similar to expected mine lives, adjusted
for our credit standing.
|
|
|
·
|
Third-Party Margin.
SFAS 143 requires the measurement of an obligation to be based upon
the amount a third party would demand to assume the obligation. Because we
plan to perform a significant amount of the reclamation activities with
internal resources, a third-party margin was added to the estimated costs
of these activities. This margin was estimated based upon our historical
experience with contractors performing similar types of reclamation
activities. The inclusion of this margin will result in a recorded
obligation that is greater than our estimates of our cost to perform the
reclamation activities. If our cost estimates are accurate, the excess of
the recorded obligation over the cost incurred to perform the work will be
recorded as a gain at the time that reclamation work is
completed.
|
On at
least an annual basis, we review our entire reclamation liability and make
necessary adjustments for permit changes as granted by state authorities,
additional costs resulting from accelerated mine closures, and revisions to cost
estimates and productivity assumptions, to reflect current experience. At
December 31, 2008, we had recorded asset retirement obligation liabilities
of $98.9 million, including amounts reported as current. While the precise
amount of these future costs cannot be determined with certainty, as of
December 31, 2008, we estimate that the aggregate undiscounted cost of
final mine closures is approximately $136.4 million.
Coal Reserves. There are
numerous uncertainties inherent in estimating quantities of economically
recoverable coal reserves, many of which are beyond our control. As a result,
estimates of economically recoverable coal reserves are by their nature
uncertain. Information about our reserves consists of estimates based on
engineering, economic and geological data assembled by our internal engineers
and geologists and reviewed by a third party consultant. Some of the factors and
assumptions that impact economically recoverable reserve estimates
include:
|
|
·
|
geological
conditions;
|
|
|
·
|
historical
production from the area compared with production from other producing
areas;
|
|
|
·
|
the
assumed effects of regulations and taxes by governmental
agencies;
|
|
|
·
|
assumptions
governing future prices; and
|
|
|
·
|
future
operating costs.
|
Each of
these factors may in fact vary considerably from the assumptions used in
estimating reserves. For these reasons, estimates of the economically
recoverable quantities of coal attributable to a particular group of properties,
and classifications of these reserves based on risk of recovery and estimates of
future net cash flows, may vary substantially. Actual production, revenues and
expenditures with respect to reserves will likely vary from estimates, and these
variances may be material. Variances could affect our projected
future revenues and expenditures, as well as the valuation of coal reserves and
depletion rates. At December 31, 2008, we had 599.7 million tons of
proven and probable coal reserves.
Postretirement Medical
Benefits. We have long-term liabilities for postretirement benefit cost
obligations. Detailed information related to these liabilities is included in
the notes to our financial statements included elsewhere in this annual report.
Liabilities for postretirement benefit costs are not funded. The liability is
actuarially determined, and we use various actuarial assumptions, including the
discount rate and future cost trends, to estimate the costs and obligations for
postretirement benefit costs. The discount rate used to determine the net
periodic benefit cost for postretirement benefits other than pensions was 6.44%
for the year ended December 31, 2008 and 5.92% for the year ended
December 31, 2007. At December 31, 2008, we had postretirement medical
benefit obligations of $61.3 million.
|
Health
care cost trend rate
|
One-percentage
point increase
|
One-percentage
point decrease
|
|||||||
|
(In
thousands)
|
|||||||||
|
Effect
on total service and interest cost components
|
$ | 65 | $ | (54 | ) | ||||
|
Effect
on a accumulated postretirement benefit obligation
|
822 | (680 | ) | ||||||
|
Discount
rate
|
One-half
percentage point increase
|
One-half
percentage point decrease
|
|||||||
|
(In
thousands)
|
|||||||||
|
Effect
on total service and interest cost components
|
$ | (429 | ) | $ | 524 | ||||
|
Effect
on a accumulated postretirement benefit obligation
|
(3,509 | ) | 4,671 | ||||||
Workers' Compensation.
Workers' compensation is a system by which individuals who sustain personal
injuries due to job-related accidents are compensated for their disabilities,
medical costs, and on some occasions, for the costs of their rehabilitation, and
by which the survivors of workers who suffer fatal injuries receive compensation
for lost financial support. The workers' compensation laws are administered by
state agencies with each state having its own set of rules and regulations
regarding compensation that is owed to an employee who is injured in the course
of employment. Our operations are covered through a combination of a
self-insurance program and an insurance policy. We accrue for any self-insured
liability by recognizing costs when it is probable that a covered liability has
been incurred and the cost can be reasonably estimated. Our estimates of these
costs are adjusted based upon actuarial studies. Actual losses may differ from
these estimates, which could increase or decrease our costs. At December
31, 2008, we had workers’ compensation obligations of $9.4 million.
Coal Workers' Pneumoconiosis.
We are required by federal and state statutes to provide benefits to employees
for awards related to coal workers' pneumoconiosis disease (black lung). These
claims are covered by a third-party insurance provider in all locations where we
operate with the exception of West Virginia. The Company is self-insured for
state black lung related claims at certain locations in West Virginia. We
account for self-insured black lung obligations under the provisions of SFAS No.
106, Employers'
Accounting for Postretirement Benefit Other than Pension (“SFAS 106”),
and SFAS No. 158, Employers' Accounting for
Defined Benefit Pension and Other Postretirement Plans (“SFAS
158”).
Charges
are made to operations for state black lung claims in West Virginia, as
determined by an independent actuary at the present value of the actuarially
computed liability for such benefits over the employee's applicable term of
service. As of December 31, 2008, we had black lung obligations of $1.9
million.
Income Taxes. We account for
income taxes in accordance with SFAS 109, which requires the recognition of
deferred tax assets and liabilities using enacted tax rates for the effect of
temporary differences between the book and tax bases of recorded assets and
liabilities. SFAS 109 also requires that deferred tax assets be reduced by
a valuation allowance if it is more likely than not that some portion or all of
the deferred tax asset will not be realized. In evaluating the need for a
valuation allowance, we analyze both positive and negative evidence as required
by SFAS 109. Such evidence includes objective evidence obtained from our
historical earnings, future sales commitments, outlooks on the coal industry by
us and third parties, expected level of future earnings (with sensitivities on
expectations considered), timing of temporary difference reversals, ability or
inability to meet forecasted earnings, unsettled industry circumstances, ability
to carry back and utilize a future tax loss (if a loss were to occur), available
tax planning strategies, limitations on deductibility of temporary differences,
and the impact the alternative minimum tax has on utilization of deferred tax
assets. The valuation allowance is monitored and reviewed quarterly. If our
conclusions change in the future regarding the realization of a portion or all
of our net deferred tax assets, we may record a change to the valuation
allowance through income tax expense in the period the determination is made,
which may have a material impact on our results. As of December 31,
2008, we had gross deferred tax assets of $162.5 million less a
valuation allowance of $34.5 million.
New
Accounting Pronouncements Issued and not yet Adopted
In May
2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff
Position (“FSP”) Accounting Principles Board (“APB”) 14-1, Accounting for Convertible Debt
Instruments that may be settled in cash upon conversion (Including partial cash
settlement) (“FSP APB 14-1”), which applies to convertible debt
instruments that, by their stated terms, may be settled in cash (or other
assets) upon conversion, including partial cash settlement, unless the embedded
conversion option is required to be separately accounted for as a derivative
under SFAS 133. FSP APB 14-1 requires issuers of such instruments to
separately account for the liability and equity components in a manner that will
reflect the entity’s nonconvertible debt borrowing rate when interest cost is
recognized in subsequent periods. This FSP is effective for financial
statements issued for fiscal years beginning after December 31, 2008, and
interim periods within those fiscal years. Early adoption is not
permitted and retroactive application to all periods presented is
required. Upon adoption of FSP APB 14-1, on January 1, 2009, we will
retrospectively apply the change in accounting principle to prior accounting
periods as if the principle has always been used. The adoption of FSP APB 14-1
will result in an estimated pre-tax increase to non-cash interest expense in
future annual periods of approximately $11.9 million. Upon
retrospective application in 2009, the adoption will also result in 2008 pretax
decrease of non-cash interest expense of $0.6 million, which is comprised of the
reversal of $8.9 million of previously written off deferred loan costs net of
$7.7 million of additional interest expense for the accretion of the liability
component of the debt and $0.6 million of deferred loan cost
amortization. Adoption of the standard will also result in the
following pre-tax balance sheet impacts at December 31, 2008; (1) a reduction of
debt by approximately $87.8 million and an increase in paid in capital by $95.5
million and (2) an increase to deferred loan
costs by approximately $5.3 million, an increase to paid in capital by $3.0
million with a pre-tax credit of $8.9 million to the income statement to record
deferred loan costs previously written off when the notes became convertible and
to allocate those costs between the portion related to the debt and equity
components. We are continuing to analyze the tax impacts of adopting
the new standard, but currently expect that adoption will also result in an
increase to deferred tax liabilities and a decrease to the valuation allowance
against deferred tax assets with the offsetting impact of these entries being
recorded to paid-in-capital.
In March
2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities (“SFAS 161”), which amends SFAS
133. SFAS 161 is intended to improve financial reporting about
derivative instruments and hedging activities by requiring enhanced disclosures
to enable investors to better understand their effects on an entity’s financial
position, financial performance, and cash flows. The new standard also improves
transparency about the location and amounts of derivative instruments in an
entity’s financial statements; how derivative instruments and related hedged
items are accounted for under SFAS 133; and how derivative instruments and
related hedged items affect its financial position, financial performance, and
cash flows. Since SFAS 161 requires only additional disclosures concerning
derivatives and hedging activities, adoption of SFAS 161 will not affect our
financial position and results of operations.
In
December 2007, the FASB issued SFAS 141(R), Business Combinations (“SFAS
141(R)”), and SFAS No. 160, Accounting and Reporting of
Noncontrolling Interest in Consolidated Financial Statements, an amendment of
ARB No. 51 (“SFAS 160”). SFAS 141(R) and SFAS 160
will significantly change the accounting for and reporting of business
combination transactions and noncontrolling (minority) interests in consolidated
financial statements. SFAS 141(R) retains the underlying concepts of SFAS
No. 141, Business
Combinations, in that all business combinations are still required to be
accounted for at fair value under the acquisition method of accounting, but SFAS
141(R) changed the method of applying the acquisition method in a number of
significant aspects. Acquisition costs will generally be expensed as incurred;
noncontrolling interests will be valued at fair value at the acquisition date;
in-process research and development will be recorded at fair value as an
indefinite-lived intangible asset at the acquisition date, until either
abandoned or completed, at which point the useful lives will be determined;
restructuring costs associated with a business combination will generally be
expensed subsequent to the acquisition date; and changes in deferred tax asset
valuation allowances and income tax uncertainties after the acquisition date
generally will affect income tax expense. SFAS 160 will change the accounting
and reporting for minority interests, which will be recharacterized as
noncontrolling interests, and classified as a component of
equity. These pronouncements will become effective January 1,
2009. Upon adoption, SFAS 141(R) will not have a significant impact
on our consolidated financial statements; however, any business combination we
enter into after the adoption may significantly impact our financial position
and results of operations when compared to acquisitions accounted for under
existing U.S. Generally Accepted Accounting Principles (GAAP) and result in more
earnings volatility and generally lower earnings due to the expensing of deal
costs and restructuring costs of acquired companies. Upon adoption,
SFAS 160 will not impact our consolidated financial statements until, if or when
we effectuate a business combination post adoption that has noncontrolling
(minority) interests.
|
Quantitative
and Qualitative Disclosures about Market
Risk
|
In
addition to risks inherent in operations, we are exposed to market risks. The
following discussion provides additional detail regarding our exposure to the
risks of changing coal and diesel fuel prices and interest rates.
Commodity
Price Risk
We are
exposed to market price risk in the normal course of selling coal. At January
16, 2009, 72.2% of our planned 2009 production was committed and priced and
approximately 17.0% was committed and unpriced, with approximately 2.4 million
tons uncommitted. The uncommitted or unpriced tons are subject to future market
price volatility. At January 16, 2009, we had entered into
commitments to purchase 2.6 million tons of coal from others during
2009.
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 fuel put options to reduce the volatility in the price of diesel fuel
for our operations. The diesel fuel swap agreements and put options have not
been designated as hedges for accounting purposes, accordingly, the changes in
the fair value for these derivative contracts are required to be recorded in
cost of sales. As a result, changes in the market price of diesel fuel can
have a material impact on our earnings. These diesel fuel swaps and
put options use the NYMEX New York Harbor No. 2 Heating Oil (“No. 2 heating
oil”) futures contract as the underlying commodity reference price.
As of
December 31, 2008, we had in place swap agreements with respect to 33.1 million
gallons of diesel fuel, at fixed prices ranging from $1.61 to $4.10 per gallon,
which mature in 2009 to 2011. The fair value of these diesel fuel
swap agreements is a liability of $38.0 million which is recorded in accrued
expenses and other current liabilities in the amount of $21.2 million and in
other liabilities in the amount of $16.8 million as of December 31,
2008.
We have
also employed an options strategy – both purchasing and selling put options – to
protect cash flows in the event diesel fuel prices decline. As of December 31,
2008, we had purchased put options for 2.6 million gallons for the first six
months of 2009 at a strike price of $3.50 per gallon. In the event that No. 2
heating oil prices decline below the strike price, we can exercise the put
options and sell the 2.6 million gallons at the strike price, therefore reducing
the negative impact of any of the swap agreements that have settlement prices
above market. As of December 31, 2008, we had sold put options for 2.6 million
gallons for the first six months of 2009 at a strike price of $3.00 per gallon.
This was part of a put spread strategy that effectively provided protection for
market prices between $3.00 and $3.50. In the event that No.2 heating
oil prices decline below the $3.00 strike price, then the sold put options will
offset the purchased put options with no net benefit or cost. The net
fair value of all these diesel fuel put options is a net asset of $1.3 million
of which $5.2 million is recorded in prepaid expenses and other current assets
and $3.9 million is recorded in accrued expenses and other current liabilities
as of December 31, 2008.
We
purchase coal in the OTC market and directly from third parties to supplement
and blend with our produced and processed coal in order to provide coal of the
quality and quantity to meet certain of our customer's requirements. We also
sell in the OTC market to fix the price of uncommitted future production from
our mines. Certain of these purchase and sale contracts meet the definition of a
derivative instrument. Any derivative instruments that we hold are held for
purposes other than trading. Our risk management policy prohibits the use of
derivatives for speculative purpose. The use of purchase and sales contracts
which are considered derivative instruments could materially affect our results
of operations as a result of the requirement to mark them to market at the end
of each reporting period.
These
transactions give rise to commodity price risk, which represents the potential
loss that can be caused by an adverse change in the price of coal. Outstanding
purchase and sales contracts at December 31, 2008 that are considered derivative
instruments are summarized as follows:
|
Purchase
Price
|
Tons
|
Fair
Value (In Millions)
|
|||||||||||
|
Purchase
Contracts
|
Range
|
Outstanding
|
Delivery
Period
|
Asset/(Liability)
|
|||||||||
| $ | 40.00-$60.00 | 180,000 |
01/01/08-12/31/09
|
$ | 1.2 | ||||||||
| $ | 60.00-$70.00 | 150,000 |
01/01/09-12/31/09
|
(0.7 | ) | ||||||||
| $ | 110.00-$120.00 | 60,000 |
01/01/09-12/31/09
|
(3.6 | ) | ||||||||
| 390,000 | $ | (3.1 | ) | ||||||||||
|
Selling
Price
|
Tons
|
Fair
Value (In Millions)
|
|||||||||||
|
Sales
Contracts
|
Range
|
Outstanding
|
Delivery
Period
|
Asset/(Liability)
|
|||||||||
| $ | 50.00-$60.00 | 140,000 |
01/01/09-12/31/09
|
$ | 0.2 | ||||||||
| $ | 60.00-$70.00 | 120,000 |
01/01/09-12/31/09
|
0.4 | |||||||||
| $ | 70.00-$80.00 | 120,000 |
01/01/09-12/31/09
|
2.3 | |||||||||
| 380,000 | $ | 2.9 | |||||||||||
Interest
Rate Risk
All of
our borrowings under our credit facility are at a variable rate, exposing us to
the effect of rising interest rates in the United States. As of December 31,
2008, we had a $233.1 million term loan outstanding under our credit facility
with a variable interest rate based upon the 3-month London Interbank Offered
Rate (“LIBOR”) (1.50% at December 31, 2008) plus an applicable margin (1.50% at
December 31, 2008). To reduce our exposure to rising interest rates,
effective May 22, 2006 we entered into a pay-fixed, receive variable interest
rate swap on the notional amount of $233.1 million for a period of approximately
six and one-half years. In effect, this swap converted the variable interest
rates based on the LIBOR to a fixed interest rate of 5.59% plus the applicable
margin defined in the debt agreement (1.50% at December 31, 2008) for the
remainder of our term loan. We account for the interest rate swap as a cash flow
hedge and accordingly changes in fair value of the swap are recorded to other
comprehensive income (loss). The fair value of the swap at year end
December 31, 2008 was a liability of $27.9 million ($21.0 million net of
tax).
|
Financial
Statements and Supplementary Data
|
Report
of Independent Registered Public Accounting Firm
The Board
of Directors and Stockholders
Alpha
Natural Resources, Inc.:
We have
audited the accompanying consolidated balance sheets of Alpha Natural Resources,
Inc. and subsidiaries (the Company) as of December 31, 2008 and 2007, and
the related consolidated statements of income, stockholders’ equity and
comprehensive income, and cash flows for each of the years in the three-year
period ended December 31, 2008. These consolidated financial statements are
the responsibility of the Company’s management. Our responsibility is to express
an opinion on these consolidated financial statements based on our
audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Alpha Natural Resources,
Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of
their operations and their cash flows for each of the years in the three-year
period ended December 31, 2008, in conformity with U.S. generally
accepted accounting principles.
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company’s internal control over financial
reporting as of December 31, 2008, based on criteria established in Internal Control – Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated February 26, 2009 expressed an
unqualified opinion on the effectiveness of the Company’s internal control over
financial reporting.
/s/ KPMG
LLP
Roanoke,
Virginia
February
26, 2009
|
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
|
||||||||||||
|
Twelve
Months Ended
|
||||||||||||
|
December
31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
(In
thousands, except share and per share amounts)
|
||||||||||||
|
Revenues:
|
||||||||||||
|
Coal
revenues
|
$ | 2,219,291 | $ | 1,647,505 | $ | 1,681,434 | ||||||
|
Freight
and handling revenues
|
279,853 | 205,086 | 188,366 | |||||||||
|
Other
revenues
|
54,980 | 33,241 | 34,743 | |||||||||
|
Total
revenues
|
2,554,124 | 1,885,832 | 1,904,543 | |||||||||
|
Costs
and expenses:
|
||||||||||||
|
Cost
of coal sales (exclusive of items shown separately below)
|
1,729,281 | 1,371,519 | 1,346,733 | |||||||||
|
Gain
on sale of coal reserves
|
(12,936 | ) | - | - | ||||||||
|
(Increase)
decrease in fair value of derivative instruments, net
|
47,265 | (8,925 | ) | (402 | ) | |||||||
|
Freight
and handling costs
|
279,853 | 205,086 | 188,366 | |||||||||
|
Cost
of other revenues
|
40,857 | 22,715 | 22,982 | |||||||||
|
Depreciation,
depletion and amortization
|
171,963 | 159,574 | 140,851 | |||||||||
|
Mine
closure/asset impairment charges
|
30,172 | - | - | |||||||||
|
Selling,
general and administrative expenses
|
||||||||||||
|
(exclusive
of depreciation and amortization shown separately above)
|
71,923 | 58,485 | 67,952 | |||||||||
|
Total
costs and expenses
|
2,358,378 | 1,808,454 | 1,766,482 | |||||||||
|
Income
from operations
|
195,746 | 77,378 | 138,061 | |||||||||
|
Other
income (expense):
|
||||||||||||
|
Interest
expense
|
(40,398 | ) | (40,366 | ) | (41,774 | ) | ||||||
|
Interest
income
|
7,352 | 2,266 | 839 | |||||||||
|
Loss
on early extinguishment of debt
|
(14,702 | ) | - | - | ||||||||
|
Gain
on termination of Cliffs' merger, net
|
56,315 | - | - | |||||||||
|
Miscellaneous
income (expense), net
|
(3,829 | ) | (93 | ) | 523 | |||||||
|
Total
other income (expense), net
|
4,738 | (38,193 | ) | (40,412 | ) | |||||||
|
Income
from continuing operations before income taxes
|
200,484 | 39,185 | 97,649 | |||||||||
|
Income
tax (expense) benefit
|
(39,139 | ) | (9,195 | ) | 30,519 | |||||||
|
Income
from continuing operations
|
161,345 | 29,990 | 128,168 | |||||||||
|
Discontinued
operations (Note 25)
|
||||||||||||
|
Loss
from discontinued operations
|
(8,273 | ) | (3,000 | ) | - | |||||||
|
Minority
interest on the loss from discontinued operations
|
490 | 179 | - | |||||||||
|
Gain
on sale of discontinued operations
|
13,622 | - | - | |||||||||
|
Income
tax (expense) benefit
|
(1,647 | ) | 565 | - | ||||||||
|
Income
(loss) from discontinued operations
|
4,192 | (2,256 | ) | - | ||||||||
|
Net
income
|
$ | 165,537 | $ | 27,734 | $ | 128,168 | ||||||
|
Basic
earnings per share:
|
||||||||||||
|
Income
from continuing operations
|
$ | 2.36 | $ | 0.46 | $ | 2.00 | ||||||
|
Income
(loss) from discontinued operations
|
0.06 | (0.03 | ) | - | ||||||||
|
Net
income
|
$ | 2.42 | $ | 0.43 | $ | 2.00 | ||||||
|
Diluted
earnings per share:
|
||||||||||||
|
Income
from continuing operations
|
$ | 2.30 | $ | 0.46 | $ | 2.00 | ||||||
|
Income
(loss) from discontinued operations
|
0.06 | (0.03 | ) | - | ||||||||
|
Net
income
|
$ | 2.36 | $ | 0.43 | $ | 2.00 | ||||||
|
See
accompanying notes to consolidated financial statements.
|
||||||||||||
|
ALPHA
NATURAL RESOURCES, INC. AND SUBSIDIARIES
|
||||||||
|
CONDENSED
CONSOLIDATED BALANCE SHEETS
|
||||||||
|
December
31,
|
December
31,
|
|||||||
|
2008
|
2007
|
|||||||
|
(In
thousands, except share and per share amounts)
|
||||||||
|
Assets
|
||||||||
|
Current
assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | 676,190 | $ | 54,365 | ||||
|
Trade
accounts receivable, net
|
163,674 | 183,969 | ||||||
|
Notes
and other receivables
|
15,074 | 11,141 | ||||||
|
Inventories
|
86,594 | 70,780 | ||||||
|
Prepaid
expenses and other current assets
|
50,251 | 59,954 | ||||||
|
Total
current assets
|
991,783 | 380,209 | ||||||
|
Property,
plant, and equipment, net
|
550,098 | 640,258 | ||||||
|
Goodwill
|
20,547 | 20,547 | ||||||
|
Other
intangibles, net
|
3,835 | 9,376 | ||||||
|
Deferred
income taxes
|
107,452 | 97,130 | ||||||
|
Other
assets
|
54,577 | 63,394 | ||||||
|
Total
assets
|
$ | 1,728,292 | $ | 1,210,914 | ||||
|
Liabilities
and Stockholders' Equity
|
||||||||
|
Current
liabilities:
|
||||||||
|
Current
portion of long term debt
|
$ | 232 | $ | 2,579 | ||||
|
Note
payable
|
18,288 | 18,883 | ||||||
|
Trade
accounts payable
|
102,975 | 95,749 | ||||||
|
Deferred
income taxes
|
639 | 9,753 | ||||||
|
Accrued
expenses and other current liabilities
|
140,459 | 96,098 | ||||||
|
Total
current liabilities
|
262,593 | 223,062 | ||||||
|
Long-term
debt
|
520,625 | 425,451 | ||||||
|
Workers’
compensation benefit obligations
|
9,604 | 9,055 | ||||||
|
Postretirement
medical benefit obligations
|
60,211 | 53,811 | ||||||
|
Asset
retirement obligation
|
90,565 | 83,020 | ||||||
|
Deferred
gains on sale of property interests
|
2,421 | 3,176 | ||||||
|
Other
liabilities
|
56,596 | 30,930 | ||||||
|
Total
liabilities
|
1,002,615 | 828,505 | ||||||
|
Minority
Interest
|
- | 1,573 | ||||||
|
Commitments
and contingencies
|
||||||||
|
Stockholders'
equity:
|
||||||||
|
Preferred
stock - par value $0.01, 10,000,000 shares
|
||||||||
|
authorized,
none issued
|
- | - | ||||||
|
Common
stock - par value $0.01, 100,000,000 shares
|
||||||||
|
authorized,
70,513,880 and
65,769,303 shares issued and outstanding
|
||||||||
|
at
December 31, 2008 and 2007, respectively
|
705 | 658 | ||||||
|
Additional
paid-in capital
|
414,410 | 227,336 | ||||||
|
Accumulated
other comprehensive loss
|
(30,107 | ) | (22,290 | ) | ||||
|
Retained
earnings
|
340,669 | 175,132 | ||||||
|
Total
stockholders' equity
|
725,677 | 380,836 | ||||||
|
Total
liabilities and stockholders' equity
|
$ | 1,728,292 | $ | 1,210,914 | ||||
|
See
accompanying notes to consolidated financial statements.
|
||||||||
|
ALPHA
NATURAL RESOURCES, INC. AND SUBSIDIARIES
|
|||||||||||||||||||||||
|
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE
INCOME
|
|||||||||||||||||||||||
|
Common
Stock
|
Additional
Paid in Capital
|
Accumulated
Other Comprehensive Loss
|
Retained
Earnings
|
Total
Stockholders' Equity
|
|||||||||||||||||||
|
Shares
|
Amount
|
||||||||||||||||||||||
|
(In
thousands)
|
|||||||||||||||||||||||
|
Balances,
December 31, 2005
|
64,420 | $ | 644 | $ | 193,608 | $ | - | $ | 18,513 | $ | 212,765 | ||||||||||||
|
Comprehensive
income
|
|||||||||||||||||||||||
|
Net
income
|
- | - | - | - | 128,168 | 128,168 | |||||||||||||||||
|
Change
in derivative financial instrument, net of income tax of
$1,787
|
- | - | - | (5,437 | ) | - | (5,437 | ) | |||||||||||||||
|
Total
comprehensive income
|
122,731 | ||||||||||||||||||||||
|
Initial
impact of adoption of Statement of Financial Standards No. 108, net of
income tax (Note 2(t))
|
- | - | - | - | 717 | 717 | |||||||||||||||||
|
Exercise
of stock options
|
60 | 1 | 953 | - | - | 954 | |||||||||||||||||
|
Amortization
of unearned stock-based compensation
|
484 | 5 | 20,459 | - | - | 20,464 | |||||||||||||||||
|
Initial
impact of adoption of Statement of Financial Standards No. 158, net of
income tax
|
- | - | - | (13,582 | ) | - | (13,582 | ) | |||||||||||||||
|
Balances,
December 31, 2006
|
64,964 | $ | 650 | $ | 215,020 | $ | (19,019 | ) | $ | 147,398 | $ | 344,049 | |||||||||||
|
Comprehensive
income
|
|||||||||||||||||||||||
|
Net
income
|
- | - | - | - | 27,734 | 27,734 | |||||||||||||||||
|
Change
in derivative financial instrument, net of income tax of
$2,070
|
- | - | - | (6,298 | ) | - | (6,298 | ) | |||||||||||||||
|
Impact
of Statement of Financial Accounting Standards No. 158, net of income tax
benefit of ($997)
|
- | - | - | 3,027 | - | 3,027 | |||||||||||||||||
|
Total
comprehensive income
|
24,463 | ||||||||||||||||||||||
|
Exercise
of stock options
|
268 | 3 | 3,969 | - | - | 3,972 | |||||||||||||||||
|
Amortization
of unearned stock-based compensation
|
537 | 5 | 8,347 | - | - | 8,352 | |||||||||||||||||
|
Balances,
December 31, 2007
|
65,769 | $ | 658 | $ | 227,336 | $ | (22,290 | ) | $ | 175,132 | $ | 380,836 | |||||||||||
|
Comprehensive
income
|
|||||||||||||||||||||||
|
Net
income
|
- | - | - | - | 165,537 | 165,537 | |||||||||||||||||
|
Change
in derivative financial instrument, net of income tax of
$3,111
|
- | - | - | (9,226 | ) | - | (9,226 | ) | |||||||||||||||
|
Impact
of Statement of Financial Accounting Standards No. 158, net of income tax
benefit of ($478)
|
- | - | - | 1,409 | - | 1,409 | |||||||||||||||||
|
Total
comprehensive income
|
157,720 | ||||||||||||||||||||||
|
Proceeds
from public offering of common shares ($41.25 per share), net of offering
costs of $7,834
|
4,182 | 42 | 164,624 | - | - | 164,666 | |||||||||||||||||
|
Exercise
of stock options
|
213 | 2 | 3,584 | - | - | 3,586 | |||||||||||||||||
|
Amortization
of unearned stock-based compensation
|
350 | 3 | 18,866 | - | - | 18,869 | |||||||||||||||||
|
Balances,
December 31, 2008
|
70,514 | $ | 705 | $ | 414,410 | $ | (30,107 | ) | $ | 340,669 | $ | 725,677 | |||||||||||
|
See
accompanying notes to consolidated financial statements.
|
|||||||||||||||||||||||
|
ALPHA
NATURAL RESOURCES, INC. AND SUBSIDIARIES
|
||||||||||||
|
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
||||||||||||
|
Twelve
Months Ended
|
||||||||||||
|
December
31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
(In
thousands)
|
||||||||||||
|
Operating
activities:
|
||||||||||||
|
Net
income
|
$ | 165,537 | $ | 27,734 | $ | 128,168 | ||||||
|
Adjustments
to reconcile net income
|
||||||||||||
|
to
net cash provided by operating
|
||||||||||||
|
activities:
|
||||||||||||
|
Depreciation,
depletion and amortization
|
172,570 | 159,579 | 140,851 | |||||||||
|
Loss
on early extinguishment of debt
|
14,702 | - | - | |||||||||
|
Amortization
of debt issuance costs
|
11,904 | 2,318 | 2,282 | |||||||||
|
Accretion
of asset retirement obligation
|
7,499 | 6,845 | 4,874 | |||||||||
|
Share-based
compensation
|
17,871 | 9,681 | 20,464 | |||||||||
|
Amortization of deferred gains on sales
|
||||||||||||
|
of
property interests
|
(679 | ) | (891 | ) | (1,870 | ) | ||||||
|
Gain
on sale of discontinued operations
|
(13,622 | ) | - | - | ||||||||
|
Gain
on sale of fixed assets and investments
|
(2,474 | ) | (2,219 | ) | (972 | ) | ||||||
|
Gain
on sale of coal reserves
|
(12,936 | ) | - | - | ||||||||
|
Mine
closure costs/asset impairment charges
|
34,706 | - | - | |||||||||
|
Minority
interest
|
(490 | ) | (179 | ) | - | |||||||
|
Change
in fair value of derivative instruments
|
47,265 | (8,925 | ) | (402 | ) | |||||||
|
Deferred
income tax expense (benefit)
|
(16,802 | ) | 1,032 | (48,720 | ) | |||||||
|
Other
|
2,042 | 3,637 | 1,317 | |||||||||
|
Changes
in operating assets and liabilities:
|
||||||||||||
|
Trade
accounts receivable
|
19,674 | (12,968 | ) | (24,101 | ) | |||||||
|
Notes
and other receivables
|
(6,640 | ) | (7,335 | ) | 3,124 | |||||||
|
Inventories
|
(16,037 | ) | 15,543 | 7,943 | ||||||||
|
Prepaid expenses and other current
|
||||||||||||
|
assets
|
5,202 | 15,530 | 20,922 | |||||||||
|
Other
assets
|
(2,736 | ) | (24,303 | ) | (3,688 | ) | ||||||
|
Trade
accounts payable
|
14,324 | 23,548 | (28,359 | ) | ||||||||
|
Accrued expenses and other current
|
||||||||||||
|
liabilities
|
13,864 | 11,684 | (19,805 | ) | ||||||||
|
Workers’
compensation benefits
|
622 | 1,375 | 875 | |||||||||
|
Postretirement
medical benefits
|
8,215 | 7,475 | 8,716 | |||||||||
|
Asset
retirement obligation
|
(4,825 | ) | (6,124 | ) | (3,187 | ) | ||||||
|
Other
liabilities
|
(713 | ) | 2,704 | 1,649 | ||||||||
|
Net
cash provided by
|
||||||||||||
|
operating
activities
|
$ | 458,043 | $ | 225,741 | $ | 210,081 | ||||||
|
Investing
activities:
|
||||||||||||
|
Capital
expenditures
|
$ | (137,751 | ) | $ | (126,381 | ) | $ | (131,943 | ) | |||
|
Proceeds from disposition of property, plant,
|
||||||||||||
|
and
equipment
|
16,649 | 6,101 | 1,471 | |||||||||
|
Investment
in and advances to investee
|
(199 | ) | (403 | ) | (344 | ) | ||||||
|
Proceeds
from sale of investment in coal terminal
|
1,500 | - | - | |||||||||
|
Proceeds
from sale of discontinued operations
|
45,000 | - | - | |||||||||
|
Investment
in Dominion Terminal Facility
|
(2,824 | ) | - | - | ||||||||
|
Purchase
of acquired companies
|
- | (43,908 | ) | (31,532 | ) | |||||||
| Other | - | (612 | ) | 2,302 | ||||||||
|
Net
cash used in investing activities
|
$ | (77,625 | ) | $ | (165,203 | ) | $ | (160,046 | ) | |||
|
Financing
activities:
|
||||||||||||
|
Repayments
of note payable
|
$ | (595 | ) | $ | (20,941 | ) | $ | (58,315 | ) | |||
|
Proceeds
from issuance of convertible debt
|
287,500 | - | - | |||||||||
|
Repayments
on long-term debt
|
(193,973 | ) | (15,580 | ) | (290,210 | ) | ||||||
|
Proceeds
from issuance of long-term debt
|
- | 18,900 | 286,821 | |||||||||
|
Proceeds
from issuance of common stock, net of offering costs of
$7,834
|
164,666 | - | - | |||||||||
|
Debt
issuance costs
|
(10,861 | ) | - | - | ||||||||
|
Premium
payment on early extinguishment of debt
|
(10,736 | ) | - | - | ||||||||
|
Increase
(decrease) in bank overdraft
|
(160 | ) | (23,654 | ) | 6,749 | |||||||
|
Tax
benefit from share-based compensation
|
1,980 | 40 | - | |||||||||
|
Payments
of sponsor distributions related to internal restructuring
|
- | (2,126 | ) | (2,400 | ) | |||||||
|
Proceeds
from exercise of stock options
|
3,586 | 3,932 | 954 | |||||||||
|
Net
cash provided by (used in)
|
||||||||||||
|
financing
activities
|
$ | 241,407 | $ | (39,429 | ) | $ | (56,401 | ) | ||||
| Net increase (decrease) in cash |
|
|||||||||||
|
and
cash equivalents
|
$ | 621,825 | $ | 21,109 | $ | (6,366 | ) | |||||
|
Cash
and cash equivalents at beginning of period
|
54,365 | 33,256 | 39,622 | |||||||||
|
Cash
and cash equivalents at end of period
|
$ | 676,190 | $ | 54,365 | $ | 33,256 | ||||||
|
See
accompanying notes to consolidated financial statements.
|
||||||||||||
|
(1)
|
Business
and Basis of Presentation
|
Organization
and Business
Alpha
Natural Resources, Inc. (“Alpha”) and its operating subsidiaries are
predominantly engaged in the business of extracting, processing and marketing
coal from deep and surface mines, located in the Central and Northern
Appalachian regions of the United States, for sale to utility and steel
companies in the United States. Alpha and its operating subsidiaries produce and
sell both steam coal, used mainly for electrical generation and metallurgical
coal, used in the production of steel, in the United States and in international
markets. Historically, the selling prices of metallurgical coal are more
volatile than the selling prices for steam coal.
On
February 11, 2005, Alpha, a Delaware corporation succeeded to the business
of ANR Holdings, LLC, a Delaware limited liability company (ANR Holdings) in a
series of internal restructuring transactions (“Internal Restructuring”), and on
February 18, 2005, Alpha completed the initial public offering of its
common stock. Prior to the Internal Restructuring transactions, ANR Fund IX
Holdings, L.P. and Alpha NR Holding, Inc. (the FR Affiliates), entities under
the common control of First Reserve GP IX, Inc., were the owners of 54.7% of the
membership interests in ANR Holdings, and the remaining membership interests in
ANR Holdings were held by affiliates of American Metals & Coal
International, Inc. (AMCI), Alpha Coal Management, LLC (ACM) and Madison
Capital Funding, LLC.
The FR
Affiliates were entities under the common control of First Reserve GP IX, Inc.
and were formed in 2002 to acquire coal mining assets in the Appalachian region
of the United States. In December 2002, the FR Affiliates formed ANR Holdings,
LLC (ANR Holdings). ANR Holdings was the parent of Alpha Natural Resources, LLC
and the latter entity and its subsidiaries acquired our predecessor, the
majority of the Virginia coal operations of Pittston Coal Company, a subsidiary
of The Brink's Company (formerly known as The Pittston Company), on
December 13, 2002.
The
acquisition of Coastal Coal Company, LLC was completed on January 31, 2003
by subsidiaries of ANR Holdings. The acquisition of the majority of the North
American operations of American Metals and Coal International, Inc. (U.S. AMCI)
was completed on March 11, 2003. Concurrent with the acquisition of
U.S. AMCI, ANR Holdings issued additional membership interests in the
aggregate amount of 45.3% to the former owners of U.S. AMCI, Madison
Capital Funding, LLC and members of management in exchange for the net assets of
U.S. AMCI and cash. After completion of this transaction, the FR Affiliates
owned 54.7% of ANR Holdings. Other major acquisitions include the acquisition of
Mears Enterprises, Inc. and affiliated entities on November 17, 2003, and
the acquisition of the Nicewonder Coal Group on October 26,
2005.
The
acquisition of Progress Fuel Corp, a subsidiary of Progress Energy, was
completed on May 1, 2006. 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 the Company's Enterprise business unit and were
integrated into Enterprise.
The
acquisition of Mingo Logan from Arch Coal, Inc. was completed on June 29,
2007. The Mingo Logan purchase consists of coal reserves, one active deep
mine and a load-out and processing plant, which is managed by the Company’s
Callaway business unit.
On April
7, 2008, the Company completed concurrent public offerings of 4,181,817 shares
of common stock at $41.25 per share and $287,500 aggregate principal amount of
2.375% convertible senior notes due 2015 (the “convertible
notes”). The aggregate net proceeds from the common stock offerings
and the notes offerings were $443,262 after commissions and
expenses.
Basis
of Presentation
The
consolidated financial statements for the years ended December 31, 2008, 2007
and 2006, respectively, include Alpha and its majority owned and controlled
subsidiaries. The entities included in the financial statements are collectively
referred to as “the Company.”
On
September 26, 2008, the Company sold its interests in Gallatin Materials, LLC.
(“Gallatin”) to an unrelated third party. The results of operations
for the current and prior periods have been reported as discontinued operations
(See Note 25).
|
(2)
|
Summary
of Significant Accounting Policies and
Practices
|
|
(a)
|
Cash
and Cash Equivalents
|
Cash and
cash equivalents consist of cash and highly liquid, short-term investments. Cash
and cash equivalents are stated at cost, which approximates fair market value.
The Company considers all highly liquid debt instruments with original
maturities of three months or less to be cash equivalents. The
Company’s cash equivalents are maintained in AAA rated funds, backed by the U.S.
government. As of December 31, 2008 and 2007, the Company had cash
and cash equivalents of $676,190 and $54,365, respectively.
|
(b)
|
Trade
Accounts Receivable and Allowance for Doubtful
Accounts
|
Trade
accounts receivable are recorded at the invoiced amount and do not bear
interest. The allowance for doubtful accounts is the Company's best estimate of
the amount of probable credit losses in the Company's existing accounts
receivable. The Company establishes provisions for losses on accounts receivable
when it is probable that all or part of the outstanding balance will not be
collected. The Company regularly reviews collectability and establishes or
adjusts the allowance as necessary using the specific identification method.
Account balances are charged off against the allowance after all means of
collection have been exhausted and the potential for recovery is considered
remote. The allowance for doubtful accounts was $104 and $399 at
December 31, 2008 and 2007, respectively. Credit losses were insignificant
in the three-year period ending December 31, 2008. However, the global
financial markets have been experiencing extreme disruption in recent months,
including, among other things, severely diminished liquidity and credit
availability. The Company continues to monitor these developments and
the resulting impact on its business and its suppliers and customers closely. A
continuation or worsening of the current economic conditions, a prolonged
global, national or regional economic recession or other similar events, may
significantly impact the creditworthiness of the Company’s customers, which
could increase the risk the Company bears on payment default in future
periods. The Company does not have off-balance-sheet credit exposure
related to its customers.
|
(c)
|
Inventories
|
Coal
inventories are stated at the lower of cost or market. The cost of coal
inventories is determined based on average cost of production, which includes
all costs incurred to extract, transport and process the coal. Coal is
classified as inventory at the point in time the coal is extracted from the mine
and weighed at a loading facility.
Material
and supplies inventories are valued at average cost, less an allowance for
obsolete and surplus items.
|
(d)
|
Property,
Plant, and Equipment
|
Costs for
mineral properties, mineral rights, and mine development incurred to expand
capacity of operating mines or to develop new mines are capitalized and charged
to operations on the units-of-production method over the estimated proven and
probable reserve tons. Mine development costs include costs incurred for site
preparation and development of the mine during the development stage. Mobile
mining equipment and other fixed assets are stated at cost and depreciated on a
straight-line basis over estimated useful lives ranging from 2 to 20 years.
Leasehold improvements are amortized, using the straight-line method, over their
estimated useful lives or the term of the lease, whichever is shorter. Major
repairs and betterments that significantly extend original useful lives or
improve productivity are capitalized and depreciated over the period benefited.
Maintenance and repairs are expensed as incurred.
|
(e)
|
Impairment
of Long-Lived Assets
|
In
accordance with Statement of Financial Accounting Standards
(“SFAS”) No. 144,
Accounting for the Impairment or Disposal of Long-lived Assets (“SFAS
144”), long-lived assets, such as property, plant, equipment, and purchased
intangibles subject to amortization, are reviewed for impairment whenever events
or changes in circumstances indicate that the carrying amount of an asset may
not be recoverable. Recoverability of assets to be held and used is measured by
a comparison of the carrying amount of an asset to estimated undiscounted future
cash flows expected to be generated by the asset. If the carrying amount of an
asset exceeds its estimated future cash flows, an impairment charge is
recognized by the amount by which the carrying amount of the asset exceeds the
fair value of the asset. Assets to be disposed of would be separately presented
in the balance sheet and reported at the lower of the carrying amount or fair
value less costs to sell, and would no longer be depreciated. The assets and
liabilities of a disposal group classified as held for sale would be presented
separately in the appropriate asset and liability sections of the balance
sheet.
|
(f)
|
Goodwill
|
Goodwill
represents the excess of costs over fair value of net assets of businesses
acquired. Pursuant to SFAS No. 142, Goodwill and Other Intangible
Assets (“SFAS 142”), goodwill and intangible assets acquired in a
purchase business combination and determined to have an indefinite useful life
are not amortized, but instead tested for impairment at least annually (as of
August 31) in accordance with the provisions of SFAS 142. The impairment
review in 2008 supported the carrying value of goodwill.
|
(g)
|
Health
Insurance Programs
|
The
Company is principally self-insured for costs related to health and medical
claims. The Company utilizes commercial insurance to cover specific claims in
excess of $500. Estimated liabilities for health and medical claims are recorded
based on the Company's historical experience and includes a component for
incurred but not reported claims.
|
(h)
|
Income
Taxes
|
The
Company accounts for income taxes in accordance with SFAS No. 109,
Accounting for Income
Taxes (“SFAS 109”), which requires the recognition of deferred tax
assets and liabilities using enacted tax rates for the effect of temporary
differences between the book and tax bases of recorded assets and liabilities.
SFAS 109 also requires that deferred tax assets be reduced by a valuation
allowance if it is more likely than not that some portion or all of the deferred
tax asset will not be realized. In evaluating the need for a valuation
allowance, the Company takes into account various factors, including objective
evidence obtained from historical earnings, future sales commitments, the
expected level of future taxable income and available tax planning strategies,
and the impact the alternative minimum tax has on utilization of deferred tax
assets. If future taxable income is lower than expected or if expected tax
planning strategies are not available as anticipated, we may record a change to
the valuation allowance through income tax expense in the period the
determination is made.
|
(i)
|
Asset
Retirement Obligation
|
Minimum
standards for mine reclamation have been established by various regulatory
agencies and dictate the reclamation requirements at the Company's operations.
The Company records these reclamation obligations under the provisions of
SFAS No. 143,
Accounting for Asset Retirement Obligations (“SFAS 143”). SFAS 143
requires the fair value of a liability for an asset retirement obligation to be
recognized in the period in which the legal obligation associated with the
retirement of the long-lived asset is incurred. When the liability is initially
recorded, the offset is capitalized by increasing the carrying amount of the
related long-lived asset. Over time, the liability is accreted to its present
value each period, and the capitalized cost is depreciated over the useful life
of the related asset. To settle the liability, the obligation is paid, and to
the extent there is a difference between the liability and the amount of cash
paid, a gain or loss upon settlement is recorded. The Company annually reviews
its estimated future cash flows for its asset retirement
obligations.
In
connection with the business acquisitions described in Note 20, the Company
recorded the fair value of the reclamation liabilities assumed as part of the
acquisitions in accordance with SFAS 143.
|
(j)
|
Royalties
|
Lease
rights to coal lands are often acquired in exchange for royalty payments.
Advance mining royalties are advance payments made to lessors under terms of
mineral lease agreements that are recoupable against future production. These
advance payments are deferred and charged to operations as the coal reserves are
mined. The Company regularly reviews recoverability of advance mining royalties
and establishes or adjusts the allowance for advance mining royalties as
necessary using the specific identification method. In instances where advance
payments are not expected to be offset against future production royalties, the
Company establishes a provision for losses on the advance payments that have
been paid and the scheduled future minimum payments are expensed and recognized
as liabilities. Advance royalty balances are charged off against the allowance
when the lease rights are either terminated or expire.
The
changes in the allowance for advance mining royalties were as
follows:
|
Balance
at December 31, 2005
|
$
|
4,830
|
||
|
Provision
for non-recoupable advance mining royalties
|
2,215
|
|||
|
Write
offs of advance mining royalties
|
(766
|
) | ||
|
Balance
at December 31, 2006
|
6,279
|
|||
|
Provision
for non-recoupable advance mining royalties
|
511
|
|||
|
Write
offs of advance mining royalties
|
(1,254
|
) | ||
|
Balance
at December 31, 2007
|
5,536
|
|||
|
Provision
for non-recoupable advance mining royalties
|
4,453
|
|||
|
Write
offs of advance mining royalties
|
(2,060
|
) | ||
|
Balance
at December 31, 2008
|
$
|
7,929
|
||
|
(k)
|
Revenue
Recognition
|
The
Company recognizes revenue on coal sales when title passes to the customer in
accordance with the terms of the sales agreement. Revenue from domestic coal
sales is recorded at the time of shipment or delivery to the customer, and the
customer takes ownership and assumes risk of loss based on shipping terms.
Revenue from international coal sales is recorded at the time coal is loaded
onto the shipping vessel, when the customer takes ownership and assumes risk of
loss. In the event that a new contract is negotiated with a customer
who incorporates an old contract with different pricing, the Company recognizes
as revenue the lower of the cumulative amount billed or an amount based on the
weighted average price of the new and old sales price applied to the tons
sold.
Freight
and handling costs paid to third-party carriers and invoiced to coal customers
are recorded as freight and handling costs and freight and handling revenues,
respectively.
Other
revenues generally consist of road construction, equipment and parts sales,
equipment rebuild and maintenance services, coal handling and processing,
royalties and rental income. These revenues, except for road construction, are
recognized in the period earned or when the service is
completed. Revenue from road construction contracts is recognized
under the percentage of completion method of accounting for long-term contracts
in accordance with Accounting Research Bulletin No. 45, Long-Term Construction
Contracts, and
the American Institute of Certified Public Accountants Statement of Position
81-1, Accounting for
Performance of Construction-Type and Certain Production-Type
Contracts.
|
(l)
|
Deferred
Financing Costs
|
Deferred
financing costs are being amortized to interest expense over the life of the
related indebtedness or credit facility using the straight-line method which
approximates the effective interest method. Unamortized deferred financing costs
are included in other assets in the accompanying balance sheets. On July
1, 2008, the Company’s 2.375% senior convertible notes became convertible at the
option of the holders and remained convertible through September 30,
2008. As a result of the notes becoming convertible, in the second
quarter of 2008, the Company fully amortized the deferred debt issuance costs in
the amount of $8,904 million incurred with the issuance of the convertible notes
on April 7, 2008. Amortization expense for the years ended
December 31, 2008, 2007 and 2006 totaled $11,904, $2,318 and $2,282,
respectively.
|
(m)
|
Virginia
Coalfield Employment Enhancement Tax
Credit
|
For tax
years 1996 through 2014, Virginia companies with an economic interest in coal
earn tax credits based upon tons sold, seam thickness, and employment levels.
The maximum credit earned equals $0.40 per ton for surface mined coal and
$1.00 or $2.00 per ton for deep mined coal depending on seam thickness.
Credits allowable are reduced from the maximum amounts if employment levels are
not maintained from the previous year, and no credit is allowed for coal sold to
Virginia utilities. Currently, the cash benefit of the credit is realized three
years after being earned and either offsets taxes imposed by Virginia at 100% or
is refundable by the state at 85% of the face value to the extent taxes are not
owed. The Company records the present value of the portion of the credit that is
refundable as a reduction of operating costs as it is
earned.
|
(n)
|
Workers'
Compensation and Pneumoconiosis (Black Lung)
Benefits
|
Workers'
Compensation
The
Company is self-insured for workers' compensation claims at certain of its
operations in West Virginia. Workers' compensation at all other locations in
West Virginia and at locations in all other states where the Company operates is
covered by a third-party insurance provider.
The
liabilities for workers' compensation claims that are self-insured are estimates
of the ultimate losses incurred based on the Company's experience, and include a
provision for incurred but not reported losses. Adjustments to the probable
ultimate liabilities are made annually based on an actuarial study and
adjustments to the liability are recorded based on the results of this
study.
Black
Lung Benefits
The
Company is required by federal and state statutes to provide benefits to
employees for awards related to black lung disease. These claims are covered by
a third-party insurance provider in all locations where the Company operates
with the exception of West Virginia. The Company is self-insured for state black
lung related claims at certain locations in West Virginia. The Company accounts
for self-insured black lung obligations under the provisions of SFAS No.
106, Employers' Accounting for
Postretirement Benefit Other than Pension (“SFAS 106”), and SFAS No.
158, Employers' Accounting for
Defined Benefit Pension and Other Postretirement Plans (“SFAS
158”).
Charges
are made to operations for self-insured state black lung claims in West
Virginia, as determined by an independent actuary at the present value of the
actuarially computed liability for such benefits over the employee's applicable
term of service. The Company did not assume any responsibility for workers'
compensation or black lung claims incurred by any of its subsidiaries prior to
their acquisition. Effective December 31, 2006, the Company adopted SFAS 158,
which requires that the Company recognize on its balance sheet the amount of the
Company's unfunded Accumulated Benefit Obligation (“ABO”) at the end of the
year. The initial effect of the adoption of SFAS 158 was recorded in accumulated
other comprehensive loss, net of tax. Amounts recognized in accumulated other
comprehensive loss are adjusted out of accumulated other comprehensive loss when
they are subsequently recognized as components of net periodic benefit
cost. Subsequent to the year of adoption, these are recorded as
components of comprehensive income (loss).
|
(o)
|
Postretirement
Benefits Other Than Pensions
|
The
Company accounts for health care benefits provided for current and certain
retired employees and their dependents by accruing the cost of such benefits
over the service lives of employees. Unrecognized actuarial gains and losses are
amortized over the estimated average remaining service period for active
employees and over the estimated average remaining life for retirees. Effective
December 31, 2006, the Company adopted SFAS 158, which requires that the Company
recognize on its balance sheet the amount of the Company's unfunded Accumulated
Postretirement Benefit Obligation (“APBO”) at the end of the year. The initial
effect of the adoption of SFAS 158 was recorded in accumulated other
comprehensive loss, net of tax. Amounts recognized in accumulated other
comprehensive loss are adjusted out of accumulated other comprehensive loss when
they are subsequently recognized as components of net periodic benefit
cost. Subsequent to the year of adoption, these are recorded as components
of comprehensive income (loss).
|
(p)
|
Equity
Investments
|
The
accompanying consolidated financial statements include the accounts of the
Company and its majority owned subsidiaries. Investments in unconsolidated
subsidiaries representing ownership of at least 20% but less than 50% are
accounted for under the equity method. Under the equity method of accounting,
the Company's proportionate share of the investment company's income or loss is
included in the Company's net income or loss with a corresponding increase or
decrease in the carrying value of the investment.
|
(q)
|
Share-Based
Compensation
|
Effective
January 1, 2006, the Company adopted SFAS No. 123(R), Share-Based Payment (“SFAS
123(R)”), which requires that the measurement and recognition of compensation
expense for all stock-based payment awards made to employees and directors be
based on the estimated fair value of the awards over the requisite service or
vesting period. Prior to January 1, 2006, the Company measured stock-based
compensation expense using the intrinsic value method of accounting in
accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to
Employees, and related interpretations (“APB 25”).
In
adopting SFAS 123(R), the Company has elected to use the modified prospective
transition method and accordingly, has not restated results from prior periods.
Under this transition method, stock-based compensation expense includes
compensation expense for all stock-based compensation awards granted prior to,
but not yet vested as of January 1, 2006, based on the grant date fair value
estimated in accordance with the original provisions of SFAS No. 123, Accounting for Stock-Based
Compensation (“SFAS 123”). Stock-based compensation expense for all
awards granted after December 31, 2005 is also based on the grant-date fair
value estimated in accordance with the provisions of SFAS 123(R).
|
(r)
|
Derivative
Financial Instruments
|
Derivative
financial instruments are accounted for in accordance with 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.
The
Company accounts for certain forward purchase and forward sale contracts that do
not qualify under the “normal purchase and normal sale” exception of SFAS 133 as
derivatives and records these contracts as assets or liabilities at fair value.
Accordingly, changes in fair value for these forward sales and forward purchase
contracts have been recorded in the income statement and are reflected in
(increase) decrease in fair value of derivatives instruments, net. At December
31, 2008, we had unrealized gains (losses) on open sales and purchase contracts
in the amount of $2,854 and ($3,042), respectively. At December 31, 2007, the
Company had unrealized gains (losses) on open sales and purchase contracts of
($2,139) and $11,253, respectively. These amounts are recorded in prepaid
expenses and other current assets and accrued expenses and other current
liabilities, respectively.
The
Company utilizes interest rate swap agreements to modify the interest
characteristics of a portion of the Company's outstanding debt. The swap
agreements essentially convert variable-rate debt to fixed-rate debt and have
been designated as cash flow hedges. Changes in the fair value of interest
rate swaps designated as hedging instruments of the variability of cash flows
associated with floating rate and long-term debt obligations are reported in
accumulated other comprehensive income (loss). These amounts are
subsequently reclassified into interest expense in the same period in which the
related floating rate debt obligation affects earnings.
The
Company is also exposed to the risk of fluctuations in cash flows related to its
purchase of diesel fuel. The Company has entered into diesel fuel swap
agreements and diesel fuel put options to reduce the volatility in the price of
diesel fuel for its operations. The diesel fuel swap agreements and put options
are not designated as hedges for accounting purposes, and therefore the changes
in the fair value for these derivative instrument contracts have been recorded
in the income statement and are reflected in (increase) decrease in fair value
of derivative instruments, net. These diesel fuel swaps and put options use the
NYMEX New York Harbor #2 heating oil as the underlying commodity reference
price. Any unrealized loss is recorded in other current liabilities
and other liabilities. Any unrealized gain is recorded in other
current assets and other assets.
As of
December 31, 2008, we had in place swap agreements with respect to 33.1 million
gallons of diesel fuel, at fixed prices ranging from $1.61 to $4.10 per gallon,
which mature in 2009 to 2011. At December 31, 2008, the fair value of
these diesel fuel swap agreements is a liability of $37,988, of which $21,176 is
recorded in accrued expenses and other current liabilities and $16,812 is
recorded in other liabilities. At December 31, 2007, the fair value
of diesel fuel swap agreements was an asset of $36.
We have
also employed an options strategy – both purchasing and selling put options – to
protect cash flows in the event diesel fuel prices decline. As of December 31,
2008, we had purchased put options for 2.6 million gallons for the first six
months of 2009 at a strike price of $3.50 per gallon. In the event that No. 2
heating oil prices decline below the strike price, we can exercise the put
options and sell the 2.6 million gallons at the strike price, therefore reducing
the negative impact of any of the swap agreements that have settlement prices
above market. As of December 31, 2008, we also sold put options for 2.6 million
gallons for the first six months of 2009 at a strike price of $3.00 per gallon.
This was part of a put spread strategy that effectively provided protection for
market prices between $3.00 and $3.50. In the event that No. 2
heating oil prices decline below the $3.00 strike price, then the sold put
options will offset the purchased put options with no net benefit or
cost. The fair value of all these diesel fuel put options is a net
asset of $1,281 of which $5,186 is recorded in prepaid expenses and other
current assets and $3,905 is recorded in accrued expenses and other current
liabilities as of December 31, 2008. At December 31, 2007, the fair
value of diesel fuel put options was an asset of $204.
|
(s)
|
New
Accounting Pronouncements Issued and not yet
Adopted
|
In May
2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff
Position (“FSP”) Accounting Principles Board (“APB”) 14-1, Accounting for Convertible Debt
Instruments that may be settled in cash upon conversion (Including partial cash
settlement) (“FSP APB 14-1”), which applies to convertible debt
instruments that, by their stated terms, may be settled in cash (or other
assets) upon conversion, including partial cash settlement, unless the embedded
conversion option is required to be separately accounted for as a derivative
under SFAS 133. FSP APB 14-1 requires issuers of such instruments to
separately account for the liability and equity components in a manner that will
reflect the entity’s nonconvertible debt borrowing rate when interest cost is
recognized in subsequent periods. This FSP is effective for financial
statements issued for fiscal years beginning after December 31, 2008, and
interim periods within those fiscal years. Early adoption is not
permitted and retroactive application to all periods presented is
required. Upon adoption of FSP APB 14-1, on January 1, 2009, the
Company will retrospectively apply the change in accounting principle to prior
accounting periods as if the principle has always been used. The adoption of FSP
APB 14-1 will result in an estimated pre-tax increase to non-cash interest
expense in future annual periods of approximately $11,944. Upon
retrospective application in 2009, the adoption will also result in 2008 pretax
decrease of non-cash interest expense of $547, which is comprised of the
reversal of $8,904 of previously written off deferred loan costs net of $7,720
of additional interest expense for the accretion of the liability component of
the debt and $637 of deferred loan cost amortization. Adoption of the
standard will also result in the following pre-tax balance sheet impacts at
December 31, 2008; (1) a reduction of debt by approximately $87,791 and an
increase in paid in capital by $95,511
and (2) an increase to deferred loan costs by
approximately $5,309, an increase to paid in capital by $2,958 with a
pre-tax credit of $8,904 to the income statement to record deferred loan costs
previously written off when the notes became convertible and to allocate those
costs between the portion related to the debt and equity
components. The company is continuing to analyze the tax impacts of
adopting the new standard, but currently expects that adoption will also result
in an increase to deferred tax liabilities and a decrease to the valuation
allowance against deferred tax assets with the offsetting impact of these
entries being recorded to paid-in-capital.
In March
2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities (“SFAS 161”), which amends SFAS
133. SFAS 161 is intended to improve financial reporting about
derivative instruments and hedging activities by requiring enhanced disclosures
to enable investors to better understand their effects on an entity’s financial
position, financial performance, and cash flows. The new standard also improves
transparency about the location and amounts of derivative instruments in an
entity’s financial statements; how derivative instruments and related hedged
items are accounted for under SFAS 133; and how derivative instruments and
related hedged items affect its financial position, financial performance, and
cash flows. Since SFAS 161 requires only additional disclosures concerning
derivatives and hedging activities, adoption of SFAS 161 will not affect the
Company’s financial position and results of operations.
In
December 2007, the FASB issued SFAS 141(R), Business Combinations (“SFAS
141(R)”), and SFAS No. 160, Accounting and Reporting of
Noncontrolling Interest in Consolidated Financial Statements, an amendment of
ARB No. 51 (“SFAS 160”). SFAS 141(R) and SFAS 160
will significantly change the accounting for and reporting of business
combination transactions and noncontrolling (minority) interests in consolidated
financial statements. SFAS 141(R) retains the underlying concepts of SFAS
141, Business
Combinations, in that all business combinations are still required to be
accounted for at fair value under the acquisition method of accounting, but SFAS
141(R) changed the method of applying the acquisition method in a number of
significant aspects. Acquisition costs will generally be expensed as incurred;
noncontrolling interests will be valued at fair value at the acquisition date;
in-process research and development will be recorded at fair value as an
indefinite-lived intangible asset at the acquisition date, until either
abandoned or completed, at which point the useful lives will be determined;
restructuring costs associated with a business combination will generally be
expensed subsequent to the acquisition date; and changes in deferred tax asset
valuation allowances and income tax uncertainties after the acquisition date
generally will affect income tax expense. SFAS 160 will change the accounting
and reporting for minority interests, which will be recharacterized as
noncontrolling interests, and classified as a component of
equity. These pronouncements will become effective January 1,
2009. Upon adoption, SFAS 141(R) will not have a significant impact
on the Company’s consolidated financial statements; however, any business
combination the Company enters into after the adoption may significantly impact
the Company’s financial position and results of operations when compared to
acquisitions accounted for under existing U.S. Generally Accepted Accounting
Principles (GAAP) and result in more earnings volatility and generally lower
earnings due to the expensing of deal costs and restructuring costs of acquired
companies. Upon adoption, SFAS 160 will not have an impact on the
Company’s consolidated financial statements until, if or when the Company
effectuates a business combination post adoption that has noncontrolling
(minority) interests.
|
(t)
|
Adoption
of SAB 108
|
On
September 13, 2006, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 108, Considering the Effects of Prior
Year Misstatements when Quantifying Misstatements in Current Year Financial
Statements (“SAB 108”), which provides interpretive guidance on the
consideration of effects of prior year misstatements in quantifying current year
misstatements for the purpose of assessing materiality. SAB 108 was effective
for the Company for the year ended December 31, 2006 and provided for a one time
transitional cumulative effect adjustment to retained earnings as of January 1,
2006 for errors which were not previously deemed to be material, but which are
material under the guidance of SAB 108. As a result of the adoption of SAB 108,
the Company changed its method of accounting for costs related to perpetual
water treatment and also for certain materials and supplies inventories which
are used in mining operations. For the year ended December 31, 2006,
the Company recorded a cumulative effect adjustment to increase beginning
retained earnings by $717 (net of income tax effect of $238) for the net effect
of these accounting changes. The Company considered the impact of these errors
to be immaterial prior to the adoption of SAB 108.
Perpetual
Water Treatment
The
Company is legally obligated to treat runoff and effluence for its mines and
preparation plants, including for closed sites, and prior to the adoption of SAB
108 had historically expensed these costs as paid. The Company believes these
costs should be accrued when incurred pursuant to
SFAS 143. Substantially all of these obligations existed upon
formation of the Company and were assumed as a result of acquisitions prior to
formation. Upon adoption of SAB 108 for the year ended December 31, 2006, the
Company recorded an increase to property, plant and equipment, net of $1,877, an
increase to goodwill of $1,906, an increase to deferred tax assets of $678,
an increase to other long-term assets of $82, a reduction of deferred gain on
sales of property interest of $1,115, an increase to asset retirement obligation
of $7,700 and a decrease in beginning retained earnings of $2,042.
Mine
Supplies Inventory
Since its
formation, the Company has not recorded as inventory certain mine supplies,
including tires, explosives and fuel that are maintained at some of its mines
and used in mine operations. The Company's policy was to expense these costs
when the supplies were purchased. Since the inventory balances remained
consistent from period to period, the impact of this policy was considered
immaterial prior to the adoption of SAB 108. Upon adoption of SAB 108, the
Company changed its policy to record these amounts in inventory when purchased
and to expense the items when used in mining operations. For the year ended
December 31, 2006, the Company recorded an increase to inventory of $3,675, a
decrease in deferred tax assets of $916 and an increase in beginning retained
earnings of $2,759.
|
(u)
|
Use
of Estimates
|
The
preparation of financial statements in conformity with U.S. generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Significant items subject to such estimates and assumptions
include inventories; mineral reserves; allowance for non-recoupable advance
mining royalties; asset retirement obligations; employee benefit liabilities;
future cash flows associated with assets; useful lives for depreciation,
depletion, and amortization; workers' compensation and black lung claims;
postretirement benefits other than pensions; income taxes; revenue recognized
using the percentage of completion method and the related estimated costs to
complete; and fair value of financial instruments. Due to the subjective nature
of these estimates, actual results could differ from those
estimates.
|
(v)
|
Reclassifications
|
Prior
period coal revenues and cost of coal sales have been adjusted to exclude
changes in the fair value of coal and diesel fuel derivative contracts to
conform to the current year presentation. In addition, prior period
trade accounts payable and accrued expenses and other current liabilities have
been reclassified to reflect the current year presentation. These
reclassification adjustments had no effect on previously reported income from
operations, net income, current liabilities, or total liabilities.
|
(3)
|
Earnings
Per Share
|
The
number of shares used to calculate basic earnings (loss) per share is based on
the weighted average number of the Company’s outstanding common shares during
the respective periods. The number of shares used to calculate diluted earnings
(loss) per share is based on the number of common shares used to calculate basic
earnings (loss) per share plus the dilutive effect of stock options and other
stock-based instruments held by the Company’s employees and directors during
each period and the 2.375% convertible senior notes due 2015 that are
convertible into the Company’s common stock. The convertible senior notes due
2015 become dilutive for earnings per share calculations when the average share
price for the quarter exceeds the conversion price of $54.66. The
shares that would be issued to settle the conversion spread are included in the
diluted earnings per share calculation when the conversion option is in the
money and amounted to 734,613 shares for the December 31, 2008 year to date
diluted earnings per share calculation.
The
computations of basic and diluted net income per share for 2008, 2007, and
2006, are set forth below:
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Numerator:
|
||||||||||||
|
Income
from continuing operations
|
$ | 161,345 | $ | 29,990 | $ | 128,168 | ||||||
|
Income
(loss) from discontinued operations
|
4,192 | (2,256 | ) | - | ||||||||
|
Net
income
|
$ | 165,537 | $ | 27,734 | $ | 128,168 | ||||||
|
Denominator:
|
||||||||||||
|
Weighted
average shares - basic
|
68,453,724 | 64,631,507 | 64,093,571 | |||||||||
|
Dilutive
effect of stock equivalents
|
1,806,011 | 377,923 | 57,209 | |||||||||
|
Weighted
average shares- diluted
|
70,259,735 | 65,009,430 | 64,150,780 | |||||||||
|
Basic
earnings per share:
|
||||||||||||
|
Income
from continuing operations
|
$ | 2.36 | $ | 0.46 | $ | 2.00 | ||||||
|
Income
(loss) from discontinued operations
|
0.06 | (0.03 | ) | - | ||||||||
|
Net
income per basic share
|
$ | 2.42 | $ | 0.43 | $ | 2.00 | ||||||
|
Diluted
earnings per share:
|
||||||||||||
|
Income
from continuing operations
|
$ | 2.30 | $ | 0.46 | $ | 2.00 | ||||||
|
Income
(loss) from discontinued operations
|
0.06 | (0.03 | ) | - | ||||||||
|
Net
income per diluted share
|
$ | 2.36 | $ | 0.43 | $ | 2.00 | ||||||
|
(4)
|
Inventories
|
Inventories
consisted of the following:
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Raw
coal
|
$ | 9,018 | $ | 8,754 | ||||
|
Saleable
coal
|
61,297 | 48,928 | ||||||
|
Equipment
purchased for resale
|
2,282 | 1,688 | ||||||
|
Materials
and supplies
|
13,997 | 11,410 | ||||||
|
Total
inventories
|
$ | 86,594 | $ | 70,780 | ||||
|
(5)
|
Prepaid
Expenses and Other Current Assets
|
Prepaid
expenses and other current assets consisted of the following:
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Prepaid
insurance
|
$ | 22,148 | $ | 20,958 | ||||
|
Advanced
mining royalties, net
|
2,538 | 4,884 | ||||||
|
Refundable
income taxes
|
- | 8,841 | ||||||
|
Fair
value of certain derivative contracts instruments
|
8,040 | 11,492 | ||||||
|
Prepaid
freight
|
11,312 | 11,213 | ||||||
|
Other
prepaid expenses
|
6,213 | 2,566 | ||||||
|
Total
prepaid expenses and other current assets
|
$ | 50,251 | $ | 59,954 | ||||
|
(6)
|
Property,
Plant, and Equipment
|
Property,
plant, and equipment consisted of the following:
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Land
|
$ | 12,882 | $ | 14,226 | ||||
|
Mineral
rights
|
339,330 | 343,152 | ||||||
|
Plant
and mining equipment
|
681,362 | 616,917 | ||||||
|
Vehicles
|
7,154 | 5,659 | ||||||
|
Mine
development
|
84,815 | 61,433 | ||||||
|
Office
equipment and software
|
15,118 | 13,030 | ||||||
|
Construction
in progress
|
3,982 | 25,410 | ||||||
| 1,144,643 | 1,079,827 | |||||||
|
Less
accumulated depreciation, depletion, and amortization
|
594,545 | 439,569 | ||||||
|
Property,
plant, and equipment, net
|
$ | 550,098 | $ | 640,258 | ||||
As of
December 31, 2008, the Company had commitments to purchase approximately
$63,980 of new equipment, expected to be acquired at various dates in
2009.
Depreciation
and amortization expense associated with property, plant and equipment was
$127,929, $120,749 and $100,732, and depletion expense was $48,011, $43,730 and
$40,716, for the years ended December 31, 2008, 2007, and 2006,
respectively.
Interest
costs applicable to major asset additions are capitalized during the
construction period. During the years ended December 31, 2008, 2007,
and 2006, interest costs of $942, $1,743, and $827 were
capitalized.
|
(7)
|
Other
Intangibles
|
Other
intangible assets consisted of the following:
|
December
31, 2008
|
December
31, 2007
|
|||||||||||||||
|
Gross
Carrying
Amount
|
Accumulated
Amortization
|
Gross
Carrying
Amount
|
Accumulated
Amortization
|
|||||||||||||
|
Sales
contracts
|
$ | 5,084 | $ | 2,994 | $ | 5,084 | $ | 1,907 | ||||||||
|
Customer
relationships
|
4,762 | 3,017 | 8,006 | 2,065 | ||||||||||||
|
Noncomplete
agreements
|
- | - | 927 | 669 | ||||||||||||
| $ | 9,846 | $ | 6,011 | $ | 14,017 | $ | 4,641 | |||||||||
Total
amortization expense for the above intangible assets was $2,297, $2,122 and
$3,210 for the years ended December 31, 2008, 2007 and 2006, respectively,
and is expected to be approximately $2,429, $1,199, $69, and $138 for the years
ended December 31, 2009, 2010, 2011, and thereafter,
respectively.
|
(8)
|
Other
Assets
|
Other
assets consisted of the following:
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Advance
mining royalties, net
|
$ | 14,234 | $ | 16,174 | ||||
|
Deferred
loan costs, net of accumulated amortization of $4,515 and $6,245 in 2008
and 2007, respectively
|
6,852 | 11,501 | ||||||
|
Investment
in terminal facility
|
3,484 | 1,498 | ||||||
|
Investment
in Excelven Pty Ltd
|
- | 4,870 | ||||||
|
Virginia
tax credit receivable
|
19,242 | 20,181 | ||||||
|
Davis-Bacon
litigation (See Note 23)
|
7,925 | 6,125 | ||||||
|
Other
|
2,840 | 3,045 | ||||||
|
Total
other assets
|
$ | 54,577 | $ | 63,394 | ||||
|
(9)
|
Note Payable
|
At
December 31, 2008, the company had one note payable for $18,288 that was
incurred to finance various insurance premiums. Interest, which accrues at the
rate of 4.44%, and principal are due in monthly installments, with the final
payment due in October 2009. At December 31, 2007, note payable
included $18,883 that was incurred to finance various insurance premiums.
Interest, which accrued at the rate of 4.96%, and principal were paid in monthly
installments, with the final payment paid in September 2008.
|
(10)
|
Accrued
Expenses and Other Current
Liabilities
|
Accrued
expenses and other current liabilities consisted of the following:
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Wages
and employee benefits
|
$ | 48,174 | $ | 29,750 | ||||
|
Current
portion of asset retirement obligation
|
8,375 | 8,179 | ||||||
|
Taxes
other than income taxes
|
15,489 | 16,884 | ||||||
|
Freight
|
8,575 | 8,154 | ||||||
|
Contractor
escrow
|
1,524 | 1,201 | ||||||
|
Deferred
revenues
|
755 | 1,355 | ||||||
|
Current
portion of self-insured workers' compensation benefits
|
1,718 | 1,779 | ||||||
|
Workers'
compensation insurance premium payable
|
635 | 1,340 | ||||||
|
Interest
payable
|
3,237 | 2,876 | ||||||
|
Fair
value of certain derivative contracts
|
28,123 | 2,139 | ||||||
|
Unamortized
portion of unfavorable coal sales contract
|
2,894 | 6,763 | ||||||
|
Construction
billings in excess of costs
|
- | 5,454 | ||||||
|
Income
taxes payable
|
11,749 | - | ||||||
|
Other
|
9,211 | 10,224 | ||||||
|
Total
accrued expenses and other current liabilities
|
$ | 140,459 | $ | 96,098 | ||||
|
(11)
|
Long-Term
Debt
|
Long-term debt consisted of the following:
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Term
loan due 2012
|
$ | 233,125 | $ | 233,125 | ||||
|
2.375%
convertible senior note due 2015
|
287,500 | - | ||||||
|
10%
senior notes repurchased in 2008
|
- | 175,000 | ||||||
|
Gallatin
loan facility
|
- | 18,500 | ||||||
|
Capital
lease obligation
|
232 | 705 | ||||||
|
Other
|
- | 700 | ||||||
|
Total
long-term debt
|
520,857 | 428,030 | ||||||
|
Less
current portion
|
232 | 2,579 | ||||||
|
Long-term
debt, net of current position
|
$ | 520,625 | $ | 425,451 | ||||
Term
Loan
On
October 26, 2005, Alpha Natural Resources, LLC (“ANR LLC”), entered into a
senior secured credit facility with a group of lending institutions led by
Citicorp North America, Inc., as administrative agent (the “Credit Facility”).
The Credit Facility consists of a $250,000 term loan facility and a $275,000
revolving credit facility. The revolving credit facility includes borrowing
capacity available for letters of credit.
In March
2008, the Company and its subsidiary, ANR LLC, entered into two amendments to
the related Credit Agreement. One of these amendments increased the
amount available under the revolving credit portion of the facility from
$275,000 to $375,000. The other amendment, among other things, removed Alpha
Natural Resources, Inc. from the application of most of the restrictive
covenants and added exceptions to certain other covenants relating to payment of
dividends and distributions.
On
October 6, 2008, the Parent and ANR LLC entered into a further amendment to the
credit agreement. This amendment included certain technical
amendments to permit ANR LLC and certain of its affiliates to enter into a
permitted receivables financing, as well as an increase in the limit on annual
capital expenditures from $150 million to $200 million.
As of
December 31, 2008 and 2007, there were $233,125 in borrowings under the
term loan facility and no borrowings under the revolving credit facility. In
addition, there were $82,575 and $82,195 in letters of credit outstanding for
December 31, 2008 and 2007, respectively. At December 31, 2008, $292,425 was
available for borrowing.
The
Credit Agreement places restrictions on the ability of ANR LLC and its
subsidiaries to make distributions or loans to the Company. The net assets of
ANR LLC are restricted, except for allowable distributions for the payment of
income taxes, administrative expenses, payments on qualified debt, and, in
certain circumstances, dividends or repurchases of common stock of the
Company.
All of the Company borrowings under the
Credit Agreement are at a variable rate, so the Company is exposed to the effect
of rising interest rates. As of December 31, 2008, the Company has a $233,125
term loan outstanding with a variable interest rate based upon the 3-month
London Interbank Offered Rate (“LIBOR”) (1.50% at December 31, 2008) plus the
applicable margin (1.50% at December 31, 2008). To reduce the Company's exposure
to rising interest rates, effective May 22, 2006, the Company entered into a
pay-fixed, receive variable interest rate swap on the notional amount of
$233,125 for a period of approximately six and one-half years. In effect, this
swap converted the variable interest rates based on LIBOR to a fixed interest
rate of 5.59% plus the applicable margin defined in the debt agreement for the
remainder of our term loan. The Company accounts for the interest rate swap as a
cash flow hedge and changes in fair value of the swap are recorded to other
comprehensive income (loss). The critical terms of the swap and the underlying
debt instrument that it hedges coincide; resulting in no hedge ineffectiveness
being recognized in the income statement during the years ended December 31,
2008, 2007, and 2006. The fair value of the swap at December 31, 2008
was a liability of $27,929 which was recorded in other liabilities in the
condensed consolidated balance sheet and the offsetting unrealized loss of
$20,961, net of tax benefit, was recorded in accumulated other comprehensive
loss. As interest expense is accrued on the debt obligation, amounts in
accumulated other comprehensive loss related to the derivative hedging
instrument are reclassified into earnings to obtain a net cost on the debt
obligation of 5.59% plus the applicable margin. For the years ended
December 31, 2008, 2007, and 2006, $4,904, $648, and $314 of losses in
accumulated other comprehensive loss were reclassified into interest
expense.
2.375% Convertible
Senior Notes Due June 2015
On April
7, 2008, the Company completed a public offering of $287,500 aggregate principal
amount of 2.375% convertible senior notes due 2015. The notes bear
interest at a rate of 2.375% per annum, payable semi-annually in arrears on
April 15 and October 15 of each year, beginning on October 15, 2008. The Notes
will mature on April 15, 2015, unless previously repurchased by the Company or
converted. The convertible senior notes are the Company's senior
unsecured obligations and rank equally with all existing and future senior
unsecured indebtedness. The convertible senior notes are effectively
subordinated to all of the existing and future secured indebtedness and all
existing and future liabilities of the Company’s subsidiaries, including trade
payables. The Company used the net proceeds from this offering and concurrent
offering of common stock, in part, to repurchase $175,000 aggregate principal
amount of the 10% senior notes due 2012, co-issued by ANR LLC and Alpha Natural
Resources Capital Corp, resulting in a $14,702 loss on early extinguishment of
debt.
The
convertible senior notes will be convertible into cash or cash and shares of the
Company’s common stock based on an initial conversion rate, subject to
adjustment, of 18.2962 shares per $1,000 principal amount of notes (which
represents an initial conversion price of approximately $54.66 per share), in
certain circumstances. Subject to earlier repurchase, holders may
convert their convertible senior notes prior to the close of business on the
business day immediately preceding the maturity date only under the following
circumstances:
|
|
1.
|
the
convertible senior notes will be convertible during any calendar quarter
(and only during that quarter) if the closing sale price per share of the
Company’s common stock for each of 20 or more trading days in a period of
30 consecutive trading days ending on the last trading day of the
immediately preceding calendar quarter exceeds 130% of the conversion
price in effect on the last trading day of the immediately preceding
calendar quarter;
|
|
|
2.
|
the
convertible senior notes will be convertible during the five consecutive
business days immediately after any five consecutive trading day
period in which the average trading price per $1,000 principal amount
of notes was equal to or less than 97% of the average conversion value of
the notes during
that note period;
|
|
|
3.
|
the
convertible senior notes will be convertible upon the occurrence of
specified corporate transactions;
and
|
|
|
4.
|
the
convertible senior notes will be convertible at any time from, and
including, January 15, 2015 until the close of business on the
business day immediately preceding April 15,
2015.
|
Upon
conversion of the convertible senior notes, holders will receive cash up to the
principal amount of the notes to be converted, and any excess conversion value
will be delivered in cash, shares of common stock or a combination thereof, at
the Company's election. A holder that surrenders convertible senior
notes for conversion in connection with a “make-whole fundamental change,” as
defined in the supplemental indenture relating to the notes, may in certain
circumstances be entitled to an increased conversion rate. In
addition, if a "fundamental change" (also as defined in the supplemental
indenture) occurs, holders may require the Company to repurchase all or a
portion of their convertible senior notes at a repurchase price in cash equal to
100% of the principal amount of the notes to be repurchased, plus any accrued
and unpaid interest to, but excluding, the fundamental change repurchase
date. The convertible senior notes are not redeemable at the
Company’s option prior to maturity.
On July
1, 2008, the convertible senior notes became convertible at the option of the
holders and remained convertible through September 30, 2008. The
notes were convertible because the Company’s common stock exceeded the
conversion threshold price of $71.06 per share (130% of the applicable
conversion price of $54.66 per share) for at least twenty trading days ending
June 30, 2008. As a result of the notes becoming convertible, in the
second quarter of 2008, the Company fully amortized the deferred debt issuance
costs in the amount of $8,904. The convertible senior notes are not
convertible at December 31, 2008 and as a result they are classified as long
term.
10% Senior
Notes Due June 2012
In 2008,
ANR LLC and Alpha Natural Resources Capital Corp. repurchased $175,000 aggregate
principal amount of the 10% senior notes due June 2012, resulting in a $14,702
loss on early extinguishment of debt. The $175,000 aggregate
principal amount of 10% senior notes due 2012 was issued on May 18, 2004 by
ANR, LLC and its wholly-owned subsidiary, Alpha Natural Resources Capital Corp.
in a private placement offering under Rule 144A of the Securities Act of
1933, as amended, resulting in net proceeds of approximately $171,500 after fees
and other offering costs. The senior notes were unsecured but were guaranteed
fully and unconditionally on a joint and several basis by all of the Company's
wholly-owned domestic restricted subsidiaries other than the issuers of the
notes, and the Company, as the parent guarantor as a result of the merger of ANR
Holdings in the Company. The senior notes were the Company's senior unsecured
obligations and ranked equally in right of payment to any existing and future
unsecured indebtedness and ranked senior in right of payment to any future
subordinated or senior subordinated indebtedness. The senior notes were
effectively subordinated in right of payment to the Company's secured
indebtedness, including borrowings under the credit facility. Interest on the
senior notes was payable semi-annually in June and December.
Gallatin
Loan Facility
Gallatin
entered into a non-recourse senior secured loan facility with Nedbank Limited on
December 28, 2006 (the “Gallatin Loan Facility”) to provide phase one project
financing for the construction of assets in the amount of $20,550 at an interest
rate based upon the 6-month London Interbank Offered Rate (“LIBOR”) plus an
applicable margin. The final maturity date was July 26,
2016. On September 26, 2008, the Company sold Gallatin for cash
in the amount of $45,000. The proceeds were used in part to repay the
outstanding amount under the Gallatin Loan Facility.
Other
Indebtedness
The
Company entered into a capital lease for equipment in conjunction with the
purchase of substantially all of the assets of Moravian Run Reclamation Co.,
Inc. on April 1, 2004. The lease has a term of sixty months with monthly
payments ranging from $20 to $60 with a final balloon payment of $180 in March
2009. The effective interest rate on the capital lease is approximately 12.15%.
The capitalized cost of the leased property was $1,847 at December 31,
2008. Accumulated amortization was $1,752 and $1,397 at December 31, 2008
and 2007, respectively. Amortization expense on capital leases is included with
depreciation expense. As of December 31, 2008, the future minimum
lease payments under this capital lease obligation, which expires in 2009, are
$232.
In the
Company's acquisition of Progress in 2006, it assumed a capital lease obligation
through Caterpillar Financial Services. The remaining lease term was 29 months
with monthly payments of $23 starting in May of 2006 and expiring in June of
2008. The effective interest rate on the capital lease was approximately 4.26%.
The capitalized cost of the leased property was $513 at December 31, 2008.
Accumulated amortization was $274 and $171 at December 31, 2008 and 2007,
respectively. Amortization expense on capital leases is included with
depreciation expense.
Future maturities of long-term
debt and capital lease obligations are as follows as of December 31,
2008:
|
Year
ending December 31:
|
||||
|
2009
|
$
|
232
|
||
|
2010
|
-
|
|||
|
2011
|
-
|
|||
|
2012
|
233,125
|
|||
|
2013
|
-
|
|||
|
Thereafter
|
287,500
|
|||
|
Total
long-term debt
|
$
|
520,857
|
||
|
(12)
|
Asset
Retirement Obligation
|
At
December 31, 2008 and 2007, the Company has recorded asset retirement
obligation accruals for mine reclamation and closure costs (including perpetual
water treatment) totaling $98,940 and $91,199, respectively. The portion of the
costs expected to be incurred within a year in the amount of $8,375 and $8,179,
at December 31, 2008 and 2007, respectively, is included in accrued
expenses and other current liabilities. There were no assets that were legally
restricted for purposes of settling asset retirement obligations at December 31,
2008 or 2007. These regulatory obligations are secured by surety
bonds in the amount of $148,952 at December 31, 2008 and $142,471 at
December 31, 2007. Changes in the reclamation obligation were as
follows:
|
Total
asset retirement obligation at December 31, 2006
|
|
$
|
77,292
|
|
|
Accretion
|
6,845
|
|||
|
Acquisitions
|
11,636
|
|||
|
Sites
added
|
3,305
|
|||
|
Revisions
in estimated cash flows
|
(1,754)
|
|||
|
Expenditures
|
(6,125)
|
|||
|
Total
asset retirement obligation at December 31, 2007
|
|
91,199
|
||
|
Accretion
|
7,499
|
|||
|
Decrease
due to sale of asset
|
(2,108)
|
|||
|
Sites
added
|
4,266
|
|||
|
Revisions
in estimated cash flows
|
2,909
|
|||
|
Expenditures
|
(4,825)
|
|||
|
Total
asset retirement obligation at December 31, 2008
|
|
$
|
98,940
|
|
|
(13)
|
Other
Liabilities
|
Other
liabilities consisted of the following:
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Fair
value of interest rate swap
|
$ | 27,929 | $ | 15,590 | ||||
|
Fair
value of certain derivative contracts
|
16,812 | - | ||||||
|
Davis-Bacon
litigation (see Note 23)
|
7,925 | 6,125 | ||||||
|
Unamortized
portion of unfavorable coal sales contract
|
- | 2,403 | ||||||
|
Employee
benefits
|
1,014 | 1,940 | ||||||
|
Advance
royalties payable
|
687 | 879 | ||||||
|
Contractor
escrow
|
1,332 | 1,324 | ||||||
|
Long-term
deferred revenue
|
468 | 405 | ||||||
|
Deferred
purchase price obligation
|
429 | 538 | ||||||
|
Payable
to former sponsor
|
- | 274 | ||||||
|
Other
long-term liabilities
|
- | 1,452 | ||||||
|
Total
other liabilities
|
$ | 56,596 | $ | 30,930 | ||||
|
(14)
|
Deferred
Gains on Sales of Property
Interests
|
In
February 2003, the Company sold an overriding royalty interest in certain mining
properties for $11,850. The gain on this transaction in the amount of $850 was
deferred and is being amortized over the ten-year term of the mineral lease.
This property interest was acquired from El Paso CGP Company in the
acquisition of the Coastal Coal properties.
In April
2003, the Company sold mineral properties for $53,625 in a sale/leaseback
transaction. These properties were originally acquired from Pittston Coal
Company. The gain on this transaction in the amount of $7,057 was deferred and
is being amortized over the ten-year term of the lease.
|
(15)
|
Fair
Value of Financial Instruments and Fair Value
Measurements
|
The
estimated fair values of financial instruments under
SFAS No. 107,
Disclosures About Fair Value of Financial Instruments, are determined
based on relevant market information. These estimates involve uncertainty and
cannot be determined with precision. The following methods and assumptions are
used to estimate the fair value of each class of financial
instrument.
Cash and Cash Equivalents, Trade
Accounts Receivables, Note Payable, Trade Accounts Payable, and Other
Current Liabilities: The carrying amounts approximate fair
value due to the short maturity of these instruments.
Notes Receivable: The
fair value approximates the carrying value as the rates associated with the
receivables are comparable to current market rates.
Long-term Debt: The fair
value of the 2.375% convertible senior notes and 10% senior notes was
estimated using observable market prices as these securities were
traded. For the year ended December 31, 2008, the fair value of the
Term Loan due 2012 is estimated using observable market prices for debt of
similar characteristics and maturities. For the year ended December
31, 2007, the carrying value of the Term Loan due 2012 and the Gallatin loan
facility approximates fair value. The carrying value of the Company’s
capital lease obligation approximates fair value due to the short maturity of
these instruments. The fair value of other long-term debt is
based on the current market rate of interest offered to the Company for debt of
similar maturities.
The
estimated fair values of long-term debt were as follows:
|
December
31,
|
||||||||||||||||
|
2008
|
2008
|
2007
|
2007
|
|||||||||||||
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|||||||||||||
|
2.375%
convertible senior notes due 2015
|
$ | 287,500 | $ | 186,013 | $ | - | $ | - | ||||||||
|
10%
senior notes repurchased in 2008
|
- | - | 175,000 | 185,063 | ||||||||||||
|
Term
loan due 2012
|
233,125 | 194,659 | 233,125 | 233,125 | ||||||||||||
|
Capital
lease obligation
|
232 | 232 | 705 | 705 | ||||||||||||
|
Gallatin
loan facility
|
- | - | 18,500 | 18,500 | ||||||||||||
|
Other
|
- | - | 700 | 700 | ||||||||||||
|
Total
long-term debt
|
$ | 520,857 | $ | 380,904 | $ | 428,030 | $ | 438,093 | ||||||||
The
Company adopted SFAS No. 157, Fair Value Measurements
(“SFAS 157”), on January 1, 2008.
This statement defines fair value, establishes a framework for measuring fair
value and expands disclosures about fair value measurements. Additionally, on
January 1, 2008, the Company elected the partial adoption of SFAS 157 under
the provisions of FSP Financial Accounting Standard (“FAS”)
157-2 (“FSP FAS 157-2”), which amends SFAS 157 to allow an entity to
delay the application of this statement until January 1,
2009 for certain non-recurring non-financial assets and
liabilities. Non-recurring nonfinancial assets and nonfinancial liabilities
for which the Company has not applied the provisions of SFAS 157 include those
measured at fair value in goodwill impairment testing, asset retirement
obligations initially measured at fair value, and those non-recurring
nonfinancial assets and nonfinancial liabilities initially measured at fair
value in a business combination. The adoption of SFAS 157 did not have a
material impact on the Company’s consolidated financial statements.
The
Company adopted SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities-Including an Amendment of FASB Statement
No. 115 (“SFAS 159”), on January 1, 2008. This standard permits
entities to choose to measure many financial instruments and certain other items
at fair value. The adoption of SFAS 159 did not impact the Company’s
consolidated financial statements, as the Company elected not to measure any
additional financial assets or liabilities at fair value other than those which
were recorded at fair value prior to adoption.
SFAS 157
clarifies that fair value is an exit price, representing the amount that would
be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants. As such, fair value is a
market-based measurement that should be determined based on assumptions that
market participants would use in pricing an asset and liability. As a
basis for considering such assumptions, SFAS 157 establishes a fair value
hierarchy that prioritizes the inputs used to measure fair value. The
hierarchy gives the highest priority to unadjusted quoted prices in active
markets for identical assets or liabilities (level 1 measurement) and the lowest
priority to unobservable inputs (level 3 measurements). The three
levels of the fair value hierarchy defined by SFAS 157 are as
follows:
|
|
Level
1 - Quoted prices in active markets for identical assets or
liabilities;
|
|
|
Level
2 - Quoted prices for similar instruments in active markets; quoted prices
for identical or similar instruments in markets that are not active;
and
|
|
|
Level
3 - Unobservable inputs in which there is little or no market data which
require the reporting entity to develop its own
assumptions.
|
The
following table sets forth by level within the fair value hierarchy the
company's financial assets that were accounted for at fair value on a recurring
basis as of December 31, 2008. As required by SFAS 157, financial
assets and liabilities are classified in their entirety based on the lowest
level of input that is significant to the fair value measurement. The
Company's assessment of the significance of a particular input to the fair value
measurement requires judgment, and may affect the valuation of fair value assets
and liabilities and their placement within the fair value hierarchy
levels.
|
As
of December 31, 2008
|
||||||||||||||||||||
|
Fair
Value Measurements Using:
|
||||||||||||||||||||
|
Quoted
|
Significant
|
|||||||||||||||||||
|
Prices
in
|
Other
|
Significant
|
||||||||||||||||||
|
Active
|
Observable
|
Unobservable
|
||||||||||||||||||
|
Carrying
|
Total
Fair
|
Markets
|
Inputs
|
Inputs
|
||||||||||||||||
|
Amount
|
Value
|
(Level
1)
|
(Level
2)
|
(Level
3)
|
||||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
Financial
assets (liabilities):
|
||||||||||||||||||||
|
Forward
coal sales
|
$ | (3,042 | ) | $ | (3,042 | ) | $ | - | $ | (3,042 | ) | $ | - | |||||||
|
Forward
coal purchases
|
2,854 | 2,854 | - | 2,854 | - | |||||||||||||||
|
Diesel
fuel derivatives
|
(36,707 | ) | (36,707 | ) | - | (36,707 | ) | - | ||||||||||||
|
Interest
rate swaps
|
(27,929 | ) | (27,929 | ) | - | (27,929 | ) | - | ||||||||||||
The
following methods and assumptions were used to estimate the fair values of the
assets and liabilities in the tables above.
Level 2
Fair Value Measurements
Forward Coal Purchases and
Sales — The fair value of the forward coal purchases and sales
contracts were estimated using discounted cash flow calculations based upon
forward commodity price curves. The curves were obtained from
independent pricing services reflecting broker market quotes.
Diesel Fuel
Derivatives — Since the Company’s diesel fuel derivative instruments
are not traded on a market exchange, the fair values are determined using
valuation models which include assumptions about commodity prices based on those
observed in the underlying markets.
Interest Rate Swaps —
The fair value of the interest rate swaps were estimated using discounted cash
flow calculations based upon forward interest-rate yield curves. The
curves were obtained from independent pricing services reflecting broker market
quotes.
|
(16)
|
Employee
Benefit Plans
|
|
(a)
|
Postretirement
Benefits Other Than Pensions
|
Three of
the Company's subsidiaries assumed collective bargaining agreements as part of
two acquisitions that require these subsidiaries to provide postretirement
medical benefits to certain employees who retire after the acquisition closing
dates. In each case, however, the sellers have retained the obligation to
provide postretirement medical benefits to employees who retired prior to the
acquisition closing dates (December 13, 2002 and March 11, 2003,
respectively) and to employees who were not retained by these subsidiaries. In
addition, the sellers retained the obligation to provide postretirement medical
benefits to a significant number of the employees who have worked for the
Company after the acquisition closing, namely, those employees who met the
eligibility criteria by December 31, 2003, even if the employees will not
retire until sometime in the future. These plans are unfunded and the
measurement date is December 31 of each year.
Effective
July 1, 2004, the Company adopted a plan offering postretirement medical
benefits to active union-free employees that will provide a credit of
$20 per month per year of service for pre-65 year old and $9 per
month per year of service for post-65 year old retirees toward the purchase
of medical benefits (as defined) from the Company. The adoption of this plan
resulted in prior service cost of $27,122. Effective April 1, 2005 and
October 3, 2005, the plan was amended to replace two union retiree medical
plans with a defined dollar benefit similar to the union-free plan, which
resulted in a prior service credit of approximately $6,167. On October 26,
2005 upon the acquisition of the Nicewonder Coal Group, the Company granted the
acquired employees up to ten years of credited service under the plan resulting
in an additional $2,020 of prior service cost. On May 1, 2006, upon the
acquisition of Progress Energy, the Company granted the acquired employees up to
ten years prior service credit under the plan resulting in an additional $1,040
of prior service cost. On June 29, 2007, upon the acquisition of
Mingo Logan, the Company granted the acquired employees up to ten years prior
service credit under the plan resulting in an additional $489 of prior service
cost. In addition, in 2007, the Company amended one of our existing
plans that resulted in an additional $508 of prior service costs.
The Company adopted SFAS 158
effective December 31, 2006. The effect of adoption was an increase in the
liability for postretirement medical benefits of $17,534, an increase in
deferred income tax asset of $4,337 and an increase in accumulated other
comprehensive loss of $13,197. Other comprehensive income (loss) will be
adjusted in subsequent years as these amounts are later recognized into income
as components of net period benefit costs.
The
components of the change in accumulated benefit obligations of the plans for
postretirement benefits other than pensions were as follows:
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Change
in benefit obligations:
|
||||||||
|
Accumulated
benefit obligation-beginning period:
|
$ | 54,784 | $ | 50,847 | ||||
|
Service
cost
|
2,777 | 3,026 | ||||||
|
Interest
cost
|
3,421 | 3,067 | ||||||
|
Actuarial
(gain) or loss
|
551 | (3,024 | ) | |||||
|
Benefits
paid
|
(241 | ) | (129 | ) | ||||
|
Plan
amendments
|
- | 997 | ||||||
|
Accumulated
benefit obligation-end of period
|
$ | 61,292 | $ | 54,784 | ||||
|
Change
in plan assets:
|
||||||||
|
Employer
contributions
|
$ | (241 | ) | $ | (129 | ) | ||
|
Benefits
paid
|
241 | 129 | ||||||
|
Fair
value of plan assets at December 31
|
- | - | ||||||
|
Funded
status
|
$ | (61,292 | ) | $ | (54,784 | ) | ||
|
Amounts
recognized in the balance sheet:
|
||||||||
|
Current
liabilities
|
$ | (1,081 | ) | $ | (973 | ) | ||
|
Long-term
liabilities
|
(60,211 | ) | (53,811 | ) | ||||
| $ | (61,292 | ) | $ | (54,784 | ) | |||
|
Amounts
recognized in accumulated other comprehensive loss:
|
||||||||
|
Prior
service cost
|
$ | 14,238 | $ | 16,605 | ||||
|
Net
actuarial gain
|
(2,898 | ) | (3,449 | ) | ||||
| $ | 11,340 | $ | 13,156 | |||||
The
following table details the components of the net periodic benefit cost for
postretirement benefits other than pensions:
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Service
cost
|
$ | 2,777 | $ | 3,026 | $ | 3,734 | ||||||
|
Interest
cost
|
3,421 | 3,067 | 2,782 | |||||||||
|
Amortization
of net loss
|
- | - | 186 | |||||||||
|
Amortization
of prior service cost
|
2,367 | 2,351 | 2,219 | |||||||||
|
Net
periodic benefit cost
|
$ | 8,565 | $ | 8,444 | $ | 8,921 | ||||||
The
following details the amounts expected to be recognized as components of net
periodic benefit cost in 2009:
|
Prior
service cost
|
$
|
2,100
|
||
|
$
|
2,100
|
|||
The
discount rates used in determining the benefit obligations as of
December 31, 2008 and 2007 were 6.17%, 6.44%, respectively. The discount
rates used in determining net periodic postretirement benefit cost were 6.44%,
5.92% and 5.50% for the years ended December 31, 2008, 2007 and 2006,
respectively. The discount rate assumption is determined from a published
yield-curve table matched to the timing of the Company’s projected cash out
flows.
The
weighted average annual rate of increase in the per capita cost of covered
benefits (i.e., health care trend rate) for medical benefits assumed is 11% for
2009, decreasing to 5% in 2015 and thereafter.
Assumed health care trend rates
have a significant effect on the amounts reported for the health care plans. A
one-percentage-point change in assumed health care trend rates would have the
following effects as of and for the year ended December 31,
2008:
|
One
percentage point increase
|
One
percentage point decrease
|
|||||||
|
Effect
on total service and interest cost components
|
$ | 65 | $ | (54 | ) | |||
|
Effect
on accumulated postretirement benefit obligation
|
822 | (680 | ) | |||||
Employer
contributions for benefits paid for the years ended December 31, 2008 and
2007 were $241 and $129, respectively. Employee contributions are not expected
to be made and the plan is unfunded.
Estimated
future benefit payments for the fiscal years ending after December 31, 2008
are as follows:
|
Year
ending December 31:
|
||||
|
2009
|
$
|
1,081
|
||
|
2010
|
1,618
|
|||
|
2011
|
2,223
|
|||
|
2012
|
2,890
|
|||
|
2013
|
3,460
|
|||
|
2014-2018
|
25,468
|
|||
Effective December 31, 2006, the
Company adopted SFAS 158 for its black lung benefit obligation and the effect of
adoption was an increase in the liability (which is reflected in workers'
compensation benefits in the consolidated balance sheet) of $512, an increase in
deferred tax assets of $127, and an increase in accumulated other comprehensive
loss of $385. The adoption of this pronouncement did not affect the Company's
comprehensive income for the year ended December 31, 2006. At December 31, 2008
and 2007, the Company's unfunded accumulated black lung benefit obligation was
$1,540 and $1,503, respectively. The net periodic benefit cost was $223, $212,
and $152 for the years ended December 31, 2008, 2007, and 2006, respectively.
The discount rate used in determining the benefit obligation at December 31,
2008 and 2007 was 5.81% and 5.60%, respectively. The discount rate used in
determining net periodic benefit cost was 5.56%, 5.60%, and 5.30%, for the years
ended December 31, 2008, 2007, and 2006, respectively.
Estimated
future cash payments for the fiscal years ending after December 31, 2008
are as follows:
|
Year
ending December 31:
|
||||
|
2009
|
$
|
143
|
||
|
2010
|
154
|
|||
|
2011
|
167
|
|||
|
2012
|
168
|
|||
|
2013
|
156
|
|||
|
2014-2018
|
700
|
|||
|
(b)
|
Savings
Plan
|
The
Company sponsors a 401(k) Savings-Investment Plan to assist its eligible
employees in providing for retirement. The Company contributes 3% of
compensation, as defined under the plan, for every employee who is eligible to
participate in the plan. Participants also receive a 50% matching contribution
from the Company on their contributions of up to 4% of their total compensation,
as defined under the plan. The effective date of the plan was February 1,
2003. Total Company contributions for the years ended December 31, 2008,
2007 and 2006, were $11,698, $9,930, and $9,183, respectively.
|
(c)
|
Self-Insured
Medical Plan
|
The
Company is principally self-insured for health insurance coverage provided for
all of its employees. The Company utilizes commercial insurance to cover
specific claims in excess of $500. Estimated liabilities for health and medical
claims are recorded based on the Company's historical experience and includes a
component for incurred but not reported claims. During the years
ended December 31, 2008, 2007 and 2006, total claims expense of $38,422,
$31,668 and $25,125, respectively, was incurred, which represents claims
processed and an estimate for claims incurred but not reported.
|
(d)
|
Multi-Employer
Pension Plan
|
Three of
the Company's subsidiaries assumed collective bargaining agreements as part of
two acquisitions that require them to participate in the United Mine Workers of
America (UMWA) 1950 and 1974 pension plans. These plans are multi-employer
pension plans. The Company is required to make contributions to these
plans at rates defined by the contract. For the years ended December
31, 2008 and 2007 we incurred expense of $2,045 and $1,238, respectively. No
expense was incurred for the year ended December 31, 2006.
Some of
the Company's subsidiaries are required to make contributions to the 1993 UMWA
Benefit Plan of fifty cents per signatory hour worked. The contributions that
the Company made to this plan for the years ended December 31, 2008, 2007
and 2006 were $191, $84 and $28, respectively.
|
(e)
|
Share-Based
Compensation Awards
|
As of
December 31, 2008, the total number of shares of Alpha Natural Resources, Inc.
common stock available for issuance or delivery under the Company’s current
Long-Term Incentive Plan was 5,982,214 shares. For the years ended
December 31, 2008, 2007, and 2006, all shared-based compensation awards granted
by the Company consisted of non-vested restricted shares, non-vested performance
shares, and restricted stock units.
Share-based
compensation expense measured in accordance with SFAS 123(R) totaled $17,871,
$9,681, and $20,464 for the years ended December 31, 2008, 2007, and 2006,
respectively.
For the
years ended December 31, 2008, 2007, and 2006, approximately 51%, 61%, and 90%,
respectively, of stock-based compensation expense is reported as selling,
general and administrative expenses and approximately 49%, 39%, and 10%,
respectively, of the stock-based compensation expense was recorded as a
component of cost of sales. For the years ended December 31, 2008, 2007, and
2006, approximately $31, $108, and $77 of stock-based compensation costs were
capitalized as a component of inventories, respectively. The total tax
effects recognized in income in relation to stock-based compensation were
benefits of $3,485, $2,275, and $5,259 in 2008, 2007, and 2006,
respectively.
Stock
Options
On
February 11, 2005, in connection with the Company’s Internal Restructuring, the
Alpha Coal Management (“ACM”) LLC 2004 Long-Term Incentive Plan (“2004 LTIP”)
was amended and restated, and the outstanding options granted under the plan
were automatically converted into options to purchase shares of Alpha common
stock and the Company assumed the obligations of ACM pursuant to this plan.
These options vest over a period of five years (with accelerated vesting upon a
change of control) and have a term of ten years. After the Internal
Restructuring, there were outstanding options under the plan to purchase an
aggregate of 596,985 shares of common stock at an exercise price of $12.73 per
share. No additional options or awards were or will be granted under this
plan.
As part
of the Internal Restructuring, the officers and employees who were members of
ACM contributed all of their interest in ANR Holdings to Alpha in exchange for
2,772,157 shares of Alpha common stock. Pursuant to the stockholder agreement,
an aggregate of 1,344,930 shares of common stock held by the Company's
executives were unvested on the grant date. These shares were vested by December
31, 2006.
In
connection with the Internal Restructuring, Alpha Natural Resources, Inc.
adopted, and its stockholders approved, the Alpha Natural Resources, Inc. 2005
Long-Term Incentive Plan (“2005 LTIP”). The principal purpose of the 2005 LTIP
is to attract, motivate, reward and retain selected employees, consultants and
directors through the granting of stock-based compensation awards. The 2005 LTIP
provides for a variety of awards, including non-qualified stock options,
incentive stock options (within the meaning of Section 422 of the Internal
Revenue Code of 1986, as amended), stock appreciation rights, non-vested shares,
dividend equivalents, performance-based awards and other stock-based awards. On
February 11, 2005 the Company granted certain of its executive officers,
directors and key employee's options to purchase an aggregate of 692,905 shares
of Alpha Natural Resources, Inc. common stock at the initial public offering
price of $19.00 per share. During the remainder of 2005, an additional 70,000
stock options were granted. All options granted during 2005 pursuant to the 2005
LTIP vest over a period of five years and have a term of ten years.
No stock
options were granted during the years ended December 31, 2008, 2007 and 2006,
respectively.
Stock
option activity for the year ended December 31, 2008 is summarized in the
following table:
|
Number
of Shares
|
Weighted-Average
Exercise Price
|
Weighted-Average
Remaining
Contractual Term
|
||||
|
Outstanding
at December 31, 2007
|
744,692
|
$
|
17.51
|
|||
|
Exercised
|
(212,851
|
) |
16.85
|
|||
|
Forfeited/cancelled
|
(11,857
|
) |
14.84
|
|||
|
Outstanding
at December 31, 2008
|
519,984
|
17.87
|
6.09
|
|||
|
Exerciseable
at December 31, 2008
|
199,482
|
17.87
|
6.09
|
|||
At
December 31, 2008, the options outstanding and the exercisable options had an
aggregate intrinsic value of $508 and $234, respectively. Cash received from the
exercise of stock options during the years ended December 31, 2008, 2007, and
2006 was $3,586, $3,932, and $954, respectively. As of December 31, 2008,
$1,631 of unrecognized compensation cost related to stock options is expected to
be recognized as expense over a weighted-average period of
1.03 years.
The total
intrinsic value of options exercised during the year ended December 31, 2008,
2007, and 2006 was $6,692, $3,081, and $479, respectively. The
Company currently uses authorized and unissued shares to satisfy share award
exercises.
Restricted
Stock Awards
The
Company grants certain of its executive officers, directors and key employee's
restricted shares of Alpha Natural Resources, Inc. common stock pursuant to the
Company’s 2005 LTIP. For executive officers and key employees, the
restricted shares vest ratably over five-year and three-year periods or cliff
vest after three years (with accelerated vesting upon a change of control),
depending on the recipients’ position with the company. For the
Company’s directors, restricted share grants vest at the time of grant, but are
restricted until for six months upon termination of such director’s service on
our Board (with accelerated vesting upon a change of control). The
fair value of restricted share awards is estimated based on the closing stock
price at the date of the grant, and, for purposes of expense recognition, the
total number of awards expected to vest is adjusted for estimated forfeitures,
which is being amortized over the requisite service periods.
During
the years ended December 31, 2008, 2007, and 2006, the Company granted
restricted shares to its executive officers, directors and key employee's in the
amount of 399,561, 611,863, and 524,277, respectively, of which 952,789 remained
outstanding at December 31, 2008.
Non-vested
restricted share award activity for the year ended December 31, 2008 is
summarized in the following table:
|
Number
of Shares
|
Weighted
Average Grant Date Fair Value
|
||||
|
Non-vested
shares outstanding at December 31, 2007
|
880,232
|
$
|
15.93
|
||
|
Granted
|
399,561
|
33.60
|
|||
|
Vested
|
(311,348
|
) |
26.14
|
||
|
Forfeited
|
(15,656
|
) |
19.47
|
||
|
Non-vested
shares outstanding at December 31, 2008
|
952,789
|
19.33
|
|||
As of
December 31, 2008, there was $5,357 of unamortized compensation cost related to
non-vested shares which is expected to be recognized as expense over a
weighted-average period of 1.60 years.
Restricted
Share Units
The
Company’s directors have the option to defer their respective cash fees earned
for service on the Company’s Board into restricted share units, as established
in the Director Deferred Compensation Agreement (as amended and restated)
(“Deferred Compensation Agreement”) of the 2005 LTIP. Under the
Deferred Compensation Agreement, the number of share units credited to each
share unit account is based upon the fair market value of our common stock on
the applicable payment date of the fees deferred by such director. Upon
termination of such director’s service on the Company’s Board, the Company will
distribute the director’s share unit account to the director in the form of
shares of the Company’s common stock, which shares will be issued under the 2005
LTIP and in accordance with the terms and conditions of such plan and the
Deferred Compensation Agreement.
For the
years ended December 31, 2008, 2007, and 2006 the Company issued restricted
share units of 5,925, 6,296, and 4,835, respectively, to directors who elected
to defer their cash compensation earned for service on the Company’s Board and
convert it into restricted share units. The value of the cash
compensation converted to restricted share units was reclassified from a
liability to equity and amounts to $246, $119, and $82, for the years ended
December 31, 2008, 2007, and 2006, respectively.
Performance
Share Awards
Non-vested
performance share award activity for the year ended December 31, 2008 is
summarized in the following table:
|
Number
of Shares
|
Weighted
Average Grant Date Fair Value
|
||||
|
Non-vested
shares outstanding at December 31, 2007
|
588,541
|
$
|
15.87
|
||
|
Granted
|
147,192
|
25.79
|
|||
|
Unearned
|
(200,185)
|
21.15
|
|||
|
Forfeited
or expired
|
(8,365)
|
18.41
|
|||
|
Non-vested
shares outstanding at December 31, 2008
|
527,183
|
16.59
|
|||
|
Shares
granted are based on the maximum shares that can be awarded based on the
achievement of targeted performance. Shares awarded related to
strategic goals do not meet the SFAS 123(R) citeria for grant date and are
excluded from this table.
|
|||||
During 2008,
the Company granted 165,045 performance share awards, of which 163,515 remain
outstanding as of December 31, 2008. Recipients of these awards can receive
shares of the Company's common stock at the end of a performance period which
ends on December 31, 2010, based on the Company's actual performance against
pre-established operating income goals, strategic goals, and total shareholder
return goals. In order to receive the shares, the recipient must also be
employed by the Company on the vesting date. The performance share awards
represent the number of shares of common stock to be awarded based on the
achievement of targeted performance and may range from 0 percent to 150 percent
of the targeted amount. The grant date fair value of the awards related to
operating income targets is based on the closing price of the Company's common
stock on the New York Stock Exchange on the grant date of the award and is being
amortized over the performance period. The awards related to strategic goals do
not meet the criteria for grant date pursuant to SFAS 123(R). The fair value of
the awards related to total shareholder return targets is based upon a Monte
Carlo simulation and is being amortized over the performance period. The Company
reassesses at each reporting date whether achievement of each of the performance
conditions is probable, as well as estimated forfeitures, and adjusts
compensation expense recognized as appropriate. At December 31, 2008, the
Company has assessed the operating income and total shareholder return targets
as probable of achievement. As of December 31, 2008, there was $1,701 of
unamortized compensation cost related to the 2008 performance share awards which
is expected to be recognized over the period ending December 31,
2010.
During 2007, the Company granted
377,247 performance share awards, of which 330,291 remain outstanding as of
December 31, 2008. Recipients of these awards can receive shares of the
Company's common stock at the end of a performance period which ends on December
31, 2009, based on the Company's actual performance against pre-established
operating income goals, strategic goals, and total shareholder return goals. In
order to receive the shares, the recipient must also be employed by the Company
on the vesting date. The performance share awards represent the number of shares
of common stock to be awarded based on the achievement of targeted performance
and may range from 0 percent to 150 percent of the targeted amount. The grant
date fair value of the awards related to operating income targets is based on
the closing price of the Company's common stock on the New York Stock Exchange
on the grant date of the award and is being amortized over the performance
period. The awards related to strategic goals do not meet the criteria for grant
date pursuant to SFAS 123(R). The fair value of the awards related to total
shareholder return targets is based upon a Monte Carlo simulation and is being
amortized over the performance period. The Company reassesses at each reporting
date whether achievement of each of the performance conditions is probable, as
well as estimated forfeitures, and adjusts the accruals of compensation expense
as appropriate. At December 31, 2008, the Company has assessed the operating
income and total shareholder return targets as probable of achievement. As of
December 31, 2008, there was $973 of unamortized compensation cost related to
the 2007 performance share awards which is expected to be recognized over the
period ending December 31, 2009.
In
2006, the Company granted 148,268 performance share awards, of which
118,305 remained outstanding as of December 31, 2008. Recipients of
these awards can receive shares of Alpha common stock at the end of a three-year
performance period which ended on December 31, 2008, based on the Company's
actual performance against pre-established operating income and return on
invested capital targets. In order to receive the shares, the recipient must
also be employed by the Company on the vesting date. The performance share
awards represent the number of common shares to be awarded based on the
achievement of targeted performance, however the actual number of shares to be
awarded based on performance may range from 0 percent to 200 percent of the
targeted amount. The grant date fair value of the performance share award was
based on the average of the high and low market price of the Company common
stock on the date of award and was amortized over the performance period. At
December 31, 2008, the Company’s evaluated its performance against the
pre-established operating income and return on invested capital targets and
determined that there was an achievement of 30% of the targeted award, which
amounts to 35,492 shares with a total compensation cost
$750. Accordingly, the Company adjusted the previously recorded
compensation expense for these shares as of December 31,
2008.
|
(17)
|
Workers'
Compensation Benefits
|
The
Company's operations generally are fully insured for workers' compensation and
black lung claims. Insurance premium expense for the years ended
December 31, 2008, 2007 and 2006 was $18,920, $20,814 and $18,698,
respectively.
A portion
of the West Virginia operations of the Company are self-insured for workers'
compensation and state black lung claims. The liability for self-insured
workers' compensation claims is an estimate of the ultimate losses to be
incurred on such claims based on the Company's experience and published industry
data. Adjustments to the probable ultimate liability are made annually based on
an actuarial valuation and are included in operations as they are determined.
The liability for self-insured black lung benefits is an estimate of such
benefit as determined by an independent actuary at the present value of the
actuarially computed liability over the employee's applicable term of
service.
The
liability for self-insured workers’ compensation claims and black lung benefits
at December 31, 2008 and 2007 was $11,322 and $10,834, respectively,
including a current portion of $1,718 and $1,779, respectively. Workers'
compensation and black lung expense for the years ended December 31, 2008,
2007 and 2006 was $5,550, $5,290 and $6,507, respectively, including fees paid
to the State of West Virginia to be self-insured.
|
(18)
|
Related
Party Transactions
|
For the
years ended December 31, 2008 and 2007, there were no related party
transactions.
The
Company leases its Latrobe, Pennsylvania operating facility from a company
controlled by the AMCI parties and one of the Company's former Executive Vice
Presidents. As of December 31, 2006, the former Company’s Executive Vice
President was no longer a related party and as of January 3, 2007, the AMCI
parties were no longer related. Total rent expense was $186 for the
year ended December 31, 2006.
One of
the Company's former Executive Vice Presidents is a 50% owner of Robindale
Energy Services, Inc. (and its subsidiary) (“Robindale”). Robindale is engaged
in the business of waste coal sales and related businesses in Pennsylvania. From
time to time, Robindale has sold and purchased coal and related products to and
from the Company's AMFIRE regional business unit in Pennsylvania. As of December
31, 2006, the former Executive Vice President was no longer
related. For the year ended December 31, 2006 the Company's
subsidiaries Alpha Coal Sales and AMFIRE Mining Company, LLC made purchases of
$359 from Robindale for trucking services and waste coal. For the year ended
December 31, 2006, the Company had sales of $206 to Robindale. For the year
2006, the Company agreed that its former Executive Vice President's continued
relationship with Robindale was not a breach of his employment agreement with
Alpha, and he did not participate in any decisions to enter into any
transactions that were proposed between Robindale and Alpha.
Since
April 2004, the Company has entered into various coal sales arrangements with
AMCI International AG, formerly, AMCI Metall & Kohle AG. Two of the ANR
Holdings and Alpha Natural Resources, Inc. former board members hold ownership
in AMCI International AG. As of January 3, 2007, none of the AMCI members were
on the Board of the Company. For the year ended December 31,
2006, total sales of $13,308 have been made pursuant to these arrangements. The
Company also had total sales of $51,693 for the year ended December 31,
2006 to AMCI Australia Pty Ltd., an entity owned by these former board members.
American Metals and Coal International, Inc., an entity owned by these board
members, facilitated coal transactions for an international buyer of $13,865 for
the year ended December 31, 2006. The Company made coal purchases totaling
$1,030 during the year ended December 31, 2006 from XCoal Energy and
Resources, an entity in which each of the former aforementioned board members
each own more than a 10% equity interest.
|
(19)
|
Commitments
|
Operating
Leases
The
Company leases coal mining and other equipment under long-term operating leases
with varying terms. In addition, the Company leases mineral interests and
surface rights from land owners under various terms and royalty
rates.
As of
December 31, 2008, aggregate future minimum lease payments under operating
leases and minimum royalties under coal leases were as follows:
|
Facility
|
Coal
Royalties
|
Total
|
||||||||||
|
Year
Ending December 31:
|
||||||||||||
|
2009
|
$ | 1,693 | $ | 10,500 | $ | 12,193 | ||||||
|
2010
|
1,434 | 10,762 | 12,196 | |||||||||
|
2011
|
1,257 | 10,584 | 11,841 | |||||||||
|
2012
|
1,216 | 10,240 | 11,456 | |||||||||
|
2013
|
1,185 | 7,163 | 8,348 | |||||||||
|
Thereafter
|
6,037 | 30,071 | 36,108 | |||||||||
|
Total
|
$ | 12,822 | $ | 79,320 | $ | 92,142 | ||||||
The above
table includes amounts due under non-cancelable leases with initial or remaining
lease terms in excess of one year.
For years
ended December 31, 2008, 2007 and 2006, net rent expense amounted to $5,286,
$7,566 and $8,029, respectively, and coal royalty expense amounted to $88,607,
$71,659 and $75,128, respectively.
Other
Commitments
As of December 31, 2008, the
Company had commitments to purchase 2,576 tons and 195 tons of coal at
a cost of $216,489 and $14,190 during 2009 and 2010, respectively. In addition,
as of December 31, 2008, the Company had commitments to purchase approximately
$63,980 of new equipment expected to be acquired at various dates in
2009.
|
(20)
|
Mergers
and Acquisitions
|
|
2007
Acquisition
|
Mingo
Logan
On June
29, 2007, the Company completed the acquisition of certain coal mining assets in
southern West Virginia from Arch Coal, Inc. known as Mingo Logan for $43,893
including working capital and assumed liabilities. The Mingo Logan
purchase consisted of coal reserves, two mines and a load-out and processing
plant that is managed by the Callaway business unit.
The
following table summarizes the fair values of the assets acquired and
liabilities assumed at the date of acquisition:
|
Current
assets
|
$
|
9,555
|
||
|
Property,
plant, and equipment
|
41,892
|
|||
|
Intangible
assets
|
4,182
|
|||
|
Total
assets acquired
|
55,629
|
|||
|
Asset
retirement obligation
|
(11,636
|
) | ||
|
Other
liabilities
|
(100
|
) | ||
|
Total
liabilities assumed
|
(11,736
|
) | ||
|
Net
assets required
|
$
|
43,893
|
||
|
2006
Acquisitions
|
Gallatin
Materials LLC
On
December 28, 2006, the Company’s subsidiary, Palladian Lime, LLC (“Palladian”)
acquired a 94% ownership interest in Gallatin, a start-up lime manufacturing
business in Verona, Kentucky by assuming liabilities in the amount of $3,567
consisting of a note payable in the amount of $1,847 and accounts payable and
accrued expenses in the amount of $1,720. The liabilities assumed were allocated
to fair value of assets acquired consisting mainly of intangible
assets. In addition, Palladian agreed to and made (i) cash capital
contributions of $10,282 of which $3,300 was funded as of December 31, 2006,
(ii) a committed subordinated debt facility of up to $8,813 provided to Gallatin
by Palladian, of which $3,813 was funded as of December 31, 2007 and (iii) a
letter of credit procured for Gallatin’s benefit under the Company’s senior
credit facility in the amount of $2,600 to cover project cost overruns. On
September 26, 2008, the Company sold its interest in Gallatin to an unrelated
third party (Note 25).
Progress
Energy
On May 1,
2006, the Company completed the acquisition of certain coal mining operations in
eastern Kentucky from Progress Fuels Corp, a subsidiary of Progress Energy, for
$28,795, including an adjustment 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 the Company's Enterprise business unit and
were integrated into Enterprise.
The
following table summarizes the fair values of the assets acquired and
liabilities assumed at the date of acquisition:
|
Current
assets
|
$
|
5,261
|
||
|
Property,
plant, and equipment
|
46,983
|
|||
|
Deferred
tax asset
|
4,838
|
|||
|
Total
assets acquired
|
57,082
|
|||
|
Current
liabilties
|
(474
|
) | ||
|
Asset
retirement obligation
|
(7,204
|
) | ||
|
Other
noncurrent liabilites
|
(20,609
|
) | ||
|
Total
liabilites assumed
|
(28,287
|
) | ||
|
Net
assets required
|
$
|
28,795
|
||
Included
in liabilities assumed is $20,000 allocated to a coal sales agreement which was
below market, and is being amortized over the remaining life of the
contract.
On
September 30, 2008, the Company completed the sale of approximately 17.6 million
tons of underground coal reserves in eastern Kentucky to a private coal producer
for $13,041 in cash. The reserves were a portion of an estimated 73
million tons of reserves and other assets acquired from Progress Fuels
Corporation in May 2006. The Company recorded a gain of $12,936 on
the sale.
|
(21)
|
Concentrations
and Major Customers
|
The
Company markets its coal principally to electric utilities in the United States
and international and domestic steel producers. As of December 31, 2008 and
2007, trade accounts receivable from electric utilities totaled approximately
$59,398 and $56,478, respectively. Credit is extended based on an evaluation of
the customer's financial condition and collateral is generally not required.
Credit losses are provided for in the consolidated financial statements and
historically have been minimal. The Company is committed under long-term
contracts to supply coal that meets certain quality requirements at specified
prices. The prices for some multi-year contracts are adjusted based on economic
indices or the contract may include year-to-year specified price changes.
Quantities sold under some contracts may vary from year to year within certain
limits at the option of the customer. Sales to the Company's largest customer
accounted for 12% of total revenues for the year ended December 31, 2008
and less than 10% in the years ended December 31, 2007 and 2006.
|
(22)
|
Segment
Information
|
The
Company extracts, processes and markets steam and metallurgical coal from
surface and deep mines for sale to electric utilities, steel and coke producers,
and industrial customers. The Company operates only in the United States with
mines in the Central Appalachian and Northern Appalachian regions. The Company
has one reportable segment: Coal Operations, which as of December 31, 2008,
consisted of 34 underground mines and 27 surface mines located in Central
Appalachia and Northern Appalachia. Coal Operations also includes the Company's
coal sales function, which markets the Company's Appalachian coal to domestic
and international customers. The All Other category includes the Company's
equipment sales and repair operations, as well as other ancillary business
activities, including terminal services, coal and environmental analysis
services, and leasing of mineral rights. In addition, the All Other category
includes the operations of the Company's road construction businesses. The
Corporate and Eliminations category includes general corporate overhead and the
elimination of intercompany transactions. The revenue elimination amount
represents inter-segment revenues. The Company evaluates the performance of its
segment based on EBITDA from continuing operations which the Company defines as
income from continuing operations plus interest expense, income tax expense, and
depreciation, depletion and amortization, less interest income.
Segment
operating results and capital expenditures from continuing operations for the
year ended December 31, 2008, and segment assets as of December 31,
2008 were as follows:
|
Coal
Operations
|
All
Other
|
Corporate
and Eliminations
|
Combined
|
|||||||||||||
|
Revenues
|
$ | 2,508,809 | $ | 93,128 | $ | (47,813 | ) | $ | 2,554,124 | |||||||
|
Depreciation,
depletion, and amortization
|
164,127 | 6,150 | 1,686 | 171,963 | ||||||||||||
|
EBITDA
from continuing operations
|
410,518 | 30,194 | (35,219 | ) | 405,493 | |||||||||||
|
Capital
expenditures
|
131,662 | 1,395 | 1,938 | 134,995 | ||||||||||||
|
Total
assets
|
1,644,176 | 122,262 | (38,146 | ) | 1,728,292 | |||||||||||
Segment
operating results and capital expenditures from continuing operations for the
year ended December 31, 2007, and segment assets as of December 31,
2007 were as follows:
|
Coal
Operations
|
All
Other
|
Corporate
and Eliminations
|
Combined
|
|||||||||||||
|
Revenues
|
$ | 1,857,157 | $ | 65,945 | $ | (37,270 | ) | $ | 1,885,832 | |||||||
|
Depreciation,
depletion, and amortization
|
152,298 | 5,930 | 1,346 | 159,574 | ||||||||||||
|
EBITDA
from continuing operations
|
281,966 | 14,585 | (59,692 | ) | 236,859 | |||||||||||
|
Capital
expenditures
|
101,834 | 860 | 1,363 | 104,057 | ||||||||||||
|
Total
assets
|
1,335,431 | 132,733 | (257,250 | ) | 1,210,914 | |||||||||||
Segment
operating results and capital expenditures from continuing operations for the
year ended December 31, 2006, and segment assets as of December 31,
2006 were as follows:
|
Coal
Operations
|
All
Other
|
Corporate
and Eliminations
|
Combined
|
|||||||||||||
|
Revenues
|
$ | 1,872,527 | $ | 72,029 | $ | (40,013 | ) | $ | 1,904,543 | |||||||
|
Depreciation,
depletion, and amortization
|
131,871 | 7,134 | 1,846 | 140,851 | ||||||||||||
|
EBITDA
from continuing operations
|
335,997 | 11,406 | (67,968 | ) | 279,435 | |||||||||||
|
Capital
expenditures
|
124,554 | 6,208 | 1,181 | 131,943 | ||||||||||||
|
Total
assets
|
1,156,502 | 96,808 | (107,517 | ) | 1,145,793 | |||||||||||
Reconciliation
of EBITDA from continuing operations to income from continuing
operations:
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Total
segment EBITDA from continuing operations
|
$ | 405,493 | $ | 236,859 | $ | 279,435 | ||||||
|
Interest
expense
|
(40,398 | ) | (40,366 | ) | (41,774 | ) | ||||||
|
Interest
income
|
7,352 | 2,266 | 839 | |||||||||
|
Income
tax (expense) benefit
|
(39,139 | ) | (9,195 | ) | 30,519 | |||||||
|
Depreciation,
depletion, and amortization
|
(171,963 | ) | (159,574 | ) | (140,851 | ) | ||||||
|
Income
from continuing operations
|
$ | 161,345 | $ | 29,990 | $ | 128,168 | ||||||
The
Company markets produced, processed and purchased coal to customers in the
United States and in international markets, primarily Brazil, Canada, and
various European countries. Export coal revenues totaled $1,317,189 or
approximately 52% of total revenues for the year ended December 31, 2008;
$704,178 or approximately 37% of total revenues for the year ended
December 31, 2007; and, $668,830 or approximately 35% of total revenues for
the year ended December 31, 2006. Included in total export revenues were:
sales totaling $187,343 to customers located in Brazil during the year
ended December 31, 2008; sales totaling $108,464 to customers located in
Canada during the year ended December 31, 2007; and sales totaling $111,756
to customers located in Canada during the year ended December 31,
2006.
|
(23)
|
Contingencies
|
|
(a)
|
Guarantees
and Financial Instruments with Off-balance Sheet
Risk
|
In the
normal course of business, the Company is a party to certain guarantees and
financial instruments with off-balance sheet risk, such as bank letters of
credit and performance or surety bonds. No liabilities related to these
arrangements are reflected in the Company's consolidated balance sheets.
Management does not expect any material losses to result from these guarantees
or off-balance sheet financial instruments. However, due to the
current instability and volatility of the financial markets, the Company’s
guarantors may experience difficulties in providing new surety bonds to us,
maintaining existing surety bonds, or satisfying liquidity requirements under
existing surety bond contract. In that event, the Company would be
required to find alternative sources of funding to satisfy its payment
obligations, which may require greater use of its credit
facility. The amount of bank letters of credit outstanding as of
December 31, 2008 was $82,575. The amount of surety bonds outstanding at
December 31, 2008 was $158,598, including $148,952 related to the Company's
reclamation obligations (Note 12). The Company has provided guarantees for
equipment financing obtained by certain of its contract mining operators
totaling approximately $144 as of December 31, 2008. The estimated fair
value of these guarantees is not significant.
|
(b)
|
Litigation
|
The
Company is a party to a number of legal proceedings incident to its normal
business activities. While the Company cannot predict the outcome of these
proceedings, it does not believe that any liability arising from these matters
individually or in the aggregate should have a material impact upon the
Company’s consolidated cash flows, results of operations or financial
condition.
Nicewonder
Litigation
In
December 2004, prior to the 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 the Company’s 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 the WVDOH and the Federal Highway
Administration (which is now a party to the suit) could not, under the
circumstances of this case, enter into a contract that did not require the
contractor to pay the prevailing wages as required by the Davis-Bacon Act.
Although the Court has not yet decided what remedy it will impose, the Company
expects a ruling before the end of the first quarter of 2010. The Company
anticipates that the most likely remedy is a directive that the contract be
renegotiated for such payment. If that renegotiation occurs, the WVDOH has
committed to agree, and NCI has a contractual right to insist, that additional
costs resulting from the order will be reimbursed by the
WVDOH. Accordingly, the Company does not believe that it will incur
any monetary expense as a result of this ruling. As of December 31, 2008, the
Company has recorded a $7,925 long-term receivable for the recovery of these
costs from the WVDOH and a $7,925 long-term liability for the potential
obligations under the ruling.
Cliffs
Proposed Acquisition
On July
15, 2008, the Company entered into a definitive merger agreement pursuant to
which, and subject to the terms and conditions thereof, Cliffs would acquire all
of the Company’s outstanding shares. Under the terms of the agreement, for
each share of the Company’s common stock, stockholders would receive 0.95
Cliffs' common shares and $22.23 in cash. The proposed merger required
approval of each company’s stockholders, for which special meetings were
scheduled to take place on November 21, 2008. On November 3, 2008,
the Company commenced litigation against Cliffs by filing an action in the
Delaware Court of Chancery to obtain an order to require Cliffs to hold its
meeting as scheduled. Later in November, each company’s Board of
Directors, after considering various issues, including the then current
macroeconomic environment, uncertainty in the steel industry, shareholder
dynamics and risks and costs of potential litigation, determined that settlement
of the litigation and termination of the merger agreement was in the best
interests of its equity holders. As a result, on November 17, 2008,
the Company and Cliffs mutually terminated the merger agreement and settled the
litigation. The terms of the settlement agreement included a $70,000
payment from Cliffs to the Company, which net of transaction costs, resulted in
a gain of $56,315.
|
(c)
|
Other
Contingencies
|
In
connection with the Company's acquisition of Coastal Coal Company, the seller,
El Paso CGP Company, agreed to retain and indemnify the Company for all
workers' compensation and black lung claims incurred prior to the acquisition
date of January 31, 2003. The majority of this liability relates to claims
in the state of West Virginia. If El Paso CGP Company fails to honor its
agreement with the Company, then the Company would be liable for the payment of
those claims, which were estimated in October 31, 2008 by the West Virginia
Workers' Compensation Commission to be approximately $1,990 on an undiscounted
basis using claims data through June 29, 2007. El Paso has posted a bond
with the State of West Virginia for the required discounted amount of $1,343 for
claims incurred prior to the acquisition.
As part
of the sale of Gallatin on September 26, 2008, an escrow balance of $4,500 was
established and the Company has agreed to indemnify and guarantee the buyer
against breaches of representations and warranties in the sale agreement and
contingencies that may have existed at closing and materialize within one year
from the date of sale.
|
(24)
|
Mine
Closure
|
Kingwood
Mining Company, LLC.
On
December 3, 2008, the Company announced the permanent closure of the Whitetail
Kittanning Mine and Whitetail Preparation Facility (Kingwood), Kingwood Mining
Company, LLC. The Whitetail mine complex stopped producing coal
in early January 2009. The decision was a result of adverse
geologic conditions and regulatory requirements that rendered the coal seam
unmineable at this location. Kingwood's 329 employees have been given
60 days' notice of the closure under the Worker Adjustment and Retraining
Notification (WARN) Act and will receive their regular rate of pay in lieu of
work, if work is not available, through the earlier of February 3, 2009 or the
date they accept other employment. The Company recorded a
charge of $30,172, which includes asset impairment charges of $21,153, write off
of advance mining royalties of $3,799, which will not be recoverable, severance
and other employee benefit costs of $3,559 and increased reclamation obligations
of $1,921. The following table displays a roll-forward of the
liabilities for the severance charge from December 3, 2008 through December 31,
2008.
|
Accrual
at
|
Accrual
at
|
|||||
|
December
3,
|
December
31,
|
|||||
|
2008
|
Payments
|
2008
|
||||
|
|
|
|
||||
|
Severance
and related personnel expenses
|
$3,559 | $126 | $3,433 | |||
Beginning
with the first quarter of 2009 when the mining operations at Kingwood cease, the
Company will report the Kingwood’s results of operations as a discontinued
operation.
|
(25)
|
Discontinued
Operations
|
Gallatin
Materials, LLC
On
September 26, 2008, the Company completed the sale of its interest in Gallatin
for cash in the amount of $45,000. The proceeds were used in part to
repay the Gallatin loan facility outstanding with NedBank Limited in the amount
of $18,227. An escrow balance of $4,500 was established and the
Company has agreed to indemnify and guarantee the buyer against breaches of
representations and warranties in the sale agreement and contingencies that may
have existed at closing and materialize within one year from the date of the
sale. The Company recorded a gain on the sale of $13,622
in the third quarter of 2008. The results of operations for the
current and prior periods have been reported as discontinued
operations. Previously, the results of operations were reported in
the All Other segment of the Company’s business.
The
following table reflects the activities for the discontinued operations for the
period ended September 26, 2008 and for the year ended December 31,
2007:
|
For
the
|
For
the
|
|||||||
|
Period
Ended
|
Year
Ended
|
|||||||
|
September
26,
|
December
31,
|
|||||||
|
2008
|
2007
|
|||||||
|
Total
revenues
|
$ | 6,863 | $ | - | ||||
|
Total
costs and expenses
|
(13,206 | ) | (3,227 | ) | ||||
|
Gain
on sale of discontinued operations
|
13,622 | - | ||||||
|
Income
(loss) from operations
|
7,279 | (3,227 | ) | |||||
|
Interest
income (expense)
|
(1,930 | ) | 227 | |||||
|
Income
tax (expense) benefit from discontinued operations
|
(1,647 | ) | 565 | |||||
|
Minority
interest in loss from discontinued operations
|
490 | 179 | ||||||
|
Income
(loss) from discontinued operations
|
$ | 4,192 | $ | (2,256 | ) | |||
The assets and liabilities of the
discontinued operations as of December 31, 2007 are shown
below:
|
December
31,
|
||||
|
2007
|
||||
|
Current
assets
|
$ | 7,307 | ||
|
Property,
plant, and equipment, net
|
23,914 | |||
|
Other
assets
|
3,731 | |||
|
Assets
of discontinued operations
|
$ | 34,952 | ||
|
Current
liabilities
|
$ | 5,280 | ||
|
Noncurrent
liabilities
|
20,668 | |||
|
Other
liabilities
|
553 | |||
| $ | 26,501 | |||
In
connection with the sale of Gallatin on September 26, 2008, the minority
interest holders contributed their interests in Gallatin in exchange for cash,
thereby eliminating the minority interest.
|
(26)
|
Supplemental
Cash Flow Disclosures
|
Cash paid
for interest (net of amounts capitalized) for the years ended December 31,
2008, 2007 and 2006 was $33,110, $37,448 and $40,392, respectively. Income taxes
paid, net of refunds, by the Company for the years ended December 31, 2008,
2007 and 2006 were $35,018, $13,090 and $15,524,
respectively. Non-cash investing and financing activities are
excluded from the consolidated statements of cash flows. Significant
non-cash activity for the year ended December 31, 2008, 2007, and 2006 were
short-term financing of prepaid insurance premiums of $18,288, $18,883, and
$20,941, respectively.
|
(27)
|
Investments
|
Dominion
Terminal Associates
On April
30, 2008, the Company’s subsidiary, Alpha Terminal Company, LLC, increased its
equity ownership position in DTA from 32.5% to 40.6% by making an additional
investment of $2,824. DTA is a partnership with two other
companies that operates a leased coal port terminal in Newport News, Virginia
(“the Terminal”) that provides the Company a cost effective export
facility. The Company accounts for this investment under the equity
method. The Company has the right to use 40.6% of the throughput and
ground storage capacity of the terminal and pay for this right based upon an
allocation of costs as determined by DTA.
For the
year ended December 31, 2008, the Company’s outside revenues totaled
$6,625, partially offset by its share of allocated costs of
$5,700. For the years ended December 31, 2007 and 2006, the
Company made advances to DTA equal to its share of allocated costs of $4,100 and
$4,923, respectively, offset by outside revenues of $2,660 and $1,677,
respectively. Outside revenues consists of tolling, storage, docking,
and loading fees which the Company earned from third-party usage of the DTA
facilities.
Excelven Pty
Ltd
In
September 2004, the Company, together with AMCI, entered into a subscription
deed with Excelven Pty Ltd, pursuant to which each party agreed to acquire a
24.5% interest in Excelven for a purchase price of $5,000 in cash. Excelven,
through its subsidiaries, owns the rights to the Las Carmelitas mining venture
in Venezuela. The investment is accounted for under the equity method, and is
included in other assets. The Company made additional investments in
Excelven totaling $29, $263, and $261 for the years ended December 31,
2008, 2007, and 2006, respectively.
The
project, in the development stage, is challenged by political and economic
uncertainties in Venezuela, and the government of Venezuela had previously
expressed an interest in increasing ownership in Venezuelan natural
resources. In addition, the Venezuelan government has delayed the
issuance of a permit that would allow Excelven to mine the coal. In
the fourth quarter of 2008, the Company concluded that it had exhausted all
reasonable efforts to obtain a mining permit from the Venezuelan government and
that it is no longer reasonable to assume that such a permit will be
granted. As a result, the Company has determined that its investment
in Excelven was not recoverable and recorded an impairment charge of $4,534 to
write off the remaining investment.
At
December 31, 2008, 2007, and 2006, the Company’s investment in Excelven was $0,
$4,884, and $5,821, respectively.
|
(28)
|
Income
Taxes
|
The total
income tax expense (benefit) provided on pretax income was allocated as
follows:
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Continuing
operations
|
$ | 39,139 | $ | 9,195 | $ | (30,519 | ) | |||||
|
Discontinued
operations
|
1,647 | (565 | ) | - | ||||||||
| $ | 40,786 | $ | 8,630 | $ | (30,519 | ) | ||||||
Significant
components of income tax expense (benefit) from continuing operations were as
follows:
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Current
tax expense:
|
||||||||||||
|
Federal
|
$ | 44,550 | $ | 8,747 | $ | 15,671 | ||||||
|
State
|
11,389 | (626 | ) | 2,530 | ||||||||
| $ | 55,939 | $ | 8,121 | $ | 18,201 | |||||||
|
Deferred
tax expense (benefit):
|
||||||||||||
|
Federal
|
$ | (13,454 | ) | $ | (737 | ) | $ | (40,461 | ) | |||
|
State
|
(3,346 | ) | 1,811 | (8,259 | ) | |||||||
| $ | (16,800 | ) | $ | 1,074 | $ | (48,720 | ) | |||||
|
Total
income tax expense (benefit):
|
||||||||||||
|
Federal
|
$ | 31,096 | $ | 8,010 | $ | (24,790 | ) | |||||
|
State
|
8,043 | 1,185 | (5,729 | ) | ||||||||
| $ | 39,139 | $ | 9,195 | $ | (30,519 | ) | ||||||
A
reconciliation of the statutory federal income tax expense at 35% to income from
continuing operations before income taxes and the actual income tax expense
(benefit) is as follows:
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Federal
statutory income tax expense
|
$ | 70,169 | $ | 13,715 | $ | 34,177 | ||||||
|
Increases
(reductions) in taxes due to:
|
||||||||||||
|
Percentage
depletion allowance
|
(22,508 | ) | (9,851 | ) | (6,345 | ) | ||||||
|
Extraterritorial
income exclusion
|
(1,945 | ) | - | (1,678 | ) | |||||||
|
Deduction
for domestic production activities
|
(3,659 | ) | - | 63 | ||||||||
|
State
taxes, net of federal tax impact
|
5,292 | 766 | 3,859 | |||||||||
|
Stock-based
compensation not deductible
|
- | 203 | 4,472 | |||||||||
|
Change
in valuation allowances
|
(10,429 | ) | 3,776 | (67,629 | ) | |||||||
|
Loss
disallowance
|
2,147 | - | - | |||||||||
|
Other,
net
|
72 | 586 | 2,562 | |||||||||
|
Income
tax expense (benefit)
|
$ | 39,139 | $ | 9,195 | $ | (30,519 | ) | |||||
Deferred
income taxes result from temporary differences between the reporting of amounts
for financial statement purposes and income tax purposes. The net deferred tax
assets and liabilities included in the consolidated financial statements include
the following amounts:
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Deferred
tax assets
|
||||||||
|
Property,
plant, and equipment
|
$ | 39,966 | $ | 45,812 | ||||
|
Asset
retirement obligation
|
38,710 | 35,346 | ||||||
|
Other
liabilities
|
26,915 | 17,828 | ||||||
|
Postretirement
medical benefits
|
23,859 | 21,233 | ||||||
|
Alternative
minimum tax credit carryforwards
|
13,507 | 23,933 | ||||||
|
Goodwill
|
13,223 | 14,415 | ||||||
|
Workers'
compensation benefits
|
3,988 | 3,764 | ||||||
|
Deferred
gains on sales of property investments
|
1,236 | 1,562 | ||||||
|
Other
Assets
|
1,068 | 811 | ||||||
|
Net
operating loss carryforwards
|
- | 887 | ||||||
|
Gross
deferred tax assets
|
162,472 | 165,591 | ||||||
|
Less
valuation allowance
|
(34,462 | ) | (44,368 | ) | ||||
|
Total
net deferred tax assets
|
128,010 | 121,223 | ||||||
|
Deferred
tax liabilities
|
||||||||
|
Other
assets
|
(1,129 | ) | (1,691 | ) | ||||
|
Prepaid
insurance and other prepaid expenses
|
(5,333 | ) | (20,117 | ) | ||||
|
Advanced
mining royalties
|
(6,261 | ) | (4,527 | ) | ||||
|
Virginia
tax credit
|
(8,474 | ) | (7,511 | ) | ||||
|
Total
deferred tax liabilities
|
(21,197 | ) | (33,846 | ) | ||||
|
Net
deferred tax asset
|
$ | 106,813 | $ | 87,377 | ||||
The
breakdown of the net deferred tax asset as recorded in the accompanying
consolidated balance sheets is as follows:
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Current
liability
|
$ | (639 | ) | $ | (9,753 | ) | ||
|
Noncurrent
asset
|
107,452 | 97,130 | ||||||
|
Total
net deferred tax asset
|
$ | 106,813 | $ | 87,377 | ||||
Changes
in the valuation allowance during the year ended December 31, 2008 were as
follows:
|
Valuation
allowance at December 31, 2007
|
$ | 44,368 | ||
|
Increase
in valuation allowance not affecting income tax expense
|
1,473 | |||
|
Decrease
in valuation allowance recorded as a reduction to income tax expense -
continuing operations
|
(10,429 | ) | ||
|
Decrease
in valuation allowance recorded as a reduction to income tax expense -
discontinued operations
|
(950 | ) | ||
|
Valuation
allowance at December 31, 2008
|
$ | 34,462 | ||
The
increase in the valuation allowance not affecting income tax expense relates to
items recorded in other comprehensive income and includes the impact of SFAS 158
and the interest rate swap. The Company's valuation allowance of $34,462 as of
December 31, 2008 includes a full valuation allowance against the $13,507
Alternative Minimum Tax (“AMT”) credit carry-forward, which is available for an
unlimited carry-forward period to offset regular federal income tax in excess of
the AMT. The remaining valuation allowance is being maintained primarily to
account for the expectation that the Company will be a perpetual AMT taxpayer at
a 20% effective tax rate.
The
Company has concluded that it is more likely than not that deferred tax assets,
net of valuation allowances, currently recorded will be realized. The
amount of the valuation allowance takes into consideration the Alternative
Minimum Tax system as required by SFAS 109. The Company monitors the valuation
allowance each quarter and makes adjustments to the allowance as
appropriate.
The
Company adopted the provisions of Financial Standards Accounting Board
Interpretation (“FIN”) No. 48 Accounting for Uncertainty in Income
Taxes (“FIN 48”) an interpretation of SFAS 109 on January 1, 2007. As a
result of the adoption of FIN 48, the Company recognized no adjustment in the
unrecognized income tax benefits that existed at December 31, 2006. Total amount
of unrecognized tax benefits that would affect the Company’s effective tax rate
if recognized is $2,828 as of December 31, 2008. This amount takes
into consideration that a valuation allowance would be recorded against certain
deferred tax assets if unrecognized tax benefits were settled. The
Company does not anticipate that total unrecognized benefits recorded as of
December 31, 2008 will significantly change during the next twelve
months.
The
Company’s policy is to classify interest and penalties related to uncertain tax
positions as part of income tax expense. As of December 31, 2008, the Company
has recorded accrued interest expense of $145. In addition, the
Company has accrued interest income of $488 for those uncertain positions where
no additional cash taxes are projected due.
The
following reconciliation illustrates the Company’s liability for uncertain tax
positions:
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Unrecognized
tax benefits – beginning of period
|
$ | 5,500 | $ | 1,437 | ||||
|
Gross
increases – tax positions in prior period
|
14 | 517 | ||||||
|
Gross
decreases – tax positions in prior period
|
(642 | ) | (857 | ) | ||||
|
Gross
increases – current period tax positions
|
2,357 | 4,403 | ||||||
|
Settlements
|
- | - | ||||||
|
Lapse
of statute of limitations
|
- | - | ||||||
|
Unrecognized
tax benefits - end of period
|
$ | 7,229 | $ | 5,500 | ||||
Tax years
2005, 2006, and 2007 remain open to federal and state
examination. The Internal Revenue Service initiated a corporate
income tax audit during first quarter 2007 for the Company’s 2005 tax
year. The audit is still ongoing. Proposed adjustments to
date have been included in the provision calculation, and the Company expects
the examination to last through the second quarter of 2010.
|
(29)
|
Quarterly Financial Information (Unaudited) |
|
Year
Ended December 31, 2008
|
||||||||||||
|
First
|
Second
|
Third
|
Fourth
|
|||||||||
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
|||||||||
|
Total
revenues from continuing operations
|
$
|
516,326
|
$
|
728,977
|
$
|
714,986
|
$
|
593,835
|
||||
|
Income
(loss) from continuing operations
|
26,304
|
75,314
|
64,866
|
(5,139
|
) | |||||||
|
Income
(loss) from discontinuing operations
|
(774
|
) |
(977
|
) |
4,997
|
946
|
||||||
|
Net
income (loss)
|
25,530
|
74,337
|
69,863
|
(4,193
|
) | |||||||
|
Basic
earnings per share - income (loss) from continuing
operations
|
0.40
|
1.08
|
0.93
|
(0.07
|
) | |||||||
|
Basic
earnings per share - income (loss) from discontinuing
operations
|
(0.01
|
) |
(0.01
|
) |
0.07
|
0.01
|
||||||
|
Diluted
earnings per share - income (loss) from continuing
operations
|
0.40
|
1.05
|
0.90
|
(0.07
|
) | |||||||
|
Diluted
earnings per share - income (loss) from discontinuing
operations
|
(0.01
|
) |
(0.01
|
) |
0.07
|
0.01
|
||||||
|
Basic
earnings per share - net income (loss)
|
0.39
|
1.07
|
1.00
|
(0.06
|
) | |||||||
|
Diluted
earnings per share - net income (loss)
|
0.39
|
1.04
|
0.97
|
(0.06
|
) | |||||||
Income
(loss) from continuing operations for the quarter ended December 31, 2008
includes a $56,315 pre-tax net gain reflecting proceeds less transaction
costs from the $70,000 payment received from Cliffs upon termination of its
planned merger with the Company, a pre-tax unrealized loss of
$36,171 related to change in fair value of derivative contracts, a pre-tax
$30,172 charge related to the closure of the Whitetail Kittanning mine
complex, a pre-tax $12,300 charge to coal revenue relating to a coal contract
settlement, a pre-tax impairment charge of $4,534 related to the Company’s
equity investment in the Excelven joint venture, and an income tax charge of
$20,303 to increase the valuation allowance for deferred tax
assets.
|
Year
Ended December 31, 2007
|
||||||||||||
|
First
|
Second
|
Third
|
Fourth
|
|||||||||
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
|||||||||
|
Total
revenues from continuing operations
|
$ | 430,591 | $ | 435,348 | $ | 509,387 | $ | 510,506 | ||||
|
Income
from continuing operations
|
8,933 | 5,197 | 9,433 | 6,427 | ||||||||
|
Loss
from discontinuing operations
|
(584 | ) | (450 | ) | (484 | ) | (738 | ) | ||||
|
Net
income
|
8,349 | 4,747 | 8,949 | 5,689 | ||||||||
|
Basic
earnings per share - income from continuing operations
|
0.14 | 0.08 | 0.15 | 0.10 | ||||||||
|
Basic
earnings per share - loss from discontinuing operations
|
(0.01 | ) | (0.01 | ) | (0.01 | ) | (0.01 | ) | ||||
|
Diluted
earnings per share - income from continuing operations
|
0.14 | 0.08 | 0.15 | 0.10 | ||||||||
|
Diluted
earnings per share - loss from discontinuing operations
|
(0.01 | ) | (0.01 | ) | (0.01 | ) | (0.01 | ) | ||||
|
Basic
earnings per share - net income
|
0.13 | 0.07 | 0.14 | 0.09 | ||||||||
|
Diluted
earnings per share - net income
|
0.13 | 0.07 | 0.14 | 0.09 | ||||||||
Net
income for the quarter ended December 31, 2007 included a pre-tax unrealized
gain of $6,673 related to the change in fair value of derivative
contracts.
|
Year
Ended December 31, 2006
|
||||||||||||||||
|
First
|
Second
|
Third
|
Fourth
|
|||||||||||||
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
|||||||||||||
|
Total
revenues from continuing operations
|
$
|
482,310
|
$
|
489,773
|
$
|
476,507
|
$
|
455,953
|
||||||||
|
Income
from continuing operations
|
27,211
|
23,128
|
14,544
|
63,285
|
||||||||||||
|
Net
income
|
27,211
|
23,128
|
14,544
|
63,285
|
||||||||||||
|
Basic
and diluted earnings per share - net income
|
0.43
|
0.36
|
0.23
|
0.98
|
||||||||||||
Net
income for the quarter ended December 31, 2006 included a charge to coal revenue
of $7,000 for a contract buyout of a multi-year legacy coal supply agreement and
an income tax benefit of $55,614 for a reversal of a deferred tax asset
valuation allowance.
|
Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
|
None.
|
Controls
and Procedures
|
Evaluation of disclosure controls
and procedures. Our Disclosure Committee has responsibility for ensuring
that there is an adequate and effective process for establishing, maintaining
and evaluating disclosure controls and procedures that are designed to ensure
that information required to be disclosed by us in our SEC reports is timely
recorded, processed, summarized and reported. In addition, we have established a
Code of Business Ethics designed to provide a statement of the values and
ethical standards to which we require our employees and directors to adhere. The
Code of Business Ethics provides the framework for maintaining the highest
possible standards of professional conduct. We also maintain an
ethics hotline for employees. There are inherent limitations to the
effectiveness of any system of disclosure controls and procedures, including the
possibility of human error and the circumvention or overriding of the controls
and procedures. Accordingly, even effective disclosure controls and procedures
can only provide reasonable assurance of achieving their control
objectives.
Under the
supervision and with the participation of our management, including our Chief
Executive Officer and our Chief Financial Officer, we evaluated the
effectiveness of our disclosure controls and procedures, as such term is defined
under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as
amended, as of the end of the period covered by this report. Based upon that
evaluation, our Chief Executive Officer and Chief Financial Officer concluded
that our disclosure controls and procedures were effective, as of the end of the
period covered by this report, in ensuring that material information relating to
Alpha Natural Resources, Inc., required to be disclosed in reports that it files
or submits under the Securities Exchange Act of 1934, is recorded, processed,
summarized and reported within the requisite time periods and is accumulated and
communicated to our management, including our Chief Executive Officer and our
Chief Financial Officer, as appropriate to allow timely decisions regarding
disclosure.
Management's
Report on Internal Control Over Financial Reporting
Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting. Our internal control over financial reporting
is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles.
Our
internal control over financial reporting includes policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect transactions and dispositions of assets;
(2) provide reasonable assurances that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures are
being made only in accordance with authorizations of management and the
directors of the Company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use or disposition
of the Company's assets that could have a material effect on our financial
statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
Management
assessed the effectiveness of the Company's internal control over
financial reporting as of December 31, 2008. In making this assessment,
management used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) in Internal Control-Integrated
Framework. Based on our assessment and those criteria, management has concluded
that we maintained effective internal control over financial reporting as of
December 31, 2008.
Report
of Independent Registered Public Accounting Firm
The Board
of Directors and Stockholders
Alpha
Natural Resources, Inc.:
We have
audited Alpha Natural Resources, Inc.’s internal control over financial
reporting as of December 31, 2008, based on criteria established in Internal Control – Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Alpha Natural Resources, Inc.’s management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s Report on Internal Control
over Financial Reporting. Our responsibility is to express an opinion
on the Company’s internal control over financial reporting based on our
audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal
control based on the assessed risk. Our audit also included performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company;
(2) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company; and (3) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the
financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our
opinion, Alpha Natural Resources, Inc. maintained, in all material respects,
effective internal control over financial reporting as of December 31,
2008, based on criteria established in Internal Control – Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of Alpha
Natural Resources, Inc. and subsidiaries as of December 31, 2008 and 2007,
and the related consolidated statements of income, stockholders’ equity and
comprehensive income, and cash flows for each of the years in the three-year
period ended December 31, 2008, and our report dated February 26, 2009
expressed an unqualified opinion on those consolidated financial
statements.
/s/ KPMG
LLP
Roanoke,
Virginia
February
26, 2009
Changes
in internal controls over financial reporting
There
were no changes that occurred during the fourth quarter of the fiscal year
covered by this Annual Report on Form 10-K that have materially affected, or are
reasonably likely to materially affect, the Company's internal control over
financial reporting.
|
Other
Information
|
Retention
Plan Restricted Stock Awards
On
February 25, 2009, the Compensation Committee of the Company's Board of
Directors approved the grant of retention plan restricted stock awards under the
2005 Long-Term Incentive Plan (as amended, the "Plan") to the Company's officers
and other key employees. The restricted stock awards vest in full on
the third anniversary of the grant date. If a participant terminates
employment before February 25, 2012, the employee will forfeit the award in full
except if: (i) employment is involuntarily terminated without cause
during the 90-day period immediately preceding a change in control or on or
within the one-year period immediately following a change in control, any
unvested shares will immediately vest in full, or (ii) employment with the
Company is terminated without cause, or as a result of permanent disability or
death, any unvested shares will become vested based on the ratio of the number
of complete months the employee is employed or serves with the Company during
the vesting period to the total number of months in the vesting
period. The named executive officers listed in the Company's most
recent proxy statement and the current Chief Financial Officer received
retention plan awards in the following amounts: Chief Executive
Officer (108,304 shares), President (86,643 shares), Chief Financial Officer
(14,183 shares), Executive Vice President and Chief Operating Officer (45,127
shares), and Senior Vice President (36,959 shares).
A copy of the
form of retention plan restricted stock agreement is attached to this Annual
Report on Form 10-K as Exhibit 10.41 and is incorporated herein by
reference.
PART III
|
Directors, Executive
Officers and Corporate Governance
|
Incorporated
herein by reference from the Proxy Statement.
The Board
of Directors of Alpha Natural Resources, Inc. has adopted a code of business
ethics that applies to our principal executive officers, principal financial
officer, and principal accounting officer, as well as other employees. A
copy of this code of ethics has been posted on our Internet website at
www.alphanr.com. Any amendments to, or waivers from, a provision of our code of
ethics that applies to our principal executive officer, principal financial
officer, controller, or persons performing similar functions and that relates to
any element of the code of ethics enumerated in paragraph (b) of
Item 406 of Regulation S-K shall be disclosed by posting such
information on our website.
Additional
Information
We file
annual, quarterly and current reports, proxy statements and other information
with the Securities and Exchange Commission (“SEC”). You may access and read our
SEC filings through our website, at www.alphanr.com, or the SEC's website, at
www.sec.gov. You may also read and copy any document we file at the SEC's public
reference room located at 100 F Street, N.E., Washington, D.C. 20549.
Please call the SEC at 1-800-SEC-0330 for further information on the public
reference room. You may also request copies of our filings, at no cost, by
telephone at (276) 619-4410 or by mail at: Alpha Natural Resources, Inc.,
One Alpha Place, P.O. Box 2345, Abingdon, Virginia 24212, attention:
Investor Relations.
Our Audit
Committee Charter, Compensation Committee Charter, Nominating and Corporate
Governance Committee Charter, Corporate Governance Practices and Policies, and
Code of Business Ethics are also available on our website and available in print
to any stockholder who requests them.
|
Executive
Compensation
|
Incorporated
herein by reference from the Proxy Statement.
|
Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
|
Incorporated
herein by reference from the Proxy Statement.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
Incorporated
herein by reference from the Proxy Statement.
|
Principal
Accountant Fees and Services
|
Incorporated
herein by reference from the Proxy Statement.
PART IV
|
Exhibits
and Financial Statement Schedules
|
Pursuant
to the rules and regulations of the Securities and Exchange Commission, the
Company has filed certain agreements as exhibits to this Annual Report on Form
10-K. These agreements may contain representations and warranties by the
parties. These warranties have been made solely for the benefit of the other
party or parties to such agreements and (i) may been qualified by disclosure
made to such other party or parties, (ii) were made only as of the date of such
agreements or such other date(s) as may be specified in such agreements and are
subject to more recent developments, which may not be fully reflected in such
Company's public disclosure, (iii) may reflect the allocation of risk among the
parties to such agreements and (iv) may apply materiality standards different
from what may be viewed as material to investors. Accordingly, these
representations and warranties may not describe the Company's actual state of
affairs at the date hereof and should not be relied upon.
|
(a)
|
Documents
filed as part of this annual
report:
|
(1) The following financial statements
are filed as part of this annual report under Item 8:
Alpha
Natural Resources, Inc. and Subsidiaries
Reports
of Independent Registered Public Accounting Firm
Consolidated
Balance Sheets, December 31, 2008 and 2007
Consolidated
Statements of Income, years ended December 31, 2008, 2007 and
2006
Consolidated
Statements of Stockholders' Equity and Comprehensive Income, years ended
December 31, 2008, 2007 and 2006
Consolidated
Statements of Cash Flows, years ended December 31, 2008, 2007 and
2006
Notes to
Consolidated Financial Statements
(2) Financial Statement
Schedules. All schedules for which provision is made in the applicable
accounting regulations of the SEC are not required under the related
instructions, are inapplicable or not material, or the information called for
thereby is otherwise included in the consolidated financial statements and
therefore has been omitted.
(3) Listing of Exhibits. See
Exhibit Index following the signature page of this annual
report.
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
|
ALPHA
NATURAL RESOURCES, INC.
|
||||
|
By:
|
/s/
Eddie W. Neely
|
|||
|
Name:
|
Eddie
W. Neely
|
|||
|
Title:
|
Executive
Vice President, Chief Financial Officer, Assistant Secretary and
Controller
|
|||
Date:
February 26, 2009
KNOW ALL
PERSONS BY THESE PRESENTS, that each person whose signature appears below
constitutes and appoints Eddie W. Neely and Vaughn R. Groves, and each of them,
his or her true and lawful attorneys-in-fact, each with full power of
substitution, for him or her in any and all capacities, to sign any amendments
to this report on Form 10-K and to file the same, with exhibits thereto and
other documents in connection therewith, with the Securities and Exchange
Commission, hereby ratifying and confirming all that each of said
attorneys-in-fact or their substitute or substitutes may do or cause to be done
by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on behalf of
the registrant and in the capacities and on the dates indicated.
|
Signature
|
Date
|
Title
|
||
|
/s/ Michael J. Quillen
|
February
26, 2009
|
Chairman
of the Board of Directors and Chief Executive Officer (Principal Executive
Officer)
|
||
|
Michael
J. Quillen
|
||||
|
/s/ Eddie W. Neely
|
February
26, 2009
|
Executive
Vice President, Chief Financial Officer, Assistant Secretary and
Controller
(Principal
Financial and Accounting Officer)
|
||
|
Eddie
W. Neely
|
||||
|
/s/ Mary Ellen Bowers
|
February
26, 2009
|
Director
|
||
|
Mary
Ellen Bowers
|
||||
|
/s/ John S. Brinzo
|
February
26, 2009
|
Director
|
||
|
John
S. Brinzo
|
||||
|
/s/ Kevin S. Crutchfield
|
February
26, 2009
|
Director
and President
|
||
|
Kevin
S. Crutchfield
|
||||
|
/s/ E. Linn Draper, Jr.
|
February
26, 2009
|
Director
|
||
|
E.
Linn Draper, Jr.
|
||||
|
/s/ Glenn A. Eisenberg
|
February
26, 2009
|
Director
|
||
|
Glenn
A. Eisenberg
|
||||
|
/s/ John W. Fox, Jr.
|
February
26, 2009
|
Director
|
||
|
John
W. Fox, Jr.
|
||||
|
/s/ Ted G. Wood
|
February
26, 2009
|
Director
|
||
|
Ted
G. Wood
|
||||
|
Exhibit
No.
|
Description
of Exhibit
|
||
|
2.1
|
Asset
Purchase Agreement by and between Pittston Coal Company and
Dickenson-Russell Coal Company, LLC, dated as of October 29, 2002, as
amended (Incorporated by reference to the Registration Statement on
Form S-1 of Alpha Natural Resources, Inc. (File No. 333-121002)
filed on December 6, 2004.)
|
||
|
2.2
|
Asset
Purchase Agreement by and between Pittston Coal Company and Paramont Coal
Company Virginia, LLC, dated as of October 29, 2002, as amended
(Incorporated by reference to the Registration Statement on Form S-1
of Alpha Natural Resources, Inc. (File No. 333-121002) filed on
December 6, 2004.)
|
||
|
2.3
|
Asset
Purchase Agreement by and between Pittston Coal Company and Alpha Land and
Reserves, LLC, dated as of October 29, 2002, as amended (Incorporated
by reference to the Registration Statement on Form S-1 of Alpha
Natural Resources, Inc. (File No. 333-121002) filed on
December 6, 2004.)
|
||
|
2.4
|
Asset
Purchase Agreement by and between Pittston Coal Company and Alpha Coal
Sales Co., LLC, dated as of October 29, 2002, as amended
(Incorporated by reference to the Registration Statement on Form S-1
of Alpha Natural Resources, Inc. (File No. 333-121002) filed on
December 6, 2004.)
|
||
|
2.5
|
Asset
Purchase Agreement by and between Pittston Coal Company and Alpha Terminal
Company, LLC, dated as of October 29, 2002, as amended (Incorporated
by reference to the Registration Statement on Form S-1 of Alpha
Natural Resources, Inc. (File No. 333-121002) filed on
December 6, 2004.)
|
||
|
2.6
|
Asset
Purchase Agreement by and between Pittston Coal Company and Maxxim Rebuild
Co., LLC, dated as of October 29, 2002, as amended (Incorporated by
reference to the Registration Statement on Form S-1 of Alpha Natural
Resources, Inc. (File No. 333-121002) filed on December 6,
2004.)
|
||
|
2.7
|
Purchase
and Sale Agreement by and among El Paso CGP Company and AMFIRE, LLC
dated as of November 14, 2002, as amended (Incorporated by reference
to the Registration Statement on Form S-1 of Alpha Natural Resources,
Inc. (File No. 333-121002) filed on December 6,
2004.)
|
||
|
2.8
|
Contribution
Agreement among the FRC Parties, the AMCI Parties, ANR Holdings, LLC and
the Additional Persons listed on the signature pages dated as of
March 11, 2003, as amended (Incorporated by reference to the
Registration Statement on Form S-1 of Alpha Natural Resources, Inc.
(File No. 333-121002) filed on December 6,
2004.)
|
||
|
2.9
|
Purchase
and Sale Agreement made and entered into as of January 31, 2003 by
and among Alpha Land and Reserves, LLC and CSTL, LLC (Incorporated by
reference to the Registration Statement on Form S-1 of Alpha Natural
Resources, Inc. (File No. 333-121002) filed on December 6,
2004.)
|
||
|
2.10
|
Purchase
and Sale Agreement dated as of April 9, 2003 by and between Alpha
Land and Reserves, LLC and CSTL LLC (Incorporated by reference to the
Registration Statement on Form S-1 of Alpha Natural Resources, Inc.
(File No. 333-121002) filed on December 6,
2004.)
|
||
|
2.11
|
Purchase
and Sale Agreement dated as of April 9, 2003 by and between
Dickenson-Russell Coal Company, LLC and WBRD LLC (Incorporated by
reference to the Registration Statement on Form S-1 of Alpha Natural
Resources, Inc. (File No. 333-121002) filed on December 6,
2004.)
|
||
|
2.12
|
Letter
agreement dated April 9, 2003 among Alpha Natural Resources, LLC,
Dickenson-Russell Company, LLC, Alpha Land and Reserves, LLC, CSTL LLC,
WBRD LLC, and Natural Resources Partners L.P. (Incorporated by reference
to the Registration Statement on Form S-1 of Alpha Natural Resources,
Inc. (File No. 333-121002) filed on December 6,
2004.)
|
||
|
2.13
|
Asset
Purchase Agreement by and among S&M Mining, S&M Mining, Inc. and
AMFIRE Mining Company, LLC dated October 29, 2003, as amended
(Incorporated by reference to the Registration Statement on Form S-1
of Alpha Natural Resources, Inc. (File No. 333-121002) filed on
December 6, 2004.)
|
||
|
2.14
|
Asset
Purchase Agreement by and among DLR Coal Co., DLR Mining, Inc. and AMFIRE
Mining Company, LLC dated October 29, 2003, as amended (Incorporated
by reference to the Registration Statement on Form S-1 of Alpha
Natural Resources, Inc. (File No. 333-121002) filed on
December 6, 2004.)
|
||
|
2.15
|
Asset
Purchase Agreement by and between Mears Enterprises, Inc. and AMFIRE
Mining Company, LLC dated October 29, 2003, as amended (Incorporated
by reference to the Registration Statement on Form S-1 of Alpha
Natural Resources, Inc. (File No. 333-121002) filed on
December 6, 2004.)
|
||
|
2.16
|
Internal
Restructuring Agreement dated as of February 11, 2005 by and among
Alpha Natural Resources, Inc., Alpha NR Ventures, Inc., ANR Holdings, LLC,
the FRC Parties named therein, the AMCI Parties named therein, Madison
Capital Funding LLC, Alpha Coal Management, LLC and the Management Members
named therein (Incorporated by reference to Exhibit 2.16 to the
Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File
No. 1-32423) filed on March 30,
2005.)
|
||
|
10-K
EXHIBIT INDEX - Continued
|
|||
|
Exhibit
No.
|
Description
of Exhibit
|
||
|
2.17
|
Sixth
Amendment to Contribution Agreement by and among the FRC Parties, the AMCI
Parties, ANR Holdings, LLC and Alpha Natural Resources, Inc. (Incorporated
by reference to Exhibit 2.17 to the Annual Report on Form 10-K
of Alpha Natural Resources, Inc. (File No. 1-32423) filed on
March 30, 2005.)
|
||
|
2.18
|
Asset
Purchase Agreement dated April 14, 2005, by and among Gallup
Transportation and Transloading Company, LLC, NATIONAL KING COAL LLC and
NKC Acquisition, LLC (Incorporated by reference to Exhibit 2.1 to the
Current Report on Form 8-K of Alpha Natural Resources, Inc. (File
No. 1-32423) filed on April 15, 2005.)
|
||
|
2.19
|
Acquisition
Agreement dated as of September 23, 2005 among Alpha Natural
Resources, LLC, Mate Creek Energy of W. Va., Inc., Virginia Energy
Company, the unitholders of Powers Shop, LLC, and the shareholders of
White Flame Energy, Inc., Twin Star Mining, Inc. and Nicewonder
Contracting, Inc. (the “Acquisition Agreement”) (Incorporated by reference
to Exhibit 2.1 to the Current Report on Form 8-K of Alpha
Natural Resources, Inc. (File No. 1-32423) filed on
September 26, 2005.)
|
||
|
2.20
|
Membership
Unit Purchase Agreement dated as of September 23, 2005 among Premium
Energy, LLC and the unitholders of Buchanan Energy Company, LLC (the
“Membership Unit Purchase Agreement”) (Incorporated by reference to
Exhibit 2.2 to the Current Report on Form 8-K of Alpha Natural
Resources, Inc. (File No. 1-32423) filed on September 26,
2005.)
|
||
|
2.21
|
Agreement
and Plan of Merger dated as of September 23, 2005 among Alpha Natural
Resources, Inc., Alpha Natural Resources, LLC, Premium Energy, LLC,
Premium Energy, Inc. and the shareholders of Premium Energy, Inc. (the
“Premium Energy Shareholders”) (the “Merger Agreement”) (Incorporated by
reference to Exhibit 2.3 to the Current Report on Form 8-K of
Alpha Natural Resources, Inc. (File No. 1-32423) filed on
September 26, 2005.)
|
||
|
2.22
|
Indemnification
Agreement dated as of September 23, 2005 among Alpha Natural
Resources, Inc., Alpha Natural Resources, LLC, Premium Energy, LLC, the
other parties to the Acquisition Agreement, the Premium Energy
Shareholders, and certain of the unitholders of Buchanan Energy Company,
LLC (Incorporated by reference to Exhibit 2.4 to the Current Report
on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32423)
filed on September 26, 2005.)
|
||
|
2.23
|
Letter
Agreement dated of as September 23, 2005 among Alpha Natural
Resources, Inc., Alpha Natural Resources, LLC, Premium Energy, LLC and the
other parties to the Acquisition Agreement, the Membership Unit Purchase
Agreement and the Merger Agreement (Incorporated by reference to
Exhibit 2.5 to the Current Report on Form 8-K of Alpha Natural
Resources, Inc. (File No. 1-32423) filed on September 26,
2005.)
|
||
|
2.24
|
Letter
Agreement dated October 26, 2005 (the “Letter Agreement”) among Alpha
Natural Resources, Inc., Alpha Natural Resources, LLC, Premium Energy,
LLC, Premium Energy, Inc. and the Sellers Representative named therein
amending certain provisions of (i) the Acquisition Agreement dated
September 23, 2005, among certain parties to the Letter Agreement and
certain other parties named therein, (ii) the Agreement and Plan of
Merger dated September 23, 2005, among the parties to the Letter
Agreement and certain other parties named therein and (iii) the
Indemnification Agreement dated September 23, 2005, among the parties
to the Letter Agreement and certain other parties named therein.
(Incorporated by reference to Exhibit 2.1 to the Current Report on
Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32423)
filed on October 31,
2005.)
|
|
2.25
|
Assignment
of Rights Under Certain Agreements executed as of October 26, 2005
among Alpha Natural Resources, LLC, Mate Creek Energy, LLC, Callaway
Natural Resources, Inc., Premium Energy, LLC and Virginia Energy Company,
LLC (Incorporated by reference to Exhibit 2.2 to the Current Report
on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32423)
filed on October 31, 2005.)
|
||
|
2.26
|
Agreement
and Plan of Merger by and among Cliffs Natural Resources Inc. (formerly
known as Cleveland-Cliffs Inc.), Alpha Merger Sub, Inc. (formerly known as
Daily Double Acquisition, Inc.), and Alpha Natural Resources, Inc., dated
as of July 15, 2008 (Incorporated by reference to Exhibit 2.1 to the
Current Report on Form 8-K (File No. 1-32423) filed on July 17,
2008.)
|
||
|
2.27*
|
|||
|
3.1
|
Restated
Certificate of Incorporation of Alpha Natural Resources, Inc.
(Incorporated by reference to Exhibit 3.1 to the Annual Report on
Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32423)
filed on March 30, 2005.)
|
||
|
3.2
|
Amended
and Restated Bylaws of Alpha Natural Resources, Inc. (Incorporated by
reference to Exhibit 3.2 to the Annual Report on Form 10-K of Alpha
Natural Resources, Inc. (File No. 1-32423) filed on March 1,
2007.)
|
||
|
4.1
|
Form
of certificate of Alpha Natural Resources, Inc. common stock (Incorporated
by reference to Amendment No. 3 to the Registration Statement on
Form S-1 of Alpha Natural Resources, Inc. (File No. 333-121002)
filed on February 10, 2005.)
|
||
|
4.2
|
Indenture
dated as of May 18, 2004 among Alpha Natural Resources, LLC, Alpha
Natural Resources Capital Corp., the Guarantors named therein and Wells
Fargo Bank, N.A., as Trustee (Incorporated by reference to
Exhibit 10.5 to the Registration Statement on Form S-1 of Alpha
Natural Resources, Inc. (File No. 333-121002) filed on
December 6, 2004.)
|
||
|
4.3
|
First
Supplemental Indenture dated as of February 1, 2005 among Alpha
Natural Resources, LLC, Alpha Natural Resources Capital Corp., the
Guarantors party thereto and Wells Fargo Bank, N.A., as Trustee
(Incorporated by reference to Exhibit 4.3 to the Annual Report on
Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32423)
filed on March 30, 2005.)
|
||
|
4.4
|
Second
Supplemental Indenture dated as of March 30, 2005 among Alpha Natural
Resources, LLC, Alpha Natural Resources Capital Corp., Alpha NR Holding,
Inc., Alpha NR Ventures, Inc., ANR Holdings, LLC, the Guarantors party
thereto and Wells Fargo Bank, N.A., as Trustee (Incorporated by reference
to Exhibit 4.4 to the Annual Report on Form 10-K of Alpha
Natural Resources, Inc. (File No. 1-32423) filed on March 30,
2005.)
|
||
|
4.5
|
Third
Supplemental Indenture dated as of October 26, 2005 among Alpha
Natural Resources, LLC, Alpha Natural Resources Capital Corp., Alpha NR
Holding, Inc., ANR Holdings, LLC, the Guarantors party thereto, the
Guaranteeing Subsidiaries party thereto and Wells Fargo Bank, N.A., as
Trustee (Incorporated by reference to Exhibit 10.3 to the Current
Report on Form 8-K of Alpha Natural Resources, Inc. (File
No. 1-32423) filed on October 31,
2005.)
|
|
10-K
EXHIBIT INDEX - Continued
|
|||
|
Exhibit
No.
|
Description
of Exhibit
|
||
|
4.6
|
Fourth
Supplemental Indenture dated as of January 3, 2006 among Alpha
Natural Resources, LLC, Alpha Natural Resources Capital Corp., Alpha NR
Holding, Inc., the Guarantors party thereto, the Guaranteeing Subsidiaries
party thereto and Wells Fargo Bank, N.A., as Trustee (Incorporated by
reference to Exhibit 4.6 to the Registration Statement on
Form S-1 of Alpha Natural Resources, Inc. (File No. 333-129030)
filed on January 9, 2006.)
|
||
|
4.7
|
Fifth
Supplemental Indenture dated as of May 1, 2006 among Alpha Natural
Resources, LLC, Alpha Natural Resources Capital Corp. , the existing
Guarantors, Wells Fargo Bank, N.A., as Trustee, and Progress Land
Corporation (Incorporated by reference to Exhibit 4.1 to the Quarterly
Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32423)
filed on August 18,
2006.)
|
|
4.8
|
Sixth
Supplemental Indenture dated as of January 10, 2007 among Alpha Natural
Resources, LLC, Alpha Natural Resources Capital Corp., the existing
Guarantors, Wells Fargo Bank, N.A., as Trustee, Palladian Holdings, LLC
and Palladian Lime, LLC (Incorporated by reference to Exhibit 4.8 to the
Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No.
1-32423) filed on March 1, 2007.)
|
||
|
4.9
|
Seventh
Supplemental Indenture, dated as of July 12, 2007, by and among Alpha
Natural Resources, LLC, Alpha Natural Resources Capital Corp., the
existing Guarantors, Wells Fargo Bank, N.A., as Trustee, and Cobra Natural
Resources, LLC (Incorporated by reference to Exhibit 4.16 to the
Registration Statement on Form S-3 of Alpha Natural Resources, Inc. (File
No. 333-134081) filed on April 1, 2008.)
|
||
|
4.10
|
Eighth
Supplemental Indenture dated as of April 14, 2008, among Alpha Natural
Resources, LLC, Alpha Natural Resources Capital Corp., the guarantors
named therein and Wells Fargo Bank, National Association, as trustee
(Incorporated by reference to Exhibit 4.1 to the Current Report on Form
8-K (File No. 1-32423) filed on April 15, 2008.)
|
||
|
4.11
|
Indenture,
dated as of April 7, 2008, between Alpha Natural Resources, Inc. and Union
Bank of California, N.A., as Trustee (Incorporated by reference to Exhibit
4.1 to the Current Report on Form 8-K (File No. 1-32423) filed on April 9,
2008.)
|
||
|
4.12
|
Subordinated
Indenture, dated as of April 7, 2008, between Alpha Natural Resources,
Inc. and Union Bank of California, N.A., as Trustee (Incorporated by
reference to Exhibit 4.2 to the Current Report on Form 8-K (File No.
1-32423) filed on April 9, 2008.)
|
||
|
4.13
|
Supplemental
Indenture dated as of April 7, 2008, between Alpha Natural Resources, Inc.
and Union Bank of California, N.A., as Trustee (Incorporated by reference
to Exhibit 4.3 to the Current Report on Form 8-K (File No. 1-32423) filed
on April 9, 2008.)
|
||
|
4.14
|
Form
of 2.375% Convertible Senior Note due 2015 (Incorporated by reference to
Exhibit 4.4 to the Current Report on Form 8-K (File No. 1-32423) filed on
April 9, 2008.)
|
||
|
10.1
|
Credit
Agreement dated as of October 26, 2005, among Alpha NR Holding, Inc.,
Alpha Natural Resources, LLC, the Lenders and Issuing Banks party thereto
from time to time, Citicorp North America, Inc., as administrative agent
and as collateral agent for the Lenders and Issuing Banks, UBS Securities
LLC as syndication agent, the co-documentation agents party thereto,
Citigroup Global Markets Inc. and UBS Securities LLC, as joint lead
arrangers and joint book managers. (Incorporated by reference to
Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural
Resources, Inc. (File No. 1-32423) filed on October 31,
2005.)
|
||
|
10.2
|
Guarantee
and Collateral Agreement, dated as of October 26, 2005, made by each
of the Grantors as defined therein, in favor of Citicorp North America,
Inc., as administrative agent and as collateral agent for the banks and
other financial institutions or entities from time to time parties to the
Credit Agreement and the other Secured Parties, as defined therein.
(Incorporated by reference to Exhibit 10.2 to the Current Report on
Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32423)
filed on October 31, 2005.)
|
||
|
10.3
|
Waiver
and Consent dated as of August 14, 2006 to Credit Agreement among Alpha NR
Holding, Inc., Alpha Natural Resources, LLC, the Lenders and Issuing Banks
party thereto from time to time, and Citicorp North America, Inc., as
administrative agent and as collateral agent for the Lenders and Issuing
Banks (Incorporated by reference to Exhibit 10.1 to the Current Report on
Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32423) filed on
August 18, 2006.)
|
||
|
10.4
|
Amendment
and Consent, dated as of December 22, 2006, to Credit Agreement, among
Alpha NR Holding, Inc., Alpha Natural Resources, LLC, the Lenders and
Issuing Banks party thereto from time to time, and Citicorp North America,
Inc., as administrative agent and as collateral agent for the Lenders and
Issuing Banks (Incorporated by reference to Exhibit 10.1 to the Current
Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32423)
filed on December 29,
2006.)
|
|
10-K
EXHIBIT INDEX - Continued
|
|||
|
Exhibit
No.
|
Description
of Exhibit
|
||
|
10.5
|
Second
Amendment and Consent to Credit Agreement dated June 28, 2007
(Incorporated by reference to Exhibit 10.1 to the Current Report on Form
8-K of Alpha Natural Resources, Inc. (File No. 1-32423) filed on July 5,
2007.)
|
||
|
10.6
|
Third
Amendment and Joinder Agreement, dated March 28, 2008, among Alpha Natural
Resources, Inc. (as successor by merger to Alpha NR Holding, Inc.
(“Holdings”), Alpha Natural Resources, LLC (“ANR LLC”), Citicorp North
America, Inc., as administrative agent and as collateral agent (the
“Agent”), and the Lenders and Issuing Banks (the “Banks”) party thereto
from time to time, to the Credit Agreement (the “Credit Agreement”), dated
as of October 26, 2005, among Holdings, ANR LLC, the Banks and the Agent,
as amended (Incorporated by reference to Exhibit 10.1 to the Current
Report on Form 8-K (File No. 1-32423)
filed on April 3, 2008.)
|
||
|
10.7
|
Fourth
Amendment and Consent, dated March 31, 2008, among Alpha Natural
Resources, Inc., ANR LLC, the Agent and the Banks party thereto
from time to time, to the Credit Agreement (Incorporated by reference to
Exhibit 10.2 to the Current Report on Form 8-K (File No. 1-32423) filed on April 3,
2008.)
|
||
|
10.8*
|
|||
|
10.9*‡
|
|||
|
10.10*‡
|
|||
|
10.11
|
Amended
and Restated Stockholder Agreement dated as of October 26, 2005, by
and among Alpha Natural Resources, Inc., the FRC Parties named therein,
the AMCI Parties named therein, Madison Capital Funding LLC, the
Nicewonder Parties named therein, and the other stockholders named
therein. (Incorporated by reference to Exhibit 10.5 to the Current
Report on Form 8-K of Alpha Natural Resources, Inc. (File
No. 1-32423) filed on October 31, 2005.)
|
||
|
10.12
|
Letter
agreement dated October 25, 2005, by the FRC Parties named therein
and the AMCI Parties named therein, amending certain provisions of the
Stockholder Agreement. (Incorporated by reference to Exhibit 10.4 to
the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File
No. 1-32423) filed on October 31, 2005.)
|
||
|
10.13
|
Letter
agreement dated December 8, 2005, by the FRC Parties named therein
and the AMCI Parties named therein and Alpha Natural Resources, Inc.,
amending certain provisions of the Stockholder Agreement (Incorporated by
reference to Exhibit 10.1 to the Current Report on Form 8-K of
Alpha Natural Resources, Inc. (File No. 1-32423) filed on
December 12,
2005.)
|
||
|
10.14
|
Letter
Agreement dated November 7, 2006, by the AMCI Parties named therein and
Alpha Natural Resources, Inc., amending certain provisions of the
Stockholder Agreement (Incorporated by reference to Exhibit 10.2 to the
Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No.
1-32423) filed November 9, 2006.)
|
||
|
10.15
|
Agreement
to Terminate the Amended and Restated Stockholder Agreement dated as of
May 23, 2007 (Incorporated by reference to Exhibit 10.1 to the Current
Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32423)
filed on May 29, 2007.)
|
||
|
10.16‡
|
Alpha
Natural Resources, Inc. Annual Incentive Bonus (AIB) Plan (Restated
as of November 20, 2007) (Incorporated by reference to Exhibit 10.16 to
the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No.
001-32423) filed on February 29, 2008.)
|
||
|
10.17‡
|
Alpha
Natural Resources, Inc. Annual Incentive Bonus Plan (effective May 14,
2008) (Incorporated by reference to Exhibit 10.2 to the Current Report on
Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32423) filed on
May 16, 2008.)
|
||
|
10.18‡
|
Alpha
Natural Resources, Inc. Amended and Restated 2004 Long-Term Incentive Plan
(Restated as of November 8, 2007) (Incorporated by reference to Exhibit
10.17 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc.
(File No. 001-32423) filed on February 29, 2008.)
|
||
|
10.19‡
|
Alpha
Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan
(Amended and Restated on November 8, 2007) (Incorporated by reference to
Exhibit 10.18 to the Annual Report on Form 10-K of Alpha Natural
Resources, Inc. (File No. 001-32423) filed on February 29,
2008.)
|
||
|
10.20‡
|
Alpha
Natural Resources, Inc. 2005 Long-Term Incentive Plan (Restated as
of May 14, 2008.) (Incorporated by reference to Exhibit 10.1 to
the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No.
001-32423) filed on May 16,
2008.)
|
|
10-K
EXHIBIT INDEX - Continued
|
|||
|
Exhibit
No.
|
Description
of Exhibit
|
||
|
10.21‡
|
Form
of Alpha Natural Resources, Inc. Grantee Stock Option Agreement under the
Alpha Natural Resources, Inc. Amended and Restated 2004
Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.2
to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc.
(File No. 1-32423) filed on August 9, 2007.)
|
||
|
10.22‡
|
Form
of Alpha Natural Resources, Inc. Grantee Stock Option Agreement under the
2005 Long-Term Incentive Plan (Amended and Restated as of November 8,
2007) (Incorporated by reference to Exhibit 10.21 to the Annual Report on
Form 10-K of Alpha Natural Resources, Inc. (File No. 001-32423) filed on
February 29, 2008.)
|
||
|
10.23‡
|
Form
of Alpha Natural Resources, Inc. Restricted Stock Agreement for Alpha
Natural Resources, Inc. 2005 Long-Term Incentive Plan (for grants on or
prior to March 3, 2006) (Incorporated by reference to
Exhibit 4.7 to the Registration Statement on Form S-8 of Alpha
Natural Resources, Inc. (File No. 333-127528) filed on
August 15, 2005.)
|
||
|
10.24*‡
|
|||
|
10.25‡
|
Form
of Alpha Natural Resources, Inc. Restricted Stock Agreement under the
Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (For
Non-Employee Directors) (Restated as of November 8, 2007) (Incorporated by
reference to Exhibit 10.24 to the Annual Report on Form 10-K of Alpha
Natural Resources, Inc. (File No. 001-32423) filed on February 29,
2008.)
|
||
|
10.26*‡
|
|||
|
10.27†
|
Coal
Mining Lease dated April 9, 2003, effective as of April 1, 2003,
by and between CSTL LLC (subsequently renamed ACIN LLC) and Alpha Land and
Reserves, LLC, as amended (the “ACIN Lease”) (Incorporated by reference to
Exhibit 10.12 to Amendment No. 1 to the Registration Statement
on Form S-1 of Alpha Natural Resources, Inc. (File
No. 333-121002) filed on January 12, 2005.)
|
||
|
10.28
|
Two
Partial Surrender Agreements and Fourth Amendment to Coal Mining Lease,
each dated September 1, 2005, by and between ACIN LLC and Alpha Land
and Reserves, LLC, amending the ACIN Lease (Incorporated by reference to
Exhibit 10.17 to the Annual Report on Form 10-K of Alpha Natural
Resources, Inc. (File No. 1-32423) filed on March 28,
2006.)
|
||
|
10.29
|
Partial
Surrender Agreement dated November 1, 2005, by and between ACIN LLC
and Alpha Land and Reserves, LLC, amending the ACIN Lease (Incorporated by
reference to Exhibit 10.18 to the Annual Report on Form 10-K of Alpha
Natural Resources, Inc. (File No. 1-32423) filed on March 28,
2006.)
|
||
|
10.30
|
Amendment
to Coal Mining Lease dated January 1, 2006, by and between ACIN LLC and
Alpha Land and Reserves, LLC, amending the ACIN Lease (Incorporated by
reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q of Alpha
Natural Resources, Inc. (File No. 1-32423) filed on May 12,
2006.)
|
|
10.31
|
Agreement
dated February 17, 2006, between ACIN LLC and Alpha Land and Reserves, LLC
and Virginia Electric and Power Company for mutual interests as to
parties’ rights and obligations with regard to certain land (Incorporated
by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Alpha
Natural Resources, Inc. (File No. 1-32423) filed on May 12,
2006.)
|
||
|
10.32‡
|
Performance
period and payout methodology for performance share award grants during
2006 under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan
as reported on Alpha Natural Resources, Inc.’s Current Report on
Form 8-K filed on March 9, 2006 and incorporated by this
reference.
|
|
10-K
EXHIBIT INDEX - Continued
|
|||
|
Exhibit
No.
|
Description
of Exhibit
|
||
|
10.33*‡
|
|||
|
10.34‡
|
Performance
goals and target bonuses set for 2005 under the AIB Plan for Alpha Natural
Resources, Inc.’s executive officers as reported on Alpha Natural
Resources, Inc.’s Current Report on Form 8-K filed on April 27, 2005
and incorporated by this reference.
|
||
|
10.35‡
|
Summary
of Retention Compensation Plan approved for certain executive officers of
Alpha Natural Resources, Inc. (Incorporated by reference to
Exhibit 10.27 to the Registration Statement on Form S-1 of Alpha
Natural Resources, Inc. (File No. 333-129030) filed on
December 2, 2005.)
|
||
|
10.36‡
|
Plan
Document and Summary Plan Description of the Alpha Natural Resources, Inc.
Key Employee Separation Plan (As Amended and Restated Effective November
20, 2007) (Incorporated by reference to Exhibit 10.35 to the Annual Report
on Form 10-K of Alpha Natural Resources, Inc. (File No. 001-32423) filed
on February 29, 2008.)
|
||
|
10.37*‡
|
|||
|
10.38*‡
|
|||
|
10.39‡
|
Letter
of Agreement with Michael D. Brown dated May 23, 2007 (Incorporated by
reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q of Alpha
Natural Resources, Inc. (File No. 1-32423) filed on August 9,
2007.)
|
||
|
10.40*‡
|
|||
|
10.41*‡
|
|||
|
12.1*
|
|||
|
12.2*
|
|||
|
21.1*
|
|||
|
23*
|
|||
|
31(a)*
|
|||
|
31(b)*
|
|||
|
32(a)*
|
|||
|
32(b)*
|
|
*
|
Filed
herewith.
|
|
†
|
Confidential
treatment has been granted with respect to portions of the exhibit.
Confidential portions have been omitted from this public filing and have
been filed separately with the Securities and Exchange
Commission.
|
|
‡
|
Management
contract or compensatory plan or
arrangement.
|