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,
2006
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OR
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o
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
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For
the transition period from
to
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Commission
File No. 1-32423
ALPHA
NATURAL RESOURCES, INC.
(Exact
name of registrant as specified in its charter)
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Delaware
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02-0733940
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(State
or other jurisdiction of incorporation or
organization)
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(I.R.S.
Employer Identification Number)
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One
Alpha Place, P.O. Box 2345, Abingdon,
Virginia
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24212
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(Address
of principal executive offices)
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(Zip
Code)
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Registrant’s
telephone number, including area code:
(276) 619-4410
Securities
registered pursuant to Section 12(b) of the Act:
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Title
of Each Class
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Name
of Each Exchange on Which Registered
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Common
stock, $0.01 par value
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New
York Stock Exchange
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Securities
registered pursuant to Section 12(g) of the Act:
None
Indicate
by check mark whether the registrant is a well-known seasoned issuer, as
defined
in Rule 405 of the Securities Act. Yes þ
No o
Indicate
by check mark if the registrant is not required to file reports pursuant
to
Section 13 or Section 15(d) of the Act.
Yes o
No þ
Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months, and (2) has been subject to such
filing requirements for the past 90 days. Yes þ
No o
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the
best of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. þ
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer (as defined in Exchange Act
Rule 12b-2).
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þ Large
accelerated filer
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o Accelerated
filer
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¨ Non-accelerated
filer
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Indicate
by check mark whether the registrant is a shell company (as defined in Exchange
Act Rule 12b-2). Yes o
No þ
The
aggregate market value of the Common Stock held by non-affiliates of the
registrant on June 30, 2006, was approximately $1,107,287,407 based on the
last sales price reported that date on the New York Stock Exchange of $19.62
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 1, 2007 —
65,543,546 shares.
DOCUMENTS
INCORPORATED BY REFERENCE
Part III
incorporates certain information by reference from the registrant’s definitive
proxy statement for the 2007 annual meeting of stockholders, which proxy
statement will be filed no later than 120 days after the close of the
registrant’s fiscal year ended December 31, 2006.
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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market
demand for coal, electricity and
steel;
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•
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future
economic or capital market
conditions;
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•
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weather
conditions or catastrophic weather-related
damage;
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•
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our
production capabilities;
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•
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the
consummation of financing, acquisition or disposition transactions
and the
effect thereof on our business;
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•
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our
ability to successfully integrate the operations we have acquired
with our
existing operations, as well as our ability to successfully integrate
operations we may acquire 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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our
relationships with, and other conditions affecting, our
customers;
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•
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timing
of changes in customer coal
inventories;
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•
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changes
in, renewal of and acquiring new long-term coal supply
arrangements;
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•
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inherent
risks of coal mining beyond our
control;
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•
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environmental
laws, including those directly affecting our coal mining and production,
and those affecting our customers’ coal
usage;
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•
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competition
in coal markets;
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•
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railroad,
barge, truck and other transportation performance and
costs;
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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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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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availability
of skilled employees and other employee workforce
factors;
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•
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regulatory
and court decisions;
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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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changes
in postretirement benefit
obligations;
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•
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our
liquidity, results of operations and financial
condition;
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•
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decline
in coal prices;
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•
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forward
sales and purchase contracts not accounted for as a
hedge;
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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;
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•
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disruption
in coal supplies; 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.
-2-
2006
ANNUAL REPORT ON FORM 10-K
TABLE
OF CONTENTS
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Page
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PART I
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Item 1.
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4 | |
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Item 1A.
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21 | |
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Item
1B.
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39 | |||
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Item 2.
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40 | |
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Item 3.
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44 | |
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Item 4.
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44 | |
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PART II
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Item 5.
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44 | |
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Item 6.
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45 | |
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Item 7.
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50 | |
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Item 7A.
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69 | |
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Item 8.
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71 | |
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Item 9.
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127 | |
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Item 9A.
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127 | |
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Item 9B.
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128 | |
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PART III
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Item 10.
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128 | ||
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Item 11.
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128 | ||
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Item 12.
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128 | ||
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Item 13.
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128 | ||
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Item 14.
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128 | ||
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PART IV
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Item 15.
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129 |
PART I
Overview
We
are a leading Appalachian coal supplier. We produce, process and sell steam
and
metallurgical coal from eight regional business units, which, as of February
1,
2007, are supported by 38 active underground mines,
27
active surface mines and 10 preparation plants located throughout Virginia,
West
Virginia, Kentucky, and Pennsylvania, as well as a road construction business
in
West Virginia that recovers coal. We are also actively involved in the purchase
and resale of coal mined by others, the majority of which we blend with coal
produced from our mines, allowing us to realize a higher overall margin for
the
blended product than we would be able to achieve selling these coals separately.
Steam
coal, which is primarily purchased by large utilities and industrial customers
as fuel for electricity generation, accounted for approximately 66% of our
2006
coal sales volume. The majority of our steam coal sales volume in 2006 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
34% of our 2006 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 sale will grow as demand for power and steel increases.
During
2006, we sold a total of 29.1 million tons of steam and metallurgical coal
and generated coal sales revenues of $1,687.6 million, EBITDA of
$279.4 million and net income of $128.2 million. We define and
reconcile EBITDA and explain its importance, in note 3 under “Selected
Financial Data.” Our coal sales during 2006 consisted of 24.7 million tons of
produced and processed coal, including 1.4 million tons purchased from
third parties and processed at our processing plants or loading facilities
prior
to resale, and 4.4 million tons of purchased coal that we resold without
processing. Approximately 68% of the purchased coal in 2006 was blended with
coal produced from our mines prior to resale. Approximately 35% of our sales
revenue in 2006 was derived from sales made outside the United States, primarily
in Canada, Italy, France, India, Brazil, and Turkey.
As
of
December 31, 2006, we owned or leased 548.6 million tons of proven and probable
coal reserves. Of our total proven and probable reserves, approximately 82%
are
low sulfur reserves, with approximately 57% having sulfur content below 1.0%.
Approximately 91% of our total proven and probable reserves have a high Btu
content which creates more energy per unit when burned compared to coals
with
lower Btu content. We believe that our total proven and probable reserves
will
support current production levels for more than 20 years.
As
discussed in Note 24 to our financial statements, we have one reportable
segment — Coal Operations — which consists of our coal extracting,
processing and marketing operations, as well as our purchased coal sales
function and certain other coal-related activities, including our recovery
of
coal incidental to our road construction operations. Our equipment and part
sales and equipment repairs operations, terminal services, coal analysis
services, leasing of mineral rights, and the non-coal recovery portion of
our road construction operations described below under “— Other
Operations” are not included in our Coal Operations segment.
History
In
2002, ANR Holdings, LLC (“ANR Holdings”) was formed by First Reserve
Fund IX, L.P. and ANR Fund IX Holdings, L.P. (referred to as the
“First Reserve Stockholders” or collectively with their affiliates, “First
Reserve”) and our management to serve as the top-tier holding company of the
Alpha Natural Resources organization. On February 11, 2005, Alpha Natural
Resources, Inc. succeeded to the business of ANR Holdings in a series of
transactions that we refer to collectively as the “Internal Restructuring,” and
on February 18, 2005, Alpha Natural Resources, Inc. completed an initial
public offering of its common stock. When we use the terms “Alpha,” “we,” “our,”
“the Company” and similar terms in this report, we mean (1) prior to our
Internal Restructuring, ANR Fund IX Holdings, L.P. and Alpha NR Holding,
Inc. (a subsidiary of First Reserve Fund IX, L.P. prior to our Internal
Restructuring) and subsidiaries on a combined basis and (2) after our
Internal Restructuring, Alpha Natural Resources, Inc. and its consolidated
subsidiaries. Alpha Natural Resources, Inc. was formed under the laws of
the
State of Delaware on November 29, 2004.
On
December 13, 2002, the First Reserve Stockholders, who then owned 100% of
the membership interests of ANR Holdings, acquired the majority of the Virginia
coal operations of Pittston Coal Company (our “Predecessor”), a subsidiary of
the Brink’s Company (formerly known as The Pittston Company), through
wholly-owned subsidiaries of ANR Holdings for $62.9 million.
On
January 31, 2003, wholly owned subsidiaries of ANR Holdings acquired
Coastal Coal Company, LLC for $67.8 million, and on March 11, 2003,
ANR Holdings and its subsidiaries acquired the U.S. coal production and
marketing operations of American Metals and Coal International, Inc. (“AMCI”)
for $121.3 million. Of the consideration for the U.S. AMCI
acquisition, $69.0 million was provided in the form of an approximate 44%
membership interest in ANR Holdings issued to the owners of AMCI, which together
with the issuances of an approximate 1% membership interest to Madison Capital
Funding, LLC and Alpha Coal Management reduced the First Reserve Stockholders
membership interest in ANR Holdings to approximately 55%.
On
November 17, 2003, we acquired the assets of Mears Enterprises, Inc.
(“Mears”) for $38.0 million.
On
April 1, 2004, we acquired substantially all of the assets of Moravian Run
Reclamation Co., Inc. for five thousand dollars in cash and the assumption
by us
of certain liabilities, including four active surface mines and two additional
surface mines under development, operating in close proximity to and serving
many of the same customers as our AMFIRE business unit located in
Pennsylvania.
On
May 10, 2004, we acquired a coal preparation plant and railroad loading
facility located in Portage, Pennsylvania and related equipment and coal
inventory from Cooney Bros. Coal Company for $2.5 million in cash and an
adjacent coal refuse disposal site from a Cooney family trust for
$0.3 million in cash.
On
October 13, 2004, our AMFIRE business unit entered into a coal mining lease
with Pristine Resources, Inc., a subsidiary of International Steel Group
Inc.,
for the right to deep mine a substantial area of the Upper Freeport Seam
in
Pennsylvania.
On
February 11, 2005, we succeeded to the business and became the indirect
parent entity of ANR Holdings in connection with the Internal Restructuring
and,
on February 18, 2005, we completed an initial public offering of our common
stock (the “IPO”).
On
April 14, 2005, we sold the assets of our Colorado mining subsidiary,
National King Coal LLC, and related trucking subsidiary, Gallup Transportation
and Transloading Company, LLC (collectively, “NKC”) to an unrelated third party
for cash in the amount of $4.4 million, plus an amount in cash equal to the
fair market value of NKC’s coal inventory, and the assumption by the buyer of
certain liabilities of NKC.
On
October 26, 2005, we acquired the Nicewonder Coal Group’s coal reserves and
operations in southern West Virginia and southwestern Virginia. The Nicewonder
acquisition consisted of the purchase of the outstanding capital stock of
White
Flame Energy, Inc., Twin Star Mining, Inc. and Nicewonder Contracting, Inc.,
the
equity interests of Powers Shop, LLC and Buchanan Energy, LLC and substantially
all of the assets of Mate Creek Energy of W. Va., Inc. and Virginia Energy
Company, and the business of Premium Energy, Inc. by merger. We paid an
aggregate purchase price of $328.2 million in the Nicewonder
acquisition. The operations we acquired from the Nicewonder Coal Group
constitute our eight business unit, Callaway Natural Resources.
On
May 1, 2006, we
acquired certain coal mining operations in eastern Kentucky from Progress
Fuels
Corp, a subsidiary of Progress Energy (Progress Acquisition) for $28.8 million,
including adjustments for working capital. The Progress Acquisition consisted
of
the purchase of the outstanding capital stock of Diamond May Coal Co. and
Progress Land Corp. and the assets of Kentucky May Coal Co., Inc. The operations
acquired are adjacent to our Enterprise business unit and have been integrated
with Enterprise.
On
December 28, 2006, we paid $3.3 million and were obligated to make an additional
contribution of $7.0 million in 2007 for a 94% ownership interest in Gallatin
Materials LLC (“Gallatin”), a lime manufacturing venture near Cincinnati, Ohio.
Gallatin plans to construct two rotary pre-heater lime kilns over the next
several years to produce lime to be sold primarily to coal-burning utilities
as
a scrubbing agent for removing sulfur dioxide from flue gas, helping them
to
meet increasingly stringent air quality standards under the federal Clean
Air
Act. The lime will also be sold to steel producers for use as flux in electric
arc and basic oxygen furnaces. The minority owners were granted restricted
member interests in Gallatin, which vest based on performance criteria
approximately three years from the closing date and which, if earned in their
entirety, would reduce our ownership to 77.5%. We are committed to providing
financing through a $3.8 million loan and a $2.6 million letter of credit
to
cover project cost overruns.
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 2006,
approximately 58% 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 are used to transport coal 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, as much coal as is feasible 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 seam recovery ranges from 35% to 70%, with higher
seam
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 2006, approximately
42% 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,
rubber-tired diesel loaders. Seam 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. All of our coal is bituminous coal, a “soft” black coal with
a heat content that ranges from 9,500 to 15,000 Btus per pound. This coal
is
located primarily in Appalachia, Arizona, the Midwest, Colorado and Utah
and is
the type most commonly used for electric power generation in the United States.
Bituminous coal is also used for metallurgical and industrial steam purposes.
Of
our estimated 548.6 million tons of proven and probable reserves,
approximately 91% has a heat content above 12,500 Btus per pound.
Sulfur
Content.
Sulfur
content can vary from seam to seam and sometimes within each seam. When coal
is
burned, it produces sulfur dioxide, the amount of which varies depending
on the
chemical composition and the concentration of sulfur in the coal. Low sulfur
coals are coals which have a sulfur content of 1.5% or less. Demand for low
sulfur coal has increased, and is expected to continue to increase, as
generators of electricity strive to reduce sulfur dioxide emissions to comply
with increasingly stringent emission standards in environmental laws and
regulations. Approximately 82% of our proven and probable reserves are low
sulfur coal.
High
sulfur coal can be burned in plants equipped with sulfur-reduction technology,
such as scrubbers, which can reduce sulfur dioxide emissions by 50% to 90%.
Plants without scrubbers can burn high sulfur coal by blending it with lower
sulfur coal or by purchasing emission allowances on the open market, allowing
the user to emit a predetermined amount of sulfur dioxide. Some older coal-fired
plants have been retrofitted with scrubbers, although most have shifted to
lower
sulfur coals as their principal strategy for complying with Phase II of the
Clean Air Act’s Acid Rain regulations. We expect that any new coal-fired
generation plant built in the United States will use clean coal-burning
technology.
Ash &
Moisture Content.
Ash is
the inorganic residue remaining after the combustion of coal. As with sulfur
content, ash content varies from seam to seam. Ash content is an important
characteristic of coal because electric generating plants must handle and
dispose of ash following combustion. The absence of ash is also important
to the
process by which metallurgical coal is transformed into coke for use in steel
production. Moisture content of coal varies by the type of coal, the region
where it is mined and the location of coal within a seam. In general, high
moisture content decreases the heat value and increases the weight of the
coal,
thereby making it more expensive to transport. Moisture content in coal,
as
sold, can range from approximately 5% to 30% of the coal’s weight.
Coking
Characteristics.
The
coking characteristics of metallurgical coal are typically measured by the
coal’s fluidity, ARNU and volatility. Fluidity and ARNU tests measure the
expansion and contraction of coal when it is heated under laboratory conditions
to determine the strength of coke that could be produced from a given coal.
Typically, higher numbers on these tests indicate higher coke strength.
Volatility refers to the loss in mass, less moisture, when coal is heated
in the
absence of air. The volatility of metallurgical coal determines the percentage
of feed coal that actually becomes coke, known as coke yield. Coal with a
lower
volatility produces a higher coke yield and is more highly valued than coal
with
a higher volatility, all other metallurgical characteristics being
equal.
Mining
Operations
We
currently have eight regional business units, including two in Virginia,
four
predominately in West Virginia, one in Pennsylvania, and one in Kentucky.
As of
February 1,
2007, these business units include 10 preparation plants, each of which receive,
blend, process and ship coal that is produced from one or more of our 65
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, 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 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
2006, 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 February 1, 2007:
Regional
Business Units
|
Number
and Type of
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||||||||||||||||||||||
|
Mines
as of
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||||||||||||||||||||||
|
February1,
2007
|
2006
|
|||||||||||||||||||||
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Preparation
plant(s) as of
|
Under-
|
Production
of Saleable Tons
|
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Regional
Business Unit
|
Location
|
February
1, 2007
|
ground
|
Surface
|
Total
|
Railroad
|
(in
000’s)(1)
|
|||||||||||||||
|
Paramont
|
Virginia | Toms Creek |
8
|
6
|
14
|
NS
|
5,640
|
|||||||||||||||
|
Dickenson-Russell
|
Virginia | McClure River and Moss#3 |
6
|
1
|
7
|
CSX,
NS
|
2,140
|
|||||||||||||||
|
Kingwood
|
West Virginia | Whitetail |
1
|
0
|
1
|
CSX
|
1,414
|
|||||||||||||||
|
Brooks
Run
|
West Virginia | Erbacon |
3
|
1
|
4
|
CSX
|
2,749
|
|||||||||||||||
|
Welch
|
West Virginia | Litwar and Kepler |
12
|
0
|
12
|
NS
|
2,998
|
|||||||||||||||
|
AMFIRE
|
Pennsylvania | Clymer and Portage |
5
|
13
|
18
|
NS
|
3,398
|
|||||||||||||||
|
Enterprise
|
Kentucky | Roxana |
3
|
3
|
6
|
CSX
|
2,554
|
|||||||||||||||
|
Callaway
|
West Virginia/ Virginia |
0
|
3
|
3
|
NS
|
3,934 | ||||||||||||||||
|
|
Total |
38
|
27
|
65
|
24,827 | |||||||||||||||||
|
(1)
|
Includes
coal purchased from third-party producers that was processed at
our
subsidiaries’ preparation plants in 2006.
|
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.
The
following provides a brief description of our business units as of February
1,
2007
Paramont.
Our
Paramont business unit produces coal from eight 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 2006, Paramont purchased
approximately 208,000 tons of coal from third parties that was blended with
Paramont’s coal and shipped to our customers. As of February 1, 2007, the
Paramont business unit was operating at a capacity to ship approximately
five
and one half million tons per year.
Dickenson-Russell.
Our
Dickenson-Russell business unit produces coal from 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
underground mines is transported by truck to the McClure River or Moss #3
preparation plants operated by Dickenson-Russell or the Toms Creek preparation
plant operated by Paramont where it is cleaned, blended and loaded on rail
or
truck for shipment to customers. The Dickenson-Russell business unit also
operates a fine coal recovery dredge operation where fine coals that were
previously discarded by the coal cleaning process are recovered, cleaned,
and
blended with other coals for sale. During 2006, Dickenson-Russell purchased
approximately 137,000 tons of coal from third parties that was blended with
Dickenson-Russell’s coal and shipped to our customers. As of February 1, 2007,
the Dickenson-Russell business unit was operating at a capacity to ship
approximately two million tons per year.
Kingwood.
Our
Kingwood business unit produces coal from one underground mine using continuous
miners and the room and pillar mining method. The Kingwood operation is staffed
and operated by Kingwood employees. The coal is belted to the Whitetail
preparation plant operated by Kingwood where it is cleaned and loaded onto
rail
or truck for shipment to customers. The Kingwood business unit has no surface
mining operations. During 2006, Kingwood purchased approximately 37,000 tons
of
coal from third parties that was blended with Kingwood’s coal and shipped to our
customers. As of February 1, 2007, the Kingwood business unit was operating
at a
capacity to ship approximately one and one-half million tons per year.
Brooks
Run.
Our
Brooks Run business unit produces coal from three underground mines using
continuous miners and the room and pillar mining method. All of the mining
operations at the Brooks Run business unit are staffed and operated by Brooks
Run employees. The coal is transported by truck to the Erbacon preparation
plant
operated by Brooks Run where it is cleaned, blended and loaded onto rail
for
shipment to customers. The Brooks Run business unit has one surface mine
operated by Brooks Run employees. Brooks Run purchased approximately 15,000
tons
of coal from third parties in 2006. As of February 1, 2007, the Brooks Run
business unit was operating at a capacity to ship approximately two million
tons
per year.
Welch.
Our
Welch business unit produces coal from twelve underground mines using continuous
miners and the room and pillar mining method. Three of the underground mines
are
operated by our employees, and the others are operated by independent
contractors. The coal is transported by truck or rail to the Litwar and Kepler
preparation plants operated by Welch where it is cleaned, blended and loaded
onto rail for shipment to customers. The Welch business unit has no active
surface mining operations as of February 1, 2007. During 2006, the Welch
business unit purchased approximately 868,000 tons of coal from third parties
that was blended with other coals and shipped to our customers. As of February
1, 2007, the Welch business unit was operating at a capacity to ship
approximately three and one-quarter million tons per year.
AMFIRE.
Our
AMFIRE business unit produces coal from five underground mines using continuous
miners and the room and pillar mining method. All of the underground mining
operations at AMFIRE are staffed and operated by AMFIRE employees. The
underground coal is delivered directly by truck to the customer, or to the
Clymer or Portage coal preparation plants or raw coal loading docks where
it is
cleaned, blended and loaded onto rail or truck for shipment to customers.
AMFIRE
also operates 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 rail or truck
for
shipment to customers. During 2006, AMFIRE purchased approximately 137,000
tons
of coal from third parties that was blended with AMFIRE’s coal and shipped to
our customers. As of February 1, 2007, the AMFIRE business unit was operating
at
a capacity to ship approximately three and one-quarter 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. Two of the underground
mining operations at Enterprise are staffed and operated by Enterprise
employees. The coal from these 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
three truck/loader surface mines, two of which are operated by independent
contractors. The coal produced by the surface mines 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 2006, Enterprise purchased
approximately 45,000 tons of coal from third parties that was blended with
Enterprise’s coal and shipped to our customers. As of February 1, 2007, the
Enterprise business unit was operating at a capacity to ship approximately
three
million tons per year. The Progress acquisition was included in the Enterprise
operations beginning May 2006.
Callaway.
Our
Callaway business unit produces coal from three surface mining operations
operated by our Callaway employees and also recovers coal from the road
construction business operated by our subsidiary Nicewonder Contracting,
Inc.
(NCI). Coal from our White Flame Surface mine and the coal recovered by
NCI is trucked to our Mate Creek load-out facility where it is blended and
loaded onto rail for shipment to customers. Coal from the Premium Energy
Surface
mine and highwall miner is currently trucked to Arch Coal, Inc’s Mingo Logan
mining complex, where a portion of the coal is sold to Arch Coal Inc. with
the
remaining tons to various other customers. Coal from the Twin Star surface
mine
is trucked to our Virginia Energy load-out facility where it is loaded onto
rail
cars for transport to customers. The Callaway business unit has no active
underground operations and did not purchase any coal from third parties during
2006. As of February 1, 2007, the Callaway business unit was operating at
a
capacity to ship approximately four million tons per year, including coal
recovered by NCI as part of its road construction business.
Marketing,
Sales and Customer Contracts
Our
marketing and sales force, which is principally based in Latrobe, Pennsylvania,
included 35
employees as of December 31, 2006, and consists of sales managers,
distribution/traffic managers and administrative personnel. In addition to
selling coal produced in our eight regional business units, we are also actively
involved in the purchase and resale of coal mined by others, the majority
of
which we blend with coal produced from our mines. We have coal supply
commitments with a wide range of electric utilities, steel manufacturers,
industrial customers and energy traders and brokers. Our overall sales
philosophy is to focus first on the customer’s individual needs and
specifications, as opposed to simply selling our production inventory. By
offering coal of both steam and metallurgical grades blended 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 who have been customers
of ours or our Predecessor and acquired companies for decades.
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, 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
1.4 million tons of our 2006 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 26.7 million tons
of coal
in 2005, consisting of 20.6 million tons of produced and processed coal and
6.1
million tons of purchased coal that we resold without processing. Of our
total
purchased coal sales of 7.6 million tons in 2005, approximately 5.0 million
tons
were blended prior to resale. Approximately 1.5 million tons of our 2005
purchased coal sales were processed by us. We sold a total of 25.3 million
tons
of coal in 2004, consisting of 18.9 million tons of produced and processed
coal
and 6.4 million tons of purchased coal that we resold without processing.
Of our
total purchased coal sales of 7.3 million tons in 2004, approximately 5.9
million tons were processed prior to resale. The breakdown of tons sold by
market served for 2006, 2005 and 2004 is set forth in the table
below:
|
Steam
Coal Sales(1)
|
Metallurgical
Coal Sales
|
||||||||||||
|
Year
|
Tons
|
%
of Total Sales
|
Tons
|
%
of Total Sales
|
|||||||||
|
(In
millions, except percentages)
|
|||||||||||||
|
2006
|
19.1
|
66
|
%
|
10.0
|
34
|
%
|
|||||||
|
2005
|
16.7
|
62
|
%
|
10.0
|
38
|
%
|
|||||||
|
2004
|
15.8
|
63
|
%
|
9.5
|
37
|
%
|
|||||||
|
(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 4%, 3% and 4% of total sales in 2006, 2005 and
2004,
respectively.
|
|
(2)
|
Our
sales of steam coal during 2006 and 2005 were made primarily to
large
utilities and industrial customers in the Eastern region of the
United
States, and our sales of metallurgical coal during those years
were made
primarily to steel companies in the Northeastern and Midwestern
regions of
the United States and in several countries in Europe, Asia and
South
America.
|
We
sold
coal to over 118 different customers in 2006. Our top ten customers in 2006
accounted for approximately 38% of 2006 revenues and our largest customer
during
2006 accounted for approximately 7% of 2006 revenues. The following table
provides information regarding our exports (including to Canada) in 2006,
2005
and 2004 by revenues and tons sold:
|
Year
|
Export
Tons Sold
|
Export
Tons Sold as a Percentage of Total Coal Sales
|
Export
Sale Revenues (1)
|
Export
Sales Revenue as a Percentage of Total Revenues
|
|||||||||
|
(In
millions, except percentages)
|
|||||||||||||
|
2006
|
7.2
|
25
|
%
|
$
|
668.8
|
35
|
%
|
||||||
|
2005
|
8.4
|
31
|
%
|
$
|
737.1
|
45
|
%
|
||||||
|
2004
|
8.1
|
32
|
%
|
$
|
597.9
|
48
|
%
|
||||||
| (1) |
Export
sale revenues in 2006 and 2005 include approximately $0.7 million
and $0.6
million, respectively, in equipment export sales. All other export
sale
revenues are coal sales revenues and freight and handling
revenues.
|
Our
export shipments during 2006, 2005 and 2004 serviced customers in 18, 16
and 18
countries, respectively, across North America, Europe, South America, Asia
and
Africa. Canada was our largest export market in 2006,
with
sales to Canada accounting for approximately 17% of export revenues and 6%
of
total revenues. Canada was our largest export market in 2005 accounting for
approximately 15% of export revenues and approximately 7% of total revenues,
while Japan was our largest export market in 2004, with sales to Japan
accounting for approximately 23% of export revenues and approximately 11%
of
total revenues. All of our sales are made in U.S. dollars, which reduces
foreign
currency risk. A portion of our sales are subject to seasonal fluctuation,
with
sales to certain customers being curtailed during the winter months due to
the
freezing of lakes that we use to transport coal to those customers.
As
is customary in the coal industry, when market conditions are appropriate
and
particularly in the steam coal market, we enter into long-term contracts
(exceeding one year in duration) with many of our customers. These arrangements
allow customers to secure a supply for their future needs and provide us
with
greater predictability of sales volume and sales prices. A
significant majority of our steam coal sales are shipped under long-term
contracts. The majority of the metallurgical coal sales contracts we entered
into during 2004 and 2005 were long-term contracts. During 2006, approximately
63% and 45% of our steam and metallurgical coal sales volume, respectively,
was
delivered pursuant to long-term contracts and during 2005, approximately
86% and
75% of our steam and metallurgical coal sales volume, respectively, was
delivered pursuant to long-term contracts.
At
February 5, 2007, 83% of our planned 2007 production was committed and priced
and 7% was committed and unpriced, with approximately 2.0 million tons
uncommitted. Committed steam coal prices for 2007 average $48 to $49 per
ton and
committed metallurgical prices average $72 to $73 per ton. Approximately
43% of
our planned production in 2008 was committed at February 5, 2007. At December
31, 2006, we had commitments to purchase 2.4 million tons of coal during
2007.
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
ten preparation plants and in certain cases directly from our mines. The
coal we
purchased is loaded in some cases directly from mines and preparation plants
operated by third parties or from an export terminal. Virtually all of our
coal
is transported from the mine to our preparation plants by truck or rail,
and
then from the preparation plant to the customer by means of railroads, trucks,
barge lines and ocean-going vessels from terminal facilities. Rail shipments
constituted approximately 73% of total shipments of coal volume produced
and
processed coal from our mines to the preparation plant to the customer in
2006.
The balance was shipped from our preparation plants, loadout facilities or
mines
via truck. In 2006, approximately 8% of our coal sales were ultimately delivered
to customers through transport on the Great Lakes, approximately 12% was
moved
through the Norfolk Southern export facility at Norfolk, Virginia, approximately
4% was moved through the coal export terminal at Newport News, Virginia operated
by Dominion Terminal Associates, 2% was moved through the export terminal
at
Baltimore, Maryland, and approximately 1% was moved through an export terminal
at New Orleans, LA. We own a 32.5%
interest in the coal export terminal at Newport News, Virginia operated by
Dominion Terminal Associates. See “— Other Operations.”
Competition
With
respect to our U.S. customers, we compete with numerous coal producers in
the Appalachian region and with a large number of western coal producers
in the
markets that we serve. Competition from coal with lower production costs
shipped
east from western coal mines has resulted in increased competition for coal
sales in the Appalachian region. We face limited competition from imports
for
our domestic customers. In 2006, only 3% of total U.S. coal consumption was
imported. Excess industry capacity, which has occurred in the past, tends
to
result in reduced prices for our coal. The most important factors on which
we
compete are delivered coal price, coal quality and characteristics,
transportation costs from the mine to the customer and the reliability of
supply. Demand for coal and the prices that we will be able to obtain for
our
coal are closely linked to coal consumption patterns of the domestic electric
generation industry, which has accounted for approximately 92% of domestic
coal
consumption over the last five years. These coal consumption patterns are
influenced by factors beyond our control, including the demand for electricity,
which is significantly dependent upon summer and winter temperatures in the
United States, environmental and other government regulations, technological
developments and the location, availability, quality and price of competing
fuels for power such as natural gas, nuclear, fuel oil and alternative energy
sources such as hydroelectric power. Demand for our low sulfur coal and the
prices that we will be able to obtain for it will also be affected by the
price
and availability of high sulfur coal, which can be marketed in tandem with
emissions allowances in order to meet Clean Air Act requirements.
Demand
for our metallurgical coal and the prices that we will be able to obtain
for
metallurgical coal will depend to a large extent on the demand for U.S. and
international steel, which is influenced by factors beyond our control,
including overall economic activity and the availability and relative cost
of
substitute materials. In the export metallurgical market, during 2006 and
2005,
we largely competed with producers from Australia, Canada, and other
international producers of metallurgical coal.
Our
business is seasonal, with operating results varying from quarter to quarter.
We
generally experience lower sales and hence build coal inventory during the
winter months primarily due to the freezing of lakes that we use to transport
coal to some of our customers.
In
addition to competition for coal sales in the United States and internationally,
we compete with other coal producers, particularly in the Appalachian region,
for the services of experienced coal industry employees at all levels of
our
mining operations.
Other
Operations
We
have
other operations and activities in addition to our normal coal production,
processing and sales business, including:
Road
Construction Business. NCI
operates a road construction business under a contract with the State of
West
Virginia Department of Transportation. Pursuant to the contract, NCI is building
approximately 11 miles of rough grade road in West Virginia over the next
four
to five 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.
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 $34.9 million for 2006, of which
approximately 86% was generated by services provided to our other subsidiaries
and approximately 14% was generated by sales to external customers, including
$0.7 million to export customers.
Dominion
Terminal Associates.
Through
our subsidiary Alpha Terminal Company, LLC, we hold a 32.5% interest in Dominion
Terminal Associates, a 22 million-ton annual capacity coal export terminal
located in Newport News, Virginia. The terminal, constructed in 1982, provides
the advantages of state of the art unloading/transloading equipment with
ground
storage capability, providing producers with the ability to custom blend
export
products without disrupting mining operations. During 2006, we shipped a
total
of 1.2 million tons of coal to our customers through the terminal. We make
periodic cash payments in respect of the terminal for operating expenses,
which
are partially offset by payments we receive for transportation incentive
payments and for renting our unused storage space in the terminal to third
parties. Our cash payments for expenses for the terminal in 2006 were
$4.9 million, partially offset by payments received in 2006 of
$1.7 million. The terminal is held in a partnership with subsidiaries of
three other companies, Dominion Energy (20%), Arch Coal (17.5%) and Peabody
Energy (30%). We and our other interested partners are currently pursuing
an
investment of approximately $35.0 million for the construction of a new
coal import facility at the terminal. Engineering and permitting work on
the
project has been completed. Construction could begin in the second half of
2007.
Gallatin
Materials LLC.
On
December 28, 2006, the Company paid $3.3 million and we are obligated to
make an
additional contribution of $7.0 million in 2007 for a 94% ownership interest
in
Gallatin Materials LLC (Gallatin), a lime manufacturing venture near Cincinnati,
Ohio. Gallatin plans to construct two rotary pre-heater lime kilns to produce
lime to be sold primarily to coal-burning utilities as a scrubbing agent
for
removing sulfur dioxide from flue gas. The lime will also be sold to steel
producers for use as flux in electric arc and basic oxygen
furnaces.
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
94% of our coal production in 2006 came from mines operated by union-free
employees, and as of December 31, 2006, over 92% of 3,546 employees were
union-free. We believe our employee relations are good, and there have been
no
material work stoppages at any of our properties in the past ten years.
Environmental
and Other Regulatory Matters
Federal,
state and local authorities regulate the U.S. coal mining industry with
respect to matters such as employee health and safety, permitting and licensing
requirements, air quality standards, water pollution, plant and wildlife
protection, the reclamation and restoration of mining properties after mining
has been completed, the discharge of materials into the environment, surface
subsidence from underground mining, and the effects of mining on groundwater
quality and availability. These regulations and legislation have had, and
will
continue to have, a significant effect on our production costs and our
competitive position. Future legislation, regulations or orders, as well
as
future interpretations and more rigorous enforcement of existing laws,
regulations or orders, may require substantial increases in equipment and
operating costs to us and delays, interruptions, or a termination of operations,
the extent of which we cannot predict. We intend to respond to these regulatory
requirements at the appropriate time by implementing necessary modifications
to
facilities or operating procedures. Future legislation, regulations or orders
may also cause coal to become a less attractive fuel source, thereby reducing
coal’s share of the market for fuels used to generate electricity. As a result,
future legislation, regulations or orders may adversely affect our mining
operations, cost structure or the ability of our customers to use coal.
We
endeavor 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, violations occur from time to
time.
None of the violations or the monetary penalties assessed upon us since our
inception in 2002 has been material. Nonetheless, we expect that future
liability under or compliance with environmental 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, may be imposed under the laws described below.
Monetary sanctions and, in severe circumstances, criminal sanctions may be
imposed for failure to comply with these laws.
As
of December 31, 2006, we had accrued $77.3 million for reclamation
liabilities and mine closures, including $7.8 million of current
liabilities.
Mining
Permits and Approvals.
Numerous
governmental permits or approvals are required for mining operations. When
we
apply for these permits and approvals, we may be required to present data
to
federal, state or local authorities pertaining to the effect or impact that
any
proposed production or processing of coal may have upon the environment.
The
authorization, permitting and/or implementation requirements imposed by any
of
these authorities may be costly and time consuming and may delay commencement
or
continuation of mining operations. Regulations also provide that a mining
permit
or modification can be delayed, refused or revoked if an officer, director
or a
stockholder with a 10% or greater interest in the entity is affiliated with
or
is in a position to control another entity that has outstanding permit
violations. Thus, past or ongoing violations of federal and state mining
laws
could provide a basis to revoke existing permits and to deny the issuance
of
additional permits.
In
order
to obtain mining permits and approvals from state regulatory authorities,
mine
operators, including us, must submit a reclamation plan for restoring, upon
the
completion of mining operations, the mined property to its prior or better
condition, productive use or other permitted condition. Typically, we submit
our
necessary permit applications several months, or even years, before we plan
to
begin mining a new area. Although permits may take six months or longer to
obtain, in the past we have generally obtained our mining permits without
significant delay. However, we cannot be sure that we will not experience
difficulty in obtaining mining permits in the future.
Surface
Mining Control and Reclamation Act.
The
Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is
administered by the Office of Surface Mining Reclamation and Enforcement
(“OSM”), establishes mining, environmental protection and reclamation standards
for all aspects of surface mining as well as many aspects of deep mining.
Mine
operators must obtain SMCRA permits and permit renewals from the OSM, or
from
the applicable state agency if the state agency has obtained primacy. A state
agency may achieve primacy if the state regulatory agency develops a mining
regulatory program that is no less stringent than the federal mining regulatory
program under SMCRA. States in which we have active mining operations have
achieved primacy and a state agency is the regulatory authority for SMCRA
permitting and enforcement activities.
SMCRA
permit provisions include a complex set of requirements which include, but
are
not limited to: 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; and re-vegetation.
The
mining permit application process is initiated by collecting baseline data
to
adequately characterize the pre-mine environmental condition of the permit
area.
This work includes, but is not limited to, surveys and/or assessments of
the
following: cultural and historical resources; geology, including soils; existing
vegetation; benthics; wildlife; potential for endangered species; surface
and
ground water hydrology; climatology; streams; and wetlands. The geologic
data is
used to define and model the soil and rock structures that will be encountered
during the mining process. The geologic data and data from the other surveys
and/or assessments are used to develop the mining and reclamation plans
presented in the permit application. The mining and reclamation plans
incorporate the provisions and performance standards of the state’s equivalent
SMCRA regulatory program, and are also used to support applications for other
authorizations and/or permits required to conduct coal mining activities.
Also
included in the permit application is information used for documenting surface
and mineral ownership, variance requests, access roads, bonding information,
mining methods, mining phases, other agreements that may relate to coal,
other
minerals, oil and gas rights, water rights, permitted areas, and ownership
and
control information required to determine compliance with OSM’s Applicant
Violator System, including the mining and compliance history of officers,
directors and principal owners of the entity.
Once
a permit application is prepared and submitted to the regulatory agency,
it goes
through an administrative completeness review and a thorough technical review.
Also, before a SMCRA permit is issued, a mine operator must submit a bond
or
otherwise secure the performance of all reclamation obligations. After the
application is submitted, a public notice or advertisement of the proposed
permit is required to be given, which begins a notice period that is followed
by
a public comment period before a permit can be issued. It is not uncommon
for a
SMCRA mine permit application to take over a year to prepare, depending on
the
size and complexity of the mine, and anywhere from six months to two years
or
even longer for the permit to be issued. The variability in time frame required
to prepare the permit and issue the permit can be attributed primarily to
the
various regulatory authorities’ discretion in the handling of comments and
objections relating to the project received from the general public and other
agencies. Also, it is not uncommon for a permit to be delayed as a result
of
litigation related to the specific permit or another related company’s
permit.
In
addition to the bond requirement for an active or proposed permit, the Abandoned
Mine Land Fund, which was created by SMCRA, requires a fee on all coal
produced.
The
current fee is $0.35 per ton on surface-mined coal and $0.15 per ton
on deep-mined coal, but tax rate revisions were recently approved and will
decrease to $0.315 per surface-mined ton and $0.135 per deep-mined ton in
October 2007. Further reductions will occur in October 2012. The main purpose
of
the fee proceeds is to fund the reclamation of mine lands closed or abandoned
prior to SMCRA’s adoption in 1977. In 2006, we recorded $5.0 million of
expense related to this reclamation tax.
SMCRA
stipulates 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”).
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. Although surety bonds are usually noncancelable during their
term,
many of these bonds are renewable on a yearly basis. The costs of these bonds
have increased in recent years while the market terms of surety bonds have
generally become more unfavorable to mine operators. These changes in the
terms
of the bonds have been accompanied by a decrease in recent years in the number
of companies willing to issue surety bonds. 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. During the fourth quarter
of 2006, we also entered into a committed bonding facility with the Chubb
Group
of Insurance Companies. Chubb has agreed, subject to certain conditions,
to
issue surety bonds on our behalf in a maximum amount of $50.0 million. As
of
December 31, 2006, we have posted an aggregate of $138.0 million in
reclamation bonds and $10.4 million of other types of bonds under these
facilities.
Clean
Air Act.
The
Clean Air Act and comparable state laws that regulate air emissions affect
coal
mining operations both directly and indirectly. Direct impacts on coal mining
and processing operations include Clean Air Act permitting requirements and/or
emission control requirements relating to particulate matter which may include
controlling fugitive dust. The Clean Air Act indirectly affects coal mining
operations by extensively regulating the emissions of fine particulate matter
measuring 2.5 micrometers in diameter or smaller, sulfur dioxide, nitrogen
oxides, mercury and other compounds emitted by coal-fired electricity generating
plants. Continued tightening of the already stringent regulation of emissions
from coal-fired power plants could eventually reduce the demand for
coal.
Clean
Air
Act requirements that may directly or indirectly affect our operations include
the following:
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Acid
Rain.
Title IV of the Clean Air Act 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. Although
we
cannot accurately predict the future effect of this Clean Air Act
provision on our operations, we believe that implementation of
Phase II has resulted in, and will continue to result in, an upward
pressure on the price of lower sulfur coals, as coal-fired power
plants
continue to comply with the more stringent restrictions of
Title IV.
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Fine
Particulate Matter.
The Clean Air Act requires the U.S. Environmental Protection Agency
(the “EPA”) to set standards, referred to as National Ambient Air Quality
Standards (“NAAQS”), for certain pollutants. Areas that are not in
compliance (referred to as “non-attainment areas”) with these standards
must take steps to reduce emissions levels. For example, NAAQS
currently
exist for particulate matter with an aerodynamic diameter less
than or
equal to 10 microns, or PM10, and for fine particulate matter with
an
aerodynamic diameter less than or equal 2.5 microns, or PM2.5.
The EPA
designated all or part of 225 counties in 20 states as well as the
District of Columbia as non-attainment areas with respect to the
PM2.5
NAAQS. 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.
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.
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Ozone.
Significant additional emissions control expenditures will be required
at
coal-fired power plants to meet the current NAAQS for ozone. Nitrogen
oxides, which are a by-product of coal combustion, are classified
as an
ozone precursor. Accordingly, emissions control requirements for
new and
expanded coal-fired power plants and industrial boilers will continue
to
become more demanding in the years ahead. For example, in November
2005,
EPA issued a final rule, called the Phase 2 Ozone Rule, describing
the action that states must take to reduce ground level ozone.
The EPA
designated counties in 32 states as non-attainment areas under the
new standard. These states will have until June 2007 to develop
plans,
referred to as state implementation plans or SIPs, for pollution
control
measures that allow them to comply with the
standards.
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NOx
SIP Call.
The NOx SIP Call program was established by the EPA in October
1998 to
reduce the transport of ozone on prevailing winds from the Midwest
and
South to states in the Northeast, which said they could not meet
federal
air quality standards because of migrating pollution. The program
is
designed to reduce nitrous oxide emissions by one million tons
per year in
22 eastern states and the District of Columbia. Installation of
additional
control measures, such as selective catalytic reduction devices,
required
under the final rules will make it more costly to operate coal-fired
electricity generating plants, thereby making coal a less attractive
fuel.
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Clean
Air Interstate Rule.
The EPA finalized the Clean Air Interstate Rule (CAIR) on
March 10, 2005. The new CAIR calls for power plants in 29 eastern
states and the District of Columbia to reduce emission levels of
sulfur
dioxide and nitrous oxide. The rule requires states to regulate
power
plants under a cap and trade program similar to the system now
in effect
for acid deposition control and to that proposed by the Clear Skies
Initiative. When fully implemented, this rule is expected to reduce
regional sulfur dioxide emissions by over 70% and nitrogen oxides
emissions by over 60% from 2003 levels. The stringency of the cap
may
require 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. Emissions
are
permanently capped and cannot increase. The rule is also subject
to
judicial challenge, which makes its impact difficult to
assess.
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Clean
Air Mercury Rule.
On March15, 2005, the EPA issued the Clean Air Mercury Rule to
permanently
cap and reduce mercury emissions from coal-fired power plants.
The Clean
Air Mercury Rule establishes mercury emissions limits from new
and
existing coal-fired power plants and creates a market-based cap-and-trade
program that is expected to reduce nationwide utility emissions
of mercury
in two phases. Stricter limitations on mercury emissions from power
plants
may adversely affect the demand for coal. In 2006, EPA proposed
a federal
plan to directly regulate mercury emissions from coal-fired power
plants
where certain states have not provided their own
plans.
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Carbon
Dioxide.
In February 2003, a number of states notified the EPA that they
planned to
sue the agency to force it to set new source performance standards
for
utility emissions of carbon dioxide and to tighten existing standards
for
sulfur dioxide and particulate matter for utility emissions. In
June 2003,
three of these states sued the EPA seeking a court order requiring
the EPA
to designate carbon dioxide as a criteria pollutant and to issue
a new
NAAQS for carbon dioxide. In February 2004, EPA entered into a
consent
decree with parties including the states that had given notice
of intent
to sue in 2003 to compel the Agency to set new source performance
standards. Under the consent decree, EPA promulgated final amendments
to
the new source performance standards for utility and industrial
boilers in
February 2006. In April 2006, ten states, the District of Columbia,
and
New York City petitioned the United States Court of Appeals for
the
District of Columbia Circuit for review of those new source performance
standards for utility and industrial boilers, claiming that the
EPA
improperly refused to regulate carbon dioxide as a criteria pollutant
and
that the standards for sulfur dioxide and nitrogen oxides are
insufficient. In June 2006, the United States Court of Appeals
heard oral
argument in a public nuisance action filed by eight states (Connecticut,
Delaware, Maine, New Hampshire, New Jersey, New York, and Vermont)
and New
York City to curb carbon dioxide emissions from power plants. In
November
2006, the United States Supreme Court heard oral argument in a
case that
commenced in June 2003 challenging the EPA’s refusal to regulate carbon
dioxide and other greenhouse gas emissions from new motor vehicles
on the
ground that it lacks the authority to list carbon dioxide as a
criteria
pollutant. If these lawsuits result in the issuance of a court
order
requiring the EPA to set emission limitations for carbon dioxide,
this in
turn could reduce the amount of coal our customers would purchase
from us.
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Regional
Emissions Trading.
In December 2005, seven Northeastern states (Connecticut, Delaware,
Maine,
New Hampshire, New Jersey, New York, and Vermont) signed the Regional
Greenhouse Gas Initiative (RGGI) Agreement, calling for a ten percent
reduction of carbon dioxide emissions by 2019, with compliance
to begin
January 1, 2009. Maryland signed onto RGGI in July 2006. The RGGI
final
model rule was issued on August 15, 2006, and participating states
are
developing their state rules. Climate change developments are also
taking
place on the west coast in California. In September 2006, California
adopted greenhouse gas legislation that prohibits long-term base-load
generation from having a greenhouse gas emissions rate greater
than that
of a combined cycle natural gas generator and that allows for long-term
deals with generators that sequester carbon emissions. In October
2006, a
trading partnership between California and the states participating
in
RGGI was announced. In December 2006, the California Public Utility
Commission proposed regulations proposing to set a 1,000 lb/MWh
carbon
dioxide emission standard. The California Public Utility Commission
is
expected to adopt final regulations implementing California’s greenhouse
gas legislation for investor-owned utilities in February 2007.
These and
other state climate change rules will likely require additional
controls
on coal-fired utilities and industrial boilers and may even cause
some
users of our coal to switch from coal to a lower carbon fuel. There
can be
no assurance at this time that a carbon dioxide cap and trade program,
if
implemented by the states where our customers operate, will not
affect the
future market for coal in this
region.
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Regional
Haze.
The EPA has initiated a regional haze program designed to protect
and to
improve visibility at and around national parks, national wilderness
areas
and international parks. Each state affected by this EPA program
must
develop and submit to EPA by mid-2007 a plan to achieve the goals
of the
program. The program may result in additional emissions restrictions
from
new coal-fired power plants whose operation may impair visibility
at and
around federally protected areas. Moreover, this program may require
certain existing coal-fired power plants to install additional
control
measures designed to limit haze-causing emissions, such as sulfur
dioxide,
nitrogen oxides, volatile organic chemicals and particulate matter.
These
limitations could affect the future market for
coal.
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Clean
Water Act.
The
Clean Water Act of 1972 (the “CWA”) and comparable state laws that regulate
waters of the United States (“Jurisdictional Waters”) can affect coal mining
operations both directly and indirectly. One of the direct impacts on coal
mining and processing operations is Clean Water Act permitting requirements
relating to the discharge of pollutants into Jurisdictional Waters. Indirect
impacts of the CWA include discharge limits placed on coal-fired power plant
ash
handling facilities’ discharges. Continued litigation of CWA issues could
eventually reduce the demand for coal.
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
Discharge Act.
Section 402 of the CWA establishes in-stream water quality criteria
and treatment standards for wastewater discharge through the National
Pollutant Discharge Elimination System (“NPDES”). Regular monitoring and
compliance with reporting requirements and performance standards
are
preconditions for the issuance and renewal of NPDES permits that
govern
the discharge of pollutants into water. The imposition of future
restrictions on the discharge of certain pollutants into waters
of the
United States could affect the permitting process, increase the
costs and
difficulty of obtaining and complying with NPDES permits and could
adversely affect our coal
production.
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Total
Maximum Daily Load (“TMDL”) regulations established a process by which states
designate stream segments as impaired (not meeting present water quality
standards). Industrial dischargers, including coal mines, will be required
to
meet new TMDL effluent standards for these stream segments. Some of our
operations currently discharge effluents into stream segments that have been
designated as impaired. 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.
Under
the CWA, states must conduct an anti-degradation review before approving
permits
for the discharge of pollutants to waters that have been designated as high
quality. A state’s anti-degradation regulations would prohibit the diminution of
water quality in these streams. In general, waters discharged from coal mines
to
high quality streams may be required to meet new “high quality” standards. This
could cause increases in the costs, time and difficulty associated with
obtaining and complying with NPDES permits, and could adversely affect our
coal
production.
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Dredge
and Fill Permits Act:
Many mining activities, such as the development of refuse impoundments,
fresh water impoundments, refuse fills, valley fills, and other
similar
structures, may result in impacts to Jurisdictional Waters. Jurisdictional
Waters typically include wetlands, streams (including intermittent
streams
and their tributaries) and may, in certain instances, include man-made
conveyances that have a hydrologic connection to such streams or
wetlands.
Prior to conducting such mining activities in jurisdictional waters,
coal
companies are required to obtain a Section 404 authorization (referred
to
as a dredge or fill permit) from the Army Corps of Engineers (“COE”). The
COE is authorized to issue two types of Section 404 permits: a
general
permit referred to as a nationwide permit, more specifically a
Nationwide
Permit 21 (“NWP 21”) for surface mining activities and an individual
permit. The COE may issue nationwide permits for any category of
activities involving the discharge of dredge or fill material if
the COE
determines that such activities are similar in nature and will
cause only
minimal adverse environmental effects individually or cumulatively.
Generally, the COE has used the NWP 21 to authorize impacts to
jurisdictional waters from mining activities because the NWP process
is a
more streamlined permitting approach and consumes less COE resources.
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The
use of the NWP 21 to authorize stream impacts from mining activities was
challenged in October 2003 in federal court in southern West Virginia. Although
the challenge was successful at the district court level, the challenge was
later overturned at the court of appeals. During the appeal period only,
the COE
was enjoined (only in the southern district of West Virginia) from using
the NWP
21 to authorize dredge and fill activities for mining impacts. A similar
challenge was filed in January 2005 prior to the court of appeals overturning
the West Virginia district court) in federal court in eastern Kentucky and
no
decision has been rendered. Although we had operations in both states subject
to
the litigation, our Section 404 permits were in place and no production
activities were interrupted. As a precaution to mitigate the uncertainty
surrounding the use of the NWP 21 in these areas, we converted certain ongoing
permits, pending applications, and planned applications from NWP 21 permits
to
individual permits. This precautionary step was taken to minimize the potential
for future production interruptions.
Mine
Safety and Health.
Stringent health and safety standards have been in effect since Congress
enacted
the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and
Health
Act of 1977 significantly expanded the enforcement of safety and health
standards and imposed safety and health standards on all aspects of mining
operations. In addition to federal regulatory programs, all of the states
in
which we operate also have state programs for mine safety and health regulation
and enforcement. Collectively, federal and state safety and health regulation
in
the coal mining industry is perhaps the most comprehensive and pervasive
system
for protection of employee health and safety affecting any segment of
U.S. industry. In reaction to the recent mine accidents in West Virginia,
state and federal legislatures and regulatory authorities have increased
scrutiny of mine safety matters and passed more stringent laws governing
mining.
For example, in 2006, Congress enacted the Mine Improvement and New Emergency
Response Act of 2006 (“MINER Act”), which imposed additional burdens on coal
operators, including (i) obligations related to (a) the development of new
emergency response plans that address post-accident communications, tracking
of
miners, breathable air, lifelines, training and communication with local
emergency response personnel, (b) establishing additional requirements for
mine
rescue teams, and (c) promptly notifying federal authorities in the event
of a
certain events, (ii) increased penalties for violations of the applicable
federal laws and regulations, and (iii) the requirement that new standards be
implemented regarding the manner in which closed areas of underground mines
are
sealed, and (iv) other matters. Various states also have enacted their own
new
laws and regulations addressing many of these same subjects. While existing
and
proposed regulations have a significant effect on our operating costs, our
U.S. competitors are subject to the same degree of regulation.
Under
the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform
Act of 1977, as amended in 1981, each coal mine operator must secure payment
of
federal black lung benefits to claimants who are current and former employees
and to a trust fund for the payment of benefits and medical expenses to
claimants who last worked in the coal industry prior to July 1, 1973. The
trust fund is funded by an excise tax on production of up to $1.10 per
ton for deep-mined coal and up to $0.55 per ton for surface- mined coal,
neither amount to exceed 4.4% of the gross sales price. The excise tax does
not
apply to coal shipped outside the United States. In 2006, we recorded
$14.8 million of expense related to this excise tax.
Coal
Industry Retiree Health Benefit Act of 1992.
Unlike
many companies in the coal business, we do not have any liability under the
Coal
Industry Retiree Health Benefit Act of 1992 (the “Coal Act”), which requires the
payment of substantial sums to provide lifetime health benefits to
union-represented miners (and their dependents) who retired before 1992,
because
liabilities under the Coal Act that had been imposed on our Predecessor or
acquired companies were retained by the sellers and, if applicable, their
parent
companies, in the applicable acquisition agreements. We should not be liable
for
these liabilities retained by the sellers unless they and, if applicable,
their
parent companies, fail to satisfy their obligations with respect to Coal
Act
claims and retained liabilities covered by the acquisition
agreements.
Endangered
Species Act.
The
federal Endangered Species Act and counterpart state legislation protect
species
threatened with possible extinction. Protection of threatened and endangered
species may have the effect of prohibiting or delaying us from obtaining
mining
permits and may include restrictions on timber harvesting, road building
and
other mining or agricultural activities in areas containing the affected
species
or their habitats. A number of species indigenous to the areas in which we
operate are protected under the Endangered Species Act. Based on the species
that have been identified to date and the current application of applicable
laws
and regulations, however, we do not believe there are any species protected
under the Endangered Species Act that would materially and adversely affect
our
ability to mine coal from our properties in accordance with current mining
plans. The U. S. Fish and Wildlife Service is working closely with OSM and
State
regulatory agencies to insure that Threatened and Endangered (T&E) species
are protected from mining-related impacts. Should more stringent protective
measures be applied to these T&E species or to their critical habitat, then
we could experience increased operating costs or difficulty in obtaining
future
mining permits.
Resource
Conservation and Recovery Act.
The RCRA
may affect coal mining operations by establishing requirements for the
treatment, storage, and disposal of hazardous wastes. Currently, certain
coal
mine wastes, such as overburden and coal cleaning wastes, are exempted from
hazardous waste management.
Subtitle
C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation
until the EPA completed a report to Congress and made a determination on
whether
the wastes should be regulated as hazardous. In a 1993 regulatory determination,
the EPA addressed some high volume-low toxicity coal combustion wastes generated
at electric utility and independent power producing facilities, such as coal
ash. In May 2000, the EPA concluded that coal combustion wastes do not warrant
regulation as hazardous under RCRA. The EPA is retaining the hazardous waste
exemption for these wastes. However, the EPA has determined that national
non-hazardous waste regulations under RCRA Subtitle D are needed for coal
combustion wastes disposed in surface impoundments and landfills and used
as
mine-fill, and OSM is currently developing these regulations. The agency
also
concluded beneficial uses of these wastes, other than for mine-filling, pose
no
significant risk and no additional national regulations are needed. As long
as
this exemption remains in effect, it is not anticipated that regulation of
coal
combustion waste will have any material effect on the amount of coal used
by
electricity generators. Most state hazardous waste laws also exempt coal
combustion 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.
Due
to
the hazardous waste exemption for coal combustion waste such as ash, much
coal
combustion waste is currently put to beneficial use. For example, in one
Pennsylvania mine from which we have the right to receive coal, we have used
some ash as mine fill. The ash we use for this purpose is mixed with lime
and
serves to help alleviate the potential for acid mine drainage.
Federal
and State Superfund Statutes.
Superfund and similar state laws may affect coal mining and hard rock operations
by creating liability for investigation and remediation in response to releases
of hazardous substances into the environment and for damages to natural
resources. Under Superfund, joint and several liabilities may be imposed
on
waste generators, site owners or operators and others regardless of fault.
In
addition, mining operations may have reporting obligations under the Emergency
Planning and Community Right to Know Act and the Superfund Amendments and
Reauthorization Act.
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.
In November 2004, Russia ratified the Kyoto Protocol to the 1992 Framework
Convention on Global Climate Change (the “Protocol”), which establishes a
binding set of emission targets for greenhouse gases. With Russia’s accedence,
the Protocol now has sufficient support and became binding on all those
countries that have ratified it on February 16, 2005. Four industrialized
nations have refused to ratify the Protocol — Australia, Liechtenstein,
Monaco, and the United States. Although the targets vary from country to
country, if the United States were to ratify the Protocol our nation would
be
required to reduce greenhouse gas emissions to 93% of 1990 levels from 2008
to
2012. Canada, which accounted for 5.4% of our sales volume in 2006, ratified
the
Protocol in 2002. Under the Protocol, Canada will be required to cut greenhouse
gas emissions to 6% below 1990 levels in 2008 to 2012, either in direct
reductions in emissions or by obtaining credits through the Protocol’s market
mechanisms. This could result in reduced demand for coal by Canadian electric
power generators.
Future
regulation of greenhouse gases in the United States could occur pursuant
to
future U.S. treaty obligations, statutory or regulatory changes under the
Clean Air Act, state adoption of a greenhouse regulatory scheme, or otherwise.
The Bush Administration has proposed a package of voluntary emission reductions
for greenhouse gases reduction targets which provide for certain incentives
if
targets are met. Some states, such as Massachusetts and California, have
already
issued regulations regulating greenhouse gas emissions from large power plants.
Further, in 2002, the Conference of New England Governors and Eastern Canadian
Premiers adopted a Climate Change Action Plan, calling for reduction in regional
greenhouse emissions to 1990 levels by 2010, and a further reduction of at
least
10% below 1990 levels by 2020. Increased efforts to control greenhouse gas
emissions, including the future ratification of the Protocol by the U.S.,
could
result in reduced demand for coal.
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 450 Fifth Street, N.W.,
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.
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Item 1A.
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Risk
Factors
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A
substantial or extended decline in coal prices could reduce our revenues
and the
value of our coal reserves.
Our
results of operations are substantially dependent upon the prices we receive
for
our coal. The prices we receive for coal depend upon factors beyond our control,
including:
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the
supply of and demand for domestic and foreign
coal;
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the
demand for electricity;
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domestic
and foreign demand for steel and the continued financial viability
of the
domestic and/or foreign steel
industry;
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the
proximity to, capacity of, and cost of transportation
facilities;
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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; and
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the
effect of worldwide energy conservation
measures.
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Declines
in the prices we receive for our coal could adversely affect our operating
results and our ability to generate the cash flows we require to improve
our
productivity and invest in our operations.
Our
coal mining production and delivery is subject to conditions and events beyond
our control, which could result in higher operating expenses and/or decreased
production and sales and adversely affect our operating
results.
A
majority of our coal mining operations are conducted in underground mines
and
the balance of our operations are 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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delays
and difficulties in acquiring, maintaining or renewing necessary
permits
or mining or surface rights;
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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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interruptions
due to transportation delays;
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adverse
weather and natural disasters, such as heavy rains and
flooding;
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accidental
mine water discharges;
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the
termination of material contracts by state or other governmental
authorities;
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the
unavailability of qualified labor;
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strikes
and other labor-related interruptions;
and
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unexpected
mine safety accidents, including fires and explosions from methane
and
other sources.
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If
any of
these conditions or events occur in the future at any of our mines or affect
deliveries of our coal to customers, they may increase our cost of mining
and
delay or halt production at particular mines or sales to our customers either
permanently for varying lengths of time, which could adversely affect our
operating results. For example, in 2004 we experienced mine roof stability
issues at our Kingwood underground mine, which resulted in a 23% decrease
in
production at this mine for 2004 as compared to 2003 full-year production
(including production in 2003 prior to our acquisition of the mine). In
addition, Hurricanes Katrina and Rita, which struck the Gulf Coast in August
and
September 2005, resulted in delayed shipments of our coal to our
customers.
Any
change in coal consumption patterns by steel producers or North American
electric power generators resulting in a decrease in the use of coal by those
consumers could result in lower prices for our coal, which would reduce our
revenues and adversely impact our earnings and the value of our coal
reserves.
Steam
coal accounted for approximately 66% and 62% of our coal sales volume during
2006 and 2005, respectively. The majority of our sales of steam coal for
2006
and 2005 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 34% and 38% of
our
coal sales volume during 2006 and 2005, respectively. In recent years,
U.S. steel producers have experienced a substantial decline in the prices
received for their products, due at least in part to a heavy volume of foreign
steel imported into the United States. Although prices for some U.S. steel
products increased moderately after the Bush administration imposed steel
import
tariffs and quotas in March 2002, those tariffs and quotas were lifted in
December 2003. Any
deterioration in conditions in the U.S. steel industry would reduce the
demand for our metallurgical coal and could impact the collectibility of
our
accounts receivable from U.S. steel industry customers. In addition, the
U.S. steel industry increasingly relies on electric arc furnaces or
pulverized coal processes to make steel. These processes do not use coke.
If
this trend continues, the amount of metallurgical coal that we sell and the
prices that we receive for it could decrease, thereby reducing our revenues
and
adversely impacting our earnings and the value of our coal reserves. In the
international market for metallurgical coal, there are indications that coal
prices may have begun to level off or decline from their current, historically
high levels. In a report issued at the end of November 2005, the EIA reported
that 2005 steel production in China has been well above projections, resulting
in a glut of steel despite China’s current position as the world’s largest
consumer of steel. 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.
Forward
sales and forward purchase contracts that are not accounted for as a hedge
could cause earnings volatility in our statement of income for a given
period.
We
participate in forward purchase and forward sales contracts that are considered
derivative
instruments under SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities
(“SFAS
133”) that do not qualify under the “normal purchase and normal sales”
exception. Transactions that do not qualify for this exception are required
to
be marked to market. Changes in fair value are recognized either in earnings
or
equity, depending on whether these transactions qualify for hedge accounting.
Our contracts do not currently qualify for hedge accounting. Accordingly,
changes in fair value have been recognized in earnings. During 2006, we
increased coal sales revenue related to mark-to-market gains on open over
the
counter (“OTC”) coal sales contracts in the amount of $6.1 million and increased
expense related to mark-to-market losses on open OTC coal purchase contracts
as
cost of coal sales in the amount of $5.7 million, resulting in an increase
in
pretax earnings of $0.4 million. At December 31, 2006, we had unrealized
gains
(losses) on open sales and purchase contracts in the amount of $6.1 million
and
($5.9 million), respectively. These amounts are recorded in prepaid expenses
and
other current assets and accrued expenses and other current liabilities,
respectively. Due to market price fluctuations, we could see earnings
volatility that we would normally not incur.
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
2004, we believe that we sold approximately 8% of our produced and processed
coal as metallurgical coal that we would have sold as steam coal in the market
conditions prevalent during 2003. We believe that we generated approximately
$65.0 million in additional revenues by selling this production as
metallurgical coal rather than steam coal during 2004, based on a comparison
of
the actual sales price and volume versus the then-prevailing market price
for
steam coal and the volume of coal that we would have sold if the coal had
been
mined, processed and marketed as steam coal. A decline in the metallurgical
market relative to the steam market could cause us to shift coal from the
metallurgical market to the steam market, thereby reducing our revenues and
profitability.
Most
of our metallurgical coal reserves possess quality characteristics that enable
us to mine, process and market them as high quality steam coal. However,
some of
our mines operate profitably only if all or a portion of their production
is
sold as metallurgical coal to the steel market. If demand for metallurgical
coal
declined to the point where we could earn a more attractive return marketing
the
coal as steam coal, these mines may not be economically viable and may be
subject to closure. Such closures would lead to accelerated reclamation costs,
as well as reduced revenue and profitability.
Acquisitions
that we have completed since our formation, as well as acquisitions that
we may
undertake in the future, involve a number of risks, any of which could cause
us
not to realize the anticipated benefits.
Since
our formation and the acquisition of our Predecessor in December 2002, we
have
completed four significant acquisitions and several smaller acquisitions
and
investments. We continually seek to expand our operations and coal reserves
through acquisitions. If we are unable to successfully integrate the companies,
businesses or properties we are able to acquire, our profitability may decline
and we could experience a material adverse effect on our business, financial
condition or results of operations. Acquisition transactions involve various
inherent risks, including:
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uncertainties
in assessing the value, strengths, and potential profitability
of, and
identifying the extent of all weaknesses, risks, contingent and
other
liabilities (including environmental or mine safety liabilities)
of,
acquisition candidates;
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the
potential loss of key customers, management and employees of an
acquired
business;
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the
ability to achieve identified operating and financial synergies
anticipated to result from an
acquisition;
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problems
that could arise from the integration of the acquired business;
and
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unanticipated
changes in business, industry or general economic conditions that
affect
the assumptions underlying our rationale for pursuing the
acquisition.
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Any
one
or more of these factors could cause us not to realize the benefits anticipated
to result from an acquisition. For example, in combining our Predecessor
and
acquired companies, we have incurred significant expenses to develop unified
reporting systems and standardize our accounting functions. Additionally,
we
were unable to profitably operate NKC, which we acquired in connection with
our
acquisition of AMCI. In September 2004, we recorded an impairment charge
of
$5.1 million to reduce the carrying value of the assets of NKC to their
estimated fair value, and we sold the assets of NKC on April 14,
2005.
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,
we
issued and subsequently repaid $221.0 million principal amount of
promissory installment notes of one of our indirect, wholly-owned subsidiaries,
we issued 2,180,233 shares of our common stock valued at approximately
$53.2 million, and we entered into a new $525.0 million credit
facility, a portion of the net proceeds of which we used to pay the cash
purchase price and acquisition expenses and the first installment of principal
due on the promissory notes. In addition, future acquisitions could result
in
our assuming more long-term liabilities relative to the value of the acquired
assets than we have assumed in our previous acquisitions.
The
inability of the sellers of our Predecessor and acquired companies to fulfill
their indemnification obligations to us under our acquisition agreements
could
increase our liabilities and adversely affect our results of operations and
financial position.
In
the acquisition agreements we entered into with the sellers of our Predecessor
and acquired companies, including the acquisition agreements we entered into
related to the Nicewonder, Progress and Gallatin acquisitions, the
respective sellers and, in some of our acquisitions, their parent companies,
agreed to retain responsibility for and indemnify us against damages resulting
from certain third-party claims or other liabilities, such as workers’
compensation liabilities, black lung liabilities, postretirement medical
liabilities and certain environmental or mine safety liabilities. The failure
of
any seller and, if applicable, its parent company, to satisfy their obligations
with respect to claims and retained liabilities covered by the acquisition
agreements could have an adverse effect on our results of operations and
financial position if claimants successfully assert that we are liable for
those
claims and/or retained liabilities. The obligations of the sellers and, in
some
instances, their parent companies, to indemnify us with respect to their
retained liabilities will continue for a substantial period of time, and
in some
cases indefinitely. The sellers’ indemnification obligations with respect to
breaches of their representations and warranties in the acquisition agreements
will terminate upon expiration of the applicable indemnification period
(generally 18-24 months from the acquisition date for most representations
and warranties, and from two to five years from the acquisition date for
environmental representations and warranties), are subject to deductible
amounts
and will not cover damages in excess of the applicable coverage limit. The
assertion of third-party claims after the expiration of the applicable
indemnification period or in excess of the applicable coverage limit, or
the
failure of any seller to satisfy its indemnification obligations with respect
to
breaches of its representations and warranties, could have an adverse effect
on
our results of operations and financial position. See “— If our assumptions
regarding our likely future expenses related to benefits for non-active
employees are incorrect, then expenditures for these benefits could be
materially higher than we have predicted.
Our
inability to continue or expand the existing road construction and mining
business of the Nicewonder Companies could adversely affect the expected
benefits from the Nicewonder Acquisition.
One
of our subsidiaries acquired the business of Nicewonder Contracting, Inc.
(“NCI”) pursuant to the Nicewonder acquisition. NCI operates a road construction
business under a contract with the State of West Virginia. Pursuant to the
contract, NCI is building approximately
11 miles of rough grade highway in West Virginia over the next four to five
years and, in exchange, NCI will be compensated by West Virginia based on
the
number of cubic yards of material excavated and/or filled to create a road
bed,
as well as for certain other cost components. In the course of the road
construction, NCI will recover any coal encountered and sell the coal to
its
customers, subject to certain costs, including coal loading, transportation,
coal royalty payments and applicable taxes and fees.
The
State
of West Virginia has only approved funding for a portion of this
road construction. If West Virginia does not fund the remaining sections of
the highway project, it would adversely affect NCI’s earnings. Even if West
Virginia funds the remainder of this project through the next four to five
years, we are uncertain whether the state will fund any similar projects
in the
future. In addition, we have no current experience conducting and completing
road projects and will rely on the expertise of the existing employees of
NCI in
order to operate the project, and other road projects we may undertake,
profitably. Furthermore, litigation has been filed against NCI and the State
of
West Virginia claiming that the project violated competitive bidding and
prevailing wage laws and regulations. If successful, the litigation could
make
the project considerably less advantageous to NCI or restrict or prohibit
NCI
from completing the project.
The
loss of, or significant reduction in, purchases by our largest customers
could
adversely affect our revenues and profitability.
Our
largest customer during 2006 accounted for approximately 7% of our total
revenues. We derived approximately 38%
of
our 2006 total revenues from sales to our ten largest customers. These customers
may not continue to purchase coal from us under our current coal supply
agreements, or at all. If these customers were to significantly reduce their
purchases of coal from us, or if we were unable to sell coal to them on terms
as
favorable to us as the terms under our current agreements, our revenues and
profitability could suffer materially.
Changes
in purchasing patterns in the coal industry may make it difficult for us
to
extend existing supply contracts or enter into new long-term supply contracts
with customers, which could adversely affect the capability and profitability
of
our operations.
We
sell a significant portion of our coal under long-term coal supply agreements,
which are contracts with a term greater than 12 months. The execution of a
satisfactory long-term coal supply agreement is frequently the basis on which
we
undertake the development of coal reserves required to be supplied under
the
contract. We believe that approximately 56% of our 2006 sales volume was
sold
under long-term coal supply agreements. At December 31, 2006, our long-term
coal
supply agreements had remaining terms of up to 10 years and an average
remaining term of approximately two years. When our current contracts with
customers expire or are otherwise renegotiated, our customers may decide
to
purchase fewer tons of coal than in the past or on different terms, including
pricing terms less favorable to us. As of February
05, 2007, approximately 10% and 57%, respectively, of our planned production
for
2007 and 2008 was uncommitted. We may not be able to enter into coal supply
agreements to sell this production on terms, including pricing terms, as
favorable to us as our existing agreements. For additional information relating
to our long-term coal supply contracts, see “Business — Marketing, Sales
and Customer Contracts.”
As
electric utilities continue to adjust to frequently changing regulations,
including the Acid Rain regulations of the Clean Air Act, the Clean Air Mercury
Rule, the Clean Air Interstate Rule and the possible deregulation of their
industry, they are becoming increasingly less willing to enter into long-term
coal supply contracts and instead are purchasing higher percentages of coal
under short-term supply contracts. The industry shift away from long-term
supply
contracts could adversely affect us and the level of our revenues. For example,
fewer electric utilities will have a contractual obligation to purchase coal
from us, thereby increasing the risk that we will not have a market for our
production. The prices we receive in the spot market may be less than the
contractual price an electric utility is willing to pay for a committed supply.
Furthermore, spot market prices tend to be more volatile than contractual
prices, which could result in decreased revenues.
Certain
provisions in our long-term supply contracts may reduce the protection these
contracts provide us during adverse economic conditions or may result in
economic penalties upon our failure to meet
specifications.
Price
adjustment, “price reopener” and other similar provisions in long-term supply
contracts may reduce the protection from short-term coal price volatility
traditionally provided by these contracts. Price reopener provisions are
particularly common in international metallurgical coal sales contracts.
Some of
our coal supply contracts contain provisions that allow for the price to
be
renegotiated at periodic intervals. Price reopener provisions may automatically
set a new price based on the prevailing market price or, in some instances,
require the parties to agree on a new price, sometimes between a pre-set
“floor”
and “ceiling.” In some circumstances, failure of the parties to agree on a price
under a price reopener provision can lead to termination of the contract.
Any
adjustment or renegotiation leading to a significantly lower contract price
could result in decreased revenues. Accordingly, supply contracts with terms
of
one year or more may provide only limited protection during adverse market
conditions.
Coal
supply agreements also typically contain force majeure provisions allowing
temporary suspension of performance by us or the customer during the duration
of
specified events beyond the control of the affected party. Most of our coal
supply agreements contain provisions requiring us to deliver coal meeting
quality thresholds for certain characteristics such as Btu, sulfur content,
ash
content, grindability and ash fusion temperature. Failure to meet these
specifications could result in economic penalties, including price adjustments,
the rejection of deliveries or termination of the contracts. Moreover, some
of
our agreements where the customer bears transportation costs permit the customer
to terminate the contract if the transportation costs borne by them increase
substantially. In addition, some of these contracts allow our customers to
terminate their contracts in the event of changes in regulations affecting
our
industry that increase the price of coal beyond specified limits.
Due
to the risks mentioned above with respect to long-term supply contracts,
we may
not achieve the revenue or profit we expect to achieve from these sales
commitments.
Disruption
in supplies of coal produced by contractors and other third parties could
temporarily impair our ability to fill customers’ orders or increase our
costs.
In
addition to marketing coal that is produced by our subsidiaries’ employees, we
utilize contractors to operate some of our mines. Operational difficulties
at
contractor-operated mines, changes in demand for contract miners from other
coal
producers, and other factors beyond our control could affect the availability,
pricing, and quality of coal produced for us by contractors. For example,
during
2005, production at our contractor operations ran approximately 25% behind
plan,
primarily due to shortages in the supply of labor. As a result of this
shortfall, we were forced to purchase coal at a higher cost than planned
so that
we could meet commitments to customers. To meet customer specifications and
increase efficiency in fulfillment of coal contracts, we also purchase and
resell coal produced by third parties from their controlled reserves. The
majority of the coal that we purchase from third parties is blended with
coal
produced from our mines prior to resale and we also process (which includes
washing, crushing or blending coal at one of our preparation plants or loading
facilities) a portion of the coal that we purchase from third parties prior
to
resale. We sold 5.8 million tons of coal purchased from third parties
during 2006, representing approximately 20% of our total sales during 2006.
We
believe that approximately 68% of our purchased coal sales in 2006 was blended
with coal produced from our mines prior to resale, and approximately 5% of
our
total sales in 2006 consisted of coal purchased from third parties that we
processed before resale. The availability of specified qualities of this
purchased coal may decrease and prices may increase as a result of, among
other
things, changes in overall coal supply and demand levels, consolidation in
the
coal industry and new laws or regulations. Disruption in our supply of
contractor-produced coal and purchased coal could temporarily impair our
ability
to fill our customers’ orders or require us to pay higher prices in order to
obtain the required coal from other sources. Any increase in the prices we
pay
for contractor-produced coal or purchased coal could increase our costs and
therefore lower our earnings. Although increases in market prices for coal
generally benefit us by allowing us to sell coal at higher prices, those
increases also increase our costs to acquire purchased coal, which lowers
our
earnings.
Competition
within the coal industry may adversely affect our ability to sell coal, and
excess production capacity in the industry could put downward pressure on
coal
prices.
We
compete with numerous other coal producers in various regions of the United
States for domestic and international sales. During the mid-1970s and early
1980s, increased demand for coal attracted new investors to the coal industry,
spurred the development of new mines and resulted in additional production
capacity throughout the industry, all of which led to increased competition
and
lower coal prices. Recent increases in coal prices could encourage the
development of expanded capacity by new or existing coal producers. Any
resulting overcapacity could reduce coal prices and therefore reduce our
revenues.
Coal
with lower production costs shipped east from western coal mines and from
offshore sources has resulted in increased competition for coal sales in
the
Appalachian region. In addition, coal companies with larger mines that utilize
the long-wall mining method typically have lower mine operating costs than
we do
and may be able to compete more effectively on price, particularly if the
current favorable market weakens. This competition could result in a decrease
in
our market share in this region and a decrease in our revenues.
Demand
for our low sulfur coal and the prices that we can obtain for it are also
affected by, among other things, the price of emissions allowances. Decreases
in
the prices of these emissions allowances could make low sulfur coal less
attractive to our customers. In addition, more widespread installation by
electric utilities of technology that reduces sulfur emissions (which could
be
accelerated by increases in the prices of emissions allowances), may make
high
sulfur coal more competitive with our low sulfur coal. This competition could
adversely affect our business and results of operations.
We
also compete in international markets against coal produced in other countries.
Measured by tons sold, exports accounted for approximately 25% of our sales
in
2006. The demand for U.S. coal exports is dependent upon a number of
factors outside of our control, including the overall demand for electricity
in
foreign markets, currency exchange rates, the demand for foreign-produced
steel
both in foreign markets and in the U.S. market (which is dependent in part
on tariff rates on steel), general economic conditions in foreign countries,
technological developments, and environmental and other governmental
regulations. For example, if the value of the U.S. dollar were to rise
against other currencies in the future, our coal would become relatively
more
expensive and less competitive in international markets, which could reduce
our
foreign sales and negatively impact our revenues and net income. In addition,
if
the amount of coal exported from the United States were to decline, this
decline
could cause competition among coal producers in the United States to intensify,
potentially resulting in additional downward pressure on domestic coal
prices.
Fluctuations
in transportation costs and the availability or reliability of transportation
could affect the demand for our coal or temporarily impair our ability to
supply
coal to our customers.
Transportation
costs represent a significant portion of the total cost of coal for our
customers. Increases in transportation costs, such as those experienced
during
2005 and 2006, 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.
Certain shipments of our coal to customers were delayed by hurricanes in
the
Gulf Coast in 2005. In some cases, this delay will affect the timing of our
recognition of revenue from these sales. 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
2006,
73% of our produced and processed coal volume was transported from the
preparation plant to the customer by rail. In the past, we have experienced
a
general deterioration in the reliability of the service provided by rail
carriers, which increased our internal coal handling costs. If there are
continued disruptions of the transportation services provided by the railroad
companies we use and we are unable to find alternative transportation providers
to ship our coal, our business could be adversely affected.
We
have
investments in mines, loading facilities, and ports that in most cases are
serviced by a single rail carrier. Our operations that are serviced by a
single
rail carrier are particularly at risk to disruptions in the transportation
services provided by that rail carrier, due to the difficulty in arranging
alternative transportation. If a single rail carrier servicing our operations
does not provide sufficient capacity, revenue from these operations and our
return on investment could be adversely impacted. The states of West Virginia
and Kentucky have recently increased enforcement of weight limits on coal
trucks
on their public roads. It is possible that other states in which our coal
is
transported by truck could undertake similar actions to increase enforcement
of
weight limits. Such stricter enforcement actions could result in shipment
delays
and increased costs. An increase in transportation costs could have an adverse
effect on our ability to increase or to maintain production on a profit-making
basis and could therefore adversely affect revenues and earnings.
Our
business will be adversely affected if we are unable to develop or acquire
additional coal reserves that are economically
recoverable.
Our
profitability depends substantially on our ability to mine coal reserves
possessing quality characteristics desired by our customers in a cost-effective
manner. As of December 31, 2006, we owned or leased 548.6 million tons
of proven and probable coal reserves that we believe will support current
production levels for more than 20 years,
which is less than the publicly reported amount of proven and probable coal
reserves and reserve lives (based on current publicly reported production
levels) of the other large publicly traded coal companies. We have not yet
applied for the permits required, or developed the mines necessary, to mine
all
of our reserves. Permits are becoming increasingly more difficult and expensive
to obtain and the review process continues to lengthen. In addition, we may
not
be able to mine all of our reserves as profitably as we do at our current
operations.
Because
our reserves are depleted as we mine our coal, our future success and growth
depend, in part, upon our ability to acquire additional coal reserves that
are
economically recoverable. If we are unable to replace or increase our coal
reserves on acceptable terms, our production and revenues will decline as
our
reserves are depleted. Exhaustion of reserves at particular mines also may
have
an adverse effect on our operating results that is disproportionate to the
percentage of overall production represented by such mines. Our ability to
acquire additional coal reserves through acquisitions in the future also
could
be limited by restrictions under our existing or future debt agreements,
competition from other coal companies for attractive properties, or the lack
of
suitable acquisition candidates.
We
face numerous uncertainties in estimating our recoverable coal reserves,
and
inaccuracies in our estimates could result in decreased profitability from
lower
than expected revenues or higher than expected costs.
Forecasts
of our future performance are based on, among other things, estimates of
our
recoverable coal reserves. We base our estimates of reserve information on
engineering, economic and geological data assembled and analyzed by our internal
engineers and which is periodically reviewed by third-party consultants.
There
are numerous uncertainties inherent in estimating the quantities and qualities
of, and costs to mine, recoverable reserves, including many factors beyond
our
control. Estimates of economically recoverable coal reserves and net cash
flows
necessarily depend upon a number of variable factors and assumptions, any
one of
which may, if incorrect, result in an estimate that varies considerably from
actual results. These factors and assumptions include:
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future
mining technology improvements;
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the
effects of regulation by governmental
agencies;
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geologic
and mining conditions, which may not be fully identified by available
exploration data and may differ from our experiences in areas we
currently
mine. As a result, actual coal tonnage recovered from identified
reserve
areas or properties, and costs associated with our mining operations,
may
vary from estimates. Any inaccuracy in our estimates related to
our
reserves could result in decreased profitability from lower than
expected
revenues or higher than expected costs; and
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Defects
in title of any leasehold interests in our properties could limit our ability
to
mine these properties or result in significant unanticipated
costs.
We
conduct a significant part of our mining operations on properties that we
lease.
Title to most of our leased properties and mineral rights is not thoroughly
verified until a permit to mine the property is obtained, and in some cases
title with respect to leased properties is not verified at all. Our right
to
mine some of our reserves may be materially adversely affected by defects
in
title or boundaries. In order to obtain leases or mining contracts to conduct
our mining operations on property where these defects exist, we may in the
future have to incur unanticipated costs or could even lose our right to
mine,
which could adversely affect our profitability.
Mining
in Central and Northern Appalachia is more complex and involves more regulatory
constraints than mining in other areas of the United States, which could
affect
our mining operations and cost structures in these
areas.
The
geological characteristics of Central and Northern Appalachian coal reserves,
such as depth of overburden and coal seam thickness, make them complex and
costly to mine. As mines become depleted, replacement reserves may not be
available when required or, if available, may not be capable of being mined
at
costs comparable to those characteristic of the depleting mines. In addition,
as
compared to mines in other regions, permitting, licensing and other
environmental and regulatory requirements are more costly and time consuming
to
satisfy. These factors could materially adversely affect the mining operations
and cost structures of, and our customers’ ability to use coal produced by, our
mines in Central and Northern Appalachia.
Our
work force could become increasingly unionized in the future, which could
adversely affect the stability of our production and reduce our
profitability.
Approximately
94% of our 2006 coal production came from mines operated by union-free
employees. As of December 31, 2006, over 92% of our 3,546 employees are
union-free. However, our subsidiaries’ employees have the right at any time
under the National Labor Relations Act to form or affiliate with a union.
Any
further unionization of our subsidiaries’ employees, or the employees of
third-party contractors who mine coal for us, could adversely affect the
stability of our production and reduce our profitability.
Our
unionized work force could strike in the future, which could disrupt production
and shipments of our coal and increase costs.
One
of
our subsidiaries has two negotiated wage agreements with the United Mine
Workers
of America (“UMWA”). These agreements, covering 275 employees as of
December 31, 2006, expire on December 31, 2009. One of our other
subsidiaries is currently negotiating a wage agreement with the UMWA covering
an
aggregate of 24 employees that expired on December 31, 2006. Some or
all of the affected employees at each location could strike, which would
adversely affect our productivity, increase our costs, and disrupt shipments
of
coal to our customers. Also, one of our other subsidiaries, that is idle,
had a
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 effected at this
time.
However, if the operation becomes active again, these employees could be
affected.
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. During 2006, we had $0.7 million of bad
debt
expense. Our customer base is changing with deregulation as utilities sell
their
power plants to their non-regulated affiliates or third parties that may
be less
creditworthy, thereby increasing the risk we bear on payment default. These
new
power plant owners may have credit ratings that are below investment grade.
In
addition, competition with other coal suppliers could force us to extend
credit
to customers and on terms that could increase the risk we bear on payment
default.
We
have contracts to supply coal to energy trading and brokering companies under
which those companies sell coal to end users. If the creditworthiness of
the
energy trading and brokering companies declines, this would increase the
risk
that we may not be able to collect payment for all coal sold and delivered
to or
on behalf of these energy trading and brokering companies.
The
government extensively regulates our mining operations, which imposes
significant costs on us, and future regulations could increase those costs
or
limit our ability to produce and sell coal.
The
coal mining industry is subject to increasingly strict regulation by federal,
state and local authorities with respect to matters such as:
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employee
health and safety;
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mandated
benefits for retired coal miners;
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mine
permitting and licensing
requirements;
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reclamation
and restoration of mining properties after mining is
completed;
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air
quality standards;
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water
pollution;
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plant
and wildlife protection;
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the
discharge of materials into the
environment;
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surface
subsidence from underground mining;
and
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the
effects of mining on groundwater quality and
availability.
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The
costs, liabilities and requirements associated with these regulations may
be
costly and time consuming and may delay commencement or continuation of
exploration or production operations. Failure to comply with these regulations
may result in the assessment of administrative, civil and criminal penalties,
the imposition of cleanup and site restoration costs and liens, the issuance
of
injunctions to limit or cease operations, the suspension or revocation of
permits and other enforcement measures that could have the effect of limiting
production from our operations. We may also incur costs and liabilities
resulting from claims for damages to property or injury to persons arising
from
our operations. If we are pursued for these sanctions, costs and liabilities,
our mining operations and, as a result, our profitability could be adversely
affected.
The
possibility exists that new legislation and/or regulations and orders may
be
adopted that may materially adversely affect our mining operations, our cost
structure and/or our customers’ ability to use coal. For example, in reaction to
recent mine accidents in West Virginia, state and federal legislatures and
regulatory authorities have increased scrutiny of mine safety matters and
passed
more stringent laws governing mining. In 2006, Congress enacted the MINER
Act,
which imposed additional burdens on coal operators, including (i) obligations
related to (a) the development of new emergency response plans that address
post-accident communications, tracking of miners, breathable air, lifelines,
training and communication with local emergency response personnel, (b) insuring
the availability of mine rescue teams, and (c) promptly notifying federal
authorities in the event of a certain events, (ii) increased penalties for
violations of the applicable federal laws and regulations, and (iii) the
requirement that new standards be implemented regarding the manner in which
closed areas of underground mines are sealed and (iv) other matters. Various
states also have enacted their own new laws and regulations addressing many
of
these same subjects. Our compliance with these or any new mine health and
safety
regulations could increase our mining costs. New legislation or administrative
regulations (or new judicial interpretations or administrative enforcement
of
existing laws and regulations), including proposals related to the protection
of
the environment that would further regulate and tax the coal industry, may
also
require us or our customers to change operations significantly or incur
increased costs. These regulations, if proposed and enacted in the future,
could
have a material adverse effect on our financial condition and results of
operations.
Extensive
environmental regulations affect our customers and could reduce the demand
for
coal as a fuel source and cause our sales to decline.
The
Clean Air Act and similar state and local laws extensively regulate the amount
of sulfur dioxide, particulate matter, nitrogen oxides, and other compounds
emitted into the air from electric power plants, which are the largest end-users
of our coal. Such regulations will require significant emissions control
expenditures for many coal-fired power plants to comply with applicable ambient
air quality standards. As a result, these generators may switch to other
fuels
that generate less of these emissions or install more effective pollution
control equipment, possibly reducing future demand for coal and the construction
of coal-fired power plants.
Various
new and proposed laws and regulations may require further reductions in
emissions from coal-fired utilities. For example, under the new Clean Air
Interstate Rule issued on March 10, 2005, the EPA will further regulate
sulfur dioxide and nitrogen oxides from coal-fired power plants. When fully
implemented, this rule is expected to reduce sulfur dioxide emissions in
affected states by over 70% and nitrogen oxides emissions by over 60% from
2003
levels. The stringency of this cap may require many coal-fired sources to
install additional pollution control equipment, such as wet scrubbers, to
comply. Installation of additional pollution control equipment required by
this
rule could result in a decrease in the demand for low sulfur coal (because
sulfur would be removed by the new emissions control equipment), potentially
driving down prices for low sulfur coal. In addition, under the Clean Air
Act,
coal-fired power plants will be required to control hazardous air pollution
emissions by no later than 2009, which likely will require significant new
investment in pollution-control devices by power plant operators. Further,
on
March 15, 2005, the EPA finalized the Clean Air Mercury Rule intended to
control mercury emissions from power plants, which could require coal-fired
power plants to install new pollution controls or comply with a mandatory,
declining cap on the total mercury emissions allowed from coal-fired power
plants nationwide. Both the Clean Air Mercury Rule and the Clean Air Interstate
Rule are subject to administrative reconsideration and judicial challenge.
These
standards and future standards could have the effect of making coal-fired
plants
unprofitable, thereby decreasing demand for 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.
Several
proposals are pending in Congress and various states that are designed to
further reduce emissions of sulfur dioxide, nitrogen oxides and mercury from
power plants, and certain ones could regulate additional air pollutants.
If such
initiatives are enacted into law, power plant operators could choose fuel
sources other than coal to meet their requirements, thereby reducing the
demand
for coal. Current and possible future governmental programs are or may be
in
place to require the purchase and trading of allowances associated with the
emission of various substances such as sulfur dioxide, nitrous oxide, mercury
and carbon dioxide. Changes in the markets for and prices of allowances could
have a material effect on demand for and prices received for our
coal.
A
regional haze program initiated by the EPA to protect and to improve visibility
at and around national parks, national wilderness areas and international
parks
restricts the construction of new coal-fired power plants whose operation
may
impair visibility at and around federally protected areas, and may require
some
existing coal-fired power plants, and certain thermal dryers, to install
additional control measures designed to limit haze-causing
emissions.
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.
In November 2004, Russia ratified the Kyoto Protocol to the 1992 Framework
Convention on Global Climate Change (the “Protocol”), which establishes a
binding set of emission targets for greenhouse gases. With Russia’s accedence,
the Protocol now has sufficient support and became binding on all those
countries that have ratified it on February 16, 2005. Four industrialized
nations have refused to ratify the Protocol — Australia, Liechtenstein,
Monaco, and the United States. Although the targets vary from country to
country, if the United States were to ratify the Protocol, our nation would
be
required to reduce greenhouse gas emissions to 93% of 1990 levels in a series
of
phased reductions from 2008 to 2012. Canada, which accounted for approximately
5.3% of our 2006 sales volume, ratified the Protocol in 2002. Under the
Protocol, Canada will be required to cut greenhouse gas emissions to 6% below
1990 levels in a series of phased reductions from 2008 to 2012, either in
direct
reductions in emissions or by obtaining credits through the Protocol’s market
mechanisms. This could result in reduced demand for coal by Canadian electric
power generators.
Future
regulation of greenhouse gases in the United States could occur pursuant
to
future U.S. treaty obligations, statutory or regulatory changes under the
Clean Air Act, or otherwise. The Bush Administration has proposed a package
of
voluntary emission reductions for greenhouse gases reduction targets which
provide for certain incentives if targets are met. Some states, such as
Massachusetts, have already issued regulations regulating greenhouse gas
emissions from large power plants. Further, in 2002, the Conference of New
England Governors and Eastern Canadian Premiers adopted a Climate Change
Action
Plan, calling for reduction in regional greenhouse emissions to 1990 levels
by
2010, and a further reduction of at least 10% below 1990 levels by 2020.
Increased efforts to control greenhouse gas emissions, including the future
ratification of the Protocol by the United States, could result in reduced
demand for our coal. See “Environmental and Other Regulatory
Matters.”
Our
operations may impact the environment or cause exposure to hazardous substances,
and our properties may have environmental contamination, which could result
in
material liabilities to us.
Our
operations currently use hazardous materials and generate limited quantities
of
hazardous wastes from time to time. Our Predecessor and acquired companies
also
utilized certain hazardous materials and generated similar wastes. We may
be
subject to claims under federal and state statutes and/or common law doctrines
for toxic torts, natural resource damages and other damages as well as for
the
investigation and clean up of soil, surface water, groundwater, and other
media.
Such claims may arise, for example, out of current or former conditions at
sites
that we own or operate currently, as well as at sites that we or our Predecessor
and acquired companies owned or operated in the past, and at contaminated
sites
that have always been owned or operated by third parties. Our liability for
such
claims may be joint and several, so that we may be held responsible for more
than our share of the contamination or other damages, or even for the entire
share. We have not been subject to claims arising out of contamination at
our
facilities, and are not aware of any such contamination, but may incur such
liabilities in the future.
We
maintain extensive coal slurry impoundments at a number of our mines. Such
impoundments are subject to extensive regulation. Slurry impoundments maintained
by other coal mining operations have been known to fail, releasing large
volumes
of coal slurry. Structural failure of an impoundment can result in extensive
damage to the environment and natural resources, such as streams or bodies
of
water that the coal slurry reaches, as well as liability for related personal
injuries and property damages, and injuries to wildlife. Some of our
impoundments overlie mined out areas, which can pose a heightened risk of
failure and of damages arising out of failure. If one of our impoundments
were
to fail, we could be subject to substantial claims for the resulting
environmental contamination and associated liability, as well as for fines
and
penalties.
These
and other similar unforeseen impacts that our operations may have on the
environment, as well as exposures to hazardous substances or wastes associated
with our operations, could result in costs and liabilities that could materially
and adversely affect us.
We
may be unable to obtain and renew permits necessary for our operations, which
would reduce our production, cash flow and
profitability.
Mining
companies must obtain numerous permits that impose strict regulations on
various
environmental and safety matters in connection with coal mining. These include
permits issued by various federal and state agencies and regulatory bodies.
The
permitting rules are complex and may change over time, making our ability
to
comply with the applicable requirements more difficult or even impossible,
thereby precluding continuing or future mining operations. Private individuals
and the public have certain rights to comment upon, submit objections to,
and
otherwise engage in the permitting process, including through court
intervention. Accordingly, the permits we need may not be issued, maintained
or
renewed, or may not be issued or renewed in a timely fashion, or may involve
requirements that restrict our ability to conduct our mining operations.
An
inability to conduct our mining operations pursuant to applicable permits
would
reduce our production, cash flow, and profitability.
Permits
under Section 404 of the Clean Water Act are required for coal companies to
conduct dredging or filling activities in jurisdictional waters for the purpose
of creating slurry ponds, water impoundments, refuse areas, valley fills
or
other mining activities. The Army Corps of Engineers (the “COE”) is empowered to
issue “nationwide” permits for specific categories of filling activity that are
determined to have minimal environmental adverse effects in order to save
the
cost and time of issuing individual permits under Section 404. Nationwide
Permit 21 authorizes the disposal of dredge-and-fill material from mining
activities into the waters of the United States. On October 23, 2003,
several citizens groups sued the COE in the U.S. District Court for the
Southern District of West Virginia seeking to invalidate “nationwide” permits
utilized by the COE and the coal industry for permitting most in-stream
disturbances associated with coal mining, including excess spoil valley fills
and refuse impoundments. Although the lower court enjoined the issuance of
Nationwide 21 permits, that decision was overturned by the Fourth Circuit
Court
of Appeals, which concluded that the COE complied with the Clean Water Act
in
promulgating this permit. Although we had no operations that were immediately
impacted or interrupted, the lower court’s decision required us to convert
certain current and planned applications for Nationwide 21 permits to
applications for individual permits. A similar lawsuit was filed on
January 27, 2005 in the U.S. District Court for the Eastern District
of Kentucky and remains pending, and other lawsuits may be filed in other
states
where we operate. Although it is not possible to predict the results of the
Kentucky litigation, it could adversely affect our Kentucky
operations.
Due
to political and economic uncertainties in Venezuela, our investment in Excelven
Pty Ltd could be at risk for loss
In
2004, we acquired a 24.5% interest in Excelven Pty Ltd, which, through its
subsidiaries, controls
the rights to the Las Carmelitas mining venture in Venezuela and the related
Palmarejo export port facility on Lake Maracaibo in Venezuela. The project
is currently in the development stage, and final governmental approval of
the project has not yet been obtained. Political and economic
uncertainties in Venezuela could delay or prevent such
governmental approval from being obtained or otherwise impede execution of
the
project. Such political and economic uncertainties could also lead
to events such as civil unrest, work stoppages or the
nationalization or other expropriation of private enterprises by the Venezuelan
government, which could result in a loss of all or a portion of
our investment in Excelven, which is in excess of $5.8 million to
date.
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. 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 no have a ready substitute for these commodities.
We
have reclamation and mine closure obligations. If the assumptions underlying
our
accruals are inaccurate, we could be required to expend greater amounts
than
anticipated.
The
Surface Mining Control and Reclamation Act establish operational, reclamation
and closure standards for all aspects of surface mining as well as most
aspects
of deep mining. We accrue for the costs of current mine disturbance and
of final
mine closure, including the cost of treating mine water discharge where
necessary. Estimates of our total reclamation and mine-closing liabilities
are
based upon permit requirements and our experience. The amounts recorded
are
dependent upon a number of variables, including the estimated future
retirement
costs, estimated proven reserves, assumptions involving profit margins,
inflation rates, and the assumed credit-adjusted risk-free interest rates.
Furthermore, these obligations are unfunded. If these accruals are insufficient
or our liability in a particular year is greater than currently anticipated,
our
future operating results could be adversely
affected.
Our
ability to operate our company effectively could be impaired if we fail to
attract and retain key personnel.
Our
ability to operate our business and implement our strategies depends, in
part,
on the efforts of our executive officers and other key employees. In addition,
our future success will depend on, among other factors, our ability to attract
and retain other qualified personnel. The loss of the services of any of
our
executive officers or other key employees or the inability to attract or
retain
other qualified personnel in the future could have a material adverse effect
on
our business or business prospects.
A
shortage of skilled labor in the Appalachian region could pose a risk to
achieving improved labor productivity and competitive costs and could adversely
affect our profitability.
Efficient
coal mining using modern techniques and equipment requires skilled laborers,
preferably with at least a year of experience and proficiency in multiple
mining
tasks. In recent years, a shortage of trained coal miners in the Appalachian
region has caused us to operate certain units without full staff, which
decreases our productivity and increases our costs. For example, during the
year
of 2005, production at our contractor operations was running approximately
25%
behind plan, primarily due to shortages in the supply of labor. 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.
Our
amount of indebtedness could harm our business by limiting our available
cash
and our access to additional capital and could force us to sell material
assets
or take other actions to attempt to reduce our
indebtedness.
Our
financial performance could be affected by our amount of indebtedness. At
December 31, 2006, we had $445.7 million of indebtedness outstanding,
representing 56% of our total capitalization. This indebtedness consisted
of
$175.0 million principal of our 10% senior notes due 2012, a $247.5
term loan under our credit facility and $23.2 million of other
indebtedness, including $1.5 million of capital lease obligations extending
through March 2009, $0.7 million principal amount that we incurred in
connection with the Gallatin Acquisition related to funds loaned by an unrelated
third party to assist in the construction of the kiln and $21.0 million
payable to an insurance premium finance company. In addition, under our credit
facility we had $81.1 million of letters of credit outstanding at
December 31, 2006.
In
connection with the Nicewonder acquisition,
we refinanced all outstanding indebtedness under our prior credit facility
with
a new credit facility, which provides for up to $525.0 million of
borrowings, including a $275.0 million revolving credit facility and a
$250.0 million term loan. In addition, under the terms of the Nicewonder
acquisition, one of our indirect, wholly-owned subsidiaries issued
$221.0 million in promissory installment notes, which have been paid in
full. We may also incur additional indebtedness in the future.
This
level of indebtedness could have important consequences to our business.
For
example, it could:
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increase
our vulnerability to general adverse economic and industry
conditions;
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make
it more difficult to self-insure and obtain surety bonds or letters
of
credit;
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limit
our ability to enter into new long-term sales
contracts;
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make
it more difficult for us to pay interest and satisfy our debt obligations,
including our obligations with respect to the
notes;
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require
us to dedicate a substantial portion of our cash flow from operations
to
payments on our indebtedness, thereby reducing the availability
of our
cash flow to fund working capital, capital expenditures, acquisitions
and
other general corporate activities;
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limit
our ability to obtain additional financing to fund future working
capital,
capital expenditures, research and development, debt service requirements
or other general corporate
requirements;
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limit
our flexibility in planning for, or reacting to, changes in our
business
and in the coal industry;
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place
us at a competitive disadvantage compared to less leveraged competitors;
and
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limit
our ability to borrow additional
funds.
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If
our cash flows and capital resources are insufficient to fund our debt service
obligations or our requirements under our other long-term liabilities, we
may be
forced to sell assets, seek additional capital or seek to restructure or
refinance our indebtedness. These alternative measures may not be successful
and
may not permit us to meet our scheduled debt service obligations, including
our
obligations with respect to the notes, or our requirements under our other
long
term liabilities. In the absence of such operating results and resources,
we
could face substantial liquidity problems and might be required to sell material
assets or operations to attempt to meet our debt service and other obligations.
Our credit facility and the indenture under which our senior notes were issued
restrict our ability to sell assets and use the proceeds from the sales.
We may
not be able to consummate those sales or to obtain the proceeds which we
could
realize from them and these proceeds may not be adequate to meet any debt
service obligations then due. Furthermore, substantially all of our material
assets secure our indebtedness under our current credit
facility.
Despite
our current leverage, we may still be able to incur substantially more debt.
This could further exacerbate the risks associated with our significant
indebtedness.
We
may be able to incur substantial additional indebtedness in the future. The
terms of our new credit facility and the indenture governing our senior notes
do
not prohibit us from doing so. Our current credit facility provides for a
revolving line of credit of up to $275.0 million,
of which $193.9 million was available as of December 31, 2006. The
addition of new debt to our current debt levels could increase the related
risks
that we now face. For example, the spread over the variable interest rate
applicable to loans under our credit facility is dependent on our leverage
ratio, and it would increase if our leverage ratio increases. Additional
drawings under our revolving line of credit could also limit the amount
available for letters of credit in support of our bonding obligations, which
we
will require as we develop and acquire new mines.
The
covenants in our credit facility and the indenture governing the notes impose
restrictions that may limit our operating and financial
flexibility.
Our
credit facility and the indenture governing our senior notes contain a number
of
significant restrictions and covenants that limit our ability and our
subsidiaries’ ability to, among other things, incur additional indebtedness or
enter into sale and leaseback transactions, pay dividends, make redemptions
and
repurchases of certain capital stock, make loans and investments, create
liens,
engage in transactions with affiliates and merge or consolidate with other
companies or sell substantially all of our assets.
These
covenants could adversely affect our ability to finance our future operations
or
capital needs or to execute preferred business strategies. In addition, if
we
violate these covenants and are unable to obtain waivers from our lenders,
our
debt under these agreements would be in default and could be accelerated
by our
lenders. If our indebtedness is accelerated, we may not be able repay our
debt
or borrow sufficient funds to refinance it. Even if we were able to obtain
new
financing, it may not be on commercially reasonable terms, on terms that
are
acceptable to us, or at all. If our debt is in default for any reason, our
business, financial condition and results of operations could be materially
and
adversely affected.
Failure
to obtain or renew surety bonds on acceptable terms could affect our ability
to
secure reclamation and coal lease obligations, which could adversely affect
our
ability to mine or lease coal.
Federal
and state laws require us to obtain surety bonds to secure payment of certain
long-term obligations such as mine closure or reclamation costs, federal
and
state workers’ compensation costs, coal leases and other obligations. These
bonds are typically renewable annually. Surety bond issuers and holders may
not
continue to renew the bonds or may demand additional collateral or other
less
favorable terms upon those renewals. The ability of surety bond issuers and
holders to demand additional collateral or other less favorable terms has
increased as the number of companies willing to issue these bonds has decreased
over time. Our failure to maintain, or our inability to acquire, surety bonds
that are required by state and federal law would affect our ability to secure
reclamation and coal lease obligations, which could adversely affect our
ability
to mine or lease coal. That failure could result from a variety of factors
including, without limitation:
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lack
of availability, higher expense or unfavorable market terms of
new
bonds;
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restrictions
on availability of collateral for current and future third-party
surety
bond issuers under the terms of our credit facility or the indenture
governing our senior notes; and
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the
exercise by third-party surety bond issuers of their right to refuse
to
renew the surety.
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Failure
to maintain capacity for required letters of credit could limit our available
borrowing capacity under our credit facility, limit our ability to obtain
or
renew surety bonds and negatively impact our ability to obtain additional
financing to fund future working capital, capital expenditure or other general
corporate requirements.
At
December 31, 2006, we had $81.1 million of letters of credit in place,
of which $70.7 million served as collateral for reclamation surety bonds
and $10.4 million secured miscellaneous obligations. Our credit facility
provides for revolving commitments of up to $275.0 million,
all of which can be used to issue additional letters of credit. In addition,
obligations secured by letters of credit may increase in the future. Any
such
increase would limit our available borrowing capacity under our current or
future credit facilities and could negatively impact our ability to obtain
additional financing to fund future working capital, capital expenditure
or
other general corporate requirements. Moreover, if we do not maintain sufficient
borrowing capacity under our revolving credit facility for additional letters
of
credit, we may be unable to obtain or renew surety bonds required for our
mining
operations.
If
our assumptions regarding our likely future expenses related to benefits
for
non-active employees are incorrect, then expenditures for these benefits
could
be materially higher than we have predicted.
At
the times that we acquired the assets of our Predecessor and acquired companies,
the Predecessor and acquired operations were subject to long-term liabilities
under a variety of benefit plans and other arrangements with active and inactive
employees. We assumed a portion of these long-term obligations and are
continuing to incur additional costs from our operations for postretirement,
workers’ compensation and black lung liabilities. The current and non-current
accrued portions of these long-term obligations, as reflected in our
consolidated financial statements as of December 31, 2006, included
$50.8 million of postretirement medical obligations and $8.3 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
annual
report. However, if our assumptions are incorrect, we could be required to
expend greater amounts than anticipated.
Several
states in which we operate consider changes in workers’ compensation laws from
time to time, which, if enacted, could adversely affect us. In addition,
if any
of the sellers from whom we acquired our operations fail to satisfy their
indemnification obligations to us with respect to postretirement claims and
retained liabilities, then we could be required to expend greater amounts
than
anticipated. See “— 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.
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 cash flow and profits have been, and may continue
to
be, negatively impacted. Lower than expected sales by us during this period
could have a material adverse effect on the timing of our cash flows and
therefore our ability to service our obligations with respect to our existing
and future indebtedness.
Terrorist
attacks and threats, escalation of military activity in response to such
attacks
or acts of war may negatively affect our business, financial condition and
results of operations.
Terrorist
attacks and threats, escalation of military activity in response to such
attacks
or acts of war may negatively affect our business, financial condition, and
results of operations. Our business is affected by general economic conditions,
fluctuations in consumer confidence and spending, and market liquidity, which
can decline as a result of numerous factors outside of our control, such
as
terrorist attacks and acts of war. Future terrorist attacks against
U.S. targets, rumors or threats of war, actual conflicts involving the
United States or its allies, or military or trade disruptions affecting our
customers may materially adversely affect our operations and those of our
customers. As a result, there could be delays or losses in transportation
and
deliveries of coal to our customers, decreased sales of our coal and extension
of time for payment of accounts receivable from our customers. Strategic
targets
such as energy-related assets may be at greater risk of future terrorist
attacks
than other targets in the United States. In addition, disruption or significant
increases in energy prices could result in government-imposed price controls.
It
is possible that any of these occurrences, or a combination of them, could
have
a material adverse effect on our business, financial condition and results
of
operations.
If
we are unable to accurately estimate the overall risks or costs when we bid
on a
road construction contract which is ultimately awarded to us, we may achieve
a
lower than anticipated profit or incur a loss on the
contract.
A
larger percentage
of our
road construction revenues and contract backlog are typically derived from
fixed
unit price contracts. Fixed unit price contracts require us to perform the
contract for a fixed unit price irrespective of our actual costs. As a result,
we realize a profit on these contracts only if we successfully estimate our
costs and then successfully control actual costs and avoid cost overruns.
If our
cost estimates for a contract are inaccurate, or if we do not execute the
contract within our cost estimates, then cost overruns may cause us to incur
losses or cause the contract not to be as profitable as we expected. 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;
|
|
•
|
availability
and skill level of workers in the geographic location of a project;
|
|
•
|
our
suppliers’ or subcontractors’ failure to perform;
|
|
•
|
mechanical
problems with our machinery or equipment;
|
|
•
|
citations
issued by a governmental authority, including the Occupational
Safety and
Health Administration and the Mine Safety and Health Administration;
|
|
•
|
difficulties
in obtaining required governmental permits or approvals;
|
|
•
|
changes
in applicable laws and regulations; and
|
|
•
|
claims
or demands from third parties alleging damages arising from our
work.
|
|
Item
1B.
|
Unresolved
Staff Issues
|
None
|
Item
2.
|
Properties
|
Coal
Reserves
We
estimate that, as of December 31, 2006, we owned or leased total proven and
probable coal reserves of approximately 548.6 million tons. We believe that
our total proven and probable reserves will support current production levels
for more than 20 years. “Reserves” are defined by SEC Industry Guide 7 as
that part of a mineral deposit which could be economically and legally extracted
or produced at the time of the reserve determination. “Proven (Measured)
Reserves” are defined by SEC Industry Guide 7 as reserves for which
(1) quantity is computed from dimensions revealed in outcrops, trenches,
workings or drill holes; grade and/or quality are computed from the results
of
detailed sampling and (2) the sites for inspection, sampling and
measurement are spaced so closely and the geologic character is so well defined
that size, shape, depth and mineral content of reserves are well-established.
“Probable reserves” are defined by SEC Industry Guide 7 as reserves for which
quantity and grade and/or quality are computed from information similar to
that
used for proven (measured) reserves, but the sites for inspection,
sampling, and measurement are farther apart or are otherwise less adequately
spaced. The degree of assurance, although lower than that for proven
(measured) reserves, is high enough to assume continuity between points of
observation.
Information
about our reserves consists of estimates based on engineering, economic and
geological data assembled and analyzed by our internal engineers, geologists
and
finance associates. We periodically update our reserve estimates to reflect
past
coal production, new drilling information and other geological or mining
data,
and acquisitions or sales of coal properties. Coal tonnages are categorized
according to coal quality, mining method, permit status, mineability and
location relative to existing mines and infrastructure. In accordance with
applicable industry standards, proven reserves are those for which reliable
data
points are spaced no more than 2,700 feet apart. Probable reserves are
those for which reliable data points are spaced 2,700 feet to
7,900 feet apart. Further scrutiny is applied using geological criteria and
other factors related to profitable extraction of the coal. These criteria
include seam height, roof and floor conditions, yield and
marketability.
We
periodically retain outside experts to independently verify our estimates
of our
coal reserves. The most recent of these reviews for our operations other
than
the Callaway and Progress reserves was completed in November 2004, and we
obtained an independent third party review of the Callaway reserves that
was
completed in September 2005 as well as an independent third party review
of the
Progress reserves upon acquisition in May 2006. These reviews included 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. Geological Survey Circular 891. Reserve estimates were developed using
criteria to assure that the basic geologic characteristics of the reserves
(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 mine operation capabilities
on
our various properties. As
a
result of the November 2004 review, we increased our reserve estimate from
326.5 million tons as of January 1, 2004 to 514.5 million tons as
of October 15, 2004.
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.
Five percent of our reserve holdings are owned and require no royalty or
per-ton
payment to other parties. The average royalties paid by us for coal reserves
from our producing properties was $3.24
per ton
in 2006, representing 4.5% of our 2006 coal sales 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, 2006.
|
Recoverable
Reserves Proven&
|
Sulfur
Content
|
Average
Btu
|
||||||||||||||||||||
|
Regional
Business Unit
|
State
|
Probable(1)
|
<1%
|
1.0%-1.5%
|
>1.5%
|
>12,500
|
<12,500
|
|||||||||||||||
|
(In
millions of tons)
|
||||||||||||||||||||||
|
(In
millions of tons)
|
(In
millions of tons)
|
|||||||||||||||||||||
|
Paramont/
Alpha Land and Reserves(2)
|
Virginia |
141.7
|
102.3
|
29.8
|
9.6
|
139.4
|
2.3
|
|||||||||||||||
|
Dickenson-Russell
|
Virginia |
27.7
|
27.7
|
0
|
0
|
27.7
|
0
|
|||||||||||||||
|
Kingwood
|
West Virginia |
28.0
|
0
|
17.0
|
11.0
|
28.0
|
0
|
|||||||||||||||
|
Brooks
Run
|
West Virginia |
25.2
|
6.4
|
18.8
|
0
|
10.1
|
15.1
|
|||||||||||||||
|
Welch
|
West Virginia |
89.3
|
89.3
|
0
|
0
|
89.3
|
0
|
|||||||||||||||
|
AMFIRE
|
Pennsylvania |
64.5
|
14.0
|
21.7
|
28.8
|
55.1
|
9.4
|
|||||||||||||||
|
Enterprise/Enterprise
Land & Reserve, Inc(3)
|
Kentucky |
151.1
|
49.8
|
49.2
|
52.1
|
140.5
|
10.6
|
|||||||||||||||
|
Callaway
|
West Virginia and Virginia |
21.1
|
21.1
|
0
|
0
|
9.0
|
12.1
|
|||||||||||||||
|
Totals
|
548.6
|
310.6
|
136.5
|
101.5
|
499.1
|
49.5
|
||||||||||||||||
|
Percentages
|
57
|
%
|
25
|
%
|
18
|
%
|
91
|
%
|
9
|
%
|
||||||||||||
________________
|
(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 6.5%. This moisture
factor represents the average moisture present on our delivered
coal.
|
|
|
|
|
(2)
|
Includes
proven and probable reserves in Virginia controlled by our subsidiary
Alpha Land and Reserves, LLC. Alpha Land and Reserves, LLC subleases
a
portion of the mining rights to its proven and probable reserves
in
Virginia to our subsidiary Paramont Coal Company Virginia,
LLC.
|
|
(3)
|
Includes
proven and probable reserves in Kentucky controlled by our subsidiary
Enterprise Land & Reserve Inc obtained from the Progress Energy
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, 2006.
|
Recoverable
|
||||||||||||||||||||||
|
Reserves
Proven &
|
Total
Tons
|
Total
Tons
|
||||||||||||||||||||
|
Regional
Business Unit
|
State
|
Probable(1)
|
Assigned(2)
|
Unassigned(2)
|
Owned
|
Leased
|
Coal
Type(3)
|
|||||||||||||||
|
|
(In
millions of tons)
|
|||||||||||||||||||||
|
(In
millions of tons)
|
(In
millions of tons)
|
|||||||||||||||||||||
|
Paramont/
Alpha Land and Reserves(4)
|
Virginia |
141.7
|
56.5
|
85.2
|
0
|
141.7
|
Steam
and Metallurgical
|
|||||||||||||||
|
Dickenson-Russell
|
Virginia |
27.7
|
27.7
|
0
|
0
|
27.7
|
Steam
and Metallurgical
|
|||||||||||||||
|
Kingwood
|
West Virginia |
28.0
|
19.6
|
8.4
|
0
|
28.0
|
Steam
and Metallurgical
|
|||||||||||||||
|
Brooks
Run
|
West Virginia |
25.2
|
12.5
|
12.7
|
2.4
|
22.8
|
Steam
and Metallurgical
|
|||||||||||||||
|
Welch
|
West Virginia |
89.3
|
43.4
|
45.9
|
1.1
|
88.2
|
Steam
and Metallurgical
|
|||||||||||||||
|
AMFIRE.
|
Pennsylvania |
64.5
|
60.2
|
4.3
|
3.5
|
61.0
|
Steam
and Metallurgical
|
|||||||||||||||
|
Enterprise/Enterprise
Land and Reserve Inc(5)
|
Kentucky |
151.1
|
17.9
|
133.2
|
20.2
|
130.9
|
Steam
|
|||||||||||||||
|
Callaway
|
West Virginia and Virginia |
21.1
|
18.9
|
2.2
|
1.1
|
20.0
|
Steam
and Metallurgical
|
|||||||||||||||
|
Totals
|
548.6
|
256.7
|
291.9
|
28.3
|
520.3
|
|||||||||||||||||
|
Percentages
|
47
|
%
|
53
|
%
|
5
|
%
|
95
|
%
|
||||||||||||||
________________
|
(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 6.5%. This moisture
factor represents the average moisture present on our delivered
coal.
|
|
(2)
|
Assigned
reserves represent recoverable coal reserves that can be mined
without a
significant capital expenditure for mine development, whereas unassigned
reserves will require significant capital expenditures to mine
the
reserves.
|
|
(3)
|
Almost
all of our reserves that we currently market as metallurgical coal
also
possess quality characteristics that would enable us to market
them as
steam coal.
|
|
(4)
|
Includes
proven and probable reserves in Virginia controlled by our subsidiary
Alpha Land and Reserves, LLC. Alpha Land and Reserves, LLC subleases
a
portion of the mining rights to its proven and probable reserves
in
Virginia to our subsidiary Paramont Coal Company Virginia,
LLC.
|
|
(5)
|
Includes
proven and probable reserves in Kentucky controlled by our subsidiary
Enterprise Land & Reserve Inc obtained from the Progress Energy
acquisition.
|
The
following map shows the locations of Alpha’s properties, including the number of
mines and preparation plants as of February 1, 2007 and 2006 production of
saleable tons for each of our eight regional business units:
See
Item 1. Business, of this report for additional information regarding our
coal operations and properties.
|
Item 3.
|
Legal
Proceedings
|
General.
We are a
party to a number of legal proceedings incident to our normal business
activities. While we cannot predict the outcome of these proceedings, we
do not
believe that any liability arising from these matters individually or in
the
aggregate should have a material impact upon our consolidated cash flows,
results of operations or financial condition.
|
Item 4.
|
Submission
of Matters to a Vote of Security
Holders
|
There
were no matters submitted to a vote of security holders of Alpha Natural
Resources, Inc. through a solicitation of proxies or otherwise during the
fourth
quarter of the Company’s fiscal year ended December 31, 2006.
PART II
|
Item 5.
|
Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity
Securities
|
The
initial public offering of our common stock commenced on February 15, 2005.
The Company’s common stock has been listed on the New York Stock Exchange since
that time under the symbol “ANR.” There was no public market for our common
stock prior to this date.
Price
range of our common stock
Trading
in our common stock commenced on the New York Stock Exchange on
February 15, 2005 under the symbol “ANR”. The following table sets forth,
for the periods indicated, the high and low sales prices per share of our
common
stock reported in the New York Stock Exchange consolidated tape.
|
2005
|
High
|
Low
|
|||||
|
First
Quarter
|
$
|
30.50
|
$
|
21.65
|
|||
|
Second
Quarter
|
29.50
|
22.00
|
|||||
|
Third
Quarter
|
32.73
|
23.83
|
|||||
|
Fourth
Quarter
|
30.47
|
18.70
|
|||||
|
2006
|
High
|
Low
|
|||||
|
First
Quarter
|
$
|
23.43
|
$
|
19.48
|
|||
|
Second
Quarter
|
25.50
|
20.37
|
|||||
|
Third
Quarter
|
19.14
|
15.10
|
|||||
|
Fourth
Quarter
|
16.51
|
14.42
|
|||||
As
of January 15, 2007, there were approximately 255 registered holders of record
of our common stock, including 192 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.
Equity
Compensation Plan Information
|
Plan
Category
|
(a)
Number of
securities
to be issued
upon
exercise of
outstanding
options,
warrants
and rights
|
(b)
Weighted-
average
exercise
price
of
outstanding
options,
warrants
and
rights
|
(c)
Number of securities
remaining
available for
future
issuance under
equity
compensation
plans
(excluding
securities
reflected in
column
(a))
|
|||||||
|
Equity
compensation plans approved by security holders
|
1,608,739
|
$
|
18.02
|
1,955,318
|
(1)
|
|||||
|
Equity
compensation plans not approved by security holders
|
—
|
—
|
—
|
|||||||
|
Total
|
1,608,739
|
$
|
18.02
|
1,955,318
|
||||||
|
(1)
|
The
Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan has
1,955,318 shares of common stock available for future issuance to
qualified participants as of December 31,
2006.
|
|
Item 6.
|
Selected
Financial Data
|
The
following table presents selected financial and other data about us and
our
Predecessor for the most recent five fiscal periods. The selected financial
data
as of December 31, 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, included elsewhere in this annual report.
The selected historical financial data as of December 31, 2003 and for the
year
then ended and for the period from December 14, 2002 to December 31, 2002
have
been derived from the audited combined balance sheet of ANR Fund IX Holdings,
L.P. and Alpha NR Holding, Inc. and subsidiaries not included in this annual
report. The selected historical financial data for the period from January
1,
2002 through December 13, 2002 (the “Predecessor Period”) have been derived from
our Predecessor’s combined financial statements 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
|
Predecessor
|
|||||||||||||||||
|
Year
Ended December 31, 2006
|
Year
Ended December 31, 2005
|
Year
Ended December 31, 2004
|
Year
Ended December 31, 2003
|
December
14, 2002 to December 31, 2002
|
January
1, 2002 to December 13, 2002
|
||||||||||||||
|
(In
thousands, except per share
amounts)
|
|||||||||||||||||||
|
Statement
of Operations Data:
|
|||||||||||||||||||
|
Revenues:
|
|||||||||||||||||||
|
Coal
revenues
|
$
|
1,687,553
|
$
|
1,413,174
|
$
|
1,079,981
|
$
|
694,596
|
$
|
6,260
|
$
|
154,715
|
|||||||
|
Freight
and handling revenues
|
188,366
|
185,555
|
141,100
|
73,800
|
1,009
|
17,001
|
|||||||||||||
|
Other
revenues
|
34,743
|
27,926
|
28,347
|
13,453
|
101
|
6,031
|
|||||||||||||
|
Total
revenues
|
1,910,662
|
1,626,655
|
1,249,428
|
781,849
|
7,370
|
177,747
|
|||||||||||||
|
Costs
and expenses:
|
|||||||||||||||||||
|
Cost
of coal sales (exclusive of items shown separately below)
|
1,352,450
|
1,184,092
|
920,359
|
626,265
|
6,268
|
158,924
|
|||||||||||||
|
Freight
and handling costs
|
188,366
|
185,555
|
141,100
|
73,800
|
1,009
|
17,001
|
|||||||||||||
|
Cost
of other revenues
|
22,982
|
23,675
|
22,994
|
12,488
|
120
|
7,973
|
|||||||||||||
|
Depreciation,
depletion and amortization
|
140,851
|
73,122
|
55,261
|
35,385
|
274
|
6,814
|
|||||||||||||
|
Selling,
general and administrative expenses (exclusive of depreciation
and
amortization shown separately above)
|
67,952
|
88,132
|
40,607
|
21,926
|
471
|
8,797
|
|||||||||||||
|
Costs
to exit business
|
—
|
—
|
—
|
—
|
—
|
25,274
|
|||||||||||||
|
Total
costs and expenses
|
1,772,601
|
1,554,576
|
1,180,321
|
769,864
|
8,142
|
224,783
|
|||||||||||||
|
Refund
of federal black lung excise tax
|
—
|
—
|
—
|
—
|
—
|
2,049
|
|||||||||||||
|
Other
operating income, net
|
—
|
—
|
—
|
—
|
—
|
1,430
|
|||||||||||||
|
Income
(loss) from operations
|
138,061
|
72,079
|
69,
107
|
11,985
|
(772
|
)
|
(45,557
|
)
|
|||||||||||
|
Other
income (expense):
|
|||||||||||||||||||
|
Interest
expense
|
(41,774
|
)
|
(29,937
|
)
|
(20,041
|
)
|
(7,848
|
)
|
(203
|
)
|
(35
|
)
|
|||||||
|
Interest
income
|
839
|
1,064
|
531
|
103
|
6
|
2,072
|
|||||||||||||
|
Miscellaneous
income
|
523
|
91
|
722
|
574
|
—
|
—
|
|||||||||||||
|
Total
other income (expense), net
|
(40,412
|
)
|
(28,782
|
)
|
(18,788
|
)
|
(7,171
|
)
|
(197
|
)
|
2,037
|
||||||||
|
Income
(loss) before income taxes and minority interest
|
97,649
|
43,297
|
50,319
|
4,814
|
(969
|
)
|
(41,520
|
)
|
|||||||||||
|
Income
tax expense (benefit)
|
(30,519
|
)
|
18,953
|
5,150
|
898
|
(334
|
)
|
(17,198
|
)
|
||||||||||
|
Minority
interest
|
—
|
2,918
|
22,781
|
1,164
|
—
|
—
|
|||||||||||||
|
Income
(loss) from continuing operations
|
128,168
|
21,426
|
22,388
|
2,752
|
(635
|
)
|
(24,322
|
)
|
|||||||||||
|
Loss
from discontinued operations
|
—
|
(213
|
)
|
(2,373
|
)
|
(490
|
)
|
—
|
—
|
||||||||||
|
Net
income (loss)
|
$
|
128,168
|
$
|
21,213
|
$
|
20,015
|
$
|
2,262
|
$
|
(635
|
)
|
$
|
(24,322
|
)
|
|||||
|
Alpha
Natural Resources, Inc and Subsidiaries
|
ANR
FUND IX Holdings, L.P. and Alpha NR Holding, Inc. and
Subsidiaries
|
Predecessor
|
|||||||||||||||||
|
Year
Ended December 31, 2006
|
Year
Ended December 31, 2005
|
Year
Ended December 31, 2004
|
Year
Ended December 31, 2003
|
December
14, 2002 to December 31, 2002
|
January
1, 2002 to December 13, 2002
|
||||||||||||||
|
(In
thousands, except per share and per ton
amounts)
|
|||||||||||||||||||
|
Earnings
per share data:
|
|||||||||||||||||||
|
Net
income (loss) per share, as adjusted(1)
|
|||||||||||||||||||
|
Basic
and diluted:
|
|||||||||||||||||||
|
Income
from continuing operations
|
$
|
2.00
|
$
|
0.38
|
$
|
1.52
|
$
|
0.19
|
|||||||||||
|
Loss
from discontinued operations
|
—
|
—
|
(0.16
|
)
|
(0.04
|
)
|
|||||||||||||
|
Net
income per basic and diluted share
|
$
|
2.00
|
$
|
0.38
|
$
|
1.36
|
$
|
0.15
|
|||||||||||
|
Pro
forma net income (loss) per share(2)
|
|||||||||||||||||||
|
Basic
and diluted:
|
|||||||||||||||||||
|
Income
from continuing operations
|
$
|
0.35
|
$
|
0.25
|
|||||||||||||||
|
Loss
from discontinued operations
|
—
|
(0.07
|
)
|
||||||||||||||||
|
Net
income per basic and diluted share
|
$
|
0.35
|
$
|
0.18
|
|||||||||||||||
|
Balance
sheet data (at period end):
|
|||||||||||||||||||
|
Cash
and cash equivalents
|
$
|
33,256
|
$
|
39,622
|
$
|
7,391
|
$
|
11,246
|
$
|
8,444
|
$
|
88
|
|||||||
|
Operating
and working capital
|
116,464
|
35,074
|
56,257
|
32,714
|
(12,223
|
)
|
4,268
|
)
|
|||||||||||
|
Total
assets
|
1,145,793
|
1,013,658
|
477,121
|
379,336
|
108,442
|
156,328
|
|||||||||||||
|
Notes
payable and long-term debt, including current portion
|
445,651
|
485,803
|
201,705
|
84,964
|
25,743
|
—
|
|||||||||||||
|
Stockholders’
equity and partners’ capital (deficit)
|
344,049
|
212,765
|
45,933
|
86,367
|
23,384
|
(132,997
|
)
|
||||||||||||
|
Statement
of cash flows data:
|
|||||||||||||||||||
|
Net
cash provided by (used in):
|
|||||||||||||||||||
|
Operating
activities
|
$
|
210,081
|
$
|
149,643
|
$
|
106,776
|
$
|
54,104
|
$
|
(295
|
)
|
$
|
(13,816
|
)
|
|||||
|
Investing
activities
|
(160,046
|
)
|
(339,387
|
)
|
(86,202
|
)
|
(100,072
|
)
|
(38,893
|
)
|
(22,054
|
)
|
|||||||
|
Financing
activities
|
(56,401
|
)
|
221,975
|
(24,429
|
)
|
48,770
|
47,632
|
35,783
|
)
|
||||||||||
|
Capital
expenditures
|
131,943
|
122,342
|
72,046
|
27,719
|
960
|
21,866
|
|||||||||||||
|
Other
data
|
|||||||||||||||||||
|
Production:
|
|||||||||||||||||||
|
Produced/processed
|
24,827
|
20,602
|
19,069
|
17,199
|
|||||||||||||||
|
Purchased
|
4,090
|
6,284
|
6,543
|
3,938
|
|||||||||||||||
|
Total
|
28,917
|
26,886
|
25,612
|
21,137
|
|||||||||||||||
|
Tons
Sold:
|
|||||||||||||||||||
|
Steam
|
19,050
|
16,674
|
15,836
|
14,809
|
|||||||||||||||
|
Met
|
10,029
|
10,023
|
9,490
|
6,804
|
|||||||||||||||
|
Total
|
29,079
|
26,697
|
25,326
|
21,613
|
|||||||||||||||
|
Coal
sales realization/ton:
|
|||||||||||||||||||
|
Steam
|
$
|
49.05
|
$
|
41.33
|
$
|
32.66
|
$
|
27.14
|
|||||||||||
|
Met
|
$
|
75.09
|
$
|
72.24
|
$
|
59.31
|
$
|
37.35
|
|||||||||||
|
Total
|
$
|
58.03
|
$
|
52.93
|
$
|
42.64
|
$
|
32.14
|
|||||||||||
|
Cost
of coal sales/ton
|
$
|
46.51
|
$
|
44.35
|
$
|
36.34
|
$
|
28.98
|
|||||||||||
|
Coal
margin/ton
|
$ | 11.52 | $ | 8.58 | $ | 6.30 | $ |
3.16
|
|||||||||||
|
EBITDA,
as adjusted(3)
|
$
|
279,435
|
$
|
145,197
|
$
|
119,327
|
$
|
47,663
|
|
|
|
||||||||
|
(1)
|
Basic
earnings per share is computed by dividing net income or loss by
the
weighted average number of shares of common stock outstanding during
the
periods. Diluted earnings per share is computed by dividing net
income or
loss by the weighted average number of shares of common stock and
dilutive
common stock equivalents outstanding during the periods. Common
stock
equivalents include the number of shares issuable on exercise of
outstanding options less the number of shares that could have been
purchased with the proceeds from the exercise of the options based
|