As
filed with the Securities and Exchange Commission on
February 10, 2012.
Registration
Statement No. 333-177259
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Amendment No. 3
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
ARMSTRONG ENERGY,
INC.
(Exact name of registrant as
specified in its charter)
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Delaware
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1221
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20-8015664
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(State or other jurisdiction
of
incorporation or organization)
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(Primary Standard Industrial
Classification Code Number)
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(IRS Employer
Identification No.)
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7733 Forsyth Boulevard,
Suite 1625
St. Louis, Missouri
63105
(314) 721-8202
(Address, including zip code,
and telephone number, including area code, of registrants
principal executive offices)
Martin D. Wilson
Armstrong Energy, Inc.
7733 Forsyth Boulevard,
Suite 1625
St. Louis, Missouri
63105
(314) 721-8202
(Name, address, including zip
code, and telephone number, including area code, of agent for
service)
With copies to:
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David W. Braswell, Esq.
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D. Rhett Brandon, Esq.
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Armstrong Teasdale LLP
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Simpson Thacher & Bartlett LLP
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7700 Forsyth Boulevard, Suite 1800
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425 Lexington Avenue
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St. Louis, Missouri 63105
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New York, New York 10017
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(314) 552-6631
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(212) 455-2000
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Approximate date of commencement of proposed sale to the
public: As soon as practicable after this
Registration Statement is declared effective.
If any securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act of 1933, check the
following
box. o
If this Form is filed to register additional securities for an
offering pursuant to Rule 462(c) under the Securities Act,
please check the following box and list the Securities Act
registration statement number of the earlier effective
registration statement for the same
offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(c) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
accelerated
filer o
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Accelerated
filer o
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Non-accelerated
filer þ
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Smaller reporting
company o
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(Do not check if a smaller
reporting company)
The Registrant hereby amends this Registration Statement on
such date or dates as may be necessary to delay its effective
date until the registrant shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act of 1933, as amended, or until the
Registration Statement shall become effective on such date as
the Securities and Exchange Commission, acting pursuant to said
Section 8(a), may determine.
The
information in this preliminary prospectus is not complete and
may be changed. We may not sell these securities until the
registration statement filed with the Securities and Exchange
Commission is effective. This preliminary prospectus is not an
offer to sell these securities and it is not soliciting an offer
to buy these securities in any state where the offer of sale is
not permitted.
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PRELIMINARY
PROSPECTUS |
SUBJECT TO COMPLETION, DATED FEBRUARY 10, 2012 |
Shares
ARMSTRONG ENERGY, INC.
Common Stock
This is the initial public offering of our common stock. We are
offering shares
of our common stock, par value $0.01 per share. No public market
currently exists for our common stock. We currently expect the
initial public offering price to be between
$ and
$ per share.
We expect to apply to list our common stock on the Nasdaq Global
Market (Nasdaq) under the symbol ARMS.
There is no assurance that this application will be approved.
Investing in our common stock involves risks. You should read
the section entitled Risk Factors beginning on
page 16 for a discussion of certain risk factors that you
should consider before investing in our common stock.
Neither the Securities and Exchange Commission nor any other
regulatory body has approved or disapproved of these securities
or passed upon the adequacy or accuracy of this registration
statement. Any representation to the contrary is a criminal
offense.
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Per Share
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Total
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Public offering price
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$
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$
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Underwriting discount
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$
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$
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Offering proceeds to Armstrong Energy, Inc. before expenses
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$
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$
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To the extent the underwriters sell more
than shares
of common stock, the underwriters have an option exercisable
within 30 days from the date of this prospectus to purchase
up
to
additional shares of common stock from us at the public offering
price, less the underwriting discount. The shares of common
stock issuable upon exercise of the underwriters
over-allotment option have been registered under the
registration statement of which this prospectus forms a part.
The underwriters expect to deliver the shares against payment in
New York, New York on or
about ,
2012.
Prospectus,
dated ,
2012
TABLE OF
CONTENTS
No dealer, salesperson or other individual has been
authorized to give any information or to make any representation
other than those contained in this prospectus in connection with
the offer made by this prospectus and, if given or made, such
information or representations must not be relied upon as having
been authorized by us or the underwriters. This prospectus does
not constitute an offer to sell or a solicitation of an offer to
buy any securities in any jurisdiction in which such an offer or
solicitation is not authorized or in which the person making
such offer or solicitation is not qualified to do so, or to any
person to whom it is unlawful to make such offer or
solicitation. Neither the delivery of this prospectus nor any
sale made hereunder shall, under any circumstances, create any
implication that there has been no change in our affairs or that
information contained herein is correct as of any time
subsequent to the date hereof.
i
ABOUT
THIS PROSPECTUS
You should rely only on the information contained in this
prospectus. We have not, and the underwriters have not,
authorized any other person to provide you with information
different from that contained in this prospectus. If anyone
provides you with different or inconsistent information, you
should not rely on it. We and the underwriters are only offering
to sell, and only seeking offers to buy, the common stock in
jurisdictions where offers and sales are permitted.
The information contained in this prospectus is accurate and
complete only as of the date of this prospectus, regardless of
the time of delivery of this prospectus or of any sale of our
common stock by us or the underwriters. Our business, financial
condition, results of operations and prospectus may have changed
since that date.
Market data used in this prospectus has been obtained from
independent industry sources and publications, as well as from
research reports prepared for other purposes. The information in
these reports represents the most recently available data from
the relevant sources and publications and we believe remains
reliable. We engaged Weir International, Inc., an independent
mining and geological consultant, to prepare a report regarding
estimates of our proven and probable coal reserves at December
31, 2010. In addition, we pay a subscription fee to Wood
Mackenzie to obtain access to pre-prepared reports. Except with
respect to payment for Weir International, Inc.s services
in this regard and the subscription fee paid to Wood Mackenzie,
we did not fund and are not otherwise affiliated with any of the
sources cited in this prospectus. Forward-looking information
obtained from these sources is subject to the same
qualifications and additional uncertainties regarding the other
forward-looking statements in this prospectus.
Unless the context otherwise requires, the information in the
prospectus (other than in the historical financial statements)
assumes that the underwriters will not exercise their
over-allotment option.
For investors outside the United States: We have not, and the
underwriters have not, done anything that would permit this
offering or possession or distribution of this prospectus in any
jurisdiction where action for that purpose is required, other
than in the United States. Persons outside the United States who
come into possession of this prospectus must inform themselves,
and observe any restrictions relating to, the offering of the
shares of our common stock and the distribution of this
prospectus outside the United States.
ii
PROSPECTUS
SUMMARY
This summary highlights information contained elsewhere in
this prospectus, but it does not contain all of the information
that you may consider important in making your investment
decision. Therefore, you should read the entire prospectus
carefully, including, in particular, the Risk
Factors section beginning on page 14 of this
prospectus and the financial statements and related notes
thereto included elsewhere in this prospectus.
As used in this prospectus, unless the context otherwise
requires or indicates, references to the Company,
we, our, and us are to
Armstrong Energy, Inc., Armstrong Resource Partners, L.P. and
their respective subsidiaries taken as a whole, after giving
effect to the Reorganization referred to herein. References to
Armstrong Resource Partners are to Armstrong
Resource Partners, L.P. and its subsidiaries taken as a whole.
References to Armstrong Energy are to Armstrong
Energy, Inc. and its subsidiaries, and do not include Armstrong
Resource Partners.
A subsidiary of Armstrong Energy, Inc. is the general partner
of, and owns a 0.4% equity interest in, Armstrong Resource
Partners. By virtue of Armstrong Energy, Inc.s control of
the general partner of Armstrong Resource Partners, the results
of Armstrong Resource Partners are consolidated in our
historical consolidated financial statements contained
herein.
As described more fully below, concurrently with the offering
of common stock of Armstrong Energy, Inc. being made pursuant to
this prospectus, Armstrong Resource Partners is engaging in an
offering of its limited partnership units. This prospectus
relates solely to the offering of the common stock of Armstrong
Energy, Inc. and does not relate to the concurrent offering by
Armstrong Resource Partners, which will be made by a separate
prospectus.
About the
Company
We are a diversified producer of low chlorine, high sulfur
thermal coal from the Illinois Basin, with both surface and
underground mines. We market our coal primarily to electric
utility companies as fuel for their steam-powered generators.
Based on 2010 production, we are the sixth largest producer in
the Illinois Basin and the second largest in Western Kentucky.
We were formed in 2006 to acquire and develop a large coal
reserve holding. We commenced production in the second quarter
of 2008 and currently operate six mines, including four surface
and two underground, and are seeking permits for four additional
mines. We control approximately 319 million tons of proven
and probable coal reserves. Our reserves and operations are
located in the Western Kentucky counties of Ohio, Muhlenberg,
Union and Webster. We also own and operate three coal processing
plants which support our mining operations. The location of our
coal reserves and operations, adjacent to the Green and Ohio
Rivers, together with our river dock coal handling and rail
loadout facilities, allow us to optimize our coal blending and
handling, and provide our customers with rail, barge and truck
transportation options. From our reserves, we mine coal from
multiple seams which, in combination with our coal processing
facilities, enhances our ability to meet customer requirements
for blends of coal with different characteristics.
Our revenue has increased from zero in 2007 to
$220.6 million in 2010, which we achieved despite a period
of recession-driven declines in U.S. demand for coal and a
challenging environment in the credit markets. For the year
ended December 31, 2010, we generated operating income of
$19.2 million and Adjusted EBITDA of $41.1 million.
Our operating income and Adjusted EBITDA for the nine months
ended September 30, 2011 were $6.4 million and
$32.1 million, respectively. Adjusted EBITDA is a non-GAAP
financial measure which represents net income (loss) before net
interest expense, income taxes, depreciation, depletion and
amortization, non-cash stock compensation expense, non-cash
charges related to non-recourse notes, and gain on
extinguishment of debt. For these purposes, GAAP
refers to U.S. generally accepted accounting principles.
Please see Summary Historical and Unaudited
Pro Forma Consolidated Financial and Operating Data for a
reconciliation of Adjusted EBITDA to net income (loss).
For the year ended December 31, 2010, we produced
5.6 million tons of coal from three surface and two
underground mines. During the first nine months of fiscal 2011,
we produced 5.1 million tons of coal, with seven mines in
operation. We currently expect a significant increase in our
production for 2011 compared to 2010. We are contractually
committed to sell 7.6 million tons of coal in 2011, which
represents substantially
1
all of our currently estimated production for 2011. Similarly,
as of September 30, 2011, we are contractually committed to
sell 8.8 million tons of coal in 2012 and 8.1 million tons
of coal in 2013, which represents 99% and 83% of our expected
total coal sales in 2012 and 2013, respectively. The following
table summarizes our mines, our recent production and our coal
reserves as of December 31, 2010:
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Quality Specifications
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Production
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(As Received)(2)
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Clean Recoverable Tons
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Nine
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(Proven and Probable
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Year
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Months
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SO2
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Reserves)(1)
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Ended
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Ended
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Heat
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Content
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Mines
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Mining
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Proven
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Probable
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December 31,
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September 30,
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Value
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(Lbs/
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Ash
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(Commenced Operations)
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Method(3)
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Reserves
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Reserves
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Total
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2010
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2011
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(Btu/Lb)
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MMBtu)
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(%)
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(In thousands)
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(Tons in thousands)
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Active mines
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Big Run (April 2008)(4)
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U
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2,849
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242
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3,091
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(5)
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572.1
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361.5
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11,822
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4.3
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7.4
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Midway (July 2008)
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S
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24,806
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3,507
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28,313
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(5)
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1,614.8
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1,290.4
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11,315
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4.8
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10.0
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Parkway (April 2009)
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U
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1,952
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58
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2,010
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(5)
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1,485.9
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1,165.6
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11,931
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4.4
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7.1
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East Fork (June 2009)(6)
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S
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2,633
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553
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3,186
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(5)
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1,641.1
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608.6
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11,136
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7.6
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11.2
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Equality Boot (September 2010)
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S
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23,687
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1,148
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24,835
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(7)
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330.8
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1,493.3
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11,587
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5.7
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8.8
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Lewis Creek (June 2011)
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S
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6,650
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70
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6,720
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(5)
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197.0
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11,420
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4.0
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9.5
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Kronos (September 2011)(8)
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U
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18,862
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3,002
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21,864
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9.6
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11,792
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4.5
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7.6
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Total active mines
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81,439
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8,580
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90,019
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5,644.7
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5,126.0
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Additional reserves
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Lewis Creek(8)
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U
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18,862
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3,002
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21,864
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11,792
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4.5
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7.6
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Ceralvo(8)
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U
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18,862
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3,002
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21,864
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11,792
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4.5
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7.6
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Ken
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S
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17,166
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3,854
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21,020
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(5)
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11,809
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5.0
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7.5
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Union/Webster Counties
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U
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43,853
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71,783
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115,637
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(9)
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12,145
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4.4
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8.2
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Other
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S/U
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37,233
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11,648
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48,881
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(10)
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11,300
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4.5
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8.0
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Total additional reserves
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135,976
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93,289
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229,265
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Total
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217,415
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101,869
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319,284
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(1) |
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For surface mines, clean recoverable tons are based on a 90%
mining recovery, preparation plant yield at 1.55 specific
gravity and a 95% preparation plant efficiency. For underground
mines other than Union/Webster Counties, clean recoverable tons
are based on a 50% mining recovery, preparation plant yield at
1.55 specific gravity and a 95% preparation plant efficiency.
For Union/Webster Counties, clean recoverable tons are based on
a 50% mining recovery, preparation plant yield at 1.60 specific
gravity and a 95% preparation plant efficiency. Proven and
probable reserves refers to coal that can be economically
extracted or produced at the time of the reserve determination. |
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(2) |
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Quality specifications displayed on an as received
basis, assuming 11% moisture. If derived from multiple seams,
data represents an average. |
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(3) |
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U = Underground; S = Surface |
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(4) |
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Big Run ceased production in October 2011. |
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(5) |
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Of these reserves, 39.45% of the interests controlled by
Armstrong Energy are leased from Armstrong Resource Partners. |
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(6) |
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Warden and Kronos pits. |
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(7) |
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Of these reserves, 39.45% of the interests controlled by
Armstrong Energy are leased from Armstrong Resource Partners.
Includes 167,000 tons related to reserves for which we own or
lease a 50% or more partial joint interest and royalties on
extractions may be payable to other owners. |
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(8) |
|
Based on internal estimates, recoverable reserves are split
evenly among the three mines that will produce coal from the
underground properties and coal reserves located in Ohio County,
Kentucky that are owned by Armstrong Resource Partners and
leased to Armstrong Energy (the Elk Creek Reserves). |
|
(9) |
|
Includes 3,235,000 tons related to reserves for which we
own or lease a 50% or more partial joint interest and royalties
on extractions may be payable to other owners. |
|
(10) |
|
Of these reserves, 39.45% of the interests controlled by
Armstrong Energy are leased from Armstrong Resource Partners.
Includes 972,000 tons related to reserves for which we own
or lease a 50% or more partial joint interest and royalties on
extractions may be payable to other owners. |
2
The following table shows the ownership status of our reserves
by mine:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Clean Recoverable Tons (Proven and Probable
|
|
Mines
|
|
Reserves)(1)
|
|
(Commenced Operations)
|
|
Owned
|
|
|
Leased
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Active mines
|
|
|
|
|
|
|
|
|
|
|
|
|
Big Run (April 2008)(2)
|
|
|
3,091
|
|
|
|
|
|
|
|
3,091
|
(3)
|
Midway (July 2008)
|
|
|
28,313
|
|
|
|
|
|
|
|
28,313
|
(3)
|
Parkway (April 2009)
|
|
|
312
|
|
|
|
1,698
|
|
|
|
2,010
|
(3)
|
East Fork (June 2009)(4)
|
|
|
2,302
|
|
|
|
884
|
|
|
|
3,186
|
(3)
|
Equality Boot (September 2010)
|
|
|
24,835
|
|
|
|
|
|
|
|
24,835
|
(5)
|
Lewis Creek (surface) (June 2011)
|
|
|
6,720
|
|
|
|
|
|
|
|
6,720
|
(3)
|
Kronos (September 2011)(6)
|
|
|
20,689
|
|
|
|
1,175
|
|
|
|
21,864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total active mines
|
|
|
|
|
|
|
|
|
|
|
90,019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Lewis Creek(6)
|
|
|
20,689
|
|
|
|
1,175
|
|
|
|
21,864
|
|
Ceralvo(6)
|
|
|
20,689
|
|
|
|
1,175
|
|
|
|
21,864
|
|
Ken
|
|
|
21,020
|
|
|
|
|
|
|
|
21,020
|
(3)
|
Union/Webster Counties
|
|
|
|
|
|
|
115,637
|
|
|
|
115,637
|
(7)
|
Other
|
|
|
32,149
|
|
|
|
16,732
|
|
|
|
48,881
|
(8)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total additional reserves
|
|
|
|
|
|
|
|
|
|
|
229,265
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
319,284
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
For surface mines, clean recoverable tons are based on a 90%
mining recovery, preparation plant yield at 1.55 specific
gravity and a 95% preparation plant efficiency. For underground
mines other than Union/Webster Counties, clean recoverable tons
are based on a 50% mining recovery, preparation plant yield at
1.55 specific gravity and a 95% preparation plant efficiency.
For Union/Webster Counties, clean recoverable tons are based on
a 50% mining recovery, preparation plant yield at 1.60 specific
gravity and a 95% preparation plant efficiency. Proven and
probable reserves refers to coal that can be economically
extracted or produced at the time of the reserve determination. |
|
(2) |
|
Big Run ceased production in October 2011. |
|
(3) |
|
Of these reserves, 39.45% of the interests controlled by
Armstrong Energy are leased from Armstrong Resource Partners. |
|
(4) |
|
Warden and Kronos pits. |
|
(5) |
|
Of these reserves, 39.45% of the interests controlled by
Armstrong Energy are leased from Armstrong Resource Partners.
Includes 167,000 tons related to reserves for which we own or
lease a 50% or more partial joint interest and royalties on
extractions may be payable to other owners. |
|
(6) |
|
Based on internal estimates, recoverable reserves are split
evenly among the three mines that comprise the Elk Creek
Reserves (Kronos, Lewis Creek underground and Ceralvo). |
|
(7) |
|
Includes 3,235,000 tons related to reserves for which we own or
lease a 50% or more partial joint interest and royalties on
extractions may be payable to other owners. |
|
(8) |
|
Of these reserves, 39.45% of the interests controlled by
Armstrong Energy are leased from Armstrong Resource Partners.
Includes 972,000 tons related to reserves for which we own or
lease a 50% or more partial joint interest and royalties on
extractions may be payable to other owners. |
3
About
Armstrong Resource Partners
Our affiliate, Armstrong Resource Partners, was formed to manage
and lease coal properties and collect royalties in the Western
Kentucky region of the Illinois Basin. Armstrong Energy holds a
0.4% equity interest in Armstrong Resource Partners through a
wholly-owned subsidiary, Elk Creek GP, LLC (Elk Creek
GP), which is the general partner of Armstrong Resource
Partners. The outstanding limited partnership interests
(common units) of Armstrong Resource Partners,
representing 99.6% of its equity interests, are owned by
investment funds managed by Yorktown Partners LLC (collectively,
Yorktown). Armstrong Energy is majority-owned by
Yorktown. Of our total controlled reserves of 319 million
tons, 66 million tons (21%) are owned 100% by Armstrong
Resource Partners, and 138 million tons (43%) are held by
Armstrong Energy and Armstrong Resource Partners as joint
tenants in common with 60.55% and 39.45% interests, respectively.
Armstrong Energy has entered into lease agreements with
Armstrong Resource Partners pursuant to which Armstrong Resource
Partners granted Armstrong Energy leases to its 39.45% undivided
interest in the mining properties described above and licenses
to mine coal on those properties. Armstrong Energy is obligated
to pay Armstrong Resource Partners a production royalty equal to
7% of the sales price of the coal which Armstrong Energy mines
from the properties, which at the option of Armstrong Energy can
be deferred under circumstances which give Armstrong Resource
Partners the right to acquire additional reserves from Armstrong
Energy.
Armstrong Resource Partners has also entered into a lease and
sublease agreement with Armstrong Energy relating to our Elk
Creek Reserves and granted Armstrong Energy a license to mine
coal on those properties. The terms of this agreement mirror
those of the lease agreements described above. Armstrong Energy
has paid $12 million of advance royalties under the lease,
which are recoupable against production royalties.
See Business About Armstrong Resource
Partners for additional information about Armstrong
Resource Partners.
Based upon our current estimates of production for 2011 and
2012, we anticipate that Armstrong Energy will owe royalties to
Armstrong Resource Partners under the above-mentioned license
and lease arrangements of approximately $7.8 million and
$16.6 million in 2011 and 2012, respectively, of which
collectively, $7.2 million will be recoupable against the
advance royalty payment referred to above.
Concurrent
Offering
Concurrent with this offering of common stock, Armstrong
Resource Partners is offering common units pursuant to a
separate initial public offering (the Concurrent ARP
Offering). Armstrong Energy indirectly holds a 0.4% equity
interest in Armstrong Resource Partners. See
Business Our Organizational History. If
the Concurrent ARP Offering and the related transactions between
Armstrong Energy and Armstrong Resource Partners are completed,
we expect to receive the net proceeds of the Concurrent ARP
Offering and to transfer to Armstrong Resource Partners
additional undivided interests in reserves controlled jointly by
Armstrong Energy and Armstrong Resources Partners. See
Corporate Structure and Certain
Relationships and Related Party Transactions
Concurrent Transactions with Armstrong Resource Partners.
We expect to apply any proceeds received by Armstrong Energy
from these transactions to repay borrowings under our Senior
Secured Credit Facility and to use any amounts not so applied
for working capital. While Armstrong Resource Partners intends
to consummate the Concurrent ARP Offering simultaneously with
this offering of common stock, the completion of this offering
is not subject to the completion of the Concurrent ARP Offering
and the completion of the Concurrent ARP Offering is not subject
to the completion of this offering. This description and other
information in this prospectus regarding the Concurrent ARP
Offering is included in this prospectus solely for informational
purposes. Nothing in this prospectus should be construed as an
offer to sell, nor the solicitation of an offer to buy, any
common units of Armstrong Resource Partners.
4
Coal
Industry Overview
According to the U.S. Department of Energys Energy
Information Administration (EIA), the U.S. coal
industry produced approximately 1.1 billion tons of coal in
2010, a substantial majority of which was sold by U.S. coal
producers to operators of electricity generation plants.
Coal-fired electricity generation is the largest component of
total world electricity generation. The following market
dynamics and trends currently impact thermal coal consumption
and production in the United States and are reshaping
competitive advantages for coal producers.
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|
|
|
|
Stable long-term outlook for U.S. thermal coal
market. According to the EIA, coal-fired
electricity generation accounted for approximately 45% of all
electricity generation in the United States in 2010. Coal
continues to be the lowest cost fossil fuel source of energy for
electric power generation. Despite recent increases in
generation from natural gas, as well as federal and state
subsidies for the construction and operation of renewable
energy, the EIA projects that generation from coal will increase
by 25% from 2009 to 2035 and that coal-fired generation will
remain the largest single source of electricity generation in
2035.
|
|
|
|
Increasing demand for coal produced in the Illinois
Basin. According to Wood Mackenzie, a leading
commodities consultancy, demand for coal produced from the
Illinois Basin is expected to grow by 69% from 2009 through 2015
and by 126% from 2009 through 2030. We believe this is due to a
combination of factors including:
|
|
|
|
|
è
|
Significant expansion of scrubbed coal-fired electricity
generating capacity. The EIA forecasts a 32%
increase in flue gas desulfurization (FGD) installed
on the coal-fired generation fleet from 168 gigawatts in 2009 to
222 gigawatts, or 70% of all U.S. coal-fired capacity in
the electric sector, by 2035 as electricity generation operators
invest in retrofit emissions reduction technology to comply with
new U.S. Environmental Protection Agency (EPA)
regulations under the Cross-State Air Pollution Rule and the
proposed Utility Boiler Maximum Achievable Control Technology
(MACT) regulations. Illinois Basin coal generally
has a higher sulfur content per ton than coal produced in other
regions. However, we believe that FGD utilization will enable
operators to use the most competitively priced coal (on a
delivered cents per million Btu basis) irrespective of sulfur
content, and thus lead to a strong increase in demand for
Illinois Basin coal.
|
|
|
è
|
Declines in Central Appalachian thermal coal
production. Wood Mackenzie forecasts that
production of Central Appalachian thermal coal will continue to
decline, falling from 128 million tons in 2010 to
64 million tons in 2015, due to reserve depletion,
regulatory-driven decreases in Central Appalachian surface
thermal coal production and more difficult geological
conditions. These factors are expected to result in
significantly higher mining costs and prices for Central
Appalachian thermal coal. We believe this will lead to an
increase in demand for thermal coal from the Illinois Basin due
to its comparatively lower delivered cost to the major Eastern
U.S. utilities who are currently the principal users of
thermal coal from Central Appalachia.
|
|
|
è
|
Growing demand for seaborne thermal
coal. Global trade in thermal coal accounted for
nearly 70% of all global coal exports in 2010 and is projected
to rise from 850 million tons in 2010 to 1.1 billion
tons by 2016. We believe that limitations on existing global
export coal supply, infrastructure constraints, relative
exchange rates, coal quality and cost structure could create
significant thermal coal export opportunities for U.S. coal
producers, including Illinois Basin coal producers, particularly
those similar to us with transportation access to both the
Mississippi River and to rail connecting to Louisiana export
terminals. In addition, we believe that certain domestic users
of U.S. thermal coal will need to seek alternative sources
of domestic supply as an increasing amount of domestic coal is
sold in global export markets.
|
5
Strategy
Our primary business strategy is to maximize returns to our
stockholders. Key components of this strategy include the
following:
|
|
|
|
|
Maintain safe mining operations and comply with environmental
standards. We consider safety to be our greatest
operational priority. For the period October 1, 2010
through September 30, 2011, our underground and surface
mines had non-fatal days lost incidence rates that were 39% and
72%, respectively, below the national averages for the same
period. Non-fatal days lost incidence rate is an industry
standard used to describe occupational injuries that result in
the loss of one or more days from an employees scheduled
work. We intend to maintain programs and policies designed to
enable us to remain among the safest coal operations in the
industry. We also intend to continue to implement responsible,
effective environmental practices throughout our operations and
reclamation activities.
|
|
|
|
Continue to grow our production. We intend to
continue to increase our coal production in the coming years to
satisfy what we believe will be an increasing demand for
Illinois Basin coal. We will seek to support production growth
by executing mining plans for our existing undeveloped reserves
and by opportunistically acquiring additional coal reserves that
are located near our current mining operations or otherwise
offer the potential for efficient and economical development of
low-cost production to serve our primary market area. We
commenced production at Lewis Creek in June 2011 and at our
Kronos underground mining operation in September 2011 and
currently expect that our 2011 production will be approximately
7.2 million tons, compared with 5.6 million tons in
2010.
|
|
|
|
Increase and diversify coal sales to utilities with base load
scrubbed power plants in our primary market area and pursue
export opportunities. We expect that the demand
for Illinois Basin coal will rise as a result of an increase in
power plants being retrofitted with scrubbers and the
construction of new power plants throughout the Illinois Basin
market area. We intend to continue to focus our marketing
efforts principally on power plants in the Mid-Atlantic,
Southeastern and Midwestern states that we expect will become
consumers of Illinois Basin coal and to seek to diversify our
customer base through a combination of multi-year coal supply
agreements and sales in the spot market. As of
September 30, 2011, we are contractually committed to sell
8.8 million tons of coal in 2012, and 8.1 million tons
of coal in 2013, which represents 99% and 83% of our expected
total coal sales in 2012 and 2013, respectively. In addition, we
believe that the relative heat, ash, sulfur content and cost of
our coal, combined with the accessibility of our coal mines and
coal processing facilities to the Mississippi River and to rail
connecting to Louisiana export terminals will provide the
opportunity to export our coal to overseas customers.
|
|
|
|
Maximize profitability by maintaining low-cost mining
operations. We operate our mines in a manner
aimed at keeping our product quality high while maintaining low
production costs. We seek to maximize our coal production and
control our costs by continuing to improve our operating
efficiency. Our efficiency is, in part, a function of the
overburden ratios (the amount of surface material needed to be
removed to extract coal) that exist at our surface coal mines.
Our efficiency is also enhanced by our fleet of mobile mining
equipment, substantially all of which is new, our use of the
only draglines in Kentucky, our utilization of river coal
movement, our information technology systems and our coordinated
equipment utilization and maintenance management functions. We
also believe that our highly experienced operating management
and well-trained workforce will continue to help in identifying
and implementing cost containment initiatives.
|
Competitive
Strengths
We believe that the following competitive strengths will enable
us to effectively execute our business strategy described above.
|
|
|
|
|
We have a demonstrated track record for successfully
completing reserve acquisitions, securing required permits,
developing new mines and producing coal. Since
our formation in 2006, we have successfully acquired coal
reserves and opened seven separate mines, obtained the necessary
regulatory permits for
|
6
|
|
|
|
|
the commencement of mining operations at those mines, and
developed significant multi-year contractual relationships with
large customers in our market area. We believe this resulted
from our deep management experience and disciplined approach to
the development of our operations and our focus on providing
competitively priced Illinois Basin coal. We believe this will
enable us to continue to grow our customer base, production,
revenues and profitability.
|
|
|
|
|
|
Our proven and probable reserves have a long reserve life and
attractive characteristics. As of
December 31, 2010, we had approximately 319 million
tons of clean recoverable (proven and probable) coal reserves.
Our reserves include both surface and underground mineable coal
residing in multiple seams which, in combination with our coal
processing facilities, enhances our ability to meet customer
requirements for blends of coal with different characteristics.
Further, the comparatively low chlorine content of our coal
relative to other Illinois Basin coal provides us with an
additional competitive advantage in meeting the desired coal
fuel profile of our customers.
|
|
|
|
Our mines are conveniently located in close proximity to our
existing and potential customers and have access to multiple
transportation options for delivery. Our mines
are located adjacent to the Green and Ohio Rivers and near our
preparation, loading and transportation facilities, providing
our customers with rail, barge and truck transportation options.
We believe this will also enable us to sell our coal in both the
domestic and export markets. Recently, we purchased an equity
interest in, and upon development will have access to, a
Mississippi River coal export terminal project in Plaquemines
Parish, Louisiana, approximately 10 miles downstream of New
Orleans. We intend to oversee the design, build-out and
operation of this export coal terminal to facilitate the
anticipated sale of our coal to international customers.
|
|
|
|
We are a reliable supplier of cost competitive
coal. Our highly skilled, non-union workforce
uses efficient mining practices that take advantage of economies
of scale and reduce operating costs per ton in both surface and
underground mining. We are among a small number of operators of
large scale dragline surface production in the eastern United
States, and our continuous miner underground mining operations
are designed to provide operating flexibility to meet production
requirements and to fulfill our coal contract specifications.
|
|
|
|
We have a highly experienced management team with a long
history of acquiring, building and operating coal
businesses. The members of our senior management
team have a demonstrated track record of acquiring, building and
operating coal businesses profitably and safely. In addition,
members of our senior management team have significant
experience managing the financial and organizational growth of
businesses, including public companies.
|
Recent
Developments
In June 2011, we commenced operations at our Lewis Creek surface
mine, and operations at our Kronos underground mine began in
September 2011. We expect that our Lewis Creek mine will have an
annual production capacity of approximately 1.0 million
tons and our Kronos underground mine will have an annual
production capacity of approximately 2.4 million tons.
Operations at our Big Run mine ended in October 2011 and
operations at our Kronos pit at the East Fork mine ended in the
fourth quarter of 2011.
In June 2011, we acquired an 8.4% equity interest in Ram
Terminals, LLC (Ram). Ram owns 600 acres of
Mississippi Riverfront property approximately 10 miles
south of New Orleans and intends to permit, design and construct
a seaborne coal export terminal capable of servicing
Panamax-sized bulk carriers with an annual through-put capacity
of up to 6 million tons, and up to 10 million tons per
year in the event of the widening of the Panama Canal. The
terminal will be used to facilitate and ensure our access to
international markets, as well as to handle export coal volumes
of both metallurgical and thermal coal of other coal companies.
One of the investment funds managed by Yorktown Partners LLC, is
the controlling unitholder in Ram and will provide the funds for
future capital expenditures related to the development of the
site. See Yorktown Partners LLC. We will
be actively involved in the design and construction of the
terminal and will provide accounting and bookkeeping assistance
to Ram. Certain of our executive officers serve as officers of
Ram.
7
In December 2011, we entered into a series of transactions with
affiliates
and/or
subsidiaries of Peabody Energy Corporation
(Peabody), pursuant to which we acquired additional
property near our existing and planned mines containing an
estimated total of 7.7 million clean recoverable tons of
coal and entered into leases for an estimated 14 million
clean recoverable tons. In addition we entered, into a joint
venture relating to coal reserves near our Parkway mine. In
connection with the joint venture, Peabody has agreed to
contribute an aggregate of approximately 25 million tons of
clean recoverable coal reserves located in Muhlenberg County,
Kentucky, and we have agreed to contribute mining assets to the
joint venture. We and Peabody have also agreed to contribute 51%
and 49%, respectively, of the cash sufficient to complete the
development of the mine and sufficient for down payments on
mining equipment. We will manage the joint ventures
day-to-day
operations and the development of the mine in exchange for a
$0.50 per ton sold management fee. Peabody will
receive a $0.25 per ton commission on all coal sales by the
joint venture.
The Company and Peabody entered into an Asset Purchase Agreement
pursuant to which we acquired from Peabody its rights and
interests in certain owned and leased coal reserves located in
Muhlenberg County, Kentucky, in exchange for (i) a cash
payment by us of approximately $8.9 million, (ii) a
promissory note in the aggregate principal amount of
approximately $4.4 million, and (iii) an overriding
royalty to Peabody to the extent we mine in excess of certain
tonnages from the property as set forth in the Asset Purchase
Agreement.
In December 2011, the Company and Midwest Coal Reserves of
Kentucky, LLC, an affiliate of Peabody (Midwest
Coal), entered into a Contract to Sell and Lease Real
Estate pursuant to which we acquired from Midwest Coal its
right, title and interest in and to the #9 seam coal
reserves in Union County, Kentucky. In addition, Midwest Coal
agreed to lease to us approximately 2,000 acres of #9
seam of coal. In consideration of the sale and lease of real
property, we agreed to deliver (i) approximately
$6.0 million in cash, (ii) a promissory note in the
aggregate principal amount of approximately $3.0 million,
and (iii) an overriding royalty of 2% of the gross selling
price on each ton of coal produced and sold from the coal
reserves that were purchased (thus excluding the leased coal).
In December 2011, Armstrong Resource Partners sold 200,000
Series A convertible preferred units of limited partner
interest to Yorktown in exchange for $20.0 million. Also in
December 2011, we entered into a Membership Interest Purchase
Agreement with Armstrong Resource Partners pursuant to which we
agreed to sell to Armstrong Resource Partners, indirectly
through contribution of a partial undivided interest in reserves
to a limited liability company and transfer of our membership
interests in such limited liability company, an additional
partial undivided interest in reserves controlled by us. In
exchange for our agreement to sell a partial undivided interest
in those reserves, Armstrong Resource Partners paid us
$20.0 million. The partial undivided interest in additional
reserves must be transferred to Armstrong Resource Partners
within 90 days after delivery of the purchase price. We
used the proceeds of this sale to fund the Muhlenberg County and
Ohio County reserve acquisitions described above.
In January 2012, in connection with entry into the Fourth
Amendment to our Senior Secured Credit Facility, we sold
300,000 shares of Series A convertible preferred stock
to Yorktown in exchange for $30.0 million. We used the
proceeds of the sale to repay a portion of our outstanding
borrowings under the Senior Secured Revolving Credit Facility
and for general corporate purposes. See Description of
Indebtedness.
8
Corporate
Structure
In August 2011, Armstrong Resources Holdings, LLC merged with
and into Armstrong Energy, Inc., which subsequently changed its
name to Armstrong Energy Holdings, Inc. Subsequently, Armstrong
Land Company, LLC was converted to a C-corporation and changed
its name to Armstrong Energy, Inc. effective October 1,
2011 (the Reorganization). In connection with the
Reorganization, each owner of Armstrong Land Company, LLC
received 9.25 shares of Armstrong Energy, Inc. common stock
for each unit held. The following chart shows a summary of the
corporate organization of Armstrong Energy, Inc. and its
principal subsidiaries, after giving effect to the
Reorganization, but prior to giving effect to the offering of
common stock being made hereby or to the Concurrent ARP Offering.
|
|
|
(1) |
|
Reserves owned solely by Armstrong Resource Partners. These
include the Kronos, Lewis Creek and Ceralvo underground mines. |
|
(2) |
|
Reserves controlled jointly by Armstrong Resource Partners (with
a 39.45% undivided interest) and Armstrong Energy (with a 60.55%
undivided interest). If the Concurrent ARP Offering and related
transactions are completed, the undivided interest of Armstrong
Resource Partners will increase, and the undivided interest of
Armstrong Energy will decrease, based on the net proceeds of the
Concurrent ARP Offering paid to Armstrong Energy and the value
of the affected reserves as agreed by Armstrong Resource
Partners and Armstrong Energy. See Certain Relationships
and Related Party Transactions Concurrent
Transactions with Armstrong Resource Partners. |
9
The following chart depicts the organization and ownership of
Armstrong Energy, Inc. after giving effect to this offering and
the Concurrent ARP Offering.
|
|
|
(1) |
|
Reserves owned solely by Armstrong Resource Partners. These
include the Kronos, Lewis Creek and Ceralvo underground mines. |
|
(2) |
|
Reserves controlled jointly by Armstrong Resource Partners (with
a % undivided interest) and
Armstrong Energy (with a %
undivided interest), assuming an offering price of
$ per unit, the midpoint of the
price range set forth on the front cover page of the prospectus
for the Concurrent ARP Offering and an estimated purchase price
of $ for Armstrong Resource
Partners additional interest in the partially owned
reserves. |
Corporate
Information
Our principal executive offices are located at 7733 Forsyth
Boulevard, Suite 1625, St. Louis, Missouri 63105 and
our telephone number is
(314) 721-8202.
Our corporate website address is www.armstrongenergyinc.com.
Information on, or accessible through, our website is not part
of, or incorporated by reference in, this prospectus. We are
incorporated under the laws of the State of Delaware.
Yorktown
Partners LLC
Yorktown was formed in 1991 and has approximately
$3.0 billion in assets under management. Yorktown invests
exclusively in the energy industry with an emphasis on North
American oil and gas production, coal mining and midstream
businesses. Yorktowns investors include university
endowments, foundations, families, insurance companies and other
institutional investors.
After giving effect to this offering, Armstrong Energy will
continue to be majority-owned by Yorktown. In addition, Yorktown
is represented on our board by Bryan H. Lawrence, founder and
principal of Yorktown Partners LLC. As a result, Yorktown has,
and can be expected to have, a significant influence in our
operations, in the outcome of stockholder voting concerning the
election of directors, the adoption or amendment of provisions
in our charter and bylaws, the approval of mergers, and other
significant corporate transactions. See Risk
Factors Yorktown will continue to have significant
influence over us, including control over decisions that require
the approval of stockholders, which could limit your ability to
influence the outcome of key transactions, including a change of
control.
10
The
Offering
The following summary contains basic information about this
offering and the shares of our common stock and is not intended
to be complete. This summary may not contain all of the
information that is important to you. For a more complete
understanding of this offering and the shares of our common
stock, we encourage you to read this entire prospectus,
including, without limitation, the sections of this prospectus
entitled Risk Factors and Description of
Capital Stock, and the documents attached to this
prospectus.
|
|
|
Common Stock Offered by Armstrong Energy, Inc.
|
|
shares. |
|
Over-Allotment Option |
|
We have granted the underwriters an option to purchase up to an
additional shares
of our common stock, equal to 15% of the shares offered in this
offering, at the public offering price, less the
underwriters discount, within 30 days after the date
of this prospectus. |
|
Common Stock to be Outstanding Immediately After this Offering
|
|
shares
(or shares
if the underwriters exercise in full their over-allotment
option). |
|
Common Stock Held by Our Existing Stockholders Immediately After
this Offering
|
|
shares
(or shares
if the underwriters exercise in full their over-allotment
option). |
|
Use of Proceeds |
|
We expect to receive net proceeds from this offering of
approximately $ million (or
approximately $ million if
the underwriters exercise in full their option to purchase
additional shares of our common stock) after deducting estimated
underwriting discounts and commissions, and after our offering
expenses estimated at
$ million, assuming the
shares are offered at $ per share,
which is the midpoint of the estimated offering price range
shown on the front cover page of this prospectus. We intend to
use $ million of the net
proceeds from this offering to repay a portion of our
outstanding borrowings under our Senior Secured Term Loan, and
to use the balance to repay a portion of our outstanding
borrowings under our Senior Secured Revolving Credit Facility
and for general corporate purposes, including to fund capital
expenditures relating to our mining operations and working
capital. |
|
Voting Rights |
|
Under Delaware law, each share of common stock entitles the
holder to one vote. |
|
Dividend Policy |
|
We do not anticipate paying cash dividends on shares of our
common stock for the foreseeable future. In addition, our Senior
Secured Credit Facility contains restrictions on the payment of
dividends to holders of our common stock. See Dividend
Policy. |
|
Proposed Symbol |
|
ARMS |
|
|
|
Risk Factors |
|
Investing in our common stock involves a high degree of risk.
For a discussion of factors you should consider in making an
investment, see Risk Factors beginning on
page 16. |
|
|
|
Conflicts of Interest |
|
Raymond James Bank, FSB, an affiliate of Raymond
James & Associates, Inc., one of the underwriters in
this offering, is expected to receive more than 5% of the net
proceeds of this offering in connection with the repayment of
our Senior Secured Term |
11
|
|
|
|
|
Loan and our Senior Secured Revolving Credit Facility. See
Use of Proceeds. Accordingly, this offering is being
made in compliance with the requirements of the Financial
Industry Regulatory Authority (FINRA)
Rule 5121. Rule 5121 requires that a qualified
independent underwriter meeting certain standards to
participate in the preparation of the registration statement and
prospectus and exercise the usual standards of due diligence
with respect thereto. FBR Capital Markets & Co. has
agreed to act as a qualified independent underwriter
within the meaning of FINRA Rule 5121 in connection with
this offering. For more information, see Conflicts of
Interest. |
Risks
Related to Our Business
Our business is subject to a number of risks of which you should
be aware before making an investment decision. These risks are
discussed more fully under the caption Risk Factors,
and include but are not limited to the following:
|
|
|
|
|
Coal prices are subject to change and a substantial or extended
decline in prices could materially and adversely affect our
profitability and the value of our coal reserves.
|
|
|
|
Our coal mining operations are subject to operating risks that
are beyond our control, which could result in materially
increased operating expenses and decreased production levels and
could materially and adversely affect our profitability.
|
|
|
|
Competition within the coal industry could put downward pressure
on coal prices and, as a result, materially and adversely affect
our revenues and profitability.
|
|
|
|
Decreases in demand for electricity and changes in coal
consumption patterns of U.S. electric power generators
could adversely affect coal prices and materially and adversely
affect our results of operations.
|
|
|
|
The use of alternative energy sources for power generation could
reduce coal consumption by U.S. electric power generators,
which could result in lower prices for our coal. Declines in the
prices at which we sell our coal could reduce our revenues and
materially and adversely affect our business and results of
operations.
|
|
|
|
Our profitability depends in part upon the multi-year coal
supply agreements we have with our customers. Changes in
purchasing patterns in the coal industry could make it difficult
for us to extend our existing multi-year coal supply agreements
or to enter into new agreements in the future. In addition, our
multi-year coal supply agreements subject us to renewal risks.
|
|
|
|
The loss of, or significant reduction in purchases by, our
largest customers could adversely affect our profitability.
|
|
|
|
The amount of indebtedness we have incurred could significantly
affect our business.
|
|
|
|
The fiduciary duties of officers and directors of Elk Creek GP,
as general partner of Armstrong Resource Partners, L.P., may
conflict with those of officers and directors of Armstrong
Energy.
|
|
|
|
Yorktown will continue to have significant influence over us,
including control over decisions that require the approval of
stockholders, which could limit your ability to influence the
outcome of key transactions, including a change of control.
|
|
|
|
New regulatory requirements limiting greenhouse gas emissions
and existing and potential future requirements relating to air
emissions could reduce the demand for coal as a fuel source,
which could cause the price and quantity of the coal we sell to
decline materially.
|
12
Summary
Historical and Unaudited
Pro Forma Consolidated Financial and Operating Data
The following table presents our summary historical and
unaudited pro forma consolidated financial and operating data
for the periods indicated for Armstrong Energy, Inc. and its
predecessor, Armstrong Land Company, LLC and their respective
subsidiaries (our Predecessor). The summary
historical financial data for the years ended December 31,
2008, 2009 and 2010 and the balance sheet data as of
December 31, 2008, 2009 and 2010 are derived from the
audited financial statements of our Predecessor. The summary
historical financial data for the nine months ended
September 30, 2010 and 2011 and the balance sheet data as
of September 30, 2010 and 2011 are derived from the
unaudited financial statements of our Predecessor. The following
unaudited pro forma consolidated financial data of Armstrong
Energy, Inc. at September 30, 2011, for the year ended
December 31, 2010, and for the nine months ended
September 30, 2011, are based on the historical
consolidated financial statements of our Predecessor and pro
forma assumptions and adjustments, which are included elsewhere
in this prospectus.
The unaudited pro forma consolidated balance sheet data at
September 30, 2011 gives effect to (a) the issuance of
common stock in this offering and the application of the net
proceeds therefrom as described in Use of Proceeds,
(b) the Deconsolidation of Armstrong Resource Partners, and
(c) the contribution of net proceeds to Armstrong Energy,
Inc. from the Concurrent ARP Offering, as if each had occurred
on September 30, 2011.
The unaudited pro forma consolidated financial data for the
fiscal year ended December 31, 2010 gives effect to
(a) adjustments to interest expense as a result of the
repayment of a portion of the secured promissory notes from the
proceeds of this offering, (b) the addition of interest
expense associated with a long-term obligation to Armstrong
Resource Partners, net of certain allocated management fees,
recognized as part of the Deconsolidation of Armstrong Resource
Partners, and (c) net adjustments to interest expense as a
result of the repayment of a portion of the secured promissory
notes from the proceeds contributed from the Concurrent ARP
Offering, partially offset by additional interest expense
associated with an additional long-term obligation owed to
Armstrong Resource Partners, as if each had occurred on
January 1, 2010.
The unaudited pro forma consolidated financial data for the nine
months ended September 30, 2011 gives effect to
(a) adjustments to interest expense as a result of the
repayment of a portion of the secured promissory notes from the
proceeds of this offering and reduction of subsequent borrowings
in February 2011 under the Senior Secured Credit Facility,
(b) the addition of interest expense associated with a
long-term obligation to Armstrong Resource Partners, net of
certain allocated management fees, recognized as part of the
Deconsolidation of Armstrong Resource Partners, and (c) net
adjustments to interest expense as a result of the repayment of
a portion of the secured promissory notes from the proceeds
contributed from the concurrent Armstrong Resource Partners
offering of units and additional interest expense associated
with an additional long-term obligation owed to Armstrong
Resource Partners, as if each had occurred on January 1,
2010. A more complete explanation can be found in our unaudited
pro forma combined financial statements included elsewhere in
this prospectus.
Historical results and unaudited pro forma consolidated
financial and operating information is included for illustrative
and informational purposes only and is not necessarily
indicative of results we expect in future periods. You should
read the following summary and unaudited pro forma financial
data in conjunction with Selected Historical Consolidated
Financial and Operating Data, Unaudited Pro Forma
Financial Information and Managements
Discussion and Analysis of Financial Condition and Results of
Operations and our financial statements and related notes
appearing elsewhere in this prospectus.
13
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Armstrong Energy, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
Months
|
|
|
|
Predecessor
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Year Ended December 31,
|
|
|
Nine Months Ended September 30,
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
(Restated)1
|
|
|
(Restated)1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Restated)1
|
|
|
(Restated)1
|
|
|
Unaudited
|
|
|
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
|
|
|
Unaudited
|
|
|
|
|
|
|
|
|
|
(In thousands, except per share data)
|
|
|
Results of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
57,069
|
|
|
$
|
167,904
|
|
|
$
|
220,625
|
|
|
$
|
176,311
|
|
|
$
|
229,980
|
|
|
$
|
|
|
|
$
|
|
|
Costs and expenses
|
|
|
64,667
|
|
|
|
166,686
|
|
|
|
201,473
|
|
|
|
158,169
|
|
|
|
223,551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(7,598
|
)
|
|
|
1,218
|
|
|
|
19,152
|
|
|
|
18,142
|
|
|
|
6,429
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(14,752
|
)
|
|
|
(12,651
|
)
|
|
|
(11,070
|
)
|
|
|
(8,532
|
)
|
|
|
(6,073
|
)
|
|
|
|
|
|
|
|
|
Other income (expense), net
|
|
|
971
|
|
|
|
988
|
|
|
|
87
|
|
|
|
259
|
|
|
|
(36
|
)
|
|
|
|
|
|
|
|
|
Gain on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(21,379
|
)
|
|
|
(10,445
|
)
|
|
|
8,169
|
|
|
|
9,869
|
|
|
|
7,274
|
|
|
|
|
|
|
|
|
|
Income tax provision
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(809
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(21,379
|
)
|
|
|
(10,445
|
)
|
|
|
8,169
|
|
|
|
9,869
|
|
|
|
6,465
|
|
|
|
|
|
|
|
|
|
Less: net income (loss) attributable to non-controlling interest
|
|
|
(5,552
|
)
|
|
|
(1,730
|
)
|
|
|
3,351
|
|
|
|
2,814
|
|
|
|
7,448
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to common stockholders
|
|
$
|
(15,827
|
)
|
|
$
|
(8,715
|
)
|
|
$
|
4,818
|
|
|
$
|
7,055
|
|
|
$
|
(983
|
)
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per share, basic and diluted
|
|
$
|
(1.35
|
)
|
|
$
|
(0.50
|
)
|
|
$
|
0.25
|
|
|
$
|
0.37
|
|
|
$
|
(0.05
|
)
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period end)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
372,674
|
|
|
$
|
450,618
|
|
|
$
|
478,038
|
|
|
$
|
461,577
|
|
|
$
|
516,299
|
|
|
|
|
|
|
$
|
|
|
Working capital
|
|
|
(34,668
|
)
|
|
|
(17,749
|
)
|
|
|
2,905
|
|
|
|
(32,582
|
)
|
|
|
(14,942
|
)
|
|
|
|
|
|
|
|
|
Total debt (including capital leases)
|
|
|
183,337
|
|
|
|
159,730
|
|
|
|
139,871
|
|
|
|
143,539
|
|
|
|
152,207
|
|
|
|
|
|
|
|
|
(2)
|
Total stockholders equity
|
|
|
168,931
|
|
|
|
255,333
|
|
|
|
296,681
|
|
|
|
287,356
|
|
|
|
307,930
|
|
|
|
|
|
|
|
|
|
Other Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold (unaudited)
|
|
|
1,398
|
|
|
|
4,674
|
|
|
|
5,387
|
|
|
|
4,339
|
|
|
|
5,481
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
(11,079
|
)
|
|
$
|
3,054
|
|
|
$
|
37,194
|
|
|
$
|
26,804
|
|
|
$
|
31,126
|
|
|
|
|
|
|
|
|
|
Investing activities
|
|
|
(80,020
|
)
|
|
|
(62,476
|
)
|
|
|
(41,755
|
)
|
|
|
(24,681
|
)
|
|
|
(47,386
|
)
|
|
|
|
|
|
|
|
|
Financing activities
|
|
|
79,402
|
|
|
|
64,854
|
|
|
|
(3,935
|
)
|
|
|
(6,017
|
)
|
|
|
15,706
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(1) (unaudited)
|
|
|
(1,029
|
)
|
|
|
16,567
|
|
|
|
41,099
|
|
|
|
34,874
|
|
|
|
32,125
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA is calculated as follows (unaudited):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(21,379
|
)
|
|
$
|
(10,445
|
)
|
|
$
|
8,169
|
|
|
$
|
9,869
|
|
|
$
|
6,465
|
|
|
$
|
|
|
|
$
|
|
|
Income tax provision
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
809
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
5,810
|
|
|
|
14,464
|
|
|
|
21,979
|
|
|
|
16,562
|
|
|
|
24,420
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
14,377
|
|
|
|
12,482
|
|
|
|
10,872
|
|
|
|
8,389
|
|
|
|
5,955
|
|
|
|
|
(3)
|
|
|
|
(3)
|
Non-cash stock compensation expense
|
|
|
163
|
|
|
|
66
|
|
|
|
79
|
|
|
|
54
|
|
|
|
1,212
|
|
|
|
|
|
|
|
|
|
Non-cash charge related to non-recourse notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
218
|
|
|
|
|
|
|
|
|
|
Gain on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,954
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,029
|
)
|
|
$
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16,567
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$
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41,099
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$
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34,874
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$
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32,125
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$
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$
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1 |
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The consolidated financial statements have been restated to
correct for an error in the calculation of depreciation,
depletion, and amortization expense for the years ended
December 31, 2009 and 2010 and the nine |
14
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months ended September 30, 2010 and 2011. See Note 3
to the interim condensed consolidated financial statements. |
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(1) |
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Adjusted EBITDA is a non-GAAP financial measure, and when
analyzing our operating performance, investors should use
Adjusted EBITDA in addition to, and not as an alternative for,
operating income and net income (loss) (each as determined in
accordance with GAAP). We use Adjusted EBITDA as a supplemental
financial measure. Adjusted EBITDA is defined as net income
(loss) before net interest expense, income taxes, depreciation,
depletion and amortization, non-cash stock compensation expense,
non-cash charges related to non-recourse notes, and gain on
extinguishment of debt. |
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Adjusted EBITDA, as used and defined by us, may not be
comparable to similarly titled measures employed by other
companies and is not a measure of performance calculated in
accordance with GAAP. There are significant limitations to using
Adjusted EBITDA as a measure of performance, including the
inability to analyze the effect of certain recurring and
non-recurring items that materially affect our net income or
loss, the lack of comparability of results of operations of
different companies and the different methods of calculating
Adjusted EBITDA reported by different companies, and should not
be considered in isolation or as a substitute for analysis of
our results as reported under GAAP. |
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For example, Adjusted EBITDA does not reflect: |
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cash expenditures, or future requirements, for
capital expenditures or contractual commitments; changes in, or
cash requirements for, working capital needs;
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the significant interest expense, or the cash
requirements necessary to service interest or principal
payments, on debt; and
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any cash requirements for assets being depreciated
and amortized that may have to be replaced in the future.
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Adjusted EBITDA does not represent funds available for
discretionary use because those funds are required for debt
service, capital expenditures, working capital and other
commitments and obligations. However, our management team
believes Adjusted EBITDA is useful to an investor in evaluating
our company because this measure: |
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is widely used by investors in our industry to
measure a companys operating performance without regard to
items excluded from the calculation of such term, which can vary
substantially from company to company depending upon accounting
methods and book value of assets, capital structure and the
method by which assets were acquired, among other
factors; and
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helps investors to more meaningfully evaluate and
compare the results of our operations from period to period by
removing the effect of our capital structure from our operating
structure, which is useful for trending, analyzing and
benchmarking the performance and value of our business.
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(2) |
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Included within pro forma total debt is
$ related to the financing
arrangement with Armstrong Energy, whereby Armstrong Resource
Partners acquired an undivided interest in certain of the land
and mineral reserves of Armstrong Energy. |
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(3) |
|
Included within pro forma interest expense, net is
$ and
$ for the nine months ended
September 30, 2011 and the year ended December 31,
2010, respectively, related to interest expense associated with
the financing arrangement with Armstrong Energy, whereby
Armstrong Resource Partners acquired an undivided interest in
certain of the land and mineral reserves of Armstrong Energy. |
15
RISK
FACTORS
An investment in our common stock involves significant risks.
In addition to matters described elsewhere in this prospectus,
you should carefully consider the following risks involved with
an investment in our common stock. You are urged to consult your
own legal, tax or financial counsel for advice before making an
investment decision. The occurrence of any one or more of the
following could materially adversely affect an investment in our
common stock or our business and operating results. If that
occurs, the value of our common stock could decline and you
could lose some or all of your investment.
Risks
Related to Our Business
Coal
prices are subject to change and a substantial or extended
decline in prices could materially and adversely affect our
profitability and the value of our coal reserves.
Our profitability and the value of our coal reserves depend upon
the prices we receive for our coal. The contract prices we may
receive in the future for coal depend upon factors beyond our
control, including the following:
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the domestic and foreign supply and demand for coal;
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the relative cost, quantity and quality of coal available from
competitors;
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competition for production of electricity from non-coal sources,
which are a function of the price and availability of
alternative fuels, such as natural gas, fuel oil, nuclear,
hydroelectric, wind, biomass and solar power, and the location,
availability, quality and price of those alternative fuel
sources;
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legislative, regulatory and judicial developments, environmental
regulatory changes or changes in energy policy and energy
conservation measures that would adversely affect the coal
industry, such as legislation limiting carbon emissions or
providing for increased funding and incentives for alternative
energy sources;
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domestic air emission standards for coal-fired power plants and
the ability of coal-fired power plants to meet these standards
by installing scrubbers and other pollution control technologies
or by other means;
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adverse weather, climatic or other natural conditions, including
natural disasters;
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domestic and foreign economic conditions, including economic
slowdowns;
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the proximity to, capacity of and cost of, transportation, port
and unloading facilities; and
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market price fluctuations for sulfur dioxide emission allowances.
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A substantial or extended decline in the prices we receive for
our future coal sales contracts or on the spot market could
materially and adversely affect us by decreasing our
profitability and the value of operating our coal reserves.
Our
coal mining operations are subject to operating risks that are
beyond our control, which could result in materially increased
operating expenses and decreased production levels and could
materially and adversely affect our profitability.
We mine coal both at underground and at surface mining
operations. Certain factors beyond our control, including those
listed below, could disrupt our coal mining operations,
adversely affect production and shipments and increase our
operating costs:
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poor mining conditions resulting from geological, hydrologic or
other conditions that may cause instability of mining portals,
highwalls or spoil piles or cause damage to mining equipment,
nearby infrastructure or mine personnel;
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delays or challenges to and difficulties in obtaining or
renewing permits necessary to produce coal or operate mining or
related processing and loading facilities;
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adverse weather and natural disasters, such as heavy rains or
snow, flooding and other natural events affecting operations,
transportation or customers;
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a major incident at the mine site that causes all or part of the
operations of the mine to cease for some period of time;
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mining, processing and plant equipment failures and unexpected
maintenance problems;
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unexpected or accidental surface subsidence from underground
mining;
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accidental mine water discharges, fires, explosions or similar
mining accidents; and
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competition
and/or
conflicts with other natural resource extraction activities and
production within our operating areas, such as coalbed methane
extraction or oil and gas development.
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If any of these conditions or events occurs, we could experience
a delay or halt of production or shipments or our operating
costs could increase significantly.
Competition
within the coal industry could put downward pressure on coal
prices and, as a result, materially and adversely affect our
revenues and profitability.
We compete with numerous other coal producers in the Illinois
Basin and in other coal producing regions of the United States,
primarily Central Appalachia and the Powder River Basin (the
PRB). The most important factors on which we compete
are:
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delivered price (i.e., the cost of coal delivered to the
customer on a cents per million Btu basis, including
transportation costs, which are generally paid by our customers
either directly or indirectly);
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coal quality characteristics (primarily heat, sulfur, ash and
moisture content); and
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reliability of supply.
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Our competitors may have, among other things, greater liquidity,
greater access to credit and other financial resources, newer or
more efficient equipment, lower cost structures, partnerships
with transportation companies or more effective risk management
policies and procedures. Our failure to compete successfully
could have a material adverse effect on our business, financial
condition or results of operations.
International demand for U.S. coal also affects competition
within our industry. The demand for U.S. coal exports
depends upon a number of factors outside our control, including
the overall demand for electricity in foreign markets, currency
exchange rates, ocean freight rates, port and shipping capacity,
the demand for foreign-priced steel, both in foreign markets and
in the U.S. market, general economic conditions in foreign
countries, technological developments and environmental and
other governmental regulations in both U.S. and foreign
markets. Foreign demand for U.S. coal has increased in
recent periods. If foreign demand for U.S. coal were to
decline, this decline could cause competition among coal
producers for the sale of coal in the United States to
intensify, potentially resulting in significant downward
pressure on domestic coal prices.
Decreases
in demand for electricity and changes in coal consumption
patterns of U.S. electric power generators could adversely
affect coal prices and materially and adversely affect our
results of operations.
Our coal is used primarily as fuel for electricity generation.
Overall economic activity and the associated demand for power by
industrial users can have significant effects on overall
electricity demand. An economic slowdown can significantly slow
the growth of electrical demand and could result in contraction
of demand for coal. Declines in international prices for coal
generally will impact U.S. prices for coal. During the past
several years, international demand for coal has been driven, in
significant part, by increases in demand due to economic growth
in emerging markets, including China and India. Significant
declines in the rates of economic growth in these regions could
materially affect international demand for U.S. coal, which
may have an adverse effect on U.S. coal prices.
Our business is closely linked to domestic demand for
electricity and any changes in coal consumption by
U.S. electric power generators would likely impact our
business over the long term. In 2010, we sold
17
substantially all of our coal to domestic electric power
generators, and we have multi-year coal supply agreements in
place with electric power generators for a significant portion
of our future production. The amount of coal consumed by
electric power generation is affected by, among other things:
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general economic conditions, particularly those affecting
industrial electric power demand, such as the downturn in the
U.S. economy and financial markets in 2008 and 2009;
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environmental and other governmental regulations, including
those impacting coal-fired power plants;
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energy conservation efforts and related governmental
policies; and
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indirect competition from alternative fuel sources for power
generation, such as natural gas, fuel oil, nuclear,
hydroelectric, wind, biomass and solar power, and the location,
availability, quality and price of those alternative fuel
sources, and government subsidies for those alternative fuel
sources.
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According to the EIA, total electricity consumption in the
United States rose by 4.3% during 2010 compared with 2009,
primarily because of the effect of the recovery from the
economic downturn on industrial electricity demand in 2009, and
U.S. electric generation from coal rose by 5.2% in 2010
compared with 2009. However, decreases in the demand for
electricity could take place in the future, such as decreases
that could be caused by a worsening of current economic
conditions, a prolonged economic recession or other similar
events, could have a material adverse effect on the demand for
coal and on our business over the long term.
Changes in the coal industry that affect our customers, such as
those caused by decreased electricity demand and increased
competition, could also adversely affect our business. Indirect
competition from gas-fired plants that are cheaper to construct
and easier to permit has the most potential to displace a
significant amount of coal-fired generation in the near term,
particularly older, less efficient coal-powered generators. In
addition, uncertainty caused by federal and state regulations
could cause coal customers to be uncertain of their coal
requirements in future years, which could adversely affect our
ability to sell coal to our customers under multi-year coal
supply agreements.
Weather patterns can also greatly affect electricity demand.
Extreme temperatures, both hot and cold, cause increased power
usage and, therefore, increased generating requirements from all
sources. Mild temperatures, on the other hand, result in lower
electrical demand. Any downward pressure on coal prices, due to
decreases in overall demand or otherwise, including changes in
weather patterns, would materially and adversely affect our
results of operations.
The
use of alternative energy sources for power generation could
reduce coal consumption by U.S. electric power generators, which
could result in lower prices for our coal. Declines in the
prices at which we sell our coal could reduce our revenues and
materially and adversely affect our business and results of
operations.
In 2010, nearly all of the tons we sold were to domestic
electric power generators. The amount of coal consumed for
U.S. electric power generation is affected by, among other
things:
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the location, availability, quality and price of alternative
energy sources for power generation, such as natural gas, fuel
oil, nuclear, hydroelectric, wind, biomass and solar
power; and
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technological developments, including those related to
alternative energy sources.
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Gas-fired electricity generation has the potential to displace
coal-fired generation, particularly from older, less efficient
coal-powered generators. We expect that many of the new power
plants needed to meet increasing demand for electricity
generation may be fueled by natural gas because gas-fired plants
are cheaper to construct and permits to construct these plants
are easier to obtain as natural gas-fired plants are seen as
having a lower environmental impact than coal-fired plants. In
addition, state and federal mandates for increased use of
electricity from renewable energy sources could have an adverse
impact on the market for our coal. Many states have mandates
requiring electricity suppliers to use renewable energy sources
to generate a certain percentage of power. There have been
numerous proposals to establish a similar uniform, national
energy portfolio standard in the U.S., although none of these
proposals have been enacted to date. Possible
18
advances in technologies and incentives, such as tax credits, to
enhance the economics of renewable energy sources could make
these sources more competitive with coal. Any reduction in the
amount of coal consumed by domestic electric power generators
could reduce the price of coal that we mine and sell, thereby
reducing our revenues and materially and adversely affecting our
business and results of operations.
Inaccuracies
in our estimates of our coal reserves could result in decreased
profitability from lower than expected revenues or higher than
expected costs.
Our future performance depends on, among other things, the
accuracy of our estimates of our proven and probable coal
reserves. The estimates of our reserves are based on
engineering, economic and geological data assembled, analyzed
and reviewed by internal and third-party engineers and
consultants. We update our estimates of the quantity and quality
of proven and probable coal reserves periodically to reflect the
production of coal from the reserves, updated geological models
and mining recovery data, the tonnage contained in new lease
areas acquired and estimated costs of production and sales
prices. There are numerous factors and assumptions inherent in
estimating the quantities and qualities of, and costs to mine,
coal reserves, including many factors beyond our control,
including the following:
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quality of the coal;
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geological and mining conditions, which may not be fully
identified by available exploration data
and/or may
differ from our experiences in areas where we currently mine;
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the percentage of coal ultimately recoverable;
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the assumed effects of regulation, including the issuance of
required permits, taxes, including severance and excise taxes
and royalties, and other payments to governmental agencies;
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assumptions concerning the timing for the development of the
reserves; and
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assumptions concerning equipment and productivity, future coal
prices, operating costs, including for critical supplies such as
fuel, tires and explosives, capital expenditures and development
and reclamation costs, including the cost of reclamation bonds.
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As a result, estimates of the quantities and qualities of
economically recoverable coal attributable to any particular
group of properties, classifications of reserves based on risk
of recovery, estimated cost of production, and estimates of
future net cash flows expected from these properties as prepared
by different engineers, or by the same engineers at different
times, may vary materially due to changes in the above factors
and assumptions. Actual production recovered from identified
reserve areas and properties, and revenues and expenditures
associated with our mining operations, may vary materially from
estimates. Any inaccuracy in our estimates related to our
reserves could result in decreased profitability from lower than
expected revenues
and/or
higher than expected costs.
Increases
in the costs of mining and other industrial supplies, including
steel-based supplies, diesel fuel, rubber tires and explosives,
or the inability to obtain a sufficient quantity of those
supplies, may adversely affect our operating costs or disrupt or
delay our production.
Our coal mining operations use significant amounts of steel,
electricity, diesel fuel, explosives, rubber tires and other
mining and industrial supplies. The cost of roof bolts we use in
our underground mining operations depends on the price of scrap
steel. We also use significant amounts of diesel fuel and tires
for the trucks and other heavy machinery we use. If the prices
of mining and other industrial supplies, particularly
steel-based supplies, diesel fuel and rubber tires, increase,
our operating costs may be adversely affected. In addition, if
we are unable to procure these supplies, our coal mining
operations may be disrupted or we could experience a delay or
halt in our production.
19
A
defect in title or the loss of a leasehold interest in certain
property could limit our ability to mine our coal reserves or
result in significant unanticipated costs.
We conduct part of our coal mining operations on properties that
we lease. A title defect or the loss of a lease could adversely
affect our ability to mine the associated coal reserves. We may
not verify title to our leased properties or associated coal
reserves until we have committed to developing those properties
or coal reserves. We may not commit to develop property or coal
reserves until we have obtained necessary permits and completed
exploration. As such, the title to property that we intend to
lease or coal reserves that we intend to mine may contain
defects prohibiting our ability to conduct mining operations.
Similarly, our leasehold interests may be subject to superior
property rights of other third parties or to royalties owed to
those third parties. In order to conduct our mining operations
on properties where these defects exist, we may incur
unanticipated costs. In addition, some leases require us to
produce a minimum quantity of coal and require us to pay minimum
production royalties. Our inability to satisfy those
requirements may cause the leasehold interest to terminate.
We
outsource certain aspects of our business to third party
contractors, which subjects us to risks, including disruptions
in our business.
We contract with third parties to provide blasting services at
all of our mines and loading services at our barge loadout
facility located on the Green River. In addition, we contract
with third parties to provide truck transportation services
between our mines and our preparation plants. Accordingly, we
are subject to the risks associated with the contractors
ability to successfully provide the necessary services to meet
our needs. If the contractors are unable to adequately provide
the contracted services, and we are unable to find alternative
service providers in a timely manner, our ability to conduct our
coal mining operations and deliver coal to our customers may be
disrupted.
The
availability and reliability of transportation facilities and
fluctuations in transportation costs could affect the demand for
our coal or impair our ability to supply coal to our
customers.
We depend upon barge, rail and truck transportation systems to
deliver coal to our customers. Disruptions in transportation
services due to weather-related problems, mechanical
difficulties, strikes, lockouts, bottlenecks, and other events
could impair our ability to supply coal to our customers. In
addition, increases in transportation costs, including the price
of gasoline and diesel fuel, could make coal a less competitive
source of energy when compared to alternative fuels or could
make coal produced in one region of the United States less
competitive than coal produced in other regions of the United
States or abroad. If transportation of our coal is disrupted or
if transportation costs increase significantly and we are unable
to find alternative transportation providers, our coal mining
operations may be disrupted, we could experience a delay or halt
of production or our profitability could decrease significantly.
Our
profitability depends in part upon the multi-year coal supply
agreements we have with our customers. Changes in purchasing
patterns in the coal industry could make it difficult for us to
extend our existing multi-year coal supply agreements or to
enter into new agreements in the future.
We sell a majority of our coal under multi-year coal supply
agreements. Under these arrangements, we fix the prices of coal
shipped during the initial year and may adjust the prices in
later years. As a result, at any given time the market prices
for similar-quality coal may exceed the prices for coal shipped
under these arrangements. Changes in the coal industry may cause
some of our customers not to renew, extend or enter into new
multi-year coal supply agreements with us or to enter into
agreements to purchase fewer tons of coal than in the past or on
different terms or prices. In addition, uncertainty caused by
federal and state regulations, including the Clean Air Act,
could deter our customers from entering into multi-year coal
supply agreements.
Because we sell a majority of our coal production under
multi-year coal supply agreements, our ability to capitalize on
more favorable market prices may be limited. Conversely, at any
given time we are subject to fluctuations in market prices for
the quantities of coal that we are planning to produce but which
we have not committed to sell. As described above under
Coal prices are subject to change and a substantial or
extended
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decline in prices could materially and adversely affect our
profitability and the value of our coal reserves, the
market prices for coal may be volatile and may depend upon
factors beyond our control. Our profitability may be adversely
affected if we are unable to sell uncommitted production at
favorable prices or at all. For more information about our
multi-year coal supply agreements, you should see the section
entitled Business Sales and
Marketing Multi-Year Coal Supply Agreements.
Our
multi-year coal supply agreements subject us to renewal
risks.
We sell most of the coal we produce under multi-year coal supply
agreements. As a result, our results of operations are dependent
upon the prices we receive for the coal we sell under these
contracts. To the extent we are not successful in renewing,
extending or renegotiating our multi-year coal supply agreements
on favorable terms, we may have to accept lower prices for the
coal we sell or sell reduced quantities of coal in order to
secure new sales contracts for our coal.
Prices and quantities under our multi-year coal supply
agreements are generally based on expectations of future coal
prices at the time the contract is entered into, renewed,
extended or reopened. The expectation of future prices for coal
depends upon factors beyond our control, including the following:
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domestic and foreign supply and demand for coal;
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domestic demand for electricity, which tends to follow changes
in general economic activity;
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domestic and foreign economic conditions;
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the price, quantity and quality of other coal available to our
customers;
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competition for production of electricity from non-coal sources,
including the price and availability of alternative fuels and
other sources, such as natural gas, fuel oil, nuclear,
hydroelectric, wind biomass and solar power, and the effects of
technological developments related to these non-coal energy
sources;
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domestic air emission standards for coal-fired power plants, and
the ability of coal-fired power plants to meet these standards
by installing scrubbers and other pollution control
technologies, purchasing emissions allowances or other
means; and
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legislative and judicial developments, regulatory changes, or
changes in energy policy and energy conservation measures that
would adversely affect the coal industry.
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For more information regarding our major customers and
multi-year coal supply agreements, see
Business Sales and Marketing.
The
loss of, or significant reduction in purchases by, our largest
customers could adversely affect our
profitability.
For the year ended December 31, 2010, we derived
approximately 76% of our total coal revenues from sales to our
two largest customers Tennessee Valley Authority
(TVA) and Louisville Gas and Electric
(LGE). For the fiscal year ended December 31,
2010, coal sales to TVA and LGE constituted approximately 40%
and 36% of our total coal revenues, respectively. Our multi-year
coal supply agreements with TVA expire in 2013 and 2018, and our
multi-year coal supply agreements with LGE expire in 2015 and
2016; however, most of our multi-year coal supply agreements
with TVA and LGE contain reopener provisions pursuant to which
either party can request reopening to renegotiate price and
other terms for the remaining term of such agreement, and,
subsequent to any such reopening, the failure to reach an
agreement can lead to the termination of such agreement. In
addition, one of our multi-year coal supply agreements with TVA
provides that, commencing on July 1, 2011, TVA has the
unilateral right to terminate the agreement upon
60 days written notice, in which case TVA is required
to pay us a termination fee equal to 10% of the base price
multiplied by the remaining number of tons to be delivered under
the agreement. If our multi-year coal supply agreements with TVA
or LGE are terminated early pursuant to the reopener provisions,
or we fail to extend or renew our multi-year coal supply
agreements with TVA or LGE, our business and results of
operations could
21
be materially and adversely affected. Even if we are able to
extend or renew our multi-year coal supply agreements with TVA
and LGE, if market prices for coal such agreements are low at
the time of such extensions or renewals or increases in costs
during the term of such extended or renewed agreements are
greater than the offsets from our cost pass-through and
inflation adjustment provisions under such extended or renewed
agreements, our business and results of operations could be
materially and adversely affected.
Our multi-year coal supply agreements typically contain force
majeure provisions allowing the parties to temporarily suspend
performance during specified events beyond their control. Most
of our multi-year coal supply agreements also contain provisions
requiring us to deliver coal that satisfies certain quality
specifications, such as heat value, sulfur content, ash content,
chlorine content, hardness and ash fusion temperature. These
provisions in our multi-year coal supply agreements could result
in negative economic consequences to us, including price
adjustments, purchasing replacement coal in a higher-priced open
market, the rejection of deliveries or, in the extreme, contract
termination. Our profitability may be negatively affected if we
are unable to seek protection during adverse economic conditions
or if we incur financial or other economic penalties as a result
of the provisions of our multi-year coal supply agreements.
If our multi-year coal supply agreements with TVA or LGE are
terminated or if we fail to extend or renew our multi-year coal
supply agreements with TVA or LGE, we may be unable to timely
replace such agreements. In such a case, our business and
results of operations could be materially and adversely affected.
Our
assets and operations are concentrated in Western Kentucky and
the Illinois Basin, and a disruption within that geographic
region could adversely affect the Companys
performance.
We rely exclusively on sales generated from products distributed
from the terminals we own, which are exclusively located in the
Illinois Basin and Western Kentucky. Due to our lack of
diversification in geographic location, an adverse development
in these areas, including adverse developments due to
catastrophic events or weather and decreases in demand for coal
or electricity, could have a significantly greater adverse
impact on our ability to operate our business and our results of
operations than if we held more diverse assets and locations.
The
amount of indebtedness we have incurred could significantly
affect our business.
At September 30, 2011, we had consolidated long-term
indebtedness of approximately $137.1 million, which is
comprised of the following: $100.0 million in borrowings
under the Senior Secured Term Loan, $34.6 million in
borrowings under the Senior Secured Revolving Credit Facility,
and $2.5 million in other long-term debt. We also have
significant lease and royalty obligations, including, but not
limited to, our capital lease obligations that totaled
approximately $15.1 million as of September 30, 2011
and our obligations under non-cancelable operating leases that
totaled approximately $57.7 million. Future minimum advance
royalties totaled approximately $3.3 million as of
September 30, 2011. In addition to advance royalties,
production royalties are payable based on the quantity of coal
minded in future years and prospective changes to mine plans.
Our ability to satisfy our debt, lease and royalty obligations,
and our ability to refinance our indebtedness, will depend upon
our future operating performance. Our ability to satisfy our
financial obligations may be adversely affected if we incur
additional indebtedness in the future. In addition, the amount
of indebtedness we have incurred could have significant
consequences to us, such as:
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limiting our ability to obtain additional financing to fund
growth, working capital, capital expenditures, debt service
requirements or other cash requirements;
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exposing us to the risk of increased interest costs if the
underlying interest rates rise;
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limiting our ability to invest operating cash flow in our
business due to existing debt service requirements;
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making it more difficult to obtain surety bonds, letters of
credit or other financing, particularly during weak credit
markets;
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causing a decline in our future credit ratings;
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limiting our ability to compete with companies that are not as
leveraged and that may be better positioned to withstand
economic downturns;
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limiting our ability to acquire new coal reserves
and/or plant
and equipment needed to conduct operations; and
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limiting our flexibility in planning for, or reacting to, and
increasing our vulnerability to, changes in our business, the
industry in which we compete and general economic and market
conditions.
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If we further increase our indebtedness, the related risks that
we now face, including those described above, could intensify.
In addition to the principal repayments on our outstanding debt,
we have other demands on our cash resources, including capital
expenditures and operating expenses. Our ability to pay our debt
depends upon our operating performance. In particular, economic
conditions could cause our revenues to decline, and hamper our
ability to repay our indebtedness. If we do not have enough cash
to satisfy our debt service obligations, we may be required to
refinance all or part of our debt, sell assets or reduce our
spending. We may not be able to, at any given time, refinance
our debt or sell assets on terms acceptable to us or at all.
We may
be unable to comply with restrictions imposed by our Senior
Secured Credit Facility and other financing
arrangements.
The agreements governing our outstanding financing arrangements
impose a number of restrictions on us. For example, the terms of
our Senior Secured Credit Facility, leases and other financing
arrangements contain financial and other covenants that create
limitations on our ability to, among other things:
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borrow the full amount under our Senior Secured Credit Facility;
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effect acquisitions or dispositions;
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pay dividends or distributions;
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make certain investments;
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incur certain liens or permit them to exist;
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enter into certain types of transactions with affiliates;
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transfer or otherwise dispose of assets; and
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incur additional debt.
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They also require us to maintain certain financial ratios and
comply with various other financial covenants. Our ability to
comply with these restrictions may be affected by events beyond
our control. A failure to comply with these restrictions could
adversely affect our ability to borrow under our Senior Secured
Credit Facility or result in an event of default under these
agreements. In the event of a default, our lenders and the
counterparties to our other financing arrangements could
terminate their commitments to us and declare all amounts
borrowed, together with accrued interest and fees, immediately
due and payable. If this were to occur, we may not be able to
pay these amounts, or we may be forced to seek an amendment to
our financing arrangements, which could make the terms of these
arrangements more onerous for us. As a result, a default under
our existing or future financing arrangements could have
significant consequences for us. For more information about some
of the restrictions contained in our Senior Secured Credit
Facility, leases and other financial arrangements, see
Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources.
Our
certificate of incorporation contains a provision renouncing our
interest and expectancy in certain corporate opportunities,
which could adversely affect our business or
prospects.
Our certificate of incorporation provides that we will renounce
any interest or expectancy in, or in being offered an
opportunity to participate in, any business opportunity that may
be from time to time presented to (i) members of our board
of directors who are not our employees, (ii) their
respective employers and (iii) affiliates of the foregoing
(other than us and our subsidiaries), other than opportunities
expressly presented
23
to such directors solely in their capacity as our director. This
provision will apply even if the opportunity is one that we
might reasonably have pursued or had the ability or desire to
pursue if granted the opportunity to do so. Furthermore, no such
person will be liable to us for breach of any fiduciary duty, as
a director or otherwise, by reason of the fact that such person
pursues or acquires any such business opportunity, directs any
such business opportunity to another person or fails to present
any such business opportunity, or information regarding any such
business opportunity. None of such persons or entities will have
any duty to refrain from engaging directly or indirectly in the
same or similar business activities or lines of business as us
or any of our subsidiaries. See Description of Capital
Stock.
For example, affiliates of our non-employee directors may become
aware, from time to time, of certain business opportunities,
such as acquisition opportunities, and may direct such
opportunities to other businesses in which they have invested or
advise, in which case we may not become aware of or otherwise
have the ability to pursue such opportunities. Further, such
businesses may choose to compete with us for these
opportunities. As a result, our renouncing our interest and
expectancy in any business opportunity that may be, from time to
time, presented to such persons or entities could adversely
impact our business or prospects if attractive business
opportunities are procured by such persons or entities for their
own benefit rather than for ours.
The
general partner of Armstrong Resource Partners, L.P. may be
removed or control of Armstrong Resource Partners, L.P. may be
otherwise transferred to a third party without the consent of
holders of our common stock.
Armstrong Resource Partners is majority-owned by Yorktown.
Pursuant to the ARP LPA, Yorktown may remove our subsidiary, Elk
Creek GP, as general partner of Armstrong Resource Partners,
L.P. or otherwise cause a change of control of Armstrong
Resource Partners, L.P. without our consent or the consent of
the holders of our common stock. If such a change in control of
Armstrong Resource Partners, L.P. were to occur, our ability to
enter into, or obtain renewals of, coal lease or mining license
agreements with Armstrong Resource Partners, L.P. could be
adversely affected. We may then have to seek alternative
agreements or arrangements with unrelated parties and such
alternative agreements or arrangements may not be available or
may be on less favorable terms.
Some
officers of Armstrong Energy may spend a substantial amount of
time managing the business and affairs of Armstrong Resource
Partners and its affiliates other than us.
These officers may face a conflict regarding the allocation of
their time between our business and the other business interests
of Armstrong Resource Partners. Armstrong Energy intends to
cause its officers to devote as much time to the management of
our business and affairs as is necessary for the proper conduct
of our business and affairs, notwithstanding that our business
may be adversely affected if the officers spend less time on our
business and affairs than would otherwise be available as a
result of such officers time being split between the
management of Armstrong Energy and of Armstrong Resource
Partners.
The
fiduciary duties of officers and directors of Elk Creek GP, as
general partner of Armstrong Resource Partners, L.P., may
conflict with those of officers and directors of Armstrong
Energy.
As the general partner of Armstrong Resource Partners, L.P., our
subsidiary Elk Creek GP has a legal duty to manage Armstrong
Resource Partners, L.P. in a manner beneficial to the limited
partners of Armstrong Resource Partners, L.P. This legal duty
originates in Delaware statutes and judicial decisions and is
commonly referred to as a fiduciary duty. However,
because Elk Creek GP is owned by Armstrong Energy, the officers
and directors of Elk Creek GP also have fiduciary duties to
manage the business of Elk Creek GP and Armstrong Resource
Partners, L.P. in a manner beneficial to Armstrong Energy. The
board of directors of Elk Creek GP, which includes some of the
directors and executive officers of Armstrong Energy, Inc., may
resolve any conflict between the interests of Armstrong Energy,
Inc. and our stockholders, on the one hand, and Armstrong
Resource Partners, L.P. and its unit holders, on the other hand,
and has broad latitude to consider the interests of all parties
to the conflict.
24
Conflicts of interest may arise between Armstrong Energy, Inc.
and Armstrong Resource Partners, L.P. with respect to matters
such as the allocation of opportunities to acquire coal reserves
in the future, the terms and amount of any related royalty
payments, whether and to what extent Armstrong Resource
Partners, L.P. may borrow under our Senior Secured Credit
Agreement or other borrowing facilities we may enter into and
other matters. Armstrong Energy may continue to provide credit
support to Armstrong Resource Partners to support borrowings it
may make in connection with any acquisition of reserves or for
other purposes, including the funding of distributions to its
unit holders. In addition, we may determine to permit Armstrong
Resource Partners to engage in other activities, including the
acquisition of coal reserves that will not be used by Armstrong
Energy.
As a result of these relationships, conflicts of interest may
arise in the future between Armstrong Energy, Inc. and its
stockholders, on the one hand, and Armstrong Resource Partners,
L.P. and its unit holders, on the other hand.
We have established a conflicts committee comprised of
independent directors of Armstrong Energy to address matters
which Armstrong Energys board of directors believes may
involve conflicts of interest. See Management and
Management Board of Directors and Board
Committees Conflicts Committee.
Armstrong
Energys board of directors may change the management and
allocation policies relating to Armstrong Resource Partners
without the approval of our stockholders.
Armstrong Energys board of directors has adopted certain
management and allocation policies to serve as guidelines in
making decisions regarding the relationships between and among
Armstrong Energy and Armstrong Resource Partners with respect to
matters such as tax liabilities and benefits, inter-group loans,
inter-group interests, financing alternatives, corporate
opportunities and similar items. These policies are not included
in our certificate of incorporation or by-laws and our board of
directors may at any time change or make exceptions to these
policies. Because these policies relate to matters concerning
the day to day management of our company, no stockholder
approval is required with respect to their adoption or
amendment. A decision to change, or make exceptions to, these
policies or adopt additional policies could disadvantage
Armstrong Energy or its stockholders.
Holders
of shares of our common stock may not have any remedies if any
action by our directors or officers in relation to Armstrong
Resource Partners has an adverse effect on only Armstrong Energy
common stock.
Principles of Delaware law and the provisions of the certificate
of incorporation and by-laws may protect decisions of our board
of directors in relation to Armstrong Resource Partners that
have a disparate impact upon holders of shares of common stock
of Armstrong Energy. Under the principles of Delaware law and
the Delaware business judgment rule, you may not be able to
successfully challenge decisions in relation to Armstrong
Resource Partners that you believe have a disparate impact upon
the holders of shares of our common stock of Armstrong Energy if
its board of directors is disinterested and independent with
respect to the action taken, is adequately informed with respect
to the action taken and acts in good faith and in the honest
belief that the board is acting in the best interest of
stockholders.
Our
capital structure may inhibit or prevent acquisition bids for
our company.
The fact that substantially all of the economic value of the
equity interests in Armstrong Resource Partners is expected to
be owned by persons or entities other than us or our controlled
affiliates could present complexities and in certain
circumstances pose obstacles, financial and otherwise, to an
acquiring person that are not present in companies which do not
have capital structures similar to ours.
25
Yorktown
will continue to have significant influence over us, including
control over decisions that require the approval of
stockholders, which could limit your ability to influence the
outcome of key transactions, including a change of
control.
After giving effect to this offering, Yorktown is expected to
beneficially own approximately % of
our outstanding common stock (or %
if the underwriters exercise their option to purchase additional
shares in full). As a result, Yorktown will retain the ability
to direct and control our business affairs. Yorktown has
influence over our decisions to enter into any corporate
transaction regardless of whether others believe that the
transaction is in our best interests. As long as Yorktown
continues to hold a large portion of our outstanding common
stock, it also will have the ability to influence the vote in
any election of directors.
Yorktown is also in the business of making investments in
companies and may from time to time acquire and hold interests
in businesses that compete directly or indirectly with us.
Yorktown may also pursue acquisition opportunities that are
complementary to our business, and, as a result, those
acquisition opportunities may not be available to us. As long as
Yorktown, or other funds controlled by or associated with
Yorktown, continue to indirectly own a significant amount of our
outstanding common stock, Yorktown will continue to be able to
strongly influence or effectively control our decisions. The
concentration of ownership may have the effect of delaying,
preventing or deterring a change of control of our company,
could deprive stockholders of an opportunity to receive a
premium for their common stock as part of a sale of our company
and might ultimately affect the market price of our common stock.
Failure
to obtain or renew surety bonds on acceptable terms could affect
our ability to secure reclamation and coal lease obligations
and, therefore, our ability to mine or lease coal.
Federal and state laws require us to obtain surety bonds to
secure performance or payment of certain long-term obligations,
such as mine closure or reclamation costs, federal and state
workers compensation costs, coal leases and other
obligations. We may have difficulty procuring or maintaining our
surety bonds. Our bond issuers may demand higher fees,
additional collateral, including letters of credit or other
terms less favorable to us upon those renewals. Because we are
required by state and federal law to have these bonds in place
before mining can commence or continue, failure to maintain
surety bonds, letters of credit or other guarantees or security
arrangements would materially and adversely affect our ability
to mine or lease coal. That failure could result from a variety
of factors, including lack of availability, higher expense or
unfavorable market terms, the exercise by third party surety
bond issuers of their right to refuse to renew the surety and
restrictions on availability on collateral for current and
future third party surety bond issuers under the terms of our
financing arrangements.
Our
ability to operate our business effectively could be impaired if
we fail to attract and retain key management
personnel.
Our ability to operate our business and implement our strategies
depends on the continued contributions of our executive officers
and key employees. In particular, we depend significantly on our
senior managements long-standing relationships within our
industry. The loss of any of our senior executives could have a
material adverse effect on our business. In addition, we believe
that our future success will depend on our continued ability to
attract and retain highly skilled management personnel with coal
industry experience and competition for these persons in the
coal industry is intense. We may not be able to continue to
employ key personnel or attract and retain qualified personnel
in the future, and our failure to retain or attract key
personnel could have a material adverse effect on our ability to
effectively operate our business.
We are
subject to various legal proceedings, which may have an adverse
effect on our business.
We are involved in a number of threatened and pending legal
proceedings incidental to our normal business activities. While
we cannot predict the outcome of the proceedings, there is
always the potential that the costs of litigation in an
individual matter or the aggregation of many matters could have
an adverse effect on our cash flows, results of operations or
financial position.
26
A
shortage of skilled labor in the mining industry could reduce
labor productivity and increase costs, which could have a
material adverse effect on our business and results of
operations.
Efficient coal mining using modern techniques and equipment
requires skilled laborers in multiple disciplines such as
equipment operators, mechanics, electricians and engineers,
among others. We have from time to time encountered shortages
for these types of skilled labor. If we experience shortages of
skilled labor in the future, our labor and overall productivity
or costs could be materially and adversely affected. If coal
prices decrease in the future or our labor prices increase, or
if we experience materially increased health and benefit costs
with respect to our employees, our results of operations could
be materially and adversely affected.
Our
work force could become unionized in the future, which could
adversely affect the stability of our production and materially
reduce our profitability.
All of our mines are operated by non-union employees. Our
employees have the right at any time under the National Labor
Relations Act to form or affiliate with a union, subject to
certain voting and other procedural requirements. If our
employees choose to form or affiliate with a union and the terms
of a union collective bargaining agreement are significantly
different from our current compensation and job assignment
arrangements with our employees, these arrangements could
adversely affect the stability of our production through
potential strikes, slowdowns, picketing and work stoppages, and
materially reduce our profitability.
Our
ability to collect payments from our customers could be impaired
if their creditworthiness deteriorates.
Our ability to receive payment for the coal we sell depends on
the continued creditworthiness of our customers. The current
economic volatility and tightening credit markets increase the
risk that we may not be able to collect payments from our
customers. A continuation or worsening of current economic
conditions or other prolonged global or U.S. recessions
could also impact the creditworthiness of our customers. If the
creditworthiness of a customer declines, this would increase the
risk that we may not be able to collect payment for all of the
coal we sell to that customer. If we determine that a customer
is not creditworthy, we may not be required to deliver coal
under the customers coal sales contract. If we are able to
withhold shipments, we may decide to sell the customers
coal on the spot market, which may be at prices lower than the
contract price, or we may be unable to sell the coal at all.
Furthermore, the bankruptcy of any of our customers could have a
material adverse effect on our financial position. In addition,
competition with other coal suppliers could force us to extend
credit to customers and on terms that could increase the risk of
payment default.
We
will be required by Section 404 of the
Sarbanes-Oxley
Act to evaluate the effectiveness of our internal controls. We
have identified control deficiencies, including material
weaknesses, in the past, which have been remediated. If we are
unable to establish and maintain effective internal controls,
our financial condition and operating results could be adversely
affected.
We are in the process of evaluating our internal controls
systems to allow management to report on, and our independent
auditors to audit, our internal controls over financial
reporting. We are also in the process of performing the system
and process evaluation and testing (and any necessary
remediation) required to comply with the management
certification and auditor attestation requirements of
Section 404 of the
Sarbanes-Oxley
Act of 2002. We anticipate that we will be required to comply
with Section 404 for the year ending December 31, 2013.
However, we cannot be certain as to the timing of completion of
our evaluation, testing and remediation actions or the impact of
the same on our operations. Furthermore, upon completion of this
process, we may identify control deficiencies of varying degrees
of severity under applicable SEC and Public Company Accounting
Oversight Board rules and regulations that remain unremediated.
As a public company, we will be required to report, among other
things, control deficiencies that constitute a material
weakness or changes in internal controls that, or that are
reasonably likely to, materially affect internal controls over
financial reporting. A material weakness is a
deficiency or combination of deficiencies in internal controls
over financial reports that results in more than a remote
likelihood that a material misstatement of the annual or
27
interim consolidated financial statements will not be prevented
or detected. A significant deficiency is a
deficiency or combination of deficiencies that is less severe
than a material weakness.
We have identified deficiencies in our internal control over
financial reporting, including in connection with the financial
statement close process for the year ended December 31,
2011, in which we identified an error in our calculation of
depreciation, depletion, and amortization. Although we believe
this material weakness has been remediated, if we are unable to
appropriately maintain the remediation plan we have implemented
and maintain any other necessary controls we implement in the
future, our management might not be able to certify, and our
independent registered public accounting firm might not be able
to deliver an unqualified report on the adequacy of our internal
control over financial reporting.
If we fail to implement the requirements of Section 404 in
a timely manner, we might be subject to sanctions or
investigation by regulatory authorities such as the SEC. In
addition, failure to comply with Section 404 or the report
by us of a material weakness may cause investors to lose
confidence in our consolidated financial statements, and as a
result our common stock price may be adversely affected. If we
fail to remedy any material weakness, our consolidated financial
statements may be inaccurate, we may face restricted access to
the capital markets and our common stock price may be adversely
affected.
Terrorist
attacks and threats, escalation of military activity in response
to these attacks or acts of war could have a material adverse
effect on our business, financial condition or results of
operations.
Terrorist attacks and threats, escalation of military activity
or acts of war may have significant effects on general economic
conditions, fluctuations in consumer confidence and spending and
market liquidity, each of which could materially and adversely
affect our business. Future terrorist attacks, rumors or threats
of war, actual conflicts involving the United States or its
allies, or military or trade disruptions affecting our customers
may significantly affect our operations and those of our
customers. Strategic targets, such as energy-related assets and
transportation assets, may be at greater risk of future
terrorist attacks than other targets in the United States.
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.
Risks
Related to Environmental, Other Regulations and
Legislation
New
regulatory requirements limiting greenhouse gas emissions could
adversely affect coal-fired power generation and reduce the
demand for coal as a fuel source, which could cause the price
and quantity of the coal we sell to decline
materially.
One major by-product of burning coal is carbon dioxide
(CO2),
which is a greenhouse gas and a source of concern with respect
to global warming, also known as Climate Change. Climate Change
continues to attract government, public and scientific
attention, especially on ways to reduce greenhouse gas
emissions, including from coal-fired power plants. Various
international, federal, regional and state proposals are being
considered to limit emissions of greenhouse gases, including
possible future U.S. treaty commitments, new federal or
state legislation that may establish a
cap-and-trade
regime, and regulation under existing environmental laws by the
EPA and other regulatory agencies. Future regulation of
greenhouse gas emissions may require additional controls on, or
the closure of, coal-fired power plants and industrial boilers
and may restrict the construction of new coal-fired power plants.
The permitting of new coal-fired power plants has also recently
been contested by state regulators and environmental advocacy
organizations due to concerns related to greenhouse gas
emissions. In addition, a federal appeals court has allowed a
lawsuit pursuing federal common law claims to proceed against
certain utilities on the basis that they may have created a
public nuisance due to their emissions of carbon dioxide,
although the U.S. Supreme Court has since held that federal
common law provides no basis for such claims. Future regulation,
litigation and permitting related to greenhouse gas emissions
may cause some users of coal to switch from coal to a
lower-carbon fuel, or otherwise reduce the use of and demand for
fossil fuels,
28
particularly coal, which could have a material adverse effect on
our business, financial condition or results of operations. See
Business Regulation and Laws
Climate Change.
Extensive
environmental requirements, including existing and potential
future requirements relating to air emissions, affect our
customers and could reduce the demand for coal as a fuel source
and cause coal prices and sales of our coal to materially
decline.
Coal contains impurities, including but not limited to sulfur,
mercury, chlorine and other elements or compounds, many of which
are released into the air when coal is burned. The operations of
our customers are subject to extensive environmental
requirements, particularly with respect to air emissions. For
example, the federal Clean Air Act and similar state and local
laws extensively regulate the amount of sulfur dioxide
(SO2),
particulate matter, nitrogen oxides (NOx), and other
compounds emitted into the air from electric power plants, which
are the largest end-users of our coal. A series of more
stringent requirements relating to particulate matter, ozone,
haze, mercury,
SO2,
NOx, toxic gases and other air pollutants have been proposed or
could become effective in coming years. In addition, concerted
conservation efforts that result in reduced electricity
consumption could cause coal prices and sales of our coal to
materially decline.
Considerable uncertainty is associated with these air emissions
initiatives. The content of additional requirements in the
U.S. is in the process of being developed, and many new
initiatives remain subject to review by federal or state
agencies or the courts. Stringent air emissions limitations are
either in place or may be imposed in the short to medium term,
and these limitations will likely require significant emissions
control expenditures for many coal-fired power plants. As a
result, these power plants may switch to other fuels that
generate fewer of these emissions and the construction of new
coal-fired power plants may become less desirable. The
EIAs expectations for the coal industry assume there will
be a significant number of as yet unplanned coal-fired plants
built in the future. Any switching of fuel sources away from
coal, closure of existing coal-fired plants, or reduced
construction of new plants could have a material adverse effect
on demand for and prices received for our coal.
In addition, contamination caused by the disposal of coal
combustion byproducts, including coal ash, can lead to material
liability to our customers under federal and state laws. In
addition, the EPA has proposed a rule concerning management of
coal combustion residuals. New EPA regulation of such management
would likely increase the ultimate costs to our customers of
coal combustion. Such liabilities and increased costs in turn
could have a material adverse effect on the demand for and
prices received for our coal.
See Business Regulation and Laws for
more information about the various governmental regulations
affecting us.
Legal
requirements that we expect to significantly expand scrubbed
coal-fired electricity generating capacity may be overturned or
not enacted at all, which could result in less demand for
Illinois Basin coal than we anticipate and materially and
adversely affect our coal prices and/or sales.
Although a number of legal requirements have been or are in the
process of being implemented that are expected to expand
significantly the scrubbed coal-fired electricity generating
capacity in the U.S., regulations driving this trend are subject
to legal challenge, and could also be the subject of future
legislation that withdraws any authorization for such
requirements. For example, the recently finalized Cross-State
Air Pollution Rule (CSAPR) has been challenged in
court by a number of southern and Midwestern states and several
energy companies. In December 2011, the U.S. Court of
Appeals for the District of Columbia Circuit issued a ruling to
stay the CSAPR pending judicial review. The outcome of such
legal proceedings, and other possible developments including,
for example, changes in presidential administration and the
administration of the EPA, or the enactment by Congress of more
lenient air pollution laws than are currently in effect, could
result in significantly less expansion of scrubbed coal-fired
electricity generating capacity than we anticipate. This in turn
could mean that the strong increase in demand for relatively
high-sulfur Illinois Basin coal we believe will occur in the
future may not materialize, or may not materialize as soon as it
otherwise would. This could adversely affect the demand for our
coal and the price we will receive, which could materially and
adversely affect our coal prices and/or sales.
29
Our
failure to obtain and renew permits and approvals necessary for
our mining operations could negatively affect our
business.
Coal production is dependent on our ability to obtain and
maintain various federal and state permits and approvals to mine
our coal reserves within the timeline specified in our mining
plans. The permitting rules, and the interpretations of these
rules, are complex, change frequently, and are often subject to
discretionary interpretations by regulators, which may increase
the costs or possibly preclude the continuance of ongoing mining
operations or the development of future mining operations. In
addition, the public, including
non-governmental
organizations, anti-mining groups and individuals, have certain
statutory rights to comment upon and otherwise impact the
permitting process, including through court intervention. The
slowing pace at which necessary permits are issued or renewed
for new and existing mines has materially impacted coal
production, especially in Central Appalachia. Permitting by the
Army Corps of Engineers (the Corps), the EPA and the
Department of the Interior has become subject to enhanced
review under both the Surface Mining Control and
Reclamation Act of 1977 (the SMCRA), and the federal
Clean Water Act (the CWA), to reduce the harmful
environmental consequences of mountain-top mining, especially in
the Appalachian region.
For example, in April 2010, the EPA issued comprehensive interim
final guidance regarding the review of certain new and renewed
CWA permit applications for Appalachian surface coal mining
operations. EPAs guidance is subject to several pending
legal challenges related to its legal effect and sufficiency
including consolidated challenges pending in Federal District
Court in the District of Columbia led by the National Mining
Association. This guidance may apply to our applications to
obtain and maintain permits that are important to our
operations. We cannot give any assurance regarding the impact
that this or any successor guidance may have on the issuance or
renewal of such permits.
Typically, we submit the necessary permit applications 12 to
30 months before we plan to mine a new area. Some of our
required mining permits are becoming increasingly difficult to
obtain within the time frames to which we were previously
accustomed, and in some instances we have had to delay the
mining of coal in certain areas covered by the application in
order to obtain required permits and approvals. Permits could be
delayed in the future if the EPA continues its enhanced review
of CWA applications. If the required permits are not issued or
renewed in a timely fashion or at all, or if permits issued or
renewed are conditioned in a manner that restricts our ability
to efficiently and economically conduct our mining activities,
we could suffer a material reduction in our production and our
operations, and there could be a material adverse effect on our
ability to produce coal profitably. See
Business Regulation and Laws.
Section 404(q) of the CWA establishes a requirement that
the Secretary of the Army and the Administrator of the EPA enter
into an agreement assuring that delays in the issuance of
permits under Section 404 are minimized. In August 1992,
the Department of the Army and the EPA entered into such an
agreement. The 1992 Section 404(q) Memorandum of Agreement
(MOA) outlines the current process and time frames
for resolving disputes in an effort to issue timely permit
decisions. Under this MOA, the EPA may request that certain
permit applications receive a higher level of review within the
Department of Army. In these cases, the EPA determines that
issuance of the permit will result in unacceptable adverse
effects to Aquatic Resources of National Importance
(ARNI). Alternately, the EPA may raise concerns over
Section 404 program policies and procedures. An ARNI is a
resource-based threshold used to determine whether a dispute
between the EPA and the Corps regarding individual permit cases
are eligible for elevation under the MOA. Factors used in
identifying ARNIs include the economic importance of the aquatic
resource, rarity or uniqueness, and/or importance of the aquatic
resource to the protection, maintenance, or enhancement of the
quality of the waters.
We received notice from the EPA dated July 25, 2011 that it
believes that the proposed discharge plan submitted by us in
connection with our Section 404 permit application for the
expanded mining at our Midway Mine would result in unacceptable
impacts on ARNIs, and in particular, downstream waters outside
the scope of the permit area. As a result, it is possible that
the Corps will deny our pending permit application, or that the
EPA will elevate the permit application to a higher level of
review should the Corps proceed with the issuance of the permit
notwithstanding EPAs concerns. Ultimately, the EPA may
consider initiating a Section 404(c) veto of
the permit. A material delay in the issuance of this permit, or
other Section 404
30
permits that we may require as part of our mining operations, or
the denial or veto of such permits, could have a materially
negative effect on our operations and profitability.
Federal
or state regulatory agencies have the authority to order certain
of our mines to be temporarily or permanently closed under
certain circumstances, which could materially and adversely
affect our ability to meet our customers
demands.
Federal or state regulatory agencies have the authority under
certain circumstances following significant health and safety
incidents, such as fatalities, to order a mine to be temporarily
or permanently closed. If this were to occur, capital
expenditures could be required in order for us to be allowed
could be required in order for us to be allowed to reopen the
mine. In the event that these agencies order the closing of our
mines, our coal sales contracts generally allow us to issue
force majeure notices which suspend our obligations to deliver
coal under these contracts. However, our customers may challenge
our issuances of force majeure notices. If these challenges are
successful, we may have to purchase coal from third-party
sources, if it is available, to fulfill these obligations, incur
capital expenditures to reopen the mines
and/or
negotiate settlements with the customers, which may include
price reductions, the reduction of commitments or the extension
of time for delivery or terminate customers contracts. Any
of these actions could have a material adverse effect on our
business and results of operations.
Extensive
environmental laws and regulations impose significant costs on
our mining operations, and future laws and regulations could
materially increase those costs or limit our ability to produce
and sell coal.
The coal mining industry is subject to increasingly strict
regulation by federal, state and local authorities with respect
to environmental matters such as:
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limitations on land use;
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mine permitting and licensing requirements;
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reclamation and restoration of mining properties after mining is
completed;
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management of materials generated by mining operations;
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the storage, treatment and disposal of wastes;
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remediation of contaminated soil and groundwater;
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air quality standards;
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water pollution;
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protection of human health, plant-life and wildlife, including
endangered or threatened species;
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protection of wetlands;
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the discharge of materials into the environment;
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the effects of mining on surface water and groundwater quality
and availability; and
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the management of electrical equipment containing
polychlorinated biphenyls.
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The costs, liabilities and requirements associated with the laws
and regulations related to these and other environmental matters
may be costly and time-consuming and may delay commencement or
continuation of exploration or production operations. We cannot
assure you that we have been or will be at all times in
compliance with the applicable laws and regulations. Failure to
comply with these laws and regulations may result in the
assessment of administrative, civil and criminal penalties, the
imposition of cleanup and site restoration costs and liens, the
issuance of injunctions to limit or cease operations, the
suspension or revocation of permits and other enforcement
measures that could have the effect of limiting production from
our operations. We may incur material costs and liabilities
resulting from claims for damages to property or injury to
persons arising from our operations. If we are pursued for
sanctions, costs and liabilities in respect of these matters, we
could be materially and adversely affected.
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New legislation or administrative regulations or new judicial
interpretations or administrative enforcement of existing laws
and regulations, including proposals related to the protection
of the environment that would further regulate and tax the coal
industry, may also require us to change operations significantly
or incur increased costs. For example, in December 2008, the
U.S. Department of the Interiors Office of Surface
Mining Reclamation and Enforcement (the OSM) revised
the original stream buffer zone rule (the SBZ
Rule), which had been issued under the SMCRA in 1983. The
SBZ Rule was challenged in the U.S. District Court for the
District of Columbia. In a March 2010 settlement with the
litigation parties, the OSM agreed to use its best efforts to
adopt a final rule by June 2012. In addition, Congress has
proposed, and may in the future propose, legislation to restrict
the placement of mining material in streams. The requirements of
the revised SBZ Rule or future legislation, when adopted, will
likely be stricter than the prior SBZ Rule to further protect
streams from the impact of surface mining. Such changes could
have a material adverse effect on our financial condition and
results of operations. See Business Regulation
and Laws.
If the
assumptions underlying our estimates of reclamation and mine
closure obligations are inaccurate, our costs could be greater
than anticipated.
SMCRA and counterpart state laws and regulations establish
operational, reclamation and closure standards for all aspects
of surface mining, as well as most aspects of underground
mining. We base our estimates of reclamation and mine closure
liabilities on permit requirements, engineering studies and our
engineering expertise related to these requirements. Our
management and engineers periodically review these estimates.
The estimates can change significantly if actual costs vary from
our original assumptions or if governmental regulations change
significantly. We are required to record new obligations as
liabilities at fair value under generally accepted accounting
principles. In estimating fair value, we considered the
estimated current costs of reclamation and mine closure and
applied inflation rates and a third-party profit, as required.
The third-party profit is an estimate of the approximate markup
that would be charged by contractors for work performed on our
behalf. The resulting estimated reclamation and mine closure
obligations could change significantly if actual amounts change
significantly from our assumptions, which could have a material
adverse effect on our results of operations and financial
condition.
Our
operations may impact the environment or cause exposure to
hazardous substances, and our properties may have environmental
contamination, which could result in material liabilities to
us.
Our operations currently use hazardous materials and generate
limited quantities of hazardous wastes from time to time, which
may affect runoff or drainage water or other aspects of the
environment. We could become subject to claims for toxic torts,
natural resource damages and other damages as well as for the
investigation and clean up of soil, surface water, groundwater,
and other media. Such claims may arise, for example, out of
conditions at sites that we currently own or operate, as well as
at sites that we previously owned or operated, or may acquire.
Our liability for such claims may be joint and several, so that
we may be held responsible for more than our share of the
contamination or other damages, or even for the entire share.
We maintain extensive coal refuse areas and slurry impoundments
at a number of our mines. Such areas and impoundments are
subject to extensive regulation. Slurry impoundments have been
known to fail, releasing large volumes of coal slurry into the
surrounding environment. Structural failure of an impoundment
can result in extensive damage to the environment and natural
resources, such as bodies of water that the coal slurry reaches,
as well as liability for related personal injuries and property
damages, and injuries to wildlife. Some of our impoundments
overlie mined out areas, which could 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 civil or criminal fines and
penalties.
Drainage flowing from or caused by mining activities can be
acidic with elevated levels of dissolved metals, a condition
referred to as acid mine drainage, which we refer to
as AMD. The treating of AMD can be costly. Although we do not
currently face material costs associated with AMD, it is
possible that we could incur significant costs in the future.
32
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.
Changes
in the legal and regulatory environment could complicate or
limit our business activities, increase our operating costs or
result in litigation.
The conduct of our businesses is subject to various laws and
regulations administered by federal, state and local
governmental agencies in the United States. These laws and
regulations may change, sometimes dramatically, as a result of
political, economic or social events or in response to
significant events. Certain recent developments particularly may
cause changes in the legal and regulatory environment in which
we operate and may impact our results or increase our costs or
liabilities. Such legal and regulatory environment changes may
include changes in:
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the processes for obtaining or renewing permits;
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costs associated with providing healthcare benefits to employees;
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health and safety standards;
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accounting standards;
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taxation requirements; and
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competition laws.
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In 2006, the Federal Mine Improvement and New Emergency Response
Act of 2006 (the MINER Act), was enacted. The MINER
Act significantly amended the Federal Mine Safety and Health Act
of 1977 (the Mine Act), imposing more extensive and
stringent compliance standards, increasing criminal penalties
and establishing a maximum civil penalty for non-compliance, and
expanding the scope of federal oversight, inspection, and
enforcement activities.
Following the passage of the MINER Act, the U.S. Mine
Safety and Health Administration (MSHA), issued new
or more stringent rules and policies on a variety of topics,
including:
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sealing off abandoned areas of underground coal mines;
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mine safety equipment, training and emergency reporting
requirements;
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substantially increased civil penalties for regulatory
violations;
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training and availability of mine rescue teams;
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underground refuge alternatives capable of
sustaining trapped miners in the event of an emergency;
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flame-resistant conveyor belt, fire prevention and detection,
and use of air from the belt entry; and
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post-accident two-way communications and electronic tracking
systems.
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Subsequent to passage of the MINER Act, Illinois, Kentucky,
Pennsylvania, Ohio and West Virginia have enacted legislation
addressing issues such as mine safety and accident reporting,
increased civil and criminal penalties, and increased
inspections and oversight. Other states may pass similar
legislation in the future. Also, additional federal and state
legislation that further increase mine safety regulation,
inspection and enforcement, particularly with respect to
underground mining operations, has been considered in light of
recent fatal mine accidents. In 2010, the 111th Congress
introduced federal legislation seeking to impose extensive
additional safety and health requirements on coal mining. While
the legislation was passed by the House of Representatives, the
legislation was not voted on in the Senate and did not become
law. On January 26, 2011, the same legislation was
reintroduced in the 112th Congress by Senators Jay
Rockefeller (D-W.Va.), Tom Harkin (D-Iowa), Patty Murray
(D-Wash.) and Joe Manchin III (D-W.Va.). Further workplace
accidents are likely to also result in more stringent
enforcement and possibly the passage of new laws and regulations.
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The Dodd-Frank Wall Street Reform and Consumer Protection Act
(the Dodd-Frank Act), that was signed into law on
July 21, 2010, requires public companies to disclose in
their periodic reports filed with the Securities and Exchange
Commission (the SEC) substantial additional
information about safety issues relating to our mining
operations. After effectiveness of our registration statement,
we will be subject to the provisions of the Dodd-Frank Act.
In response to the April 2010 explosion at Massey Energy
Companys Upper Big Branch Mine and the ensuing tragedy, we
expect that safety matters pertaining to underground coal mining
operations may be the topic of additional new federal
and/or state
legislation and regulation, as well as the subject of heightened
enforcement efforts. For example, federal authorities have
announced special inspections of coal mines to evaluate several
safety concerns, including the accumulation of coal dust and the
proper ventilation of gases such as methane. In addition,
federal authorities have announced that they are considering
changes to mine safety rules and regulations which could
potentially result in additional or enhanced required safety
equipment, more frequent mine inspections, stricter and more
thorough enforcement practices and enhanced reporting
requirements. Any new environmental, health and safety
requirements may be replicated in the states in which we operate
and could increase our operating costs or otherwise may prevent,
delay or reduce our planned production, any of which could
adversely affect our financial condition, results of operations
and cash flows.
Although we are unable to quantify the full impact, implementing
and complying with new laws and regulations could have an
adverse impact on our business and results of operations and
could result in harsher sanctions in the event of any
violations. See Business Regulation and
Laws.
Certain
United States federal income tax preferences currently available
with respect to coal exploration and development may be
eliminated as a result of future legislation.
President Obamas Proposed Fiscal Year 2012 budget
recommends elimination of certain key United States federal
income tax preferences relating to coal exploration and
development (the Budget Proposal). The Budget
Proposal would (1) eliminate current deductions and
60-month
amortization for exploration and development costs relating to
coal and other hard mineral fossil fuels, (2) repeal the
percentage depletion allowance with respect to coal properties,
(3) repeal capital gains treatment of coal and lignite
royalties, and (4) exclude from the definition of domestic
production gross receipts all gross receipts derived from the
sale, exchange, or other disposition of coal, other hard mineral
fossil fuels, or primary products thereof. The passage of any
legislation as a result of the Budget Proposal or any other
similar changes in United States federal income tax laws could
eliminate certain tax deductions that are currently available
with respect to coal exploration and development, and any such
change could increase our taxable income and negatively impact
the value of an investment in our common stock.
Risks
Related to This Offering and Our Common Stock
An
active, liquid trading market for our common stock may not
develop.
Prior to this offering, there has not been a public market for
our common stock. We cannot predict the extent to which investor
interest in us will lead to the development of a trading market
on Nasdaq or otherwise or how active and liquid that market may
become. If an active and liquid trading market does not develop,
you may have difficulty selling any of our common stock that you
purchase.
Our
stock price may change significantly following the offering, and
you could lose all or part of your investment as a
result.
Even if an active trading market develops, the market price for
shares of our common stock may be highly volatile and could be
subject to wide fluctuations after this offering. We and the
underwriters will negotiate to determine the initial public
offering price. You may not be able to resell your shares at or
above
34
the initial public offering price due to a number of factors
such as those listed in Risks Related to the
Company. Some of the factors that could negatively affect
our share price include:
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changes in oil and gas prices;
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changes in our funds from operations and earnings estimates;
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publication of research reports about us or the energy services
industry;
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increase in market interest rates, which may increase our cost
of capital;
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changes in applicable laws or regulations, court rulings and
enforcement and legal actions;
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changes in market valuations of similar companies;
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adverse market reaction to any increased indebtedness we may
incur in the future;
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additions or departures of key management personnel;
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actions by our stockholders;
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speculation in the press or investment community;
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a large volume of sellers of our common stock pursuant to our
resale registration statement with a relatively small volume of
purchasers; or
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general market and economic conditions.
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Furthermore, the stock market has recently experienced extreme
volatility that in some cases has been unrelated or
disproportionate to the operating performance of particular
companies. These broad market and industry fluctuations may
adversely affect the market price of our common stock,
regardless of our actual operating performance.
In the past, following periods of market volatility,
stockholders have instituted securities class action litigation.
If we were involved in securities litigation, it could have a
substantial cost and divert resources and the attention of
executive management from our business regardless of the outcome
of such litigation.
The
offering price per share of the common stock may not accurately
reflect its actual value.
The initial public offering price per share of our common stock
offered under this prospectus reflects the result of
negotiations between us and the underwriters. The offering price
may not accurately reflect the value of our common stock, and
may not be indicative of prices that will prevail in the open
market following this offering.
We do
not anticipate paying any dividends on our common stock in the
foreseeable future.
For the foreseeable future, we intend to retain earnings to grow
our business. Payments of future dividends, if any, will be at
the discretion of our board of directors and will depend on many
factors, including general economic and business conditions, our
strategic plans, our financial results and condition, legal
requirements and other factors as our board of directors deems
relevant. Our Senior Secured Credit Facility restricts our
ability to pay cash dividends on our common stock and we may
also enter into credit agreements or borrowing arrangements in
the future that will restrict our ability to declare or pay cash
dividends on our common stock.
We
will incur increased costs as a result of being a public
company.
As a privately held company, we have not been responsible for
the corporate governance and financial reporting practices and
policies required of a publicly traded company. Following the
effectiveness of the registration statement of which this
prospectus is a part, we will be a public company. As a public
company with listed equity securities, we will need to comply
with new laws, regulations and requirements, certain corporate
governance provisions of the Sarbanes-Oxley Act of 2002, related
regulations of the SEC and the
35
requirements of Nasdaq or other stock exchange on which our
common stock is listed, with which we are not required to comply
as a private company. Complying with these statutes, regulations
and requirements will occupy a significant amount of time of our
board of directors and management and will significantly
increase our costs and expenses. We will need to:
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institute a more comprehensive compliance function;
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design, establish, evaluate and maintain a system of internal
controls over financial reporting in compliance with the
requirements of Section 404 of the Sarbanes-Oxley Act of
2002 and the related rules and regulations of the SEC and the
Public Company Accounting Oversight Board;
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comply with rules promulgated by the NYSE, Nasdaq or other stock
exchange on which our common stock is listed;
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prepare and distribute periodic public reports in compliance
with our obligations under the federal securities laws;
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establish new internal policies, such as those relating to
disclosure controls and procedures and insider trading;
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involve and retain to a greater degree outside counsel and
accountants in the above activities; and
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establish an investor relations function.
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In addition, we also expect that being a public company subject
to these rules and regulations will require us to accept less
director and officer liability insurance coverage than we desire
or to incur substantial costs to obtain coverage. These factors
could also make it more difficult for us to attract and retain
qualified members of our board of directors, particularly to
serve on our audit committee, and qualified executive officers.
Future
sales, or the perception of future sales, of our common stock
may depress our share price.
We may in the future issue our previously authorized and
unissued securities. At the closing of this offering, we will be
authorized to issue shares of
common stock and preferred stock with such designations,
preferences and rights as determined by our board of directors.
The potential issuance of such additional shares of common stock
will result in the dilution of the ownership interests of the
purchasers of our common stock in this offering and may create
downward pressure on the trading price, if any, of our common
stock. The sales of substantial amounts of our common stock
following the effectiveness of the registration statement of
which this prospectus is a part, or the perception that these
sales may occur, could cause the market price of our common
stock to decline and impair our ability to raise capital. Based
on shares of common stock
outstanding as of , 2012, upon
completion of this offering, we will
have shares of common stock
outstanding. Of these outstanding shares, all of the shares of
our common stock sold in this offering will be freely tradable
in the public market, except for any shares held by our
affiliates, as defined in Rule 144 under the Securities Act.
We, our directors, executive officers and stockholders have
agreed with the underwriters, subject to certain exceptions, not
to dispose of or hedge any shares of our common stock or any
securities convertible into, or exercisable or exchangeable for,
shares of our common stock for a period of 180 days from
the date of this prospectus, which may be extended upon the
occurrence of specified events, except with the prior written
consent
of . ,
at any time and without notice, may release all or any portion
of the common stock subject to the
lock-up
agreements entered into in connection with this offering. If the
restrictions under the
lock-up
agreements are waived, our common stock will be available for
sale into the market, which could reduce the market value for
our common stock.
After the expiration of the
lock-up
agreements and other contractual restrictions that prohibit
transfers for at least 180 days after the date of this
prospectus, up to restricted
securities may be sold into the public market in the future
without registration under the Securities Act to the extent
permitted under Rule 144. Of these restricted securities,
approximately shares will be
available for sale
approximately days after the
date of this prospectus, subject to volume or other limits under
Rule 144.
36
If
securities or industry analysts do not publish research or
reports about our business, if they adversely change their
recommendations regarding our common stock, or if our operating
results do not meet their expectations, the price and trading
volume of our common stock could decline.
The trading market for our common stock will be influenced by
the research and reports that securities or industry analysts
publish about us or our business. Securities analysts may elect
not to provide research coverage of our common stock. This lack
of research coverage could adversely affect the price of our
common stock. We do not have any control over these reports or
analysts. If any of the analysts who cover us downgrades our
stock, or if our operating results do not meet the
analysts expectations, our stock price could decline.
Moreover, if any of these analysts ceases coverage of us or
fails to publish regular reports on our business, we could lose
visibility in the market, which in turn could cause our common
stock price and trading volume to decline and our common stock
to be less liquid.
You
will incur immediate dilution in the book value of your common
stock as a result of this offering.
The initial public offering price of our common stock is
considerably more than the as adjusted, net tangible book value
per share of our outstanding common stock. This reduction in the
value of your equity is known as dilution. This dilution occurs
in large part because our earlier investors paid substantially
less than the initial public offering price when they purchased
their shares. Investors purchasing common stock in this offering
will incur immediate dilution of $
in as adjusted, net tangible book value per share of common
stock, based on the assumed initial public offering price of
$ per share, which is the midpoint
of the price range listed on the front cover page of this
prospectus. In addition, following this offering, purchasers in
the offering will have
contributed % of the total
consideration paid by our stockholders to purchase shares of
common stock. For a further description of the dilution that you
will experience immediately after this offering, see
Dilution. In addition, if we raise funds by issuing
additional securities, the newly-issued shares will further
dilute your percentage ownership of us.
Provisions
in our organizational documents and under Delaware law could
delay or prevent a change in control of our company, which could
adversely affect the price of our common stock.
The existence of some provisions in our organizational documents
and under Delaware law could delay or prevent a change in
control of our company that a stockholder may consider
favorable, which could adversely affect the price of our common
stock. The provisions in our amended and restated certificate of
incorporation and bylaws that could delay or prevent an
unsolicited change in control of our company include board
authority to issue preferred stock without stockholder approval,
and advance notice provisions for director nominations or
business to be considered at a stockholder meeting. These
provisions may also discourage acquisition proposals or delay or
prevent a change of control, which could harm our stock price.
See Description of Capital Stock Anti-Takeover
Effects of Certain Provisions of Our Amended and Restated
Certificate of Incorporation, Bylaws and Delaware Law.
Our
management team may not be able to organize and effectively
manage a publicly traded operating company, which could
adversely affect our overall financial position.
Some of our senior executive officers or directors have not
previously organized or managed a publicly traded operating
company, and our senior executive officers and directors may not
be successful in doing so. The demands of organizing and
managing a publicly traded operating company are much greater as
compared to a private company and some of our senior executive
officers and directors may not be able to meet those increased
demands. Failure to organize and effectively manage us could
adversely affect our overall financial position.
37
Future
offerings of debt securities, which would rank senior to our
common stock upon our liquidation, and future offerings of
equity securities, which would dilute our existing stockholders,
may adversely affect the market value of common
stock.
In the future, we may attempt to increase our capital resources
by making offerings of debt or additional offerings of equity
securities, including commercial paper, medium-term notes,
senior or subordinated notes and classes of preferred stock.
Upon liquidation, holders of our debt securities and preferred
stock and lenders with respect to other borrowings will receive
a distribution of our available assets prior to the holders of
our common stock. Additional equity offerings may dilute the
holdings of our existing stockholders or reduce the market value
of our common stock, or both. Our preferred stock, which could
be issued without stockholder approval, if issued, could have a
preference on liquidating distributions or a preference on
dividend payments that would limit amounts available for
distribution to holders of our common stock. Because our
decision to issue securities in any future offering will depend
on market conditions and other factors beyond our control, we
cannot predict or estimate the amount, timing or nature of our
future offerings. Thus, holders of our common stock bear the
risk of our future offerings reducing the market value of our
common stock and diluting their share holdings in us.
Non-U.S.
holders of our common stock may be subject to United States
federal income tax with respect to gain on the disposition of
our common stock.
If we are or have been a United States real property
holding corporation within the meaning of the Internal
Revenue Code of 1986, as amended (the Code), at any
time within the shorter of (1) the five-year period
preceding a disposition of our common stock by a
non-U.S. holder
(as defined below under Material United States Federal
Income and Estate Tax Consequences to
Non-U.S. Holders),
or (2) such holders holding period for such common
stock, and assuming our common stock is regularly
traded, as defined by applicable United States Treasury
regulations, on an established securities market, the
non-U.S. holder
may be subject to United States federal income tax with respect
to gain on such disposition if it held more than 5% of our
common stock at any time during the shorter of periods
(1) and (2) above. We believe we are, and will
continue to be, a United States real property holding
corporation.
If our common stock is not considered to be regularly traded on
an established securities market during the calendar year in
which a sale or disposition occurs, the buyer or other
transferee of our common stock generally will be required to
withhold tax at the rate of 10% on the sales price or other
amount realized as a prepayment of a transferors United
States federal income tax liability, unless the transferor
furnishes an affidavit certifying that it is not a foreign
person in the manner and form specified in applicable United
States Treasury regulations.
38
CAUTIONARY
STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Various statements contained in this prospectus, including those
that express a belief, expectation or intention, as well as
those that are not statements of historical fact, are
forward-looking statements. These forward-looking statements may
include projections and estimates concerning the timing and
success of specific projects and our future production,
revenues, income and capital spending. Our forward-looking
statements are generally accompanied by words such as
estimate, project, predict,
believe, expect, anticipate,
potential, plan, goal or
other words that convey the uncertainty of future events or
outcomes. The forward-looking statements in this prospectus
speak only as of the date of this prospectus; we disclaim any
obligation to update these statements unless required by law,
and we caution you not to rely on them unduly. We have based
these forward-looking statements on our current expectations and
assumptions about future events. While our management considers
these expectations and assumptions to be reasonable, they are
inherently subject to significant business, economic,
competitive, regulatory and other risks, contingencies and
uncertainties, most of which are difficult to predict and many
of which are beyond our control. These and other important
factors, including those discussed under Risk
Factors and Managements Discussion and
Analysis of Financial Condition and Results of Operations
may cause our actual results, performance or achievements to
differ materially from any future results, performance or
achievements expressed or implied by these forward-looking
statements. These risks, contingencies and uncertainties
include, but are not limited to, the following:
|
|
|
|
|
market demand for coal and electricity;
|
|
|
|
geologic conditions, weather and other inherent risks of coal
mining that are beyond our control;
|
|
|
|
competition within our industry and with producers of competing
energy sources;
|
|
|
|
excess production and production capacity;
|
|
|
|
our ability to acquire or develop coal reserves in an
economically feasible manner;
|
|
|
|
inaccuracies in our estimates of our coal reserves;
|
|
|
|
availability and price of mining and other industrial supplies,
including steel-based supplies, diesel fuel, rubber tires and
explosives;
|
|
|
|
availability of skilled employees and other workforce factors;
|
|
|
|
disruptions in the quantities of coal produced at our operations
as a consequence of weather or equipment or mine failures;
|
|
|
|
our ability to collect payments from our customers;
|
|
|
|
defects in title or the loss of a leasehold interest;
|
|
|
|
railroad, barge, truck and other transportation performance and
costs;
|
|
|
|
our ability to secure new coal supply arrangements or to renew
existing coal supply arrangements;
|
|
|
|
our relationships with, and other conditions affecting, our
customers;
|
|
|
|
the deferral of contracted shipments of coal by our customers;
|
|
|
|
our ability to service our outstanding indebtedness;
|
|
|
|
our ability to comply with the restrictions imposed by our
Senior Secured Credit Facility and other financing arrangements;
|
|
|
|
the availability and cost of surety bonds;
|
|
|
|
terrorist attacks, military action or war;
|
|
|
|
our ability to obtain and renew various permits, including
permits authorizing the disposition of certain mining waste;
|
39
|
|
|
|
|
existing and future legislation and regulations affecting both
our coal mining operations and our customers coal usage,
governmental policies and taxes, including those aimed at
reducing emissions of elements such as mercury, sulfur dioxide,
nitrogen oxides, toxic gases, such as hydrogen chloride,
particulate matter or greenhouse gases;
|
|
|
|
the accuracy of our estimates of reclamation and other mine
closure obligations;
|
|
|
|
customers ability to meet existing or new regulatory
requirements and associated costs, including disposal of coal
combustion waste material;
|
|
|
|
our ability to attract/retain key management personnel;
|
|
|
|
efforts to organize our workforce for representation under a
collective bargaining agreement;
|
|
|
|
costs to comply with the Sarbanes-Oxley Act of 2002; and
|
|
|
|
the other factors affecting our business described below under
the caption Risk Factors.
|
40
USE OF
PROCEEDS
We estimate that the net proceeds to us from the sale of our
common stock in this offering will be
$ million, at an assumed
initial public offering price of $
per share, the midpoint of the price range set forth on the
cover of this prospectus, and after deducting estimated
underwriting discounts and commissions and offering expenses
estimated at $ million. Our
net proceeds will increase by approximately
$ million if the
underwriters option to purchase additional shares is
exercised in full. Each $1.00 increase (decrease) in the assumed
initial public offering price of $
per share, the midpoint of the price range set forth on the
cover of this prospectus, would increase (decrease) the net
proceeds to us of this offering by
$ million, or
$ million if the
underwriters option is exercised in full, assuming the
number of shares offered by us, as set forth on the cover of
this prospectus, remains the same and after deducting estimated
underwriting discounts and commissions and offering expenses.
We intend to use $ million of
the net proceeds from this offering to repay a portion of our
outstanding borrowings under our Senior Secured Term Loan,
$ million of the net proceeds
to repay a portion of our outstanding borrowings under our
Senior Secured Revolving Credit Facility and the balance, if
any, for general corporate purposes, including to fund capital
expenditures relating to our mining operations and working
capital. The interest rate applicable to the Senior Secured Term
Loan and the Senior Secured Revolving Credit Facility fluctuates
based on our leverage ratio and the applicable interest option
elected. The interest rate as of September 30, 2011 was
5.75%, which was reduced to 5.25% on November 14, 2011. The
Senior Secured Credit Facility matures on February 9, 2016.
See Description of Indebtedness. Raymond James Bank,
FSB, an affiliate of Raymond James & Associates, Inc.
is a lender under our Senior Secured Term Loan and our Senior
Secured Revolving Credit Facility and may receive a portion of
the net proceeds of this offering. See Conflicts of
Interest.
41
DIVIDEND
POLICY
Historically, we have not paid cash dividends to holders of our
common stock. For the foreseeable future, we intend to retain
earnings to grow our business. Payments of future dividends, if
any, will be at the discretion of our board of directors and
will depend on many factors, including general economic and
business conditions, our strategic plans, our financial results
and condition, legal requirements and other factors that our
board of directors deems relevant. Our Senior Secured Credit
Facility restricts our ability to pay cash dividends on our
common stock, and we may also enter into credit agreements or
other borrowing arrangements in the future that will restrict
our ability to declare or pay cash dividends on our common stock.
42
CAPITALIZATION
The following table shows:
|
|
|
|
|
Our capitalization as of September 30, 2011; and
|
|
|
|
Our unaudited pro forma capitalization as of September 30,
2011, as adjusted, to reflect the following: (a) the
receipt of the net proceeds from the sale by us in this offering
of shares of common stock at an assumed public offering price of
$ per share, the midpoint of the
range set forth on the front cover page of this prospectus,
after deducting estimated underwriting discounts and commissions
and estimated offering expenses payable by us, (b) the
repayment of certain outstanding indebtedness with the
application of proceeds from this offering, (c) the application
of amounts we expect to receive from the Concurrent ARP Offering
and related transactions as described in Certain
Relationships and Related Party Transactions
Concurrent Transactions with Armstrong Resource Partners,
and (d) the recognition of new debt financing arrangements
as a result of the Deconsolidation of Armstrong Resource
Partners.
|
We derived this table from, and it should be read in conjunction
with and is qualified in its entirety by reference to, our
historical and unaudited pro forma consolidated financial
statements and the accompanying notes included elsewhere in this
prospectus. You should also read this table in conjunction with
Selected Historical Consolidated Financial and Operating
Data, Unaudited Pro Forma Financial
Information, and Managements Discussion and
Analysis of Financial Condition and Results of Operations.
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2011
|
|
|
|
|
|
|
Pro-Forma As
|
|
|
|
Actual
|
|
|
Adjusted(1)(2)
|
|
|
|
(In thousands)
|
|
|
Cash and cash equivalents
|
|
$
|
7,547
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, including current portion:
|
|
|
|
|
|
|
|
|
Revolving credit facility
|
|
$
|
34,600
|
|
|
$
|
|
|
Term loan facility
|
|
|
100,000
|
|
|
|
|
|
Capital leases
|
|
|
15,131
|
|
|
|
|
|
Long-term obligation to related party
|
|
|
|
|
|
|
|
|
Other
|
|
|
2,476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
152,207
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value; 70,000,000 shares authorized
and 19,110,500 shares issued and outstanding on an actual
basis; 70,000,000 shares authorized
and shares
issued and outstanding on an as adjusted basis(3)
|
|
|
191
|
|
|
|
|
|
Additional
paid-in-capital
|
|
|
206,790
|
|
|
|
|
|
Accumulated deficit
|
|
|
(35,257
|
)
|
|
|
|
|
Accumulated other comprehensive income
|
|
|
(1,778
|
)
|
|
|
|
|
Non-controlling interest
|
|
|
137,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
307,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
$
|
460,137
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Each $1.00 increase or decrease in the assumed public offering
price of $ per share would
increase or decrease, respectively, each of total
stockholders equity and total capitalization by
approximately $ million,
after deducting the underwriting discount and estimated offering
expenses payable by us. We may also increase or decrease the
number of shares we are offering. Each increase of
1.0 million shares offered by us, together with a
concomitant $1.00 increase in the assumed offering price to
$ per share, would increase total
stockholders equity and total capitalization by
approximately |
43
|
|
|
|
|
$ million. Similarly, each
decrease of 1.0 million shares offered by us, together with
a concomitant $1.00 decrease in the assumed offering price to
$ per share, would decrease total
stockholders equity and total capitalization by
approximately $ million. The
information discussed above is illustrative only and will be
adjusted based on the actual public offering price and other
terms of this offering determined at pricing. |
|
(2) |
|
Each $1.00 increase or decrease in the assumed public offering
price of the Concurrent ARP Offering of
$ per share if paid to us as
described in Certain Relationships and Related Party
Transactions Concurrent Transactions with Armstrong
Resource Partners would increase or decrease,
respectively, each of total stockholders equity and total
capitalization by approximately
$ million, after deducting
the underwriting discount and estimated offering expenses
payable by Armstrong Resource Partners. Armstrong Resource
Partners may also increase or decrease the number of shares it
is offering. Each increase of 1.0 million shares offered by
Armstrong Resource Partners, together with a concomitant $1.00
increase in the assumed offering price of the Concurrent ARP
Offering to $ per share, if paid
to us, would increase total stockholders equity and total
capitalization by approximately
$ million. Similarly, each
decrease of 1.0 million shares offered by Armstrong
Resource Partners, together with a concomitant $1.00 decrease in
the assumed offering price of the Concurrent ARP Offering to
$ per share, if paid to us, would
decrease total stockholders equity and total
capitalization by approximately
$ million. The information
discussed above is illustrative only and will be adjusted based
on the actual public offering price and other terms of this
offering determined at pricing. |
|
(3) |
|
The number of shares of common stock issued and outstanding on a
pro forma basis includes shares of common stock outstanding,
including awards of unrestricted stock to management, excludes
awards of unvested restricted stock to management, and does not
reflect the repurchase
of shares of common stock in
connection with the cancellation of certain indebtedness. See
Certain Relationships and Related Party
Transactions Loans to Executive Officers and Loan
Repayment for additional information. |
44
DILUTION
Dilution is the amount by which the offering price paid by
purchasers of common stock sold in this offering will exceed the
pro forma net tangible book value per share of common stock
after the offering. As of September 30, 2011, our net
tangible book value was approximately
$ , or
$ per share. Net tangible book
value is our total tangible assets less total liabilities. Based
on an assumed initial offering price of
$ per share of common stock, on a
pro forma as adjusted basis as of ,
after giving effect to the offering
of shares of common stock and
the application of the related net proceeds, our net tangible
book value was $ million, or
$ per share of common stock.
Purchasers of common stock in this offering will experience
immediate and substantial dilution in net tangible book value
per share for financial accounting purposes, as illustrated in
the following table:
|
|
|
|
|
|
|
|
|
Assumed purchase price per share of common stock
|
|
|
|
|
|
$
|
|
|
Net tangible book value per share before this offering
|
|
|
|
|
|
|
|
|
Decrease in net tangible book value per share attributable to
new investors
|
|
|
|
|
|
|
|
|
Less: Pro forma net tangible book value per share after this
offering
|
|
|
|
|
|
|
|
|
Immediate dilution in net tangible book value per share to new
investors
|
|
|
|
|
|
$
|
|
|
A $1.00 increase in the assumed initial public offering price of
$ per share (which is the midpoint
of the range set forth in the cover of this prospectus) would
increase our net tangible book value after the offering by
$ million, and decrease the
dilution to new investors by $ ,
assuming the number of shares offered by us, as set forth on the
cover page of this prospectus, remains the same and after
deducting the estimated underwriting discounts and commissions
and estimated offering expenses payable by us.
The following table sets forth, as
of , 2012, the number of shares of
common stock purchased from us, the total consideration paid to
us and the average price per share paid by existing stockholders
and to be paid by new investors purchasing shares of common
stock in this offering, after giving pro forma effect to the
Deconsolidation and to the new investors in this offering at the
assumed initial public offering price of
$ per share, together with the
total consideration paid and average price per share paid by
each of these groups, before deducting underwriting discounts
and commissions and estimated offering expenses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
Shares Purchased
|
|
|
Total Consideration
|
|
|
Price per
|
|
|
|
Number
|
|
|
Percent
|
|
|
Amount
|
|
|
Percent
|
|
|
Share
|
|
|
|
(In thousands)
|
|
|
Existing stockholders
|
|
|
|
|
|
|
|
%
|
|
$
|
|
|
|
|
|
%
|
|
$
|
|
|
New investors
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
%
|
|
$
|
|
|
|
|
|
%
|
|
$
|
|
|
The foregoing tables do not give effect to:
(a) 109,150 shares of restricted stock outstanding
held by our employees, including our executive officers; and
(b) additional shares of common stock available for future
issuance under our stock option and incentive plans.
If the underwriters over-allotment option is exercised in
full, the number of shares held by new investors will
be , or
approximately, % of the total
number of shares of common stock.
45
UNAUDITED
PRO FORMA FINANCIAL INFORMATION
The following tables present our selected unaudited pro forma
consolidated financial and operating data for the periods
indicated for Armstrong Energy. The following unaudited pro
forma consolidated financial data of Armstrong Energy at
September 30, 2011, for the year ended December 31,
2010, and for the nine months ended September 30, 2011, are
based on the historical consolidated financial statements of our
Predecessor, which are included elsewhere in this prospectus.
The unaudited pro forma consolidated balance sheet data at
September 30, 2011 gives effect to (a) the issuance of
common stock in this offering and the application of the net
proceeds therefrom as described in Use of Proceeds,
(b) the Deconsolidation of Armstrong Resource Partners, and
(c) the contribution of net proceeds to Armstrong Energy
from the Concurrent ARP Offering, as if each had occurred on
September 30, 2011.
The unaudited pro forma consolidated financial data for the
fiscal year ended December 31, 2010 gives effect to
(a) adjustments to interest expense as a result of the
repayment of a portion of the secured promissory notes from the
proceeds of this offering, (b) the addition of interest
expense associated with a long-term obligation to Armstrong
Resource Partners, net of certain allocated management fees,
recognized as part of the Deconsolidation of Armstrong Resource
Partners, and (c) net adjustments to interest expense as a
result of the repayment of a portion of the secured promissory
notes from the proceeds contributed from the Concurrent ARP
Offering, partially offset by additional interest expense
associated with an additional long-term obligation owed to
Armstrong Resource Partners, as if each had occurred on
January 1, 2010.
The unaudited pro forma consolidated financial data for the nine
months ended September 30, 2011 gives effect to
(a) adjustments to interest expense as a result of the
repayment of a portion of the secured promissory notes from the
proceeds of this offering and reduction of subsequent borrowings
in February 2011 under the Senior Secured Credit Facility,
(b) the addition of interest expense associated with a
long-term obligation to Armstrong Resource Partners, net of
certain allocated management fees, recognized as part of the
Deconsolidation of Armstrong Resource Partners, and (c) net
adjustments to interest expense as a result of the repayment of
a portion of the secured promissory notes from the proceeds
contributed from the Concurrent ARP Offering and additional
interest expense associated with an additional long-term
obligation owed to Armstrong Resource Partners, as if each had
occurred on January 1, 2010.
In connection with the Reorganization, effective October 1,
2011, Armstrong Energy converted its legal structure from a
partnership to a corporation for income tax purposes. The
conversion of Armstrong Energy to a corporation would result in
the recognition of deferred tax assets and liabilities for the
difference between its asset basis for financial reporting and
income tax purposes. However, consistent with the prior
reporting of the subsidiary corporations, the consolidated
income tax filing group will recognize a full valuation
allowance against its deferred tax assets. Therefore, there is
no expected impact to the statements of operations or financial
position as a result of this transaction. As such, no income tax
adjustments from the Reorganization have been reflected in the
unaudited pro forma financial information.
This unaudited pro forma consolidated financial information
should be read in conjunction with Managements
Discussion and Analysis of Financial Condition and Results of
Operations and our financial statements and related notes
included elsewhere in this prospectus.
Our unaudited pro forma adjustments are based on available
information and certain assumptions that we believe are
reasonable. Presentation of our unaudited pro forma consolidated
financial and operating data is prepared in conformity with
Article 11 of
Regulation S-X.
The unaudited pro forma consolidated financial and operating
data is included for illustrative and informational purposes
only and is not necessarily indicative of results we expect in
future periods.
46
Unaudited
Pro Forma Consolidated Statement of Operations
For the Year Ended December 31, 2010
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
for the
|
|
|
|
|
|
|
|
|
|
|
|
|
for the
|
|
|
Pro Forma
|
|
|
Deconsolidation,
|
|
|
|
|
|
|
|
|
|
|
|
|
Deconsolidation
|
|
|
for the
|
|
|
this Offering,
|
|
|
|
|
|
|
|
|
|
|
|
|
and this
|
|
|
Concurrent
|
|
|
and the
|
|
|
|
As Reported
|
|
|
|
|
|
|
|
|
Offering
|
|
|
ARP Offering
|
|
|
Concurrent ARP
|
|
|
|
for the
|
|
|
|
|
|
|
|
|
for the
|
|
|
for the
|
|
|
Offering for the
|
|
|
|
Year Ended
|
|
|
Adjustments
|
|
|
Adjustments
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
Related to the
|
|
|
Related to this
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
Deconsolidation
|
|
|
Offering
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
|
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
220,625
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
151,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, and amortization
|
|
|
18,892
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation expense
|
|
|
3,087
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selling, general, and administrative costs
|
|
|
27,656
|
|
|
|
|
(A)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
19,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(11,070
|
)
|
|
|
|
(B)
|
|
|
|
(D)
|
|
|
|
|
|
|
|
(E)
|
|
|
|
|
Other income (expense), net
|
|
|
(111
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
8,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income attributable to non-controlling interest
|
|
|
(3,351
|
)
|
|
|
|
(C)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stockholders
|
|
$
|
4,818
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma weighted average shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(A) |
|
Represents the management fee and other legal and accounting
fees charged to Armstrong Resource Partners for the year ended
December 31, 2010. |
|
(B) |
|
Represents interest expense on the long-term obligations with
Armstrong Resource Partners for the year ended December 31,
2010. |
|
(C) |
|
Reflects the deconsolidation of the non-controlling interest
associated with Armstrong Resource Partners for the year ended
December 31, 2010. |
|
(D) |
|
Reflects elimination of historical interest expense related to
secured promissory notes repaid with proceeds from this offering
had it occurred on January 1, 2010. |
|
(E) |
|
Reflects elimination of historical interest expense of
$ million related to the
secured promissory notes, as Armstrong Energy intends to utilize
the net proceeds contributed from the Concurrent ARP Offering to
repay these obligations. The amount is offset by additional
interest expense of $ million
associated with a long-term obligation Armstrong Energy would
enter into with Armstrong Resource Partners in exchange for an
undivided interest in additional mineral reserves. |
47
Unaudited
Pro Forma Condensed Consolidated Balance Sheet
As of September 30, 2011
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
for the
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deconsolidation,
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
this Offering
|
|
|
|
|
|
|
|
|
|
|
|
|
for the
|
|
|
|
|
|
and the
|
|
|
|
|
|
|
|
|
|
|
|
|
Deconsolidation
|
|
|
Adjustments
|
|
|
Concurrent
|
|
|
|
|
|
|
|
|
|
|
|
|
and this
|
|
|
Related
|
|
|
ARP Offering
|
|
|
|
As Reported as
|
|
|
Adjustments
|
|
|
Adjustments
|
|
|
Offering as of
|
|
|
to the
|
|
|
as of
|
|
|
|
of September 30,
|
|
|
Related to the
|
|
|
Related to this
|
|
|
September 30,
|
|
|
Concurrent
|
|
|
September 30,
|
|
|
|
2011
|
|
|
Deconsolidation
|
|
|
Offering
|
|
|
2011
|
|
|
ARP Offering
|
|
|
2011
|
|
|
|
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
7,547
|
|
|
$
|
|
(F)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
(R)
|
|
$
|
|
|
Accounts receivable
|
|
|
23,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inventories
|
|
|
10,887
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid and other assets
|
|
|
3,476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
45,199
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant equipment, and mine development, net
|
|
|
451,008
|
|
|
|
|
(G)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
|
|
|
2,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible assets, net
|
|
|
1,488
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Related party other receivables, net
|
|
|
|
|
|
|
|
(H)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other noncurrent assets
|
|
|
16,134
|
|
|
|
|
(I)
|
|
|
|
(N)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
516,299
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and stockholders equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
24,628
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Accrued liabilities and other
|
|
|
14,831
|
|
|
|
|
|
|
|
|
(O)
|
|
|
|
|
|
|
|
(S),(T)
|
|
|
|
|
Construction retainage
|
|
|
375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued interest on related party obligations
|
|
|
|
|
|
|
|
(J)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of capital lease obligations
|
|
|
4,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
15,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
60,141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, less current maturities
|
|
|
121,100
|
|
|
|
|
|
|
|
|
(P)
|
|
|
|
|
|
|
|
(T)
|
|
|
|
|
Long-term obligation to related party
|
|
|
|
|
|
|
|
(K)
|
|
|
|
|
|
|
|
|
|
|
|
(T)
|
|
|
|
|
Asset retirement obligations
|
|
|
14,352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term portion of capital lease obligations
|
|
|
10,800
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other non-current liabilities
|
|
|
1,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
208,369
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated deficit
|
|
|
(35,257
|
)
|
|
|
|
(L)
|
|
|
|
(N)
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss)
|
|
|
(1,778
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
191
|
|
|
|
|
|
|
|
|
(Q)
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional paid in capital
|
|
|
206,790
|
|
|
|
|
|
|
|
|
(Q)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Armstrong Energy, Inc.s equity
|
|
|
169,946
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-controlling interest
|
|
|
137,984
|
|
|
|
|
(M)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
307,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
516,299
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(F) |
|
Represents cash held by Armstrong Resource Partners as of
September 30, 2011. |
|
(G) |
|
Reflects the mineral rights and land held by Armstrong Resource
Partners as of September 30, 2011. |
|
(H) |
|
Represents net amounts due from Armstrong Resource Partners for
various expense paid on its behalf. |
|
(I) |
|
Represents an advance royalty paid to Armstrong Resource
Partners of $ million and the
investment in Armstrong Resource Partners of
$ million as of
September 30, 2011. |
48
|
|
|
(J) |
|
Represents accrued interest on obligations owed to Armstrong
Resource Partners as of September 30, 2011. |
|
(K) |
|
Represents obligations owed to Armstrong Resource Partners as of
September 30, 2011 as a result of a financing arrangement
to mine certain mineral reserves transferred to Armstrong
Resource Partners. See Description of Indebtedness. |
|
(L) |
|
Represents the impact to the results of operations. |
|
(M) |
|
Reflects the deconsolidation of the non-controlling interest
associated with Armstrong Resource Partners as of
September 30, 2011. |
|
(N) |
|
Reflects the write-off of unamortized deferred financing costs
associated with the expected repayment of a portion of the
Senior Secured Term Loan with proceeds from the offering. |
|
(O) |
|
Reflects the expected payment of accrued interest on
$ million of the Senior
Secured Term Loan and
$ million of the Senior
Secured Revolving Credit Facility repaid with proceeds from this
offering. |
|
(P) |
|
Reflects the expected repayment of
$ million of the Senior
Secured Term Loan and
$ million of the Senior
Secured Revolving Credit Facility with proceeds from this
offering. |
|
(Q) |
|
Reflects the adjustments to common stock and additional paid in
capital for the public offering of Armstrong Energys
common stock as follows (dollars in thousands): |
|
|
|
|
|
Proceeds from this offering(1)
|
|
$
|
|
|
Less: estimated fees and expense related with this offering
|
|
|
|
|
|
|
|
|
|
Net proceeds from this offering
|
|
|
|
|
Less: par value of common stock issued in this offering(2)
|
|
|
|
|
|
|
|
|
|
Additional paid in capital on shares issued in this offering
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
To reflect the issuance
of shares of
Armstrong Energys common stock offered hereby at an
assumed initial public offering price of
$ per share (the mid point of the
range set forth on the front cover page of this prospectus).
|
|
|
(2)
|
To reflect the reclassification to common stock of the par value
of $0.01 per share for
the shares issued in this
offering.
|
|
|
|
(R) |
|
Reflects adjustments to cash and cash equivalents for sources
and uses of funds from the Concurrent ARP Offering, summarized
as follows (dollars in thousands): |
|
|
|
|
|
Proceeds from the Concurrent ARP Offering(1), net of expenses
|
|
$
|
|
|
Use of cash to repay Senior Secured Revolving Credit Facility
|
|
|
|
|
Use of cash to pay accrued but unpaid interest
|
|
|
|
|
|
|
|
|
|
Pro forma adjustment
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
To reflect the issuance
of common units
of Armstrong Resource Partners representing limited partner
interests to be offered by Armstrong Resource Partners pursuant
to the concurrent ARP Offering at an assumed initial public
offering price of $ per unit (the
mid point of the range set forth on the front cover page of the
prospectus related to the Concurrent ARP Offering).
|
|
|
|
(S) |
|
Reflects the expected payment of accrued interest on the portion
of the Senior Secured Revolving Credit Facility repaid with
proceeds contributed from the Concurrent ARP Offering. |
|
(T) |
|
The expected net proceeds of the Concurrent ARP Offering of
$ million will be paid to
Armstrong Energy to purchase an undivided interest in additional
mineral reserves of Armstrong Energy. The amount received is
expected to be utilized to repay the remaining outstanding
balance of the Senior Secured Revolving Credit Facility
(approximately $ million) and
related accrued interest (approximately
$ million), with expected
excess cash of approximately
$ million. Armstrong Energy
expects to simultaneously enter into a financing arrangement
with Armstrong Resource Partners to mine the mineral reserves
transferred, resulting in the recognition of an obligation of
$ million. |
49
Unaudited
Pro Forma Consolidated Statement of Operations
For the Nine Months Ended September 30, 2011
(In thousands, except per share amount)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma for the
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deconsolidation,
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma for the
|
|
|
|
|
|
this Offering, and
|
|
|
|
|
|
|
|
|
|
|
|
|
Deconsolidation
|
|
|
Adjustments
|
|
|
the Concurrent
|
|
|
|
As Reported
|
|
|
|
|
|
|
|
|
and this Offering
|
|
|
Related
|
|
|
ARP Offering
|
|
|
|
for the Nine
|
|
|
Adjustments
|
|
|
Adjustments
|
|
|
for the Nine Months
|
|
|
to the
|
|
|
for the Nine
|
|
|
|
Months Ended
|
|
|
Related to the
|
|
|
Related to this
|
|
|
Ended September 30,
|
|
|
Concurrent
|
|
|
Months Ended
|
|
|
|
September 30, 2011
|
|
|
Deconsolidation
|
|
|
Offering
|
|
|
2011
|
|
|
ARP Offering
|
|
|
September 30, 2011
|
|
|
|
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
229,980
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
170,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, and amortization
|
|
|
21,478
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation expenses
|
|
|
2,942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selling, general, and administrative costs
|
|
|
28,834
|
|
|
|
|
(U)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
6,429
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(6,073
|
)
|
|
|
|
(V)
|
|
|
|
(Y)
|
|
|
|
|
|
|
|
(Z)
|
|
|
|
|
Other income (expense), net
|
|
|
(154
|
)
|
|
|
|
(W)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on extinguishment of debt
|
|
|
6,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
7,274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision
|
|
|
809
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
6,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Income) loss attributable to noncontrolling interests
|
|
|
(7,448
|
)
|
|
|
|
(X)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stockholders
|
|
$
|
(983
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma earnings per share Basic and diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma weighted average shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(U) |
|
Represents the management fee and other legal and accounting
fees charged to Armstrong Resource Partners for the nine months
ended September 30, 2011. |
(V) |
|
Represents interest expense on the long term obligations with
Armstrong Resource Partners for the nine months ended
September 30, 2011. |
(W) |
|
Represents the fee owed of
$ million to Armstrong
Resource Partners for acting as a guarantor to the
Companys Senior Secured Credit Facility. |
|
(X) |
|
Reflects the de-consolidation of the non-controlling interest
associated with Armstrong Resource Partners for the nine months
ended September 30, 2011. |
50
|
|
|
(Y) |
|
As of the beginning of 2011, the Companys outstanding debt
included $ million of secured
promissory notes, which were repaid from proceeds from the
Senior Secured Credit Facility entered into in February 2011,
which included a $100.0 million Senior Secured Term Loan
and $50.0 million Senior Secured Revolving Credit Facility.
Had the offering occurred on the first day of 2010, the Company
would have used the proceeds to repay
$ million of secured
promissory notes. Subsequently, when the Company repaid the
remaining secured promissory notes in February 2011, the
outstanding balance would have been
$ million. As the secured
promissory notes would have been
$ million lower at the time
of the repayment, the pro forma adjustments assume the Company
would have reduced the amount of the Senior Secured Term Loan by
$ million and borrowings
under the Senior Secured Revolving Credit Facility by
$ million. In addition, had
the amount of the Senior Secured Term Loan been reduced, the
amount of the deferred financing costs would have been reduced
by approximately $ million,
which would have resulted in an additional reduction in the
amount initially borrowed on Senior Secured Revolving Credit
Facility by a corresponding amount. The pro forma adjustments to
historical interest expense related to the offering are as
follows (dollars in thousands): |
|
|
|
|
|
Interest Expense
|
|
|
|
|
Secured promissory notes
|
|
$
|
|
|
Senior Secured Term Loan
|
|
|
|
|
Senior Secured Revolving Credit Facility
|
|
|
|
|
Deferred financing fees
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
(Z) |
|
The expected net proceeds of the Concurrent ARP Offering of
$ million will be paid to
Armstrong Energy to purchase an undivided interest in additional
mineral reserves of Armstrong Energy. Had the Concurrent ARP
Offering occurred on the first day of 2010, the Company would
have used the proceeds contributed by Armstrong Resource
Partners to repay $ million
of the secured promissory notes. Subsequently, when the Company
repaid the remaining secured promissory notes in February 2011,
the outstanding balance would have been
$ million lower. As the
secured promissory notes would have been
$ million lower at the time
of the repayment, the pro forma adjustments assume the Company
would not have borrowed an initial amount under the Senior
Secured Credit Facility or a subsequent amount under the
facility through September 30, 2011. In connection with the
receipt of proceeds from Armstrong Resource Partners, the
Company will simultaneously enter into a financing arrangement
with Armstrong Resource Partners to mine the mineral reserves
transferred, resulting in the recognition of a long-term
obligation of $ million. The
additional interest incurred on this obligation would total
approximately $ million. The
pro forma adjustments to historical interest expense related to
the offering are as follows (dollars in thousands): |
|
|
|
|
|
Interest Expense
|
|
|
|
|
Secured promissory notes
|
|
$
|
|
|
Senior Secured Revolving Credit Facility
|
|
|
|
|
Long-term obligation to related party
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
51
SELECTED
HISTORICAL
CONSOLIDATED FINANCIAL
AND OPERATING DATA
The following table presents our selected historical
consolidated financial and operating data for the periods
indicated for Armstrong Energy, Inc.s predecessor,
Armstrong Land Company, LLC and its subsidiaries (our
Predecessor). The summary historical financial data
for the years ended December 31, 2007, 2008, 2009 and 2010
and the balance sheet data as of December 31, 2007, 2008,
2009 and 2010 are derived from the audited financial statements
of our Predecessor. The selected historical financial data for
the nine months ended September 30, 2010 and 2011 and the
balance sheet data as of September 30, 2010 and 2011 are
derived from the unaudited financial statements of our
Predecessor. Historical results are not necessarily indicative
of results we expect in future periods. You should read the
following summary financial data in conjunction with
Managements Discussion and Analysis of Financial
Condition and Results of Operations and our financial
statements and related notes appearing elsewhere in this
prospectus.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Year Ended December 31,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
(Restated)(1)
|
|
|
(Restated)(1)
|
|
|
|
|
|
|
|
|
|
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
(Restated)(1)
|
|
|
(Restated)(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
|
|
|
Unaudited
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Results of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
|
|
|
$
|
57,069
|
|
|
$
|
167,904
|
|
|
$
|
220,625
|
|
|
$
|
176,311
|
|
|
$
|
229,480
|
|
Costs and expenses
|
|
|
6,369
|
|
|
|
64,667
|
|
|
|
166,686
|
|
|
|
201,473
|
|
|
|
158,169
|
|
|
|
223,551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(6,369
|
)
|
|
|
(7,598
|
)
|
|
|
1,218
|
|
|
|
19,152
|
|
|
|
18,142
|
|
|
|
6,429
|
|
Interest expense
|
|
|
(8,730
|
)
|
|
|
(14,752
|
)
|
|
|
(12,651
|
)
|
|
|
(11,070
|
)
|
|
|
(8,532
|
)
|
|
|
(6,073
|
)
|
Other income (expense), net
|
|
|
983
|
|
|
|
971
|
|
|
|
988
|
|
|
|
87
|
|
|
|
259
|
|
|
|
(36
|
)
|
Gain on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(14,116
|
)
|
|
|
(21,379
|
)
|
|
|
(10,445
|
)
|
|
|
8,169
|
|
|
|
9,869
|
|
|
|
7,274
|
|
Income tax provision
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(809
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(14,116
|
)
|
|
|
(21,379
|
)
|
|
|
(10,445
|
)
|
|
|
8,169
|
|
|
|
9,869
|
|
|
|
6,465
|
|
Less: net income (loss) attributable to non-controlling interest
|
|
|
(329
|
)
|
|
|
(5,552
|
)
|
|
|
(1,730
|
)
|
|
|
3,351
|
|
|
|
2,814
|
|
|
|
7,448
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to common stockholders
|
|
$
|
(13,787
|
)
|
|
$
|
(15,827
|
)
|
|
$
|
(8,715
|
)
|
|
$
|
4,818
|
|
|
$
|
7,005
|
|
|
$
|
(983
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per share, basic and diluted
|
|
$
|
(1.53
|
)
|
|
$
|
(1.35
|
)
|
|
$
|
(0.50
|
)
|
|
$
|
0.25
|
|
|
$
|
0.37
|
|
|
$
|
(0.05
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period end)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
222,118
|
|
|
$
|
372,674
|
|
|
$
|
450,618
|
|
|
$
|
478,038
|
|
|
$
|
461,577
|
|
|
$
|
516,299
|
|
Working capital
|
|
|
15,999
|
|
|
|
(34,668
|
)
|
|
|
(17,749
|
)
|
|
|
2,905
|
|
|
|
(32,582
|
)
|
|
|
(14,942
|
)
|
Total debt (including capital leases)
|
|
|
128,375
|
|
|
|
183,337
|
|
|
|
159,730
|
|
|
|
139,871
|
|
|
|
143,539
|
|
|
|
152,207
|
|
Total stockholders equity
|
|
|
83,180
|
|
|
|
168,931
|
|
|
|
255,333
|
|
|
|
296,681
|
|
|
|
287,356
|
|
|
|
307,930
|
|
Other Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold (unaudited)
|
|
|
|
|
|
|
1,398
|
|
|
|
4,674
|
|
|
|
5,387
|
|
|
|
4,339
|
|
|
|
5,481
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
(6,109
|
)
|
|
$
|
(11,079
|
)
|
|
$
|
3,054
|
|
|
$
|
37,194
|
|
|
$
|
26,804
|
|
|
$
|
31,126
|
|
Investing activities
|
|
|
(48,418
|
)
|
|
|
(80,020
|
)
|
|
|
(62,476
|
)
|
|
|
(41,755
|
)
|
|
|
(24,681
|
)
|
|
|
(47,386
|
)
|
Financing activities
|
|
|
67,505
|
|
|
|
79,402
|
|
|
|
64,854
|
|
|
|
(3,935
|
)
|
|
|
(6,017
|
)
|
|
|
15,706
|
|
Adjusted EBITDA(2) (unaudited)
|
|
|
(5,724
|
)
|
|
|
(1,029
|
)
|
|
|
16,567
|
|
|
|
41,099
|
|
|
|
34,874
|
|
|
|
32,125
|
|
Adjusted EBITDA is calculated as follows (unaudited):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(14,116
|
)
|
|
$
|
(21,379
|
)
|
|
$
|
(10,445
|
)
|
|
$
|
8,169
|
|
|
$
|
9,869
|
|
|
$
|
6,465
|
|
Income tax provision
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
809
|
|
Depreciation, depletion and amortization
|
|
|
264
|
|
|
|
5,810
|
|
|
|
14,464
|
|
|
|
21,979
|
|
|
|
16,562
|
|
|
|
24,420
|
|
Interest expense, net
|
|
|
7,429
|
|
|
|
14,377
|
|
|
|
12,482
|
|
|
|
10,872
|
|
|
|
8,389
|
|
|
|
5,955
|
|
Non-cash stock compensation expense
|
|
|
699
|
|
|
|
163
|
|
|
|
66
|
|
|
|
79
|
|
|
|
54
|
|
|
|
1,212
|
|
Non-cash charge related to non-recourse notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
218
|
|
Gain on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,954
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(5,724
|
)
|
|
$
|
(1,029
|
)
|
|
$
|
16,567
|
|
|
$
|
41,099
|
|
|
$
|
34,874
|
|
|
$
|
32,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The consolidated financial statements have been restated to
correct for an error in the calculation of depreciation,
depletion, and amortization expense for the years ended
December 31, 2009 and 2010 and |
52
|
|
|
|
|
the nine months ended September 30, 2010 and 2011. See
Note 3 to the interim condensed consolidated financial
statements. |
(2) |
|
Adjusted EBITDA is a non-GAAP financial measure, and when
analyzing our operating performance, investors Adjusted EBITDA
in addition to, and not as an alternative for, operating income
and net income (loss) (each as determined in accordance with
GAAP). We use Adjusted EBITDA as a supplemental financial
measure. |
|
|
|
Adjusted EBITDA is defined as net income (loss) before net
interest expense, income taxes, depreciation, depletion and
amortization, non-cash stock compensation expense, non-cash
charges related to non-recourse notes, and gain on
extinguishment of debt. |
|
|
|
Adjusted EBITDA, as used and defined by us, may not be
comparable to similarly titled measures employed by other
companies and is not a measure of performance calculated in
accordance with GAAP. There are significant limitations to using
Adjusted EBITDA as a measure of performance, including the
inability to analyze the effect of certain recurring and
non-recurring items that materially affect our net income or
loss, the lack of comparability of results of operations of
different companies and the different methods of calculating
Adjusted EBITDA reported by different companies, and should not
be considered in isolation or as a substitute for analysis of
our results as reported under GAAP. |
|
|
|
For example, Adjusted EBITDA does not reflect: |
|
|
|
cash expenditures, or future requirements, for
capital expenditures or contractual commitments; changes in, or
cash requirements for, working capital needs;
|
|
|
|
the significant interest expense, or the cash
requirements necessary to service interest or principal
payments, on debt; and
|
|
|
|
any cash requirements for assets being depreciated
and amortized that may have to be replaced in the future.
|
|
|
|
Adjusted EBITDA does not represent funds available for
discretionary use because those funds are required for debt
service, capital expenditures, working capital and other
commitments and obligations. However, our management team
believes Adjusted EBITDA is useful to an investor in evaluating
our company because this measure: |
|
|
|
is widely used by investors in our industry to
measure a companys operating performance without regard to
items excluded from the calculation of such term, which can vary
substantially from company to company depending upon accounting
methods and book value of assets, capital structure and the
method by which assets were acquired, among other
factors; and
|
|
|
|
helps investors to more meaningfully evaluate and
compare the results of our operations from period to period by
removing the effect of our capital structure from our operating
structure, which is useful for trending, analyzing and
benchmarking the performance and value of our business.
|
53
MANAGEMENTS
DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition
and results of operations should be read in conjunction with
Selected Historical Consolidated Financial and Operating
Data and our audited and unaudited financial statements
and related notes appearing elsewhere in this prospectus. Our
actual results may differ materially from those anticipated in
these forward-looking statements as a result of a variety of
risks and uncertainties, including those described in this
prospectus under Cautionary Statement Concerning
Forward-Looking Statements and Risk Factors.
We assume no obligation to update any of these forward-looking
statements.
As discussed in Note 3 to the consolidated financial
statements as of and for the years ended December 31, 2010
and 2009 and Note 3 to the condensed consolidated financial
statements as of and for the nine months ended
September 30, 2011 and 2010, our financial statements have
been restated. The accompanying management discussion and
analysis gives effect to the restatement.
Overview
We are a diversified producer of low chlorine, high sulfur
thermal coal from the Illinois Basin with both surface and
underground mines. We market our coal primarily to electric
utility companies as fuel for their steam-powered generators.
Based on 2010 production, we are the sixth largest producer in
the Illinois Basin and the second largest in Western Kentucky.
We were formed in 2006 to acquire and develop a large coal
reserve holding. We commenced production in the second quarter
of 2008 and currently operate six mines, including four surface
and two underground, and are seeking permits for four additional
mines. We control approximately 319 million tons of proven
and probable coal reserves. Our reserves and operations are
located in the Western Kentucky counties of Ohio, Muhlenberg,
Union and Webster. We also own and operate three coal processing
plants which support our mining operations. The location of our
coal reserves and operations, adjacent to the Green and Ohio
Rivers, together with our river dock coal handling and rail
loadout facilities, allow us to optimize our coal blending and
handling, and provide our customers with rail, barge and truck
transportation options. From our reserves, we mine coal from
multiple seams which, in combination with our coal processing
facilities, enhances our ability to meet customer requirements
for blends of coal with different characteristics.
We market our coal primarily to large utilities with coal-fired,
base-load, scrubbed power plants under multi-year coal supply
agreements. Our multi-year coal supply agreements usually have
specific and possibly different volume and pricing arrangements
for each year of the agreement. These agreements allow customers
to secure a supply for their future needs and provide us with
greater predictability of sales volume and sales prices. In
2010, we sold approximately 90% of our coal under multi-year
coal supply agreements. At September 30, 2011, we had 10
multi-year coal supply agreements with terms ranging from one to
eight years. For the fiscal year ended December 31, 2010,
coal sales to TVA and LGE constituted approximately 40% and 36%,
respectively, of our total coal revenues. We are contractually
committed to sell 7.6 million tons of coal in 2011, which
represents substantially all of our currently estimated
production for 2011. Similarly, as of September 30, 2011,
we are contractually committed to sell 8.8 million tons of
coal in 2012 and 8.1 million tons of coal in 2013, which
represents 99% and 83% of our expected total coal sales in 2012
and 2013, respectively.
During 2010 and the first nine months of 2011, we produced
5.6 million and 5.1 million tons of coal,
respectively, and during the same periods, we sold
5.4 million and 5.5 million tons of coal,
respectively. For the year ended December 31, 2010, our
revenue from coal sales was $220.6 million, and we
generated operating income of $19.2 million and Adjusted
EBITDA of $41.1 million. Our revenue, operating income and
Adjusted EBITDA for the nine months ended September 30,
2011 were $230.0 million, $6.4 million and
$32.1 million, respectively. Our coal production increased
from 1.4 million tons in 2008 to 4.4 million tons in
2009, and to 5.6 million tons in 2010, and we estimate that
we will produce approximately 7.2 million tons in 2011.
Our principal expenses related to the production of coal are
labor and benefits, equipment, materials and supplies
(explosives, diesel fuel and electricity), maintenance,
royalties and excise taxes. Unlike some of our
54
competitors, we employ a totally non-union workforce. Many of
the benefits of our non-union workforce are related to higher
productivity and are not necessarily reflected in our direct
costs. In addition, while we do not pay our customers
transportation costs, they may be substantial and are often the
determining factor in a coal consumers contracting
decision. The location of our coal reserves and operations,
adjacent to the Green and Ohio Rivers, together with our river
dock coal handling and rail loadout facilities, allow us to
optimize our coal blending and handling and provide our
customers with rail, barge and truck transportation options.
Evaluating
the Results of Our Operations
We evaluate the results of our operations based on several key
measures:
|
|
|
|
|
our coal production, sales volume and weighted average sales
prices;
|
|
|
|
our cost of coal sales; and
|
|
|
|
our Adjusted EBITDA, a non-GAAP financial measure.
|
We define our coal sales price per ton, or average sales price,
as total coal sales divided by tons sold. We review coal sales
price per ton to evaluate marketing efforts and for market
demand and trend analysis. We define Adjusted EBITDA as our net
income (loss) before net interest expense, income taxes,
depreciation, depletion and amortization, non-cash stock
compensation expense, non-cash charges related to non-recourse
notes, and gain on extinguishment of debt. Adjusted EBITDA is
used as a supplemental financial measure by our management and
by external users of our financial statements such as investors,
commercial banks, research analysts and others, to assess the
financial performance of our assets without regard to financing
methods, capital structure or historical cost basis, the ability
of our assets to generate cash sufficient to pay interest costs
and support our indebtedness, our operating performance and
return on investment compared to those of other companies in the
coal energy sector, without regard to financing or capital
structures, and the viability of acquisitions and capital
expenditure projects and the overall rates of return on
alternative investment opportunities. Adjusted EBITDA has
several limitations that are discussed under Prospectus
Summary Summary Historical and Unaudited Pro Forma
Consolidated Financial and Operating Data, where we also
include a quantitative reconciliation of Adjusted EBITDA to the
most directly comparable GAAP financial measure, which is net
income (loss).
Coal
Production, Sales Volume and Sales Prices
We evaluate our operations based on the volume of coal we
produce, the volume of coal we sell and the prices we receive
for our coal. Because we sell substantially all of our coal
under multi-year coal supply agreements, our coal production,
sales volume and sales prices are largely dependent upon the
terms of those contracts. The volume of coal we sell is also a
function of the productive capacity of our mines and changes in
our inventory levels and those of our customers.
Our multi-year coal supply agreements typically provide for a
fixed price, or a schedule of fixed prices, over the contract
term. In addition, the contracts typically contain price
reopeners that provide for a market-based adjustment to the
initial price after the initial years of those contracts have
been fulfilled. These contracts will terminate if we cannot
agree upon a market-based price with the customer. In addition,
many of our multi-year coal supply agreements have full or
partial cost pass through or inflation adjustment provisions;
specifically, costs related to fuel, explosives and new
government impositions are subject to certain pass-through
provisions under many of our multi-year coal supply agreements.
Cost pass-through provisions typically provide for increases in
our sales prices in rising operating cost environments and for
decreases in declining operating cost environments. Inflation
adjustment provisions typically provide some protection in
rising operating cost environments. We also receive premiums, or
pay penalties, based upon the actual quality of the coal we
deliver, which is measured for characteristics such as heat
(Btu), sulfur and moisture content.
55
We evaluate the price we receive for our coal on an average
sales price per ton basis. The following table provides
operational data with respect to our coal production, coal sales
volume and average sales prices per ton for the periods
indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
Year Ended
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
|
(In thousands, except per ton amounts)
|
|
|
Tons of Coal Produced
|
|
|
1,379
|
|
|
|
4,434
|
|
|
|
5,645
|
|
|
|
4,296
|
|
|
|
5,126
|
|
Tons of Coal Sold
|
|
|
1,398
|
|
|
|
4,674
|
|
|
|
5,387
|
|
|
|
4,339
|
|
|
|
5,481
|
|
Tons of Coal Sold Under Multi-Year Agreements
|
|
|
1,398
|
|
|
|
4,674
|
|
|
|
4,827
|
|
|
|
4,205
|
|
|
|
5,071
|
|
Average Sales Price Per Ton
|
|
$
|
40.82
|
|
|
$
|
35.92
|
|
|
$
|
40.96
|
|
|
$
|
40.63
|
|
|
$
|
41.96
|
|
Cost
of Coal Sales
We evaluate our cost of coal sales on a cost per ton basis. Our
cost of coal sales per ton produced represents our production
costs divided by the tons of coal we sell. Our production costs
include labor and associated benefits, fuel, lubricants,
explosives, operating lease expenses, repairs and maintenance,
royalties, and all other costs that are directly related to our
mining operations, other than the cost of depreciation,
depletion and amortization (DD&A) expenses. Our
production costs also exclude any indirect costs, such as
selling, general and administrative (SG&A)
expenses. Our production costs do not take into account the
effects of any of the inflation adjustment or cost pass-through
provisions in our multi-year coal supply agreements, as those
provisions result in an adjustment to our coal sales price.
The following table provides summary information for the dates
indicated relating to our cost of coal sales per ton produced:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
Year Ended
|
|
Ended
|
|
|
December 31,
|
|
September 30,
|
|
|
2008
|
|
2009
|
|
2010
|
|
2010
|
|
2011
|
|
|
(In thousands, except per ton amounts)
|
|
Tons of Coal Sold
|
|
|
1,398
|
|
|
|
4,674
|
|
|
|
5,387
|
|
|
|
4,339
|
|
|
|
5,481
|
|
Average Sales Price Per Ton
|
|
$
|
40.82
|
|
|
$
|
35.92
|
|
|
$
|
40.96
|
|
|
$
|
40.63
|
|
|
$
|
41.96
|
|
Cost of Coal Sales Per Ton
|
|
$
|
32.77
|
|
|
$
|
27.36
|
|
|
$
|
28.19
|
|
|
$
|
27.70
|
|
|
$
|
31.07
|
|
ADJUSTED
EBITDA
Although Adjusted EBITDA is not a measure of performance
calculated in accordance with GAAP, our management believes that
it is useful in evaluating our financial performance and our
compliance with our existing Senior Secured Credit Facility.
Adjusted EBITDA has several limitations that are discussed under
Prospectus Summary Summary Historical and
Unaudited Pro Forma Consolidated Financial and Operating
Data, where we also include a quantitative reconciliation
of Adjusted EBITDA to the most directly comparable GAAP
financial measure, which is net income (loss).
Factors
that Impact Our Business
For the past three years, over 93% of our coal sales were made
under multi-year coal supply agreements. We intend to continue
to enter into multi-year coal supply agreements for a
substantial portion of our annual coal production, using our
remaining production to take advantage of market opportunities
as they present themselves. We believe our use of multi-year
coal supply agreements reduces our exposure to fluctuations in
the spot price for coal and provides us with a reliable and
stable revenue base. Using multi-year coal supply agreements
also allows us to partially mitigate our exposure to rising
costs, to the extent those contracts have full or partial cost
pass through provisions or inflation adjustment provisions. For
example, our contracts with LGE contain provisions that adjust
the price paid for our coal in the event there is change in the
price of
56
diesel fuel, a key cost component in our coal production.
Certain of our other contracts, such as those with TVA, contain
provisions that permit us to seek additional price adjustments
to account for changes in environmental and other laws and
regulations to which we are subject, to the extent those changes
increase the cost of our production of coal. For further
information about our multi-year coal supply agreements, please
see Business Sales and Marketing
Multi-Year Coal Supply Agreements.
The following table reflects the portion of our anticipated coal
production that is committed and priced, committed but unpriced,
and uncommitted for sale under our multi-year coal supply
agreements for the years 2011 to 2015.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
|
(In millions of tons, except price per ton data)
|
|
|
Committed
|
|
|
7.6
|
|
|
|
8.8
|
|
|
|
5.7
|
|
|
|
4.1
|
|
|
|
4.0
|
|
Committed but unpriced
|
|
|
|
|
|
|
|
|
|
|
2.4
|
|
|
|
2.8
|
|
|
|
2.8
|
|
Uncommitted
|
|
|
|
|
|
|
0.1
|
|
|
|
1.6
|
|
|
|
3.6
|
|
|
|
3.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
7.6
|
|
|
|
8.9
|
|
|
|
9.7
|
|
|
|
10.5
|
|
|
|
10.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average price per committed ton
|
|
$
|
40.02
|
|
|
$
|
41.91
|
|
|
$
|
41.56
|
|
|
$
|
38.67
|
|
|
$
|
39.38
|
|
Certain of our multi-year coal supply agreements contain option
provisions that give the customer the right to elect to
purchase, or defer the purchase of, additional tons of coal each
month during the contract term at a fixed price provided for in
the contract. Our multi-year coal supply agreements that provide
for these option tons typically require the customer to provide
us with advance notice of an election to take or defer these
option tons. Because the price of these option tons is fixed
under the terms of the contract, we could be obligated to
deliver coal to those customers at a price that is below the
market price for coal on the date the option is exercised. If
our customers elect to receive these option tons, we believe we
will have the operating flexibility to meet these requirements
through increased production. Similarly, short term changes by
our customers in the amount of coal they purchase as a result of
these option and deferment provisions may affect our average
sales price per ton of coal in any given month or similarly
narrow window. For example, as discussed in more detail below,
our average sales price per ton during the first nine months of
2011 was higher than the average sales price per ton during the
first nine months of 2010, partially as the result of certain of
our customers accelerating deliveries of tonnage.
We believe the other key factors that influence our business are:
|
|
|
|
|
demand for coal;
|
|
|
|
demand for electricity;
|
|
|
|
economic conditions;
|
|
|
|
the quantity and quality of coal available from competitors;
|
|
|
|
competition for production of electricity from non-coal sources;
|
|
|
|
domestic air emission standards and the ability of coal-fired
power plants to meet these standards using coal produced from
the Illinois Basin;
|
|
|
|
legislative, regulatory and judicial developments, including
delays, challenges to, and difficulties in acquiring,
maintaining or renewing necessary permits or mineral or surface
rights; and
|
|
|
|
our ability to meet governmental financial security requirements
associated with mining and reclamation activities.
|
For additional information regarding some of the risks and
uncertainties that affect our business and the industry in which
we operate, please see Risk Factors.
57
Recent
Trends and Economic Factors Affecting the Coal
Industry
Coal consumption and production in the United States have been
driven in recent periods by several market dynamics and trends.
Total coal consumption in the United States in 2010 increased by
approximately 50 million tons, or 5.0%, from 2009 levels.
The rise in U.S. domestic coal consumption during 2010 was
largely a function of the recovering economic growth following
the
2008-2009
recession and the rebound in industrial electricity consumption
and domestic steel making output. According to the EIA, coal is
expected to remain the dominant energy source for electric power
generation for the foreseeable future. Please read The
Coal Industry Recent Trends and Coal
Consumption and Demand for the recent trends and economic
factors affecting the coal industry.
Results
of Operations
Factors
Affecting the Comparability of Our Results of
Operations
The comparability of our operating results for the years ending
December 31, 2010, 2009 and 2008 is impacted by the opening
of additional mines during each of the periods. We began
production of coal mid-year 2008 at one underground mine and one
surface mine. Our coal production increased substantially from
1.4 million tons in 2008 to 5.6 million tons in 2010.
The increase in production was primarily the result of the
opening of two additional mines in 2009 and a third in 2010. Due
to these changes in the number of operating mines during the
aforementioned periods, it is difficult to provide direct
comparisons of reported results during each period. In addition,
as discussed in more detail below, from late 2009 through
November 2010, we received a price incentive from LGE under one
of our multi-year coal supply agreements, which added $3.29 per
ton to the sales price under that agreement.
Similarly, the comparability of our operating results for the
nine months ended September 30, 2011 and 2010 is impacted
by the opening of one additional mine in the fourth quarter of
fiscal 2010, one in the second quarter of fiscal 2011 and one in
the third quarter of fiscal 2011. Our coal production increased
from 4.3 million tons in the nine months ended
September 30, 2010 to 5.1 million tons in the nine
months ended September 30, 2011. The increase in production
was primarily the result of the opening of the additional mines.
58
Summary
The following table presents certain of our historical
consolidated financial data for the periods indicated. The
following table should be read in conjunction with
Selected Historical Consolidated Financial and Operating
Data.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except per share and per ton amounts)
|
|
|
Results of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
57,069
|
|
|
$
|
167,904
|
|
|
$
|
220,625
|
|
|
$
|
176,311
|
|
|
$
|
229,980
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of coal sales
|
|
|
45,817
|
|
|
|
127,886
|
|
|
|
151,838
|
|
|
|
120,204
|
|
|
|
170,297
|
|
Depreciation, depletion and amortization
|
|
|
5,451
|
|
|
|
12,480
|
|
|
|
18,892
|
|
|
|
14,017
|
|
|
|
21,478
|
|
Asset retirement obligation expenses
|
|
|
359
|
|
|
|
1,984
|
|
|
|
3,087
|
|
|
|
2,545
|
|
|
|
2,942
|
|
Selling, general and administrative expenses
|
|
|
13,040
|
|
|
|
24,336
|
|
|
|
27,656
|
|
|
|
21,403
|
|
|
|
28,834
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
64,667
|
|
|
|
166,686
|
|
|
|
201,473
|
|
|
|
158,169
|
|
|
|
223,551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(7,598
|
)
|
|
|
1,218
|
|
|
|
19,152
|
|
|
|
18,142
|
|
|
|
6,429
|
|
Interest expense
|
|
|
(14,752
|
)
|
|
|
(12,651
|
)
|
|
|
(11,070
|
)
|
|
|
(8,532
|
)
|
|
|
(6,073
|
)
|
Other income (expense), net
|
|
|
971
|
|
|
|
988
|
|
|
|
87
|
|
|
|
259
|
|
|
|
(36
|
)
|
Gain on extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(21,379
|
)
|
|
|
(10,445
|
)
|
|
|
8,169
|
|
|
|
9,869
|
|
|
|
7,274
|
|
Income tax provision
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(809
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(21,379
|
)
|
|
|
(10,445
|
)
|
|
|
8,169
|
|
|
|
9,869
|
|
|
|
6,465
|
|
Less: net (income) loss attributable to non-controlling interest
|
|
|
(5,552
|
)
|
|
|
(1,730
|
)
|
|
|
3,351
|
|
|
|
2,814
|
|
|
|
7,448
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to common stockholders
|
|
$
|
(15,827
|
)
|
|
$
|
(8,715
|
)
|
|
$
|
4,818
|
|
|
$
|
7,005
|
|
|
$
|
(983
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per share, basic and diluted
|
|
$
|
(1.35
|
)
|
|
$
|
(0.50
|
)
|
|
$
|
0.25
|
|
|
$
|
0.37
|
|
|
$
|
(0.05
|
)
|
Other Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (unaudited)
|
|
$
|
(1,029
|
)
|
|
$
|
16,567
|
|
|
$
|
41,099
|
|
|
$
|
34,874
|
|
|
$
|
32,125
|
|
Adjusted EBITDA per ton sold (unaudited)
|
|
|
(0.74
|
)
|
|
|
3.54
|
|
|
|
7.63
|
|
|
|
8.04
|
|
|
|
5.86
|
|
Nine
Months Ended September 30, 2011 Compared to Nine Months
Ended September 30, 2010
Overview
We reported revenue of $230.0 million for the nine months
ended September 30, 2011 (the 2011 First Nine
Months), compared to $176.3 million for the nine
months ended September 30, 2010 (the 2010 First Nine
Months). Coal sales increased 28% to 5.5 million tons
in the 2011 First Nine Months, compared to 4.3 million tons
in the 2010 First Nine Months. Our average sales price per ton
in the 2011 First Nine Months increased 3.3%, or $1.33 per ton,
compared to the 2010 First Nine Months. Our net income for the
2011 First Nine Months decreased from $9.9 million for the
2010 First Nine Months to $6.5 million for the 2011 First
Nine Months. Our Adjusted EBITDA decreased to $32.1 million
for the 2011 First Nine Months from $34.9 million for the
2010 First Nine Months.
Coal
Production and Sales Volume
Our tons of coal produced increased 18.6% to 5.1 million
tons in the 2011 First Nine Months from 4.3 million tons in
the 2010 First Nine Months. This increase is primarily
attributable to the commencement
59
of production at the Equality Boot surface mine, which increased
our sales by 1.7 million tons for the 2011 First Nine
Months, as compared to the 2010 First Nine Months. This increase
was partially offset by lower production at our other surface
mines as a result of high levels of rainfall, decreases at our
East Fork operation of 0.8 million tons as a portion of the
mine was depleted and MSHA mandates that impacted production at
the Big Run mine. Sales volume during the 2011 First Nine Months
was slightly lower than anticipated due to weather-induced high
water issues on the Green and Ohio Rivers, which delayed barge
deliveries to two of our customers. However, the reduction in
barge-delivered tons was partially offset by an increase in the
number of tons delivered by truck. In addition, maintenance
cycles at the primary plants receiving our coal under our
contracts with TVA resulted in the deferment of approximately
320,000 tons of scheduled deliveries during the 2011 First Nine
Months.
Average
Sales Price Per Ton
Our average sales price per ton increased 3.3% to $41.96 in the
2011 First Nine Months from $40.63 in the 2010 First Nine
Months. This $1.33 per ton increase resulted from the
combination of: (a) higher pricing on our long-term
contracts due to the annual increases under the majority of our
multi-year coal supply agreements, and (b) spot sales that did
not occur in the 2010 First Nine Months. These increases were
partially offset by the elimination of the $3.29 per ton price
adjustment in December 2010 that we received from LGE pending
permitting approval of our Equality Boot mine.
Revenue
Our coal sales revenue for the 2011 First Nine Months increased
by $53.7 million, or 30.4%, compared to the 2010 First Nine
Months. This increase is primarily attributable to coal sales
from our Equality Boot mine, which was opened during January
2011 and contributed an additional $62.9 million of revenue
as compared to the 2010 First Nine Months. The positive effect
of the opening of the Equality Boot mine was partially offset by
record rainfall amounts that hampered barge deliveries, the
partial deferment of deliveries of scheduled tons under contract
by TVA, Big Rivers and Alcoa, which are anticipated to be
partially made up over the course of the remainder of 2011.
Cost of
Coal Sales (Excluding DD&A Expenses and SG&A
Expenses)
Cost of coal sales (excluding DD&A expenses) increased
41.7% to $170.3 million in the 2011 First Nine Months, from
$120.2 million in the 2010 First Nine Months. This increase
was primarily attributable to the opening of our Equality Boot
mine in January 2011, which resulted in operating costs of
$53.5 million during the 2011 First Nine Months. On a per
ton basis, our cost of coal sales increased during the 2011
First Nine Months, compared to the 2010 First Nine Months, from
$27.70 per ton to $31.07 per ton, due to unfavorable mining
conditions at our surface mines as a result of record rainfall
amounts, poor roof conditions at the Big Run mine that required
additional support and reduced productivity, and reduced
production at the Parkway and East Fork mines. In addition, we
experienced higher material and supplies costs in the 2011 First
Nine Months, compared to the 2010 First Nine Months, related to
equipment maintenance expenses, fuel and oil-related expenses
and labor costs. Specifically:
|
|
|
|
|
Equipment maintenance expenses per ton sold increased 23.3% to
$8.40 per ton in the 2011 First Nine Months from $6.81 per ton
in the 2010 First Nine Months. The increase of
$16.2 million in the 2011 First Nine Months as compared to
the 2010 First Nine Months is primarily the result of the cost
of additional equipment at our Equality Boot mine;
|
|
|
|
Fuel and oil-related expenses per ton sold increased 63.2% to
$4.03 per ton in the 2011 First Nine Months from $2.47 per ton
in the 2010 First Nine Months. The increase of
$11.2 million in the 2011 First Nine Months as compared to
the 2010 First Nine Months is the result of higher fuel prices
in the 2011 First Nine Months. A portion of the higher fuel
prices will be recovered through higher revenue in future
periods through fuel adjustment cost provisions in certain of
our multi-year coal supply agreements; and
|
60
|
|
|
|
|
Labor costs per ton sold increased to $9.07 per ton in the 2011
First Nine Months from $9.06 per ton in the 2010 First Nine
Months. This increased production costs by $10.0 million.
The increase was the result of increased labor costs due to the
opening of our Equality Boot, Lewis Creek and Kronos mines in
the 2011 First Nine Months, as well as annual wage adjustments.
|
Depreciation,
Depletion and Amortization
DD&A expenses increased by $7.5 million, or 53.2%,
during the 2011 First Nine Months, as compared to the same
period in 2010. The primary reason for the increase was a
$5.1 million increase in depreciation associated with the
Equality Boot operations. Depletion and amortization expenses
were also slightly higher as a result of the higher production
in 2011. Lower depreciation was realized at operations with
reduced production, thereby offsetting a portion of the
increases.
Asset
Retirement Obligation Expense
Asset retirement obligation expense increased by
$0.4 million, or 15.6%, in the 2011 First Nine Months, as
compared to the 2010 First Nine Months. The increase is due
primarily to the opening of the Equality Boot mine.
Selling,
General and Administrative Expenses
SG&A expenses were $28.8 million for the 2011 First
Nine Months, which was $7.4 million, or 34.7%, higher than
the 2010 First Nine Months. On a cost per ton sold basis for the
First Nine Months of 2011, SG&A expenses were $5.26,
compared to $4.93 for the First Nine Months of 2010.
Administrative expenses related to the Equality Boot mine
accounted for the majority of the increase in costs, and higher
coal severance and similar costs that are directly related to
the $53.7 million, or 30.5%, increase in total sales for
the 2011 First Nine Months as compared to the 2010 First Nine
Months.
Interest
Expense
Interest expense was $6.1 million for the 2011 First Nine
Months, as compared to $8.5 million for the 2010 First Nine
Months. The decrease was principally attributable to lower
interest rates associated with our Senior Secured Credit
Facility as compared to our existing debt during the 2010 First
Nine Months in the form of the promissory notes that were repaid
when we entered into our Senior Secured Credit Facility in
February 2011. See Description of Indebtedness for a
more detailed discussion of our financing activities. As a
result of the aforementioned repayment, we recorded a gain on
the extinguishment of debt of $7.0 million.
Income
Taxes
We recorded an income tax provision of $0.8 million for the
2011 First Nine Months while no provision was recorded in the
2010 First Nine Months. The provision related primarily to
current alternative minimum tax and certain state income tax.
The current provision is due to taxable income generated in the
2011 First Nine Months for certain subsidiaries, compared to
taxable losses generated in the same period of the prior year.
Adjusted
EBITDA
Our Adjusted EBITDA for the 2011 First Nine Months was
$32.1 million, or $5.86 per ton, as compared to
$34.9 million, or $8.04 per ton, for the 2010 First Nine
Months. The decrease resulted from the partial deferment of
deliveries of scheduled tons under contract by TVA, Big Rivers
and Alcoa until later in the year, the expiration of the price
incentive realized during the 2010 First Nine Months in
connection with one of our LGE sales contracts, and the higher
operating costs attributable to the commencement of production
at the Equality Boot mine during the 2011 First Nine Months.
61
Production
Mix Analysis
During the 2011 First Nine Months we operated three underground
mines (Big Run, Kronos, and Parkway) and four surface mines
(Midway, East Fork, Equality Boot and Lewis Creek). In contrast,
during the 2010 First Nine Months, we only had four mines in
operation, as production at the Equality Boot mine did not
commence until January 2011, Lewis Creek in June 2011, and
Kronos in September 2011. The following table provides
information concerning our underground mines and surface mines
during both the 2010 First Nine Months and the 2011 First Nine
Months.
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2010
|
|
|
2011
|
|
|
|
(In thousands, except
|
|
|
|
per ton amounts)
|
|
|
Tons of Coal Sold
|
|
|
|
|
|
|
|
|
Underground Mining Operations
|
|
|
1,583
|
|
|
|
1,576
|
|
Surface Mining Operations
|
|
|
2,756
|
|
|
|
3,905
|
|
Revenue
|
|
|
|
|
|
|
|
|
Underground Mining Operations
|
|
$
|
78,054
|
|
|
$
|
82,133
|
|
Surface Mining Operations
|
|
$
|
98,257
|
|
|
$
|
147,847
|
|
Production Costs per Ton Sold
|
|
|
|
|
|
|
|
|
Underground Mining Operations
|
|
$
|
28.89
|
|
|
$
|
29.05
|
|
Surface Mining Operations
|
|
$
|
20.78
|
|
|
$
|
26.59
|
|
Plants, Dock, Other
|
|
$
|
3.96
|
|
|
$
|
3.78
|
|
Sales from our surface mines increased from 2.8 million
tons in the 2010 First Nine Months to 3.9 million tons in
the 2011 First Nine Months. The increase in tons sold is
primarily attributable to the opening of the Equality Boot mine
in January 2011 and Lewis Creek in June 2011. Our production
costs on a per ton basis at our surface mining operations also
increased from $20.78 per ton produced during the 2010 First
Nine Months to $26.59 per ton produced during the 2011 First
Nine Months. The increase in production costs on a per ton basis
at our surface mines is the result of many factors, including
higher fuel prices, weather-related impediments, reduced
production levels at the East Fork mine as one area of the mine
is depleted, and the continued development of the
recently-opened Equality Boot mine.
Sales from our underground mines of 1.6 million tons during
the 2010 First Nine Months were comparable to 1.6 million
tons during the 2011 First Nine Months. Production costs per ton
at our underground mines increased from $28.89 per ton produced
during the 2010 First Nine Months to $29.05 per ton produced
during the 2011 First Nine Months. This increase is primarily
the result of increased per ton production costs at our Big Run
mine due to the increased material cost for roof bolts and the
temporary replacement of a continuous miner unit for a scheduled
overhaul prior to relocating to the new underground operation at
Kronos resulting in a decrease in productivity.
Year
Ended December 31, 2010 Compared to Year Ended
December 31, 2009
Overview
We reported revenue of $220.6 million for the year ended
December 31, 2010, compared to $167.9 million for
2009. Coal sales increased 15% to 5.4 million tons in 2010,
as compared to 4.7 million tons in 2009. In addition to
increasing our total production, our average sales price per ton
in 2010 increased 14%, or $5.04 per ton, compared to 2009. In
part as a result of that increase in the average price per ton,
we generated income from operations in 2010 of
$19.2 million, as compared to $1.2 million in 2009,
and our Adjusted EBITDA increased to $41.1 million in 2010,
from $16.6 million in 2009.
62
Coal
Production and Sales Volume
Our tons of coal produced increased 27.3% to 5.6 million
tons in 2010 from 4.4 million tons in 2009. This increase
is primarily attributable to operations at our East Fork surface
mine and our Parkway underground mine. The East Fork mine, which
commenced production during the second quarter of 2009, sold
1.7 million tons during 2010, as compared to
0.9 million tons in 2009. Similarly, the Parkway
underground mine, which also commenced production during the
second quarter of 2009, sold 1.5 million tons in 2010
compared to 0.7 million tons in 2009. Sales volume during
the fourth quarter of 2010 was slightly less than anticipated
due to a delay in the opening of our Equality Boot surface mine
until 2011 and its corresponding effect on budgeted spot market
sales. During 2010, sales to our two largest customers, LGE and
TVA, accounted for 76% of our total sales, representing 36% and
40% of total sales respectively.
Average
Sales Price Per Ton
Our average sales price per ton increased 14% to $40.96 in 2010
from $35.92 in 2009. This $5.04 per ton increase was primarily
the result of a combination of factors, including: (a) a
contractually-based price incentive in one of our multi-year
coal supply agreements with LGE, which provided for a $3.29 per
ton increase from September 2009 through November 2010;
(b) the renegotiation of another of our multi-year coal
supply agreements, which resulted in an increase in the price
per ton of $8.73; (c) a price adjustment with respect to
one of our contracts with TVA pursuant to which governmental
imposition reimbursements increased our price per ton by $2.00;
(d) the annual escalation of prices contained in the
majority of our multi-year coal supply agreements, and
(e) the execution of a new multi-year coal supply agreement
with OMU, pursuant to which we obtained an average sales price
of $43.27 per ton. Our ability to obtain short-term sales at
prices and volumes higher than in previous years also
contributed to the increase in our average sales price per ton.
Revenue
Our coal sales revenue in 2010 increased by $52.7 million,
or 31.4%, compared to 2009. This increase is primarily
attributable to coal sales from our East Fork surface mine and
Parkway underground mine, both of which were opened during 2009
and thus experienced their first full year of production during
2010. As a result, the combined sales from the East Fork and
Parkway mines during 2010 exceeded their aggregate 2009 sales by
1.5 million tons. In addition, our revenue increased as a
result of the increase in the average price per ton at which we
sold our coal for the reasons set forth immediately above.
Cost of
Coal Sales (Excluding DD&A Expenses and SG&A
Expenses)
In 2010, cost of coal sales (excluding DD&A expenses and
SG&A expenses) increased 18.7%, to $151.8 million,
from $127.9 million in 2009, which was primarily attributed
to the 15.3% increase in the total tons of coal we sold during
the same period, combined with a 3% per ton increase in our
operating costs of $0.83 during 2010, compared to 2009. The
increase in our operating costs per ton was due in part to the
progression into areas at our Midway and East Fork surface mines
where we experienced higher mining ratios, thus increasing the
costs required to produce each ton of coal, as well as the need
to incur additional overtime labor costs at those surface mines
to meet contractual sales requirements in light of the delay in
the opening of the Equality Boot surface mine. These per ton
cost increases were partially offset by a decrease in the
operating costs at our Parkway and Big Run underground mines
resulting from improved productivity over the course of 2010 at
those mines. In addition, we experienced higher equipment
maintenance expenses, fuel and oil-related expenses and
royalties in 2010, compared to 2009. Specifically:
|
|
|
|
|
Equipment maintenance expenses per ton sold increased 11% to
$7.10 per ton in 2010 from $6.37 per ton in 2009. The increase
of $8.5 million resulted from increased production, as two
mines were added during 2009, and higher mining ratios during
2010;
|
|
|
|
Fuel and oil-related expenses per ton sold increased 25% to
$2.53 per ton in 2010, from $2.02 per ton in 2009. This
represents a $4.2 million increase and is the result of
higher production levels and higher fuel prices in 2010; and
|
63
|
|
|
|
|
Royalties (which were incurred as a percentage of coal sales or
based on coal volumes) increased $0.17 per ton sold in 2010,
compared to 2009, primarily as a result of increased average
coal sales prices and our increase in the total volume of
production and sales.
|
Depreciation,
Depletion and Amortization Expenses
DD&A expenses for 2010 were $18.9 million, which was
$6.4 million, or 51.4%, higher, as compared to 2009. This
was due to a $2.4 million increase in depletion and
amortization expense that resulted from our increase in total
production in 2010, as well as a $4.0 million increase in
depreciation as operations expanded with new equipment additions
and a full year of expenses that we incurred at our East Fork
and Parkway mines, as compared to the partial year of expenses
at those mines during 2009, the year in which they commenced
production.
Asset
Retirement Obligation Expense
Asset retirement obligation expense increased by
$1.1 million, or 55.5%, in 2010, as compared to the prior
year. The increase is due primarily to having a full year of
expense in 2010 related to the Parkway and East Fork mines,
which were added in the second quarter of 2009.
Selling,
General and Administrative Expenses
SG&A expenses were $27.7 million for 2010, which was
$3.3 million higher than 2009, but on a cost per ton sold
basis decreased from $5.21 per ton to $5.13 per ton. While total
sales increased in 2010 by 31.4%, a proportional increase in
sales-related costs was partially offset by the generally fixed
legal, accounting and other professional fee expenses we incur
that were spread across a greater number of tons.
Interest
Expense
Interest expense decreased by $1.6 million in 2010 as
compared to 2009, from $12.7 million to $11.1 million,
primarily as a result of the repayment in June 2009 of one of
the promissory notes made in connection with the acquisition of
the Elk Creek Reserves in March 2008.
Adjusted
EBITDA
Our Adjusted EBITDA was $24.5 million higher in 2010 as
compared to 2009, increasing 148% from $16.6 million, or
$3.54 per ton, to $41.1 million, or $7.63 per ton sold. The
increase primarily resulted from the annual increase in the
sales prices contained in the majority of our multi-year coal
supply agreements, the renegotiation of the sales price under
another of our contracts, and a price-based incentive of $3.29
per ton contained in one of our contracts with LGE that
increased the sales price under that contract through November
2010.
Production
Mix Analysis
During 2010, we operated two underground mines (Big Run and
Parkway) and three surface mines (Midway, East Fork and Equality
Boot), although the production from Equality Boot during 2010
was recorded and capitalized as part of the mines
development costs. In contrast, during 2009, we only had four
mines in operation Big Run, Parkway, Midway and East
Fork, and the Parkway mine only began
64
production during April 2009, followed shortly thereafter by the
East Fork mine in June 2009. The following table provides
information concerning our underground and surface mines during
both 2009 and 2010.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2009
|
|
2010
|
|
|
(In thousands, except per ton amounts)
|
|
Tons of Coal Sold
|
|
|
|
|
|
|
|
|
Underground Mining Operations
|
|
|
1,356
|
|
|
|
2,066
|
|
Surface Mining Operations
|
|
|
3,318
|
|
|
|
3,321
|
|
Revenue
|
|
|
|
|
|
|
|
|
Underground Mining Operations
|
|
$
|
61,373
|
|
|
$
|
102,109
|
|
Surface Mining Operations
|
|
$
|
106,531
|
|
|
$
|
118,516
|
|
Production Costs per Ton Sold
|
|
|
|
|
|
|
|
|
Underground Mining Operations
|
|
$
|
36.36
|
|
|
$
|
28.54
|
|
Surface Mining Operations
|
|
$
|
17.38
|
|
|
$
|
21.84
|
|
Plants, Dock, Other
|
|
$
|
4.38
|
|
|
$
|
3.46
|
|
Our production costs on a per ton basis at our surface mining
operations also increased from $17.38 per ton during 2009 as
compared to $21.84 per ton during 2010. The increase in
production costs on a per ton basis at our surface mines is the
result of many factors, including higher stripping ratios
encountered in our mining operations, increased explosives costs
due to mining wet areas early in the calendar year, and
additional overtime costs for labor needed to meet sales
contract requirements due to the delay in the opening of the
Equality Boot mine.
Sales from our underground mines also increased from
1.4 million tons during 2009 to 2.1 million tons
during 2010. The majority of the increase in sales is
attributable to the opening of our second underground mine at
Parkway during June 2009. Production costs per ton at our
underground mines decreased from $36.36 per ton during 2009 to
$28.54 per ton during 2010, reflecting a 21.5% decrease. This
decrease is primarily the result of the lower mining costs
experienced at our Parkway mine ($23.84 per ton), which were
partially offset by the slightly higher production costs
incurred at our Big Run underground mine attributable to
unexpected continuous miner repairs, larger than anticipated
transportation expenses and the costs of complying with new
governmental regulations.
Year
Ended December 31, 2009 Compared to Year Ended
December 31, 2008
Overview
We reported revenue of $167.9 million for the year ended
December 31, 2009, compared to $57.1 million for 2008.
Total tons sold increased 234% to 4.67 million tons in 2009
as compared to 1.40 million tons in 2008. Our average sales
price per ton in 2009 decreased 12%, or $4.90 per ton, compared
to 2008. As a result of the increase in the sales volume, we
generated operating income of $1.2 million in 2009, as
compared to a loss of $7.6 million in 2008, and our
Adjusted EBITDA increased to $16.6 million in 2009 from
$(1.0) million in 2008.
Coal
Production and Sales Volume
Our tons of coal produced increased 221.5% to 4.4 million
tons in 2009 from 1.4 million tons in 2008. This increase
is primarily attributable to operations at our East Fork surface
mine and our Parkway underground mine. The East Fork mine, which
commenced production during the second quarter of 2009, sold
0.9 million tons in 2009. Similarly, the Parkway
underground mine, which also commenced production during the
second quarter of 2009, sold 0.7 million tons in 2009.
During 2009, our sales to our two largest customers, LGE and
TVA, accounted for 79% of our total sales, representing 42% and
37% of total sales, respectively.
65
Average
Sales Price Per Ton
Our average sales price per ton decreased 12% to $35.92 in 2009,
from $40.82 in 2008. This $4.90 per ton decrease was primarily
the result of increased shipments under lower priced agreements
and the lack of higher priced spot sales that did not occur in
2009.
Revenue
Our coal sales revenue in 2009 increased by $110.8 million,
or 194%, compared to 2008. This increase is primarily
attributable to coal sales from our East Fork surface mine and
Parkway underground mine, both of which were opened during 2009.
As a result, the combined sales from the East Fork and Parkway
mines during 2009 was 1.7 million tons, or
$71.4 million. In addition, the Midway mine that opened in
July 2008, benefited from a full year of production, which
increased our tons sold by 1.6 million in 2009.
Cost of
Coal Sales (Excluding DD&A Expenses and SG&A
Expenses)
Cost of coal sales (excluding DD&A expenses and SG&A
expenses) in 2009 increased 179%, to $127.9 million, from
$45.8 million in 2008, which was primarily attributed to
the 234% increase in the total tons of coal we sold during the
same period, offset with a per ton decrease in our operating
costs of $5.41 during 2009, which represents a 16.5% decrease as
compared to 2008. The decrease in our operating costs per ton
was primarily the result of the efficiencies achieved at the
higher production levels.
Depreciation,
Depletion and Amortization
DD&A expenses for 2009 were $12.5 million, which was
$7.0 million, or 129%, higher, as compared to 2008. This
was due to (i) the increase in depletion and amortization
expense that resulted from our increase in total production in
2009, (ii) an increase in depreciation as operations
expanded with new equipment additions and a full year of
expenses that we incurred at our Midway mine, and (iii) the
East Fork and Parkway mines having a partial year of expenses
during 2009 (the year in which they commenced production).
Asset
Retirement Obligation Expense
Asset retirement obligation expense increased by
$1.6 million, or 453%, in 2009, as compared to 2008. The
increase is due to the addition of the East Fork and Parkway
mines in the second quarter of 2009, as well as a full year of
expense related to the Midway mine in 2009.
Selling,
General and Administrative Expenses
SG&A expenses were $24.3 million for 2009, which was
$11.3 million higher than 2008 On a cost per ton sold
basis, SG&A expenses decreased from $9.33 per ton in 2008
to $5.21 per ton in 2009. While total sales increased in 2009 by
194%, a proportional increase in sales-related costs was more
than offset by the generally fixed legal, accounting and other
professional fee expenses we incur that were spread across a
greater number of tons.
Interest
Expense
Interest expense decreased by $2.1 million in 2009 as
compared to 2008, from $14.8 million to $12.7 million,
primarily as the result of the repayment in June 2009 of one of
the promissory notes made in connection with the acquisition of
the Elk Creek Reserves in March 2008.
Adjusted
EBITDA
Our Adjusted EBITDA was $17.6 million higher in 2009 as
compared to 2008, increasing from $(1.0) million, or
$(0.74) per ton, to $16.6 million, or $3.54 per ton. The
increase primarily resulted from the annual increase in the
sales prices contained in the majority of our multi-year coal
supply agreements, the renegotiation of the sales price under
another of our contracts, and a price-based incentive contained
in one of our contracts with LGE that increased the sales price
under that contract through November 2010.
66
Production
Mix Analysis
During 2009, we operated four mines (Big Run, Parkway, Midway
and East Fork) as compared to only two mines (Big Run and
Midway) during 2008. The following table provides information
concerning our underground and surface mines during 2008 and
2009.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2008
|
|
2009
|
|
|
(In thousands, except per ton amounts)
|
|
Tons of Coal Sold
|
|
|
|
|
|
|
|
|
Underground Mining Operations
|
|
|
609
|
|
|
|
1,356
|
|
Surface Mining Operations
|
|
|
789
|
|
|
|
3,318
|
|
Revenue
|
|
|
|
|
|
|
|
|
Underground Mining Operations
|
|
$
|
25,650
|
|
|
$
|
61,373
|
|
Surface Mining Operations
|
|
$
|
31,419
|
|
|
$
|
106,531
|
|
Production Costs per Ton Sold
|
|
|
|
|
|
|
|
|
Underground Mining Operations
|
|
$
|
27.76
|
|
|
$
|
36.36
|
|
Surface Mining Operations
|
|
$
|
26.22
|
|
|
$
|
17.38
|
|
Plants, Dock, Other
|
|
$
|
5.88
|
|
|
$
|
4.38
|
|
Sales from our surface mines increased from 0.8 million
tons in 2008 to 3.3 million tons in the 2009. The increase
in sales is primarily attributable to the opening of the East
Fork mine in mid-year 2009, and we benefited from an entire year
of production at the Midway mine. Our production costs on a per
ton basis at our surface mining operations also decreased from
$26.22 per ton during 2008 to $17.38 per ton during 2009. The
decrease in production costs on a per ton basis at our surface
mines is the result of higher production levels and lower
stripping ratios encountered in our mining operations.
Sales from our underground mines also increased from
0.6 million tons during 2008 to 1.4 million tons
during 2009. The majority of the increase in sales is
attributable to the opening of our second underground mine at
Parkway during June 2009. Production costs per ton at our
underground mines increased from $27.76 per ton during 2008 to
$36.36 per ton during 2009. This increase is primarily the
result of less favorable geologic conditions at our Big Run mine
and inefficiencies encountered during the start of operations at
our Parkway mine.
Liquidity
and Capital Resources
Liquidity
Our business is capital intensive and requires substantial
capital expenditures for purchasing, upgrading and maintaining
equipment used in mining our reserves, as well as complying with
applicable environmental laws and regulations. Our principal
liquidity requirements are to finance current operations, fund
capital expenditures, including acquisitions from time to time,
and to service our debt. Our primary sources of liquidity to
meet these needs have been cash generated by our operations,
borrowings under our Senior Secured Credit Facility and
contributions from Yorktown.
We believe that cash generated from operations and borrowings
under our Senior Secured Credit Facility will be sufficient to
meet working capital requirements, anticipated capital
expenditures and scheduled debt payments for at least the next
several years. We manage our exposure to changing commodity
prices for our long-term coal contract portfolio through the use
of multi-year coal supply agreements. We enter into fixed price,
fixed volume supply contracts with terms greater than one year
with customers with whom we have historically had limited
collection issues. Our ability to satisfy debt service
obligations, to fund planned capital expenditures, to make
acquisitions, will depend upon our future operating performance,
which will be affected by prevailing economic conditions in the
coal industry and financial, business and other factors, some of
which are beyond our control.
67
The principal indicators of our liquidity are our cash on hand
and availability under our Senior Secured Credit Facility. As of
September 30, 2011, our available liquidity was
$22.9 million, comprised of cash on hand of
$7.5 million and $15.4 million available under our
Senior Secured Credit Facility.
Cash
Flows
The following table reflects cash flows for the applicable
periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
Year Ended
|
|
Ended
|
|
|
December 31,
|
|
September 30,
|
|
|
2008
|
|
2009
|
|
2010
|
|
2010
|
|
2011
|
|
|
(In thousands)
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities
|
|
$
|
(11,079
|
)
|
|
$
|
3,054
|
|
|
$
|
37,194
|
|
|
$
|
26,804
|
|
|
$
|
31,126
|
|
Investing Activities
|
|
$
|
(80,020
|
)
|
|
$
|
(62,476
|
)
|
|
$
|
(41,755
|
)
|
|
$
|
(24,681
|
)
|
|
$
|
(47,386
|
)
|
Financing Activities
|
|
$
|
79,402
|
|
|
$
|
64,854
|
|
|
$
|
(3,935
|
)
|
|
$
|
(6,017
|
)
|
|
$
|
15,706
|
|
Nine
Months Ended September 30, 2011 Compared to Nine Months
Ended September 30, 2010
Net cash provided by operating activities was $31.1 million
for the nine months ended September 30, 2011, an increase
of $4.3 million from net cash provided by operating
activities of $26.8 million for the same period of 2010.
The increase in cash provided by operating activities was
principally attributable to the expansion of our operations with
the opening of the Equality Boot, Lewis Creek and Kronos mines
in September 2010, June 2011, and September 2011, respectively.
The additional mines and higher production levels resulted in
increased depreciation, depletion, and amortization expense in
the current year, as well as impacted our cash flows from
operating assets and liabilities, primarily by leading to an
increase in accounts payable and payroll and other accrued
incentives in the current year. Negatively impacting cash flows
from operations was a year over year decline in net income due
to higher overall operating costs and the inclusion of a
non-cash gain on early extinguishment of debt recognized in the
nine months ended September 30, 2011.
Net cash used in investing activities was $47.4 million for
the nine months ended September 30, 2011 compared to
$24.7 million for the same period of 2010. This
$22.7 million increase was primarily attributable to
capital expenditures on equipment and mine development for our
Kronos and Lewis Creek mines, as well as an investment in an
affiliate for the planned construction of an export facility on
the lower Mississippi River.
Net cash provided in financing activities was $15.7 million
for the nine months ended September 30, 2011 compared to
net cash used in financing activities of $6.0 million for
the nine months ended September 30, 2010. This difference
was primarily attributable to the closing of our Senior Secured
Credit Facility and the repayment of our existing long-term debt
in connection therewith. See Description of
Indebtedness for a more detailed discussion of our
financing activities.
Year
Ended December 31, 2010 Compared to Year Ended
December 31, 2009
Net cash provided by operating activities was $37.2 million
for 2010, an increase of $34.1 million from net cash
provided by operating activities of $3.1 million for 2009.
The increase in cash provided by operating activities was
principally attributable to an increase in net income and
depreciation, amortization, and depletion expense of
$18.6 million and $6.4 million, respectively, due
primarily to the continued expansion of our business through the
opening of the Equality Boot mine in September 2010 and having a
full year of production from the Parkway and East Fork mines,
which opened in 2009. In addition, average sales price per ton
increased approximately 14% from 2009 to 2010 due primarily to
certain price incentives received and annual price escalations
contained in our long-term supply contracts. The change in
interest on long term obligations of $9.9 million added to
the increase in cash flows from operations due to the timing of
interest payments. Partially offsetting this increase in cash
flows from operations is the decline in the net change in
operating assets and liabilities. The change in accounts
receivable and inventory of $16.3 million and
($4.2 million), respectively, is due to the timing of
shipments at year-end. The increase in the use of cash
associated with other non-current
68
assets of $3.0 million relates primarily to an increase in
collateral posted on surety bonds and cash bonds to secure the
performance of our reclamation obligations as a result of our
additional mine being commissioned in 2010. The decline in cash
provided by accounts payable and accrued liabilities of
$10.1 million is primarily related to the timing of
payments associated with general operating expenses and
royalties.
Net cash used in investing activities was $41.8 million for
2010 compared to $62.5 million for the 2009. This
$20.7 million decrease was primarily attributable to a
reduction in capital expenditures as higher capital was required
in 2009 to start the new mining operations that began in 2009.
Net cash used in financing activities was $3.9 million for
2010 compared to net cash provided by financing activities of
$64.9 million for the 2009. This difference was primarily
attributable to $55.2 million of member contributions
recorded during 2009 which were not made during 2010 and an
additional $8.5 million of minority contributions made in
2009.
Year
Ended December 31, 2009 Compared to Year Ended
December 31, 2008
Net cash provided by operating activities was $3.1 million
for 2009, an increase of $14.2 million from net cash used
by operating activities of $11.1 million for 2008. The
increase in cash provided by operating activities was
principally attributable to a reduction in our net loss and
increase in depreciation, amortization, and depletion expense of
$10.9 million and $8.7 million, respectively, due to
better leveraging of our operating expenses and the increased
output from our operations. Partially offsetting the increase in
cash flows was the $5.7 million increase in net operating
assets and liabilities. The change in accounts receivable of
$4.1 million is due to the timing of shipments at year-end.
The decrease in the use of cash associated with other
non-current assets of $5.1 million is due largely to
deposits made during 2008 for the purchase of machinery and
equipment to be utilized as we expand our operations. The
increase in cash provided by accounts payable and accrued
liabilities of $5.3 million is primarily related to the
timing of payments associated with general operating expenses
and royalties. The change in interest on long term obligations
of $11.5 million reduced cash flows from operations due to
the timing of interest payments.
Net cash used in investing activities was $62.5 million for
2009 compared to $80.0 million for 2008. This
$17.5 million decrease was primarily attributable to lower
capital expenditures.
Net cash provided by financing activities was $64.9 million
for 2009 compared to net cash provided by financing activities
of $79.4 million for 2008. This difference is due primarily
to higher minority contributions in 2008.
Senior
Secured Credit Facility
In February 2011, we repaid certain promissory notes that were
delivered in connection with the acquisition of our coal
reserves (see Business Our Operational
History) and entered into the Senior Secured Credit
Facility, which is comprised of the Senior Secured Term Loan and
the Senior Secured Revolving Credit Facility. The Senior Secured
Term Loan is a $100.0 million term loan, and the Senior
Secured Revolving Credit Facility is a $50.0 million
revolving credit facility. As a result of the repayment of the
existing debt obligations, we recognized a gain of approximately
$7.0 million in the quarter ended March 31, 2011. The
Senior Secured Term Loan is a five-year term loan that requires
principal payments in the amount of $5.0 million each on
the first day of each quarter commencing on January 1, 2012
through January 1, 2016, with a final balloon payment due
upon maturity on February 9, 2016. Interest payments are
also payable quarterly in arrears on the first day of each
quarter. The interest rate fluctuates based on our leverage
ratio and the applicable interest option elected. The interest
rate as of September 30, 2011 was 5.75%. The Senior Secured
Revolving Credit Facility provides for quarterly interest
payments in arrears that fluctuate on the same terms as our term
loan. The Senior Secured Revolving Credit Facility also provides
for a commitment fee based on the unused portion of the facility
at certain times. As of September 30, 2011, we had
$34.6 million outstanding, with $15.4 million
available for borrowing under our Senior Secured Revolving
Credit Facility. The obligations under the credit agreement are
secured by a first lien on substantially all of our assets,
including but not limited to certain of our mines, coal reserves
and related fixtures. The credit agreement contains certain
customary covenants as well as certain limitations on, among
other things,
69
additional debt, liens, investments, acquisitions and capital
expenditures, future dividends, and asset sales. We incurred
approximately $3.3 million in fees related to the new
credit agreement which will be amortized over the term of the
Senior Secured Term Loan. We entered into an interest rate swap
agreement, effective January 1, 2012, to hedge our exposure
to rising interest rates. Pursuant to this agreement, we are
required to make payments at a fixed interest rate of 2.89% to
the counterparty on an initial notional amount of
$47.5 million (amortizing thereafter) in exchange for
receiving variable payments based on the greater of 1.0% or the
three-month LIBOR rate, which was 0.37433% as of
September 30, 2011. This agreement has quarterly settlement
dates and matures on February 9, 2016.
On July 1, 2011, we entered into the First Amendment to our
Senior Secured Credit Facility which, among other things,
amended the provisions of the loan documents so as to permit an
offering of our securities and the completion of the
Reorganization. The amendment also made certain changes to our
financial covenants, including our maximum leverage ratio. In
addition, our interest rate increased to 5.75%, which can be
reduced in future periods to the extent our results improve.
Pursuant to such provision, on November 15, 2011, our
interest rate was reduced to 5.25%. We incurred approximately
$1.1 million of fees related to this amendment, which will
be amortized over the remaining term of the Senior Secured Term
Loan. We entered into the Second Amendment to our Senior Secured
Credit Facility on September 29, 2011, pursuant to which
restrictions to the consummation of this offering were
eliminated. Additionally, on December 29, 2011, we entered
into the Third Amendment to our Senior Secured Credit Facility
which, among other things, amended the provisions of the loan
documents so as to permit the acquisition of additional coal
reserves. On February 8, 2012, we entered into the Fourth
Amendment to our Senior Secured Credit Facility which, among
other things, amended the provisions of the loan documents so as
to modify the consolidated EBITDA threshold, eliminate the
minimum fixed charge coverage ratio, add a minimum interest
coverage ratio beginning in 2013 and make certain changes to our
financial covenants, including our maximum leverage ratio and
our minimum consolidated EBITDA. In connection with entry into
the Third and Fourth Amendments to the Senior Secured Credit
Facility, we paid fees in the aggregate amount of
$1.125 million.
Contractual
Obligations
We have various commitments primarily related to long-term debt,
including capital leases and operating lease commitments related
to equipment. We expect to fund these commitments with cash on
hand, cash generated from operations and borrowings under our
Senior Secured Credit Facility. The following table provides
details regarding our contractual cash obligations as of
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
Total
|
|
Less Than One Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More Than Five Years
|
|
|
(In thousands)
|
|
Long-term debt obligations (principal and interest)(1)
|
|
$
|
142,116
|
|
|
$
|
55,279
|
|
|
$
|
80,307
|
|
|
$
|
6,507
|
|
|
$
|
23
|
|
Operating lease obligations
|
|
|
61,765
|
|
|
|
15,328
|
|
|
|
29,488
|
|
|
|
16,949
|
|
|
|
|
|
Capitalized lease obligations (principal and interest)
|
|
|
18,235
|
|
|
|
4,730
|
|
|
|
8,839
|
|
|
|
4,127
|
|
|
|
539
|
|
Purchase obligations
|
|
|
5,371
|
|
|
|
5,371
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
227,487
|
|
|
$
|
80,708
|
|
|
$
|
118,634
|
|
|
$
|
27,583
|
|
|
$
|
562
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
At December 31, 2010, the payments to be made in 2011 were
classified as long-term on our audited balance sheet since these
debt obligations were repaid in February 2011 from proceeds from
the Senior Secured Credit Facility and no amounts were due in
2011 under the new credit agreement. The Senior |
70
|
|
|
|
|
Secured Credit Facility is comprised of the $100 million
Senior Secured Term Loan and the $50 million Senior Secured
Revolving Credit Facility. Of the proceeds from borrowings under
the Senior Secured Credit Facility totaling $118.5 million,
$115.7 million was used to repay the outstanding secured
promissory notes. As of September 30, 2011, principal and
interest on the term loan of $21.2 million,
$48.3 million, $47.7 million and $0 is due in less
than 12 months, one to three years, three to five years and
after five years, respectively. |
On February 9, 2011, Armstrong Resource Partners exercised
its option to acquire a 39.45% undivided interest in certain of
our mineral reserves and land in satisfaction of certain
indebtedness owed by us, the payment of $5.0 million and as
repayment of the accrued advanced royalty payments owed by us.
Simultaneous with this transaction, we entered into a lease
agreement with a subsidiary of Armstrong Resource Partners to
mine the acquired mineral reserves. The lease has a term of
10 years that can be extended for additional periods until
all the respective merchantable and mineable coal is removed.
Armstrong Energy accounted for the aforementioned lease
transaction as a financing arrangement due to Armstrong
Energys continuing involvement in the land and mineral
reserves transferred. This has resulted in the recognition of an
initial obligation of $69.5 million. As the financial
results of Armstrong Resource Partners have historically been
consolidated, this transaction has not impacted our results of
operations or financial condition through September 30,
2011. As noted above, effective October 1, 2011, we amended
the ARP LPA, which resulted in the deconsolidation of Armstrong
Resource Partners. Subsequently, the long-term obligation will
be reflected on our balance sheet and will continue to be
amortized through 2031 at an annual rate of 7% of the estimated
gross revenue generated from the sale of the coal originating
from the leased mineral reserves. As of September 30, 2011,
the outstanding principal balance of the long-term obligations
to Armstrong Resource Partners was $70.3 million.
Capital
Expenditures
Our mining operations require investments to expand, upgrade or
enhance existing operations and to comply with environmental
regulations. Our anticipated total capital expenditures for 2011
are estimated in a range of $60.0 to $70.0 million.
Management anticipates funding 2011 capital requirements with
cash flows provided by operations, borrowing available under our
Senior Secured Credit Facility as discussed below, leases and
the proceeds of this offering. We will continue to have
significant capital requirements over the long-term, which may
require us to incur debt or seek additional equity capital. The
availability and cost of additional capital will depend upon
prevailing market conditions, the market price of our securities
and several other factors over which we have limited control, as
well as our financial condition and results of operations.
Equality
Boot Mine Development
Mine development costs are capitalized until production
commences, other than production incidental to the mine
development process, and are amortized on a units of production
method based on the estimated proven and probable reserves. Mine
development costs represent costs incurred in establishing
access to mineral reserves and include costs associated with
sinking or driving shafts and underground drifts, permanent
excavations, roads and tunnels. The end of the development phase
and the beginning of the production phase takes place when
construction of the mine for economic extraction is
substantially complete. Our estimate of when construction of the
mine for economic extraction is substantially complete is based
upon a number of assumptions, such as expectations regarding the
economic recoverability of reserves, the type of mine under
development, and completion of certain mine requirements, such
as ventilation. Coal extracted during the development phase is
incidental to the mines production capacity and is not
considered to shift the mine into the production phase. During
the last four months of 2010, as we completed development of the
dragline pits at our Equality Boot surface mine, certain costs
related thereto were capitalized and will be amortized over the
life of the mine. These costs are reduced by any revenue
generated during the development stage. The net amount
capitalized with respect to these activities in 2010 was
$8.2 million.
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Kronos
Underground Mine Development
The Kronos underground mine will initially be a two unit
underground mine. The majority of the equipment for the mine
will be transferred from our existing Big Run underground mine.
Notwithstanding the fact that we will initially begin production
on the Kronos mine as a two unit mine, the infrastructure will
be developed so as to facilitate expansion for up to four units
as demand warrants such increased production. The saleable
production from the mine is estimated to be 1.2 million
saleable tons annually. As and when the mine is expanded to four
units, production is estimated to double to approximately
2.4 million tons annually. The estimated total cost of
development of the Kronos underground mine, including the
planned expansion to four units, is approximately
$59 million. Capitalized development costs in 2010 were
$4.4 million.
Off-Balance
Sheet Arrangements
In the normal course of business, we are a party to certain
off-balance sheet arrangements. These arrangements include
guarantees and financial instruments with off-balance sheet
risk, such as surety bonds and performance bonds. No liabilities
related to these arrangements are reflected in our consolidated
balance sheet, and we do not expect any material adverse effects
on our financial condition, results of operations or cash flows
to result from these off-balance sheet arrangements.
Federal and state laws require us to secure certain long-term
obligations such as mine closure and reclamation costs and other
obligations. We typically secure these obligations by using
surety bonds, an off-balance sheet instrument. The use of surety
bonds is less expensive for us than the alternative of posting a
100% cash bond. To the extent that surety bonds become
unavailable, we would seek to secure our reclamation obligations
with letters of credit, cash deposits or other suitable forms of
collateral. We also post performance bonds to secure our
performance of various contractual obligations.
As of September 30, 2011, we had approximately
$16.5 million in surety bonds outstanding to secure the
performance of our reclamation obligations, which were supported
by approximately $4.0 million of cash posted as collateral.
As of September 30, 2011, we had approximately
$1.0 million of performance bonds outstanding, none of
which were secured by collateral.
Critical
Accounting Policies and Estimates
Our preparation of financial statements in conformity with GAAP
requires that we make estimates and assumptions that affect the
amounts reported in the consolidated financial statements and
accompanying notes. We base our judgments, estimates and
assumptions on historical information and other known factors
that we deem relevant. Estimates are inherently subjective as
significant management judgment is required regarding the
assumptions utilized to calculate accounting estimates. The most
significant areas requiring the use of management estimates and
assumptions relate to
units-of-production
amortization calculations, asset retirement obligations, useful
lives for depreciation of fixed assets and estimates of fair
values for asset impairment purposes. This section describes
those accounting policies and estimates that we believe are
critical to understanding our historical consolidated financial
statements and that we believe will be critical to understanding
our consolidated financial statements subsequent to this
offering.
Inventory
Inventory consists of coal that has been completely uncovered or
that has been removed from the pit and stockpiled for crushing,
washing or shipment to customers. Inventory also consists of
supplies, primarily spare parts and fuel. Inventory is valued at
the lower of average cost or market. The cost of coal inventory
includes labor, equipment operating expenses and certain
transportation and operating overhead.
Property,
Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures
that extend the useful lives of existing plant and equipment are
capitalized. Maintenance and repairs that do not extend the
useful life or increase
72
productivity are charged to operating expense as incurred. Plant
and equipment are depreciated principally on the straight-line
method over the estimated useful lives of the assets.
There are numerous uncertainties inherent in estimating
quantities of reserves, including many factors beyond our
control. Estimates of coal reserves necessarily depend upon a
number of variables and assumptions, any one of which may vary
considerably from actual results. These factors and assumptions
relate to: geological and mining conditions, which may not be
fully identified by available exploration data
and/or
differ from our experiences in areas where we currently mine;
the percentage of coal in the ground ultimately recoverable;
historical production from the area compared with production
from other producing areas; the assumed effects of regulation
and taxes by governmental agencies; and assumptions concerning
future coal prices, operating costs, capital expenditures,
severance and excise taxes and development and reclamation costs.
For these reasons, estimates of the recoverable quantities of
coal attributable to any particular group of properties,
classifications of reserves based on risk of recovery and
estimates of future net cash flows expected from these
properties as prepared by different engineers, or by the same
engineers at different times, may vary substantially. Actual
production, revenue and expenditures with respect to our
reserves will likely vary from estimates, and these variations
may be material. Certain account classifications within our
financial statements such as depreciation, depletion, and
amortization and certain liability calculations such as asset
retirement obligations may depend upon estimates of coal reserve
quantities and values. Accordingly, when actual coal reserve
quantities and values vary significantly from estimates, certain
accounting estimates and amounts within our consolidated
financial statements may be materially impacted. Coal reserve
values are reviewed annually, at a minimum, for consideration in
our consolidated financial statements.
Advance
Royalties
A substantial portion of our reserves are leased. Advance
royalties are advance payments made to lessors under terms of
mineral lease agreements that are recoupable through a reduction
in royalties payable on future production. Amortization of
leased coal interests is computed using the
units-of-production
method over estimated recoverable tonnage.
Long-Lived
Assets
We review the carrying value of long-lived assets and certain
identifiable intangibles whenever events or changes in
circumstances indicate that the carrying amount may not be
recoverable. Long-lived assets and certain intangibles are not
reviewed for impairment unless an impairment indicator is noted.
Several examples of impairment indicators include: a significant
decrease in the market price of a long-lived asset; a
significant adverse change in legal factors or in the business
climate that could affect the value of a long-lived asset; or a
significant adverse change in the extent or manner in which a
long-lived is being used or in its physical condition. The
foregoing factors are not all inclusive, and management must
continually evaluate whether other factors are present that
would indicate a long-lived asset may be impaired. The amount of
impairment is measured by the difference between the carrying
value and the fair value of the asset. We have not recorded an
impairment loss for any of the periods presented.
Asset
Retirement Obligation
Our asset retirement obligations primarily consist of spending
estimates for surface land reclamation and support facilities at
both surface and underground mines in accordance with applicable
reclamation laws in the U.S. as defined by each mining
permit. Asset retirement obligations are determined for each
mine using various estimates and assumptions including, among
other items, estimates of disturbed acreage as determined from
engineering data, estimates of future costs to reclaim the
disturbed acreage and the timing of these cash flows, discounted
using a credit-adjusted, risk-free rate. As changes in estimates
occur (such as mine plan revisions, changes in estimated costs,
or changes in timing of the reclamation activities), the
obligation and asset are revised to reflect the new estimate
after applying the appropriate credit-adjusted, risk-free rate.
If our assumptions do not materialize as expected, actual cash
expenditures and costs that we incur could be
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materially different than currently estimated. Moreover,
regulatory changes could increase our obligation to perform
reclamation and mine closing activities. Asset retirement
obligation expense for the year ended December 31, 2010 was
$2.4 million. See Note 13 to our consolidated
financial statements for additional details regarding our asset
retirement obligations.
Income
Taxes
We account for income taxes in accordance with accounting
guidance which requires deferred tax assets and liabilities be
recognized using enacted tax rates for the effect of temporary
differences between the book and tax bases of recorded assets
and liabilities. The guidance also requires that deferred tax
assets be reduced by a valuation allowance if it is more
likely than not that some portion or the entire deferred
tax asset will not be realized. In our evaluation of the need
for a valuation allowance, we take into account various factors,
including the expected level of future taxable income and
available tax planning strategies. If actual results differ from
the assumptions made in our evaluation, we may record a change
in valuation allowance through income tax expense in the period
such determination is made. We believe that the judgments and
estimates are reasonable; however, actual results could differ.
Revenue
Recognition and Accounts Receivable
Revenues from coal sales are recognized when title passes to the
customer as the coal is shipped. Some coal supply agreements
provide for price adjustments based on variations in quality
characteristics of the coal shipped. In certain cases, a
customers analysis of the coal quality is binding and the
results of the analysis are received on a delayed basis. In
these cases, we estimate the amount of the quality adjustment
and adjust the estimate to actual when the information is
provided by the customer. Historically such adjustments have not
been material.
Our accounts receivable are recorded at the invoiced amount. Our
sales are primarily to large utilities that have excellent
credit. We evaluate the need for an allowance for doubtful
accounts based on anticipated recovery and industry data. If any
of our customers were to encounter financial difficulties that
restricted their ability to make payments, our estimate of an
appropriate allowance for doubtful accounts could change. As of
December 31, 2010 and 2009, we had not established an
allowance for accounts receivable.
Stock-Based
Compensation
We account for stock-based compensation in accordance with the
authoritative guidance on stock compensation. Under the fair
value recognition provisions of this guidance, stock-based
compensation is measured at the grant date based on the fair
value of the award and is recognized as expense, net of
estimated forfeitures, over the requisite service period, which
is generally the vesting period of the respective award.
The primary stock-based compensation tool used by us for our
employee base is through awards of restricted stock. The
majority of restricted stock awards generally cliff vest after
two to three year of service. The fair value of restricted stock
is equal to the fair market value of our common stock at the
date of grant and is amortized to expense ratably over the
vesting period, net of forfeitures. Because our common stock is
not publicly traded, we must estimate the fair market value
based on multiple valuation methods. The valuations of our
common stock were determined in accordance with the guidelines
outlined in the American Institute of Certified Public
Accountants Practice Aid, Valuation of Privately-Held-Company
Equity Securities Issued as Compensation by a third-party
valuation specialist. The assumptions we use in the valuation
model are based on future expectations combined with management
judgment. In the absence of a public trading market, our board
of directors with input from management exercised significant
judgment and considered numerous objective and subjective
factors to determine the fair value of our common stock as of
the date of each option grant, including the following factors:
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our operating and financial performance;
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current business conditions and projections;
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the likelihood of achieving a liquidity event for the shares of
common stock underlying these restricted stock grants, such as
an initial public offering or sale of our company, given
prevailing market conditions;
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our stage of development;
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any adjustment necessary to recognize a lack of marketability
for our common stock;
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the market performance of comparable publicly traded
companies; and
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the U.S. and global capital market conditions.
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We granted restricted stock awards with the following grant date
fair values between January 1, 2009 and the date of this
prospectus:
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Number of
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Shares
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Underlying the
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Grant-Date
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Grant Date
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Award
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Fair Value
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January 2010
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18,500
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6.49
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August 2010
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16,650
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5.95
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June 2011
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83,250
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13.93
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September 2011
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9,250
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14.80
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The fair value of our common stock was determined by our Board
of Directors based on multiple valuation methodologies utilizing
both quantitative and qualitative factors. Significant factors
considered by our board of directors and the valuation
methodology used to determine the fair value of our common stock
at these grant dates include:
January
2010
In September 2009, we sold 1,387,500 shares of common stock
to our majority stockholder at $10.81 per share. As our
financial forecast and expected growth rate had not materially
changed from this date and the demand for Illinois Basin coal
remained strong, we utilized $10.81 was a reasonable
undiscounted fair value of our common stock for the restricted
stock grant made in January 2011. Through the use of a third
party specialist, a non-marketability discount of 40% was
derived due to the unlikely nature of a liquidity event
occurring in the near future, resulting in an overall fair value
of $6.49 per share.
August
2010
Between February 2010 and August 2010, the economic factors
impacting our business had not changed significantly, and, thus,
we assumed the undiscounted fair value of our common stock had
remained unchanged at $10.81 per share. Through the use of a
third party specialist, a non-marketability discount of 45% was
derived based on the likelihood of a liquidity event, resulting
in an overall fair value of $5.95 per share.
June
2011
Between September 2010 and June 2011, we experienced significant
growth in our business due primarily to two additional mines
commencing operations. In addition, due to the continued
strength in the coal markets during this period, we concluded
the likelihood of a liquidity event had increased in order to
support our future growth plans. In June 2011, we granted
restricted stock awards to certain executive and non-executive
employees. The undiscounted fair value of our common stock,
which totaled $17.41 per share, was determined by a third party
specialist based on both a market approach using the comparable
company method and an income approach using the discounted cash
flow method. Given a liquidity event was expected to occur
within approximately one year, a non-marketability discount of
20% was applied to determine an overall fair value per share.
Based on this valuation and the factors discussed above, the
overall fair value per share was determined to be $13.93.
75
September
2011
Between July 2011 and September 2011, our outlook on the
industry remained positive and the likelihood of a liquidity
event became more probable. In September 2011, a non-executive
employee was granted a restricted stock award. As our financial
forecasts and expectations for growth had not changed
significantly from June 2011, we concluded the undiscounted fair
value of our common stock had remained unchanged from our
previous grant at $17.41 per share. Given a liquidity event was
expected to occur within approximately six to nine months, a
non-marketability discount of 15% was determined by a third
party specialist and applied to determine an overall fair value
per share. Based on this valuation and the factors discussed
above, the overall fair value per share was determined to be
$14.80.
Stock compensation expense totaled $1.2 million,
$0.1 million, $0.1 million, $0.1 million and
$0.2 million for the nine months ended September 30,
2011 and 2010 and the years ended December 31, 2010, 2009,
and 2008, respectively. Stock compensation expense to be
recognized on non-vested restricted stock awards as of
September 30, 2011 was approximately $1.2 million.
New
Accounting Standards Issued and Adopted
In January 2010, the Financial Accounting Standards Board (the
FASB) issued accounting guidance that requires new
fair value disclosures, including disclosures about significant
transfers into and out of Level 1 and Level 2
fair-value measurements and a description of the reasons for the
transfers. In addition, the guidance requires new disclosures
regarding activity in Level 3 fair value measurements,
including a gross basis reconciliation. The new disclosure
requirements became effective for interim and annual periods
beginning January 1, 2010, except for the disclosure of
activity within Level 3 fair value measurements, which
became effective January 1, 2011. The new guidance did not
have an impact on our consolidated financial statements.
New
Accounting Standards Issued and Not Yet Adopted
In June 2011, the FASB amended requirements for the presentation
of other comprehensive income (loss), requiring presentation of
comprehensive income (loss) in either a single, continuous
statement of comprehensive income or on separate but consecutive
statements, the statement of operations and the statement of
other comprehensive income (loss). The amendment is effective
for fiscal years, and interim periods within those years,
beginning after December 15, 2011, or March 31, 2012
for us. The adoption of this guidance will not impact our
financial position, results of operations or cash flows and will
only impact the presentation of other comprehensive income
(loss) on the financial statements.
In May 2011, the FASB amended the guidance regarding fair value
measurement and disclosure. The amended guidance clarifies the
application of existing fair value measurement and disclosure
requirements. The amendment is effective for interim and annual
periods beginning after December 15, 2011, or
March 31, 2012 for us. Early adoption is not permitted. The
adoption of this amendment is not expected to materially affect
our consolidated financial statements.
Quantitative
and Qualitative Disclosures about Market Risk
We define market risk as the risk of economic loss as a
consequence of the adverse movement of market rates and prices.
We believe our principal market risks are commodity price risks
and interest rate risk.
Commodity
Price Risk
We sell most of the coal we produce under multi-year coal supply
agreements. Historically, we have principally managed the
commodity price risks from our coal sales by entering into
multi-year coal supply agreements of varying terms and
durations, rather than through the use of derivative
instruments. See Results of
Operations Factors that Impact our Business
for more information about our multi-year coal supply agreements.
Some of the products used in our mining activities, such as
diesel fuel, explosives and steel products for roof support used
in our underground mining, are subject to price volatility.
Through our suppliers, we utilize forward purchases to manage a
portion of our exposure related to diesel fuel volatility. A
hypothetical increase
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of $0.10 per gallon for diesel fuel would have reduced net
income by $0.6 million for the year ended December 31,
2010. A hypothetical increase of 10% in steel prices would have
reduced net income by $0.7 million for the year ended
December 31, 2010. A hypothetical increase of 10% in
explosives prices would have reduced net income by
$1.1 million for the year ended December 31, 2010.
Interest
Rate Risk
We have exposure to changes in interest rates on our
indebtedness associated with our Senior Secured Credit Facility.
In 2011, we entered into an interest rate swap agreement,
effective January 1, 2012, to hedge our exposure to rising
interest rates. Pursuant to this agreement, we are required to
make payments at a fixed interest rate of 2.89% to the
counterparty on an initial notional amount of $47.5 million
(amortizing thereafter) in exchange for receiving variable
payments based on the greater of 1.0% or the three-month LIBOR
rate, which was 0.37433% as of September 30, 2011. This
agreement has quarterly settlement dates and matures on
February 9, 2016.
A hypothetical increase or decrease in interest rates by 1%
would have changed our interest expense by $0.7 million for
the nine months ended September 30, 2011, $1.7 million
for the year ended December 31, 2010 and $1.9 million
for the year ended December 31, 2009.
Seasonality
Our business has historically experienced some variability in
its results due to the effect of seasons. Demand for coal-fired
power can increase due to unusually hot or cold weather as power
consumers use more air conditioning or heating. Conversely, mild
weather can result in softer demand for our coal. Adverse
weather conditions, such as floods or blizzards, can impact our
ability to mine and ship our coal and our customers
ability to take delivery of coal.
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THE COAL
INDUSTRY
Overview
Coal is an abundant natural resource that serves as the primary
fuel source for the generation of electric power and as a key
ingredient in the production of steel. According to the World
Coal Association (WCA), approximately 42% of the
worlds electricity generation and approximately 68% of
global steel production is fueled by coal. Global hard coal and
brown coal production totaled more than 7.5 billion tons in
2009 according to the WCA.
Coal is the most abundant fossil fuel in the United States. The
EIA estimates that there are approximately 261 billion tons
of recoverable coal reserves in the United States, more than in
any other country, which represents over 200 years of
domestic coal supply based on current production rates. The
United States is second only to China in annual coal production,
producing approximately 1.1 billion tons in 2010, according
to the EIA.
Coal is ranked by heat content, with anthracite, bituminous,
subbituminous and lignite coal representing the highest to
lowest carbon and heat ranking, respectively. Coal is also
characterized by end use market as either thermal coal or
metallurgical coal. Thermal coal is used by utilities and
independent and industrial power producers to generate
electricity
and/or steam
or heat and metallurgical coal is used by steel companies to
produce metallurgical coke for use in the steel making process.
Important factors in evaluating thermal coal quality are its Btu
or heat content, sulfur, ash and moisture content, while
metallurgical coal is evaluated on the additional metrics of
contained volatile matter and coking characteristics, including
expansion, plasticity and strength.
Electricity generation accounts for 68% of global coal
consumption (2008) while industrial consumption accounts
for nearly 36% of global coal production. Thermal coals
abundance and relatively wide in-situ global resource
distribution have contributed to its relative ease of
availability and competitive cost versus other electricity
generating fuels. Global thermal coal trade is expected to grow
to 1.1 billion annual tons in 2016 from 850 million
tons in 2010, driven largely by increased electricity demand in
the developing world, a significant portion of which is expected
to be supplied by coal-fired power plants. The
U.S. domestic thermal coal market consumption, which
accounts for close to 90% of U.S. domestic coal production,
is expected to grow by 25% by 2035 from 2009 levels, according
to the EIA, and coal-fired electricity generation is expected to
continue to be the largest single fuel source of
U.S. electricity (43% in 2035).
Recent
Trends
U.S. and international coal market supply, demand and
prices are influenced by many factors including relative coal
quality, available capacity and costs of transportation and
related infrastructure (such as rail, barge and river or export
terminals), mining production costs, and the relative costs of
generating electricity with competing fuels (natural gas, fuel
oil, hydro, nuclear and renewable such as wind and solar power).
U.S. domestic thermal coal demand and global thermal coal
demand are strongly correlated with the pace of domestic and
global economic growth.
Our operations are located in the Western Kentucky region of the
Illinois Basin and we produce thermal coal for consumption by
electricity generators operating scrubbed power plants in the
Eastern United States and along the Mississippi River and for
international coal consumers who are capable of utilizing our
coal. We compete with other producers of similar quality coal in
the Illinois Basin, as well as with producers of other thermal
coal in other U.S. production regions including the Powder
River Basin and Northern, Central and Southern Appalachia.
According to the EIA, the U.S. coal industry produced
approximately 1.1 billion tons of coal in 2010, a
substantial majority of which was sold by U.S. coal
producers to operators of electricity generation plants.
Coal-fired electricity generation is the largest component of
total world electricity generation. The following market
dynamics and trends currently impact thermal coal consumption
and production in the United States and are reshaping
competitive advantages for coal producers.
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Stable long-term outlook for U.S. thermal coal
market. According to the EIA, coal-fired
electricity generation accounted for approximately 45% of all
electricity generation in the United States in 2010. Coal
continues to be the lowest cost fossil fuel source of energy for
electric power generation. Despite recent increases in
generation from natural gas, as well as federal and state
subsidies for the construction and
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operation of renewable energy, the EIA projects that generation
from coal will increase by 25% from 2009 to 2035 and that
coal-fired generation will remain the largest single source of
electricity generation in 2035.
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Increasing demand for coal produced in the Illinois
Basin. According to Wood Mackenzie, a leading
commodities consultancy, demand for coal produced from the
Illinois Basin is expected to grow by 69% from 2009 through 2015
and by 126% from 2009 through 2030. We believe this is due to a
combination of factors including:
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Significant expansion of scrubbed coal-fired electricity
generating capacity. The EIA forecasts a 32%
increase in FGD installed on the coal-fired generation fleet
from 168 gigawatts in 2009 to 222 gigawatts, or 70% of all
U.S. coal-fired capacity in the electric sector, by 2035,
as electricity generation operators invest in retrofit emissions
reduction technology to comply with new EPA regulations under
the Cross-State Air Pollution Rule and the proposed Utility
Boiler MACT regulations. Illinois Basin coal generally has a
higher sulfur content per ton than coal produced in other
regions. However, we believe that FGD utilization will enable
operators to use the most competitively priced coal (on a
delivered cents per million Btu basis) irrespective of sulfur
content, and thus lead to a strong increase in demand for
Illinois Basin coal.
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Declines in Central Appalachian thermal coal
production. Wood Mackenzie forecasts that
production of Central Appalachian thermal coal will continue to
decline, falling from 128 million tons in 2010 to
64 million tons in 2015, due to reserve depletion,
regulatory-driven decreases in Central Appalachian surface
thermal coal production and more difficult geological
conditions. These factors are expected to result in
significantly higher mining costs and prices for Central
Appalachian thermal coal. We believe this will lead to an
increase in demand for thermal coal from the Illinois Basin due
to its comparatively lower delivered cost to the major Eastern
U.S. utilities who are currently the principal users of
thermal coal from Central Appalachia.
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Growing demand for seaborne thermal
coal. Global trade in thermal coal accounted for
nearly 70% of all global coal exports in 2010 and is projected
to rise from 850 million tons in 2010 to 1.1 billion
tons by 2016. We believe that limitations on existing global
export coal supply, infrastructure constraints, relative
exchange rates, coal quality and cost structure could create
significant thermal coal export opportunities for U.S. coal
producers, including Illinois Basin coal producers, particularly
those similar to us with transportation access to the
Mississippi River and to rail connecting to Louisiana export
terminals. In addition, we believe that certain domestic users
of U.S. thermal coal will need to seek alternative sources
of domestic supply as an increasing amount of domestic coal is
sold in global export markets.
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Coal
Consumption and Demand
The vast majority of thermal coal consumed in the United States
is used to generate electricity, with the balance used by a
variety of industrial users to heat and power a range of
manufacturing and processing facilities. Metallurgical coal is
primarily used in steelmaking blast furnaces. In 2009,
coal-fired power plants produced approximately 45% of all
electric power generation, more than natural gas and nuclear,
the two next largest domestic fuel sources, combined. Thermal
coal used by electric utilities and other power producers
accounted for 976 million tons or 93.1% of total coal
consumption in 2010, an increase of 42 million tons or 4.5%
over 2009 consumption levels.
Total coal consumption in the United States in 2010 increased by
approximately 51 million tons, or 5.1%, from 2009 levels.
The rise in U.S. domestic coal consumption during 2010 was
largely a function of the recovering economic growth following
the
2008-2009
recession and the rebound in industrial electricity consumption
and domestic steel making output. In 2010, electricity
consumption in the United States increased approximately 4.3%
from 2009, and the average growth rate in the decade prior to
2010 was approximately 0.7% per year according to EIA estimates.
Because coal-fired generation is used in most cases to meet base
load electricity demand requirements, coal consumption has
generally grown at the pace of electricity demand growth. Among
coals primary advantages are its relatively low cost and
ease of transportation ability compared to other fuels used to
generate electricity. According to the EIA, coal is expected to
remain the dominant energy source for electric power generation
for the foreseeable future.
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Over the long term, the EIA forecasts in its 2011 reference case
that total coal consumption will grow by approximately 32%
through 2035, primarily due to steady increases in coal-fired
electric power generation and the introduction of
coal-to-liquids
plants.
The following table sets forth historical and forecasted
U.S. coal consumption as aggregated by the EIA for the
periods indicated.
U.S. Coal
Consumption by Sector
(tons in millions)
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Actual
|
|
|
Actual
|
|
|
Forecast
|
|
|
Forecast
|
|
|
Forecast
|
|
|
Forecast
|
|
|
Forecast
|
|
|
|
2008
|
|
|
2009
|
|
|
2015
|
|
|
2020
|
|
|
2025
|
|
|
2030
|
|
|
2035
|
|
|
Electric Power
|
|
|
1,041
|
|
|
|
937
|
|
|
|
928
|
|
|
|
989
|
|
|
|
1,066
|
|
|
|
1,094
|
|
|
|
1,119
|
|
Industrial
|
|
|
54
|
|
|
|
45
|
|
|
|
49
|
|
|
|
49
|
|
|
|
48
|
|
|
|
48
|
|
|
|
47
|
|
Steel Production
|
|
|
22
|
|
|
|
15
|
|
|
|
22
|
|
|
|
22
|
|
|
|
21
|
|
|
|
20
|
|
|
|
18
|
|
Residential/Commercial
|
|
|
4
|
|
|
|
3
|
|
|
|
3
|
|
|
|
3
|
|
|
|
3
|
|
|
|
3
|
|
|
|
3
|
|
Coal-to-Liquids
|
|
|
|
|
|
|
|
|
|
|
11
|
|
|
|
13
|
|
|
|
44
|
|
|
|
82
|
|
|
|
128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total U.S. Consumption
|
|
|
1,121
|
|
|
|
1,000
|
|
|
|
1,013
|
|
|
|
1,076
|
|
|
|
1,182
|
|
|
|
1,247
|
|
|
|
1,315
|
|
Source: EIA 2011 Energy Outlook
Illinois
Basin Coal Market
We market and deliver our coal to electricity generating
customers both in close proximity to our production area in
Western Kentucky along the Green and Ohio Rivers and to
customers along the Mississippi River and in the Southeastern
United States. In 2010, 49.1% of the electricity in our market
area was generated by coal-fired power plants. The table below
compares the total electricity generation in our market area to
that which was coal-fired for 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 Total
|
|
|
|
|
|
|
|
|
|
Electricity
|
|
|
2010 Coal-Fired Electricity Generation
|
|
|
|
Generation
|
|
|
|
|
|
Percent of
|
|
|
|
GWh
|
|
|
GWh
|
|
|
Total
|
|
|
Total-Our Primary Market Area(1)
|
|
|
2,765,970
|
|
|
|
1,357,670
|
|
|
|
49.1
|
%
|
Total United States
|
|
|
4,120,028
|
|
|
|
1,850,750
|
|
|
|
44.9
|
%
|
|
|
|
(1) |
|
Any state east of the Mississippi River, as well as Minnesota,
Iowa, Missouri, Arkansas and Louisiana. |
Source: EIA
The number of new coal-fired power plants in the Illinois Basin
coal market is expected to increase, as eight new plants have
recently been built or are permitted and under construction. The
table below represents the EIA Form 860 information
and/or
public filing data on these new and under construction
coal-fired units, which represent over 5,000mw of nameplate
capacity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Under
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Construction
|
|
MW
|
|
|
Effective
|
Utility Name
|
|
Plant Name
|
|
State
|
|
County
|
|
Region
|
|
Nameplate
|
|
|
Year
|
|
Virginia Electric & Power Co.
|
|
Virginia City Hybrid Energy Center
|
|
VA
|
|
Wise
|
|
RFC
|
|
|
585
|
|
|
2012
|
Duke Energy Carolinas LLC
|
|
Cliffside
|
|
NC
|
|
Cleveland
|
|
SERC
|
|
|
800
|
|
|
2011
|
Duke Energy Indiana Inc.
|
|
Edwardsport (IGCC)
|
|
IN
|
|
Knox
|
|
RFC
|
|
|
618
|
|
|
2011
|
Cash Creek Generating LLC
|
|
Cash Creek (Coal Gasification)
|
|
KY
|
|
Henderson
|
|
SERC
|
|
|
640
|
|
|
2011
|
GenPower
|
|
Longview Power LLC
|
|
WV
|
|
Monongalia
|
|
RFC
|
|
|
695
|
|
|
2011
|
Louisiana Gas & Electric
|
|
Trimble County
|
|
KY
|
|
Trimble
|
|
SERC
|
|
|
834
|
|
|
2010
|
City Utilities of Springfield
|
|
Southwest Power Station
|
|
MO
|
|
Greene
|
|
SERC
|
|
|
300
|
|
|
2010
|
Dynegy Services Plum Point Inc.
|
|
Plum Point Energy Station
|
|
AR
|
|
Mississippi
|
|
SERC
|
|
|
665
|
|
|
2010
|
Source: EIA
80
More importantly, the progressive tightening by the EPA of
SO2,
NOx and other hazardous air pollutant emissions standards from
coal-fired electricity generation plants is expected to result
in additional significant increases in the number of generating
stations retrofitted with FGD systems.
U.S.
Scrubber Market
The 1990 amendments to the Clean Air Act imposed progressively
stringent regulations on the emissions of
SO2
and NOx. Among the coal-fired electricity generation
industrys response to these regulations was the
development of emission control technologies to reduce
SO2
emissions released in the burning of coal, such as FGD systems,
also known as scrubbers. Scrubbers have the
additional benefit of being able to reduce mercury emissions,
which are soon to be restricted under the EPAs hazardous
air pollutants regulations.
To implement requirements under the Clean Air Act, in July 2011,
the EPA adopted the CSAPR (aimed at
SO2
and NOx). In December 2011, the U.S. Court of Appeals for
the District of Columbia Circuit issued a ruling to stay the
CSAPR pending judicial review. The EPA is also presently
developing additional rules to further reduce the release of
certain combustion by-product emissions from fossil fuel power
plants. These rules include the proposed Utility Boiler MACT
that would regulate the emission of other air pollutants,
including mercury and other metals, fine particulates, and acid
gases such as hydrogen chloride (HCl).
To comply with the expected tightening of emissions limitations,
operators of coal-fired electricity generation have increasingly
invested in FGD, selective and non-selective catalytic reduction
systems and other advanced control technologies at their large,
base load power plants. 199gw of the current 316gw of
U.S. coal-fired generation is presently equipped with FGD
emissions systems. We believe that with the implementation of
the CSAPR and MACT, new FGD systems will likely be installed on
additional coal-fired generation increasing the total amount of
generation capacity to approximately 70% of all
U.S. capacity in the electric sector capacity by 2035.
Today, the number of scrubbers being installed at coal-fired
power plants across the United States is growing, and the
operating and economic profile use of this technology has become
well understood and broadly applied. We expect that the
continuation of this trend will substantially increase the
demand for higher sulfur coal given the competitive cost of
Illinois Basin coal, and will expand the competitive reach of
our coal and our primary market area.
The following table contains Wood Mackenzies forecasts of
additional generation capacity by installing and utilizing FGD
units and the related affected coal consumption potential from
2010 through 2014. The scrubbed generation unit additions are
expected to impact over 250 million tons of coal
consumption at these units which may position higher sulfur coal
from the Illinois Basin to effectively compete for a greater
share of supply to these units.
Projected
Affected Tons Due to Announced Scrubbing
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
|
Actual
|
|
|
Forecast
|
|
|
Forecast
|
|
|
Forecast
|
|
|
Forecast
|
|
|
MW Scrubbed (U.S. Total)
|
|
|
37,448
|
|
|
|
10,629
|
|
|
|
9,940
|
|
|
|
11,987
|
|
|
|
9,121
|
|
Coal Tons Affected (Million Tons)
|
|
|
120
|
|
|
|
34
|
|
|
|
32
|
|
|
|
38
|
|
|
|
29
|
|
Source: Wood Mackenzie Illinois Basin Market Outlook, March
2011
Wood Mackenzie forecasts that the U.S. domestic electricity
generation coal consumption will grow from a projected
975 million tons in 2011 to 985 million tons by 2015.
More importantly, the Wood Mackenzie forecast projects Illinois
Basin coal production growth from 114 million tons in 2011
to 167 million tons by 2015 (43% growth) and then to over
200 million tons by 2020.
81
Long-Term
U.S. Thermal Coal Outlook Fall 2011: Summary Table
of Key Data
(in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
2020
|
|
|
2025
|
|
|
2030
|
|
|
Supply (Mst)
|
|
|
1,112
|
|
|
|
1,109
|
|
|
|
1,113
|
|
|
|
1,108
|
|
|
|
1,145
|
|
|
|
1,139
|
|
|
|
1,179
|
|
|
|
1,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Powder River Basin
|
|
|
467
|
|
|
|
487
|
|
|
|
483
|
|
|
|
486
|
|
|
|
508
|
|
|
|
481
|
|
|
|
508
|
|
|
|
552
|
|
Central Appalachia
|
|
|
115
|
|
|
|
89
|
|
|
|
76
|
|
|
|
64
|
|
|
|
64
|
|
|
|
46
|
|
|
|
56
|
|
|
|
71
|
|
Illinois Basin
|
|
|
117
|
|
|
|
130
|
|
|
|
144
|
|
|
|
157
|
|
|
|
167
|
|
|
|
204
|
|
|
|
216
|
|
|
|
224
|
|
Northern Appalachia
|
|
|
116
|
|
|
|
121
|
|
|
|
129
|
|
|
|
134
|
|
|
|
136
|
|
|
|
132
|
|
|
|
125
|
|
|
|
124
|
|
Metallurgical (not including Thermal Cross Over)
|
|
|
86
|
|
|
|
84
|
|
|
|
82
|
|
|
|
69
|
|
|
|
70
|
|
|
|
81
|
|
|
|
87
|
|
|
|
93
|
|
Imports
|
|
|
10
|
|
|
|
8
|
|
|
|
5
|
|
|
|
3
|
|
|
|
3
|
|
|
|
5
|
|
|
|
5
|
|
|
|
5
|
|
Other (including Refuse or Petcoke)
|
|
|
201
|
|
|
|
190
|
|
|
|
195
|
|
|
|
196
|
|
|
|
197
|
|
|
|
190
|
|
|
|
131
|
|
|
|
171
|
|
Stockpile Increase (Decrease)
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Demand (Mst)
|
|
|
1,154
|
|
|
|
1,109
|
|
|
|
1,113
|
|
|
|
1,108
|
|
|
|
1,145
|
|
|
|
1,139
|
|
|
|
1,179
|
|
|
|
1,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity Generation
|
|
|
975
|
|
|
|
942
|
|
|
|
942
|
|
|
|
967
|
|
|
|
985
|
|
|
|
954
|
|
|
|
837
|
|
|
|
794
|
|
Industrial
|
|
|
59
|
|
|
|
52
|
|
|
|
51
|
|
|
|
52
|
|
|
|
52
|
|
|
|
53
|
|
|
|
54
|
|
|
|
54
|
|
Thermal Export
|
|
|
33
|
|
|
|
32
|
|
|
|
38
|
|
|
|
21
|
|
|
|
38
|
|
|
|
52
|
|
|
|
200
|
|
|
|
299
|
|
Metallurgical Demand (includes Thermal Cross Over)
|
|
|
86
|
|
|
|
84
|
|
|
|
82
|
|
|
|
69
|
|
|
|
70
|
|
|
|
81
|
|
|
|
87
|
|
|
|
93
|
|
Source: Wood Mackenzie Long Term US Thermal Coal Market
Outlook, October 2011
Wood Mackenzie estimates that demand for Illinois Basin coal
will grow at a compound annual rate of 3.7%, taking total
consumption from 114 million tons in 2011 to more than
225 million tons by 2030. This is compared to total
U.S. coal production, which Wood Mackenzie estimates will
grow at a compound annual rate of 0.2% over the same period.
Importantly, Illinois Basin coal production is projected to grow
more sharply over the
2010-2020
period (6.3% CAGR) than over the latter part of the
20-year
projection period.
Source: Wood Mackenzie
Global
Thermal Coal Markets
Global coal production accounted for 30% of global primary
energy consumption in 2010, according to BP.
82
2009
Global Primary Energy Consumption by Fuel
Source: BP Statistical Review of World Energy, June 2011
Thermal coal fueled 44% of electricity generation in 2007 and is
projected by EIA to fuel 43% of world electricity generation in
2035. Coals relative abundance, wide distribution,
competitive pricing and favorable transportation profile has
facilitated its global adoption as a reliable electricity
generation fuel. The rapid industrialization of the emerging
Asian economies, particularly China and India, are supporting
forecasts for significant increases in seaborne thermal coal
trade. In 2010, Asia accounted for 66% of world thermal coal
imports.
The Australian Bureau of Agricultural and Resource Economics and
Sciences (ABARES) projects world thermal coal trade will grow by
4% annually to 1.1 billion tons in 2016, with Asia
accounting for more than 717 million tons of import demand,
up from 562 million tons in 2010.
In the Atlantic thermal coal market, European Union and other
European coal imports are projected to rise from
207 million tons in 2010 to 246 million tons by 2016.
We believe the projected robust growth in global thermal coal
trade to satisfy growing demand for electricity generation will
create substantial opportunities for U.S. coal producers
with competitive transportation advantages to profitably export
thermal coal.
The Illinois Basin coal production region is strategically well
positioned with access to the Green, Ohio and Mississippi River
systems to deliver coal to New Orleans or Port of Mobile coal
export terminals for delivery of coal to growing Atlantic and
Pacific import coal consumers.
Costs and
Pricing Trends
Coal prices are influenced by a number of factors and vary
materially by region. As a result of these regional
characteristics, prices of coal by product type within a given
major coal producing region tend to be relatively consistent
with each other. The price of coal within a region is influenced
by market conditions, coal quality, transportation costs
involved in moving coal from the mine to the point of use and
mine operating costs. For example, higher carbon and lower ash
content generally result in higher prices, and higher sulfur and
higher ash content generally result in lower prices within a
given geographic region.
The cost of coal at the mine is also influenced by geologic
characteristics such as seam thickness, overburden ratios and
depth of underground reserves. It is generally cheaper to mine
coal seams that are thick and located close to the surface than
to mine thin underground seams. Within a particular geographic
region,
83
underground mining is generally more expensive than surface
mining. This is due to typically higher capital costs, including
costs for construction of extensive ventilation systems, and
higher per unit labor costs arising from lower productivity
associated with underground mining.
During the past decade, the price of coal has fluctuated like
any commodity as a result of changes in supply and demand. For
example, when coal supplies declined from 2003 to part of 2006
and subsequently for a short time in 2007 and 2008, the prices
for coal reached record highs in the United States. The
increased worldwide demand for coal is being driven by higher
prices for oil, together with overseas economic expansion in
countries such as China and India who rely heavily on coal-fired
electricity generation. At the same time, infrastructure,
weather-related production interruptions and supply restrictions
on exports from China and Indonesia have contributed to a
tightening of worldwide thermal coal supply, affecting global
prices of coal.
Coal
Characteristics
The quality of coal is measured primarily by its heat content in
British thermal units per pound (Btu/lb). However,
sulfur, ash and moisture content, and volatile content and
coking characteristics are also important variables in the
ranking and marketing of coal. These characteristics help
producers determine the best end use of a particular type of
coal. The following is a description of these general coal
characteristics:
Heat Value. In general, the carbon content of
coal supplies most of its heating value, but other factors also
influence the amount of energy it contains per unit of weight.
Coal with higher heat value is priced higher than coal with
lower heat value because less coal is needed to generate the
same quantity of electric power. Coal is generally classified
into four categories, ranging from lignite, subbituminous,
bituminous and anthracite, reflecting the progressive response
of individual deposits of coal to increasing heat and pressure.
Anthracite is coal with the highest carbon content and,
therefore, the highest heat value, nearing 15,000 Btus/lb.
Bituminous coal, used primarily to generate electricity and to
make coke for the steel industry, has a heat value ranging
between 10,500 and 15,500 Btus/lb. Subbituminous coal ranges
from approximately 8,000 to 9,500 Btus/lb and is generally used
for electric power generation. Finally, lignite coal is a
geologically young coal and has the lowest carbon content, with
a heat value ranging between approximately 4,000 and 8,000
Btus/lb.
Sulfur Content. When coal is burned,
SO2
and other air emissions are released. Federal and state
environmental regulations limit the amount of
SO2
that may be emitted as a result of combustion. Following the
implementation of the Clean Air Act Title IV amendments,
coals sulfur content could be categorized as
compliance or non-compliance. Compliance
coal is coal that emits less than 1.2 lbs of
SO2
per million Btu and complies with applicable Clean Air Act
environmental regulations without the use of scrubbers. Higher
sulfur coal can be burned in utility plants fitted with
sulfur-reduction technology. Coal-fired power plants can also
comply with
SO2
emission regulations by utilizing coal with sulfur content below
1.2 lbs. per million Btu
and/or
purchasing emission allowances on the open market.
Ash. Ash is the inorganic residue remaining
after the combustion of coal. Ash content is an important
characteristic of coal because it impacts boiler performance,
and electric generating plants must handle and dispose of ash
following combustion. The composition of the ash, including the
proportion of sodium oxide and fusion temperature, help
determine the suitability of the coal to end users.
Moisture. Moisture content of coal varies by
the type of coal, the region where it is mined and the location
of the coal within a seam. In general, high moisture content
decreases the heat value and increases the weight of the coal,
thereby making it more expensive to transport. Moisture content
in coal, on an as-sold basis, can range from approximately 2% to
over 15% of the coals weight.
Other. Users of metallurgical coal measure
certain other characteristics, including fluidity, swelling
capacity and volatility to assess the strength of coke (which is
the solid fuel obtained from coal after removal of volatile
components) produced from coal or the amount of coke that
certain types of coal will yield. These coking characteristics
may be important elements in determining the value of the
metallurgical coal. We do not produce metallurgical coal or own
any metallurgical coal reserves at this time.
84
U.S. Coal
Producing Regions
Coal is mined from coal basins throughout the United States,
with the major production centers located in three regions:
Appalachia, the Interior and the Western region. Within those
three regions, the major producing centers are Northern and
Central Appalachia, the Illinois Basin in the Interior region,
and the Powder River Basin in the Western region. The type,
quality and characteristics of coal vary by, and within each,
region.
Appalachian Region. The Appalachian region is
divided into the Northern, Central and Southern regions, with
the Northern and Central areas being the largest coal producers
in the region. Northern Appalachia includes Ohio, Pennsylvania,
Maryland and northern West Virginia. The area includes reserves
of bituminous coal with heat content ranging from 10,300 to
13,000 Btu/lb) and sulfur content ranging from 1.0% to 2.0%.
Coal produced in Northern Appalachia is marketed primarily to
electric utilities, industrial consumers and the export market,
with some metallurgical coal marketed to steelmakers.
Central Appalachia includes eastern Kentucky, southern West
Virginia, Virginia and northern Tennessee. The area includes
reserves of bituminous coal with a typical heat content of
12,000 Btu/lb or greater and sulfur content ranging from 0.5% to
1.5%. Coal produced in Central Appalachia is marketed primarily
to electric utilities, with metallurgical coal marketed to
steelmakers. The combination of reserve depletion and increasing
regulatory enforcement, mining costs and geologic complexity in
Central Appalachia is expected to lead to substantial production
declines over the long term. In fact, actual production has
declined from approximately 257 million tons in 2000 to
186 million tons in 2010. In addition, the widespread
installation of scrubbers is expected to enable higher sulfur
coal from Northern Appalachia and the Illinois Basin to displace
coal from Central Appalachia.
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Interior Region. The major coal producing
center of the Interior region is the Illinois Basin, which
includes Illinois, Indiana and western Kentucky. The area
includes reserves of bituminous coal with a heat content ranging
from 10,100 to 12,600 Btu/lb and sulfur content ranging from
1.0% to 4.3%. Despite its high sulfur content, coal from the
Illinois Basin can generally be used by some electric power
generation facilities that have installed pollution control
devices, such as scrubbers, to reduce emissions. Most of the
coal produced in the Illinois Basin is used in the generation of
electricity, with small amounts used in industrial applications.
The EIA forecasts that production of high sulfur coal in the
Illinois Basin, which has trended down since the early 1990s
when many coal-fired plants switched to lower sulfur coal to
reduce
SO2
emissions after the passage of the Title IV amendments to
the Clean Air Act, will significantly rebound as existing
coal-fired capacity is retrofitted with scrubbers and new
coal-fired capacity with scrubbers is added.
Western Region. The Western United States
region includes, among other areas, the Powder River Basin, the
Western Bituminous region (including the Uinta Basin) and the
Four Corners area. The Powder River Basin, the Western
Regions largest coal producing area, is located in Wyoming
and Montana. This area produces subbituminous coal with sulfur
content ranging from 0.2% to 0.9% and heat content ranging from
8,000 to 9,500 Btu/lb. After strong growth in production over
the past 20 years, growth in demand for Powder River Basin
coal is expected to moderate in the future due to the slowing
demand for low sulfur, low Btu coal as more scrubbers are
installed and concerns about increases in rail transportation
rates and rising operating costs grow.
Mining
Methods
Coal is mined utilizing underground or surface mining methods
depending upon the geology and most economical means of coal
recovery.
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 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, and shuttle cars are generally used to transport
coal to a conveyor belt for subsequent delivery to the surface.
Once mining has advanced to the end of a panel, retreat mining
may begin to mine as much coal as can be safely and feasibly be
mined from each of the pillars created.
The other underground mining method commonly used in the United
States is the longwall mining method. 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. We currently do not, nor do we plan to
in the near future, produce coal using longwall mining
techniques.
Surface
Mining
Surface mining produces the majority of U.S. coal output,
accounting for approximately 69% of U.S. production in
2010. Surface mining is generally used when coal is found
relatively close to the surface, when multiple seams in close
vertical proximity are being mined or when conditions otherwise
warrant. Surface mining involves the removal of overburden
(earth and rock covering the coal) with heavy earth moving
equipment and explosives, loading out the coal, replacing the
overburden and topsoil after the coal has been excavated and
reestablishing approximate original counter, vegetation and
plant life, and making other improvements that have local
community and environmental benefit. Overburden is typically
removed at mines using explosives in combination with large,
rubber-tired diesel loaders or more efficient draglines. Surface
mining can recover nearly 90% of the coal from a reserve deposit.
There are four primary surface mining methods in use in
Appalachia and the Illinois Basin: area, contour, auger and
highwall. Area mines are surface mines that remove shallow coal
over a broad area where the land is relatively flat. After the
coal has been removed, the overburden is placed back into the
pit. Contour mines are surface mines that mine coal in steep,
hilly or mountainous terrain. A wedge of overburden is removed
along the coal outcrop on the side of a hill, forming a bench at
the level of the coal. After the coal is
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removed, the overburden is placed back on the bench to return
the hill to its natural slope. Highwall mining is a form of
mining in which a remotely controlled continuous miner extracts
coal and conveys it via augers, belt or chain conveyors to the
outside. The cut is typically a rectangular, horizontal cut from
a highwall bench, reaching depths of several hundred feet or
deeper. A highwall is the unexcavated face of exposed overburden
and coal in a surface mine. Mountaintop removal mines are
special area mines not present in the Illinois Basin that are
used where several thick coal seams occur near the top of a
mountain. Large quantities of overburden are removed from the
top of the mountains, and this material is used to fill in
valleys next to the mine.
Transportation
The U.S. coal industry is dependent on the availability of
a transportation network connecting the mining regions to the
U.S. and international distribution markets. Most
U.S. coal is transported via railroad and barge, though
trucks and conveyor belts are used to move coal over shorter
distances. The method of transportation and the delivery
distance can impact the total cost of coal delivered to the
consumer.
Coal used for domestic consumption is generally sold
free-on-board
at the mine, which means the purchaser normally bears the
transportation costs. Transportation can be a large component of
a coal purchasers total delivered cost. Although the
purchaser typically pays the freight, transportation costs are
important to coal mining companies because the purchaser may
choose a supplier largely based on the total delivered cost of
coal, which includes the cost of transportation.
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BUSINESS
Overview
About the
Company
We are a diversified producer of low chlorine, high sulfur
thermal coal from the Illinois Basin with both surface and
underground mines. We market our coal primarily to electric
utility companies as fuel for their steam-powered generators.
Based on 2010 production, we are the sixth largest producer in
the Illinois Basin and the second largest in Western Kentucky.
We were formed in 2006 to acquire and develop a large coal
reserve holding. We commenced production in the second quarter
of 2008 and currently operate six mines, including four surface
and two underground, and are seeking permits for four additional
mines. We control approximately 319 million tons of proven
and probable coal reserves. Our reserves and operations are
located in the Western Kentucky counties of Ohio, Muhlenberg,
Union and Webster. We also own and operate three coal processing
plants which support our mining operations. The location of our
coal reserves and operations, adjacent to the Green and Ohio
Rivers, together with our river dock coal handling and rail
loadout facilities, allow us to optimize our coal blending and
handling, and provide our customers with rail, barge and truck
transportation options. From our reserves, we mine coal from
multiple seams which, in combination with our coal processing
facilities, enhances our ability to meet customer requirements
for blends of coal with different characteristics.
We are majority - owned by Yorktown. After giving
effect to this offering, we will continue to be
majority - owned by Yorktown. In addition, Yorktown
is represented on our board by Bryan H. Lawrence, founder and
principal of Yorktown Partners LLC. As a result, Yorktown has,
and can be expected to have, a significant influence in our
operations, in the outcome of stockholder voting concerning the
election of directors, the adoption or amendment of provisions
in our charter and bylaws, the approval of mergers, and other
significant corporate transactions. See Risk
Factors Yorktown will continue to have significant
influence over us, including control over decisions that require
the approval of stockholders, which could limit your ability to
influence the outcome of key transactions, including a change of
control.
Our revenue has increased from zero in 2007 to
$220.6 million in 2010, which we achieved despite a period
of recession-driven declines in U.S. demand for coal and a
challenging environment in the credit markets. For the year
ended December 31, 2010, we generated operating income of
$19.2 million and Adjusted EBITDA of $41.1 million.
Our operating income and Adjusted EBITDA for the nine months
ended September 30, 2011 were $6.4 million and
$32.1 million, respectively. Adjusted EBITDA is a non-GAAP
financial measure which represents net income (loss) before net
interest expense, income taxes, depreciation, depletion and
amortization, non-cash stock compensation expense, non-cash
charges related to non-resource notes, and gain on
extinguishment of debt. Please see Prospectus
Summary Summary Historical and Unaudited Pro Forma
Consolidated Financial and Operating Data for a
reconciliation of Adjusted EBITDA to net income (loss).
We are headquartered in St. Louis, Missouri, and maintain a
regional office in Madisonville, Kentucky.
Strategy
Our primary business strategy is to maximize returns to our
stockholders. Key components of this strategy include the
following:
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Maintain safe mining operations and comply with environmental
standards. We consider safety to be our greatest
operational priority. For the period October 1, 2010
through September 30, 2011, our underground and surface
mines had non-fatal days lost incidence rates that were 39% and
72%, respectively, below the national averages for the same
period. Non-fatal days lost incidence rate is an industry
standard used to describe occupational injuries that result in
the loss of one or more days from an employees scheduled
work. We intend to maintain programs and policies designed to
enable us to remain among the safest coal operations in the
industry. We also intend to continue to implement responsible,
effective environmental practices throughout our operations and
reclamation activities.
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Continue to grow our production. We intend to
continue to increase our coal production in the coming years to
satisfy what we believe will be an increasing demand for
Illinois Basin coal. We will seek to support production growth
by executing mining plans for our existing undeveloped reserves
and by opportunistically acquiring additional coal reserves that
are located near our current mining operations or otherwise
offer the potential for efficient and economical development of
low-cost production to serve our primary market area. We
commenced production at Lewis Creek in June 2011 and plan to
commence production at our Kronos underground mining operation
in September 2011 and currently expect that our 2011 production
will be approximately 7.2 million tons, compared with
5.6 million tons in 2010.
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Increase and diversify coal sales to utilities with base load
scrubbed power plants in our primary market area and pursue
export opportunities. We expect that the demand
for Illinois Basin coal will rise as a result of an increase in
power plants being retrofitted with scrubbers and the
construction of new power plants throughout the Illinois Basin
market area. We intend to continue to focus our marketing
efforts principally on power plants in the Mid-Atlantic,
Southeastern and Midwestern states that we expect will become
consumers of Illinois Basin coal and to seek to diversify our
customer base through a combination of multi-year coal supply
agreements and sales in the spot market. As of
September 30, 2011, we are contractually committed to sell
8.8 million tons of coal in 2012, and 8.1 million tons
of coal in 2013, which represents 99% and 83% of our expected
total coal sales in 2012 and 2013, respectively. In addition, we
believe that the relative heat, ash, sulfur content and cost of
our coal, combined with the accessibility of our coal mines and
coal processing facilities to the Mississippi River and to rail
connecting to Louisiana export terminals will provide the
opportunity to export our coal to overseas customers.
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Maximize profitability by maintaining low-cost mining
operations. We operate our mines in a manner
aimed at keeping our product quality high while maintaining low
production costs. We seek to maximize our coal production and
control our costs by continuing to improve our operating
efficiency. Our efficiency is, in part, a function of the
overburden ratios (the amount of surface material needed to be
removed to extract coal) that exist at our surface coal mines.
Our efficiency is also enhanced by our fleet of mobile mining
equipment, substantially all of which is new, our use of the
only draglines in Kentucky, our utilization of river coal
movement, our information technology systems and our coordinated
equipment utilization and maintenance management functions. We
also believe that our highly experienced operating management
and well-trained workforce will continue to help in identifying
and implementing cost containment initiatives.
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Competitive
Strengths
We believe that the following competitive strengths will enable
us to effectively execute our business strategy described above.
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We have a demonstrated track record for successfully
completing reserve acquisitions, securing required permits,
developing new mines and producing coal. Since
our formation in 2006, we have successfully acquired coal
reserves and opened seven separate mines, obtained the necessary
regulatory permits for the commencement of mining operations at
those mines, and developed significant multi-year contractual
relationships with large customers in our market area. We
believe this resulted from our deep management experience and
disciplined approach to the development of our operations and
our focus on providing competitively priced Illinois Basin coal.
We believe this will enable us to continue to grow our customer
base, production, revenues and profitability.
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Our proven and probable reserves have a long reserve life and
attractive characteristics. As of
December 31, 2010, we had approximately 319 million
tons of clean recoverable (proven and probable) coal reserves.
Our reserves include both surface and underground mineable coal
residing in multiple seams which, in combination with our coal
processing facilities, enhances our ability to meet customer
requirements for blends of coal with different characteristics.
Further, the comparatively low chlorine content of our coal
relative to other Illinois Basin coal provides us with an
additional competitive advantage in meeting the desired coal
fuel profile of our customers.
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Our mines are conveniently located in close proximity to our
existing and potential customers and have access to multiple
transportation options for delivery. Our mines
are located adjacent to the Green and Ohio Rivers and near our
preparation, loading and transportation facilities, providing
our customers with rail, barge and truck transportation options.
We believe this will also enable us to sell our coal in both the
domestic and export markets. Recently, we purchased an equity
interest in, and upon development will have access to, a
Mississippi River coal export terminal project in Plaquemines
Parish, Louisiana, approximately 10 miles downstream of New
Orleans. We intend to oversee the design, build-out and
operation of this export coal terminal to facilitate the
anticipated sale of our coal to international customers.
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We are a reliable supplier of cost competitive
coal. Our highly skilled, non-union workforce
uses efficient mining practices that take advantage of economies
of scale and reduce operating costs per ton in both surface and
underground mining. We are among a small number of operators of
large scale dragline surface production in the eastern United
States, and our continuous miner underground mining operations
are designed to provide operating flexibility to meet production
requirements and to fulfill our coal contract specifications.
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We have a highly experienced management team with a long
history of acquiring, building and operating coal
businesses. The members of our senior management
team have a demonstrated track record of acquiring, building and
operating coal businesses profitably and safely. In addition,
members of our senior management team have significant
experience managing the financial and organizational growth of
businesses, including public companies.
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Our
Operational History
Since 2006, we have acquired a substantial portion of our coal
reserves, surface properties, mining rights and other assets
through a series of transactions including the following:
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Date
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Principal Assets Acquired
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Purchase Price
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September 2006
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Surface properties and mineral reserves (both fee and leasehold)
in Ohio and Muhlenberg Counties, Kentucky, including certain of
the Ken and Rockport reserves.
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$25.5 million
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December 2006
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Approximately 9,500 acres of surface property and mineral
reserves (both fee and leasehold), including certain of the
Equality Boot and Parkway reserves.
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$41.0 million
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March 2007
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Properties and mineral reserves (both fee and leasehold) in Ohio
and Muhlenberg Counties, Kentucky, including certain of the West
Fork, Midway, Paradise and Vogue reserves.
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$46.5 million
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May 2007
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Surface properties and mineral reserves (both fee and leasehold)
in Ohio and Muhlenberg Counties, Kentucky, including certain of
the Sunnyside, Lewis Creek and East Fork reserves, and the idled
Big Run mine.
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$49.6 million
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March 2008
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Elk Creek Reserves.*
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$75.6 million
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December 2011
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Properties and mineral reserves (both fee and leasehold) in
Muhlenberg County, Kentucky.
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$13.3 million
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December 2011
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#9 seam coal reserves in union County, Kentucky (both fee and
leasehold interests).
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$9.0 million
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Purchased through Armstrong Resource Partners. |
These acquisitions were funded through aggregate payments of
approximately $82.7 million and promissory notes with an
aggregate principal amount of approximately $177.8 million.
In October 2010, we entered into a lease that gives us the right
to mine the substantial underground coal reserves located in
Union and Webster Counties, Kentucky (the Union/Webster
Counties reserves). The Union/Webster Counties reserves
contain approximately 116 million tons of clean recoverable
reserves. The lease requires us to pay minimum annual advance
royalties in the form of 16,000 tons, recoupable against earned
royalties up to $500,000 per calendar year. The lease also
provides for a 6.0% earned royalty rate that may also be
satisfied by the delivery of coal at the election of the lessor.
We are obligated to meet certain due diligence requirements or
pay additional advance royalties prior to the commencement of
mining.
In 2009 and 2010, we borrowed an aggregate principal amount of
$44.1 million from Armstrong Resource Partners, and the
proceeds of those loans were used to satisfy various installment
payments required by the promissory notes referred to above.
Under the terms of these borrowings, Armstrong Resource Partners
had the option to acquire interests in coal reserves then held
by Armstrong Energy in Muhlenberg and Ohio Counties in
satisfaction of the loans it had made to Armstrong Energy. On
February 9, 2011, Armstrong Resource Partners exercised
this option. In connection with that exercise, Armstrong
Resource Partners paid Armstrong Energy an additional
$5.0 million in cash and agreed to offset
$12.0 million in accrued advance royalty payments owed by
Armstrong Energy to Armstrong Resource Partners, relating to the
lease of the Elk Creek Reserves, to acquire an additional
partial undivided interest in certain of the coal reserves held
by Armstrong Energy in Muhlenberg and Ohio Counties at fair
market value. Through these transactions, Armstrong Resource
Partners acquired a 39.45% undivided interest as a joint tenant
in common with Armstrong Energy in the majority of our coal
reserves, excluding the Union/Webster Counties reserves. The
aggregate amount paid by Armstrong Resource Partners to acquire
its interest in these reserves was the equivalent of
approximately $69.5 million.
In February 2011, all outstanding amounts under the promissory
notes referred to above were repaid with the proceeds of
borrowings under our Senior Secured Credit Facility. See
Description of Indebtedness.
Our
Organizational History
In August 2011, Armstrong Resources Holdings, LLC merged with
and into Armstrong Energy, Inc., which subsequently changed its
name to Armstrong Energy Holdings, Inc. Subsequently, Armstrong
Land Company, LLC was converted to a C-corporation and changed
its name to Armstrong Energy, Inc. effective October 1,
2011. In connection with the Reorganization, each owner of
Armstrong Land Company, LLC received 9.25 shares of
Armstrong Energy, Inc. common stock for each unit held. The
following chart shows a summary of the corporate organization of
Armstrong Energy, Inc. and its principal subsidiaries, after
giving effect to the Reorganization, but prior to giving effect
to the offering of common stock being made hereby or to the
Concurrent ARP Offering.
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Reserves owned solely by Armstrong Resource Partners. These
include the Kronos, Lewis Creek and Ceralvo underground mines. |
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Reserves controlled jointly by Armstrong Resource Partners (with
a 39.45% undivided interest) and Armstrong Energy (with a 60.55%
undivided interest). If the Concurrent ARP Offering and related
transactions are completed, the undivided interest of Armstrong
Resource Partners will increase, and the undivided interest of
Armstrong Energy will decrease, based on the net proceeds of the
Concurrent ARP Offering paid to Armstrong Energy and the value
of the affected reserves as agreed by Armstrong Resource
Partners and Armstrong Energy. See Certain Relationships
and Related Party Transactions Concurrent
Transactions with Armstrong Resource Partners. |
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The following chart depicts the organization and ownership of
Armstrong Energy, Inc. after giving effect to this offering and
the Concurrent ARP Offering.
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(1) |
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Reserves owned solely by Armstrong Resource Partners. These
include the Kronos, Lewis Creek and Ceralvo underground mines. |
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(2) |
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Reserves controlled jointly by Armstrong Resource Partners (with
a % undivided interest) and
Armstrong Energy (with a %
undivided interest), assuming an offering price of
$ per unit, the midpoint of the
price range set forth on the front cover page of the prospectus
for the Concurrent ARP Offering and an estimated purchase price
of $ for Armstrong Resource
Partners additional interest in the partially owned
reserves. |
About
Armstrong Resource Partners
Armstrong Resource Partners was formed in 2008 to engage in the
business of management and leasing of coal properties and
collection of royalties in the Western Kentucky region of the
Illinois Basin. Armstrong Energy holds a 0.4% equity interest in
Armstrong Resource Partners through a wholly-owned subsidiary,
Elk Creek GP, which is the general partner of Armstrong Resource
Partners. The outstanding limited partnership interests
(common units) of Armstrong Resource Partners,
representing 99.6% of its equity interests, are owned by
Yorktown. Armstrong Energy is majority-owned by Yorktown.
Yorktown is entitled to 99.6% of all distributions made by
Armstrong Resource Partners. Of our total reserves of
319 million tons, 66 million tons (21%) are owned 100%
by Armstrong Resource Partners, and 138 million tons (43%)
are held by Armstrong Energy and Armstrong Resource Partners as
joint tenants in common with 60.55% and 39.45% interests,
respectively.
Pursuant to the ARP LPA, Elk Creek GP has the exclusive
authority to conduct, direct and manage all activities of
Armstrong Resource Partners. By virtue of Armstrong
Energys control of Elk Creek GP, the results of Armstrong
Resource Partners are consolidated in our historical
consolidated financial statements contained herein. Pursuant to
the ARP LPA, effective October 1, 2011, Yorktown
unilaterally may remove Elk Creek GP as general partner in some
circumstances. As a result, Armstrong Energy will no longer
consolidate
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the results of Armstrong Resource Partners in the financial
statements of Armstrong Energy. See Unaudited Pro Forma
Financial Information.
In 2009 and 2010, Armstrong Energy borrowed an aggregate
principal amount of $44.1 million from Armstrong Resource
Partners, and the proceeds of those loans were used to satisfy
various installment payments required by the promissory notes
that were delivered in connection with the acquisition of our
coal reserves. Under the terms of these borrowings, Armstrong
Resource Partners had the option to acquire interests in coal
reserves then held by Armstrong Energy in Muhlenberg and Ohio
Counties in satisfaction of the loans it had made to Armstrong
Energy. On February 9, 2011, Armstrong Resource Partners
exercised this option. In connection with that exercise,
Armstrong Resource Partners paid Armstrong Energy an additional
$5.0 million in cash and agreed to offset
$12.0 million in accrued advance royalty payments owed by
Armstrong Energy to Armstrong Resource Partners, relating to the
lease of the Elk Creek Reserves, to acquire an additional
partial undivided interest in certain of the coal reserves held
by Armstrong Energy in Muhlenberg and Ohio Counties at fair
market value. Through these transactions, Armstrong Resource
Partners acquired a 39.45% undivided interest as a joint tenant
in common with Armstrong Energy in the majority of our coal
reserves, excluding the Union/Webster Counties reserves. The
aggregate amount paid by Armstrong Resource Partners to acquire
its interest in these reserves was the equivalent of
approximately $69.5 million.
Armstrong Resource Partners, L.P. is a co-borrower under our
$100.0 million Senior Secured Term Loan and a guarantor on
the $50.0 million Senior Secured Revolving Credit Facility
and the Senior Secured Term Loan. Substantially all of our
assets and the assets of Armstrong Resource Partners are pledged
to secure borrowings under our Senior Secured Credit Facility.
On February 9, 2011, Armstrong Energy entered into lease
agreements with Armstrong Resource Partners pursuant to which
Armstrong Resource Partners granted Armstrong Energy leases to
its 39.45% undivided interest in the mining properties described
above and licenses to mine coal on those properties. The initial
term of each such agreement is ten years, and will automatically
extend for subsequent one-year terms until all mineable and
merchantable coal has been mined from the properties, unless
either party elects not to renew or such agreement is terminated
upon proper notice. Armstrong Energy is obligated to pay
Armstrong Resource Partners a production royalty equal to 7% of
the sales price of the coal which Armstrong Energy mines from
the properties. Under the terms of these agreements, Armstrong
Resource Partners retains the surface rights to use the
properties containing these reserves for non-mining purposes.
Events of default under the lease agreements include the failure
by Armstrong Energy to pay royalty payments to Armstrong
Resource Partners when due and a default by Armstrong Energy
under any agreement, indenture or other obligation to any
creditor that, in the opinion of Armstrong Resource Partners,
may have a material adverse effect on Armstrong Energys
ability to meet its obligations under the lease agreements. If
any event of default occurs and is not cured by Armstrong
Energy, then Armstrong Resource Partners can terminate one or
more of the lease agreements. In addition, Armstrong Energy has
agreed to indemnify Armstrong Resource Partners from and against
any and all claims, damages, demands, expenses, fines,
liabilities, taxes and any other losses related in any way to
Armstrong Energys mining operations on such premises, and
to reclaim the surface lands on such premises in accordance with
applicable federal, state and local laws.
The aforementioned lease transaction has been accounted for as a
financing arrangement due to our continuing involvement in the
land and mineral reserves transferred. This has resulted
in the recognition of an initial obligation of
$69.5 million by Armstrong Energy, which represents the
fair value of the assets transferred. As the financial results
of Armstrong Resource Partners historically have been
consolidated, this transaction has not impacted our results of
operations or financial condition through September 30,
2011. As noted above, the Deconsolidation was effective
October 1, 2011. Subsequently, the long-term obligation
will be reflected on our balance sheet and will continue to be
amortized through 2031 at an annual rate of 7% of the estimated
gross revenue generated from the sale of the coal originating
from the leased mineral reserves. As of September 30, 2011,
the outstanding principal balance of the long-term obligations
to Armstrong Resource Partners was $70.3 million.
Effective February 9, 2011, we entered into an agreement
with Armstrong Resource Partners pursuant to which Armstrong
Resource Partners granted Armstrong Energy the option to defer
payment of the 7%
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production royalty described above. In consideration for the
granting of the option to defer these payments, we granted to
Armstrong Resource Partners the option to acquire an additional
partial undivided interest in certain of the coal reserves held
by Armstrong Energy in Muhlenberg and Ohio Counties by engaging
in a financing arrangement, under which we would satisfy payment
of any deferred fees by selling to Armstrong Resource Partners
part of our interest in the aforementioned coal reserves at fair
market value for such reserves determined at the time of the
exercise of such options.
On February 9, 2011, Armstrong Resource Partners also
entered into a lease and sublease agreement with Armstrong
Energy relating to our Elk Creek Reserves and granted Armstrong
Energy a license to mine coal on those properties. The terms of
this agreement mirror those of the lease agreements described
above. Armstrong Energy has paid $12 million of advance
royalties under the lease, which are recoupable against
production royalties.
Based upon our current estimates of production for 2011 and
2012, we anticipate that Armstrong Energy will owe royalties to
Armstrong Resource Partners under the above-mentioned license
and lease arrangements of approximately $7.8 million and
$16.6 million in 2011 and 2012, respectively, of which
collectively, $7.2 million will be recoupable against the
advance royalty payment referred to above.
Concurrent
Offering
Concurrent with this offering of common stock, Armstrong
Resource Partners is offering common units pursuant to a
separate initial public offering. Armstrong Energy indirectly
holds a 0.4% equity interest in Armstrong Resource Partners. See
Our Organizational History. If the
Concurrent ARP Offering is completed, we expect that the net
proceeds received by Armstrong Resource Partners will be applied
as described in Use of Proceeds. While we intend to
consummate the Concurrent ARP Offering simultaneously with this
offering of common stock, the completion of this offering is not
subject to the completion of the Concurrent ARP Offering and the
completion of the Concurrent ARP Offering is not subject to the
completion of this offering.
This description and other information in this prospectus
regarding the Concurrent ARP Offering is included in this
prospectus solely for informational purposes. Nothing in this
prospectus should be construed as an offer to sell, nor the
solicitation of an offer to buy, any common units of Armstrong
Resource Partners.
Our
Mining Operations
We currently operate six active mines, all of which are located
in the Illinois Basin coal region in western Kentucky. Our
operations are comprised of four surface mines and two
underground mines, and we have three preparation plants serving
these operations. In 2010, approximately 64% of the coal that we
produced came from our surface mining operations.
In addition, we are seeking permits for four additional mines.
Permit applications for the Hickory Ridge surface mine have been
submitted to the Corps and the State of Kentucky but have yet to
be issued. We are also in the process of preparing permit
applications relating to Ken surface mine and the Lewis Creek
and Ceralvo underground mines. We intend to submit those permit
applications to the Corps and the State of Kentucky beginning in
January 2012.
Our current operating mines are all located in Muhlenberg and
Ohio Counties, Kentucky. The Western Kentucky Parkway crosses
our properties from Southwest to Northeast, and the Green River
separates our properties in Ohio and Muhlenberg Counties. Our
barge loading facility on the Green River is located near the
town of Kirtley, Kentucky. In addition, we have a network of
off-highway truck haul roads, which connect the majority of our
active mines and provide access to our barge loading and rail
loadout facilities.
95
The following tables provide a summary of information regarding
our active mines.
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Production
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Quality Specifications
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Clean Recoverable Tons
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Nine
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(As Received)(2)
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(Proven and Probable
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Year
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Months
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SO2
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Mines
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Reserves)(1)
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Ended
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Ended
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Heat
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Content
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(Commenced
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Mining
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Proven
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Probable
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December 31,
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September 30,
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Value
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(Lbs/
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Ash
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Operations)
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Method(3)
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Reserves
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Reserves
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Total
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2010
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2011
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(Btu/Lb)
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MMBtu)
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(%)
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(In thousands)
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(Tons in thousands)
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Active mines
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Big Run (April 2008)(4)
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U
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2,849
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242
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3,091
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(5)
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572.1
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361.5
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11,822
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4.3
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7.4
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Midway (July 2008)
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S
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24,806
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3,507
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28,313
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(5)
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1,614.8
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1,290.4
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11,315
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4.8
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10.0
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Parkway (April 2009)
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U
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1,952
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58
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2,010
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(5)
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1,485.9
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1,165.6
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11,931
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4.4
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7.1
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East Fork (June 2009)(6)
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S
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2,633
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553
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3,186
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(5)
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1,641.1
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608.6
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11,136
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7.6
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11.2
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Equality Boot (September 2010)
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S
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23,687
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1,148
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24,835
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(7)
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330.8
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1,493.3
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11,587
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5.7
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8.8
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Lewis Creek (June 2011)
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S
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6,650
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70
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6,720
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(5)
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197.0
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11,420
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4.0
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9.5
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Kronos (September 2011)(8)
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U
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18,862
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3,002
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21,864
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9.6
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11,792
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4.5
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7.6
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Total active mines
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81,439
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8,580
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90,019
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5,644.7
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5,126.0
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(1) |
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For surface mines, clean recoverable tons are based on a 90%
mining recovery, preparation plant yield at 1.55 specific
gravity and a 95% preparation plant efficiency. For underground
mines, clean recoverable tons are based on a 50% mining
recovery, preparation plant yield at 1.55 specific gravity and a
95% preparation plant efficiency. Proven and probable
reserves refers to coal that can be economically extracted
or produced at the time of the reserve determination. |
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(2) |
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Quality specifications displayed on an as received
basis, assuming 11% moisture. If derived from multiple seams,
data represents an average. |
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(3) |
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U = Underground; S = Surface |
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(4) |
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Big Run ceased production in October 2011. |
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(5) |
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Of these reserves, 39.45% of the interests controlled by
Armstrong Energy are leased from Armstrong Resource Partners. |
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(6) |
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Warden and Kronos pits. |
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(7) |
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Of these reserves, 39.45% of the interests controlled by
Armstrong Energy are leased from Armstrong Resource Partners.
Includes 167,000 tons related to reserves for which we own or
lease a 50% or more partial joint interest and royalties on
extractions may be payable to other owners. |
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(8) |
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Based on internal estimates, recoverable reserves are split
evenly among the three mines that comprise the Elk Creek
Reserves (Kronos, Lewis Creek underground and Ceralvo). See the
table and related footnotes under Prospectus
Summary About the Company. |
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Clean Recoverable Tons (Proven
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Primary
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and Probable Reserves)(1)
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Transportation
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Owned
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Leased
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Total
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Method
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(In thousands)
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Active mines
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Big Run (April 2008)(2)
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3,091
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3,091
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(3)
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Rail
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Midway (July 2008)
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28,313
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28,313
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(3)
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Rail, barge & truck
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Parkway (April 2009)
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312
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1,698
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2,010
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(3)
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Truck
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East Fork (June 2009)(4)
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2,302
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884
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3,186
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(3)
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Rail, barge & truck
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Equality Boot (September 2010)
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24,835
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24,835
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(5)
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Barge
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Lewis Creek (surface) (June 2011)
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6,720
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6,720
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(3)
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Rail, barge & truck
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Kronos (September 2011)(6)
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20,689
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1,175
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21,864
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Rail, barge & truck
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Total active mines
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90,019
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96
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(1) |
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For surface mines, clean recoverable tons are based on a 90%
mining recovery, preparation plant yield at 1.55 specific
gravity and a 95% preparation plant efficiency. For underground
mines other than Union/Webster Counties, clean recoverable tons
are based on a 50% mining recovery, preparation plant yield at
1.55 specific gravity and a 95% preparation plant efficiency.
For Union/Webster Counties, clean recoverable tons are based on
a 50% mining recovery, preparation plant yield at 1.60 specific
gravity and a 95% preparation plant efficiency. Proven and
probable reserves refers to coal that can be economically
extracted or produced at the time of the reserve determination. |
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(2) |
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Big Run ceased production in October 2011. |
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(3) |
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Of these reserves, 39.45% of the interests controlled by
Armstrong Energy are leased from Armstrong Resource Partners. |
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(4) |
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Warden and Kronos pits. |
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(5) |
|
Of these reserves, 39.45% of the interests controlled by
Armstrong Energy are leased from Armstrong Resource Partners.
Includes 167,000 tons related to reserves for which we own or
lease a 50% or more partial joint interest and royalties on
extractions may be payable to other owners. |
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(6) |
|
Based on internal estimates, recoverable reserves are split
evenly among the three mines that comprise the Elk Creek
Reserves (Kronos, Lewis Creek underground and Ceralvo). |
The following map shows the locations of our mining operations
and coal reserves:
In general, we have developed our mines and preparation plants
at strategic locations in close proximity to rail or barge
shipping facilities. Coal is transported from our mines to
customers by means of railroads, trucks, and barge lines. We
currently own or lease under long-term arrangements a
substantial portion of the
97
equipment utilized in our mining operations. We employ
sophisticated preventative maintenance and rebuild programs and
upgrade our equipment to ensure that it is productive,
well-maintained and cost-competitive. Our maintenance programs
also employ procedures designed to enhance the efficiencies of
our operations.
We control approximately 204 million tons of coal available
for production at our active and proposed mines in Ohio and
Muhlenberg counties in Western Kentucky, of which we lease
approximately 23 million tons from various unaffiliated
landowners.
Armstrong Coal Company, Inc., our wholly-owned subsidiary
(Armstrong Coal), has entered into leases with
Western Mineral Development, LLC (Western Mineral),
Western Land Company, LLC (Western Land) and Western
Diamond, LLC (Western Diamond), each of which is our
wholly-owned subsidiary, for the reserves described above,
excluding the Elk Creek Reserves. Those leases are for a term of
ten years but can be renewed for an additional ten-year term or
until all of the mineable and merchantable coal has been mined.
The leases provide for a 7% production royalty payment to be
paid by Armstrong Coal to the lessors.
Effective February 9, 2011, Armstrong Coal, Western Diamond
and Western Land entered into a Royalty Deferment and Option
Agreement with Western Mineral. Pursuant to this agreement,
Western Mineral agreed to grant to Armstrong Coal and its
affiliates the option to defer payment of Western Minerals
pro rata share of the 7% production royalty described under
Lease Agreements below. In consideration
for Western Minerals granting of the option to defer these
payments, Armstrong Coal and its affiliates granted to Western
Mineral the option to acquire an additional partial undivided
interest in certain of the coal reserves held by Armstrong
Energy, Inc. in Muhlenberg and Ohio Counties by engaging in a
financing arrangement, under which Armstrong Coal and its
affiliates would satisfy payment of any deferred fees by selling
part of their interest in the aforementioned coal reserves at
fair market value for such reserves determined at the time of
the exercise of such options.
On October 11, 2011, Western Diamond and Western Land
(together, the Sellers) entered into an agreement
with Western Mineral pursuant to which the Sellers agreed to
sell an additional partial undivided interest in substantially
all of the coal reserves and real property owned by the Sellers
previously subject to the options exercised by Armstrong
Resource Partners on February 9, 2011 (see Certain
Relationships and Related Party Transactions Sale of
Coal Reserves), other than any of Sellers real
property and related mining rights associated with the Parkway
mine. Such interest shall be equal to a fraction, the numerator
of which shall be equal to the amount of net proceeds received
by Western Mineral
and/or its
parents or affiliates from the Concurrent ARP Offering (see
Prospectus Summary Concurrent Offering),
and the denominator of which is a dollar amount the parties
agree represents the aggregate fair market value of the
property. The closing of the sale, which is conditioned on the
closing of the Concurrent ARP Offering, shall occur on or before
90 days after Western Mineral
and/or its
parents or affiliates receives the net proceeds of the
Concurrent ARP Offering.
We also lease the Elk Creek Reserves from Armstrong Resource
Partners, and the terms of that lease mirror the leases
described above. The lease with Armstrong Resource Partners also
recognizes and permits us to recoup a pre-existing annual
advance royalty balance of $12.0 million against production
royalties as they come due.
Approximately 116 million tons of recoverable coal are
located in the Union/Webster Counties reserves. We have entered
into a lease with a non-affiliated third party for such
reserves, which requires us to pay minimum annual advance
royalties in the form of 16,000 tons, recoupable against earned
royalties up to $500,000 per calendar year. The lease also
provides for a 6% earned royalty rate that may also be satisfied
by the delivery of coal at the election of lessor. We are also
obligated to meet certain due diligence requirements or pay
additional advance royalties prior to the commencement of mining.
Big Run Mine. The Big Run mine was an
underground mine located near Centertown, Kentucky that was
previously operated by Peabody Energy. In October 2011,
production at Big Run ceased, and the equipment that had been
used to extract thermal coal from the West Kentucky #9 seam
was relocated to the Kronos mine. The Kronos mine commenced
production in September 2011. Big Run produced
approximately 0.4 million clean tons of coal in 2011, which
was processed at our Midway Preparation Plant.
98
Midway Mine. Midway is a surface mine located
two miles southeast of Centertown, Kentucky in Ohio County and
is west of and adjacent to the Midway Preparation Plant. The
Midway Mine commenced production in April 2008 and extracts
thermal coal from the West Kentucky #13a, #13,
and #11 seams. Stripping ratios for coal that has not
undergone any processing, or run-of-mine coal, at
the Midway Mine are favorable and range from 12 to 13.5-to-1.
Midway is expected to produce approximately 1.6 million
tons of clean coal in 2011 and is currently equipped with one
dragline (45 yard bucket) and a spread of surface mining
equipment, including power shovels, excavators, loaders and haul
trucks. Our reserve studies have indicated that Midway has
approximately 28 million tons of proven and probable
reserves. Coal from the Midway mine is transported less than one
mile to the Midway Preparation Plant for processing, where it is
then shipped to customers via truck, rail or barge.
Parkway Mine. Parkway is an underground mine
located northeast of Central City, Kentucky in Muhlenberg County
that extracts thermal coal primarily from the West
Kentucky #9 seam and accesses that seam from an older
surface mining pit that was abandoned prior to our acquisition
of Parkway. Parkway consists of two working super sections, and
each section is currently equipped with two continuous miners
that operate concurrently. Parkway is expected to produce
approximately 1.6 million tons of clean coal in 2011.
Additional reserves that we do not currently control are located
adjacent to the current Parkway reserves that could extend the
life of the Parkway mine. The majority of the coal from the
Parkway mine is transported to the surface stockpile where it is
processed at the Parkway Preparation Plant and trucked to a
single customer via a seven mile private haul road.
East Fork Mine. East Fork is a surface mine
located three miles west of Centertown, Kentucky. The East Fork
complex consists of two pits, the Warden and Kronos pits, which
extract thermal coal from the West Kentucky #14 seam. The
Kronos pit commenced operations in June 2009, and the Warden pit
commenced operations in August 2009. East Fork is expected to
produce approximately 0.8 million tons of clean coal in
2011, and there were approximately 3.2 million tons of
proven and probable reserves at the East Fork mine at December
2010. We currently anticipate that production at the Kronos pit
will continue until late 2011 while production at the Warden pit
will continue through 2013. East Fork
run-of-mine
coal is trucked 3.6 miles to the Armstrong Dock Preparation
Plant via a private haul road where it is processed, blended and
shipped to customers.
Equality Boot Mine. Equality Boot is a surface
mining operation located eight miles southwest of Centertown,
Kentucky, which commenced operations in September 2010. The
Equality Boot mine extracts thermal coal from the West
Kentucky #14, #13, #12 and #11 seams and is
expected to produce approximately 2.3 million tons of coal
in 2011. The Equality Boot mine uses two draglines equipped with
45 yard buckets and a spread of surface equipment, including
power shovels, excavators, loaders and haul trucks to remove
overburden and interburden and construct the dragline bench.
Run-of-mine
stripping ratios at the Equality Boot mine are favorable and
have averaged less than 10-to-1, a trend we expect to continue.
Equality Boot has approximately 25 million tons of proven
and probable reserves. Coal from the Equality Boot mine is
transported less than one mile by truck to the Equality Boot
run-of-mine facility, where a 4,400 foot overland conveyor
system is used to transport the coal to the 2,500 tons per hour
barge loadout facility located on the Green River. The coal is
then loaded onto barges and transported approximately
5 miles to the Armstrong Dock Preparation Plant where it is
unloaded, processed, reloaded onto barges and then shipped to
its customers.
99
Lewis Creek Mine. The Lewis Creek mine is a
surface mine located approximately five miles south of
Centertown, Kentucky and approximately 3.5 miles from the
Midway Preparation Plant. Production commenced in June 2011 at
Lewis Creek, and thermal coal is being mined from the West
Kentucky seams #13A and #13. Lewis Creek is expected
to produce approximately 0.5 million tons of clean coal in
2011. A dragline equipped with a 20 yard bucket is used in
conjunction with mobile mining equipment to remove overburden
and construct the dragline bench at Lewis Creek. There are
approximately 7 million tons of proven and probable
reserves at the Lewis Creek surface mine. Coal mined at Lewis
Creek is transported by truck to the Midway Preparation Plant
for processing and subsequent delivery to our customers.
Kronos Mine. The Kronos mine, which commenced
operations in September 2011, is an underground mine located
approximately three miles southwest of Centertown, Kentucky. It
will extract thermal coal from the West Kentucky #9 seam
and is expected to produce approximately 0.4 million tons
of clean coal in 2011. The mine currently utilizes two
continuous miner super sections, but we expect to increase to
four super sections in early 2012. At that time, we expect that
the mines annual production will be 2.4 million tons.
There are approximately 22 million tons of proven and
probable reserves at the Kronos mine. Coal mined at Kronos is
transported by truck to the Midway Preparation Plan and the
Armstrong Dock Preparation Plant for processing and delivery.
Future Underground Mines. We anticipate
opening the Lewis Creek underground mine in 2013 and the Ceralvo
underground mine in 2015 in Ohio County, Kentucky, assuming that
we receive all necessary permits for operation of those mines.
Both mines will produce coal from the West Kentucky #9 seam
utilizing two continuous miner super sections operating
concurrently. Once fully operational, the Lewis Creek and
Ceralvo underground mines are projected to produce approximately
1 million tons each of clean coal per year. There are
approximately 22 million tons of proven and probable
reserves at each of the Lewis Creek and Ceralvo reserves.
100
Future Surface Mines. We anticipate opening
the Hickory Ridge, Ken and Maddox surface mines in 2013 and
2014. These surface mines will produce thermal coal from
primarily the West Kentucky #14, #13, #13A
and #11 seams. Conventional
truck-and-shovel
operations are anticipated to be used at all of the mines. The
Hickory Ridge, Ken and Maddox surface mines have approximately
23 million tons in the aggregate of proven and probable
reserves.
Our Coal
Preparation Facilities
The majority of coal from each of our mining operations is
processed at a coal preparation plant located near the mine or
connected to the mine by an overland conveyor system. Currently,
we have three preparation plants, Midway, Parkway and Armstrong
Dock. These coal preparation plants allow us to treat the coal
we extract from our mines to ensure a consistent quality and to
enhance its suitability for particular end-users. In 2010, our
preparation plants processed approximately 98% of the raw coal
we produced. In addition, depending on coal quality and customer
requirements, we may blend coal mined from different locations
in order to achieve a more suitable product. At the current
time, our preparation plants do not process coal from other
companies, and we do not have any present intention to do so.
The following chart provides information regarding our
preparation plants:
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Midway
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Parkway
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Armstrong Dock
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|
Location:
|
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Centertown, Kentucky
|
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Central City, Kentucky
|
|
Centertown, Kentucky
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Inception:
|
|
July 2008
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April 2009
|
|
March 2010
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Mines Serviced:
|
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Midway, Big Run, Lewis Creek
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Parkway
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East Fork, Equality Boot, Kronos
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Tons Per Hour:
|
|
600 Expandable to 1,200
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400
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1,200
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Loadout Tons Per Hour:
|
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2,500 (Rail)
|
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2,500 (Barge)
|
Transportation:
|
|
Rail, Truck
|
|
Truck
|
|
Barge
|
Our Midway Plant is 600
tons-per-hour
(TPH) raw coal feed, heavy media preparation plant
that was constructed in 2008. The plant is connected to the
P&L Railroad via a newly-constructed unit train railroad
loop extension of approximately 16,000 feet,
and also includes a coal handling system similar to that present
at the Armstrong Dock Plant that permits the loading of coal
into railcars or trucks. With additional capital expenditures,
the Midway Plant is expandable to 1,200 TPH.
The Parkway Preparation Plant is located adjacent to the Parkway
mine and has a run-of-mine coal capacity of 400 TPH. Clean coal
from the preparation plant is placed in a 60,000 ton capacity
stockpile and subsequently loaded into trucks for delivery to
our customers.
The Armstrong Dock Plant is a 1200 TPH raw coal feed, heavy
media preparation plant that was constructed in 2008. The plant
is connected to a newly-refurbished 10,000 ton donut
storage stockpile and an extensive conveyor handling system. The
Armstrong Dock Plant has a coal handling system that permits the
loading of coal into barges adjacent to the dock conveyor or
into trucks adjacent to the plant itself.
The treatments we employ at our preparation plants depend on the
size of the raw coal. For coarse material, the separation
process relies on the difference in the density between coal and
waste rock where, for the very fine fractions, the separation
process relies on the difference in surface chemical properties
between coal and the waste minerals. To remove impurities, we
crush raw coal and classify it into various sizes. For the
largest size fractions, we use dense media vessel separation
techniques in which we float coal in a tank containing a liquid
of a pre-determined specific gravity. Since coal is lighter than
its impurities, it floats, and we can separate it from rock and
shale. We treat intermediate sized particles with dense medium
cyclones, in which a liquid is spun at high speeds to separate
coal from rock. Fine coal is treated in spirals, in which the
differences in density between coal and rock allow them, when
suspended in water, to be separated. Ultra fine coal is
recovered in column flotation cells utilizing the differences in
surface chemistry between coal and rock. By injecting stable air
bubbles through a suspension of ultra fine coal and rock, the
coal particles adhere to the bubbles and rise to the surface of
the column where they are removed. To minimize the moisture
content in coal, we process most coal sizes through centrifuges.
A centrifuge spins coal very quickly, causing
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water accompanying the coal to separate. Coarse refuse from our
preparation plants is back-hauled and disposed of in our mining
pits or other locations in accordance with applicable
regulations and permits.
Sales and
Marketing
Our sales and marketing functions are handled from our
St. Louis, Missouri headquarters with assistance from our
Madisonville, Kentucky operations center. Prior to 2011, the
majority of our coal sales were made through the use of
third-party independent contractors who were paid a per-ton
commission with respect to the coal they brokered for sale.
Commencing in 2011, the majority of our new coal sales have been
made through our in-house Director of Coal Sales, and no new
commissions are paid with respect to coal sold by our employees.
Multi-year
Coal Supply Agreements
As is customary in the coal industry, we enter into multi-year
coal supply agreements with many of our customers. Multi-year
coal supply agreements usually have specific and possibly
different volume and pricing arrangements for each year of the
agreement. These agreements allow customers to secure a supply
for their future needs and provide us with greater
predictability of sales volume and sales prices. In 2010, we
sold approximately 90% of our coal under multi-year coal supply
agreements. The majority of our multi-year coal supply
agreements include a fixed price for the term of the agreement
or a pre-determined escalation in price for each year. Some of
our multi-year coal supply agreements may include a variable
pricing system. While most of our multi-year coal supply
agreements are for terms of one to five years, some spot
agreements and purchase orders provide for deliveries for as
little as one month, and other agreements have terms up to
10.5 years. At September 30, 2011, we had 11
multi-year coal supply agreements with remaining terms ranging
from one to seven years.
We typically enter into multi-year coal supply agreements
through a
request-for-proposal
process and after competitive bidding and negotiations.
Therefore, the terms of these agreements vary by customer. Our
multi-year coal supply agreements typically contain provisions
to adjust the base price due to new laws and regulations that
affect our costs. Additionally, some of our agreements contain
provisions that allow for the recovery of costs affected by
modifications or changes in the interpretations or application
of any applicable statute by local, state or federal government
authorities.
The price of coal sold under certain of our agreements is
subject to fluctuation. For example, some of our agreements
include index provisions that change the price based on changes
in market-based indices and or changes in economic indices.
Other agreements contain price reopener provisions that may
allow a party to renegotiate pricing at a set time. Price
reopener provisions may automatically set a new price based on
then-current market prices or require us to negotiate a new
price. In a limited number of agreements, if the parties do not
agree on a new price, either party has an option to terminate
the agreement. In addition, certain of our agreements contain
clauses that may allow customers to terminate the agreement in
the event of certain changes in environmental laws and
regulations that impact their operations.
The coal supply agreements establish the quality and volume of
coal to be sold. Most of our agreements fix annual pricing and
volume obligations, though in certain instances, the volume
obligations may change depending on the customers needs.
Most of our coal supply agreements contain provisions requiring
us to deliver coal within certain ranges for specific coal
characteristics such as heat content, sulfur, ash and moisture
content as well as others. Failure to meet these specifications
can result in economic penalties, suspension or cancellation of
shipments or termination of the agreements.
Our coal supply agreements also typically contain force majeure
provisions allowing temporary suspension of performance by us or
our customers in the event that circumstances beyond the control
of the affected party occur, including events such as strikes,
adverse mining conditions, mine closures or serious
transportation problems that affect us or unanticipated plant
outages that may affect the buyer. Our agreements also generally
provide that in the event a force majeure event exceeds a
certain time period, the unaffected party may have the option to
terminate the purchase or sale in whole or in part.
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Customers
The following map identifies current or planned scrubbed power
plants to which we presently sell coal or to which Illinois
Basin coal could be sold in the future.
Our primary customers are electric utilities. We may also sell
coal to industrial companies, brokers and other coal producers.
For the year ended December 31, 2010 and the nine months
ended September 30, 2011,
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approximately 96% and 94%, respectively, of our coal revenues
related to sales to electric utilities. The majority of our
electric utility customers purchase coal for terms of one to
five years, but we also supply coal on a spot basis for some of
our customers.
In 2010, we sold coal to eight domestic customers with
operations located in numerous states. The majority of those
customers operate power plants in the Midwestern and Southern
regions of the United States. For the year ended
December 31, 2010, we derived approximately 76% of our
total coal revenues from sales to our two largest
customers Tennessee Valley Authority
(TVA) and Louisville Gas and Electric
(LGE). For the fiscal year ended December 31,
2010, coal sales to TVA and LGE constituted approximately 40%
and 36% of our total coal revenues, respectively.
We currently have two multi-year coal supply agreements with LGE
for the sale of coal. The first agreement was entered into in
2008, as amended, and expires in 2016. It calls for
2.1 million tons annually through 2015 and 0.9 million
tons in 2016. Pricing ranges from $28.19 to $30.25 per ton over
the term of the agreement subject to certain additional quality
related adjustments that are typical of the industry. There is
no price reopener provision in this agreement. The agreement
with LGE that was entered into in 2009 calls for annual delivery
of 1.25 million tons from 2011 through 2013 and
0.75 million tons from 2014 through 2016. In addition to
typical quality adjustments, the price ranges from $42.00 to
$45.00 per ton from 2011 through 2013. The agreement then
provides that either party may elect at its sole option to
reopen the agreement for negotiations with respect to price
and/or other
terms as it concerns all coal to be delivered in 2014 and
beyond. Should either party seek to reopen the agreement (which
must be done no later than April 1, 2013) and the
parties be unable to reach a mutually acceptable agreement as to
those terms being renegotiated, the agreement will terminate as
of December 31, 2013.
We also have two multi-year coal supply agreements with TVA for
the sale of coal. The agreement with TVA that was entered into
in 2007, as amended, calls for the delivery of 1.0 million
tons annually in 2011 and 2.0 million tons from 2012
through 2018. The price ranges from $40.57 to $41.68 per ton in
2011 and 2012. The agreement then provides that either party may
elect at its sole option to reopen the agreement for
negotiations with respect to price
and/or other
terms as it concerns all coal to be delivered in 2013 and
beyond. Should either party seek to reopen the agreement (which
must be done by no later than April 1, 2012) and the
parties are unable to reach a mutually acceptable agreement as
to those terms being renegotiated, the agreement will terminate
as of December 31, 2012. The agreement also provides for
typical quality adjustments. In addition, commencing on
July 1, 2011, TVA has the unilateral right to terminate the
agreement upon 60 days written notice, in which case TVA is
required to pay us a termination fee equal to 10% of the base
price multiplied by the remaining number of tons to be delivered
under the agreement.
The agreement with TVA that was entered into in 2008 calls for
delivery of between 0.9 million and 1.1 million tons
annually from
2009-2013.
The price ranges from $56.00 to $58.00 between 2011 and 2013.
The agreement then provides that either party may elect at its
sole option to reopen the agreement for negotiations with
respect to price
and/or other
terms as it concerns all coal to be delivered in 2012 and 2013.
TVA exercised its option under the agreement. As a result the
parties reached an agreement to reprice the coal to be delivered
in 2012 and 2013 with pricing from $54.25 to $55.88 per ton.
Transportation
We ship our coal to domestic customers by means of railcars,
barges or trucks, or a combination of these means of
transportation. We generally sell coal free on board at the mine
or nearest loading facility. Our customers normally bear the
costs of transporting coal by rail or barge. Historically, most
domestic electricity generators have arranged long-term shipping
agreements with rail or barge companies to assure stable
delivery costs. Approximately 37% of our coal shipped in 2010
was delivered by barge, which is generally less expensive than
transporting coal by truck or rail. The Armstrong Dock, which is
located on the Green River, can load up to six million tons of
coal annually for shipment on inland waterways. For the first
nine months of 2011, 50%, 27% and 23% of our coal sales tonnage
was shipped by barge, truck and rail, respectively.
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Competition
The coal industry is highly competitive. There are numerous
large and small producers in all coal producing regions of the
United States, and we compete with many of these producers. Our
main competitors include Alliance Resource Partners, L.P.,
Patriot Coal Corp., Peabody Energy, Inc., the Cline Groups
Foresight Energy LLC, Oxford Resource Partners, LP and Murray
Energy, all of which are companies mining in the Illinois Basin.
Many of these coal producers have greater financial resources
and more proven and probable reserves than we do. Based on MSHA
data, we were the sixth largest producer of Illinois Basin coal
in fiscal 2010, producing approximately 5% of the total Illinois
Basin coal. As the price of domestic coal increases, we also
compete with companies that produce coal from one or more
foreign countries, such as Colombia, Indonesia and Venezuela.
The most important factors on which we compete are price,
quality and characteristics, transportation costs and
reliability of supply. The demand for our coal and the prices
that we will be able to obtain for our coal are closely related
to coal consumption patterns of the U.S. electric
generation industry and international consumers. The patterns of
coal consumption are affected by various factors beyond our
control, including economic conditions, temperatures in the
United States, government regulation, technological developments
and the location, quality, price and availability of competing
sources of fuel such as natural gas, oil and nuclear sources,
and alternative energy sources such as hydroelectric power and
wind.
Our
Safety Programs
For the period October 1, 2010 through September 30,
2011, our underground and surface mines had non-fatal days lost
incidence rates that were 39% and 72%, respectively, below the
national averages for the same period. Non-fatal days lost
incidence rate is an industry standard used to describe
occupational injuries that result in the loss of one or more
days from an employees scheduled work. We attribute our
lower incident rate to our safety program, which includes:
(i) employing eight full-time safety professionals;
(ii) implementing policies and procedures to protect
employees and visitors at our mines; (iii) utilizing
experienced third-party blasting professionals to conduct our
blasting activities; (iv) requiring a certified surface
mine foreman to be in charge of the activities at each mine; and
(v) ensuring that each employee undergoes the required
safety, hazard and task training.
We have won numerous awards for our safety record since 2008
recognizing our low injury and incident rates, as follows:
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Mine/Facility
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Year
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Award
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Equality Boot
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2010
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Sentinels of Safety award for 86,661 employee hours worked
without a Lost Workday Injury
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Midway Preparation Plant
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2010
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Sentinels of Safety award for 66,688 employee hours worked
without a Lost Workday Injury
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Parkway Mine Surface Facilities
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2010
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Sentinels of Safety award for 43,130 employee hours worked
without a Lost Workday Injury
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Parkway
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2010
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Sentinels of Safety award for 332,851 employee hours worked
without a Lost Workday Injury
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Armstrong Dock & Preparation Plant
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2010
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Sentinels of Safety award for 52,568 employee hours worked
without a Lost Workday Injury
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East Fork
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2010
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Sentinels of Safety award for 202,898 employee hours worked
without a Lost Workday Injury
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Kronos
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2010
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Green River Safety Council in recognition of 607 man hours
worked with an incident rate of 0.0
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Parkway
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2010
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Green River Safety Council in recognition of 334,923 man hours
worked with an incident rate of 0.0
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Mine/Facility
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Year
|
|
|
Award
|
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Equality Boot
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|
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2010
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|
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Green River Safety Council in recognition of 86,661 man hours
worked with an incident rate of 0.0
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East Fork
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2010
|
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Green River Safety Council in recognition of 202,898 man hours
worked with an incident rate of 0.0
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Parkway Preparation Plant
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2010
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Green River Safety Council in recognition of 43,130 man hours
worked with an incident rate of 0.0
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Midway Preparation Plant
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2010
|
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Green River Safety Council in recognition of 66,688 man hours
worked with an incident rate of 0.0
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Armstrong Dock & Preparation Plant
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2010
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|
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Green River Safety Council in recognition of 52,568 man hours
worked with an incident rate of 0.0
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Parkway
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2010
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Kentucky Office of Mine Safety & Licensing for being the
safest underground coal mine in Western Kentucky
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Parkway
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2009
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Green River Safety Council in recognition of 175,051 man hours
worked with an incident rate of 2.29
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Midway
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2009
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Sentinels of Safety award for 255,731 employee hours worked
without a Lost Workday Injury
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Midway
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2009
|
|
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Green River Safety Council in recognition of 255,731 man hours
worked with an incident rate of 0.0
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Parkway Preparation Plant
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2009
|
|
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Sentinels of Safety award for 24,855 man hours worked without a
Lost Workday Injury
|
Parkway Preparation Plant
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|
|
2009
|
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Green River Safety Council in recognition of 24,855 man hours
worked with an incident rate of 0.0
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Armstrong Dock & Preparation Plant
|
|
|
2009
|
|
|
Sentinels of Safety award for 24,255 employees hours worked
without a Lost Workday Injury
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Armstrong Dock & Preparation Plant
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|
2009
|
|
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Green River Safety Council in recognition of 24,255 man hours
worked with an incident rate of 0.0
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Midway
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2008
|
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Sentinels of Safety award for 112,174 employee hours worked
without a Lost Workday Injury
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Midway
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2008
|
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Green River Safety Council in recognition of 112,174 man hours
worked with an incident rate of 0.0
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Armstrong Dock & Preparation Plant
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2008
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Green River Safety Council in recognition of 461 man hours
worked with an incident rate of 0.0
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On October 28, 2011, an accident occurred at the
Companys Equality Boot mine and, tragically, two employees
of a local blasting company were killed when rock fell from the
highwall to the pit floor where they were travelling. Following
the accident, pursuant to Section 103(k) of the Mine Act,
MSHA issued an order prohibiting all activity at the Equality
Boot Mine until MSHA determined that it was safe to resume
normal mining operations. On November 2, 2011, MSHA
modified the 103(k) order to permit the Company to resume mining
the #14 seam in the Equality Boot mine.
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On November 8, 2011, the Company submitted a ground control
plan addendum to MSHA which was approved the same day, and
subsequently incorporated into the Companys mining
operations at the Equality Boot mine. As a result, on
November 8, 2011, MSHA modified the 103(k) order to permit
the Company to resume normal mining activities in all areas of
the Equality Boot mine until such time as the Commonwealth of
Kentucky completes its accident report concerning the incident.
On February 7, 2012, the Kentucky Office of Mine Safety and
Licensing issued its Fatal Accident Report. The Commonwealth of
Kentucky concluded that the failure of the highwall occurred
where the rock strata transitioned from wide bands of shale to
smaller bands on laminated rock, thus creating a slicken slide
fault in the area where the rock fell. The Kentucky Office of
Mine Safety and Licensing did not find any causes or
circumstances which contributed to the accident other than the
aforementioned naturally occurring geological condition.
Suppliers
We use various supplies and raw materials in our coal mining
operations, such as petroleum-based fuels, explosives, tires and
steel, as well as spare parts and other consumables. We use
third-party suppliers for a significant portion of our equipment
rebuilds and repairs, drilling services and construction. We use
sole source suppliers for certain parts of our business such as
explosives and fuel, and preferred suppliers for other parts at
our business such as dragline and shovel parts and related
services. We believe adequate substitute suppliers are available.
Employees
At September 30, 2011, we employed a total of approximately
774 employees, none of whom is represented for collective
bargaining by a union. We believe that our relations with all
employees are good.
Seasonality
Our business has historically experienced some variability in
its results due to the effect of seasons. Demand for coal-fired
power can increase due to unusually hot or cold weather as power
consumers use more air conditioning or heating. Conversely, mild
weather can result in softer demand for our coal. Adverse
weather conditions, such as floods or blizzards, can impact our
ability to mine and ship our coal and our customers
ability to take delivery of coal.
Legal
Proceedings
From time to time, we are involved in litigation and claims
arising out of our operations in the normal course of business.
At this time, we do not believe that we are a party to any
litigation that will have a material adverse impact on our
financial condition or results of operations. We are not aware
of any significant and material legal or governmental
proceedings against us, or contemplated to be brought against
us. We maintain insurance policies in amounts and with coverage
and deductibles that we believe are reasonable and appropriate.
However, we cannot assure you that this insurance will be
adequate to protect us from all material expenses related to
potential future claims for personal and property damage or that
these levels of insurance will be available in the future at
economical prices.
Regulation
and Laws
Federal, state and local authorities regulate the U.S. coal
mining industry with respect to matters such as:
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employee health and safety;
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permitting and licensing requirements;
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air quality standards;
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water pollution;
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storage, treatment and disposal of wastes;
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protection of plant life and wildlife, including endangered or
threatened species;
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reclamation and restoration of mining properties after mining is
completed;
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remediation of contaminated soil and groundwater;
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surface subsidence from underground mining;
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the effects of mining on surface and groundwater quality and
availability; and
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competing uses of adjacent, overlying or underlying lands,
pipelines, roads and public facilities.
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In addition, many of our customers are subject to extensive
regulation regarding the environmental impacts associated with
the combustion or other use of coal, which could affect demand
for our coal.
The costs of compliance with these laws and regulations have
been and are expected to continue to be significant. Future
laws, regulations or orders, as well as future interpretations
and more rigorous enforcement of existing laws, regulations or
orders, may substantially increase equipment and operating
costs, result in delays and disrupt operations or termination of
operations, the extent of which cannot be predicted with any
degree of certainty. Changes in applicable laws or the adoption
of new laws relating to energy production may cause coal to
become a less attractive source of energy. For example, if
emissions rates or caps on greenhouse gases are enacted or a tax
on carbon is imposed, the market share of coal as fuel used to
generate electricity would be expected to decrease. Thus, future
laws, regulations or enforcement priorities may adversely affect
our mining operations, cost structure or the demand for coal.
We are committed to operating our mines in compliance with
applicable federal, state and local laws and regulations.
However, because of extensive and comprehensive regulatory
requirements, violations during mining operations occur from
time to time. Violations, including violations of any permit or
approval, can result in substantial civil and criminal fines and
penalties, including revocation or suspension of mining permits.
None of the violations we have experienced to date have had a
material impact on our operations or financial condition.
Mining
Permits and Approvals
Numerous governmental permits and approvals are required for our
coal mining operations. When we apply for some of these, we are
required to assess the effect or impact that any proposed
production or processing of coal may have upon the environment.
The authorization and permitting requirements imposed by
governmental authorities are costly and may delay or prevent
commencement or continuation of mining operations in certain
locations. These requirements may also be supplemented, modified
or re-interpreted from time to time. 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 federal and
state regulatory authorities, mine operators or applicants must
submit a reclamation plan for restoring the mined land to its
prior productive use, better condition or other approved use.
Typically, we submit the necessary permit applications several
months, or even years, before we plan to mine a new area. Some
required mining permits are becoming increasingly difficult to
obtain in a timely manner, or at all, particularly those permits
involving the Clean Water Act. Specifically, issuance of Corps
permits allowing placement of material in valleys or streams has
been slowed in recent years due to ongoing disputes over the
requirements for obtaining such permits. While we do not engage
in mountaintop mining, we are required to obtain permits from
the Corps and our mining operations do impact bodies of water
regulated by the Corps. The application review process takes
longer to complete and permit applications are increasingly
being challenged by environmental and other advocacy groups,
although we are not aware of any such challenges to any of our
pending permit applications. We may experience difficulty or
delays in obtaining mining permits or other necessary approvals
in the future, or even face denials of permits altogether.
108
Violations of federal, state and local laws, regulations or any
permit or approval issued under such authorization can result in
substantial fines and penalties, including revocation or
suspension of mining permits and, in certain circumstances,
criminal sanctions.
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 within the Department
of the Interior (OSM), establishes operational,
reclamation and closure standards for all aspects of surface
mining, including the surface effects of underground coal
mining. Mining operators must obtain SMCRA permits and permit
renewals from the OSM or from the applicable state agency if the
state has obtained primacy. A state may achieve primacy if it
develops a regulatory program that is no less stringent than the
federal program and is approved by OSM. SMCRA stipulates
compliance with many other major environmental statutes,
including the federal Clean Air Act, Clean Water Act, Resource
Conservation and Recovery Act (RCRA) and
Comprehensive Environmental Response, Compensation and Liability
Act (CERCLA or Superfund). Our mines are
located in Kentucky, which has primacy to administer the SMCRA
program.
SMCRA permit provisions include a complex set of requirements,
which include, among other things, coal exploration, mine plan
development, topsoil or a topsoil removal alternative, 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 runoff and drainage control, mine
drainage and mine discharge control and treatment, establishment
of suitable post mining land uses and re-vegetation. Our
preparation of a mining permit application begins by collecting
baseline data to adequately characterize the pre-mining
environmental conditions of the permit area. This work is
typically conducted by third-party consultants with specialized
expertise and typically includes surveys or assessments of the
following: cultural and historical resources, geology, soils,
vegetation, aquatic organisms, wildlife, potential for
threatened, endangered or other special status species, surface
and groundwater hydrology, climatology, riverine and riparian
habitat and wetlands. The geologic data and information derived
from the surveys or assessments are used to develop the mining
and reclamation plans presented in the permit application. The
mining and reclamation plans address the provisions and
performance standards of the states equivalent SMCRA
regulatory program, and are also used to support applications
for other authorizations 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, public road use, bonding information, mining
methods, mining phases, other agreements that may relate to
coal, other minerals, oil and gas rights, water rights,
permitted areas, and ownership and control information required
to determine compliance with OSMs Applicant Violator
System, including the mining and compliance history of officers,
directors and principal owners of the permitting entity and its
affiliates.
Some SMCRA mine permits take us over a year to prepare,
depending on the size and complexity of the mine. Once a permit
application is prepared and submitted to the regulatory agency,
it goes through a completeness and 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, public notice
or advertisement of the proposed permit action is required,
which is followed by a public comment period. It is not uncommon
for this process to take from a year to several years for a
SMCRA mine permit to be issued. This variability in time frame
for permitting is a function of the discretion vested in the
various regulatory authorities handling of comments and
objections relating to the project that may be received from the
governmental agencies involved and the general public. The
public also has the right to comment on and otherwise engage in
the permitting process including at the public hearing and
through judicial challenges to an issued permit.
Federal laws and regulations also provide that a mining permit
or modification can be delayed, refused or revoked if owners of
specific percentages of ownership interests or controllers
(i.e., officers and directors or other entities) of the
applicant have, or are affiliated with another entity that has
outstanding violations of SMCRA or state or tribal programs
authorized by SMCRA. This condition is often referred to as
being permit blocked under the federal Applicant
Violator Systems. Thus, non-compliance with SMCRA can
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provide the bases to deny the issuance of new mining permits or
modifications of existing mining permits. We know of no basis to
be, and are not, permit-blocked.
In 1983, the OSM adopted the stream buffer zone rule
(SBZ Rule), which prohibited mining disturbances
within 100 feet of streams if there would be a negative
effect on water quality. In December 2008, the OSM finalized a
revised SBZ Rule, which purported to clarify certain aspects of
the 1983 SBZ Rule. Several organizations challenged the 2008
revision to the SBZ Rule in two related actions filed in the
U.S. District Court for the District of Columbia. In June
2009, the Interior Department and the U.S. Army entered
into a memorandum of understanding on how to protect waterways
from degradation if the revised SBZ Rule were vacated due to the
litigation. In August 2009, the District Court concluded that
the revised SBZ Rule could not be vacated without following the
Administrative Procedure Act and other related requirements. In
November 2009, the OSM published an advanced notice of proposed
rulemaking to further revise the SBZ Rule. In a March 2010
settlement with litigation parties, OSM agreed to use its best
efforts to adopt a final rule by June 2012. The revised SBZ
Rule, when adopted, may be stricter than the SBZ Rule
promulgated in December 2008 in order to further protect streams
from the impacts of surface mining, and it may adversely affect
our business and operations. In addition, legislation has been
introduced in Congress in the past, and may be introduced in the
future, in an attempt to preclude placing any fill material in
streams. Implementation of new requirements or enactment of such
legislation could negatively impact our future ability to
conduct certain types of mining activities.
In addition to the bond requirement for an active or proposed
permit, the Abandoned Mine Land Fund (AML), which
was created by SMCRA, imposes a fee on all coal produced. The
proceeds of the fee are used to restore mines closed or
abandoned prior to SMCRAs adoption in 1977. The current
fee is $0.315 per ton of coal produced from surface mines and
$0.135 per ton on deep-mined coal from 2008 to 2012, with
reductions to $0.28 per ton on surface-mined coal and $0.12 per
ton on deep-mined coal from 2013 to 2021. In 2010, we recorded
approximately $1.3 million of expense related to these
reclamation fees.
Surety
Bonds
Federal and state laws require a mine operator to secure the
performance of its reclamation obligations required under SMCRA
through the use of surety bonds or other approved forms of
performance security to cover the costs the state would incur if
the mine operator were unable to fulfill its obligations. The
cost of surety bonds have fluctuated in recent years, and the
market terms of these bonds have generally become more
unfavorable to mine operators. For example, in connection with
our current bonds, we are required to post substantial security
in the form of cash collateral. These changes in the terms of
the bonds have been accompanied at times by a decrease in the
number of companies willing to issue surety bonds. Some mine
operators have therefore used letters of credit to secure the
performance of a portion of our reclamation obligations. Many of
these bonds are renewable on a yearly basis. We cannot predict
our ability to obtain bonds or other approved forms of
performance security, or the cost of such security, in the
future. As of September 30, 2011, we had approximately
$16.5 million in surety bonds outstanding to secure the
performance of our reclamation obligations which are
collateralized by cash deposits of 25% of the value of the bonds.
Mine
Safety and Health
Stringent health and safety standards have been in effect since
the enactment of the Federal Coal Mine Health and Safety Act of
1969. The Mine Act provided for MSHA and significantly expanded
the enforcement of safety and health standards and imposed
safety and health standards on all aspects of mining operations.
For example, it requires periodic inspections of surface and
underground coal mines and the issuance of citations or orders
for the violation of a mandatory health and safety standard. A
civil penalty must be assessed for each citation or order
issued. Serious violations of mandatory health and safety
standards may result in the issuance of an order requiring the
immediate withdrawal of miners from the mine or shutting down a
mine or any section of a mine or any piece of mine equipment.
The Mine Act also imposes criminal liability for corporate
operators who knowingly or willfully violate a mandatory health
and safety standard, or order and provides that civil and
criminal penalties may be assessed against individual agents,
officers and directors who knowingly or willfully violate a
mandatory health and safety standard or order. In addition,
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criminal liability may be imposed against any person for
knowingly falsifying records required to be kept under the Mine
Act and standards. In addition to federal regulatory programs,
the State of Kentucky in which we operate, also has programs for
mine safety and health regulation and enforcement. Collectively,
federal and state safety and health regulation in the coal
mining industry is among the most comprehensive systems for
protection of employee health and safety affecting any segment
of U.S. industry. Such regulation has a significant effect
on our operating costs.
In 2006, in response to underground mine accidents, Congress
enacted the MINER Act. Among other things, it (i) imposed
additional obligations on coal operators related to
(a) developing 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 of incidents that pose a
reasonable risk of death; and (ii) increased penalties for
violations of applicable federal laws and regulations. In
addition, in October, 2010, MSHA published a proposed rule to
reduce the permissible concentration of respirable dust in
underground coal mines from the current standard of 2.0
milligrams per cubic meter of air to 1.0 milligram per cubic
meter. We believe MSHA is also likely to adopt new safety
standards for proximity protection for miners that will require
certain underground mining equipment to be equipped with devices
that will shut the equipment down if a person is too close to
the equipment to avoid injuries where individuals are caught
between equipment and blocks of unmined coal. Various states
also have enacted their own new laws and regulations addressing
many of these same subjects. In the wake of several recent
underground mine accidents, enforcement scrutiny has also
increased, including more inspection hours at mine sites,
increased numbers of inspections and increased issuance of the
number and the severity of enforcement actions.
After the MINER Act, Illinois, Kentucky, Pennsylvania and West
Virginia enacted legislation addressing issues such as mine
safety and accident reporting, increased civil and criminal
penalties, and increased inspections and oversight. Other states
may pass similar legislation in the future. Additionally, in
2010, the 111th Congress introduced federal legislation seeking
to impose extensive additional safety and health requirements on
coal mining. While the legislation was passed by the House of
Representatives, the legislation was not voted on in the Senate
and did not become law. In January 2011, a similar bill was
reintroduced in the 112th Congress. Our compliance with current
or future mine health and safety regulations could increase our
mining costs. At this time, it is not possible to predict the
full effect that the new or proposed statutes, regulations and
policies will have on our operating costs, but they will
increase our costs and those of our competitors. Some, but not
all, of these additional costs may be passed on to customers.
We are required to compensate employees for work-related
injuries under various state workers compensation laws.
Our costs will vary based on the number of accidents that occur
at our mines and other facilities, and our costs of addressing
these claims. We provide benefits to our employees by being
insured through state-sponsored programs or an insurance carrier
where there is no state-sponsored program.
Black
Lung
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 pay federal black lung benefits to claimants
who are current and former employees and also make payments to a
trust fund for the payment of benefits and medical expenses to
eligible claimants who last worked in the coal industry prior to
January 1, 1970. 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. During 2010, we
recorded $4.2 million of expense related to this excise tax.
In December 2000, the Department of Labor amended regulations
implementing the federal black lung laws to, among other things,
establish a presumption in favor of a claimants treating
physician and limit a coal operators ability to introduce
medical evidence regarding the claimants medical
condition. Due to these changes, the number of claimants who are
awarded benefits has since increased, and will continue to
increase, as will the amounts of those awards. The Patient
Protection and Affordable Care Act (PPACA), which
was
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implemented in 2010, provided changes to the legal criteria used
to assess and award claims by creating a legal presumption that
miners are entitled to benefits if they have worked at least
15 years in coal mines and suffer from totally disabling
lung disease. A coal company would have to prove that a miner
did not have black lung or that the disease was not caused by
the miners work. Second, it changed the law so black lung
benefits being received by miners automatically go to their
dependent survivors, regardless of the cause of the miners
death. Our payment obligations for federal black lung benefits
to claimants entitled to such benefits are either substantially
secured by insurance coverage or paid from a tax exempt trust
established for that purpose. Based on actuarial reports and
required funding levels, from time to time we may have to
supplement the trust corpus to cover the anticipated liabilities
going forward. These regulations may have a material impact on
our costs expended in association with the federal Black Lung
program. In addition, we could be held liable under various
Kentucky statutes for black lung claims.
Coal
Industry Retiree Health Benefit Act of 1992
The Coal Industry Retiree Health Benefit Act of 1992 (Coal
Act) provides for the funding of health benefits for
certain United Mine Workers of America (UMWA),
retirees and their spouses or dependants. The Coal Act
established the Combined Benefit Fund into which employers who
are signatory operators are obligated to pay annual
premiums for beneficiaries. The Combined Benefit Fund covers a
fixed group of individuals who retired before July 1, 1976,
and the average age of the retirees in this fund is over
80 years of age. Because of our union-free status, we are
not required to make payments to retired miners under the Coal
Act. The Coal Act also created a second benefit fund, the 1992
UMWA Benefit Plan (1992 Plan), for miners who
retired between July 1, 1976 and September 30, 1994,
and whose former employers are no longer in business to provide
them retiree medical benefits. Companies with 1992 Plan
liabilities also pay premiums into this plan. We are not
required to pay any premiums into the 1992 Plan.
Clean
Air Act
The federal Clean Air Act and the amendments thereto and state
laws that regulate air emissions both directly and indirectly
affect coal mining operations. Direct impacts on our coal mining
and processing operations include Clean Air Act permitting
requirements and control requirements for particulate matter,
which includes fugitive dust from roadways, parking lots, and
equipment such as conveyors and storage piles. Our customers
also are subject to extensive air emissions requirements,
including those applicable to the air emissions of
SO2,
NOx, particulates, mercury and other compounds from coal-fired
electricity generating plants and industrial facilities that
burn coal. These requirements are complex, and are generally
becoming increasingly stringent as new regulations or revisions
to existing regulations are adopted. In addition, legal
challenges by environmental advocacy groups, affected members of
the regulated community, and others to regulations may impact
their content and the timing of their implementation.
More stringent air emissions requirements in future years may
increase the cost of producing and consuming coal and impact the
demand for coal. These requirements may result in an upward
pressure on the price of lower sulfur eastern coal, and more
demand for western coal, as coal-fired power plants continue to
comply with the more stringent restrictions initially focused on
SO2
emissions. As utilities continue to invest the capital to add
scrubbers and other devices to address emissions of NOx, mercury
and other hazardous air pollutants, demand for lower sulfur coal
may drop. However, we cannot predict these impacts with
certainty.
In June 2010, several environmental groups petitioned the EPA to
list coal mines as a source of air pollution and establish
emissions standards under the Clean Air Act for several
pollutants, including particulate matter, NOx, volatile organic
compounds and methane. Petitioners further requested that the
EPA regulate other emissions from mining operations, including
dust and clouds of NOx associated with blasting operations. If
the petitioners are successful, emissions of these or other
materials associated with our mining operations could become
subject to further regulation pursuant to existing laws such as
the Clean Air Act. In that event, we may be required to install
additional emissions control equipment or take other steps to
lower emissions associated with our operations, thereby reducing
our revenues and adversely affecting our operations.
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The Clean Air Act indirectly affects coal mining operations by
extensively regulating the emissions of particulate matter,
SO2,
NOx, carbon monoxide, ozone, mercury and other compounds emitted
by coal-fired power plants, which are the largest end users of
our coal. In addition to developments directed at limiting
greenhouse gas emissions, which are discussed separately further
below, air emission control programs that affect our operations,
directly or indirectly, include, but are not limited to, the
following:
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Acid Rain. Title IV of the Clean Air Act
requires reductions of
SO2
and NOx emissions by electric utilities regulated under the Acid
Rain Program (ARP). The ARP was designed to reduce
the electric power sector emissions of
SO2
and NOx and was implemented in two phases, Phase II of
which commenced in 2000 for both
SO2
and NOx.
SO2
emissions were controlled through the development of a national
market-based
cap-and-trade
system applicable to all coal-fired power plants with a capacity
of more than 25 megawatts, among other sources. Under the ARP, a
cap on annual
SO2
emissions is established and then EPA issues allowances to
regulated entities up to the cap using defined formulas. A small
percentage of the allowances are retained for auctions. Each
power plant must have enough allowances to cover all its annual
SO2
emissions or pay penalties. The electric power plant can choose
to reduce emissions and sell or bank the surplus allowances or
purchase allowances. Power plants are allowed to choose to emit
or control emissions, emission reductions are encouraged by
requiring an allowance to be retired every year for each ton of
SO2
emitted. Affected power plants have sought to reduce
SO2
emissions by switching to lower sulfur fuels, installing
pollution control devices, reducing electricity generating
levels or purchasing or trading
SO2
emissions allowances. The ARP makes it more costly to operate
coal-fired power plants and could make coal a less attractive
fuel alternative in the planning and building of power plants in
the future.
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New National Ambient Air Quality
Standards. The federal Clean Air Act requires the
EPA to determine and, where appropriate, from time to time
update ambient air quality standards applicable nationwide,
known as national ambient air quality standards
(NAAQSs) for six common air pollutants. Such
standards can have significant impacts on sources of such air
pollutants, particularly after such standards are tightened.
Although the NAAQSs do not apply directly to sources of such
pollutants, NAAQSs can result in sources having to meet
substantially stricter emissions limitations for such pollutants
upon renewal of their air permits, which commonly are issued for
five-year terms. Where an air quality management district has
not attained the NAAQS for such a pollutant (a
non-attainment area), sources may face more onerous
requirements regarding such a pollutant. Coal combustion
generates or affects several pollutants subject to NAAQSs,
including
SO2,
NO2,
ozone, and particulate matter, so when any such standard is made
stricter, it may indirectly affect our customers current
or anticipated future costs of using coal. In addition, NAAQSs
for particulate matter may affect aspects of our own operations,
which can generate such emissions. The EPA has revised
and/or
proposed to revise a number of such NAAQSs in recent years. For
example, in June 2010, the EPA issued a stricter NAAQS for
SO2
emissions which, among other things, establishes a new
1-hour
standard at a level of 75 parts per billion to protect against
short-term exposure and minimize health-based risks, revokes the
previous
24-hour and
annual standard for
SO2,
and imposes requirements for monitoring and reporting
SO2
concentrations. In February 2010, the EPA issued a stricter
NAAQS for NOx and in January 2010 also proposed a revised,
stricter ground-level ozone NAAQS. In addition, in 2006 the EPA
issued stricter NAAQSs for particulate matter and subsequently
has been implementing, and reviewing state implementation of,
those standards. While aspects of the EPAs rules
promulgating some of these standards or predecessor standards
have been, and in some instances remain, the subject of
litigation by industry representatives, environmental advocacy
groups, and others, and while EPA is reviewing aspects of some
of these NAAQSs, in important respects these NAAQSs
and/or their
implementation have become stricter, and may become more so due
to ongoing developments.
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Cross-State Air Pollution Rule. In July 2011,
the EPA promulgated the CSAPR, which replaces the EPAs
Clean Air Interstate Rule (CAIR), issued in 2005. A
decision in July 2008 by the U.S. Court of Appeals for the
District of Columbia Circuit concluded that CAIR should be
vacated and directed the EPA to develop a replacement. The
CSAPR, including a related proposed rulemaking that would revise
the CSAPR by subjecting six additional states to NOx emission
limits, requires additional
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reductions in
SO2
and NOx emissions from power plants in 27 states and
severely limits interstate emissions trading as a compliance
option. The CSAPR may result in many coal-fired sources
installing additional pollution control equipment for NOx and
SO2,
which we believe could lead plants with these controls to become
less sensitive to the sulfur-content of coal and more sensitive
to delivered price, thereby making high sulfur coal more
competitive. In December 2011, the U.S. Court of Appeals for the
District of Columbia Circuit issued a ruling to stay the CSAPR
pending judicial review.
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Mercury. In May 2011, the EPA formally
proposed its rule to establish a national standard to reduce
mercury and other toxic air pollutants from coal and oil-fired
power plants, sometimes referred to as the EPAs Mercury
and Air Toxics Standards (MATS) proposed rule. The
EPA is obligated to finalize the rule by November 2011, under a
consent decree of the U.S. Court of Appeals for the
District of Columbia Circuit in the proceeding that resulted in
that courts vacating the EPAs Clean Air Mercury Rule
(CAMR), which was issued in 2005 and had established
a cap and trade program to reduce mercury emissions from power
plants. At present, there are no federal regulations that
require monitoring and reducing of mercury emissions at existing
power plants. In the meantime,
case-by-case
MACT determinations for mercury may be required for new and
reconstructed coal-fired power plants. Apart from CAMR, several
states have enacted or proposed regulations requiring reductions
in mercury emissions from coal-fired power plants, and federal
legislation to reduce mercury emissions from power plants has
also been proposed from time to time. In addition, in March
2011, EPA issued new MACT determinations for several classes of
boilers and process heaters, including large coal-fired boilers
and process heaters, which would require significant reductions
in the emission of particulate matter, carbon monoxide, hydrogen
chloride, dioxins and mercury, although in May the effective
date of these rules for major sources was delayed for
reconsideration of certain aspects of the rule.
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Regional Haze. In 1999, the EPA issued a rule
in an effort to meet Clean Air Act requirements regarding a
nationwide regional haze program designed to protect and improve
visibility at and around 156 federal areas such as national
parks, national wilderness areas and international parks; this
rule was revised by another EPA rule issued in 2005. This
program may result in additional restrictions on emissions from
new coal-fired power plants whose operation may impair
visibility at and near such federally protected areas. This
program may also require certain existing coal-fired power
plants to install additional control measures designed to limit
haze-causing emissions, such as
SO2,
NOx, ozone and particulate matter. Insofar as this program
results in limitations on coal combustion in addition to those
that are otherwise applicable, it could also affect the future
market for coal, although we are unable to predict the extent of
any such impacts with any reasonable degree of certainty.
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New Source Review. A number of enforcement
actions in recent years are affecting the impact of the
EPAs New Source Review (NSR) program as
applied to some existing sources, including certain coal-fired
power plants. The NSR program requires existing coal-fired power
plants, when undertaking certain modifications, to install the
same air emissions control equipment as new plants. Enforcement
proceedings alleging that such modifications were made without
implementing the required control equipment have resulted in a
number of settlements involving commitments, including those by
coal-fired power plants, to incur extensive air emissions
controls involving substantial expenses. Such enforcement, and
other changes affecting the scope or interpretation of aspects
of the NSR program, may impact demand for coal, but we are
unable to predict the magnitude of any such impact on us with
any reasonable degree of certainty.
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Climate
Change
CO2
is a greenhouse gas, the man-made emissions of which
are of major concern under any regulatory framework intended to
control what is sometimes referred to as global
warming or, due to other possible impacts on climate that
many policy-makers and scientists believe such warming may have,
climate change.
CO2
is a major by-product of the combustion process within
coal-fired power plants. Methane, which must be expelled from
our underground coal mines for mining safety reasons, also is
classified as a greenhouse gas; although estimates may vary, it
is generally considered to have a greenhouse gas impact many
times that of an equivalent amount of
CO2.
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Considerable and increasing government attention in the United
States and other countries is being paid to reducing greenhouse
gas emissions, including
CO2
from coal-fired power plants and methane emissions from mining
operations. In 2005, the Kyoto Protocol to the 1992 United
Nations Framework Convention on Climate Change, which
establishes a binding set of emission targets for greenhouse
gases, became binding on all those countries that had ratified
it. To date, the U.S. has not ratified the Kyoto Protocol,
which expires in 2012. The United States is participating in
international discussions currently underway to develop a treaty
to replace the Kyoto Protocol after its expiration in 2012. A
replacement treaty or other international arrangement requiring
additional reductions in greenhouse gas emissions could have a
potentially significant impact on the demand for coal,
particularly if the United States were to adopt it but,
depending on the requirements it imposes and the extent to which
other nations adopt it, even if the United States does not
adopt it.
Future regulation of greenhouse gases in the United States could
occur pursuant to, for example, future U.S. treaty
commitments; new domestic legislation that imposes a tax on
greenhouse gas emissions, a greenhouse gas
cap-and-trade
program or other programs aimed at greenhouse gas reduction; or
regulatory programs that may be established by the EPA under its
existing authority. Congress has actively considered various
proposals to reduce greenhouse gas emissions, mandate
electricity suppliers to use renewable energy sources to
generate a certain percentage of power, promote the use of clean
energy and require energy efficiency measures. In June 2009, the
House of Representatives passed a comprehensive climate change
and energy bill, the American Clean Energy and Security Act, and
the Senate has considered similar legislation that would, among
other things, impose a nationwide cap on greenhouse gas
emissions and require major sources, including coal-fired power
plants, to obtain allowances to meet that cap.
Passage of such comprehensive climate change or energy
legislation could impact the demand for coal. Any reduction in
the demand for coal by North American electric power generators
could reduce the price of coal that we mine and sell and thereby
reduce our revenues, which could have a material adverse affect
on our business and the results of our operations.
Even in the absence of new federal legislation, greenhouse gas
emissions may be regulated in the future by the EPA pursuant to
the Clean Air Act. In response to the 2007 U.S. Supreme
Court ruling in Massachusetts v. Environmental Protection
Agency that the EPA has authority to regulate greenhouse gas
emissions under the Clean Air Act, the EPA has taken several
steps towards implementing regulations regarding greenhouse gas
emissions. In December 2009, the EPA issued a finding that
CO2
and certain other greenhouse gases emitted by motor vehicles
endanger public health and the environment. This finding allows
the EPA to begin regulating greenhouse gas emissions under
existing provisions of the Clean Air Act. In October 2009, the
EPA published a final rule requiring certain emitters of
greenhouse gases, including coal-fired power plants, to monitor
and report their greenhouse gas emissions to the EPA beginning
in 2011 for emissions occurring in 2010. In May 2010, the EPA
issued a final tailoring rule that determines which
stationary sources of greenhouse emissions need to obtain a
construction or operating permit, and install best available
control technology for greenhouse gas emissions, under the Clean
Air Acts Prevention of Significant Deterioration or
Title V programs when such facilities are built or
significantly modified. Without the tailoring rule, permits
would have been required for stationary sources with emissions
that exceed either 100 or 250 tons per year (depending on the
type of source), which the EPA considered not feasible. The
tailoring rule substantially increases this threshold for
greenhouse gas emissions to 75,000 tons per year beginning in
January 2011, and further modifies the threshold after July
2011; the EPA has stated that the rule will be limited to the
largest greenhouse gas emitters in the United States, primarily
power plants, refineries, and cement production facilities that
the EPA estimates are responsible for nearly 70% of greenhouse
gas emissions from the countrys stationary sources. The
tailoring rule also commits the EPA to undertake and complete
another rulemaking by no later than July 2012 to, among other
things, consider expanding permitting requirements to sources
with greenhouse gas emissions greater than 50,000 tons per year.
A number of lawsuits have been filed challenging the tailoring
rule. The final outcome of federal legislative action on
greenhouse gas emissions may change one or more of the foregoing
final or proposed EPA findings and regulations. If the EPA were
to set emission limits or impose additional permitting
requirements for
CO2
from coal-fired power plants, the amount of coal our customers
purchase from us could decrease.
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Many states and regions have adopted greenhouse gas initiatives
and certain governmental bodies have or are considering the
imposition of fees or taxes based on the emission of greenhouse
gases by certain facilities. For example, beginning in January
2009, the Regional Greenhouse Gas Initiative (RGGI),
a regional greenhouse gas
cap-and-trade
program, began its first control period, operating with ten
Northeastern and mid-Atlantic states (Connecticut, Delaware,
Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New
York, Rhode Island and Vermont). The RGGI program has had
several emission allowances auctions and will enter its second
three-year control period in 2012. The RGGI program calls for
signatory states to stabilize
CO2
emissions to current levels from 2009 to 2015, followed by a
2.5% reduction each year from 2015 through 2018. Since RGGI was
first proposed, the states formally participating and observing
have varied somewhat; recently politicians in several states
have taken formal steps (including an announcement by New
Jerseys governor, and a bill passed by New
Hampshires legislature but vetoed by its governor) to
withdraw from RGGI. RGGI has been holding quarterly
CO2
allowance auctions for its initial three-year compliance period
from January 1, 2009 to December 31, 2011 to allow
utilities to buy allowances to cover their
CO2
emissions. Midwestern states and Canadian provinces have also
adopted initiatives to reduce and monitor greenhouse gas
emissions. In November 2007, Illinois, Iowa, Kansas, Michigan,
Minnesota, South Dakota and Wisconsin signed the Midwestern
Greenhouse Gas Reduction Accord to develop and implement steps
to reduce greenhouse gas emissions; also, Indiana, Ohio and
Manitoba signed as observers. Draft recommendations were
released in June 2009, although they have not been finalized.
Climate change initiatives are also being considered or enacted
in some western states.
Also, litigation to address climate change impacts is being
pursued against major emitters of greenhouse gases. A federal
appeals court allowed a lawsuit pursuing federal common law
claims to proceed against certain utilities on the basis that
they may have created a public nuisance due to their emissions
of
CO2;
while the United States Supreme Court recently reversed the
appeals court, it did not reach the question whether state
common law is available for such claims because that question
had not been addressed by the lower court. A second federal
appeals court had earlier dismissed a case seeking damages
allegedly caused by climate change that had been filed against
scores of large corporate defendants, including a number of
electrical power generating companies and coal companies, but
the dismissal was on procedural grounds; the case has since been
re-filed. Claims seeking remedies to address conditions or
losses allegedly caused by climate change that in turn allegedly
has resulted from greenhouse gas-generating conduct by the
defendants remain pending in the courts. Such claims could
continue to be asserted against our customers in the future, and
might also be asserted against us; accordingly, such claims
could adversely affect us either directly or indirectly.
In addition to direct regulation of greenhouse gases, over
30 states have adopted mandatory renewable portfolio
standards, which require electric utilities to obtain a
certain percentage of their electric generation portfolio from
renewable resources by a certain date. These standards range
generally from 10% to 30%, over time periods that generally
extend from the present until between 2020 and 2030. Several
other states have renewable portfolio standard goals that are
not yet legal requirements. Additional states may adopt similar
goals or requirements, and federal legislation has been
repeatedly proposed in this area although no bills imposing such
requirements have been enacted into law to date. To the extent
these requirements affect our current and prospective customers,
their demand for coal-fueled power may decline, which may reduce
long-term demand for our coal.
These and other current or future climate change rules, court
orders or other legally enforceable mechanisms may in the future
require, additional controls on coal-fired power plants and
industrial boilers and may cause some users of coal to switch
from coal to lower greenhouse gas emitting fuels or shut-down
coal-fired power plants. There can be no assurance at this time
that a greenhouse gas cap and trade program, a greenhouse gas
tax or other regulatory regime, if implemented by the states in
which our customers operate or at the federal level, or future
court orders or other legally enforceable mechanisms, will not
affect the future market for coal in those regions. The
permitting of new coal-fired power plants has also recently been
contested by some state regulators and environmental
organizations based on concerns relating to greenhouse gas
emissions. Increased efforts to control greenhouse gas emissions
could result in reduced demand for coal. If mandatory
restrictions on greenhouse gas emissions are imposed, the
ability to capture and store large
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volumes of
CO2
emissions from coal-fired power plants may be a key mitigation
technology to achieve emissions reductions while meeting
projected energy demands. A number of recent legislative and
regulatory initiatives to encourage the development and use of
carbon capture and storage (CCS) technology have
been proposed or enacted. For example, the U.S. Department
of Energy announced in May 2009 that it would provide
$2.4 billion of federal stimulus funds under the American
Recovery and Reinvestment Act of 2009 to expand and accelerate
the commercial deployment of large-scaled CCS technology.
However, there can be no assurances that cost-effective CCS
technology will become commercially feasible in the near future,
or at all.
Clean
Water Act
The Clean Water Act of 1972 (CWA) and corresponding
state and local laws and regulations affect coal mining
operations by restricting the discharge of pollutants, including
the discharge of dredged or fill materials, into waters of the
United States. The CWA provisions and associated state and
federal regulations are complex and subject to amendments, legal
challenges and changes in implementation. Recent court
decisions, regulatory actions and proposed legislation have
created uncertainty over CWA jurisdiction and permitting
requirements that could either increase or decrease our costs
and time spent on CWA compliance.
CWA requirements that may directly or indirectly affect our
operations include the following:
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Wastewater Discharge. Section 402 of the
CWA regulates the discharge of pollutants into
navigable waters of the United States. The National Pollutant
Discharge Elimination System (NPDES) requires a
permit for any such discharges and entails regular monitoring,
reporting and compliance with performance standards, all of
which are preconditions for the issuance and renewal of NPDES
permits that govern the discharge of pollutants into water.
Failures to comply with the CWA or the NPDES permits can lead to
the imposition of penalties, compliance costs and delays in coal
production. The CWA and corresponding state laws also protect
waters that states have designated for special protections
including those designated as: impaired (i.e., as not meeting
present water quality standards) through Total Maximum Daily
Load (TMDL) regulations and high
quality/exceptional use streams through anti-degradation
regulations which restrict or prohibit discharges which result
in degradation. Likewise, when water quality in a receiving
stream is better than required, states are required to adopt an
anti-degradation policy by which further
degradation of the existing water quality is
reviewed and possibly limited. In the case of both the TMDL and
anti-degradation review, the limits in our NPDES discharge
permits could become more stringent, thereby potentially
increasing our treatment costs and making it more difficult to
obtain new surface mining permits. Other requirements may result
in obligations to treat discharges from coal mining properties
for non-traditional pollutants, such as chlorides, selenium and
dissolved solids; and to take measures intended to protect
streams, wetlands, other regulated water sources and associated
riparian lands from surface mining
and/or the
surface impacts of underground mining. Individually and
collectively, these requirements may cause us to incur
significant additional costs that could adversely affect our
operating results, financial condition and cash flows.
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Dredge and Fill Permits. Many mining
activities, including the development of settling ponds and
other impoundments, may require a Section 404 permit from
the Corps, prior to conducting such mining activities where they
involve discharges of fill into navigable waters of
the United States. The Corps is empowered to issue
nationwide permits for specific categories of
filling activities that are determined to have minimal
environmental adverse effects in order to save the cost and time
of issuing individual permits under Section 404 of the CWA.
Using this authority, the Corps issued NWP 21, which authorizes
the disposal of
dredge-and-fill
material from mining activities into the waters of the United
States. Individual Section 404 permits are required for
activities determined to have more significant impacts to waters
of the United States.
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Since 2003, environmental groups have pursued litigation
primarily in West Virginia and Kentucky challenging the validity
of NWP 21 and various individual Section 404 permits
authorizing valley fills associated with surface coal mining
operations (primarily mountain-top removal operations). This
litigation has resulted in delays in obtaining these permits and
has increased permitting costs. The most
117
recent major decision in this line of litigation is the opinion
of the U.S. Court of Appeals for the Fourth Circuit in Ohio
Valley Environmental Council v. Aracoma Coal Company, 556
F.3d 177 (2009) (Aracoma), issued in February 2009. In Aracoma,
the Court rejected all of the substantive challenges to the
Section 404 permits involved in the case primarily by
deferring to the expertise of the Corps in review of the permit
applications. After this decision was published, however, the
EPA undertook several initiatives to address the issuance of
Section 404 permits for coal mining activities in the
Eastern U.S. First, the EPA began to comment on
Section 404 permit applications pending before the Corps
raising many of the same issues decided in favor of the coal
industry in Aracoma. Many of the EPAs comment letters were
submitted long after the end of the EPAs comment period
based on what the EPA contended was new information
on the impacts of valley fills on stream water quality
immediately downstream of valley fills. These letters have
created regulatory uncertainty regarding the issuance of
Section 404 permits for coal mining operations and have
substantially expanded the time required for issuance of these
permits, particularly in the Appalachian region.
In June 2009, the Corps, the EPA and the Department of the
Interior announced an interagency action plan for enhanced
coordination procedures in reviewing any project that
requires both a SMCRA and a CWA permit, designed to reduce the
harmful environmental consequences of mountain-top mining in the
Appalachian region. As part of this interagency memorandum of
understanding, the Corps proposed to suspend and modify NWP 21
in the Appalachian region of Kentucky, Ohio, Pennsylvania,
Tennessee, Virginia and West Virginia to prohibit its use to
authorize discharges of fill material into waters of the United
States for mountain-top mining.
In June 2010, the Corps announced the suspension of the NWP 21
permitting process in the Appalachian region of the six states
referred to above until the Corps takes further action on NWP
21, or until NWP 21 expires on March 18, 2012. While the
suspension is in effect, proposed surface coal mining projects
in the Appalachian region of these states that involve
discharges of dredged or fill material into waters of the United
States will have to obtain individual permits from the Corps.
Projects currently permitted under NWP 21 are not affected by
the suspension, and NWP 21 remains available for proposed
surface coal mining projects outside the Appalachian region.
The EPA is also taking a more active role in its review of NPDES
permit applications for coal mining operations in Appalachia,
and announced in September 2009 that it was delaying the
issuance of 74 Section 404 permits in central Appalachia.
This is especially true in West Virginia, where the EPA plans to
review all applications for NPDES permits even though the State
of West Virginia is authorized to issue NPDES permits in West
Virginia. In addition, in April 2010, the EPA issued an interim
guidance document on water quality requirements for coal mines
in Appalachia. This guidance follows up on the June 2009
enhanced coordination procedures memorandum for the issuance of
Section 404 permits whereby the EPA undertook a new level
of review of Section 404 permits than it had previously
undertaken. Ultimately, the EPA identified 79 coal-related
applications for Section 404 permits that would need to go
through that process. The EPAs actions in issuing the
enhanced coordination procedures memorandum and the guidance are
being challenged in a lawsuit pending before the
U.S. District Court of the District of Columbia in a case
captioned National Mining Assoc. v. U.S. Environmental
Protection Agency. In a ruling issued in January 2011, the
District Court held that these measures are legislative
rules that were adopted in violation of notice and comment
requirements. The court would not grant the motion for a
preliminary injunction to enjoin further use of these measures
but also refused to dismiss the Complaint as the EPA had sought.
In July 2011, after a notice and comment process, the EPA issued
final guidance on review of Appalachian surface coal mining
operations that replaced the interim guidance it had issued in
April 2010.
In January 2011 the EPA exercised its veto power
under Section 404(c) of the CWA to withdraw or restrict the
use of previously issued permits in connection with the Spruce
No. 1 Surface Mine in West Virginia, which is one of the
largest surface mining operations ever authorized in Appalachia.
This action is the first time that such power was exercised with
regard to a previously permitted coal mining project. These
initiatives have extended the time required for operations
affected by them to obtain permits for coal mining, and the
costs associated with obtaining and complying with those permits
may
118
increase substantially. Additionally, while it is unknown
precisely what other future changes will be implemented as a
result of the interagency action plan, any future changes could
further restrict our ability to obtain other new permits or to
maintain existing permits.
Section 404(q) of the CWA establishes a requirement that
the Secretary of the Army and the Administrator of the EPA enter
into an agreement assuring that delays in the issuance of
permits under Section 404 are minimized. In August 1992,
the Department of the Army and the EPA entered into such an
agreement. The 1992 Section 404(q) Memorandum of Agreement
(MOA) outlines the current process and time frames
for resolving disputes in an effort to issue timely permit
decisions. Under this MOA, the EPA may request that certain
permit applications receive a higher level of review within the
Department of Army. In these cases, the EPA determines that
issuance of the permit will result in unacceptable adverse
effects to Aquatic Resources of National Importance
(ARNI). Alternately, the EPA may raise concerns over
Section 404 program policies and procedures. An ARNI is a
resource-based threshold used to determine whether a dispute
between the EPA and the Corps regarding individual permit cases
are eligible for elevation under the MOA. Factors used in
identifying ARNIs, include the economic importance of the
aquatic resource, rarity or uniqueness,
and/or
importance of the aquatic resource to the protection,
maintenance, or enhancement of the quality of the waters.
We received notice from the EPA dated July 25, 2011 that it
believes that the proposed discharge plan submitted by us in
connection with our Section 404 permit application for the
expanded mining at our Midway Mine would result in unacceptable
impacts on ARNIs, and in particular, downstream waters outside
the scope of the permit area. As a result, it is possible that
the Corps will deny our pending permit application, or that the
EPA will elevate the permit application to a higher level of
review should the Corps proceed with the issuance of the permit
notwithstanding EPAs concerns. Ultimately, the EPA may
consider initiating a Section 404(c) veto of
the permit. A material delay in the issuance of this permit, or
other Section 404 permits that we may require as part of
our mining operations, or the denial or veto of such permits,
could have a materially negative effect on our operations and
profitability.
Other
Regulations on Stream Impacts
Federal and state laws and regulations can also impose measures
to be taken to minimize
and/or avoid
altogether stream impacts caused by both surface and underground
mining. Temporary stream impacts from mining are not uncommon,
but when such impacts occur there are procedures we follow to
mitigate or remedy any such impacts. These procedures have
generally been effective and we work closely with applicable
agencies to implement them. Our inability to mitigate or remedy
any temporary stream impacts in the future, and the application
of existing or new laws and regulations to disallow any stream
impacts, could adversely affect our operating and financial
results.
Resource
Conservation and Recovery Act
The Resource Conservation and Recovery Act (RCRA)
was enacted in 1976 to establish requirements for the management
of hazardous wastes from the point of generation through
treatment and disposal. RCRA does not apply to certain wastes
generated at coal mines, such as overburden and coal cleaning
wastes, because they are not considered hazardous wastes as the
EPA applies that term. Only a small portion of the wastes
generated at a mine are regulated as hazardous wastes.
Although RCRA has the potential to apply to wastes from the
combustion of coal, the EPA determined in 1993 with respect to
certain coal combustion wastes, and in May 2000 with respect to
others, that coal combustion wastes do not warrant regulation as
hazardous wastes under RCRA. Most state solid waste laws also
regulate coal combustion wastes as non-hazardous wastes. In May
2010, the EPA issued proposed regulations governing management
and disposal of coal ash from coal-fired power plants. The EPA
sought public comment on two regulatory options. Under the more
stringent option, the EPA would regulate coal ash as a
special waste subject to hazardous waste standards
when disposed in landfills or surface impoundments, which would
be subject to stringent design, permitting, closure and
corrective action requirements. Alternatively, coal ash would be
regulated as non-hazardous waste under RCRA subtitle D, with
national minimum criteria for disposal
119
but no federal permitting or enforcement. Under both options,
the EPA would establish dam safety requirements to address the
structural integrity of surface impoundments to prevent
catastrophic releases. The EPA is expected to issue a final
decision by the end of 2011. The EPA did not address in the
proposed regulations the use of coal combustion wastes as
minefill, but indicated that it would separately work with the
Office of Surface Mining in order to develop effective federal
regulations ensuring that such placement is adequately
controlled. If coal ash from coal-fired power plants is
re-classified as hazardous waste, regulations may impose
restrictions on ash disposal, provide specifications for storage
facilities, require groundwater testing and impose restrictions
on storage locations, which could increase our customers
operating costs and potentially reduce their ability to purchase
coal. If coal ash is regulated under RCRA subtitle D, it could
also adversely affect our customers and potentially reduce the
desirability of coal for them. In addition, contamination caused
by the past disposal of coal combustion byproducts, including
coal ash, can lead to material liability to our customers under
RCRA or other federal or state laws and potentially reduce the
demand for coal.
Comprehensive
Environmental Response, Compensation and Liability
Act
The Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA or Superfund), and
similar state laws affect coal mining operations by, among other
things, imposing cleanup requirements for threatened or actual
releases of hazardous substances. Under CERCLA and similar state
laws, joint and several liability may be imposed on waste
generators, site owners, lessees and others regardless of fault
or the legality of the original disposal activity. Although the
EPA excludes most wastes generated by coal mining and processing
operations from the hazardous waste laws, such wastes can, in
certain circumstances, constitute hazardous substances for the
purposes of CERCLA. In addition, the disposal, release or
spilling of some products used by coal companies in operations,
such as chemicals, could trigger the liability provisions of
CERCLA or similar state laws. Thus, we may be subject to
liability under CERCLA and similar state laws for coal mines
that we currently own, lease or operate, and sites to which we
have sent waste materials. We are currently unaware of any
material liability associated with the release or disposal of
hazardous substances from our mine sites. We may be liable under
CERCLA or similar state laws for the cleanup of hazardous
substance contamination and natural resource damages at sites
where we own surface rights.
Endangered
Species Act
The federal Endangered Species Act (ESA) and
counterpart state legislation protect species threatened with
possible extinction. The U.S. Fish and Wildlife Service
(USFWS), works closely with the OSM and state
regulatory agencies to ensure that species subject to the ESA
are protected from mining-related impacts. A number of species
indigenous to the areas in which we operate are protected under
the ESA, and compliance with ESA requirements could have the
effect of prohibiting or delaying us from obtaining mining
permits. These requirements may also include restrictions on
timber harvesting, road building and other mining or
agricultural activities in areas containing the affected species
or their habitats. Should more stringent protective measures be
applied, this could result in increased operating costs,
heightened difficulty in obtaining future mining permits, or the
need to implement additional mitigation measures.
Use of
Explosives
We use third party contractors for blasting services and our
surface mining operations are subject to numerous regulations
relating to blasting activities. Pursuant to these regulations,
we incur costs to design and implement blast schedules and to
conduct pre-blast surveys and blast monitoring. In addition, the
storage of explosives is subject to regulatory requirements. We
presently do not directly engage in blasting activities;
instead, all of our blasting activities are conducted by
independent contractors that use certified blasters.
Other
Environmental Laws and Matters
We and our customers are subject to and are required to comply
with numerous other federal, state and local environmental laws
and regulations in addition to those previously discussed which
place stringent requirements on our coal mining and other
operations as well as the ability of our customers to use coal.
Federal, state and local regulations also require regular
monitoring of our mines and other facilities to ensure
120
compliance with these many laws and regulations. Some of these
additional laws and regulations include, for example, the Safe
Drinking Water Act, the Toxic Substance Control Act and the
Emergency Planning and Community
Right-to-Know
Act.
Other
Facilities
We currently lease office space for our headquarters in
St. Louis, Missouri, as well as our regional office in
Madisonville, Kentucky. We believe our properties are sufficient
for our current needs.
121
MANAGEMENT
Executive
Officers and Directors
Set forth below are the names, ages and positions of our
executive officers and directors as of January 31, 2012.
All directors are elected for a term of three years and serve
until their successors are elected and qualified. All executive
officers hold office until their successors are elected and
qualified.
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Name
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Age
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Position with the Company
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J. Hord Armstrong, III
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70
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Chairman (Class II) and Chief Executive Officer
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Martin D. Wilson
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50
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President and Director (Class I)
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Kenneth E. Allen
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65
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Executive Vice President of Operations
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David R. Cobb, P.E.
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63
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Executive Vice President of Business Development
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J. Richard Gist
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55
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Senior Vice President, Finance and Administration and Chief
Financial Officer
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Brian G. Landry
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55
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Vice President, Information Technology
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Anson M. Beard, Jr.
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75
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Director (Class I)
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James C. Crain
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63
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Director (Class III)
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Richard F. Ford.
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75
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Director (Class III)
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Bryan H. Lawrence
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69
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Director (Class III)
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Greg A. Walker.
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56
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Director (Class II)
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Biographical information concerning the directors and executive
officers listed above is set forth below. The term of our
Class I directors expires in 2012, the term of our
Class II directors expires in 2013, and the term of our
Class III directors expires in 2014.
J. Hord Armstrong, III
Mr. Armstrong served as our Predecessors Chairman and
Chief Executive Officer, and as a member of our
Predecessors board of managers, from its formation in 2006
until the Reorganization in October 2011. Since the
Reorganization, Mr. Armstrong has been our Chairman and
Chief Executive Officer. Previously, Mr. Armstrong worked
for the Morgan Guaranty Trust Company and was elected
Assistant Treasurer in 1967. He subsequently spent 10 years
with White Weld & Company as First Vice President
until the firm was acquired by Merrill Lynch in 1978.
Mr. Armstrong then joined Arch Mineral Corporation,
St. Louis, as Treasurer
(1978-1981),
and ultimately became its Vice President and Chief Financial
Officer
(1981-1987).
Mr. Armstrong left Arch Mineral in 1987, when he founded
D&K Healthcare Resources. Mr. Armstrong served as
D&Ks Chief Executive Officer from 1987 to 2005.
D&K Healthcare Resources became a public company in 1992
and was acquired by McKesson Corporation in 2005.
Mr. Armstrong served for 10 years as a member of the
Board of Trustees of the St. Louis College of Pharmacy, as
well as a Director of Jones Pharma Incorporated. He was formerly
Chairman of the Board of Trustees of the Pilot Fund, a
registered investment company. He was also formerly a Director
of BHA, Inc. of Kansas City, Missouri, and a Director of GeoMet,
Inc. of Houston, Texas. He currently serves as Advisory Director
of US Bancorp. The board selected Mr. Armstrong to
serve as a director because of his extensive experience in the
coal industry and public company management, as well as his
previous tenure with our company. The board believes his prior
experiences afford him unique insights into our companys
strategies, challenges and opportunities.
Martin D. Wilson Mr. Wilson served as
our Predecessors President, and as a member of our
Predecessors board of managers, from its formation in 2006
until the Reorganization in October 2011. Since the
Reorganization, Mr. Wilson has been our President. From
1985 to 1988, Mr. Wilson was employed by KPMG Peat Marwick.
From 1988 until 2005, Mr. Wilson served as President and
Chief Operating Officer of D&K Healthcare Resources.
Mr. Wilson currently serves on the Board of Trustees of the
St. Louis College of Pharmacy and is a former member of the
Board of Directors of Healthcare Distribution Management
Association (HDMA). The board selected Mr. Wilson to serve
as a director because of his experience in public company
management, finance and administration, as well as for his
in-depth knowledge of our company.
122
Kenneth E. Allen Mr. Allen served as our
Predecessors Vice President of Operations from 2007 until
the Reorganization in October 2011. Since the Reorganization,
Mr. Allen has been our Executive Vice President of
Operations. He started his career with Peabody Coal Company in
1967 and has over 40 years of experience in the coal
industry. In 1971, he moved into a supervisory position and
continued to hold various supervisory and management positions,
including Chief Electrical Engineer, Mine Superintendent,
General Manager, Operations Manager, Vice President Resource
Development and Conservancy. Prior to joining our company in
2007, Mr. Allen held the position of President and
Operations Manager of Bluegrass Coal Company, a subsidiary of
Peabody Energy. Mr. Allen is Chairman of the Upper Pond
River Conservancy District, Chairman of Cedar West Inc., and
member of the Madisonville Community College Energy Advisory
Committee. He is a past member of the Kentucky Coal Counsel, the
Kentucky Governors Finance Committee, and Kentucky Consortium
for Energy and the Environment. He is past Chairman and current
member of the Executive Boards of the Kentucky Coal Association
and the Western Kentucky Coal Association.
David R. Cobb, P.E. Mr. Cobb served as
our Predecessors Vice President of Business Development
since its inception in 2006 until the Reorganization in October
2011. Since the Reorganization, Mr. Cobb has been our
Executive Vice President of Business Development. He has over
40 years of experience in the coal business, beginning with
AMAX Coal Company, where he served as a Resident Mine Engineer,
Administrative Engineer, and Southern Division Engineer. In
1975, he joined Danco Engineering, a mine consulting firm
located in Western Kentucky, serving as a Principal Engineer and
later becoming its owner and President. Danco was acquired by
Associated Engineers, Inc. in 2005. Mr. Cobb stayed on as
the Director of Mining Services until joining our company in
2006. Mr. Cobb is registered in the fields of Civil and
Mining Engineering and is licensed as a Professional Engineer in
Kentucky, Indiana, and Illinois along with being a Certified
Fire and Explosion Investigator. Mr. Cobb is a member of
the Society of Mining Engineers, the National and Kentucky
Societies of Professional Engineers, the American Society of
Civil Engineers, the American Society of Surface Mining and
Reclamation, and the National Association of Fire Investigators.
J. Richard Gist Mr. Gist served as
our Predecessors Vice President and Controller from 2009
until the Reorganization in October 2011. Since the
Reorganization, Mr. Gist has been our Senior Vice
President, Finance and Administration and Chief Financial
Officer. Mr. Gist began his career with Arthur Andersen in
1978 and subsequently held a number of positions at St. Joe
Minerals, an entity which owned part of Massey Energy, NERCO,
Ziegler Coal and Peabody Energy. From 2000 until its purchase by
McKesson Corporation in 2005, Mr. Gist was the Vice
President and Controller of D&K Healthcare Resources. From
2005 until 2006, Mr. Gist worked as part of the transition
team with McKesson. From 2006 until 2009, he served as Vice
President Marketing Administration of Arch Coal.
Mr. Gist is a Certified Public Accountant.
Brian G. Landry Mr. Landry served as our
Predecessors Vice President, Information Technology from
2010 until the Reorganization in October 2011. Since the
Reorganization, Mr. Landry has been our Vice President,
Information Technology. From 2007 until 2010, Mr. Landry
served as Senior Vice President of Information Technology of
H.D. Smith Drug Company. Prior to that, Mr. Landry spent
10 years with D&K Healthcare Resources, Inc.,
ultimately serving as its Senior Vice President of Operations
and Chief Information Officer.
Anson M. Beard, Jr. Mr. Beard was
appointed to our board in October 2011. He joined Morgan
Stanley & Co. as a Vice President to found Private
Client Services in 1977. He was promoted to Principal in 1979
and Managing Director in 1980. In January 1981, he was put in
charge of the Firms Equity Division, responsible for sales
and trading relationships with institutional and individual
investors of all equity and related products worldwide. In 1987,
he was elected to the Firms Management Committee and the
Board of Directors of Morgan Stanley Group. Mr. Beard was
also the former Chairman of Morgan Stanley Security Services,
Inc., a subsidiary of Morgan Stanley Group, which engaged in
stock borrowing/lending, customer and dealer clearance,
international settlements and custody. He previously served as a
Trustee of the Morgan Stanley Foundation, Vice Chairman of the
National Association of Securities Dealers, and Chairman of its
NASDAQ, Inc. subsidiary. In February 1994, Mr. Beard
retired and became an Advisory Director of Morgan Stanley. He
continues to serve in this capacity. Mr. Beard was selected
for board membership because of his past board and committee
experience and his knowledge of securities markets and publicly
traded companies.
123
James C. Crain Mr. Crain was appointed
to our board of directors in October 2011. Mr. Crain has
been in the energy industry for over 30 years, both as an
attorney and as an executive officer. Since 1984, Mr. Crain
has been an officer of Marsh Operating Company, an investment
management company focusing on energy investing, including his
current position as president, which he has held since 1989.
Mr. Crain has served as general partner of Valmora
Partners, L.P., a private investment partnership that invests in
the oil and gas sector, among others, since 1997. Before joining
Marsh in 1984, Mr. Crain was a partner in the law firm of
Jenkens & Gilchrist, where he headed the firms
energy section. Mr. Crain is a director of Crosstex Energy,
Inc., a midstream natural gas company, GeoMet, Inc., a natural
gas exploration and production company, and Approach Resources,
Inc., an independent oil and natural gas company. During the
past five years, Mr. Crain has also been a director of
Crosstex Energy, GP, LLC, the general partner of a midstream
natural gas company, and Crusader Energy Group Inc., an oil and
gas exploration and production company. The board selected
Mr. Crain to serve as a director because of his extensive
legal, investment and transactional experience, as well as his
public company board experience.
Richard F. Ford Mr. Ford was appointed
to our board in October 2011. Mr. Ford is the retired
general partner of Gateway Associates, L.P., a venture capital
management firm that he formed in 1984. Mr. Ford serves as
a member of the board of directors and a member of the audit
committees of each of Barry-Wehmiller Company and Stifel
Financial Corp. Mr. Ford also serves as a member of the
board of directors and chair of the audit committee of Spartan
Light Metal Products, Inc., a privately-held company. He
currently serves on the board of directors of Washington
University in St. Louis, Missouri. The board selected
Mr. Ford to serve as a director because of his substantial
experience in the financial services industry. He also has
considerable board and committee leadership experience at other
publicly held and large private companies.
Bryan H. Lawrence Mr. Lawrence served as
a member of our Predecessors board of managers from its
formation in 2006 until the Reorganization. He was appointed to
our board of directors in October 2011. He is a founder and
principal of Yorktown Partners, LLC, the manager of the Yorktown
group of investment partnerships, which make investments in
companies engaged in the energy industry. The Yorktown
partnerships were formerly affiliated with the investment firm
of Dillon, Read & Co., Inc. where Mr. Lawrence
had been employed since 1966, serving as a Managing Director
until the merger of Dillon Read with SBC Warburg in September
1997. Mr. Lawrence serves as a director of Crosstex Energy,
Inc., Crosstex Energy GP, LLC, Hallador Energy Company, Star Gas
Partners, L.P., and Approach Resources, Inc. (each a United
States publicly traded company) and Winstar Resources, Ltd., (a
Canadian public company) and certain non-public companies in the
energy industry in which Yorktown partnerships hold equity
interests. Mr. Lawrence serves on our board of directors
because of his significant knowledge of all aspects of the
energy industry.
Greg A. Walker Mr. Walker was appointed
to our board of directors in October 2011. From 2009 to January
2011, he served as a Senior Vice President of Alpha Natural
Resources, Inc., assisting with integration issues after the
merger of Alpha Natural Resources, Inc. and Foundation Coal
Holdings, Inc. From 2004 to 2009, Mr. Walker served as the
Senior Vice President, General Counsel and Secretary of
Foundation Coal Holdings, Inc. From 1999 to 2004, he served as
the Senior Vice President, General Counsel and Secretary of RAG
American Coal Holdings, Inc., which was the predecessor entity
to Foundation Coal Holdings, Inc. From 1989 through 1999, he
served in various capacities in the law department of Cyprus
Amax Minerals Company. He spent three years in private law
practice in Denver, Colorado from 1986 to 1989, and from 1981
through 1986 he held various positions within the law department
of Mobil Oil Corporation. He has been a member of the board of
directors since 2005, and Chairman in 2008, of the FutureGen
Industrial Alliance, Inc., a
not-for-profit
entity whose global members are working with the United States
Department of Energy to build and operate a commercial scale
carbon dioxide sequestration project. He currently also serves
as the Treasurer and Secretary of FutureGen. From 2007 through
2010, he served as an appointee from the United States to the
Coal Industry Advisory Board, an international advisory panel to
the International Energy Administration with respect to matters
regarding the production, use and demand for coal on a global
basis. The board selected Mr. Walker to serve as a director
because of his specialized knowledge of the coal and energy
industry and applicable regulations, as well as his experience
in public company management.
124
Board of
Directors and Board Committees
Our board currently consists of seven directors. Our board has
established the following committees: an audit committee, a
compensation committee, a nominating and governance committee
and a conflicts committee. The composition and responsibilities
of each committee are described below. Members serve on these
committees until their resignation or until otherwise determined
by our board.
The majority of our board members are independent. The board has
determined that each of Messrs. Beard, Crain, Ford and
Walker is an independent director pursuant to the requirements
of Nasdaq, and each of the members of the audit committee
satisfies the additional conditions for independence for audit
committee members required by Nasdaq.
Audit
Committee
Messrs. Crain, Ford and Walker, each an independent
director, serve on our audit committee. Mr. Ford is the
chair of the audit committee. The committee assists our board in
fulfilling its oversight responsibilities relating to
(i) the integrity of our financial statements, internal
accounting, financial controls, disclosure controls and
financial reporting processes, (ii) the independent
auditors qualifications and independence, (iii) the
performance of our internal audit function and independent
auditors, and (iv) our compliance with legal and regulatory
requirements. The board has determined that Mr. Ford
qualifies as an audit committee financial expert, as
that term is defined in Item 407(d)(5) of
Regulation S-K,
as promulgated by the SEC.
Compensation
Committee
Messrs. Beard, Ford and Walker, each an independent
director, serve on our compensation committee. Mr. Beard is
the chair of the compensation committee. The committee is
responsible for discharging the boards responsibility
relating to compensation of our executive officers and
directors, evaluating the performance of our executive officers
in light of our goals and objectives and recommending to the
board for approval our compensation plans, policies and
programs. Each member of the committee is independent, a
non-employee director for purposes of
Rule 16b-3
under the Exchange Act, and an outside director for
purposes of Section 162(m) of the Code.
Nominating
and Governance Committee
Messrs. Beard, Crain and Ford, each an independent
director, serve on our nominating and governance committee.
Mr. Crain is the chair of this committee. The committee is
responsible for (i) assisting the board by indentifying
individuals qualified to become board members, and recommending
to our board nominees for election as director,
(ii) leading the board in its annual performance review,
(iii) recommending to the board members and chairpersons
for each committee, (iv) monitoring the attendance,
preparation and participation of individual directors and
conducting a performance evaluation of each director prior to
the time he or she is considered for re-nomination to the board
of directors, (v) monitoring and evaluating corporate
governance issues and trends, and (vi) discharging the
boards responsibilities relating to compensation of our
directors by reviewing such compensation annually and then
recommending any changes in such compensation to the full board
of directors.
Conflicts
Committee
Messrs. Beard, Crain and Walker, each an independent
director, serve on our conflicts committee. Mr. Walker is
the chair of this committee. The committee is responsible for
(i) reviewing specific matters that the board believes may
involve conflicts of interest, (ii) reviewing specific
matters requiring action of the conflicts committee pursuant to
any agreement to which we are a party, (iii) advising the
board on actions to be taken by us upon the boards
request, and (iv) carrying out any other duties delegated
to the conflicts committee by the board of directors.
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Compensation
Committee Interlocks and Insider Participation
Although our board did not have a compensation committee during
the entire current or previous fiscal year, none of the
individuals who currently serve on our compensation committee
has served our company or any of our subsidiaries as an officer
or employee. In addition, none of our executive officers serves
as a member of the board of directors or compensation committee
of any entity which has one or more executive officers serving
as a member of our board or compensation committee.
Code of
Ethics
We have adopted a code of business conduct and ethics applicable
to all employees, including executive officers, and directors. A
copy of the code of business conduct and ethics is available on
our web site at www.armstrongcoal.com. Any amendments to, or
waivers from, provisions of the code related to certain matters
will be disclosed on our website.
Compensation
of Directors
Historically, our directors have not received compensation for
their service. In connection with this offering, we adopted a
new director compensation program pursuant to which each of our
non-employee directors will receive (i) an annual cash
retainer of $50,000, and (ii) a restricted stock award with
a value of $25,000 on the date of grant. Our Nominating and
Governance Committee reviews and makes recommendations to the
board regarding compensation of directors, including
equity-based plans. We reimburse our non-employee directors for
reasonable travel expenses incurred in attending board and
committee meetings. We also intend to allow our non-employee
directors to participate in the 2011 Long-Term Incentive Plan
(the LTIP) and any other equity compensation plans
that we adopt in the future.
Executive
Officer Compensation
Compensation
Discussion and Analysis
This Compensation Discussion and Analysis describes and explains
our compensation program for the fiscal year ended
December 31, 2010 for our named executive officers, who are
listed as follows:
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J. Hord Armstrong, III, Chairman and Chief Executive
Officer;
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Martin D. Wilson, President;
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Kenneth E. Allen, Executive Vice President of Operations;
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David R. Cobb, P.E., Executive Vice President of Business
Development; and
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J. Richard Gist, Senior Vice President, Finance and
Administration and Chief Financial Officer.
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This section also explains how we expect the compensation of the
named executive officers to change following this offering.
Historical
Compensation Decisions
Our compensation approach has been tied to our stage of
development as a company. Before this offering, we were
privately-held and therefore, not subject to any stock exchange
or SEC rules relating to compensation, board committees and
independent board representation. We informally considered the
responsibilities connected with each management position and the
available funds for management compensation when making past
compensation decisions. Each year, after the financial
statements for the prior fiscal year were prepared,
Messrs. Armstrong and Wilson, together with Yorktown
convened to discuss compensation of management and certain other
employees, including themselves, and made adjustments to
executive pay as they deemed appropriate and feasible given our
companys financial position.
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Although we did not have a formal compensation program in place,
we believe that our informal program and compensation methods
furthered the following objectives:
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To retain talented individuals to contribute to our
companys sustained progress, growth and
profitability; and
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To reflect the unique qualifications, skills, experiences and
responsibilities of each individual.
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New
Compensation Philosophy and Objectives
We recently formed a compensation committee comprised of board
members who meet the definition of independence as set forth in
applicable Nasdaq rules. As of its inception, the compensation
committee has been tasked with the responsibility to establish
and implement our new compensation philosophy and objectives,
administrate our executive and director compensation programs
and plans, and review and approve the compensation of our named
executive officers. The committee is currently in the process of
evaluating our historical compensation practices and customizing
a new management compensation program for our specific
circumstances.
As we gain experience as a public company, we expect that the
specific director, emphasis and components of our executive
compensation program will continue to evolve. Accordingly, the
compensation paid to our named executive officers in the past is
not necessarily indicative of how we will compensate them after
this offering.
Compensation
Committee Procedures
The compensation committees responsibilities are specified
in its charter. The compensation committees functions and
authority include, among other things:
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Establishment and annual review of corporate goals and
objectives relevant to the compensation of the executive
officers, including the chief executive officer;
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Evaluation of the executive officers performance;
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Determination and approval of executive officer compensation;
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Administration of equity compensation plans, annual bonus and
long-term incentive cash-based compensation plans;
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Review and approval of employment agreements and severance
arrangements of all executive officers; and
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Management of risk relating to incentive compensation.
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Elements
of Compensation
Historically, our executive officers have received annual
salaries as their compensation for services. In addition, our
board may grant discretionary cash bonuses and equity to our
executive officers. In connection with Mr. Gists
appointment as an executive officer, effective January 1,
2010, we granted Mr. Gist 18,500 shares of common
stock of Armstrong Energy, which vested on September 30,
2011. The aggregate grant date value of Mr. Gists
award was $120,000. In addition, on June 1, 2011, we
granted to each of Messrs. Armstrong, Wilson, Allen and
Cobb 18,500 shares of common stock of Armstrong Energy, which
vest on April 1, 2013. The aggregate grant date fair value
of each award was approximately $258,000.
We believe that our key executives compensation is
reflective of their leadership roles in a growing company in
relation to our financial performance. We believe that our
executive compensation is competitive within our industry and
adequate to retain and incentivize our key executives.
We recently adopted the LTIP. Going forward, we expect that our
executive officers compensation will consist of base
salary, annual cash incentive compensation, and long-term
incentive compensation. Executive officers are eligible to
receive annual performance-based and discretionary cash bonuses.
Long-term incentive
127
compensation further aligns the interests of our executive
officers with those of our stockholders over the long-term,
encourages the retention of our executives, and rewards
executive actions that enhance long-term stockholder returns.
The LTIP provides for the granting of stock options, stock
appreciation rights, restricted stock, restricted stock units,
performance grants and other equity-based incentive awards to
those who contribute significantly to our strategic and
long-term performance objectives and growth. The LTIP is more
fully described below under 2011 Long-Term
Incentive Plan.
Other
Executive Benefits
Our named executive officers are eligible for the following
benefits on the same basis as other eligible employees:
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Health insurance;
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Vacation, personal holidays and sick time;
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Life insurance and supplemental life insurance;
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Short-term and long-term disability; and
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A 401(k) plan with matching contributions.
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In addition, we provide our named executive officers with an
annual car allowance and a payment equal to the group term life
insurance premium paid on each named executive officers
behalf. Also, we provide Mr. Wilson with an allowance for
club membership dues.
Employment
Agreements
2007 Allen and Cobb Employment Agreements
Effective June 1, 2007, we entered into an employment
agreement (the 2007 Allen Employment Agreement) with
Mr. Allen. Effective January 1, 2007, we entered into
an employment agreement (the 2007 Cobb Employment
Agreement and together with the Allen Employment
Agreement, the 2007 Agreements) with Mr. Cobb.
Pursuant to the 2007 Agreements, we agreed to pay
Messrs. Allen and Cobb initial base salaries of $240,000
and $180,000, respectively. The base salaries are subject to
adjustment annually as determined by the board of directors. In
2010, the base salaries of Messrs. Allen and Cobb were
$260,000 and $226,000. Effective January 1, 2011, base
salaries of Messrs. Allen and Cobb were increased to
$275,000 and $238,000, respectively.
The 2007 Agreements provide that Messrs. Allen and Cobb
shall be eligible to participate in such benefits as may be
authorized and adopted from time to time by the board of
directors for our employees, including, without limitation, any
pension plan, profit-sharing plan or other qualified retirement
plan and any group insurance plan. The term of each of the 2007
Agreements is three years, and each shall be automatically
renewed for additional one year terms until such time, if any,
as we or the respective executive give written notice to the
other party that such automatic extension shall cease. In the
case of the 2007 Allen Employment Agreement, such notice must be
given at least 60 days prior to the expiration of the then
current term.
The 2007 Agreements provide that we may terminate the agreement
with or without cause, and the executive may terminate his
respective agreement with or without good reason. See
Payments upon Termination or a Change in
Control for additional information regarding termination
rights and payments due to the executives upon termination or a
change in control.
The 2007 Agreements contain non-competition and non-solicitation
provisions that endure for a period of twelve months following
the executives termination of employment with us.
In addition, pursuant to each of the 2007 Agreement and the
related overriding royalty agreement, as amended, between
Mr. Allen and us, and the 2007 Cobb Employment Agreement
and the related overriding royalty agreement, as amended,
between Mr. Cobb and us, Messrs. Allen and Cobb each
receive an overriding
128
royalty equal to $0.05 per ton sold by us from certain reserves
described in those agreements. See Overriding
Royalty Agreements.
2009 Gist Employment Agreement
Effective September 17, 2009, we entered into an employment
agreement (the 2009 Gist Agreement) with
Mr. Gist. Pursuant to the 2009 Gist Agreement, we agreed to
pay Mr. Gist a base salary of $192,500. In 2010,
Mr. Gists base salary was $195,000. Effective
January 1, 2011, his base salary was increased to $210,000.
Pursuant to the 2009 Gist Agreement, Mr. Gist is also
eligible to receive a bonus, with a target of 45% of his base
compensation. The bonus will be earned based on our
companys achievement of profitability targets and
Mr. Gists satisfactory achievement of goals and
objectives as determined by our President. For 2009,
Mr. Gist was to earn a bonus equal to a minimum of 22.5% of
base salary, less $15,000. In addition, Mr. Gist received a
signing bonus of $15,000 in 2009.
In addition, pursuant to the terms of the 2009 Gist Agreement,
Mr. Gist was granted 18,500 restricted shares of Armstrong
Energy common stock. Such shares vested on September 30,
2011.
The 2009 Gist Agreement provides that Mr. Gist shall be
eligible to participate in any future stock option plans,
restricted stock grants, phantom stock, or any other stock
compensation programs as approved by the board of directors or
our shareholders. Awards will be made at the discretion of the
board of directors and our President.
The 2009 Gist Agreement provides that we may terminate without
cause, and Mr. Gist may terminate for good reason. See
Payments upon Termination or a Change in
Control for additional information regarding termination
rights and payments due to Mr. Gist upon termination or a
change in control.
2011 Gist Employment Agreement
Effective October 1, 2011, we terminated the 2009 Gist
Agreement upon mutual agreement of the parties thereto and
entered into a new employment agreement with Mr. Gist (the
2011 Gist Agreement).
Pursuant to the 2011 Gist Agreement, we agreed to pay
Mr. Gist $210,000 for his services as our Senior Vice
President, Finance and Administration and Chief Financial
Officer. In addition, Mr. Gist is entitled to an annual
target bonus of 50% of the then annual salary. The bonus will be
based upon the achievement of performance criteria established
by us and to be awarded at the discretion of our President or
board of directors. As of December 16, 2011, the Company
has not established any performance criteria pursuant to the
2011 Gist Agreement. The board may grant Mr. Gist a
discretionary cash bonus for 2011, however.
The 2011 Gist Agreement provides that Mr. Gist shall be
eligible to participate in such benefits as may be authorized
and adopted from time to time by the board of directors for our
employees, including, without limitation, any pension plan,
profit-sharing plan or other qualified retirement plan and any
group insurance plan. The term of the 2011 Gist Agreement is one
year, and shall be automatically renewed for additional one year
terms until such time, if any, as we or Mr. Gist gives
written notice to the other party that such automatic extension
shall cease. Such notice must be given at least 60 days
prior to the expiration of the then current term.
The 2011 Gist Agreement provides that we may terminate the
agreement with or without cause. See Payments
upon Termination or a Change in Control for additional
information regarding termination rights and payments due to the
executives upon termination or a change in control.
The 2011 Gist Agreement contains non-competition and
non-solicitation provisions that endure for a period of
12 months following Mr. Gists termination of
employment with us.
Armstrong and Wilson Employment Agreements
Effective October 1, 2011, we entered into an employment
agreement (the 2011 Armstrong Agreement) with each
of Messrs. Armstrong and Wilson (together, the
Armstrong and Wilson Agreements).
Pursuant to each of the Armstrong and Wilson Agreements, we
agreed to pay each of Messrs. Armstrong and Wilson a base
salary of $300,000. In addition, each of Messrs. Armstrong
and Wilson is entitled to an
129
annual bonus based upon achievement of performance criteria
established by us and to be awarded by our board. The target
amount will not be less than 75% of the executives then
annual base salary. The executives base salary and bonus
will be reviewed from time to time and may be increased. As of
December 16, 2011, the Company has not established any
performance criteria pursuant to Armstrong and Wilson
Agreements. The board may grant Mr. Armstrong and/or Mr. Wilson
a discretionary cash bonus for 2011, however.
The Armstrong and Wilson Agreements provide that
Messrs. Armstrong and Wilson shall be entitled to
participate in any of our benefit plans made available to other
senior executive officers. The term of each of the Armstrong and
Wilson Agreements is three years, and each shall automatically
renew for successive one year terms unless either party gives
the other a notice of non-renewal at least 90 days before
the end of then current term.
The Armstrong and Wilson Agreements provide that we may
terminate the agreement with or without cause, and the executive
may terminate the agreement with or without good reason. See
Payments upon Termination or a Change in
Control for additional information regarding termination
rights and payments due to Messrs. Armstrong and Wilson
upon termination or a change in control.
The Armstrong and Wilson Agreements contain non-competition
provisions that continue for 18 months following a
termination of employment with us. In addition, the Armstrong
and Wilson Agreements contain non-solicitation provisions that
endure for a period of 24 months following the
executives termination.
Overriding
Royalty Agreements
On December 3, 2008, we entered into an amended and
restated overriding royalty agreement with Mr. Cobb
pursuant to which we agreed to pay Mr. Cobb a royalty of
five cents ($0.05) per ton of all coal thereafter mined or
extracted and subsequently sold from certain of our reserves.
The term of the royalty began on November 22, 2006, and is
set to continue until the later of: (i) November 22,
2026, or (ii) such time as all of the mineable and saleable
coal from the subject properties has been mined. The agreement
also states that the overriding royalty shall constitute an
independent and enforceable obligation that shall run with the
land and shall be binding on us, our respective assigns and
successors, and any subsequent owner of the subject properties.
On December 3, 2008, we entered into an amended and
restated overriding royalty agreement with Mr. Allen
pursuant to which we agreed to pay Mr. Allen a royalty of
five cents ($0.05) per ton of all coal thereafter mined or
extracted and subsequently sold from certain of our reserves.
The term of the royalty began on February 9, 2007, and is
set to continue until the later of: (i) February 9,
2027, or (ii) such time as all of the mineable and saleable
coal from the subject properties has been mined. The agreement
also states that the overriding royalty shall constitute an
independent and enforceable obligation that shall run with the
land and shall be binding on us, our respective assigns and
successors, and any subsequent owner of the subject properties.
Tax
Considerations
In the past, we have not taken into consideration the tax
consequences to employees and us when considering the types and
levels of awards and other compensation granted to executives
and directors. However, we anticipate that the compensation
committee will consider these tax implications when determining
executive compensation in the future.
130
2010
Summary Compensation Table
The following table sets forth all compensation paid to our
named executive officers for the years ending December 31,
2010, 2009, and 2008.
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Name and Principal
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All Other
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Position
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Year
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Salary
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Bonus
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Stock Awards
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Compensation
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Total
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J. Hord Armstrong, III,
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2010
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$
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250,000
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$
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187,500
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$
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$
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21,456
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(1)
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$
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458,956
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Chairman and Chief
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2009
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124,000
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42,000
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5,780
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171,780
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Executive Officer
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2008
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60,000
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3,076
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63,076
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Martin D. Wilson,
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2010
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$
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250,000
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$
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187,500
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$
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$
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9,868
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$
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447,368
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President
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2009
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206,000
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206,000
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2008
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200,000
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1,710
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201,710
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Kenneth E. Allen(2),
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2010
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$
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260,000
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$
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130,000
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$
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$
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606,219
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(3)
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$
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996,219
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Executive Vice President of
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2009
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247,000
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42,000
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12,560
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301,560
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Operations
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2008
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243,000
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15,641
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258,641
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David R. Cobb, P.E.(4),
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2010
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$
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226,000
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$
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113,000
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$
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$
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300,567
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(5)
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$
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639,567
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Executive Vice President of
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2009
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210,000
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42,000
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244,428
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496,428
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Business Development
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2008
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182,000
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81,402
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263,402
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J. Richard Gist(6),
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2010
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$
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195,000
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$
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88,000
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$
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120,000
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$
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4,129
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$
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407,129
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Senior Vice President,
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2009
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48,250
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43,000
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91,250
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Finance and Administration and
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2008
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Chief Financial Officer
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(1) |
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Includes our matching contributions paid to our 401(k) plan on
behalf of Mr. Armstrong ($14,600). |
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(2) |
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Mr. Allen was appointed Executive Vice President of
Operations effective October 1, 2011. Prior to this time,
Mr. Allen was our Vice President of Operations. |
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(3) |
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Includes overriding royalties paid to Mr. Allen ($569,000)
(see Overriding Royalty Agreements for a
description of Mr. Allens agreement with us regarding
the payment of overriding royalties) and our matching
contributions paid to our 401(k) plan on behalf of
Mr. Allen ($15,100). |
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(4) |
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Mr. Cobb was appointed Executive Vice President of Business
Development effective October 1, 2011. Prior to this time,
Mr. Cobb was our Vice President of Business Development. |
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(5) |
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Includes overriding royalties paid to Mr. Cobb ($265,000)
(see Overriding Royalty Agreements for a
description of Mr. Cobbs agreement with us regarding
the payment of overriding royalties) and our matching
contributions paid to our 401(k) plan on behalf of Mr. Cobb
($13,400). |
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(6) |
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Mr. Gist became Vice President and Controller on
October 7, 2009, and Senior Vice President, Finance and
Administration and Chief Financial Officer effective
October 1, 2011. |
Payments
upon Termination or a Change in Control
Each of our named executive officers has entered into an
agreement with us regarding his respective employment. The
following is a description of the termination provisions
contained in each agreement and the payments due to the named
executive officers upon termination or a change in control.
2007
Allen and Cobb Employment Agreements
Pursuant to the 2007 Agreements, we may terminate each agreement
at any time for cause, which is defined as: (i) the
executives failure substantially to perform his duties
under the agreement in a manner satisfactory to the board, as
determined in good faith by the board, provided that the board
has given the executive written notice of the action(s) or
omission(s) which are claimed to constitute such failure and the
executive does not fully remedy such failure within 10 calendar
days after receipt of the written notice, (ii) the
executive has engaged in gross misconduct, dishonest, disloyal,
illegal or unethical conduct, or any other conduct which has or
could reasonably have a detrimental impact on our company or its
reputation, all facts to be determined in good faith by the
board, (iii) the executive has acted in a dishonest or
disloyal manner, or
131
breached any fiduciary duty to our company that, in either case,
results or was intended to result in personal profit to the
executive at the expense of our company or any of its customers,
(iv) the executive has been convicted of or pleads guilty
or no contest to any felony, (v) the executive has one or
more physical or mental impairments which have substantially
impaired his ability to perform the essential functions of his
job under the agreement, (vi) the executives death,
(vii) any breach by the executive of certain obligations
under the agreement, (viii) resignation by the executive
under circumstances where a termination for cause
was impending or could have reasonably been foreseen.
We also may terminate each of the 2007 Agreements without cause,
as defined above. In the event of such termination without
cause, the executive shall be entitled to receive (i) the
executives base salary for 12 months following
termination, at the same rate as was in effect on the day prior
to termination, and (ii) health insurance premiums for
12 months. In addition, the respective overriding royalty
will run with the land per the provisions of the overriding
royalty agreements. See Overriding Royalty
Agreements.
Under each of the 2007 Agreements, the executive may resign for
good reason, which is defined as a material demotion or
reduction, without the executives consent, in the
executives duties. In the event of a resignation for good
reason, the executive shall be entitled to receive (i) the
executives base salary for 12 months following
termination, at the same rate as was in effect on the day prior
to termination, and (ii) health insurance premiums for
12 months. In addition, the respective overriding royalty
will run with the land per the provisions of the overriding
royalty agreements. See Overriding Royalty
Agreements.
In the event of a termination of the executives
employment, other than for cause, within 12 months of a
change in control, the executive shall be entitled to receive
health insurance premiums for 12 months. In addition, we
will pay, promptly following such termination, a lump sum
payment equal to one times the executives annual base
salary at the time of his termination, plus any accrued and
unpaid overriding royalty. For this purpose, a change in control
means: (i) any purchase or other acquisition by an
individual or group of person(s) (including entity(ies)) acting
in concert, which results in persons who are our shareholders as
of the date of entry into the respective agreement no longer
being the legal and beneficial owners of 51% or more of the
outstanding equity in our company, (ii) consummation of a
reorganization, merger, recapitalization, consolidation, or any
other transaction, in each case with respect to which persons
who were our shareholders as of the date of entry into the
respective agreement do not, immediately thereafter, legally and
beneficially own 51% or more of the equity in the
newly-organized, merged, recapitalized, consolidated, or other
resulting entity, or (iii) the sale of all or substantially
all of our assets in a transaction approved by the board.
2009
Gist Employment Agreement
Pursuant to the 2009 Gist Agreement, if we terminate the
agreement without cause, Mr. Gist is entitled to receive
12 months of salary, bonus and health benefits. If
Mr. Gist resigns for good reason, which is defined as
significant diminishing of Mr. Gists job
responsibilities, change in position or title, etc.,
Mr. Gist is entitled to receive 12 months of salary,
bonus and health benefits. Pursuant to the 2009 Gist Agreement,
if there is a change in control and Mr. Gists job is
eliminated or Mr. Gist resigns for good reason within one
year of the change in control, Mr. Gist is entitled to
receive 12 months of salary, bonus and health benefits.
2011
Gist Employment Agreement
Pursuant to the 2011 Gist Agreement, we may terminate the
agreement at any time for cause, which is defined as:
(i) Mr. Gists failure substantially to perform
his duties under the agreement in a manner satisfactory to the
board, as determined in good faith by the board, provided that
the board has given Mr. Gist written notice of the
action(s) or omission(s) which are claimed to constitute such
failure and Mr. Gist does not fully remedy such failure
within 10 calendar days after receipt of the written notice,
(ii) Mr. Gist has engaged in gross misconduct,
dishonest, disloyal, illegal or unethical conduct, or any other
conduct which has or could reasonably have a detrimental impact
on our company or its reputation, all facts to be determined in
good faith by the board, (iii) Mr. Gist has acted in a
dishonest or disloyal manner, or breached any fiduciary duty to
our company that, in either case, results or was intended to
result in personal profit to Mr. Gist at the expense of our
company or any of its customers, (iv) Mr. Gist has
been convicted of or pleads guilty or no
132
contest to any felony, (v) Mr. Gist has one or more
physical or mental impairments which have substantially impaired
his ability to perform the essential functions of his job under
the agreement, (vi) Mr. Gists death,
(vii) any breach by Mr. Gist of certain obligations
under the agreement, (viii) resignation by Mr. Gist
under circumstances where a termination for cause
was impending or could have reasonably been foreseen.
We also may terminate the 2011 Gist Agreement without cause, as
defined above. In the event of such termination without cause,
the executive shall be entitled to receive (i) the
executives base salary for 12 months following
termination, at the same rate as was in effect on the day prior
to termination, plus any accrued but unpaid bonus as of the
termination date, and (ii) health insurance premiums for
12 months.
Pursuant to the 2011 Gist Agreement, Mr. Gist may resign
for good reason, which is defined as a material demotion or
reduction, without Mr. Gists consent, in
Mr. Gists duties. In the event of a resignation for
good reason, Mr. Gist shall be entitled to receive
(i) his base salary for 12 months following
termination, at the same rate as was in effect on the day prior
to termination, and (ii) health insurance premiums for
12 months.
In the event of a termination of Mr. Gists
employment, other than for cause, within 12 months of a
change in control, Mr. Gist shall be entitled to receive
health insurance premiums for 12 months. In addition, we
will pay, promptly following such termination, a lump sum
payment equal to one times Mr. Gists annual base
salary at the time of his termination, plus one years
bonus in an amount equal to 50% of Mr. Gists then
existing annual base salary. For this purpose, a change in
control means: (i) any purchase or other acquisition by an
individual or group of person(s) (including entity(ies)) acting
in concert, which results in persons who are our shareholders as
of the date of entry into the respective agreement no longer
being the legal and beneficial owners of 51% or more of the
outstanding equity in our company, (ii) consummation of a
reorganization, merger, recapitalization, consolidation, or any
other transaction, in each case with respect to which persons
who were our shareholders as of the date of entry into the
respective agreement do not, immediately thereafter, legally and
beneficially own 51% or more of the equity in the
newly-organized, merged, recapitalized, consolidated, or other
resulting entity, or (iii) the sale of all or substantially
all of our assets in a transaction approved by the board.
Armstrong
and Wilson Employment Agreements
Pursuant to the Armstrong and Wilson Agreements, we may
terminate Mr. Armstrongs and Mr. Wilsons
employment at any time without cause (as defined below), and
each of Mr. Armstrong and Mr. Wilson may terminate his
own employment at any time for good reason (as defined below).
In the event of a termination without cause, failure by us to
renew the agreement or termination by the executive for good
reason, (i) we will continue to pay the executives
base salary and provide his other benefits under the respective
agreement (including automobile allowance, vacation and health
insurance) for 24 months, and (ii) the executive shall
also be entitled to a bonus for that year equal to 75% of his
base salary then in effect (irrespective of whether performance
objectives have been achieved). In addition, (a) we will
provide the executive with outplacement services, and
(b) the executive shall be entitled to a contribution under
our retirement benefit plan for that fiscal year equal to the
greater of (x) the amount that would have been contributed
for that fiscal year determined in accordance with past
practice, or (y) the highest amount contributed by us on
behalf of the executive for any of the three prior fiscal years.
For this purpose, cause means (i) the executives
willful and continued failure substantially to perform his
duties under the respective agreement (other than as a result of
sickness, injury or other physical or mental incapacity or as a
result of termination by the executive for good reason);
provided, however, that such failure shall constitute
cause only if (x) we deliver a written demand
for substantial performance to the executive that specifies the
manner in which we believe he has failed substantially to
perform his duties under the agreement and (y) the
executive shall not have corrected such failure within 10
business days after his receipt of such demand;
(ii) willful misconduct by the executive in the performance
of his duties under the agreement that is demonstrably and
materially injurious to our company or any affiliated company
for which he is required to perform duties hereunder;
(iii) the executives conviction of (or plea of nolo
contendere to) a financial-related felony or other similarly
material crime under the laws of the United States or any state
133
thereof; or (iv) any material violation of the respective
agreement by the executive. No action, or failure to act, shall
be considered willful if it is done by the executive
in good faith and with the reasonable belief that the action or
omission was in the best interest of our company. If our Board
determines in its sole discretion that a cure of the acts or
omissions described above is possible and appropriate, we will
give the executive written notice of the acts or omissions
constituting cause and no termination of the agreement shall be
for cause unless and until the executive fails to cure such acts
or omissions within 20 business days following receipt of such
notice. If the Board determines in its sole discretion that a
cure is not possible and appropriate, the executive shall have
no notice or cure rights before the agreement is terminated for
cause.
For this purpose, good reason means the occurrence of any of the
following (other than by reason of a termination of the
executive for cause or disability or with the executives
consent): (i) the authority, duties or responsibilities of
the executive are significantly and materially reduced
(including, without limitation, by reason of the elimination of
the executives position or the failure to elect the
executive to such position or by reason of a change in the
reporting responsibilities to and of such position, or,
following a change in control, by reason of a substantial
reduction in the size of our company or other substantial change
in the character or scope of our companys operations);
(ii) the annual base salary is materially reduced (except
if such reduction occurs prior to a change in control and is
part of an
across-the-board
reduction applicable to all senior level executives);
(iii) the executive is required to change his regular work
location to a location that is more than 75 miles from his
regular work location prior to such change; or (iv) any
other action or inaction that constitutes a material breach by
us of the agreement. To exercise his right to terminate for good
reason the executive must provide written notice of his belief
that good reason exists within 90 days of the initial
existence of the condition(s) giving rise to good reason. We
shall have 20 days to remedy the good reason condition(s).
If not remedied within that
20-day
period, the executive may terminate his employment; provided,
however, that such termination must occur no later than
180 days after the date of the initial existence of the
condition(s) giving rise to the good reason.
Pursuant to the Armstrong and Wilson Agreements, in the event
that: (i) we terminate the executives employment
without cause in anticipation of, or pursuant to a notice of
termination delivered to the executive within 24 months
after, a change in control (as defined below); (ii) the
executive terminates his employment for good reason pursuant to
a notice of termination delivered to us in anticipation of, or
within 24 months after, a change in control; or
(iii) we fail to renew the agreement in anticipation of, or
within 24 months after, a change in control:
(a) we shall pay to the executive, within 30 days
following the executives separation from service (within
the meaning of Code Section 409A and the regulations and
other guidance promulgated thereunder), a lump-sum cash amount
equal to: (x) two times the sum of (A) his salary then
in effect and (B) 75% of his then current salary; plus
(y) a bonus for the then current fiscal year equal to 75%
of his salary (irrespective of whether performance objectives
have been achieved); plus (z) if such notice is given
within the first 12 months after October 1, 2011,
then, the salary the executive should have been paid from the
date of termination through the end of such 12-month
period; and
(b) during the portion, if any, of the
24-month
period commencing on the date of the executives separation
from service that the executive is eligible to elect and elects
to continue coverage for himself and his eligible dependents
under our health plan pursuant to COBRA or a similar state law,
we shall reimburse the executive for the difference between the
amount the executive pays to effect and continue such coverage
and the employee contribution amount that our active senior
executive employees pay for the same or similar coverage.
For purposes of the Armstrong and Wilson Agreements, a change in
control means the occurrence of any of the following: (i) a
merger, consolidation, exchange, combination or other
transaction involving our company and another entity (or our
securities and such other entity) as a result of which the
holders of all of the shares of our common stock outstanding
prior to such transaction do not hold, directly or indirectly,
shares of the outstanding voting securities of, or other voting
ownership interest in, the surviving, resulting or successor
entity in such transaction in substantially the same proportions
as those in which they held the outstanding shares of our common
stock immediately prior to such transaction; (ii) the sale,
transfer,
134
assignment or other disposition by us in one transaction or a
series of transactions within any period of 18 consecutive
calendar months (including, without limitation, by means of the
sale of capital stock of any subsidiary or subsidiaries of our
company) of assets which account for an aggregate of 50% or more
of the consolidated revenues of our company and its
subsidiaries, as determined in accordance with GAAP, for the
fiscal year most recently ended prior to the date of such
transaction (or, in the case of a series of transactions as
described above, the first such transaction); provided, however,
that no such transaction shall be taken into account if
substantially all the proceeds thereof (whether in cash or in
kind) are used after such transaction in the ongoing conduct by
our company
and/or its
subsidiaries of the business conducted by our company
and/or its
subsidiaries prior to such transaction; (iii) our company
is dissolved; or (iv) a majority of our directors are
persons who were not members of the board as of the date which
is the more recent of the date hereof and the date which is two
years prior to the date on which such determination is made,
unless the first election or appointment (or the first
nomination for election by our shareholders) of each director
who was not a member of the board on such date was approved by a
vote of at least two-thirds of the board of directors in office
prior to the time of such first election, appointment or
nomination.
Pursuant to the terms of the Armstrong and Wilson Agreement if
the executive is a disqualified individual (as
defined in Section 280G of the Code), and the severance or
change of control payments and benefits, together with any other
payments which the executive has the right to receive from the
Company, would constitute a parachute payment (as
defined in Section 280G of the Code), the payments provided
hereunder shall be reduced (but not below zero) so that the
aggregate present value of such payments received by the
executive from the Company shall be $1.00 less than three times
the executives base amount (as defined in
Section 280G of the Code) and so that no portion of such
payments received by the executive shall be subject to the
excise tax imposed by Section 4999 of the Code.
The following table illustrates the payments and benefits due to
each of Messrs. Allen, Cobb and Gist assuming that the
termination or change in control took place on the last business
day of our last completed fiscal year. There would have been no
payments or benefits due to Messrs. Armstrong or Wilson in
such an event, as Messrs. Armstrong and Wilson were not
parties to an employment agreement as of December 31, 2010.
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|
|
|
|
|
|
|
|
|
|
|
|
|
Termination
|
|
|
|
|
|
|
|
|
|
|
in Connection
|
|
|
|
|
|
|
|
|
Termination
|
|
with a
|
|
|
Termination for
|
|
Termination
|
|
Termination for
|
|
Without Good
|
|
Change in
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Name
|
|
Cause
|
|
Without Cause
|
|
Good Reason
|
|
Reason
|
|
Control
|
|
Kenneth E. Allen
|
|
$
|
19,691
|
|
|
$
|
292,315
|
|
|
$
|
292,315
|
|
|
$
|
19,691
|
|
|
$
|
292,315
|
|
David R. Cobb, P.E.
|
|
$
|
19,691
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|
|
$
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270,315
|
|
|
$
|
270,315
|
|
|
$
|
19,691
|
|
|
$
|
270,315
|
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J. Richard Gist
|
|
|
|
|
|
$
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302,154
|
|
|
$
|
302,154
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|
|
|
|
|
|
$
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302,154
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2011
Long-Term Incentive Plan
Our board of directors recently adopted the 2011 LTIP for our
employees and directors, as well as for consultants and
independent contractors who perform services for us. The LTIP is
administered by the compensation committee, which has the
authority to select recipients of awards and determine the type,
size, terms and conditions of awards. The maximum aggregate
number of shares of common stock available for issuance under
the LTIP is 10% of our authorized shares of common stock.
The LTIP provides for the granting of stock options, stock
appreciation rights, restricted stock, restricted stock units,
performance grants and other equity-based incentive awards to
those who contribute significantly to our strategic and
long-term performance objectives and growth, as the compensation
committee may determine.
Except with respect to restricted stock awards and unless
otherwise determined by the committee in its discretion, the
recipient of an award has no rights as a stockholder until he or
she receives a stock certificate or has his or her ownership
entered into the books of the Company.
135
The compensation committee has the authority to administer the
LTIP and may determine the type, number and size of the awards,
the recipients of awards and the terms and conditions applicable
to awards made under the LTIP. The committee may also generally
amend the terms and conditions of awards, subject to certain
restrictions.
The LTIP will terminate upon the earlier of the adoption of a
board resolution terminating the LTIP or ten years from its
effective date.
The following is a brief summary of the types of awards
available for issuance under the LTIP:
Stock
Options
The committee may grant non-qualified and incentive stock
options under the LTIP, provided that incentive stock options
shall be granted to employees only. The exercise price of stock
options must be no less than the fair market value of the common
stock on the date of grant and expire ten years after the date
of grant. The exercise price of incentive stock options granted
to holders of at least 10% of the Companys stock must be
no less than 110% of such fair market value, and incentive stock
options expire five years from the date of grant.
Stock
Appreciation Rights
An award of a stock appreciation right entitles the recipient to
receive, without payment, the number of shares of common stock
having an aggregate value equal to the excess of the fair market
value of one share of common stock at the time of exercise over
the exercise price, times the number of shares of common stock
subject to the award. Stock appreciation rights shall have an
exercise price no less than the fair market value of the common
stock on the date of grant.
Restricted
Stock and Restricted Stock Units
In addition to other terms and conditions applicable to
restricted stock and restricted stock unit awards, the
compensation committee shall establish the restricted period
applicable to such awards. The awards shall vest in one or more
increments during the restricted period, which shall not be less
than three years; provided, however, that this limitation shall
not apply to awards granted to non-employee directors. As may be
subject to additional conditions in the committees
discretion, recipients of such awards shall have voting,
dividend and other stockholder rights with respect to the awards
from the date of grant.
Performance
Grants
Performance grants shall consist of a right that is
(i) denominated in cash, common stock or any other form of
award issuable under the LTIP, (ii) valued in accordance
with the achievement of certain performance goals applicable to
performance periods as the committee may establish, and
(iii) payable at such time and in such form as the
committee shall determine. The committee may reduce the amount
of any performance grant in its discretion if it believes a
reduction is necessary based on the recipients
performance, comparisons with compensation received by
similarly-situated recipients within the industry, the
Companys financial results, or any other factors deemed
relevant.
Other
Share-Based Awards
Other share-based awards may consist of any other right payable
in, valued by, or otherwise related to common stock. The awards
shall vest in one or more increments during a service period,
which shall not be less than three years; provided, however,
that this limitation shall not apply to awards granted to
non-employee directors.
136
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table shows the amount of our common stock
beneficially owned as of January 31, 2012 prior to the
offering and after giving effect to the Reorganization and this
offering by (i) each person who is known by us to own
beneficially more than 5% of our common stock, (ii) each
member of the board of directors, (iii) each of the named
executive officers, and (iv) all members of the board of
directors and the executive officers, as a group. A person is a
beneficial owner of a security if that person has or
shares voting or investment power over the security or if he or
she has the right to acquire beneficial ownership within
60 days. Unless otherwise noted, these persons, to our
knowledge, have sole voting and investment power over the shares
listed. Percentage computations are based on
19,095,763 shares of our common stock outstanding as of
January 31, 2012, after giving effect to the
Reorganization. The following table includes equity awards
granted to our executive officers on a discretionary basis.
Except as otherwise noted, the principal address for the
stockholders listed below is
c/o Armstrong
Energy, Inc., 7733 Forsyth Boulevard, Suite 1625,
St. Louis, Missouri 63105.
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Shares Beneficially
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Shares Beneficially Owned
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Name
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Owned Prior to this Offering
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After this Offering(1)
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Number
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|
|
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Percent
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|
|
Number
|
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|
|
Percent
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J. Hord Armstrong, III
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129,701
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*
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129,701
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*
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Martin D. Wilson
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114,772
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*
|
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114,772
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*
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Kenneth E. Allen
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*
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*
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David R. Cobb, P.E.
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*
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*
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J. Richard Gist
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18,500
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*
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18,500
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*
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Anson M. Beard, Jr.
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James C. Crain
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Richard F. Ford
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Bryan H. Lawrence(2)
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Greg A. Walker
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All Directors and Executive Officers as a group (11 persons)
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262,973
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1.38
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%
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262,973
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%
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Yorktown VII Associates LLC(2)(3)
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11,562,500
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60.55
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%
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11,562,500
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%
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Yorktown VIII Associates LLC(2)(4)
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6,012,500
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31.49
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%
|
|
|
6,012,500
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|
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%
|
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|
* |
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Less than 1%. |
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(1) |
|
Assumes that the underwriters do not exercise their option to
purchase additional shares of our common stock. |
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(2) |
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The address of this beneficial owner is 410 Park Avenue, 19th
Floor, New York, New York 10022. |
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(3) |
|
These shares are held of record by Yorktown Energy Partners VII,
L.P. Yorktown VII Company LP is the sole general partner of
Yorktown Energy Partners VII, L.P. Yorktown VII Associates LLC
is the sole general partner of Yorktown VII Company LP. As a
result, Yorktown VII Associates LLC may be deemed to have the
power to vote or direct the vote or to dispose or direct the
disposition of the shares owned by Yorktown Energy Partners VII,
L.P. Yorktown VII Company LP and Yorktown VII Associates LLC
disclaim beneficial ownership of the securities owned by
Yorktown Energy Partners VII, L.P. in excess of their pecuniary
interests therein. |
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(4) |
|
These shares are held of record by Yorktown Energy Partners
VIII, L.P. Yorktown VIII Company LP is the sole general partner
of Yorktown Energy Partners VIII, L.P. Yorktown VIII Associates
LLC is the sole general partner of Yorktown VIII Company LP. As
a result, Yorktown VIII Associates LLC may be deemed to have the
power to vote or direct the vote or to dispose or direct the
disposition of the shares owned by Yorktown Energy Partners
VIII, L.P. Yorktown VIII Company LP and Yorktown VIII Associates
LLC disclaim beneficial ownership of the securities owned by
Yorktown Energy Partners VIII, L.P. in excess of their pecuniary
interests therein. |
137
CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Administrative
Services Agreement
Effective as of January 1, 2011, Armstrong Energy entered
into an Administrative Services Agreement with Armstrong
Resource Partners (f/k/a Elk Creek L.P.) and its general
partner, Elk Creek GP, LLC, pursuant to which Armstrong Energy
will provide Armstrong Resource Partners with general
administrative and management services, including, but not
limited to, human resources, information technology, financial
and accounting services and legal services. As consideration for
the use of Armstrong Energys employees and services, and
for certain shared fixed costs, including, but not limited to,
office lease, telephone and office equipment leases, Armstrong
Resource Partners will pay Armstrong Energy (i) a monthly
fee equal to $60,000 per month, and (ii) an aggregate
annual fee equal to $279,996 per year, until December 31,
2011. The monthly fee is subject to adjustment annually in
accordance with the terms of the Administrative Services
Agreement. Armstrong Resource Partners shall also be liable for
all taxes that are applicable to the services Armstrong Energy
provides on its behalf.
Sale of
Coal Reserves
Armstrong Energy is majority-owned by Yorktown. Effective
February 9, 2011, Armstrong Energy and several of its
affiliates participated in a transaction with Armstrong Resource
Partners, an entity also majority-owned by Yorktown, and several
of its affiliates. In 2009 and 2010, Armstrong Energy borrowed
an aggregate principal amount of $44.1 million from
Armstrong Resource Partners. The borrowings were evidenced by
promissory notes in favor of Armstrong Resource Partners in the
principal amounts of $11.0 million on November 30,
2009, $9.5 million on March 31, 2010, $12.6 million on
May 31, 2010 and $11.0 million on November 30, 2010,
respectively. The promissory notes had a fixed interest rate of
3%. In addition, contingent interest equal to 7% of revenue
would be accrued to the extent it exceeds the fixed interest
amount. No payments of principal or interest were due until the
earliest of May 31, 2014, or the 91st day after the
secured promissory notes had been paid in full. In consideration
for Armstrong Resource Partners making these loans, Armstrong
Energy granted it a series of options to acquire interests in
the majority of coal reserves then held by us in Muhlenberg and
Ohio Counties. On February 9, 2011, Armstrong Resources
Partners exercised its options, paid Armstrong Energy an
additional $5.0 million in cash and offset
$12.0 million in accrued advance royalty payments owed by
Armstrong Energy to Ceralvo Resources, LLC, and thereby acquired
a 39.45% undivided interest as a joint tenant in common with
Armstrong Energys subsidiaries in the aforementioned coal
reserves. The aggregate amount paid by Armstrong Resource
Partners to acquire its interest was the equivalent of
approximately $69.5 million. See Description of
Indebtedness.
Credit
and Collateral Support Fee, Indemnification and Right of First
Refusal Agreement
In addition, effective February 9, 2011, Armstrong Energy
and several of its affiliates entered into a credit and
collateral support fee, indemnification and right of first
refusal agreement with Armstrong Resource Partners, an entity
also majority-owned by Yorktown, and several of its affiliates,
pursuant to which Armstrong Resource Partners joined Armstrong
Energy as a co-borrower under Armstrong Energys Senior
Secured Term Loan, and its affiliates pledged their real estate
as collateral for and became guarantors on the Senior Secured
Revolving Credit Facility and the Senior Secured Term Loan. In
exchange, Armstrong Energy agreed to pay Armstrong Resource
Partners a credit support fee in an amount equal to 1% per annum
of the principal amount outstanding under the Senior Secured
Credit Facility, which principal amount may be as high as
$150 million. The principal amount outstanding under the
Senior Secured Credit Facility as of September 30, 2011 was
$134.6 million. Under the agreement, Armstrong Energy also
granted Armstrong Resources Partners a right of first refusal to
purchase its remaining interests in the coal reserves in which
they acquired a 39.45% undivided interest through the exercise
of options described above.
Lease
Agreements
On February 9, 2011, Armstrong Energys subsidiary,
Armstrong Coal, entered into a number of coal mining lease
agreements with Western Mineral (a subsidiary of Armstrong
Resource Partners) and two of
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Armstrong Energys wholly-owned subsidiaries. Pursuant to
these agreements, Western Mineral granted Armstrong Coal a lease
to its 39.45% undivided interest in certain mining properties
and a license to mine coal on those properties that it had
acquired in the above-described option transaction. The initial
term of the agreement is ten years, and it renews for subsequent
one-year terms until all mineable and merchantable coal has been
mined from the properties, unless either party elects not to
renew or it is terminated upon proper notice. Armstrong Coal
must pay the lessors a production royalty equal to 7% of the
sales price of the coal it mines from the properties.
On February 9, 2011, Armstrong Coal also entered into a
lease and sublease agreement with Ceralvo Holdings, LLC, a
subsidiary of Armstrong Resource Partners (Ceralvo
Holdings). Pursuant to this agreement, Ceralvo Holdings
granted Armstrong Coal leases and subleases, as applicable, to
the Elk Creek Reserves and a license to mine coal on those
properties. The initial term of the agreement is ten years, and
it renews for one-year terms until all mineable and merchantable
coal has been mined from the properties, unless either party
elects not to renew or it is terminated upon proper notice.
Armstrong Coal must pay the lessor a production royalty equal to
7% of the sales price of the coal it mines from the properties.
Armstrong Energy has paid $12 million of advance royalties
under the lease, which are recoupable against production
royalties. See Description of Indebtedness.
Royalty
Deferment and Option Agreement
Effective February 9, 2011, Armstrong Coal, Western Diamond
and Western Land, each of which is a wholly owned subsidiary of
Armstrong Energy, entered into a Royalty Deferment and Option
Agreement with Western Mineral and Ceralvo Holdings, both wholly
owned subsidiaries of Armstrong Resource Partners. Pursuant to
this agreement, Western Mineral and Ceralvo Holdings agreed to
grant to Armstrong Coal and its affiliates the option to defer
payment of their pro rata share of the 7% production royalty
described under Business Our Mining
Operations above. In consideration for the granting of the
option to defer these payments, Armstrong Coal and its
affiliates granted to Western Mineral the option to acquire an
additional undivided interest in certain of the coal reserves
held by Armstrong Energy, Inc. in Muhlenberg and Ohio Counties
by engaging in a financing arrangement, under which Armstrong
Coal and its affiliates would satisfy payment of any deferred
fees by selling part of their interest in the aforementioned
coal reserves at fair market value for such reserves determined
at the time of the exercise of such options.
Investment
in Ram Terminals, LLC
On May 26, 2011, Armstrong Energy made a capital
contribution in Ram in the amount of $2.47 million. Upon
amendment of the Limited Liability Company Agreement of Ram (the
Operating Agreement) on June 23, 2011,
Armstrong Energys membership interest in Ram constituted
8.4%. The remaining membership interest is owned by Yorktown
Energy Partners IX, L.P., a fund managed by Yorktown. Armstrong
Energy is majority-owned by Yorktown. Yorktown Energy Partner
IX, L.P. will provide the funds for future capital expenditures
related to the development of the site. Armstrong Energy will be
actively involved in the design and construction of the terminal
and will provide accounting and bookkeeping assistance to Ram.
Certain of Armstrong Energys executive officers will serve
as officers of Ram. Pursuant to the Operating Agreement,
Armstrong Energy will not be liable for the debts, liabilities
and other obligations of Ram.
Western
Diamond and Western Land Coal Reserves Sale Agreement
On October 11, 2011, two of our subsidiaries, Western
Diamond and Western Land (together, the Sellers),
entered into an agreement with Western Mineral, a subsidiary of
Armstrong Resource Partners, pursuant to which the Sellers
agreed to sell an additional partial undivided interest in
substantially all of the coal reserves and real property owned
by the Sellers previously subject to the options exercised by
Armstrong Resource Partners on February 9, 2011 (see
Sale of Coal Reserves and
Concurrent Transactions with Armstrong
Resource Partners), other than any of Sellers real
property and related mining rights associated with the Parkway
mine.
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Agreement
to Enter into Voting and Stockholders Agreement
On October 1, 2011, Armstrong Energy, Inc. entered into an
agreement to enter into a voting and stockholders
agreement with all of its stockholders. Pursuant to the terms of
this agreement, Armstrong Energy, Inc. and its stockholders
agreed to enter into a voting and stockholders agreement
in the event this offering is not completed on or before
February 1, 2012; provided, however, that the deadline may
be extended to a date mutually agreed upon by Yorktown and
Armstrong Energy, Inc., which in no event shall be later than
May 1, 2012.
Concurrent
Transactions with Armstrong Resource Partners
Concurrent with this offering of common stock, Armstrong
Resource Partners is offering common units pursuant to a
separate initial public offering (the Concurrent ARP
Offering). Armstrong Energy indirectly holds a 0.4% equity
interest in Armstrong Resource Partners. See
Business Our Organizational History.
If the Concurrent ARP Offering is completed, we expect that the
net proceeds received by Armstrong Resource Partners, estimated
to be $ million, assuming an
offering price of $ per unit, the
midpoint of the range set forth on the cover of the prospectus
related to the Concurrent ARP Offering, will be used to purchase
an additional partial undivided interest in substantially all of
the coal reserves and real property owned by us previously
subject to the options exercised by Armstrong Resource Partners
on February 9, 2011. If the Concurrent ARP Offering is
completed, and the net proceeds are applied in this manner,
Armstrong Resource Partners, through its subsidiary Western
Mineral, will have a % undivided
interest as a joint tenant in common with us in the majority of
our coal reserves, excluding the Union/Webster Counties
reserves. Such interest shall be equal to a fraction, the
numerator of which shall be equal to the amount of net proceeds
received from the Concurrent ARP Offering described above, and
the denominator of which is a dollar amount which we and
Armstrong Reserve Partners agree represents the aggregate fair
market value of the affected reserves. The closing of the sale,
which is conditioned on the closing of the Concurrent ARP
Offering, is expected to occur on or before 90 days after
Armstrong Resource Partners receives the net proceeds of the
Concurrent ARP Offering. See Western Diamond
and Western Land Coal Reserves Sale Agreement.
The amount received by us in such purchase is expected to be
utilized first to repay the remaining outstanding balance of the
Senior Secured Revolving Credit Facility (approximately
$ million) and related
accrued interest (approximately
$ million). Any cash we
receive in excess of those amounts will be used by us for
working capital purposes. In connection with such purchases, we
expect to enter into a financing arrangement with Armstrong
Resource Partners to mine the mineral reserves transferred,
resulting in the recognition of an obligation of
$ million. See Certain
Relationships and Related Party Transactions Lease
Agreements.
While we expect that Armstrong Resource Partners will consummate
the Concurrent ARP Offering concurrently with this offering of
common stock, the completion of this offering is not subject to
the completion of the Concurrent ARP Offering and the completion
of the Concurrent ARP Offering is not subject to the completion
of this offering.
This description and other information in this prospectus
regarding the Concurrent ARP Offering is included in this
prospectus solely for informational purposes. Nothing in this
prospectus should be construed as an offer to sell, nor the
solicitation of an offer to buy, any common units of Armstrong
Resource Partners.
Madisonville
Office Lease
Beginning in 2008, pursuant to an oral agreement, Armstrong Coal
leased from David R. Cobb, one of our executive officers, and
Rebecca K. Cobb, Mr. Cobbs spouse, certain property
to be used by Armstrong Coal as its office space in
Madisonville, Kentucky, equipment, furniture, supplies and the
use of Mr. Cobbs employees. Armstrong Coal agreed to
pay $4,700 per month in exchange for the leased property,
equipment, furniture, supplies and use of employees. On
August 1, 2009, Armstrong Coal entered into a written lease
agreement with Mr. and Mrs. Cobb regarding the subject
matter of the oral agreement. The terms of the
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written lease were the same as the terms of the prior oral
agreement. The lease term ends on July 31, 2012, but
automatically renews for additional
12-month
periods unless either party gives written notice of termination
no later than 30 days prior to the end of the term or a
renewal term.
Loans to
Executive Officers and Loan Repayment
During the fiscal years ended December 31, 2006 through
2008, our Predecessor entered into certain transactions with J.
Hord Armstrong, III, its Chairman and Chief Executive
Officer, and Martin D. Wilson, its President and member of its
board of managers, pursuant to which our Predecessor loaned
Messrs. Armstrong and Wilson money in connection with their
purchase of shares of common stock of our Predecessor. In a
series of separate transactions, each of Messrs. Armstrong
and Wilson executed promissory notes in favor of our Predecessor
in connection with his purchase of shares of common stock, as
follows:
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Number of Shares
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Amount of Loan from
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Date
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Purchased(1)
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Predecessor
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J. Hord Armstrong, III
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September 28, 2006
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23,125
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$
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250,000
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December 6, 2006
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23,125
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$
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250,000
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March 7, 2007
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46,250
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$
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500,000
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June 6, 2008
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11,563
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$
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125,000
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Martin D. Wilson
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September 28, 2006
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23,125
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$
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250,000
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December 6, 2006
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23,125
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$
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250,000
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March 7, 2007
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46,250
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$
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500,000
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(1) |
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In connection with the Reorganization, each of the issued and
outstanding limited liability company units was converted to
9.25 shares of common stock. In accordance with SEC Staff
Accounting Bulletin Topic 4.6, all share information has been
retroactively adjusted to reflect the common stock conversion. |
Each of the promissory notes was secured by the shares purchased
in each of the transactions, including the shares purchased with
cash and those financed by the promissory notes. In addition,
each of the promissory notes provided that interest on the
unpaid principal balance accrued at 6.00% per annum. Interest
was not required to be paid until repayment of the loan.
The largest aggregate amount of principal outstanding and the
amount of principal and interest paid on these loans for the
periods presented below are as follows:
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Fiscal Year Ended December 31,
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(in thousands)
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2008
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2009
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2010
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J. Hord Armstrong, III
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Largest Aggregate Amount of Principal Outstanding
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$
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1,125
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$
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1,125
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$
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1,125
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Amount of Principal Paid
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Amount of Interest Paid
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Martin D. Wilson
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Largest Aggregate Amount of Principal Outstanding
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$
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1,000
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$
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1,000
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$
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1,000
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Amount of Principal Paid
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Amount of Interest Paid
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Effective September 30, 2011, each of
Messrs. Armstrong and Wilson entered into a Unit Repurchase
Agreement with our Predecessor, pursuant to which our
Predecessor repurchased a number of membership units from
Messrs. Armstrong and Wilson in full satisfaction of the
loans described above. Pursuant to Mr. Armstrongs
Unit Repurchase Agreement, our Predecessor repurchased
78,424 shares of Mr. Armstrongs common stock in
satisfaction of his total outstanding debt as of
September 30, 2011 of approximately $1.43 million.
Pursuant to Mr. Wilsons Unit Repurchase Agreement,
our Predecessor repurchased 70,228 shares of
Mr. Wilsons common stock in satisfaction of his total
outstanding debt as of September 30, 2011 of approximately
$1.28 million. Effective September 30, 2011, these
loans were repaid in full.
141
Policies
and Procedures for Related Party Transactions
The conflicts committee must review and approve all transactions
between Armstrong Energy and any related person that are
required to be disclosed pursuant to Item 404 of
Regulation S-K.
Related person and transaction shall
have the meanings given to such terms in Item 404 of
Regulation S-K,
as amended from time to time. In determining whether to approve
or ratify a particular transaction, the conflicts committee will
take into account any factors it deems relevant.
142
DESCRIPTION
OF INDEBTEDNESS
In February 2011, we repaid certain promissory notes that were
delivered in connection with the acquisition of our coal
reserves (see Business Our Operational
History) and entered into the Senior Secured Credit
Facility, which is comprised of the $100.0 million Senior
Secured Term Loan and the $50.0 million Senior Secured
Revolving Credit Facility. Of the proceeds from borrowings under
the Senior Secured Credit Facility totaling $118.5 million,
$115.7 million was used to repay the outstanding promissory
notes, which were included in long-term debt obligations as of
December 31, 2010. As a result of the repayment of the
existing debt obligations, we recognized a gain of approximately
$7.0 million in the nine months ended September 30,
2011. The Senior Secured Term Loan is a five-year term loan that
requires principal payments in the amount of $5.0 million
each on the first day of each quarter commencing on
January 1, 2012 through January 1, 2016, with a final
balloon payment due upon maturity on February 9, 2016.
Interest payments are also payable quarterly in arrears on the
first day of each quarter. The interest rate fluctuates based on
our leverage ratio and the applicable interest option elected.
The interest rate as of September 30, 2011 was 5.75%. The
Senior Secured Revolving Credit Facility provides for quarterly
interest payments in arrears that fluctuate on the same terms as
our term loan. The Senior Secured Revolving Credit Facility also
provides for a commitment fee based on the unused portion of the
facility at certain times. As of September 30, 2011, we had
$34.6 million outstanding, with $15.4 million
available for borrowing under our Senior Secured Revolving
Credit Facility. The obligations under the credit agreement are
secured by a first lien on substantially all of our assets,
including but not limited to certain of our mines, coal reserves
and related fixtures. The credit agreement contains certain
customary covenants as well as certain limitations on, among
other things, additional debt, liens, investments, acquisitions
and capital expenditures, future dividends, and asset sales. We
incurred approximately $3.3 million in fees related to the
new credit agreement which will be amortized over the term of
the Senior Secured Term Loan. Armstrong Energy entered into an
interest rate swap agreement, effective January 1, 2012, to
hedge our exposure to rising interest rates. Pursuant to this
agreement, Armstrong Energy is required to make payments at a
fixed interest rate of 2.89% to the counterparty on an initial
notional amount of $47.5 million (amortizing thereafter) in
exchange for receiving variable payments based on the greater of
1.0% or the three-month LIBOR rate, which was 0.37433% as of
September 30, 2011. This agreement has quarterly settlement
dates and matures on February 9, 2016. Armstrong Resource
Partners is a co-borrower under the Senior Secured Term Loan and
guarantor under the Senior Secured Credit Revolving Facility and
the Senior Secured Term Loan, and substantially all of its
assets are pledged to secure borrowings under the Senior Secured
Credit Facility.
On July 1, 2011, we entered into the First Amendment to our
Senior Secured Credit Facility which, among other things,
amended the provisions of the loan documents so as to permit an
offering of our securities and the completion of the
Reorganization. The amendment also made certain changes to our
financial covenants, including our maximum leverage ratio. In
addition, our interest rate increased to 5.75%, which can be
reduced in future periods to the extent our results improve. We
incurred approximately $1.1 million of fees related to this
amendment, which will be amortized over the remaining term of
the Senior Secured Term Loan. We entered into the Second
Amendment to our Senior Secured Credit Facility on
September 29, 2011, pursuant to which restrictions to the
consummation of this offering were eliminated. Additionally, on
December 29, 2011, we entered into the Third Amendment to
our Senior Secured Credit Facility which, among other things,
amended the provisions of the loan documents so as to permit the
acquisition of additional coal reserves. On February 8,
2012, we entered into the Fourth Amendment to our Senior Secured
Credit Facility which, among other things, amended the
provisions of the loan documents so as to modify the
consolidated EBITDA threshold, eliminate the minimum fixed
charge coverage ratio, add a minimum interest coverage ratio
beginning in 2013 and make certain changes to our financial
covenants, including our maximum leverage ratio and our minimum
consolidated EBITDA. In connection with entry into the Third and
Fourth Amendments to the Senior Secured Credit Facility, we paid
fees in the aggregate amount of $1.125 million.
In 2009 and 2010, Armstrong Energy borrowed an aggregate
principal amount of $44.1 million from Armstrong Resource
Partners. The borrowings were evidenced by promissory notes in
favor of Armstrong Resource Partners in the principal amounts of
$11.0 million on November 30, 2009, $9.5 million
on
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March 31, 2010, $12.6 million on May 31, 2010 and
$11.0 million on November 30, 2010, respectively. The
promissory notes had a fixed interest rate of 3%. In addition,
contingent interest equal to 7% of revenue would be accrued to
the extent it exceeds the fixed interest amount. No payments of
principal or interest were due until the earliest of
May 31, 2014, or the 91st day after the secured
promissory notes had been paid in full. The proceeds of those
loans were used to satisfy various installment payments required
by the promissory notes referred to above. In consideration for
Armstrong Resource Partners making the loans Armstrong Energy
granted to Armstrong Resource Partners a series of options to
acquire an undivided interest in the coal reserves acquired by
us in the above transactions, excluding the Webster/Union
Counties reserves. On February 9, 2011, Armstrong Resource
Partners exercised its option to acquire an interest in those
reserves in satisfaction of the loans it had made to Armstrong
Energy. In connection with that exercise, Armstrong Resource
Partners paid an additional $5.0 million in cash and agreed
to offset $12.0 million in accrued advance royalty payments owed
by Armstrong Energy to Armstrong Resource Partners, relating to
the lease of the Elk Creek Reserves, to acquire an additional
partial undivided interest in certain of the coal reserves held
by Armstrong Energy in Muhlenberg and Ohio Counties at fair
market value. As a result, Armstrong Resource Partners obtained
a 39.45% undivided interest as a joint tenant in common with
Armstrong Energys subsidiaries in certain of our coal
reserves. Simultaneous with this transaction, Armstrong Energy
entered into a lease agreement with a subsidiary of Armstrong
Resource Partners to mine the acquired mineral reserves. The
lease has a term of 10 years that can be extended for
additional periods until all the respective merchantable and
mineable coal is removed. The lease transaction has been
accounted for as a financing arrangement due to Armstrong
Energys continuing involvement in the land and mineral
reserves transferred. This has resulted in the recognition of an
initial obligation of $69.5 million by Armstrong Energy. As
the financial results of Armstrong Resource Partners have
historically been consolidated, this transaction has not
impacted our results of operations or financial condition
through September 30, 2011. As noted above, the
Deconsolidation was effective October 1, 2011.
Subsequently, the long-term obligation will be reflected on our
balance sheet and will continue to be amortized through 2031 at
an annual rate of 7% of the estimated gross revenue generated
from the sale of the coal originating from the leased mineral
reserves. As of September 30, 2011, the outstanding
principal balance of the long-term obligations to Armstrong
Resource Partners was $70.3 million.
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DESCRIPTION
OF CAPITAL STOCK
The following description of our capital stock is based upon our
amended and restated certificate of incorporation, our bylaws,
the certificate of designations for the shares of Series A
convertible preferred stock and applicable provisions of law, in
each case as currently in effect. This discussion does not
purport to be complete and is qualified in its entirety by
reference to our amended and restated articles of incorporation,
our bylaws and the certificate of designation for the shares of
Series A preferred stock, copies of which are filed with the SEC
as exhibits to the registration statement of which this
prospectus is a part.
Authorized
Capital Stock
Upon the closing of this offering, our authorized capital stock
will consist of (i) 70,000,000 shares of common stock,
par value $0.01 per share, of
which shares
will be issued and outstanding, and
(ii) 1,000,000 shares of preferred stock,
$0.01 par value per share, of which no shares will be
issued and outstanding. As of January 31, 2012, we had
19,095,763 outstanding shares of common stock, held of record by
13 stockholders, and 300,000 outstanding shares of Series A
preferred stock, held of record by one stockholder.
Common
Stock
Except as provided by law or in a preferred stock designation,
holders of common stock are entitled to one vote for each share
held of record on all matters submitted to a vote of the
stockholders, will have the exclusive right to vote for the
election of directors and do not have cumulative voting rights.
Subject to preferences that may be applicable to any outstanding
shares or series of preferred stock, holders of common stock are
entitled to receive ratably such dividends (payable in cash,
stock or otherwise), if any, as may be declared from time to
time by our board of directors out of funds legally available
for dividend payments. All outstanding shares of common stock
are fully paid and non-assessable, and the shares of common
stock to be issued upon the closing of this offering will be
fully paid and non-assessable. The holders of common stock have
no preferences or rights of conversion, exchange, pre-emption or
other subscription rights. There are no redemption or sinking
fund provisions applicable to the common stock. In the event of
any liquidation, dissolution or
winding-up
of our affairs, holders of common stock will be entitled to
share ratably in our assets that are remaining after payment or
provision for payment of all of our debts and obligations and
after liquidation payments to holders of outstanding shares of
preferred stock, if any.
Preferred
Stock
Our amended and restated certification of incorporation
authorizes our board of directors, subject to any limitations
prescribed by law, without further stockholder approval, to
establish and to issue from time to time one or more classes or
series of preferred stock. Each class or series of preferred
stock will cover the number of shares and will have the powers,
preferences, rights, qualifications, limitations and
restrictions determined by the board of directors, which may
include, among others, dividend rights, liquidation preferences,
voting rights, conversion rights, preemptive rights and
redemption rights. Except as provided by law or in a preferred
stock designation, the holders of preferred stock will not be
entitled to vote at or receive notice of any meeting of
stockholders.
Description
of Series A Convertible Preferred Stock
The certificate of designations for the Series A
convertible preferred stock authorizes 300,000 shares of
Series A convertible preferred stock, all of which are
outstanding as of February 6, 2012. There are no sinking
fund provisions applicable to our Series A convertible
preferred stock. All outstanding shares of Series A
convertible preferred stock are fully paid and non-assessable.
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Ranking. As described more fully below, the
Series A convertible preferred stock ranks senior with
respect to liquidation preference to any Junior
Securities, which means the common stock, any preferred
stock other than the Series A convertible preferred stock,
and any other class or series of stock that we may issue.
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Liquidation Preference. In the event of any
voluntary or involuntary liquidation, dissolution, or winding up
of the Company, a holder of Series A convertible preferred
stock will be entitled to receive, before any distribution or
payment is made to any holders of Junior Securities, an amount
in cash equal to $100 per share of Series A convertible
preferred stock held by such holder.
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Dividends. Holders of the Series A
convertible preferred stock are not entitled to the payment of
any dividends by the Company.
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Automatic Conversion. Upon the closing of this
offering, all of the outstanding shares of Series A
convertible preferred stock will automatically and without
further action required by any person convert into that number
of shares of common stock equal of the quotient obtained by
dividing (i) $100 times the number of shares of
Series A convertible preferred stock outstanding, by (ii)
(a) the initial public offering price per share, less any
underwriting discount per share, of common stock sold in this
offering, as reflected in this prospectus on or immediately
prior to the closing of this offering (the IPO
Price), minus (b) a Discount Amount. The
Discount Amount shall be determined by multiplying the IPO Price
by a percentage equal to the difference between (x) 100%
and (y) the fraction, expressed as a percentage, the
numerator of which is $300 million and the denominator of
which is the IPO Valuation Amount; provided, however, that if
the IPO Valuation amount is $300 million or less, the
discount amount shall be zero. For this purpose, the IPO
Valuation Amount means an amount determined by multiplying the
IPO Price by the total number of shares of common stock issued
and outstanding as of the date of the execution and delivery of
the underwriting agreement relating to this offering and
assuming the conversion in full of the Series A convertible
preferred stock at the IPO Price minus the Discount Amount.
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Conversion at Option of Holder. At any time
commencing January 12, 2013 or earlier in connection with
certain change in control events and provided that this offering
has not closed, any holder of Series A convertible
preferred stock may convert all or any portion of the shares
held into a number of shares of common stock equal to the
quotient obtained by dividing (a) $100 times the
number of shares of Series A convertible preferred stock to
be converted, by (b) the conversion price (which shall
initially be $100 per share), as may be adjusted for certain
specified events.
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Voting. The holders of Series A
convertible preferred stock shall vote together as a single
class with the holders of common stock, with each share of
Series A convertible preferred stock having one vote per
share, on all matters submitted to a vote of the holders of
common stock, except that when the Series A convertible
preferred stock and the common stock shall vote together as a
single class, then each holder of shares of Series A convertible
preferred stock shall be entitled to the number of votes with
respect to such holders Series A convertible preferred
stock equal to the number of whole shares into which such shares
of Series A convertible preferred stock would have been
converted under the provisions of the certificate of
designations at the conversion price then in effect on the
record date for determining stockholders entitled to vote on
such matters or, if no record date is specified, as of the date
of such vote. In addition, so long as any Series A
convertible preferred stock remains outstanding, the holders of
a majority of the Series A convertible preferred stock must
approve, voting separately as a class:
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Any amendment to our certificate of incorporation, including any
certificate of designations or bylaws that would affect
adversely the rights, preferences, privileges or voting rights
of holders of the Series A convertible preferred stock or
the terms of the Series A convertible preferred stock;
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Any proposed issuance of capital stock that ranks pari passu
or senior to the Series A convertible preferred stock,
or any proposed issuance of any securities other than
Series A convertible preferred stock which are required to
be redeemed by the Company at any time that any shares of
Series A convertible preferred stock are
outstanding; or
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Any increase in the number of authorized shares of capital stock
of the Company, except as specifically required in the
certificate of designations.
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Anti-Takeover
Effects of Certain Provisions of Our Amended and Restated
Certificate of Incorporation, Bylaws and Delaware Law
These provisions, summarized below, are expected to discourage
coercive takeover practices and inadequate takeover bids. These
provisions are also designed to encourage persons seeking to
acquire control of us to first negotiate with us. We believe
that the benefits of increased protection and our potential
ability to negotiate with the proponent of an unfriendly or
unsolicited proposal to acquire or restructure us outweigh the
disadvantages of discouraging these proposals because, among
other things, negotiation of these proposals could result in an
improvement of their terms.
Amended
and Restated Certificate of Incorporation and
Bylaws
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Classified Board of Directors. Our amended and
restated certificate of incorporation provides that our board of
directors be divided into three classes. Each class of directors
serves a three-year term.
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Removal of Directors; Vacancies. Our bylaws
provide that a director may be removed from office by the
stockholders only for cause and only in the manner provided in
the amended and restated certificate of incorporation. A vacancy
on the board of directors may be filled only by a majority of
the directors then in office.
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Calling of Special Meetings of
Stockholders. The bylaws provide that special
meetings of the stockholders may be called only by the chairman
of the board, our chief executive officer, president or
secretary after receipt of the request of a majority of the
total number of directors that we would have if there were no
vacancies.
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Advance Notice Requirements for Stockholder Proposals and
Director Nominations. Our amended and restated
certificate of incorporation and bylaws establish an advance
notice procedure for stockholder proposals to be brought before
an annual meeting of our stockholders, including proposed
nominations of persons for election to the board of directors.
Stockholders at an annual meeting will only be able to consider
proposals or nominations properly brought before the annual
meeting. To be properly brought before an annual meeting,
business must be (i) specified in the notice of meeting,
(ii) otherwise properly brought before the annual meeting
by the presiding officer or by or at the director of a majority
of the board of directors, or (iii) otherwise properly
requested to be brought by a stockholder who was a stockholder
of record at the time of the giving of notice for the annual
meeting, who is entitled to vote at the meeting, and who has
given our secretary timely written notice in proper form, of the
stockholders intention to bring that business before the
meeting.
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Amendment of Bylaws. Our bylaws can only be
amended by the board of directors or by the affirmative vote of
the holders of at least 80% of the outstanding common stock,
voting together as a single class.
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Opt-Out of Section 203 of the Delaware General
Corporation Law (DGCL). We have
expressly elected not to be governed by the business
combination provisions of Section 203 of the DGCL.
Section 203 prohibits a person who acquires more than 15%
but less than 85% of all classes of our outstanding voting stock
without the approval of our board of directors from thereafter
merging or combining with us for a period of three years, unless
such merger or combination is approved by both a two-thirds vote
of the shares not owned by such person and our board of
directors. These provisions would apply even if the proposed
merger or acquisition could be considered beneficial by some
stockholders.
Limitation
of Liability and Indemnification Matters
Our amended and restated certificate of incorporation limits the
liability of our directors for monetary damages for breach of
their fiduciary duty as directors, except for liability that
cannot be eliminated under the
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DGCL. Delaware law provides that directors of a company will not
be personally liable for monetary damages for breach of their
fiduciary duty as directors, except for liabilities:
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for any breach of their duty of loyalty to us or our
stockholders;
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for acts or omissions not in good faith or which involve
intentional misconduct or a knowing violation of law;
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for unlawful payment of dividend or unlawful stock repurchase or
redemption, as provided under Section 174 of the
DGCL; or
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for any transaction from which the director derived an improper
personal benefit.
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Any amendment, repeal or modification of these provisions will
be prospective only and would not affect any limitation on
liability of a director for acts or omissions that occurred
prior to any such amendment, repeal or modification.
Our amended and restated certificate of incorporation and bylaws
also provide that we will indemnify our directors and officers
to the fullest extent permitted by Delaware law. Our amended and
restated certificate of incorporation and bylaws also permit us
to purchase insurance on behalf of any director, officer,
employee or agent of the Company or another corporation,
partnership, joint venture, trust or other enterprise against
any liability arising out of that persons actions as our
officer, director, employee or agent, regardless of whether
Delaware law would permit indemnification. We intend to enter
into indemnification agreements with each of our current and
future directors and officers. These agreements will require us
to indemnify these individuals to the fullest extent permitted
under Delaware law against liability that may arise by reason of
their service to us, and to advance expenses incurred as a
result of any proceeding against them as to which they could be
indemnified. We believe that the limitation of liability
provision in our amended and restated certification of
incorporation and the indemnification agreements will facilitate
our ability to continue to attract and retain qualified
individuals to serve as directors and officers.
Renunciation
of Interest and Expectancy in Certain Corporate
Opportunities
Our certificate of incorporation provides that we will renounce
any interest or expectancy in, or in being offered an
opportunity to participate in, any business opportunity that may
be from time to time presented to (i) members of our board
of directors who are not our employees, (ii) their
respective employers and (iii) affiliates of the foregoing
(other than us and our subsidiaries), other than opportunities
expressly presented to such directors solely in their capacity
as our director. This provision will apply even if the
opportunity is one that we might reasonably have pursued or had
the ability or desire to pursue if granted the opportunity to do
so. Furthermore, no such person will be liable to us for breach
of any fiduciary duty, as a director or otherwise, by reason of
the fact that such person pursues or acquires any such business
opportunity, directs any such business opportunity to another
person or fails to present any such business opportunity, or
information regarding any such business opportunity. None of
such persons or entities will have any duty to refrain from
engaging directly or indirectly in the same or similar business
activities or lines of business as us or any of our subsidiaries.
For example, affiliates of our non-employee directors may become
aware, from time to time, of certain business opportunities,
such as acquisition opportunities, and may direct such
opportunities to other businesses in which they have invested or
advise, in which case we may not become aware of or otherwise
have the ability to pursue such opportunities. Further, such
businesses may choose to compete with us for these
opportunities. As a result, our renouncing our interest and
expectancy in any business opportunity that may be, from time to
time, presented to such persons or entities could adversely
impact our business or prospects if attractive business
opportunities are procured by such persons or entities for their
own benefit rather than for ours.
148
SHARES ELIGIBLE
FOR FUTURE SALE
Prior to this offering, there has been no public market for our
common stock, and we cannot predict what effect, if any, market
sales of shares of common stock or the availability of shares of
common stock for sale will have on the market price of our
common stock. Future sales of substantial amounts of our common
stock in the public market, or the perception that substantial
sales may occur, could materially and adversely affect the
prevailing market price of our common stock and could impair our
future ability to raise capital through the sale of our equity
at a time and price we deem appropriate.
Upon completion of this offering, we will
have shares of common stock
outstanding. Of these shares of common stock,
the shares of common stock
being sold in this offering will be freely tradable without
restriction under the Securities Act, except for any such shares
which may be held or acquired by an affiliate of
ours, as that term is defined in Rule 144 promulgated under
the Securities Act, which shares will be subject to the volume
limitations and other restrictions of Rule 144 described
below. The remaining shares
of common stock held by our existing stockholders upon
completion of this offering will be restricted
securities, as that phrase is defined in Rule 144,
and may be resold only after registration under the Securities
Act or pursuant to an exemption from such registration,
including, among others, the exemptions provided by
Rule 144 of the Securities Act, which is summarized below.
Taking into account the
lock-up
agreements described below and the provisions of Rule 144,
additional shares of our common stock will be available for sale
in the public market as follows:
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shares
of restricted securities will be available for sale at various
times after the date of this prospectus pursuant to
Rule 144; and
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shares
subject to the
lock-up
agreements will be eligible for sale at various times beginning
180 days after the date of this prospectus pursuant to Rule
144.
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Rule 144
The availability of Rule 144 will vary depending on whether
shares of our common stock are restricted and whether they are
held by an affiliate or a non-affiliate. For purposes of
Rule 144, a non-affiliate is any person or entity that is
not our affiliate at the time of sale and has not been our
affiliate during the preceding three months.
In general, under Rule 144, once we have been a reporting
company subject to the reporting requirements of Section 13
or Section 15(d) of the Exchange Act for at least
90 days, an affiliate who has beneficially owned shares of
our restricted common stock for at least six months would be
entitled to sell within any three-month period any number of
such shares that does not exceed the greater of:
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1% of the number of shares of our common stock then outstanding,
which will equal
approximately shares
immediately after consummation of this offering; or
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the average weekly trading volume of our common stock on the
open market during the four calendar weeks preceding the filing
of a notice on Form 144 with respect to that sale.
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In addition, any sales by our affiliates under Rule 144 are
also subject to manner of sale provisions and notice
requirements and to the availability of current public
information about us. Our affiliates must comply with all the
provisions of Rule 144 (other than the six-month holding
period requirement) in order to sell shares of our common stock
that are not restricted securities, such as shares acquired by
our affiliates either in this offering or through purchases in
the open market following this offering. An
affiliate is a person that directly, or indirectly
through one or more intermediaries, controls, is controlled by,
or is under common control with, an issuer.
Similarly, once we have been a reporting company for at least
90 days, a non-affiliate who has beneficially owned shares
of our restricted common stock for at least six months would be
entitled to sell those shares without complying with the volume
limitation, manner of sale and notice provisions of
Rule 144, provided that certain public information is
available. Furthermore, a non-affiliate who has beneficially
owned
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our shares of restricted common stock for at least one year will
not be subject to any restrictions under Rule 144 with
respect to such shares, regardless of how long we have been a
reporting company.
We are unable to estimate the number of shares that will be sold
under Rule 144 since this will depend on the market price
for our common stock, the personal circumstances of the
stockholder and other factors.
Lock-Up
Agreements
We and our officers, directors and holders of all of our common
stock have agreed with the underwriters not to offer, sell,
dispose of or hedge any shares of our common stock or securities
convertible into or exchangeable for shares of our common stock,
subject to specified limited exceptions and extensions described
elsewhere in this prospectus, during the period continuing
through the date that is 180 days (subject to extension)
after the date of this prospectus, except with the prior written
consent
of ,
on behalf of the underwriters. See
Underwriting.
may release any of the securities subject to these
lock-up
agreements at any time without notice.
Immediately following the consummation of this offering,
stockholders subject to
lock-up
agreements will
hold shares
of our common stock, representing
about % of our outstanding shares
of common stock after giving effect to this offering.
150
MATERIAL
UNITED STATES FEDERAL INCOME AND ESTATE TAX CONSEQUENCES TO
NON-U.S.
HOLDERS
The following is a summary of the material United States federal
income and estate tax consequences to a
non-U.S. holder
(as defined below) of the purchase, ownership and disposition of
shares of our common stock as of the date hereof. Except where
noted, this summary deals only with shares of our common stock
that are held as a capital asset (generally property held for
investment).
A
non-U.S. holder
means a beneficial owner of common stock (other than a
partnership or entity treated as a partnership for United States
federal income tax purposes) that is not for United States
federal income tax purposes any of the following:
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an individual citizen or resident of the United States,
including an alien individual who is a lawful permanent resident
of the United States or who meets the substantial
presence test under Section 7701(b) of the Code;
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a corporation (or any other entity treated as a corporation for
United States federal income tax purposes) created or organized
in or under the laws of the United States, any state thereof or
the District of Columbia;
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an estate the income of which is subject to United States
federal income taxation regardless of its source; or
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a trust if it (1) is subject to the primary supervision of
a court within the United States and one or more United States
persons have the authority to control all substantial decisions
of the trust or (2) has a valid election in effect under
applicable United States Treasury regulations to be treated as a
United States person.
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This summary is based upon provisions of the Code, and United
States Treasury regulations, administrative rulings and judicial
decisions as of the date hereof. Those authorities may be
changed, perhaps retroactively, so as to result in United States
federal income and estate tax consequences different from those
summarized below. This summary does not address all aspects of
United States federal income and estate taxes and does not deal
with foreign, state, local or other tax considerations that may
be relevant to
non-U.S. holders
in light of their personal circumstances. In addition, it does
not represent a detailed description of the United States
federal income tax consequences applicable to you if you are an
investor subject to special treatment under the United States
federal income tax laws such as (without limitation):
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United States expatriates;
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stockholders that hold our common stock as part of a straddle,
appreciated financial position, synthetic security, hedge,
conversion transaction or other integrated investment or risk
reduction transaction;
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stockholders who hold our common stock as a result of a
constructive sale;
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stockholders who acquired our common stock through the exercise
of employee stock options or otherwise as compensation or
through a tax-qualified retirement plan;
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stockholders that are partnerships or entities treated as
partnerships for United States federal income tax purposes or
other pass-through entities or owners thereof;
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controlled foreign corporations;
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passive foreign investment companies;
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financial institutions;
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insurance companies;
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tax-exempt entities;
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dealers in securities or foreign currencies; and
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traders in securities that
mark-to-market.
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Furthermore, this summary does not address any aspect of state,
local or foreign tax laws or the alternative minimum tax
provisions of the Code.
If a partnership (including an entity that is classified as a
partnership for United States federal income tax purposes) holds
shares of our common stock, the tax treatment of a partner will
generally depend upon the status of the partner and the
activities of the partnership. If you are a partner of a
partnership (including an entity that is classified as a
partnership for United States federal income tax purposes
holding shares of our common stock, you should consult your tax
advisors.
We have not sought any ruling from the IRS with respect to the
statements made and the conclusions reached in the following
summary, and there can be no assurance that the IRS will agree
with such statements and conclusions. If you are considering
the purchase of shares of our common stock, you should consult
your own tax advisors concerning the particular United States
federal income and estate tax consequences to you of the
ownership of shares of our common stock, as well as the
consequences to you arising under the laws of any other taxing
jurisdiction.
Dividends
If we make distributions on our common stock, such distributions
will constitute dividends for United States federal income tax
purposes to the extent paid from our current or accumulated
earnings and profits, as determined under United States federal
income tax principles. Distributions in excess of earnings and
profits will constitute a return of capital that is applied
against and reduces the
non-U.S. holders
adjusted tax basis in our common stock. Any remaining excess
will be treated as gain realized on the sale or other
disposition of our common stock and will be treated as described
under Gain on Disposition of Common Stock below. Any
dividends paid to a
non-U.S. holder
of shares of our common stock generally will be subject to
withholding of United States federal income tax at a 30% rate or
such lower rate as may be specified by an applicable income tax
treaty. In order to receive a reduced treaty rate, a
non-U.S. holder
must (a) provide us with IRS
Form W-8BEN
(or applicable substitute or successor form) properly
certifying, under penalty of perjury, eligibility for the
reduced rate, or (b) if shares of our common stock are held
through certain foreign intermediaries, satisfy the relevant
certification requirements of applicable United States Treasury
regulations. A
non-U.S. holder
of shares of our common stock eligible for a reduced rate of
United States withholding tax pursuant to an income tax treaty
may obtain a refund of any excess amounts withheld by filing an
appropriate claim for refund with the IRS.
Dividends paid to a
non-U.S. holder
that are effectively connected with the conduct of a trade or
business by the
non-U.S. holder
within the United States (and, if required by an applicable
income tax treaty, are attributable to a United States permanent
establishment) generally are not subject to the withholding tax.
Instead, such dividends are subject to United States federal
income tax on a net income basis in the same manner as if the
non-U.S. holder
were a United States person as defined under the Code. In order
to obtain this exemption from withholding tax, a
non-U.S. holder
must provide us with an IRS
Form W-8ECI
(or applicable substitute or successor form) properly
certifying, under penalty of perjury, eligibility for such
exemption. Any such effectively connected dividends received by
a foreign corporation may be subject to an additional
branch profits tax at a 30% rate or such lower rate
as may be specified by an applicable income tax treaty.
Gain on
Disposition of Common Stock
Any gain realized on the disposition of shares of our common
stock generally will not be subject to United States federal
income tax unless:
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the gain is effectively connected with a trade or business of
the
non-U.S. holder
in the United States (and, if required by an applicable income
tax treaty, is attributable to a United States permanent
establishment of the
non-U.S. holder);
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the
non-U.S. holder
is an individual who is present in the United States for
183 days or more in the taxable year of that disposition,
and certain other conditions are met; or
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we are or have been a United States real property holding
corporation for United States federal income tax purposes
at any time during the shorter of the period that the
non-U.S. holder
has held our common stock or the five-year period ending on the
date that the
non-U.S. holder
disposes of our common stock.
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Unless an applicable income tax treaty provides otherwise, a
non-U.S. holder
who has gain that is described in the first bullet point
immediately above will be subject to tax on the net gain derived
from the sale or other taxable disposition under regular
graduated United States federal income tax rates in the same
manner as if it were a United States person as defined under the
Code. In addition, a
non-U.S. holder
described in the first bullet point immediately above that is a
foreign corporation may be subject to the branch profits tax
equal to 30% of its effectively connected earnings and profits
that are not reinvested in its United States trade or business
or at such lower rate as may be specified by an applicable
income tax treaty.
An individual
non-U.S. holder
who is described in the second bullet point immediately above
will be subject to a flat 30% tax on the gain recognized from
the sale or other taxable disposition (or such lower rate as may
be specified by an applicable income tax treaty), which may be
offset by certain United States-source capital losses.
With respect to the third bullet point, we have determined that
we are, and will continue to be, a United States real
property holding corporation for United States federal
income tax purposes. However, if shares of our common stock are
regularly traded on an established securities market, only a
non-U.S. holder
who holds or held (at any time during the shorter of the
five-year period preceding the date of disposition or the
holders holding period) more than 5% of the shares of our
common stock will be subject to United States federal income tax
on the disposition of shares of our common stock. If shares of
our common stock are not regularly traded on an established
securities market, all
non-U.S. holders
will be subject to United States federal income tax on
disposition of shares of our common stock.
Non-U.S. holders
should consult their tax advisors with respect to the
application of the foregoing rules to their ownership and
disposition of our common stock.
Federal
Estate Tax
Shares of our common stock held by an individual
non-U.S. holder
at the time of death will be included in such holders
gross estate for United States federal estate tax purposes,
unless an applicable estate tax treaty provides otherwise, and
therefore, may be subject to United States federal estate tax.
Information
Reporting and Backup Withholding
We must report annually to the IRS and to each
non-U.S. holder
the amount of dividends paid to such holder and the tax withheld
with respect to such dividends, regardless of whether
withholding was required. Copies of the information returns
reporting such dividends and withholding may also be made
available to the tax authorities in the country in which the
non-U.S. holder
resides under the provisions of an applicable income tax treaty.
A
non-U.S. holder
will be subject to backup withholding for dividends paid to such
holder unless such holder certifies under penalty of perjury
that it is a
non-U.S. holder
(and the payor does not have actual knowledge or reason to know
that such holder is a United States person as defined under the
Code), or such holder otherwise establishes an exemption.
Information reporting and, depending on the circumstances,
backup withholding will apply to the proceeds of a sale of
shares of our common stock within the United States or conducted
through certain United States-related financial intermediaries,
unless the beneficial owner certifies under penalty of perjury
that it is a
non-U.S. holder
(and the payor does not have actual knowledge or reason to know
that the
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beneficial owner is a United States person as defined under the
Code), or such owner otherwise establishes an exemption.
Backup withholding is not an additional tax. Any amounts
withheld under the backup withholding rules may be allowed as a
refund or a credit against a
non-U.S. holders
United States federal income tax liability provided the required
information is timely furnished to the IRS.
Additional
Withholding Requirements
Under recently enacted legislation and administrative guidance,
the relevant withholding agent may be required to withhold 30%
of any dividends paid after December 31, 2013 and the
proceeds of a sale of shares of our common stock paid after
December 31, 2014 to (1) a foreign financial
institution unless such foreign financial institution agrees to
verify, report and disclose its U.S. accountholders and
meets certain other specified requirements or (2) a
non-financial foreign entity that is the beneficial owner of the
payment unless such entity certifies that it does not have any
substantial United States owners or provides the name, address
and taxpayer identification number of each substantial United
States owner and such entity meets certain other specified
requirements.
154
CERTAIN
ERISA CONSIDERATIONS
The following is a summary of certain considerations associated
with the purchase of shares of our common stock by employee
benefit plans that are subject to Title I of the Employee
Retirement Income Security Act of 1974, as amended
(ERISA), plans, individual retirement accounts
(IRAs) and other arrangements that are subject to
Section 4975 of the Code or provisions under any federal,
state, local,
non-U.S. or
other laws or regulations that are similar to such provisions of
the Code or ERISA (collectively, Similar Laws), and
entities whose underlying assets are considered to include
plan assets of any such plan, account or arrangement
(each, a Plan).
General
Fiduciary Matters
ERISA and the Code impose certain duties on persons who are
fiduciaries of a Plan subject to Title I of ERISA or
Section 4975 of the Code and prohibit certain transactions
involving the assets of a Plan and its fiduciaries or other
interested parties. Under ERISA and the Code, any person who
exercises any discretionary authority or control over the
administration of such a Plan or the management or disposition
of the assets of such a Plan, or who renders investment advice
for a fee or other compensation to such a Plan, is generally
considered to be a fiduciary of the Plan.
In considering an investment in shares of our common stock with
the assets of any Plan, a fiduciary should determine whether the
investment is in accordance with the documents and instruments
governing the Plan and the applicable provisions of ERISA, the
Code or any Similar Law relating to a fiduciarys duties to
the Plan including, without limitation, the prudence,
diversification, delegation of control and prohibited
transaction provisions of ERISA, the Code and any other
applicable Similar Laws.
Prohibited
Transaction Issues
Section 406 of ERISA and Section 4975 of the Code
prohibit Plans from engaging in specified transactions involving
plan assets with persons or entities who are parties in
interest, within the meaning of ERISA, or
disqualified persons, within the meaning of
Section 4975 of the Code, unless an exemption is available.
A party in interest or disqualified person who engages in a
non-exempt prohibited transaction may be subject to excise taxes
and other penalties and liabilities under ERISA and the Code. In
addition, the fiduciary of a Plan that engages in such a
non-exempt prohibited transaction may be subject to penalties
and liabilities under ERISA and the Code.
The foregoing discussion is general in nature and is not
intended to be all-inclusive. Due to the complexity of these
rules and the penalties that may be imposed upon persons
involved in non-exempt prohibited transactions, it is
particularly important that fiduciaries, or other persons
considering purchasing shares of our common stock on behalf of,
or with the assets of, any employee benefit plan, consult with
their counsel to determine whether such employee benefit plan,
IRA or other arrangement is subject to Title I of ERISA,
Section 4975 of the Code or any Similar Laws.
155
UNDERWRITING
Under the terms and subject to the conditions contained in an
underwriting agreement dated the date of this prospectus, the
underwriters named below have severally agreed to purchase, and
we have agreed to sell to them, the number of shares of common
stock set forth opposite their names below:
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Number of Shares of
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Name of Underwriter
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Common Stock
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FBR Capital Markets & Co.
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Raymond James & Associates, Inc.
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Total
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The underwriting agreement provides that the obligations of the
underwriters to purchase and accept delivery of the common stock
offered by this prospectus are subject to the satisfaction of
the conditions contained in the underwriting agreement,
including:
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the representations and warranties made by us to the
underwriters are true;
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there is no material adverse change in the financial
market; and
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we deliver customary closing documents and legal opinions to the
underwriters.
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The underwriters are obligated to purchase and accept delivery
of all of the shares of common stock offered by this prospectus,
if any are purchased, other than those covered by the option to
purchase additional shares of common stock described below. The
underwriting agreement also provides that if any underwriter
defaults, the purchase commitments of non-defaulting
underwriters may be increased or the offering may be terminated.
The underwriters propose to offer the common stock directly to
the public at the public offering price indicated on the cover
page of this prospectus and to various dealers at that price
less a concession not in excess of
$ per share. Any underwriter may
allow, and such dealers may reallow, a concession not in excess
of $ per share. If all of the
shares of common stock are not sold at the public offering
price, the underwriters may change the public offering price and
other selling terms. The common stock is offered by the
underwriters as stated in this prospectus, subject to receipt
and acceptance by them. The underwriters reserve the right to
reject an order for the purchase of shares of common stock in
whole or in part.
Option to
Purchase Additional Common Stock
We have granted the underwriters an option, exercisable for
30 days after the date of this prospectus, to purchase from
time to time up to an aggregate
of
additional shares of common stock to cover over-allotments, if
any, at the public offering price less the underwriting discount
set forth on the cover page of this prospectus. The underwriters
may exercise the option to purchase additional shares of common
stock only to cover over-allotments made in connection with the
sale of common stock offered in this offering.
Discounts
and Expenses
The following table shows the amount per share of common stock
and total underwriting discounts we will pay to the underwriters
(dollars in thousands, except per share amounts). The amounts
are shown assuming both no exercise and full exercise of the
underwriters option to purchase additional shares of
common stock.
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Total Without
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Total With
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Over-Allotment
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Over-Allotment
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Per Share
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Exercise
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Exercise
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Price to the public
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Underwriting discount and commissions
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Proceeds to us (before offering expenses)
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The expenses of this offering that are payable by us are
estimated to be $ .
156
Indemnification
We have agreed to indemnify the underwriters against certain
liabilities that may arise in connection with this offering,
including liabilities under the Securities Act, and to
contribute to payments that the underwriters may be required to
make for those liabilities.
Lock-Up
Agreements
Subject to specified exceptions, we, our directors, executive
officers and stockholders have agreed with the underwriters, for
a period of days after the
date of this prospectus, without the prior written consent
of :
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not to offer for sale, sell, pledge or otherwise dispose of the
common stock;
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not to grant or sell any option or contract to purchase any of
the common stock;
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not to file or cause to be filed a registration statement,
including any amendments, with respect to the registration of
any shares of common stock or participate in any such
registration, including under this registration statement;
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not to enter into any swap or other agreement that transfers any
of the economic consequences of ownership of or otherwise
transfer or dispose of, directly or indirectly, any of the
common stock; and
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not to enter into any hedging, collar or other transaction or
arrangement that is designed or reasonably expected to lead to
or result in a transfer, in whole or in part, of any of the
economic consequences of ownership of the common stock, whether
or not such transfer would be for any consideration.
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These agreements also prohibit us from entering into any of the
foregoing transactions with respect to any securities that are
convertible into or exchangeable for the common stock or with
respect to us, to publicly disclose the intention to do the
foregoing transactions.
may, in its discretion and at any time, release all or any
portion of the securities subject to these
agreements.
does not have any present intent or any understanding to release
all or any portion of the securities subject to these agreements.
The -day period described in the
preceding paragraphs will be extended if:
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during the last 17 days of
the -day period, we issue an
earnings release or material news or a material event relating
to us occurs; or
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prior to the expiration of
the -day
period, we announce that we will release earnings results during
the 16-day period beginning on the last day of
the -day period, in which case the
restrictions described in the preceding paragraphs will continue
to apply until the expiration of the
18-day
period beginning on the issuance of the earnings release or the
occurrence of the material event.
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Stabilization
Until this offering is completed, rules of the SEC may limit the
ability of the underwriters to bid for and purchase the common
stock. As an exception to these rules, the underwriters may
engage in activities that stabilize, maintain or otherwise
affect the price of the common stock, including:
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short sales;
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syndicate covering transactions;
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imposition of penalty bids; and
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purchases to cover positions created by short sales.
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Stabilizing transactions consist of bids or purchases made for
the purpose of preventing or retarding a decline in the market
price of the common stock while this offering is in progress.
Stabilizing transactions may include making short sales of
shares of common stock, which involve the sale by the
underwriters of a
157
greater number of shares of common stock than they are required
to purchase in this offering and purchasing common stock from us
or in the open market to cover positions created by short sales.
Short sales may be covered shorts, which are short
positions in an amount not greater than the underwriters
option to purchase additional shares of common stock referred to
above, or may be naked shorts, which are short
positions in excess of that amount.
Each underwriter may close out any covered short position either
by exercising its option to purchase additional shares of common
stock, in whole or in part, or by purchasing common stock in the
open market. In making this determination, each underwriter will
consider, among other things, the price of common stock
available for purchase in the open market compared to the price
at which the underwriter may purchase shares of common stock
pursuant to the option to purchase additional shares of common
stock.
A naked short position is more likely to be created if the
underwriters are concerned that there may be downward pressure
on the price of the common stock in the open market that could
adversely affect investors who purchased in this offering. To
the extent that the underwriters create a naked short position,
they will purchase shares of common stock in the open market to
cover the position.
As a result of these activities, the price of the common stock
may be higher than the price that otherwise might exist in the
open market. If the underwriters commence these activities, they
may discontinue them without notice at any time. The
underwriters may carry out these transactions on Nasdaq or
otherwise.
Discretionary
Accounts
The underwriters may confirm sales of the common stock offered
by this prospectus to accounts over which they exercise
discretionary authority but do not expect those sales to exceed
5% of the total shares of commons stock offered by this
prospectus.
Listing
We expect to apply to list our common stock on Nasdaq under the
symbol ARMS. There is no assurance that this
application will be approved.
Determination
of Initial Offering Price
Prior to this offering, there has been no public market for the
shares. The initial public offering price has been negotiated
among us and the representatives. Among the factors to be
considered in determining the initial public offering price of
the shares, in addition to prevailing market conditions, will be
our historical performance, estimates of our business potential
and earnings prospects, an assessment of our management and the
consideration of the above factors in relation to market
valuation of companies in related businesses.
Neither we nor the underwriters can assure investors that an
active market will develop for our common stock or that shares
will trade in the public market at or above the initial public
offering price.
Electronic
Prospectus
A prospectus in electronic format may be available on the
Internet sites or through other online services maintained by
one or more of the underwriters participating in this offering,
or by their affiliates. In those cases, prospective investors
may view offering terms online and, depending upon the
underwriters, prospective investors may be allowed to place
orders online. The underwriters may agree with us to allocate a
specific number of shares of common stock for sale to online
brokerage account holders. Any such allocation for online
distributions will be made by the underwriters on the same basis
as other allocations.
Other than the prospectus in electronic format, the information
on any underwriters website and any information contained
in any other website maintained by the underwriters is not part
of this prospectus or the registration statement of which this
prospectus forms a part, has not been approved or endorsed by us
or any underwriter in its capacity as underwriter and should not
be relied upon by investors.
158
Notice to
Prospective Investors in the EEA
In relation to each Member State of the European Economic Area
(EEA) which has implemented the Prospectus Directive (each, a
Relevant Member State) an offer to the public of any
shares which are the subject of the offering contemplated by
this prospectus may not be made in that Relevant Member State,
except that an offer to the public in that Relevant Member State
of any shares may be made at any time under the following
exemptions under the Prospectus Directive, if they have been
implemented in that Relevant Member State:
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(a)
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to legal entities which are authorized or regulated to operate
in the financial markets or, if not so authorized or regulated,
whose corporate purpose is solely to invest in securities;
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(b)
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to any legal entity which has two or more of (1) an average
of at least 250 employees during the last financial year;
(2) a total balance sheet of more than 43,000,000 and
(3) an annual net turnover of more than 50,000,000,
as shown in its last annual or consolidated accounts;
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(c)
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it is a qualified investor within the meaning of the
law in that Relevant Member State implementing
Article 2(1)(e) of the Prospectus Directive; and
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(d)
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in the case of any shares acquired by it as a financial
intermediary, as that term is used in Article 3(2) of the
Prospectus Directive, (i) the shares acquired by it in the
offering have not been acquired on behalf of, nor have they been
acquired with a view to their offer or resale to, persons in any
Relevant Member State other than qualified investors
(as defined in the Prospectus Directive), or in circumstances in
which the prior consent of the representative has been given to
the offer or resale; or (ii) where shares have been
acquired by it on behalf of persons in any Relevant Member State
other than qualified investors, the offer of those shares to it
is not treated under the Prospectus Directive as having been
made to such persons.
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In addition, in the United Kingdom, this document is being
distributed only to, and is directed only at, and any offer
subsequently made may only be directed at persons who are
qualified investors (as defined in the Prospectus
Directive) (i) who have professional experience in matters
relating to investments falling within Article 19
(5) of the Financial Services and Markets Act 2000
(Financial Promotion) Order 2005, as amended (the
Order)
and/or
(ii) who are high net worth companies (or persons to whom
it may otherwise be lawfully communicated) falling within
Article 49(2)(a) to (d) of the Order (all such persons
together being referred to as relevant persons).
This document must not be acted on or relied on in the United
Kingdom by persons who are not relevant persons. In the United
Kingdom, any investment or investment activity to which this
document relates is only available to, and will be engaged in
with, relevant persons.
Notice to
Prospective Investors in Australia
This document has not been lodged with the Australian
Securities & Investments Commission and is only
directed to certain categories of exempt persons. Accordingly,
if you receive this document in Australia:
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(a)
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you confirm and warrant that you are either:
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(i)
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a sophisticated investor under
section 708(8)(a) or (b) of the Corporations Act 2001
(Cth) of Australia (Corporations Act);
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(ii)
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a sophisticated investor under
section 708(8)(c) or (d) of the Corporations Act and
that you have provided an accountants certificate to the
Company which complies with the requirements of
section 708(8)(c)(i) or (ii) of the Corporations Act
and related regulations before the offer has been made; or
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(iii)
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a professional investor within the meaning of
section 708(11)(a) or (b) of the Corporations Act,
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and to the extent that you are unable to confirm or warrant that
you are an exempt sophisticated investor or professional
investor under the Corporations Act, any offer made to you under
this document is void and incapable of acceptance.
159
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(b)
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you warrant and agree that you will not offer any of the shares
issued to you pursuant to this document for resale in Australia
within 12 months of those shares being issued unless any
such resale offer is exempt from the requirement to issue a
disclosure document under section 708 of the Corporations
Act.
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Notice to
Prospective Investors in Switzerland
This document, as well as any other material relating to the
shares which are the subject of the offering contemplated by
this prospectus, do not constitute an issue prospectus pursuant
to Article 652a
and/or 1156
of the Swiss Code of Obligations. The shares will not be listed
on the SIX Swiss Exchange and, therefore, the documents relating
to the shares, including, but not limited to, this document, do
not claim to comply with the disclosure standards of the listing
rules of SIX Swiss Exchange and corresponding prospectus schemes
annexed to the listing rules of the SIX Swiss Exchange. The
shares are being offered in Switzerland by way of a private
placement, i.e., to a small number of selected investors only,
without any public offer and only to investors who do not
purchase the shares with the intention to distribute them to the
public. The investors will be individually approached by the
issuer from time to time. This document, as well as any other
material relating to the shares, is personal and confidential
and do not constitute an offer to any other person. This
document may only be used by those investors to whom it has been
handed out in connection with the offering described herein and
may neither directly nor indirectly be distributed or made
available to other persons without express consent of the
issuer. It may not be used in connection with any other offer
and shall in particular not be copied
and/or
distributed to the public in (or from) Switzerland.
Notice to
Prospective Investors in the United Kingdom
Each underwriter has represented and agreed that it has only
communicated or caused to be communicated and will only
communicate or cause to be communicated an invitation or
inducement to engage in investment activity (within the meaning
of Section 21 of the Financial Services and Markets Act
2000) in connection with the issue or sale of the shares in
circumstances in which Section 21(1) of such Act does not
apply to us and it has complied and will comply with all
applicable provisions of such Act with respect to anything done
by it in relation to any shares in, from or otherwise involving
the United Kingdom.
160
CONFLICTS
OF INTEREST
The underwriters and their affiliates may provide, in the
future, investment banking, financial advisory or other
financial services for us and our affiliates, for which they may
receive advisory or transaction fees, as applicable, plus
out-of-pocket
expenses, of the nature and in amounts customary in the industry
for such financial services.
The underwriters are also expected to be underwriters in
connection with the Concurrent ARP Offering and may receive
certain discounts, commissions and fees in connection therewith.
Raymond James Bank, FSB, an affiliate of Raymond
James & Associates, Inc., one of the underwriters in
this offering, is expected to receive more than 5% of the net
proceeds of this offering in connection with the repayment of
our Senior Secured Term Loan and our Senior Secured Revolving
Credit Facility. See Use of Proceeds. Accordingly,
this offering is being made in compliance with the requirements
of FINRA Rule 5121. Rule 5121 requires that a
qualified independent underwriter meeting certain
standards to participate in the preparation of the registration
statement and prospectus and exercise the usual standards of due
diligence with respect thereto. FBR Capital Markets &
Co. has agreed to act as a qualified independent
underwriter within the meaning of FINRA Rule 5121 in
connection with this offering. FBR Capital Markets &
Co. will not receive any additional compensation for acting as a
qualified independent underwriter. Raymond James &
Associates, Inc. will not confirm sales of the securities to any
account over which it exercises discretionary authority without
the prior written approval of the customer.
161
LEGAL
MATTERS
The validity of the shares of common stock offered hereby and
certain legal matters in connection with this offering will be
passed upon for us by Armstrong Teasdale LLP. The validity of
the shares of common stock will be passed upon for the
underwriters by Simpson Thacher & Bartlett LLP, New
York, New York.
COAL
RESERVES
The information appearing in, and incorporated by reference in,
this prospectus concerning our estimates of proven and probable
coal reserves at December 31, 2010 were prepared by Weir
International, Inc., an independent mining and geological
consultant.
INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRMS
The consolidated financial statements of Armstrong Energy, Inc.
and subsidiaries (formerly Armstrong Land Company, LLC and
subsidiaries) as of December 31, 2010 and 2009 and for each
of the years in the two-year period ended December 31, 2010
appearing in this prospectus have been audited by
Ernst & Young LLP, an independent registered public
accounting firm, as stated in their report appearing in this
prospectus, and are included in reliance upon such report given
on their authority as experts in accounting and auditing.
The consolidated financial statements of Armstrong Energy, Inc.
and subsidiaries (formerly Armstrong Land Company, LLC and
subsidiaries) as of December 31, 2008 and for the year
ended December 31, 2008 appearing in this prospectus have
been audited by Grant Thornton LLP, an independent registered
public accounting firm, as stated in their report appearing in
this prospectus.
CHANGE IN
AUDITOR
Prior to engaging Ernst & Young as our independent
registered public accounting firm, KPMG LLP was engaged as our
Predecessors independent registered public accounting firm
to audit our Predecessors financial statements for the
fiscal year ended December 31, 2008. In February 2010, the
board of managers of our Predecessor dismissed KPMG LLP as our
Predecessors independent registered public accounting firm.
KPMG LLPs report on our Predecessors financial
statements for the fiscal year ended December 31, 2008 did
not contain an adverse opinion or a disclaimer of opinion, and
was not qualified or modified as to uncertainty, audit scope or
accounting principles. We have not included KPMGs report
in this prospectus. KPMG LLP was not engaged as the principal
accountant to audit our Predecessors financial statements
for the fiscal year ended December 31, 2010 or 2009, and
therefore, did not issue a report on such financial statements.
Furthermore, during the fiscal year ended December 31, 2008
and the subsequent period through February 2010, (i) there
were no disagreements with KPMG LLP on any matter of accounting
principles or practices, financial statement disclosure or
auditing scope or procedure, which disagreements, if not
resolved to the satisfaction of KPMG LLP, would have caused it
to make reference to the subject matter of the disagreement in
connection with its report on our Predecessors financial
statements for such period; and (ii) there were no
reportable events described in Item 304(a)(1)(v) of
Regulation S-K,
except that KPMG LLP advised our Predecessor of the material
weakness described herein. KPMG LLP identified several audit
adjustments. As a result of these adjustments and KPMG
LLPs interaction with our Predecessors former
controller, KPMG LLP believed that our Predecessor lacked an
adequately trained finance and accounting controller with
appropriate GAAP expertise. In KPMG LLPs opinion, this
resulted in an ineffective internal review of technical
accounting matters, overall financial statement presentation and
disclosure, resulting in a material weakness in internal
controls as of December 31, 2008. Our Predecessor
terminated the former controller and hired a new controller in
2009.
On March 4, 2010, our Predecessors board of managers
appointed Ernst & Young LLP as our new independent
registered public accounting firm. Ernst & Young LLP
audited our Predecessors financial statements for the
fiscal years ended December 31, 2009 and 2010 and has been
engaged as our independent registered public accounting firm for
our fiscal year ending December 31, 2011. During our two
most recent fiscal years, we did not consult with
Ernst & Young LLP with respect to any of the matters
or reportable events set forth in Item 304(a)(2)(i) and
(ii) of
Regulation S-K.
162
Notwithstanding the 2010 appointment of Ernst & Young
LLP as our Predecessors new independent registered public
accounting firm, on June 4, 2010, our Predecessors
board of managers engaged Grant Thornton LLP solely to re-audit
our Predecessors financial statements for the fiscal year
ended December 31, 2008. Our Predecessor was unable to
engage Ernst & Young LLP to re-audit the 2008
financial statements due to the fact that Ernst &
Young LLP performed certain consulting services for our
Predecessor during 2008 and, therefore, would not have been
deemed to be independent. During our two most recent fiscal
years, we did not consult with Grant Thornton LLP with respect
to any of the matters or reportable events set forth in
Item 304(a)(2)(i) and (ii) of
Regulation S-K.
On July 31, 2010, following Grant Thornton LLPs
completion of the 2008 audit, the board of managers of our
Predecessor dismissed Grant Thornton LLP. Grant Thornton
LLPs report on our Predecessors financial statements
for the fiscal year ended December 31, 2008 did not contain
an adverse opinion or a disclaimer of opinion, and was not
qualified or modified as to uncertainty, audit scope or
accounting principles. Grant Thornton LLP was not engaged as the
principal accountant to audit our Predecessors financial
statements for the fiscal year ended December 31, 2010 or
2009, and therefore, did not issue a report on such financial
statements. Furthermore, during the fiscal year ended
December 31, 2008 and the subsequent period through
July 31, 2010, (i) there were no disagreements with
Grant Thornton LLP on any matter of accounting principles or
practices, financial statement disclosure or auditing scope or
procedure, which disagreements, if not resolved to the
satisfaction of Grant Thornton LLP, would have caused it to make
reference to the subject matter of the disagreement in
connection with its report on our Predecessors financial
statements for such period; and (ii) there were no
reportable events described in Item 304(a)(1)(v) of
Regulation S-K.
We provided KPMG LLP and Grant Thornton LLP with a copy of the
foregoing disclosure prior to its filing with the SEC and
requested that each of KPMG LLP and Grant Thornton LLP furnish
us with a letter addressed to the SEC stating whether or not
each of them agrees with the above statements and, if not,
stating the respects in which it does not agree. Grant Thornton
LLPs and KPMG LLPs letters to the SEC are filed as
Exhibits 16.1 and 16.2, respectively, to the registration
statement of which this prospectus is a part.
WHERE YOU
CAN FIND MORE INFORMATION
We have filed a registration statement, of which this Prospectus
is a part, on
Form S-1
with the SEC relating to this offering. This Prospectus does not
contain all of the information in the registration statement and
the exhibits and financial statements included with the
registration statement. References in this Prospectus to any of
our contracts, agreements or other documents are not necessarily
complete, and you should refer to the exhibits attached to the
registration statement for copies of the actual contracts,
agreements or documents.
The Companys filings with the SEC are available to the
public on the SECs website at www.sec.gov. Those filings
will also be available to the public on, or accessible through,
our corporate web site at www.armstrongcoal.com. The information
contained on or accessible through our corporate web site or any
other web site that we may maintain is not part of this
prospectus or the registration statement of which this
prospectus is a part. You may also read and copy, at SEC
prescribed rates, any document we file with the SEC, including
the registration statement (and its exhibits) of which this
prospectus is a part, at the SECs Public Reference Room
located at 100 F Street, N.E., Washington D.C. 20549.
You can call the SEC at
1-800-SEC-0330
to obtain information on the operation of the Public Reference
Room. You may also request a copy of these filings, at no cost,
by writing to us at Armstrong Energy, Inc., 7733 Forsyth
Boulevard, Suite 1625, St. Louis, Missouri 63105,
Attention: Senior Vice President, Finance and Administration and
Chief Financial Officer or telephoning us at
(314) 727-8202.
163
Upon the effectiveness of the registration statement, we will be
subject to the informational requirements of the Exchange Act
and, in accordance with the Exchange Act, will file periodic
reports, proxy and information statements and other information
with the SEC. Such annual, quarterly and current reports; proxy
and information statements; and other information can be
inspected and copied at the locations set forth above. We will
report our financial statements on a year ended
December 31. We intend to furnish our stockholders with
annual reports containing consolidated financial statements
audited by our independent registered public accounting firm and
will post on our website our quarterly reports containing
unaudited consolidated financial statements for each of the
first three quarters of each fiscal year.
164
INDEX TO
FINANCIAL STATEMENTS
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F-2
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F-3
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F-4
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F-5
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F-6
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F-7
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F-8
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F-27
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F-28
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F-29
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F-30
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F-31
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F-1
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Armstrong Energy, Inc. and Subsidiaries (formerly
Armstrong Land Company, LLC and Subsidiaries)
We have audited the accompanying consolidated balance sheets of
Armstrong Energy, Inc. and Subsidiaries (formerly Armstrong Land
Company, LLC and Subsidiaries) (the Company) as of
December 31, 2010 and 2009, and the related consolidated
statements of operations, stockholders equity, and cash
flows for years then ended. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. We were not engaged to perform an
audit of the Companys internal control over financial
reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of
the Companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of the Company at December 31, 2010 and
2009, and the consolidated results of its operations and its
cash flows for the years then ended, in conformity with
U.S. generally accepted accounting principles.
As discussed in Note 3, the consolidated financial
statements have been restated to properly record depletion and
amortization of mineral rights, mine development and asset
retirement obligations.
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St. Louis, Missouri
May 9, 2011
Except for Notes 17 and 20, as to which date is
October 7, 2011 and Note 3, as to which the date is
February 10, 2012
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/s/ Ernst &
Young LLP
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F-2
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
Armstrong Energy, Inc. and Subsidiaries (formerly Armstrong Land
Company, LLC and Subsidiaries)
We have audited the accompanying consolidated statements of
operations, stockholders equity and cash flows of
Armstrong Energy, Inc. (a Delaware Corporation) and subsidiaries
(formerly Armstrong Land Company, LLC and subsidiaries) (the
Company) for the year ended December 31, 2008.
These financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. The Company is not required to
have, nor were we engaged to perform an audit of its internal
control over financial reporting. Our audit included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Companys internal control over
financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the results
of operations and cash flows of Armstrong Energy, Inc. and
subsidiaries (formerly Armstrong Land Company, LLC and
subsidiaries) for the year ended December 31, 2008 in
conformity with accounting principles generally accepted in the
United States of America.
St. Louis, Missouri
July 30, 2010 (except for Note 17
and the Reorganization paragraph
in Note 20, as to which the
date is October 7, 2011)
F-3
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and
Subsidiaries)
CONSOLIDATED
BALANCE SHEETS
(Dollars in thousands)
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|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
Restated
|
|
|
Restated
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
8,101
|
|
|
$
|
16,597
|
|
Accounts receivable
|
|
|
13,927
|
|
|
|
18,888
|
|
Inventories
|
|
|
13,011
|
|
|
|
5,774
|
|
Prepaid and other assets
|
|
|
1,357
|
|
|
|
1,139
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
36,396
|
|
|
|
42,398
|
|
Property, plant, equipment, and mine development, net
|
|
|
425,719
|
|
|
|
395,476
|
|
Intangible assets, net
|
|
|
2,037
|
|
|
|
2,742
|
|
Other noncurrent assets
|
|
|
13,886
|
|
|
|
10,002
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
478,038
|
|
|
$
|
450,618
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
18,681
|
|
|
$
|
16,725
|
|
Accrued liabilities and other
|
|
|
8,697
|
|
|
|
10,521
|
|
Construction retainage
|
|
|
625
|
|
|
|
853
|
|
Current portion of capital lease obligations
|
|
|
3,802
|
|
|
|
3,307
|
|
Short-term debt
|
|
|
1,686
|
|
|
|
28,741
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
33,491
|
|
|
|
60,147
|
|
Long-term debt
|
|
|
122,310
|
|
|
|
112,483
|
|
Asset retirement obligations
|
|
|
13,249
|
|
|
|
7,324
|
|
Accrued interest
|
|
|
|
|
|
|
889
|
|
Capital lease obligations
|
|
|
12,073
|
|
|
|
14,310
|
|
Other non-current liabilities
|
|
|
234
|
|
|
|
132
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
181,357
|
|
|
|
195,285
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value, 70,000,000 shares
authorized, 19,110,500 and shares issued and outstanding as of
December 31, 2010 and 2009, respectively
|
|
|
191
|
|
|
|
191
|
|
Preferred stock, $0.01 par value, 1,000,000 shares authorized,
no shares issued and outstanding as of December 31, 2010
and 2009, respectively
|
|
|
|
|
|
|
|
|
Additional
paid-in-capital
|
|
|
204,888
|
|
|
|
204,809
|
|
Accumulated deficit
|
|
|
(34,274
|
)
|
|
|
(39,092
|
)
|
|
|
|
|
|
|
|
|
|
Armstrong Energy, Inc.s equity
|
|
|
170,805
|
|
|
|
165,908
|
|
Non-controlling interest
|
|
|
125,876
|
|
|
|
89,425
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
296,681
|
|
|
|
255,333
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
478,038
|
|
|
$
|
450,618
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-4
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and
Subsidiaries)
CONSOLIDATED
STATEMENTS OF OPERATIONS
(Dollars in thousands, except per share
amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
Restated
|
|
|
Restated
|
|
|
|
|
|
Revenue
|
|
$
|
220,625
|
|
|
$
|
167,904
|
|
|
$
|
57,069
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
151,838
|
|
|
|
127,886
|
|
|
|
45,817
|
|
Depreciation, depletion, and amortization
|
|
|
18,892
|
|
|
|
12,480
|
|
|
|
5,451
|
|
Asset retirement obligation expenses
|
|
|
3,087
|
|
|
|
1,984
|
|
|
|
359
|
|
Selling, general, and administrative costs
|
|
|
27,656
|
|
|
|
24,336
|
|
|
|
13,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
19,152
|
|
|
|
1,218
|
|
|
|
(7,598
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
198
|
|
|
|
169
|
|
|
|
375
|
|
Interest expense
|
|
|
(11,070
|
)
|
|
|
(12,651
|
)
|
|
|
(14,752
|
)
|
Other income (expense), net
|
|
|
(111
|
)
|
|
|
819
|
|
|
|
596
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
8,169
|
|
|
|
(10,445
|
)
|
|
|
(21,379
|
)
|
Income (loss) attributable to non-controlling interest
|
|
|
(3,351
|
)
|
|
|
1,730
|
|
|
|
5,552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to common stockholders
|
|
$
|
4,818
|
|
|
$
|
(8,715
|
)
|
|
$
|
(15,827
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share attributable to common stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
0.25
|
|
|
$
|
(0.50
|
)
|
|
$
|
(1.35
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-5
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and
Subsidiaries)
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS EQUITY
Years Ended December 31, 2010, 2009 and
2008
(Amounts in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Common
|
|
|
|
|
|
Additional
|
|
|
Accumulated
|
|
|
Non-Controlling
|
|
|
Stockholders
|
|
|
|
Stock
|
|
|
Amount
|
|
|
Paid-in-Capital
|
|
|
Deficit
|
|
|
Interest
|
|
|
Equity
|
|
|
Balance at December 31, 2007
|
|
|
9,250
|
|
|
$
|
93
|
|
|
$
|
98,578
|
|
|
$
|
(14,550
|
)
|
|
$
|
671
|
|
|
$
|
84,792
|
|
Issuance of common stock
|
|
|
4,745
|
|
|
|
47
|
|
|
|
50,878
|
|
|
|
|
|
|
|
|
|
|
|
50,925
|
|
Stock compensation expense
|
|
|
|
|
|
|
|
|
|
|
163
|
|
|
|
|
|
|
|
|
|
|
|
163
|
|
Minority contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54,500
|
|
|
|
54,500
|
|
Purchase of minority interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(84
|
)
|
|
|
(84
|
)
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
|
|
14
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15,827
|
)
|
|
|
(5,552
|
)
|
|
|
(21,379
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
13,995
|
|
|
|
140
|
|
|
|
149,619
|
|
|
|
(30,377
|
)
|
|
|
49,549
|
|
|
|
168,931
|
|
Issuance of common stock
|
|
|
5,116
|
|
|
|
51
|
|
|
|
55,124
|
|
|
|
|
|
|
|
|
|
|
|
55,175
|
|
Stock compensation expense
|
|
|
|
|
|
|
|
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
66
|
|
Minority contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41,606
|
|
|
|
41,606
|
|
Net loss (Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,715
|
)
|
|
|
(1,730
|
)
|
|
|
(10,445
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009 (Restated)
|
|
|
19,111
|
|
|
|
191
|
|
|
|
204,809
|
|
|
|
(39,092
|
)
|
|
|
89,425
|
|
|
|
255,333
|
|
Issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock compensation expense
|
|
|
|
|
|
|
|
|
|
|
79
|
|
|
|
|
|
|
|
|
|
|
|
79
|
|
Minority contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33,100
|
|
|
|
33,100
|
|
Net income (Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,818
|
|
|
|
3,351
|
|
|
|
8,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010 (Restated)
|
|
|
19,111
|
|
|
$
|
191
|
|
|
$
|
204,888
|
|
|
$
|
(34,274
|
)
|
|
$
|
125,876
|
|
|
$
|
296,681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-6
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and
Subsidiaries)
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
|
|
|
Operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
8,169
|
|
|
$
|
(10,445
|
)
|
|
$
|
(21,379
|
)
|
Adjustments to reconcile net loss to net cash provided by
|
|
|
|
|
|
|
|
|
|
|
|
|
(used in) operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash stock compensation expense
|
|
|
79
|
|
|
|
66
|
|
|
|
163
|
|
Depreciation, depletion, and amortization
|
|
|
18,892
|
|
|
|
12,480
|
|
|
|
5,451
|
|
Accretion of asset retirement obligations
|
|
|
3,933
|
|
|
|
2,439
|
|
|
|
544
|
|
Gain on sale of property, plant, and equipment
|
|
|
(68
|
)
|
|
|
(7
|
)
|
|
|
(141
|
)
|
Interest on long-term obligations
|
|
|
12,593
|
|
|
|
2,675
|
|
|
|
14,150
|
|
Change in working capital accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in accounts receivable
|
|
|
4,961
|
|
|
|
(11,357
|
)
|
|
|
(7,265
|
)
|
Increase in inventories
|
|
|
(7,237
|
)
|
|
|
(3,028
|
)
|
|
|
(2,581
|
)
|
Decrease (increase) in prepaid assets and other
|
|
|
(218
|
)
|
|
|
(242
|
)
|
|
|
90
|
|
Increase in other non-current assets
|
|
|
(3,883
|
)
|
|
|
(858
|
)
|
|
|
(5,911
|
)
|
Decrease in accounts payable and accrued liabilities
|
|
|
1,328
|
|
|
|
11,384
|
|
|
|
6,130
|
|
Decrease in other non-current liabilities
|
|
|
(1,355
|
)
|
|
|
(53
|
)
|
|
|
(330
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
37,194
|
|
|
|
3,054
|
|
|
|
(11,079
|
)
|
Investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in property, plant, equipment, and mine development
|
|
|
(41,755
|
)
|
|
|
(62,476
|
)
|
|
|
(80,288
|
)
|
Proceeds from sale of fixed assets
|
|
|
|
|
|
|
|
|
|
|
352
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
(84
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(41,755
|
)
|
|
|
(62,476
|
)
|
|
|
(80,020
|
)
|
Financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment on capital lease obligation
|
|
|
(3,692
|
)
|
|
|
(2,824
|
)
|
|
|
(1,159
|
)
|
Payment of debt
|
|
|
(33,343
|
)
|
|
|
(29,103
|
)
|
|
|
(24,864
|
)
|
Member contributions
|
|
|
|
|
|
|
55,175
|
|
|
|
50,925
|
|
Minority contributions
|
|
|
33,100
|
|
|
|
41,606
|
|
|
|
54,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(3,935
|
)
|
|
|
64,854
|
|
|
|
79,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
|
(8,496
|
)
|
|
|
5,432
|
|
|
|
(11,697
|
)
|
Cash and cash equivalents, at beginning of year
|
|
|
16,597
|
|
|
|
11,165
|
|
|
|
22,862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, at end of year
|
|
$
|
8,101
|
|
|
$
|
16,597
|
|
|
$
|
11,165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Supplemental cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
30,440
|
|
|
$
|
12,877
|
|
|
$
|
5,003
|
|
Non-cash transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in property, plant, and equipment; mine development;
and intangibles acquired with debt
|
|
|
2,638
|
|
|
|
|
|
|
|
54,000
|
|
Assets acquired by capital lease
|
|
|
1,951
|
|
|
|
5,689
|
|
|
|
14,050
|
|
Member contributions financed
|
|
|
|
|
|
|
125
|
|
|
|
375
|
|
Intangibles acquired in exchange of property, plant, and
equipment
|
|
|
|
|
|
|
|
|
|
|
3,354
|
|
Interest on long-term obligations
|
|
|
12,593
|
|
|
|
2,675
|
|
|
|
14,150
|
|
See accompanying notes to consolidated financial statements.
F-7
|
|
1.
|
DESCRIPTION
OF BUSINESS AND ENTITY STRUCTURE
|
Armstrong Energy, Inc. (formerly Armstrong Land Company, LLC)
(AE) and subsidiaries (collectively, the Company) commenced
business on September 19, 2006 (inception), for the purpose
of owning and operating coal reserves (also referred to as
mineral rights) and production assets. The Company is
headquartered in St. Louis, Missouri, with operational
facilities in western Kentucky. As of December 31, 2010,
the Company had approximately 675 employees, none of whom
are under a collective bargain arrangement.
All of the Companys subsidiaries are majority-owned by the
Company with the exception of Armstrong Resource Partners, L.P.
(formerly Elk Creek, LP) (ARP) and its subsidiaries, which were
not majority-owned by the Company as of December 31, 2010,
but whose results have been consolidated in accordance with
Financial Accounting Standards Board (FASB) Accounting Standards
Codification (ASC)
810-20,
Consolidation Control of Partnerships and Similar
Entities. ARP was set up on March 31, 2008, for the purpose
of owning and subleasing coal production assets. The Company as
Elk Creek General Partner (ECGP) has an approximate 0.4%
ownership in ARP. The various limited partners of ARP are
related parties, as the entities are owned by certain private
equity funds that also own AE. General creditors of ARP and
subsidiaries have no recourse to the assets of the Company and
its majority-owned subsidiaries.
The Company acquired mineral rights and other assets from
inception. Significant purchase transactions are outlined as
follows:
|
|
|
|
|
On September 19, 2006, the Company purchased land and
mineral rights in western Kentucky from an unrelated third party
for $7,000 in cash and a promissory note with a principal amount
of $29,000, which has been discounted using an effective
interest rate of 10% due to the seller in various amounts from
2009 to 2011.
|
|
|
|
On December 6, 2006, the Company purchased land and mineral
rights, an office and building, easements (for roads and
transmission lines), and spare parts in western Kentucky from an
unrelated third party for $12,500 in cash and a $45,400
promissory note, which has been discounted using an effective
interest rate of 10% due to the seller in various amounts from
2009 to 2012.
|
|
|
|
On March 7, 2007, the Company purchased land, mineral
rights, and various easements in western Kentucky from an
unrelated third party for $14,300 in cash and a $50,900
promissory note, which has been discounted using an effective
interest rate of 10% due to the seller in various amounts from
2010 to 2013.
|
|
|
|
On May 31, 2007, the Company purchased land, mineral
rights, a building, various easements, and spare parts in
western Kentucky from an unrelated third party for $12,500 in
cash and a $58,107 promissory note, which has been discounted
using an effective interest rate of 10% due to the seller in
various amounts from 2010 to 2014.
|
|
|
|
On March 31, 2008, ARP purchased land and mineral rights in
western Kentucky from an unrelated third party for $21,500 cash
and a promissory note with a principal balance of $54,000,
partially paid in December 2008 and the balance paid in June
2009. An effective interest rate of 12% has been applied to any
unpaid portion of the note from January 1, 2009, until the
date of the final payment.
|
|
|
|
On October 29, 2010, the Company entered into a lease that
gives it the right to mine the coal reserves in a western
Kentucky property. The Company is in process of having a third
party perform a study to determine the estimated proven and
probable reserves in the lease. Though not determined proven and
probable as of the date of this report, the Company estimates
that there are at least 400 million tons (unaudited) of
recoverable reserves. Prior to the commencement of mining, the
lease requires annual
|
F-8
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
advance royalties in the form of 16,000 tons, which are
recoupable against future production royalties. Once production
commences, the lessor has the ability to take either a cash
royalty of 6% of the selling price or a stated amount of 60,000
tons. Advanced royalties are recoupable against such payments.
The Company is obligated to meet certain minimum mining
requirements or pay additional advance royalties prior to the
commencement of mining.
|
|
|
2.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Factors
Affecting Comparability
Certain prior year amounts have been reclassified to conform to
current year presentation.
Principles
of Consolidation
The consolidated financial statements include the accounts of AE
and its wholly and majority-owned subsidiaries. As of
December 31, 2010, 2009 and 2008, the results of ARP and
its subsidiaries have been consolidated in accordance with
ASC 810-20.
The Company records non-controlling interest for
non-wholly-owned subsidiaries. All significant intercompany
balances and transactions were eliminated.
Accounting
Pronouncements Adopted
In June 2009, the FASB issued accounting guidance in
ASC 810 that modifies how a company determines when an
entity that is insufficiently capitalized or is not controlled
through voting (or similar rights) should be consolidated. The
guidance clarifies that the determination of whether a company
is required to consolidate an entity is based on, among other
things, an entitys purpose and design and a companys
ability to direct the activities of the entity that most
significantly affect the entitys economic performance. The
guidance also requires an ongoing reassessment of whether a
company is the primary beneficiary of a variable interest entity
and additional disclosures about a companys involvement in
variable interest entities and any associated changes in risk
exposure. The guidance is applicable for annual periods
beginning after November 15, 2009 (January 1, 2010,
for the Company). The Company performed a qualitative assessment
of its existing interests and determined that the new guidance
had no impact on the Companys financial statement
presentation.
In January 2010, ASC guidance for fair value measurements and
disclosure was updated to require additional disclosures related
to transfers in and out of Level 1 and Level 2 fair
value measurements. The guidance was amended to clarify the
level of disaggregation required for assets and liabilities and
the disclosures required for inputs and valuation techniques
used to measure the fair value of assets and liabilities that
fall in either Level 2 or Level 3. The updated
guidance was effective for the Companys fiscal year
beginning January 1, 2010. The adoption had no impact on
the Companys consolidated financial position, results of
operations, or cash flows.
Use
of Estimates
The preparation of consolidated financial statements in
conformity with United States generally accepted accounting
principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the consolidated financial statements and the reported amounts
of income and loss during the reporting periods. Actual results
could differ from those estimates.
F-9
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Revenue
Coal sales are recognized as revenue when title and risk of loss
passes to the customer. Coal sales are made to customers under
the terms of supply agreements, most of which are long-term
(greater than one year). Under the terms of the Companys
coal supply agreements, title and risk of loss typically
transfer to the customer at the mine where coal is loaded on the
truck, rail, or barge. Coal sales include the freight charged to
the customer on destination contracts.
Other
Income
Other income includes farm income, timber income, and other
income from the lease of property.
Cash
and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates
fair value. The Company considers all cash and temporary
investments having an original maturity of less than three
months to be cash equivalents.
Financial
Instruments
Cash and cash equivalents, accounts receivable, accounts
payable, and debt are stated at their approximate fair value on
the consolidated balance sheets due to the short maturity and
financial nature of the balances.
Accounts
and Other Receivables
Accounts receivable are recorded at the invoiced amount and do
not bear interest. The Company evaluates the need for an
allowance for doubtful accounts based on anticipated recovery
and industry data. As of December 31, 2010, 2009 and 2008,
the Company had not established an allowance for accounts
receivable.
Inventories
Inventories consist of coal as well as materials and supplies
that are valued at the lower of cost or market. Raw coal
stockpiles may be sold in their current condition or processed
further prior to shipment. Cost is determined using the
first-in,
first-out method for materials and supplies. Coal inventory
costs include labor, supplies, equipment cost, royalties, taxes,
other related costs, and, where applicable, preparation plant
cost. Stripping costs incurred during the production phase of
the mine are considered variable production costs and are
included in the cost of coal during the period the stripping
costs are incurred.
Prepaid
Expenses and Other Assets
Prepaid expenses primarily consist of prepaid insurance and
workers compensation premiums.
Property,
Plant, Equipment, and Mine Development
Property, plant, and equipment are recorded at cost. Interest
costs applicable to major asset additions are capitalized during
the construction period. Capitalized interest in 2010, 2009 and
2008 was $2,830, $3,954 and $3,521, respectively.
Expenditures that extend the useful lives of existing plant and
equipment assets are capitalized, while normal repairs and
maintenance that do not extend the useful life or increase the
productivity of the asset are expensed as incurred. Plant and
equipment are depreciated using the straight-line method over
the useful lives of the assets, which are detailed below.
F-10
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
Asset Type
|
|
Life (Years)
|
|
|
Buildings and improvements
|
|
|
7-40
|
|
Mine equipment
|
|
|
2-10
|
|
Vehicles
|
|
|
3-10
|
|
Office equipment and software
|
|
|
3-7
|
|
Costs to acquire or construct significant new assets are
capitalized and amortized using the
units-of-production
method over the estimated recoverable reserves that are
associated with the property being benefited, when placed into
service, as a part of the new asset being constructed. These
costs include but are not limited to legal fees, permit and
license costs, materials cost, associated labor costs, mine
design, construction of access roads, shafts, slopes and main
entries, and removing overburden to access reserves in a new
pit. Where multiple assets are acquired for one purchase price,
the cost of the purchase is allocated among the individual
assets in proportion to their market value with assistance from
a third party specializing in the valuation of the purchased
assets.
Mineral rights are recorded at cost as property, plant,
equipment, and mine development. Amortization of mineral rights
and mine development is provided by the
units-of-production
method over estimated total recoverable proven and probable
reserves.
Costs related to locating coal deposits and evaluating the
economic viability of such deposits are expensed as incurred.
The Company did not incur these costs in 2010, 2009 or 2008.
Start-up
costs are expensed as incurred. Certain costs incurred to
develop coal mines or to expand the capacity of an existing mine
are capitalized and amortized using the
units-of-production
method.
Other
Non-Current Assets
Other non-current assets include advance royalties and amounts
held by third parties to guarantee performance on the delivery
of coal, reclamation bonds, and other performance guarantees.
The amounts pledged are restricted for the term of the bonds and
cannot be withdrawn without the consent of the bonding companies.
Rights to leased coal and the related surface land can be
acquired through royalty payments. Where royalty payments
represent prepayments recoupable against future production, they
are recorded as a prepaid asset, and amounts expected to be
recouped within one year are classified as a current asset. As
mining occurs on these leases, the prepayment is charged to cost
of coal sales. See Note 12 for further details of royalty
agreements.
Long-Lived
Assets
If facts and circumstances suggest that a long-lived asset may
be impaired, the carrying value is reviewed for recoverability.
If this review indicates that the carrying value of the asset
will not be recovered, as determined based on projected
undiscounted cash flows related to the asset over its remaining
life, the carrying value of the asset is reduced to its
estimated fair value through an impairment loss. No impairments
have been recognized during the years ended December 31,
2010, 2009 or 2008.
Asset
Retirement Obligations (ARO) and Reclamation
The Companys ARO activities consist of estimated spending
related to reclaiming surface land and support facilities at
both surface and underground mines in accordance with federal
and state reclamation laws as defined by each mining permit.
Obligations are incurred when development of a mine commences
for
F-11
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
underground mines and surface facilities or, in the case of
support facilities, refuse areas and slurry ponds when
construction begins.
The obligations fair value is determined using discounted
cash flow techniques and is accreted to its present value at the
end of each period. The Company estimates ARO liabilities for
final reclamation and mine closure based upon detailed
engineering calculations of the amount and timing of future cash
spending for a third party to perform the required work.
Spending estimates are escalated for inflation and then
discounted at the credit-adjusted, risk-free rate. The Company
records an ARO asset associated with the discounted liability
for final reclamation and mine closure. The obligation and
corresponding asset are recognized in the period in which the
liability is incurred. The ARO asset for equipment, structures,
and buildings is amortized on the straight-line method over
their expected lives. Once production commences, the ARO asset
for mine development is amortized using the
units-of-production
method over the estimated recoverable reserves that are
associated with the property being benefited. The ARO liability
is accreted to the projected spending date. As changes in
estimates occur (such as mine plan revisions, changes in
estimated costs, or changes in timing of performance of
reclamation activities), the revisions to the obligation and
asset are recognized at the appropriate credit-adjusted,
risk-fee rate.
Fair
Value
For assets and liabilities that are recognized or disclosed at
fair value in the consolidated financial statements, the Company
defines fair value as the price that would be received to sell
an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date.
Income
Taxes
The Company is subject to taxation. Deferred income taxes are
recorded by applying statutory tax rates in effect at the date
of the balance sheet to differences between the income tax bases
of assets and liabilities and their carrying amounts for
financial reporting purposes. Deferred tax assets are reduced by
a valuation allowance if, based on the weight of available
evidence, it is more likely than not that some portion or all of
the deferred tax assets will not be realized. In determining
whether a valuation allowance is appropriate, projected
realization of tax benefits is considered based on expected
levels of future taxable income, available tax planning
strategies, and the overall deferred tax position. If actual
results differ from the assumptions made in the evaluation of
the amount of the valuation allowance, the Company records a
change in the valuation allowance through income tax expense in
the period such determination is made. Certain subsidiaries are
disregarded for income tax purposes and are included in each
respective parent entitys tax returns.
The calculations of the Companys tax liabilities involve
dealing with uncertainties in the application of complex tax
regulations. On January 1, 2008, the Company adopted
ASC 740-10-25,
Income Taxes General Recognition,
guidance related to uncertain tax positions. As a result of
implementing this guidance, the Company recognized liabilities
for uncertain tax positions based on the two-step process
prescribed in the guidance. The first step is to evaluate the
tax position for recognition by determining whether it is more
likely than not that a tax position will be sustained upon
examination, including resolution of any related appeals or
litigation processes, based on the technical merits of the
position. The second step requires the Company to estimate and
measure the tax benefit as the largest amount that is more than
50% likely to be realized upon settlement. The Company
re-evaluates these uncertain tax positions annually. This
evaluation is based on factors including, but not limited to,
changes in facts or circumstances, changes in tax law,
effectively settled issues under audit, or new audit activity.
Such a change in recognition or measurement results in the
recognition of a tax benefit or an additional charge to the tax
provision.
F-12
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Equity
Awards
The Company accounts for common stock (and previously,
members equity units) paid with a note and issued to
employees as compensation expense. Amounts are recorded at fair
market value. The Company used the Black-Scholes option model in
estimating the fair value of awards. Compensation expense is
measured on grant date and recognized over the term of the notes
payable to the Company.
|
|
3.
|
RESTATEMENT
OF PRIOR PERIOD FINANCIAL STATEMENTS
|
The Company has restated its previously issued financial
statements for the years ended December 31, 2010 and 2009 to
correct the accounting for depreciation, depletion, and
amortization expense. An error was identified in the calculation
of depreciation, depletion, and amortization expense resulting
in a net understatement of the results of operations. The
restatement has no effect on the Companys net cash flows
or liquidity. These adjustments also impact the calculation of
income attributable to non-controlling interests and the
determination of deferred tax balances in each of the periods
affected.
Impact
of the Financial Statement Adjustments on the Consolidated
Statements of Operations
The table below presents the impact of the financial statement
adjustments related to the restatement of the Companys
previously issued Consolidated Statements of Operations for the
years ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
Depreciation, depletion, and amortization
|
|
$
|
14,728
|
|
|
$
|
(2,248
|
)
|
|
$
|
12,480
|
|
|
$
|
21,122
|
|
|
$
|
(2,230
|
)
|
|
$
|
18,892
|
|
Asset retirement obligation expense
|
|
|
1,505
|
|
|
|
479
|
|
|
|
1,984
|
|
|
|
2,352
|
|
|
|
735
|
|
|
|
3,087
|
|
Operating income (loss)
|
|
|
(551
|
)
|
|
|
1,769
|
|
|
|
1,218
|
|
|
|
17,657
|
|
|
|
1,495
|
|
|
|
19,152
|
|
Income (loss) before income taxes
|
|
|
(12,214
|
)
|
|
|
1,769
|
|
|
|
(10,445
|
)
|
|
|
6,674
|
|
|
|
1,495
|
|
|
|
8,169
|
|
Net Income (loss)
|
|
|
(12,214
|
)
|
|
|
1,769
|
|
|
|
(10,445
|
)
|
|
|
6,674
|
|
|
|
1,495
|
|
|
|
8,169
|
|
(Income) loss attributable to non-controlling interest
|
|
|
1,739
|
|
|
|
(9
|
)
|
|
|
1,730
|
|
|
|
(3,344
|
)
|
|
|
(7
|
)
|
|
|
(3,351
|
)
|
Net income (loss) attributable to common stockholders
|
|
|
(10,475
|
)
|
|
|
1,760
|
|
|
|
(8,715
|
)
|
|
|
3,330
|
|
|
|
1,488
|
|
|
|
4,818
|
|
Net income (loss) per share attributable to common stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
(0.61
|
)
|
|
$
|
0.11
|
|
|
$
|
(0.50
|
)
|
|
$
|
0.17
|
|
|
$
|
0.08
|
|
|
$
|
0.25
|
|
F-13
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Impact
of the Financial Statement Adjustments on the Consolidated
Balance Sheets
The table below presents the impact of the financial statement
adjustments related to the restatement of the Companys
previously issued Consolidated Balance Sheets for the years
ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009
|
|
|
As of December 31, 2010
|
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
Property, plant, equipment, and mine development, net
|
|
$
|
393,707
|
|
|
$
|
1,769
|
|
|
$
|
395,476
|
|
|
$
|
422,455
|
|
|
$
|
3,264
|
|
|
$
|
425,719
|
|
Total Assets
|
|
|
448,849
|
|
|
|
1,769
|
|
|
|
450,618
|
|
|
|
474,774
|
|
|
|
3,264
|
|
|
|
478,038
|
|
Accumulated deficit
|
|
|
(40,852
|
)
|
|
|
1,760
|
|
|
|
(39,092
|
)
|
|
|
(37,522
|
)
|
|
|
3,248
|
|
|
|
(34,274
|
)
|
Armstrong Energy, Inc.s equity
|
|
|
164,148
|
|
|
|
1,760
|
|
|
|
165,908
|
|
|
|
167,557
|
|
|
|
3,248
|
|
|
|
170,805
|
|
Non-controlling interest
|
|
|
89,416
|
|
|
|
9
|
|
|
|
89,425
|
|
|
|
125,860
|
|
|
|
16
|
|
|
|
125,876
|
|
Total stockholders equity
|
|
|
253,564
|
|
|
|
1,769
|
|
|
|
255,333
|
|
|
|
293,417
|
|
|
|
3,264
|
|
|
|
296,681
|
|
Total liabilities and stockholders equity
|
|
|
448,849
|
|
|
|
1,769
|
|
|
|
450,618
|
|
|
|
474,774
|
|
|
|
3,264
|
|
|
|
478,038
|
|
Impact
of the Financial Statement Adjustments on the Consolidated
Statements of Cash Flows
The restatement of the Consolidated Statements of Cash Flows for
the years ended December 31, 2010 and 2009 did not affect
the Companys cash flows from financing or investing
activities. The table below reflects adjustments to the
Companys cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
(12,214
|
)
|
|
$
|
1,769
|
|
|
$
|
(10,445
|
)
|
|
$
|
6,674
|
|
|
$
|
1,495
|
|
|
$
|
8,169
|
|
Depreciation, depletion, and amortization
|
|
|
14,728
|
|
|
|
(2,248
|
)
|
|
|
12,480
|
|
|
|
21,122
|
|
|
|
(2,230
|
)
|
|
|
18,892
|
|
Asset retirement obligation expense
|
|
|
1,960
|
|
|
|
479
|
|
|
|
2,439
|
|
|
|
3,198
|
|
|
|
734
|
|
|
|
3,932
|
|
Net cash provided by operating activities
|
|
|
3,054
|
|
|
|
|
|
|
|
3,054
|
|
|
|
37,194
|
|
|
|
|
|
|
|
37,194
|
|
Inventories consist of the following amounts:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Materials and supplies
|
|
$
|
7,359
|
|
|
$
|
4,527
|
|
Coal raw and saleable
|
|
|
5,652
|
|
|
|
1,247
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
13,011
|
|
|
$
|
5,774
|
|
|
|
|
|
|
|
|
|
|
|
|
5.
|
PROPERTY,
PLANT, EQUIPMENT, AND MINE DEVELOPMENT
|
Mineral rights are estimated to contain 217,415 tons (unaudited)
and 101,869 tons (unaudited) of proven and probable reserves
with a net book value of $193,804 and $198,768 at
December 31, 2010 and 2009,
F-14
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
respectively. The allocation of the costs of the assets acquired
reflects fair value based on a valuation completed in 2008.
Included in the book value of mineral rights are leased coal
interests with net book value of $28,101 and $30,014 at
December 31, 2010 and 2009, respectively. The remaining net
book value of $165,703 and $168,754 at December 31, 2010 and
2009, respectively, relates to coal reserves owned in fee
ownership. During 2010, the Company acquired the lease to a
large reserve in western Kentucky. Though not determined proven
and probable as of the date of this report, the Company
estimates that there are at least 400,000 tons (unaudited) of
recoverable reserves in the area. A reserve study is in process,
so the Company has not included the tonnages in the figures
above. Once a reserve study is completed, these reserves will be
included in the Companys reserve estimates.
Property, plant, equipment, and mine development consist of the
following as of December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
Land
|
|
$
|
30,536
|
|
|
$
|
27,112
|
|
Mineral rights
|
|
|
203,051
|
|
|
|
203,051
|
|
Machinery and equipment
|
|
|
105,309
|
|
|
|
66,865
|
|
Buildings and facilities
|
|
|
73,279
|
|
|
|
55,639
|
|
Other items
|
|
|
1,450
|
|
|
|
1,416
|
|
Mine development costs
|
|
|
21,647
|
|
|
|
7,397
|
|
ARO assets
|
|
|
13,093
|
|
|
|
7,762
|
|
Construction-in-progress
|
|
|
18,376
|
|
|
|
45,374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
466,741
|
|
|
|
414,616
|
|
Less accumulated depreciation and depletion
|
|
|
(41,022
|
)
|
|
|
(19,140
|
)
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
425,719
|
|
|
$
|
395,476
|
|
|
|
|
|
|
|
|
|
|
Other items include furniture, fixtures, computer hardware, and
software. Depreciation expense, including amounts from
capitalized leases, for the years ended December 31, 2010,
2009 and 2008, was $11,375, $8,466 and $3,467, respectively. For
the years ended December 31, 2010, 2009 and 2008, depletion
expense related to mineral rights amounted to $4,443, $2,877 and
$1,406, respectively; amortization expense related to mine
development costs amounted to $1,707, $842 and $274,
respectively; and depreciation expense related to the ARO assets
amounted to $2,241, $1,449 and $224, respectively.
The Company has pledged substantially all buildings and
equipment as security for capital lease obligations.
The Company had outstanding construction commitments as of
December 31, 2010, of approximately $26,930. All
construction commitments are expected to be completed within the
next fiscal year.
Intangible assets consist of mine plans and permits acquired in
the property acquisitions outlined in Note 1, as well as a
non-compete agreement entered into in conjunction with the
purchase of minority unitholders interest and settlement
of litigation. Mine plans and permits are being amortized over
five years beginning in the year that mining operations commence
on the associated area. The non-compete agreement is being
amortized, using the straight-line method, over the five-year
term of the agreement. Amortization expense related to
intangible assets amounted to $705, $748 and $304 for the years
ended December 31, 2010, 2009 and 2008, respectively.
Amortization expense is estimated to be approximately $732 per
year for the next
F-15
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
two years, $431 in year three, and $9 in years four and five.
Intangible assets consist of the following as of
December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
Mine plans and other intangibles acquired
|
|
$
|
440
|
|
|
$
|
440
|
|
Non-compete agreement
|
|
|
3,354
|
|
|
|
3,354
|
|
Amortization of intangible assets
|
|
|
(1,757
|
)
|
|
|
(1,052
|
)
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,037
|
|
|
$
|
2,742
|
|
|
|
|
|
|
|
|
|
|
|
|
7.
|
OTHER
NON-CURRENT ASSETS
|
Other non-current assets consist of the following as of
December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
Escrows and deposits
|
|
$
|
4,233
|
|
|
$
|
3,322
|
|
Restricted surety and cash bonds
|
|
|
7,770
|
|
|
|
5,607
|
|
Advanced royalties
|
|
|
1,883
|
|
|
|
1,073
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
13,886
|
|
|
$
|
10,002
|
|
|
|
|
|
|
|
|
|
|
|
|
8.
|
RISKS AND
CONCENTRATIONS
|
Geographical
Concentration
The Companys operations are concentrated in western
Kentucky, and a disruption within that geographic region could
adversely affect the Companys performance.
Customer
Concentration
The Company has multi-year coal supply agreements with six
customers. The top two customers accounted for 40% and 36%,
respectively, of net sales at December 31, 2010. The
Company seeks to mitigate credit risk by monitoring
creditworthiness of these customers and adjusting credit amounts
provided accordingly. Significant interruption to these customer
facilities covered under force majeure provisions of their
contracts could adversely affect the Companys results.
|
|
9.
|
RELATED-PARTY
TRANSACTIONS
|
The Company rented office space, equipment, furniture, supplies,
and the use of the related partys employees from a key
employee of the Company. Expenses of $56, $46 and $40 were paid
during the years ended December 31, 2010, 2009 and 2008,
respectively.
In 2006 and 2007, the Company entered into overriding royalty
agreements with two key executive employees to compensate them
$0.05/ton of coal mined and sold from properties owned by
certain subsidiaries of the Company. The agreements remains in
effect for the later of 20 years from the date of the
agreement or until all salable coal has been extracted. Both
royalties transfer with the property regardless of ownership or
lease status. The royalties are payable the month following the
sale of coal mined from the specified properties. The Company
accounts for these royalty arrangements as expense in the period
in which the coal is sold. Expense recorded in the years ended
December 31, 2010, 2009 and 2008, was $569, $467 and $146,
respectively.
F-16
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On November 30, 2009, and again on March 31, 2010,
May 31, 2010, and November 30, 2010, AE entered into
promissory notes with ARP whereby ARP loaned funds to AE for the
sole purpose of making the scheduled payments under the debt
agreements described in Note 10. The amounts were $11,000
on November 30, 2009; $9,500 on March 31, 2010;
$12,600 on May 31, 2010; and $11,000 on November 30,
2010. The promissory notes have a fixed interest rate of 3%. In
addition, contingent interest equal to 7% of revenue would be
accrued to the extent it exceeds the fixed interest amount. The
amount recorded on ARP (which is eliminated in consolidation of
the Company) was $4,209 and $161 at December 31, 2010 and
2009, respectively. No payments of principal or interest are due
until the earliest of May 31, 2014, or the 91st day
after the debt agreements described in Note 10 have been
paid in full. No voluntary prepayments of these notes are
allowed. Further, ARP, in lieu of payment of the outstanding
amounts of principal and interest, has the option to purchase an
interest in the mineral reserves of the Company equal to the
percentage of the aggregate amount of principal loaned and
related accrued interest to the amount paid by the Company to
repay or repurchase and retire the promissory notes discussed in
Note 10. This option can only be exercised if all
promissory notes are repaid in full. If ARP exercises the option
to purchase the mineral reserves, ARP will lease to the Company,
under mutually agreeable terms and conditions, the interest in
the mineral reserves that ARP acquired. See Debt
Repayment discussion in Note 20.
As further explained in Note 20 under Debt
Repayment, the Company repaid the secured promissory note
obligations through the proceeds associated with a new credit
agreement entered into February 9, 2011. Accordingly, the
balances of the secured promissory notes were classified as
non-current as of December 31, 2010, since subsequently
refinanced on a long-term basis. Debt discounted using an
effective interest rate of 10% consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2010
|
|
|
2009
|
|
Type
|
|
Current
|
|
|
Non-Current
|
|
|
Current
|
|
|
Non-Current
|
|
|
Secured promissory notes, due 2011 through 2014
|
|
$
|
|
|
|
$
|
121,363
|
|
|
$
|
28,502
|
|
|
$
|
112,483
|
|
Secured notes relating to land purchases, due 2011 through 2013
|
|
|
1,686
|
|
|
|
947
|
|
|
|
239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,686
|
|
|
$
|
122,310
|
|
|
$
|
28,741
|
|
|
$
|
112,483
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As detailed in Note 1, the Company has promissory notes
outstanding from various acquisitions during 2008 and 2007. The
terms of the notes indicate that, in the event of default, the
Company has 30 days after written notice by the owner to
cure the default. If the default has not been remedied, then all
notes are considered in default, and the owner may exercise any
and all rights available in the respective notes, which rights
include acceleration of payment, foreclosure, and the right to
take possession. Substantially all of the Companys mineral
reserves secure these notes. The Company has recorded the notes
at their net present value using an effective interest rate of
10%. The fair value of debt is $146,697 at December 31,
2010.
F-17
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
If the promissory notes had not been repaid in February 2011,
there would be required principal payments including imputed
interest using an effective interest rate of 10% after
December 31, 2010, as follows:
|
|
|
|
|
2011
|
|
$
|
55,164
|
|
2012
|
|
|
44,412
|
|
2013
|
|
|
35,833
|
|
2014 and thereafter
|
|
|
6,531
|
|
|
|
|
|
|
Total payments
|
|
|
141,940
|
|
Less amounts representing unamortized discount
|
|
|
17,944
|
|
|
|
|
|
|
Net debt
|
|
|
123,996
|
|
Less short-term debt
|
|
|
1,686
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
122,310
|
|
|
|
|
|
|
Subsequent to the balance sheet date, the Company refinanced its
long-term debt as discussed in Note 20, and therefore the
above payout scheduled has been amended. Commensurate with this
refinancing, the Company has required principal payments of $0
in 2011 and $20 million in 2012, 2013, 2014, and 2015, with
the remaining balance to be paid in full in February 2016.
The Company leases equipment and facilities directly under
various non-cancelable lease agreements. Certain lease
agreements require the maintenance of specified ratios and
contain restrictive covenants for the return of collateral or
security deposits. Other leases contain renewal or purchase
terms in the contract. Rental expense under operating leases was
$10,683, $8,012 and $3,966 for the years ended December 31,
2010, 2009 and 2008, respectively.
Future minimum lease payments under non-cancelable operating
leases (with initial or remaining lease terms in excess of one
year) and future minimum capital lease payments as of
December 31, 2010, are:
|
|
|
|
|
|
|
|
|
|
|
Capital
|
|
|
Operating
|
|
|
|
Leases
|
|
|
Leases
|
|
|
Year ending December 31:
|
|
|
|
|
|
|
|
|
2011
|
|
$
|
4,730
|
|
|
$
|
15,328
|
|
2012
|
|
|
4,606
|
|
|
|
15,299
|
|
2013
|
|
|
4,233
|
|
|
|
14,189
|
|
2014
|
|
|
2,796
|
|
|
|
10,898
|
|
2015 and thereafter
|
|
|
1,870
|
|
|
|
6,051
|
|
|
|
|
|
|
|
|
|
|
Total minimum lease payments
|
|
|
18,235
|
|
|
$
|
61,765
|
|
|
|
|
|
|
|
|
|
|
Less amount representing interest
|
|
|
2,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present value of net minimum capital lease payments
|
|
|
15,875
|
|
|
|
|
|
Less current installments of obligations under capital leases
|
|
|
3,802
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligations under capital leases, excluding current installments
|
|
$
|
12,073
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-18
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The net amount of leased assets capitalized on the balance sheet
is:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Asset cost
|
|
$
|
23,741
|
|
|
$
|
21,790
|
|
Accumulated depreciation
|
|
|
(7,059
|
)
|
|
|
(3,944
|
)
|
|
|
|
|
|
|
|
|
|
Net
|
|
$
|
16,682
|
|
|
$
|
17,846
|
|
|
|
|
|
|
|
|
|
|
Royalty expense during the years ended December 31, 2010,
2009 and 2008, was $5,372, $3,819 and $146, respectively. At
December 31, 2010 and 2009, the Company recorded $831 and
$307, respectively, of advance royalty payments. These payments
are recoupable against royalties generated from future mining
activity. Included in the 2010 total of payments is an advance
royalty related to a new leased reserve. The lease requires the
Company to provide the owner with a certain amount of tonnage
each year until production commences on the leased reserve. The
Company valued this tonnage using market pricing as of
December 31, 2010, at $500 in 2010 and accordingly recorded
the value as an advance, as the value of the tonnage provided is
recoupable against royalties generated by future mining
activity. The value and term of future advanced royalties are
dependent on the market value of the coal and the date that
operations commence on the property. For disclosure purposes,
the Company has included an anticipated annual minimum advance
royalty based on estimated market prices for similar coal
through 2016, at which time the lessor can terminate the
agreement if mining has not commenced.
Anticipated future minimum advance royalties as of
December 31, 2010, are payable as follows:
|
|
|
|
|
2011
|
|
$
|
782
|
|
2012
|
|
|
870
|
|
2013
|
|
|
905
|
|
2014
|
|
|
925
|
|
2015 and thereafter
|
|
|
1,243
|
|
|
|
|
|
|
Total
|
|
$
|
4,725
|
|
|
|
|
|
|
In addition to the above advanced royalties, production
royalties are payable based on the quantity of coal mined in
future years.
Various royalties and commissions have been negotiated with
management, a former minority unitholder, and sales brokers. See
Note 9 for the terms of royalties to employees.
F-19
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
13.
|
ASSET
RETIREMENT OBLIGATIONS AND RECLAMATION
|
Asset retirement obligation and reclamation balances consist of
the following as of December 31, 2010 and 2009:
Reconciliation
of asset retirement obligations
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
Balance at beginning of year
|
|
$
|
8,524
|
|
|
$
|
4,613
|
|
Accretion expense
|
|
|
852
|
|
|
|
455
|
|
Liabilities incurred (net)
|
|
|
5,331
|
|
|
|
3,456
|
|
|
|
|
|
|
|
|
|
|
Balance at end of year
|
|
|
14,707
|
|
|
|
8,524
|
|
Less current obligation
|
|
|
1,458
|
|
|
|
1,200
|
|
|
|
|
|
|
|
|
|
|
Total obligation less current portion
|
|
$
|
13,249
|
|
|
$
|
7,324
|
|
|
|
|
|
|
|
|
|
|
The credit-adjusted, risk-free rate used to discount the
estimated liability was 10% in both 2010 and 2009.
The income or loss before income taxes and non-controlling
interest was income of $8,169 and a loss of $10,445 for the
years ended December 31, 2010 and 2009, respectively.
The income tax rate differed from the U.S. federal
statutory rate as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
Tax expense (benefit) at federal statutory rates
|
|
$
|
2,859
|
|
|
$
|
(3,656
|
)
|
State income taxes
|
|
|
577
|
|
|
|
(407
|
)
|
Nontaxable entities, net of non-controlling interest
|
|
|
798
|
|
|
|
1,771
|
|
Other permanent items
|
|
|
102
|
|
|
|
157
|
|
Other
|
|
|
2,074
|
|
|
|
|
|
Change in valuation allowance
|
|
|
(6,410
|
)
|
|
|
2,135
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
F-20
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and liabilities
consist of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Tax loss carryforwards
|
|
$
|
38,847
|
|
|
$
|
32,058
|
|
Deferred organization costs and other intangibles
|
|
|
412
|
|
|
|
100
|
|
Vacation accrual
|
|
|
311
|
|
|
|
478
|
|
Deferred compensation costs
|
|
|
|
|
|
|
161
|
|
Charitable contributions
|
|
|
124
|
|
|
|
50
|
|
Asset retirement obligation
|
|
|
2,150
|
|
|
|
884
|
|
|
|
|
|
|
|
|
|
|
Total gross deferred tax assets
|
|
|
41,844
|
|
|
|
33,731
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Property, plant, and equipment
|
|
|
(35,318
|
)
|
|
|
(20,794
|
)
|
|
|
|
|
|
|
|
|
|
Total gross deferred tax liabilities
|
|
|
(35,318
|
)
|
|
|
(20,794
|
)
|
Valuation allowance
|
|
|
(6,526
|
)
|
|
|
(12,937
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Changes to the valuation allowance during the years ended
December 31, 2010 and 2009, were as follows:
|
|
|
|
|
(Restated)
|
|
|
|
Valuation allowance at December 31, 2008
|
|
$
|
10,802
|
|
Increase in valuation allowance
|
|
|
2,135
|
|
|
|
|
|
|
Valuation allowance at December 31, 2009
|
|
|
12,937
|
|
Decrease in valuation allowance
|
|
|
(6,411
|
)
|
|
|
|
|
|
Valuation allowance at December 31, 2010
|
|
$
|
6,526
|
|
|
|
|
|
|
The Companys net deferred tax assets are offset by a
valuation allowance of $6,526 and $12,937 at December 31,
2010 and 2009, respectively. The Company evaluated and assessed
the expected near-term utilization of net operating loss
carryforwards, book and taxable income trends, available tax
strategies, and the overall deferred tax position and believes
that it is more likely than not that the benefit related to the
deferred tax assets will not be realized and has thus
established the valuation allowance required as of
December 31, 2010 and 2009.
The Companys net deferred tax assets included federal and
state net operating loss (NOL) carryforwards of $102,821 and
$73,281, respectively, as of December 31, 2010. The NOLs
begin to expire in 2026.
The Companys federal income tax returns for the tax years
from 2006 forward remain subject to examination by the Internal
Revenue Service. The Companys state income tax returns for
the same period remain subject to examination by the various
state taxing authorities.
During 2010, 2009 and 2008, the Company made no federal income
tax payments and made only insignificant state and local income
tax payments for the years ended December 31, 2010, 2009
and 2008.
F-21
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
There were no uncertain tax positions as of December 31,
2010 or 2009, and combined with the existence of NOL
carryforwards, the Company has not currently accrued interest or
penalties. If the accrual of interest or penalties becomes
appropriate, the Company will record an accrual as part of its
income tax provision.
|
|
15.
|
EMPLOYEE
BENEFIT PLANS
|
Beginning September 2007, the Company offered a 401(k) savings
plan for all employees. The costs included in the consolidated
statements of operations totaled $1,434, $1,090 and $515 for the
years ended December 31, 2010, 2009 and 2008, respectively.
The Chief Executive Officer, the President, and a board member
have purchased common stock in the Company, which have been paid
with cash and non-recourse promissory notes. Certain minority
stockholders also have purchased common stock in the
majority-owned, consolidated subsidiaries that have been paid
with cash and non-recourse promissory notes. All notes carry a
stated interest rate of 6% simple interest per annum. All notes
are due eight years from their date of issuance. All promissory
notes are collateralized by both paid and unpaid ownership
interest, as well as dividends, proceeds, or other benefits
obtained by the holder of the common stock. No portions of the
notes are subject to release until full payment has been
tendered on the applicable note. In the event of default, the
notes shall bear interest at 12% per annum. As of
December 31, 2010, there are no defaults under the terms of
the notes.
The common stock purchased with non-recourse notes are accounted
for as equity awards. The Company recorded $0, $66 and $163 of
expense related to the awards during the years ended
December 31, 2010, 2009 and 2008. As the awards were fully
vested at the date of issuance, the associated compensation
expense was recognized at the date of issuance and was recorded
under selling, general, and administrative costs in the
consolidated statements of operations. No awards were granted in
2010. The weighted-average grant-date fair value of the awards
issued during the year ended December 31, 2009, was $5.67
per share. As of December 31, 2010 and 2009, there was no
unrecognized compensation cost.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Average
|
|
|
Grant Date Fair
|
|
|
Average
|
|
|
|
Common Shares
|
|
|
Exercise Price
|
|
|
Value
|
|
|
Remaining Life
|
|
|
Outstanding at January 1, 2010
|
|
|
277,500
|
|
|
$
|
16.00
|
|
|
$
|
1,400
|
|
|
|
5.15
|
|
Granted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2010
|
|
|
277,500
|
|
|
$
|
16.00
|
|
|
$
|
1,400
|
|
|
|
4.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable
|
|
|
277,500
|
|
|
$
|
|
|
|
$
|
|
|
|
|
4.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average assumptions used in determining fair value,
using a Black-Scholes option pricing model, are as follows:
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
Risk-free interest rate
|
|
|
N/A
|
|
|
|
2.0
|
%
|
Expected unit price volatility
|
|
|
N/A
|
|
|
|
0.55
|
%
|
Expected term (years)
|
|
|
N/A
|
|
|
|
8
|
|
Expected dividends
|
|
|
|
|
|
|
|
|
F-22
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company concluded that there was a remote probability of
early repayment of the non-recourse promissory notes; therefore,
the expected term is the term of the notes. The amounts due on
the notes held by award holders are offset to the respective
entitys equity account. Notes receivable, including
accrued interest, offset against members equity as of
December 31, 2010 and 2009, were $3,724 and $3,568,
respectively.
The Company may issue restricted shares which require no payment
from the employee. Restricted shares cliff-vest at various
dates. Compensation expense is based on the fair value on the
grant date and is recorded ratably over the vesting period.
Information regarding restricted shares activity and
weighted-average grant-date fair value follows for the year
ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
Restricted Shares
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
Average Grant-
|
|
|
|
Shares
|
|
|
Date Fair Value
|
|
|
|
(In thousands)
|
|
|
|
|
|
Outstanding at January 1
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
35.2
|
|
|
|
6.23
|
|
Vested
|
|
|
|
|
|
|
|
|
Canceled
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31
|
|
|
35.2
|
|
|
$
|
6.23
|
|
|
|
|
|
|
|
|
|
|
Unearned compensation of $140 will be recognized over the
remaining vesting period of the outstanding restricted shares.
The Company recognized expense of approximately $79 related to
restricted shares for the year ended December 31, 2010.
The computation of basic and diluted earnings per common share
is as follows (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
|
|
|
Net income (loss) applicable to common stockholders
basic and diluted
|
|
$
|
4,818
|
|
|
$
|
(8,715
|
)
|
|
$
|
(15,827
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average number of common shares outstanding
|
|
|
19,111
|
|
|
|
17,265
|
|
|
|
11,713
|
|
Effect of dilutive securities
|
|
|
22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average number of common shares outstanding
|
|
|
19,133
|
|
|
|
17,265
|
|
|
|
11,713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share basic and diluted
|
|
$
|
0.25
|
|
|
$
|
(0.50
|
)
|
|
$
|
(1.35
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009 and 2008, there were no unvested
restricted stock awards outstanding.
No distributions have been made to any of the members of AE or
any of its subsidiaries, including distributions to minority
unitholders.
F-23
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
19.
|
COMMITMENTS
AND CONTINGENCIES
|
The Company is subject to various market, operational,
financial, regulatory, and legislative risks. Numerous federal,
state, and local governmental permits and approvals are required
for mining operations. Federal and state regulations require
regular monitoring of mines and other facilities to document
compliance. Monetary penalties of $602, $535 and $62 related to
Mine Safety and Health Administration (MSHA) fines were accrued
in the results of operations for 2010, 2009 and 2008.
Periodically, there may be various claims and legal proceedings
against the Company arising from the normal course of business.
The Company is also involved in litigation matters arising in
the ordinary course of business. In the opinion of management,
the resolution of these matters will not have a material adverse
effect on the Companys consolidated financial statements.
The Company, via contractual agreements, has committed volumes
of sales in 2011 and 2012 of 7.6 million tons and
8.3 million tons, respectively.
Equipment
Commitments
During 2010, the Company entered into lease agreements for
approximately $5,550 of equipment that will be delivered in 2011.
Coal
Transportation Agreements
In December 2007, the Company entered into a lease services
agreement with a third party commencing January 2008 and
expiring December 2015. The third party will provide all barge
switching, coal loading, tug, hauling, and similar services
necessary for the Companys operations. During the term of
the agreement, the Company will pay a monthly amount based on
the annual volume of tons of coal loaded at the dock facility.
The Company commenced activity under the lease in January 2009
and incurred $835 and $501 of expense during the years ended
December 31, 2010 and 2009, respectively.
The Company has evaluated subsequent events through the date of
this report, May 9, 2011.
Debt
Repayment
On February 9, 2011, the Company repaid its secured
promissory note obligations through the proceeds associated with
a new credit agreement. The new credit agreement consists of a
$100 million term loan and a $50 million revolving
credit facility. The term loan has a term of five years, with
principal repayment amounts of $5 million on the first day
of each quarter commencing on January 1, 2012 through
January 1, 2016, with the remaining principal balance
payable at maturity. Interest payments are also payable
quarterly in arrears on the first day of each quarter. The
interest rate fluctuates based on the Companys leverage
ratio and the applicable interest option elected. The interest
rate as of June 30, 2011 was 5.75%. The revolving credit
facility provides for quarterly interest payments in arrears
that fluctuate on the same method as the term loan. The
revolving credit facility also calls for a commitment fee based
on the unused portion of the facility. As of June 30, 2011,
the Company has $28.5 million outstanding under this
revolving credit facility. The obligations under the credit
agreement are secured by a first lien on substantially all of
the Companys assets, including but not limited to certain
of the Companys mines, coal reserves, and related
fixtures. The credit agreement contains certain customary
covenants as well as certain limitations on, among other things,
additional debt, liens, investments, acquisitions and capital
expenditures, future dividends, and asset sales. The Company
incurred approximately $3.2 million in fees related to the
new credit agreement. These fees will be amortized over the term
of the agreements. The Company has also entered into an interest
rate swap agreement with an
F-24
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
effective date of January 1, 2012, which will terminate in
February 2016. The initial amount of the arrangement is
$47.5 million with a fixed rate of 2.89%. The amount will
decline as principal payments are made on the term note. As a
result of the repayment of the existing debt obligations, the
Company will recognize a gain of approximately $6.9 million
in 2011.
As a result of the repayment of the secured promissory notes,
the related party promissory notes to ARP were converted at
ARPs option to a 39.45% undivided interest in the original
non-ARP reserves held by the Company. The Company will now pay
to a subsidiary of ARP a royalty based on its interest in the
reserves at a rate of 7% of revenue. In addition, ARP is a
guarantor of the new Armstrong Coal Company credit agreement,
and its assets are pledged as collateral. ARP will receive, as
compensation for these restrictions, a fee of 1% of the
weighted-average outstanding balance under the credit agreements.
Ownership
Items
On January 17, 2011, additional capital of $5,000 was
contributed by the limited partners in ARP as part of the
repayment of its secured promissory note obligations and
entering into the new credit facility.
Equipment
Purchase Agreements
Agreements to purchase or lease various pieces of surface and
underground equipment totaled approximately $17,200 and were
signed in 2011.
Reorganization
In August 2011, Armstrong Resources Holdings, LLC merged with
and into Armstrong Energy, Inc., which subsequently changed its
name to Armstrong Energy Holdings, Inc. Subsequently, Armstrong
Land Company, LLC (ALC) adopted a Plan of Conversion
(the Plan), which resulted in ALC being converted to
a C-corporation named Armstrong Land Company, Inc.
(ALCI) effective October 1, 2011. In addition,
the Plan authorized the conversion of each issued and
outstanding membership units of ALC into 9.25 shares of
common stock of ALCI. Concurrent with the effectiveness of the
Plan, ALCI changed its name to Armstrong Energy, Inc.
(collectively, the Reorganization). As a result of
the Reorganization, the Company will have 70,000,000 authorized
shares of common stock with a par value of $0.01 per share,
19,095,763 shares of common stock which are issued and
outstanding and 1,000,000 authorized shares of preferred stock
with a par value of $0.01 per share, of which none are issued
and outstanding as of October 1, 2011.
In accordance with SEC Staff Accounting Bulletin Topic 4.C,
Changes in Capital Structure, all common share information
presented has been retroactively adjusted to reflect the common
stock conversion.
Deconsolidation
of Armstrong Resource Partners
On October 1, 2011, the partners of ARP entered into the
Amended and Restated Agreement of Limited Partnership of
Armstrong Resource Partners, L.P. (the ARP LPA).
Pursuant to the ARP LPA, effective October 1, 2011,
investment funds managed by Yorktown Partners LLC, unilaterally
may remove the Companys subsidiary, Elk Creek GP, as
general partner of ARP or otherwise cause a change of control of
ARP without the Companys consent or the consent of the
holders of ARPs equity units. As a result, the Company
will no longer consolidate the results of operations of ARP in
accordance with
ASC 810-20
effective October 1, 2011 and will begin to account for its
ownership in ARP under the equity method of
F-25
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
accounting. The following is summarized financial information of
ARP as of December 31, 2010 (in thousands):
|
|
|
|
|
Total assets
|
|
$
|
137,929
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
12,000
|
|
Partners capital
|
|
|
125,929
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
137,929
|
|
|
|
|
|
|
Executive
Stock Repurchase
In 2006 thru 2008, the Companys Board of Directors
approved the issuance of promissory notes payable to the Company
to certain executive officers to finance the purchase of
membership units of the Companys predecessor. Promissory
notes payable to the Company, including accrued and unpaid
interest, were $2,687 and $2,623 as of June 30, 2011 and
December 31, 2010, respectively, but are not recorded
within the consolidated balance sheet as these notes are
non-recourse. In September 2011, all promissory notes
outstanding as of June 30, 2011 were repaid in full through
the sale of membership units back to the Companys
predecessor by the borrowers.
F-26
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
7,547
|
|
|
$
|
8,101
|
|
Accounts receivable
|
|
|
23,289
|
|
|
|
13,927
|
|
Inventories
|
|
|
10,887
|
|
|
|
13,011
|
|
Prepaid and other assets
|
|
|
3,476
|
|
|
|
1,357
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
45,199
|
|
|
|
36,396
|
|
Property, plant, equipment, and mine development, net
|
|
|
451,008
|
|
|
|
425,719
|
|
Investment in affiliate
|
|
|
2,470
|
|
|
|
|
|
Intangible assets, net
|
|
|
1,488
|
|
|
|
2,037
|
|
Other non-current assets
|
|
|
16,134
|
|
|
|
13,886
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
516,299
|
|
|
$
|
478,038
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
24,628
|
|
|
$
|
18,681
|
|
Accrued liabilities and other
|
|
|
14,831
|
|
|
|
8,697
|
|
Construction retainage
|
|
|
375
|
|
|
|
625
|
|
Current portion of capital lease obligations
|
|
|
4,331
|
|
|
|
3,802
|
|
Current maturities of long-term debt
|
|
|
15,976
|
|
|
|
1,686
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
60,141
|
|
|
|
33,491
|
|
Long-term debt, less current maturities
|
|
|
121,100
|
|
|
|
122,310
|
|
Asset retirement obligations
|
|
|
14,352
|
|
|
|
13,249
|
|
Long-term portion of capital lease obligations
|
|
|
10,800
|
|
|
|
12,073
|
|
Other non-current liabilities
|
|
|
1,976
|
|
|
|
234
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
208,369
|
|
|
|
181,357
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value, 70,000,000 shares
authorized, 19,095,763 and 19,110,500 shares issued and
outstanding as of September 30, 2011 and December 31,
2010, respectively
|
|
|
191
|
|
|
|
191
|
|
Preferred stock, $0.01 par value, 1,000,000 shares
authorized, no shares issued and outstanding as of
September 30, 2011 and December 31, 2010, respectively
|
|
|
|
|
|
|
|
|
Additional
paid-in-capital
|
|
|
206,790
|
|
|
|
204,888
|
|
Accumulated deficit
|
|
|
(35,257
|
)
|
|
|
(34,274
|
)
|
Accumulated other comprehensive income (loss)
|
|
|
(1,778
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Armstrong Energy, Inc.s equity
|
|
|
169,946
|
|
|
|
170,805
|
|
Non-controlling interest
|
|
|
137,984
|
|
|
|
125,876
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
307,930
|
|
|
|
296,681
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
516,299
|
|
|
$
|
478,038
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated
financial statements.
F-27
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
Revenue
|
|
$
|
229,980
|
|
|
$
|
176,311
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
170,297
|
|
|
|
120,204
|
|
Depreciation, depletion, and amortization
|
|
|
21,478
|
|
|
|
14,017
|
|
Asset retirement obligation expenses
|
|
|
2,942
|
|
|
|
2,545
|
|
Selling, general and administrative costs
|
|
|
28,834
|
|
|
|
21,403
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
6,429
|
|
|
|
18,142
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
118
|
|
|
|
143
|
|
Interest expense
|
|
|
(6,073
|
)
|
|
|
(8,532
|
)
|
Other income / (expense), net
|
|
|
(154
|
)
|
|
|
116
|
|
Gain on early extinguishment of debt
|
|
|
6,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
7,274
|
|
|
|
9,869
|
|
Income tax provision
|
|
|
809
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
6,465
|
|
|
|
9,869
|
|
Income attributable to non-controlling interests
|
|
|
(7,448
|
)
|
|
|
(2,814
|
)
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to common stockholders
|
|
$
|
(983
|
)
|
|
$
|
7,055
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per share attributable to common stockholders
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
(0.05
|
)
|
|
$
|
0.37
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated
financial statements.
F-28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
Other
|
|
|
Non-
|
|
|
Total
|
|
|
|
Common
|
|
|
|
|
|
Additional
|
|
|
Accumulated
|
|
|
Comprehensive
|
|
|
Controlling
|
|
|
Stockholders
|
|
|
|
Stock
|
|
|
Amount
|
|
|
Paid-in-Capital
|
|
|
Deficit
|
|
|
Loss
|
|
|
Interest
|
|
|
Equity
|
|
|
|
|
|
|
|
|
|
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Restated)
|
|
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
Balance at December 31, 2010
|
|
|
19,111
|
|
|
$
|
191
|
|
|
$
|
204,888
|
|
|
$
|
(34,274
|
)
|
|
$
|
|
|
|
$
|
125,876
|
|
|
$
|
296,681
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(983
|
)
|
|
|
|
|
|
|
7,448
|
|
|
|
6,465
|
|
Decrease in fair value of cash flow hedge
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,778
|
)
|
|
|
|
|
|
|
(1,778
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,687
|
|
Stock based compensation
|
|
|
|
|
|
|
|
|
|
|
279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
279
|
|
Acquisition of non-controlling interest
|
|
|
74
|
|
|
|
1
|
|
|
|
472
|
|
|
|
|
|
|
|
|
|
|
|
(340
|
)
|
|
|
133
|
|
Issuance of common stock to non-employees
|
|
|
41
|
|
|
|
0
|
|
|
|
217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
217
|
|
Repurchase of common stock
|
|
|
(149
|
)
|
|
|
(1
|
)
|
|
|
934
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
933
|
|
Shares issued under employee plan
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,000
|
|
|
|
5,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2011
|
|
|
19,096
|
|
|
$
|
191
|
|
|
$
|
206,790
|
|
|
$
|
(35,257
|
)
|
|
$
|
(1,778
|
)
|
|
$
|
137,984
|
|
|
$
|
307,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated
financial statements.
F-29
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
6,465
|
|
|
$
|
9,869
|
|
Adjustments to reconcile net income to cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Gain on early extinguishment of debt
|
|
|
(6,954
|
)
|
|
|
|
|
Gain on disposal of assets
|
|
|
(36
|
)
|
|
|
|
|
Non-cash stock compensation expense
|
|
|
1,212
|
|
|
|
54
|
|
Non-cash charge related on non-recourse notes
|
|
|
218
|
|
|
|
|
|
Amortization of debt issuance costs
|
|
|
440
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
21,478
|
|
|
|
13,961
|
|
Asset retirement obligation expenses
|
|
|
2,942
|
|
|
|
2,545
|
|
Interest on long-term obligations
|
|
|
2,428
|
|
|
|
10,933
|
|
Change in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(9,362
|
)
|
|
|
1,206
|
|
Inventories
|
|
|
2,124
|
|
|
|
(2,517
|
)
|
Prepaid and other assets
|
|
|
(2,119
|
)
|
|
|
134
|
|
Other non-current assets
|
|
|
1,711
|
|
|
|
(3,339
|
)
|
Accounts payable and accrued liabilities
|
|
|
10,615
|
|
|
|
(6,087
|
)
|
Other non-current liabilities
|
|
|
(36
|
)
|
|
|
45
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities:
|
|
|
31,126
|
|
|
|
26,804
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
Investment in property, plant, equipment, and mine development
|
|
|
(45,035
|
)
|
|
|
(24,681
|
)
|
Investment in affiliate
|
|
|
(2,470
|
)
|
|
|
|
|
Proceeds from the sale of fixed assets
|
|
|
119
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(47,386
|
)
|
|
|
(24,681
|
)
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
Payment on capital lease obligations
|
|
|
(3,040
|
)
|
|
|
(2,774
|
)
|
Payment of secured promissory notes
|
|
|
(115,679
|
)
|
|
|
(25,100
|
)
|
Payment of secured notes
|
|
|
(908
|
)
|
|
|
(243
|
)
|
Payment of financing costs and fees
|
|
|
(4,399
|
)
|
|
|
|
|
Proceeds from senior secured term loan
|
|
|
100,000
|
|
|
|
|
|
Proceeds from senior secured revolving credit facility
|
|
|
34,600
|
|
|
|
|
|
Proceeds from the acquisition of non-controlling interest
|
|
|
132
|
|
|
|
|
|
Minority contributions
|
|
|
5,000
|
|
|
|
22,100
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
15,706
|
|
|
|
(6,017
|
)
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
(554
|
)
|
|
|
(3,894
|
)
|
Cash, at the beginning of the period
|
|
|
8,101
|
|
|
|
16,597
|
|
|
|
|
|
|
|
|
|
|
Cash, at the end of the period
|
|
$
|
7,547
|
|
|
$
|
12,703
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
Supplemental cash flow information:
|
|
2011
|
|
|
2010
|
|
Non-Cash Transactions:
|
|
|
|
|
|
|
|
|
Assets acquired by capital lease
|
|
$
|
2,296
|
|
|
$
|
994
|
|
|
|
|
|
|
|
|
|
|
Investment in property, plant, equipment, and mine development
acquired with debt
|
|
$
|
750
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated
financial statements.
F-30
|
|
1.
|
DESCRIPTION
OF BUSINESS AND ENTITY STRUCTURE
|
In August 2011, Armstrong Resources Holdings, LLC merged with
and into Armstrong Energy, Inc., which subsequently changed its
name to Armstrong Energy Holdings, Inc. Subsequently, Armstrong
Land Company, LLC (ALC) adopted a Plan of Conversion
(the Plan), which resulted in ALC being converted to
a C-corporation named Armstrong Land Company, Inc.
(ALCI) effective October 1, 2011. Concurrent
with the effectiveness of the Plan, ALCI changed its name to
Armstrong Energy, Inc. (collectively, the
Reorganization).
The accompanying unaudited condensed consolidated financial
statements include the accounts of Armstrong Energy, Inc. and
its subsidiaries and controlled entities (collectively the
Company or AE). The Companys
primary business is the production of thermal coal from surface
and underground mines located in western Kentucky, for sale to
utility, industrial and export markets. Intercompany
transactions and accounts have been eliminated in consolidation.
The accompanying unaudited condensed consolidated financial
statements have been prepared in accordance with
U.S. generally accepted accounting principles for interim
financial reporting and U.S. Securities and Exchange
Commission regulations. In the opinion of management, all
adjustments, consisting of normal, recurring accruals considered
necessary for a fair presentation, have been included. Results
of operations for the nine months ended September 30, 2011
are not necessarily indicative of results to be expected for the
year ending December 31, 2011. These financial statements
should be read in conjunction with the audited financial
statements and related notes as of and for the year ended
December 31, 2010.
All of the Companys subsidiaries are majority-owned by the
Company with the exception of Armstrong Resource Partners, L.P.
(formerly Elk Creek, LP) (ARP) and its subsidiaries,
which were not majority-owned by the Company as of
September 30, 2011, but whose results have been
consolidated in accordance with Financial Accounting Standards
Board (FASB) Accounting Standards Codification (ASC)
810-20,
Consolidation Control of Partnerships and Similar
Entities. ARP was established on March 31, 2008, for the
purpose of owning and subleasing coal production assets. The
Company as Elk Creek General Partner (ECGP) has an approximate
0.4% ownership in ARP. The various limited partners of ARP are
related parties, as the entities are owned by certain private
investment funds that also own AE. General creditors of ARP and
subsidiaries have no recourse to the assets of the Company and
its majority-owned subsidiaries. As a result of an amendment to
the partnership agreement, ARP will be deconsolidated from the
operating results of the Company effective October 1, 2011
(see Note 16).
The Company has evaluated subsequent events and transactions for
potential recognition or disclosure in the financial statements
through the day the financial statements are available to be
issued.
|
|
2.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Derivatives
Derivative instruments are accounted for in accordance with the
applicable FASB guidance on accounting for derivative
instruments and hedging activity. This guidance provides
comprehensive and consistent standards for the recognition and
measurement of derivative and hedging activities. It also
requires that derivatives be recorded on the consolidated
balance sheet at fair value and establishes criteria for hedges
of changes in fair values of assets, liabilities, or firm
commitments; hedges of variable cash flows of forecasted
transactions; and hedges of foreign currency exposures of net
investments in foreign operations. The Company currently uses
derivatives only to hedge the variable cash flows of future
interest payments on long-term debt. To the extent a derivative
qualifies as a cash flow hedge, the gain or loss associated with
the effective portion
F-31
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands)
(unaudited)
is recorded as a component of Accumulated Other Comprehensive
Income (Loss). Changes in the fair value of derivatives that do
not meet the criteria for hedge accounting would be recognized
in the consolidated statements of operations. When an interest
rate swap agreement terminates, any resulting gain or loss is
recognized over the shorter of the remaining original term of
the hedging instrument or the remaining life of the underlying
debt obligation. The Company does not anticipate any
nonperformance by the counterparty.
Newly
Adopted Accounting Standard
In January 2010, the FASB issued accounting guidance that
requires new fair value disclosures, including disclosures about
significant transfers into and out of Level 1 and
Level 2 fair-value measurements and a description of the
reasons for the transfers. In addition, the guidance requires
new disclosures regarding activity in Level 3 fair value
measurements, including a gross basis reconciliation. The new
disclosure requirements became effective for interim and annual
periods beginning January 1, 2010, except for the
disclosure of activity within Level 3 fair value
measurements, which became effective January 1, 2011. The
new guidance did not have an impact on the Companys
consolidated financial statements.
Accounting
Standards Not Yet Implemented
In June 2011, the FASB amended requirements for the presentation
of other comprehensive income (loss), requiring presentation of
comprehensive income (loss) in either a single, continuous
statement of comprehensive income or on separate but consecutive
statements, the statement of operations and the statement of
other comprehensive income (loss). The amendment is effective
for fiscal years, and interim periods within those years,
beginning after December 15, 2011, or March 31, 2012
for the Company. The adoption of this guidance will not impact
the Companys financial position, results of operations or
cash flows and will only impact the presentation of other
comprehensive income (loss) on the financial statements.
In May 2011, the FASB amended the guidance regarding fair value
measurement and disclosure. The amended guidance clarifies the
application of existing fair value measurement and disclosure
requirements. The amendment is effective for interim and annual
periods beginning after December 15, 2011, or
March 31, 2012 for the Company. Early adoption is not
permitted. The adoption of this amendment is not expected to
materially affect the Companys consolidated financial
statements.
|
|
3.
|
RESTATEMENT
OF PRIOR PERIOD FINANCIAL STATEMENTS
|
The Company has restated its previously issued financial
statements for the years ended December 31, 2010 and 2009, and
the interim periods of fiscal years 2011 and 2010, to correct
the accounting for depreciation, depletion, and amortization
expense. An error was identified in the calculation of
depreciation, depletion, and amortization expense resulting in a
net understatement of the results of operations. The restatement
has no effect on the Companys net cash flows or liquidity.
These adjustments also impact the calculation of income
attributable to non-controlling interests and the determination
of deferred tax balances in each of the periods affected.
In addition, during the third quarter of 2011, the Company has
restated its previously issued unaudited consolidated financial
statements as of and for the six months ended June 30, 2011
to correct its calculation of income attributable to
non-controlling interests.
The Company identified adjustments in the determination of
income attributable to non-controlling interests related to the
treatment of certain related-party expenses arising from the
financing arrangement entered into on February 9, 2011 with
ARP. The effect of the correction resulted in the increase in
the net loss
F-32
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands)
(unaudited)
attributable to common stockholders, net loss per share
attributable to common stockholders and income attributable to
non-controlling interests.
Impact
of the Financial Statement Adjustments on the Consolidated
Statements of Operations
The table below presents the impact of the financial statement
adjustments related to the restatement of the Companys
previously issued Consolidated Statements of Operations for the
years ended December 31, 2010 and 2009 and interim periods
of fiscal years 2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
Depreciation, depletion, and amortization
|
|
$
|
14,728
|
|
|
$
|
(2,248
|
)
|
|
$
|
12,480
|
|
|
$
|
21,122
|
|
|
$
|
(2,230
|
)
|
|
$
|
18,892
|
|
Asset retirement obligation expense
|
|
|
1,505
|
|
|
|
479
|
|
|
|
1,984
|
|
|
|
2,352
|
|
|
|
735
|
|
|
|
3,087
|
|
Operating income (loss)
|
|
|
(551
|
)
|
|
|
1,769
|
|
|
|
1,218
|
|
|
|
17,657
|
|
|
|
1,495
|
|
|
|
19,152
|
|
Income (loss) before income taxes
|
|
|
(12,214
|
)
|
|
|
1,769
|
|
|
|
(10,445
|
)
|
|
|
6,674
|
|
|
|
1,495
|
|
|
|
8,169
|
|
Net Income (loss)
|
|
|
(12,214
|
)
|
|
|
1,769
|
|
|
|
(10,445
|
)
|
|
|
6,674
|
|
|
|
1,495
|
|
|
|
8,169
|
|
(Income) loss attributable to non-controlling interest
|
|
|
1,739
|
|
|
|
(9
|
)
|
|
|
1,730
|
|
|
|
(3,344
|
)
|
|
|
(7
|
)
|
|
|
(3,351
|
)
|
Net income (loss) attributable to common stockholders
|
|
|
(10,475
|
)
|
|
|
1,760
|
|
|
|
(8,715
|
)
|
|
|
3,330
|
|
|
|
1,488
|
|
|
|
4,818
|
|
Net income (loss) per share attributable to common stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
(0.61
|
)
|
|
$
|
0.11
|
|
|
$
|
(0.50
|
)
|
|
$
|
0.17
|
|
|
$
|
0.08
|
|
|
$
|
0.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2010
|
|
|
Nine Months Ended September 30, 2011
|
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
Depreciation, depletion, and amortization
|
|
$
|
15,817
|
|
|
$
|
(1,800
|
)
|
|
$
|
14,017
|
|
|
$
|
22,101
|
|
|
$
|
(623
|
)
|
|
$
|
21,478
|
|
Asset retirement obligation expense
|
|
|
1,938
|
|
|
|
607
|
|
|
|
2,545
|
|
|
|
2,859
|
|
|
|
83
|
|
|
|
2,942
|
|
Operating income
|
|
|
16,949
|
|
|
|
1,193
|
|
|
|
18,142
|
|
|
|
5,889
|
|
|
|
540
|
|
|
|
6,429
|
|
Income before income taxes
|
|
|
8,676
|
|
|
|
1,193
|
|
|
|
9,869
|
|
|
|
6,734
|
|
|
|
540
|
|
|
|
7,274
|
|
Income tax provision
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
726
|
|
|
|
83
|
|
|
|
809
|
|
Net Income
|
|
|
8,676
|
|
|
|
1,193
|
|
|
|
9,869
|
|
|
|
6,008
|
|
|
|
457
|
|
|
|
6,465
|
|
Income attributable to non-controlling interest
|
|
|
(2,808
|
)
|
|
|
(6
|
)
|
|
|
(2,814
|
)
|
|
|
(7,445
|
)
|
|
|
(3
|
)
|
|
|
(7,448
|
)
|
Net income attributable to common stockholders
|
|
|
5,868
|
|
|
|
1,187
|
|
|
|
7,055
|
|
|
|
(1,437
|
)
|
|
|
454
|
|
|
|
(983
|
)
|
Net income (loss) per share attributable to common stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
0.31
|
|
|
$
|
0.06
|
|
|
$
|
0.37
|
|
|
$
|
(0.07
|
)
|
|
$
|
0.02
|
|
|
$
|
(0.05
|
)
|
F-33
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2010
|
|
|
Six Months Ended June 30, 2011
|
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
Depreciation, depletion, and amortization
|
|
$
|
10,448
|
|
|
$
|
(1,197
|
)
|
|
$
|
9,251
|
|
|
$
|
14,621
|
|
|
$
|
(876
|
)
|
|
$
|
13,745
|
|
Asset retirement obligation expense
|
|
|
1,249
|
|
|
|
384
|
|
|
|
1,633
|
|
|
|
1,724
|
|
|
|
63
|
|
|
|
1,787
|
|
Operating income
|
|
|
13,061
|
|
|
|
813
|
|
|
|
13,874
|
|
|
|
(3,074
|
)
|
|
|
813
|
|
|
|
(2,261
|
)
|
Income before income taxes
|
|
|
7,594
|
|
|
|
813
|
|
|
|
8,407
|
|
|
|
71
|
|
|
|
813
|
|
|
|
884
|
|
Net Income
|
|
|
7,594
|
|
|
|
813
|
|
|
|
8,407
|
|
|
|
(766
|
)
|
|
|
813
|
|
|
|
47
|
|
Income attributable to non-controlling interest
|
|
|
(1,531
|
)
|
|
|
(4
|
)
|
|
|
(1,535
|
)
|
|
|
(1,703
|
)
|
|
|
(2,661
|
)
|
|
|
(4,364
|
)
|
Net income attributable to common stockholders
|
|
|
6,063
|
|
|
|
809
|
|
|
|
6,872
|
|
|
|
(2,469
|
)
|
|
|
(1,848
|
)
|
|
|
(4,317
|
)
|
Net income (loss) per share attributable to common stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
0.32
|
|
|
$
|
0.04
|
|
|
$
|
0.36
|
|
|
$
|
(0.13
|
)
|
|
$
|
(0.10
|
)
|
|
$
|
(0.23
|
)
|
Impact of
the Financial Statement Adjustments on the Consolidated Balance
Sheets
The table below presents the impact of the financial statement
adjustments related to the restatement of the Companys
previously issued Consolidated Balance Sheets for the years
ended December 31, 2010 and 2009 and interim periods of
fiscal years 2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009
|
|
|
As of December 31, 2010
|
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
Property, plant, equipment, and mine development, net
|
|
$
|
393,707
|
|
|
$
|
1,769
|
|
|
$
|
395,476
|
|
|
$
|
422,455
|
|
|
$
|
3,264
|
|
|
$
|
425,719
|
|
Total Assets
|
|
|
448,849
|
|
|
|
1,769
|
|
|
|
450,618
|
|
|
|
474,774
|
|
|
|
3,264
|
|
|
|
478,038
|
|
Accumulated deficit
|
|
|
(40,852
|
)
|
|
|
1,760
|
|
|
|
(39,092
|
)
|
|
|
(37,522
|
)
|
|
|
3,248
|
|
|
|
(34,274
|
)
|
Armstrong Energy, Inc.s equity
|
|
|
164,148
|
|
|
|
1,760
|
|
|
|
165,908
|
|
|
|
167,557
|
|
|
|
3,248
|
|
|
|
170,805
|
|
Non-controlling interest
|
|
|
89,416
|
|
|
|
9
|
|
|
|
89,425
|
|
|
|
125,860
|
|
|
|
16
|
|
|
|
125,876
|
|
Total stockholders equity
|
|
|
253,564
|
|
|
|
1,769
|
|
|
|
255,333
|
|
|
|
293,417
|
|
|
|
3,264
|
|
|
|
296,681
|
|
Total liabilities and stockholders equity
|
|
|
448,849
|
|
|
|
1,769
|
|
|
|
450,618
|
|
|
|
474,774
|
|
|
|
3,264
|
|
|
|
478,038
|
|
F-34
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2011
|
|
|
As of September 30, 2011
|
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
Property, plant, equipment, and mine development, net
|
|
$
|
436,057
|
|
|
$
|
4,076
|
|
|
$
|
440,133
|
|
|
$
|
447,204
|
|
|
$
|
3,804
|
|
|
$
|
451,008
|
|
Total assets
|
|
|
490,860
|
|
|
|
4,076
|
|
|
|
494,936
|
|
|
|
512,495
|
|
|
|
3,804
|
|
|
|
516,299
|
|
Accrued liabilities and other
|
|
|
13,307
|
|
|
|
|
|
|
|
13,307
|
|
|
|
14,748
|
|
|
|
83
|
|
|
|
14,831
|
|
Total current liabilities
|
|
|
47,641
|
|
|
|
|
|
|
|
47,641
|
|
|
|
60,058
|
|
|
|
83
|
|
|
|
60,141
|
|
Total liabilities
|
|
|
194,275
|
|
|
|
|
|
|
|
194,275
|
|
|
|
208,286
|
|
|
|
83
|
|
|
|
208,369
|
|
Accumulated deficit
|
|
|
(39,991
|
)
|
|
|
1,399
|
|
|
|
(38,592
|
)
|
|
|
(38,959
|
)
|
|
|
3,702
|
|
|
|
(35,257
|
)
|
Additional paid in capital
|
|
|
204,998
|
|
|
|
|
|
|
|
204,998
|
|
|
|
206,771
|
|
|
|
19
|
|
|
|
206,790
|
|
Armstrong Energy, Inc.s equity
|
|
|
164,022
|
|
|
|
1,399
|
|
|
|
165,421
|
|
|
|
166,225
|
|
|
|
3,721
|
|
|
|
169,946
|
|
Non-controlling interest
|
|
|
132,563
|
|
|
|
2,677
|
|
|
|
135,240
|
|
|
|
137,984
|
|
|
|
|
|
|
|
137,984
|
|
Total stockholders equity
|
|
|
296,585
|
|
|
|
4,076
|
|
|
|
300,661
|
|
|
|
304,209
|
|
|
|
3,721
|
|
|
|
307,930
|
|
Total liabilities and stockholders equity
|
|
|
490,860
|
|
|
|
4,076
|
|
|
|
494,936
|
|
|
|
512,495
|
|
|
|
3,804
|
|
|
|
516,299
|
|
Impact
of the Financial Statement Adjustments on the Consolidated
Statements of Cash Flows
The restatement of the Consolidated Statements of Cash Flows for
the years ended December 31, 2010 and 2009 and interim
periods of fiscal years 2011 and 2010 did not affect the
Companys cash flows from financing or investing
activities. The table below reflects adjustments to the
Companys cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
(12,214
|
)
|
|
$
|
1,769
|
|
|
$
|
(10,445
|
)
|
|
$
|
6,674
|
|
|
$
|
1,495
|
|
|
$
|
8,169
|
|
Depreciation, depletion, and amortization
|
|
|
14,728
|
|
|
|
(2,248
|
)
|
|
|
12,480
|
|
|
|
21,122
|
|
|
|
(2,230
|
)
|
|
|
18,892
|
|
Asset retirement obligation expense
|
|
|
1,960
|
|
|
|
479
|
|
|
|
2,439
|
|
|
|
3,198
|
|
|
|
734
|
|
|
|
3,932
|
|
Net cash provided by operating activities
|
|
|
3,054
|
|
|
|
|
|
|
|
3,054
|
|
|
|
37,194
|
|
|
|
|
|
|
|
37,194
|
|
F-35
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2010
|
|
|
Nine Months Ended September 30, 2011
|
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
8,676
|
|
|
$
|
1,193
|
|
|
$
|
9,869
|
|
|
$
|
6,008
|
|
|
$
|
457
|
|
|
$
|
6,465
|
|
Depreciation, depletion, and amortization
|
|
|
15,761
|
|
|
|
(1,800
|
)
|
|
|
13,961
|
|
|
|
22,101
|
|
|
|
(623
|
)
|
|
|
21,478
|
|
Asset retirement obligation expense
|
|
|
1,938
|
|
|
|
607
|
|
|
|
2,545
|
|
|
|
2,859
|
|
|
|
83
|
|
|
|
2,942
|
|
Increase/(decrease) in accounts payable and accrued liabilities
|
|
|
(6,087
|
)
|
|
|
|
|
|
|
(6,087
|
)
|
|
|
10,532
|
|
|
|
83
|
|
|
|
10,615
|
|
Net cash provided by operating activities
|
|
|
26,804
|
|
|
|
|
|
|
|
26,804
|
|
|
|
31,126
|
|
|
|
|
|
|
|
31,126
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2010
|
|
|
Six Months Ended June 30, 2011
|
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
As Reported
|
|
|
Adjustment
|
|
|
As Adjusted
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
7,594
|
|
|
$
|
813
|
|
|
$
|
8,407
|
|
|
$
|
(766
|
)
|
|
$
|
812
|
|
|
$
|
46
|
|
Depreciation, depletion, and amortization
|
|
|
10,448
|
|
|
|
(1,197
|
)
|
|
|
9,251
|
|
|
|
14,621
|
|
|
|
(875
|
)
|
|
|
13,746
|
|
Asset retirement obligation expense
|
|
|
1,249
|
|
|
|
384
|
|
|
|
1,633
|
|
|
|
1,724
|
|
|
|
63
|
|
|
|
1,787
|
|
Net cash provided by operating activities
|
|
|
17,571
|
|
|
|
|
|
|
|
17,571
|
|
|
|
15,706
|
|
|
|
|
|
|
|
15,706
|
|
Inventories consist of the following amounts:
|
|
|
|
|
|
|
|
|
|
|
September 30, 2011
|
|
|
2010 December 31,
|
|
|
Materials and supplies
|
|
$
|
9,183
|
|
|
$
|
7,359
|
|
Coal raw and saleable
|
|
|
1,704
|
|
|
|
5,652
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,887
|
|
|
$
|
13,011
|
|
|
|
|
|
|
|
|
|
|
F-36
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands)
(unaudited)
|
|
5.
|
ACCRUED
AND OTHER LIABILITIES
|
Accrued and other liabilities consist of the following amounts:
|
|
|
|
|
|
|
|
|
|
|
September 30, 2011
|
|
|
December 31, 2010
|
|
|
Payroll and related benefits
|
|
$
|
6,436
|
|
|
$
|
4,761
|
|
Taxes other than income taxes
|
|
|
3,581
|
|
|
|
1,240
|
|
Interest
|
|
|
1,174
|
|
|
|
23
|
|
Asset retirement obligations
|
|
|
1,458
|
|
|
|
1,458
|
|
Royalties
|
|
|
1,197
|
|
|
|
686
|
|
Other
|
|
|
985
|
|
|
|
529
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
14,831
|
|
|
$
|
8,697
|
|
|
|
|
|
|
|
|
|
|
|
|
6.
|
FAIR
VALUE OF FINANCIAL INSTRUMENTS
|
The Company measures the fair value of assets and liabilities
using a three-tier fair value hierarchy which prioritizes the
inputs used in measuring fair value as follows:
Level 1 observable inputs such as quoted
prices in active markets; Level 2 inputs,
other than quoted market prices in active markets, which are
observable, either directly or indirectly; and
Level 3 valuations derived from valuation
techniques in which one or more significant inputs are
unobservable. In addition, the Company may use various valuation
techniques including the market approach, using comparable
market prices; the income approach, using present value of
future income or cash flow; and the cost approach, using the
replacement cost of assets.
The Companys financial instruments consist of cash
equivalents, accounts receivable, long-term debt, and other
long-term obligations. For cash equivalents, accounts receivable
and other long-term obligations, the carrying amounts
approximate fair value. The estimated fair market values of the
Companys debt instruments and cash flow hedge are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2011
|
|
December 31, 2010
|
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
|
Value
|
|
Value
|
|
Value
|
|
Value
|
|
Senior Secured Term Loan
|
|
$
|
100,000
|
|
|
$
|
100,000
|
|
|
$
|
|
|
|
$
|
|
|
Senior Secured Revolving Credit Agreement
|
|
|
34,600
|
|
|
|
34,600
|
|
|
|
|
|
|
|
|
|
Cash flow hedge
|
|
|
1,778
|
|
|
|
1,778
|
|
|
|
|
|
|
|
|
|
Secured promissory notes
|
|
|
|
|
|
|
|
|
|
|
146,697
|
|
|
|
121,363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
136,378
|
|
|
$
|
136,378
|
|
|
$
|
146,697
|
|
|
$
|
121,363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As the Senior Secured Term Loan and the Senior Secured Revolving
Credit Agreement bear interest at a variable rate, the carrying
value of these debt instruments approximates their fair value.
The fair value of the secured promissory notes was estimated
based on the cash flows discounted to their present value.
|
|
7.
|
RELATED-PARTY
TRANSACTIONS
|
On November 30, 2009, and again on March 31, 2010,
May 31, 2010, and November 30, 2010, AE entered into
promissory notes with ARP (ARP promissory notes)
whereby ARP loaned funds to AE for the sole purpose of making
the scheduled payments under the secured debt agreements
outstanding with various third parties existing at
December 31, 2010 (secured promissory notes).
The amounts were $11,000 on
F-37
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands)
(unaudited)
November 30, 2009; $9,500 on March 31, 2010; $12,600
on May 31, 2010; and $11,000 on November 30, 2010. The
ARP promissory notes had a fixed interest rate of 3%. In
addition, contingent interest equal to 7% of revenue would be
accrued to the extent it exceeds the fixed interest amount. No
payments of principal or interest were due until the earliest of
May 31, 2014, or the 91st day after the secured
promissory notes had been paid in full. Further, ARP, in lieu of
payment of the outstanding amounts of principal and interest,
had the option to obtain an interest in the mineral reserves of
the Company equal to the percentage of the aggregate amount of
principal loaned and related accrued interest to the amount paid
by the Company to repay or repurchase and retire the ARP
promissory notes. This option could only be exercised if all
secured promissory notes are repaid in full.
As discussed in Note 8, the secured promissory notes were
repaid in full on February 9, 2011, which resulted in ARP
exercising its option to convert the ARP promissory notes to a
39.45% undivided interest in the original non-ARP land and
mineral reserves held by the Company. Outstanding principal and
interest of the ARP promissory notes totaled $46,620 as of
February 9, 2011. As additional consideration for the land
and mineral reserves transferred, ARP paid $5,000 cash and
certain amounts due ARP totaling $17,871 were forgiven,
resulting in aggregate consideration of $69,491. Simultaneous
with this transaction, the Company entered into a lease
agreement with a subsidiary of ARP, under mutually agreeable
terms and conditions, to mine the acquired mineral reserves. The
lease is for a term of 10 years and can be extended for
additional periods until all the respective merchantable and
mineable coal is removed. Due to the Companys continuing
involvement in the land and mineral reserves transferred, this
transaction has been accounted for as a financing arrangement. A
long-term obligation has been established that will be amortized
over a 20 year period, or the estimated life of the mineral
reserves, at an annual rate of 7% of the estimated gross revenue
generated from the sale of the coal originating from the leased
mineral reserves. Based on the Companys estimates, the
effective interest rate of the lease was 12.5% at the time of
the transaction, which will be adjusted prospectively based on
changes to the mine plan. As the financial results of ARP have
been consolidated in accordance with
ASC 810-20,
this transaction does not have an impact on the consolidated
results of operations or financial condition of the Company for
the period ended or as of September 30, 2011. Had the
results of ARP not been consolidated, during the nine month
period ended September 30, 2011, the Company would have
recorded interest expense of $6,227 related to this obligation
and had an outstanding obligation of $70,349 as of
September 30, 2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2011
|
|
|
December 31, 2010
|
|
Type
|
|
Current
|
|
|
Non-Current
|
|
|
Current
|
|
|
Non-Current
|
|
|
Secured promissory notes, due 2011 through 2014
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
121,363
|
|
Secured notes relating to land purchases, due 2011 through 2013
|
|
|
976
|
|
|
|
1,500
|
|
|
|
1,686
|
|
|
|
947
|
|
Senior secured term loan
|
|
|
15,000
|
|
|
|
85,000
|
|
|
|
|
|
|
|
|
|
Senior secured revolving credit facility
|
|
|
|
|
|
|
34,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
15,976
|
|
|
$
|
121,100
|
|
|
$
|
1,686
|
|
|
$
|
122,310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2010, the secured promissory notes were
recorded at their net present value using an effective interest
rate of 10%. On February 9, 2011, the Company entered into
a new credit facility (the Senior Secured Credit
Facility), which is comprised of a $100,000 term loan (the
Senior Secured Term Loan) and a $50,000 revolving
credit facility (the Senior Secured Revolving Credit
Facility). The Senior
F-38
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands)
(unaudited)
Secured Term Loan is a five-year term loan that requires
principal payments in the amount of $5,000 on the first day of
each quarter commencing on January 1, 2012 through
January 1, 2016, with the remaining outstanding principal
and interest balance due upon maturity on February 9, 2016.
Interest payments are also payable quarterly in arrears on the
first day of each quarter. The interest rate fluctuates based on
our leverage ratio and the applicable interest option elected.
The Senior Secured Revolving Credit Facility provides for
quarterly interest payments in arrears that fluctuate on the
same terms as our term loan and also provides for a commitment
fee based on the unused portion of the facility at certain
times. The interest rate on the Senior Secured Credit Facility
as of September 30, 2011 was 5.75%, which was reduced to
5.25% on November 14, 2011. The Company incurred $3,317 of
deferred financing fees related to the Senior Secured Credit
Facility that have been capitalized and will be amortized over
the life of the Senior Secured Term Loan. As of
September 30, 2011, the Company had $15,400 available for
borrowing under the Senior Secured Revolving Credit Facility.
The obligations under the Senior Secured Credit Facility are
secured by a first lien on substantially all of the
Companys assets, including but not limited to certain of
our mines, coal reserves and related fixtures. In addition, ARP
is a co-borrower under the Senior Secured Term Loan and
guarantor on the Senior Secured Revolving Credit Facility and
the Senior Secured Term Loan, and substantially all of its
assets are pledged as collateral. ARP will receive, as
compensation for these restrictions, a fee of 1% of the
weighted-average outstanding balance under the Senior Secured
Credit Facility, which for the nine months ended
September 30, 2011 totaled $810.
The Senior Secured Credit Facility contains certain customary
covenants as well as certain limitations on, among other things,
additional debt, liens, investments, acquisitions and capital
expenditures, future dividends, and asset sales. In July 2011,
the Company amended the Senior Secured Credit Facility in
connection with a contemplated equity offering. The Senior
Secured Credit Facility was amended to allow the equity
offering, allow the Company to use a portion of the proceeds to
reduce the revolving portion of the credit agreement, revise
certain financial covenants based on current expectations, and
allow other items impacted by the equity offering. The Company
was in compliance with each of the covenants as of
September 30, 2011. Deferred financing fees of $1,082 were
incurred related to the amendment to the agreement, which will
be amortized over the remaining life of the Senior Secured Term
Loan.
Proceeds from the Senior Secured Term Loan and borrowings under
the Senior Secured Revolving Credit Facility were used to repay
the outstanding principal and interest balance of the secured
promissory notes. As a result of the repayment of the existing
debt obligations, the Company recognized a gain on early
extinguishment of debt of approximately $6,954.
The Company recorded an income tax provision of $809 for the
nine months ended September 30, 2011, related primarily to
a liability for alternative minimum tax and certain state income
tax. Because of substantial net operating loss carryforwards,
the Company has not recognized certain income tax benefits as it
does not believe it is more likely than not it will be able to
realize its net deferred tax assets. The Company has therefore
established a valuation allowance against its net deferred tax
assets as of September 30, 2011.
In connection with the Reorganization, effective October 1,
2011, the Company converted its legal structure from a
partnership to a corporation for income tax purposes. The
conversion of the Company to a corporation will result in the
recognition of deferred tax assets and liabilities for the
difference between its asset basis for financial reporting and
income tax purposes. However, consistent with the prior
reporting of the subsidiary corporations, the consolidated
income tax filing group will recognize a full valuation
allowance
F-39
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands)
(unaudited)
against its net deferred tax assets. Therefore, there is no
expected impact to the statements of operations or financial
position as a result of this transaction.
On June 1, 2011, the Company entered into an agreement to
acquire an approximate 8.4% equity interest in RAM Terminal, LLC
(RAM) for $2,470. RAM owns 600 acres of
Mississippi River front property approximately 10 miles
south of New Orleans and intends to permit, design and construct
a seaborne coal export terminal with an annual through-put
capacity of up to 10 million tons. All future expenditures
are expected to be funded by a related party and therefore the
Companys equity interest will be significantly reduced in
the future. Because of the Companys limited influence over
the investment and future dilution of ownership interest, the
cost method is used to account for this investment.
In order to manage the risk associated with changes in interest
rates, the Company entered into an interest rate swap agreement
that effectively converts a portion of its floating-rate debt to
a fixed-rate basis, thereby reducing the impact of interest rate
changes on future cash interest payments beginning
January 1, 2012. On September 30, 2011, the notional
amount of the outstanding interest rate swap agreement, which
expires in February 2016, was $47,500. The swap is designated as
a cash flow hedge of expected future interest payments and
measured at fair value on a recurring basis. Under the interest
rate swap agreement, the Company receives three-month LIBOR
based interest payments from the swap counterparty and pays a
fixed rate of 2.89%. The interest rate swap agreement contains
an embedded floor, whereby the Company receives a minimum 1%
floating interest rate. LIBOR was 0.374% as of
September 30, 2011.
The Company endeavors to utilize the best available information
in measuring fair value. The interest rate swap is valued based
on quoted data from the counterparty, corroborated with
indirectly observable market data, which, combined, are deemed
to be a Level 2 input in the fair value hierarchy. At
September 30, 2011, the Company recorded a liability of
$1,778, in other long term liabilities on the condensed
consolidated balance sheet for the fair value of the swap. The
effective portion of the related loss on the swap of $1,778, net
of tax of $0, is deferred in accumulated other comprehensive
income (loss) and will subsequently be reclassified into
interest expense during the same period in which the interest
payments being hedged affect earnings. No ineffectiveness was
recorded in the condensed consolidated statement of operations
during the nine months ended September 30, 2011. In
addition, there was no amount reclassified from accumulated
other comprehensive income (loss) to interest expense related to
the effective portion of the interest rate swap during the nine
months ended September 30, 2011. The amount of loss
expected to be reclassified from accumulated other comprehensive
income (loss) to interest expense over the next twelve months is
approximately $300.
On June 1, 2011, the Company awarded 74,000 restricted
shares, which vest on April 1, 2013, to certain executive
officers. In addition, on June 1, 2011 and
September 21, 2011, 9,250 shares and 9,250 shares
were issued to certain non-executive officers that will vest on
April 1, 2014 and August 1, 2014, respectively. The
awards contain normal conditions regarding employment status and
any
change-of-control
during the vesting period. Because the Companys common
stock is not publicly traded, the fair value of the restricted
shares at the date of grant was determined utilizing multiple
valuation methods, including a market approach and
F-40
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands)
(unaudited)
income approach, and is amortized to expense ratably over the
vesting period. Stock compensation expense related to restricted
stock awards for the nine months ended September 30, 2011
was $279.
Effective October 1, 2011, the Plan authorized the
conversion of each issued and outstanding membership unit of ALC
into 9.25 shares of common stock of AE. As a result, the
Company had 19,095,763 shares of common stock issued and
outstanding as of October 1, 2011. In accordance with SEC
Staff Accounting Bulletin Topic 4.C, Changes in Capital
Structure, all common share information presented has been
retroactively adjusted to reflect the common stock conversion.
The computation of basic and diluted earnings (loss) per common
share is as follows (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
Nine-months ended September 30,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
Net (loss) income attributable to common stockholders
basic and diluted
|
|
$
|
(983
|
)
|
|
$
|
7,055
|
|
Basic weighted average number of common shares outstanding
|
|
|
19,132
|
|
|
|
19,111
|
|
Effect of dilutive securities
|
|
|
|
|
|
|
9
|
|
Diluted weighted average number of common shares outstanding
|
|
|
19,132
|
|
|
|
19,120
|
|
Earnings (loss) per common share basic and diluted
|
|
$
|
(0.05
|
)
|
|
$
|
0.37
|
|
The diluted weighted average number of common shares calculation
excludes all unvested restricted stock for the nine months ended
September 30, 2011, as they would be antidilutive. As of
September 30, 2011, there were 109,150 unvested restricted
stock awards outstanding.
|
|
14.
|
COMMITMENTS
AND CONTINGENCIES
|
Coal
Sales Contracts
The Company is committed under multi-year supply agreements to
sell coal that meets certain quality requirements at specified
prices. These contracts typically have specific and possibly
different volume and pricing arrangements for each year of the
agreement, which allows customers to secure a supply for their
future needs and provides the Company with greater
predictability of sales volume and sales prices. Quantities sold
under some of these contracts may vary from year to year within
certain limits at the option of the customer or the Company. The
remaining terms of the Companys long-term contracts range
from one to eight years.
Legal
Periodically, there may be various claims and legal proceedings
against the Company arising from the normal course of business.
The Company is also involved in litigation matters arising in
the ordinary course of business. In the opinion of management,
the resolution of these matters will not have a material adverse
effect on the Companys consolidated financial statements.
F-41
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands)
(unaudited)
|
|
15.
|
EXECUTIVE
STOCK REPURCHASE
|
In 2006 thru 2008, the Companys Board of Directors
approved the issuance of promissory notes payable to the Company
to certain executive officers to finance the purchase of
membership units of the Companys predecessor. Promissory
notes payable to the Company, including accrued and unpaid
interest, were $2,716 and $2,623 as of September 30, 2011
and December 31, 2010, respectively, but are not recorded
within the consolidated balance sheet as these notes are
non-recourse. On September 30, 2011, all promissory notes
outstanding were repaid in full through the sale of membership
units back to the Companys predecessor by the borrowers.
As the membership units were repurchased at a discount from the
fair value on the date of acquisition, a non-cash charge of $933
was recognized in the results of operations as a component of
selling, general, and administrative expense for the nine months
ended September 30, 2011.
|
|
16.
|
DECONSOLIDATION
OF ARMSTRONG RESOURCE PARTNERS
|
The Company has historically consolidated the results of ARP in
accordance with
ASC 810-20
as ECGP was presumed to control the partnership. On
October 1, 2011, the partners of ARP entered into the
Amended and Restated Agreement of Limited Partnership of
Armstrong Resource Partners, L.P. (the ARP LPA).
Pursuant to the ARP LPA, effective October 1, 2011,
investment funds managed by Yorktown Partners LLC, ARPs
largest unit holder, unilaterally may remove the Companys
subsidiary, ECGP, as general partner of ARP or otherwise cause a
change of control of ARP without the Companys consent or
the consent of the holders of ARPs equity units. As a
result of the loss of control of ARP by ECGP, the Company will
no longer consolidate the results of operations of ARP effective
October 1, 2011 and will begin to account for its ownership
in ARP under the equity method of accounting. Under the
deconsolidation accounting guidelines, the investors
opening investment is recorded at fair value as of the date of
deconsolidation. The difference between this initial fair value
of the investment and the net carrying value is recognized as a
gain or loss in earnings.
In order to determine the fair value of its initial investment
in ARP, the Company completed a valuation analysis based on the
income approach using the discounted cash flow method. The
discount rate, long-term growth rate, and profitability
assumptions are material inputs utilized in the discounted cash
flow model. Based on the results of this valuation, the
deconsolidation date fair value of the Companys investment
in ARP was determined to be $716. The Company will recognize a
non-cash gain included as a component of other income (expense),
net of approximately $308 in the fourth fiscal quarter of 2011
related to the deconsolidation of ARP.
The following is summarized financial information of ARP as of
September 30, 2011 (in thousands):
|
|
|
|
|
Total assets
|
|
$
|
146,738
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
11,957
|
|
Partners capital
|
|
$
|
134,781
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
146,738
|
|
|
|
|
|
|
|
|
17.
|
ACQUISITION
OF NON-CONTROLLING INTEREST
|
Prior to the Reorganization in August 2011, the Company acquired
all of the outstanding common stock held by certain third
parties in the former Armstrong Energy, Inc. and Armstrong
Resources Holdings, LLC. A portion of the outstanding shares
were acquired in exchange for membership interests in ALC, which
totaled 7,957.5 units of membership interest
(73,606 shares of common stock of AE). In addition, the
Company had
F-42
Armstrong
Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands)
(unaudited)
outstanding non-recourse promissory notes with these third
parties related to a portion of their original purchase of
shares in Armstrong Energy, Inc. in December 2006 and March
2007. The non-recourse notes, including all accrued and unpaid
interest, were repaid in full through payment of cash of $125
and the sale of their remaining shares in the former Armstrong
Energy, Inc. to the Company. Simultaneous with the above, the
Company sold 4,520 units of membership interest in ALC
(41,810 shares of common stock of AE) to these third party
investors financed with new non-recourse promissory notes
totaling $452, which are not recorded within the consolidated
balance sheet as these notes are non-recourse. Each of the
promissory notes carries a stated interest rate of 6% per annum
and are collateralized by the unpaid ownership interest. No
portions of the promissory notes are subject to release until
full payment has been tendered on the applicable note. In the
event of default, the notes shall bear interest at 12% per annum.
The units purchased with non-recourse notes are accounted for as
options. As the options were fully vested at the date of
issuance, the Company recognized a non-cash charge in the nine
months ended September 30, 2011 of $217 within other income
(expense), net, which represents the total fair value of the
options awarded.
On October 28, 2011, a portion of the highwall at the
Companys Equality Mine collapsed, fatally injuring two
employees of a local blasting company. Following the accident,
pursuant to Section 103(k) of the Mine Act, the Federal
Mine Safety and Health Administration (MSHA) issued an order
prohibiting all activity at the Equality Mine until it was
determined to be safe to resume normal mining operations. MSHA
approved resuming mining of the uppermost coal seam on
November 2, 2011. An addendum to the ground control plan
was submitted to MSHA and approved on November 8, 2011,
which allowed for mining of the lower seams to resume. The
Company is currently unable to estimate the total cost of this
accident, but does not believe the impact should have a material
adverse effect on its consolidated cash flows, results of
operations or financial condition. The Company will continue to
evaluate the need for any necessary accruals or other related
expenses as a result of the accident and record the charges in
the period in which the determination is made.
F-43
ARMSTRONG ENERGY,
INC.
Shares
of
Common Stock
PROSPECTUS
FBR
Raymond
James
, 2012
Dealer
Prospectus Delivery Obligation
Through and
including ,
2012 (the 25th day after the date of this prospectus), all
dealers effecting transactions in these securities, whether or
not participating in this offering, may be required to deliver a
prospectus. This is in addition to the dealers obligation
to deliver a prospectus when acting as underwriters and with
respect to their unsold allotments or subscriptions.
PART II:
INFORMATION NOT REQUIRED IN PROSPECTUS
|
|
Item 13.
|
Other
Expenses of Issuance and Distribution
|
The following table sets forth the costs and expenses, other
than underwriting discounts and commissions, payable solely by
Armstrong Energy, Inc. (the Company) and expected to
be incurred in connection with the offer and sale of the
securities being registered. All amounts are estimates, except
the SEC registration fee and the FINRA filing fee.
|
|
|
|
|
|
|
Amount to be Paid
|
|
|
SEC registration fee
|
|
$
|
7,907.40
|
|
FINRA filing fee
|
|
$
|
7,400.00
|
|
Blue sky fees and expenses*
|
|
|
|
|
Nasdaq listing fee*
|
|
|
|
|
Printing and engraving expenses*
|
|
|
|
|
Legal fees and expenses*
|
|
|
|
|
Accounting fees and expenses*
|
|
|
|
|
Transfer agent fees*
|
|
|
|
|
Miscellaneous*
|
|
|
|
|
|
|
|
|
|
Total*
|
|
|
|
|
|
|
|
* |
|
To be completed by amendment. |
|
|
Item 14.
|
Indemnification
of Directors and Officers
|
Section 145 of the DGCL permits a Delaware corporation to
indemnify its officers, directors and other corporate agents to
the extent and under the circumstances set forth therein.
Our amended and restated certificate of incorporation and bylaws
provide that, to the fullest extent permitted by the DGCL,
directors shall not be personally liable to the Company or its
stockholders for monetary damages for breach of duty as a
director. Pursuant to Section 102(b)(7) of the DGCL, our
amended and restated certificate of incorporation eliminates the
personal liability of a director to us or our shareholders for
monetary damages for a breach of fiduciary duty as a director,
except for liabilities:
|
|
|
|
|
for any breach of the directors duty of loyalty to us or
our shareholders;
|
|
|
|
for acts or omissions not in good faith or which involve
intentional misconduct or a knowing violation of law;
|
|
|
|
under Section 174 of the DGCL; and
|
|
|
|
for any transaction from which the director derived an improper
personal benefit.
|
Pursuant to our amended and restated certificate of
incorporation, each person who was or is made a party or is
threatened to be made a party to or is involved in any action,
suit or proceeding, whether civil, criminal, administrative or
investigative (hereinafter a proceeding), by reason
of the fact that he or she, or a person of whom he or she is the
legal representative, is or was a director or officer of the
Company, or serves, in any capacity, any corporation,
partnership or other entity in which the Company has a
partnership or other interest, including service with respect to
employee benefit plans, whether the basis of such proceeding is
alleged action in an official capacity as a director, officer,
employee or agent or in any other capacity while serving as a
director, officer, employee or agent, shall be indemnified and
held harmless by the Company to the fullest extent authorized by
the DGCL, against all expense, liability and loss reasonably
incurred or suffered by such person in connection therewith and
such indemnification shall continue as to a person who has
ceased to be a director, officer, employee or agent and shall
inure to the benefit of his or her heirs, executors and
administrators. The Company may provide indemnification to
employees or agents of the
II-1
Company with the same scope and effect as the foregoing
indemnification of directors and officers. These indemnification
provisions may be sufficiently broad to permit indemnification
of the registrants executive officers and directors for
liabilities, including reimbursement of expenses incurred,
arising under the Securities Act.
The above discussion of Section 145 of the DGCL and of our
amended and restated certificate of incorporation and bylaws is
not intended to be exhaustive and is respectively qualified in
its entirety by Section 145 of the DGCL, our amended and
restated certificate of incorporation and our bylaws.
As permitted by Section 145 of the DGCL, we intend to carry
primary and excess insurance policies insuring our directors and
officers against certain liabilities they may incur in their
capacity as directors and officers. Under the policies, the
insurer, on our behalf, may also pay amounts for which we
granted indemnification to our directors and officers.
|
|
Item 15.
|
Recent
Sales of Unregistered Securities
|
In the three years preceding the filing of this registration
statement, Armstrong Energy, Inc. and Armstrong Energy,
Inc.s predecessor, Armstrong Land Company, LLC
(Armstrong Land), issued the following securities
that were not registered under the Securities Act:
1. On October 1, 2008, Armstrong Land issued
925,000 shares of common stock to Yorktown Energy
Partners VIII, L.P. in consideration of $10,000,000. These
shares were issued in a transaction exempt from the registration
requirements of the Securities Act under Section 4(2) of
the Securities Act.
2. On February 10, 2009, Armstrong Land issued
1,850,000 shares of common stock to Yorktown Energy
Partners VIII, L.P. in consideration of $20,000,000. These
shares were issued in a transaction exempt from the registration
requirements of the Securities Act under Section 4(2) of
the Securities Act.
3. On May 6, 2009, Armstrong Land issued
(i) 1,850,000 shares of common stock
200,000 units of membership interest to Yorktown Energy
Partners VIII, L.P., (ii) 23,125 shares of common
stock to James H. Brandi and (iii) 4,625 shares
of common stock to LucyB Trust in consideration of $20,300,000
in the aggregate, $125,000 of which was evidenced by a
non-recourse promissory note executed by Mr. Brandi and
secured by a pledge of the shares purchased by Mr. Brandi.
These units were issued in a transaction exempt from the
registration requirements of the Securities Act under
Section 4(2) of the Securities Act.
4. On September 15, 2009, Armstrong Land issued
1,387,500 shares of common stock to Yorktown Energy
Partners VIII, L.P. in consideration of $15,000,000. These
shares were issued in a transaction exempt from the registration
requirements of the Securities Act under Section 4(2) of
the Securities Act.
5. On January 1, 2010, Armstrong Land issued
18,500 shares of restricted stock to one of its employees.
These shares were issued in a transaction exempt from the
registration requirements of the Securities Act under
Rule 701, promulgated under the Securities Act.
6. On August, 16, 2010, Armstrong Land issued
16,650 shares of restricted stock to one of its employees.
These shares were issued in a transaction exempt from the
registration requirements of the Securities Act under
Rule 701, promulgated under the Securities Act.
7. On June 1, 2010 Armstrong Land issued
83,250 shares of restricted stock to certain of its
employees. These shares were issued in a transaction exempt from
the registration requirements of the Securities Act under
Rule 701, promulgated under the Securities Act.
8. On August 9, 2011, Armstrong Land issued
(i) 37,024 shares of common stock to John Stites and
(ii) 78,394 shares of common stock to Hutchinson
Brothers, LLC. $452,000 of the consideration was paid by
non-recourse promissory notes secured by a pledge of the shares
purchased, and the balance was evidenced by the contribution to
Armstrong Land of minority interests in subsidiaries of
Armstrong Land. These shares were issued in a transaction exempt
from the registration requirements of the Securities Act under
Section 4(2) of the Securities Act.
II-2
9. On September 21, 2011 Armstrong Land issued 9,250
shares of common stock to one of its employees. These shares
were issued in a transaction exempt from the registration
requirements of the Securities Act under Rule 701,
promulgated under the Securities Act.
10. On January 13, 2012, Armstrong Energy, Inc. issued
300,000 shares of Series A convertible preferred stock to
Yorktown Energy Partners IX, L.P. in consideration of
$30,000,000. These shares were issued in a transaction exempt
from the registration requirements of the Securities Act under
Section 4(2) of the Securities Act.
|
|
Item 16.
|
Exhibits
and Financial Statement Schedules
|
(a) Exhibits.
See the Exhibit Index on the page immediately preceding the
exhibits for a list of exhibits filed as part of this
registration statement on
Form S-1,
which Exhibit Index is incorporated herein by reference.
(b) Financial Statement Schedules.
None.
Insofar as indemnification for liabilities arising under the
Securities Act of 1933, as amended (the Securities
Act), may be permitted to directors, officers and
controlling persons pursuant to the provisions described in
Item 14 above, or otherwise, it is the opinion of the
Securities and Exchange Commission that such indemnification is
against public policy as expressed in the Securities Act and is,
therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment
by us of expenses incurred or paid by a director, officer or
controlling person of us in the successful defense of any
action, suit or proceeding) is asserted by such director,
officer or controlling person in connection with the securities
being registered, we will, unless in the opinion of our counsel
the matter has been settled by controlling precedent, submit to
a court of appropriate jurisdiction the question whether such
indemnification by us is against public policy as expressed in
the Securities Act and will be governed by the final
adjudication of such issue.
The undersigned registrant hereby undertakes to provide to the
underwriters at the closing specified in the underwriting
agreement, certificates in such denominations and registered in
such names as required by the underwriters to permit prompt
delivery to each purchaser.
We hereby undertake that:
(i) for purposes of determining any liability under the
Securities Act, the information omitted from the form of
prospectus filed as part of this registration statement in
reliance upon Rule 430A and contained in a form of
prospectus filed by the registrant pursuant to
Rule 424(b)(1) or (4) or 497(h) under the Securities
Act shall be deemed to be part of this registration statement as
of the time it was declared effective; and
(ii) for purposes of determining any liability under the
Securities Act, each post-effective amendment that contains a
form of prospectus shall be deemed to be a new registration
statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be
the initial bona fide offering thereof.
II-3
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as
amended, Armstrong Energy, Inc. has duly caused this
registration statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the County of
St. Louis, State of Missouri, on
February 10, 2012.
ARMSTRONG ENERGY, INC.
Martin D. Wilson
President
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons
in the capacities indicated on February 10, 2012.
|
|
|
|
|
Signature
|
|
Title
|
|
|
|
|
*
J.
Hord Armstrong, III
|
|
Chairman and Chief Executive Officer
(Principal Executive Officer)
|
|
|
|
/s/ Martin
D. Wilson
Martin
D. Wilson
|
|
President and Director
|
|
|
|
*
J.
Richard Gist
|
|
Senior Vice President, Finance and Administration
and Chief Financial Officer
(Principal Financial and Accounting Officer)
|
|
|
|
*
Anson
M. Beard, Jr.
|
|
Director
|
|
|
|
*
James
C. Crain
|
|
Director
|
|
|
|
*
Richard
F. Ford
|
|
Director
|
|
|
|
*
Bryan
H. Lawrence
|
|
Director
|
|
|
|
*
Greg
A. Walker
|
|
Director
|
|
|
|
*By: /s/ Martin
D. Wilson
Attorney-in-fact
|
|
|
II-4
EXHIBIT INDEX
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
1
|
.1*
|
|
Form of Underwriting Agreement.
|
|
3
|
.1**
|
|
Certificate of Conversion of Armstrong Land Company, LLC to
Armstrong Land Company, Inc., effective as of October 1, 2011.
|
|
3
|
.2**
|
|
Certificate of Incorporation of Armstrong Land Company, Inc.,
effective as of October 1, 2011.
|
|
3
|
.3**
|
|
Certificate of Amendment to Certificate of Incorporation of
Armstrong Land Company, Inc., effective as of October 5, 2011.
|
|
3
|
.4
|
|
Certificate of Designations of Series A Convertible Preferred
Stock of Armstrong Energy, Inc., effective as of
January 13, 2012.
|
|
3
|
.5**
|
|
Bylaws of Armstrong Energy, Inc., effective as of October 3,
2011.
|
|
3
|
.6
|
|
Survant Mining Company, LLC Limited Liability Company Agreement
(The Operating Agreement) effective as of December 2011 by and
among Cyprus Creek Land Resources, LLC and Armstrong Coal
Company, Inc.
|
|
4
|
.1*
|
|
Agreement to Enter into Voting and Stockholders Agreement by and
among Armstrong Energy, Inc., J. Hord Armstrong, III,
Martin D. Wilson, Yorktown Energy Partners VI, L.P., Yorktown
Energy Partners VII, L.P., Yorktown Energy Partners VIII, L.P.,
James H. Brandi, LucyB Trust, Lorenzo Weisman/Danielle Weisman
Joint Ownership with Right of Survivorship, Brim Family 2004
Trust, Franklin W. Hobbs IV, Hutchinson Brothers, LLC and John
H. Stites, III, dated as of October 1, 2011.
|
|
4
|
.2
|
|
Extension of Agreement to Enter into Voting and
Stockholders Agreement by and among Armstrong Energy,
Inc., Yorktown Energy Partners VI, L.P., Yorktown Energy
Partners VII, L.P. and Yorktown Energy Partners VIII, dated as
of February 1, 2012.
|
|
5
|
.1**
|
|
Form of Opinion of Armstrong Teasdale LLP.
|
|
10
|
.1**
|
|
Credit Agreement by and among Armstrong Coal Company, Inc.,
Armstrong Land Company, LLC, Western Mineral Development, LLC,
Western Diamond, LLC, Western Land Company, LLC and Elk Creek,
L.P., as Borrowers, the Lenders party thereto, The Huntington
National Bank, as Syndication Agent, Union Bank, N.A. as
Documentation Agent and PNC Bank, National Association, as
Administrative Agent, dated as of February 9, 2011.
|
|
10
|
.2**
|
|
First Amendment to Credit Agreement by and among Armstrong Coal
Company, Inc., Armstrong Land Company, LLC, Western Mineral
Development, LLC, Western Diamond, LLC, Western Land Company,
LLC and Elk Creek, L.P., as Borrowers, the Guarantors party
thereto, the financial institutions party thereto and PNC Bank,
National Association, as Administrative Agent, dated as of July
1, 2011.
|
|
10
|
.3**
|
|
Second Amendment to Credit Agreement by and among Armstrong Coal
Company, Inc., Armstrong Land Company, LLC, Western Mineral
Development, LLC, Western Diamond, LLC, Western Land Company,
LLC and Elk Creek, L.P., as Borrowers, the Guarantors party
thereto, the financial institutions party thereto and PNC Bank,
National Association, as Administrative Agent, dated as of
September 29, 2011.
|
|
10
|
.4*
|
|
Third Amendment to Credit Agreement by and among Armstrong Coal
Company, Inc., Armstrong Energy, Inc., Western Mineral
Development, LLC, Western Diamond LLC, Western Land Company, LLC
and Armstrong Resource Partners, L.P., as Borrowers, the
Guarantors party thereto, the financial institutions party
thereto and PNC Bank, National Association, as Administrative
Agent, dated as of December 29, 2011.
|
|
10
|
.5*
|
|
Fourth Amendment to Credit Agreement by and among Armstrong Coal
Company, Inc., Armstrong Energy, Inc., Western Mineral
Development, LLC, Western Diamond LLC, Western Land Company, LLC
and Armstrong Resource Partners, L.P., as Borrowers, the
Guarantors party thereto, the financial institutions party
thereto and PNC Bank, National Association, as Administrative
Agent, dated as of February 8, 2012.
|
|
10
|
.6**
|
|
Coal Mining Lease between Alcoa Fuels, Inc. and Armstrong Coal
Company, Inc., dated as of October 27, 2010.
|
|
10
|
.7*
|
|
Contract for Purchase and Sale of Eastern Coal by and between
Tennessee Valley Authority and Armstrong Coal Company, Inc.,
dated as of November 30, 2007.
|
II-5
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
10
|
.8
|
|
Tennessee Valley Authority Coal Acquisition & Supply
Contract Supplement No. 1, dated as of July 29, 2008.
|
|
10
|
.9
|
|
Tennessee Valley Authority Coal Acquisition & Supply
Contract Supplement No. 2, dated as of July 29, 2008.
|
|
10
|
.10
|
|
Tennessee Valley Authority Coal Acquisition & Supply
Contract Supplement No. 3, dated as of November 12, 2008.
|
|
10
|
.11
|
|
Tennessee Valley Authority Coal Acquisition & Supply
Contract Supplement No. 4, dated as of December 11, 2008.
|
|
10
|
.12
|
|
Tennessee Valley Authority Coal Acquisition & Supply
Contract Supplement No. 5, dated as of February 12, 2009.
|
|
10
|
.13
|
|
Tennessee Valley Authority Coal Acquisition & Supply
Contract Supplement No. 6, dated as of October 9, 2009.
|
|
10
|
.14
|
|
Tennessee Valley Authority Coal Acquisition & Supply
Contract Supplement No. 7, dated as of December 29, 2009.
|
|
10
|
.15
|
|
Tennessee Valley Authority Coal Supply & Origination
Contract Supplement No. 8, dated as of May 25, 2011.
|
|
10
|
.16
|
|
Tennessee Valley Authority Coal Supply & Origination
Contract Supplement No. 9, dated as of August 9, 2011.
|
|
10
|
.17*
|
|
Coal Supply Agreement by and between Louisville Gas and Electric
Company and Kentucky Utilities Company, as Buyer, and Armstrong
Coal Company, Inc., as Seller, effective as of January 1, 2008.
|
|
10
|
.18*
|
|
Amendment No. 1 to Coal Supply Agreement by and between
Louisville Gas and Electric Company and Kentucky Utilities
Company, as Buyer, and Armstrong Coal Company, Inc., as Seller,
effective as of July 1, 2008.
|
|
10
|
.19*
|
|
Amendment No. 2 to Coal Supply Agreement by and between
Louisville Gas and Electric Company and Kentucky Utilities
Company, as Buyer, and Armstrong Coal Company, Inc., as Seller,
effective as of December 22, 2009.
|
|
10
|
.20*
|
|
Letter Agreement by and between Louisville Gas and Electric
Company and Kentucky Utilities Company, as Buyer, and Armstrong
Coal Company, Inc., as Seller, dated December 8, 2008.
|
|
10
|
.21*
|
|
Letter Agreement by and between Louisville Gas and Electric
Company and Kentucky Utilities Company, as Buyer, and Armstrong
Coal Company, Inc., as Seller, dated April 1, 2009.
|
|
10
|
.22*
|
|
Settlement Agreement and Release by and between Louisville Gas
and Electric Company and Kentucky Utilities Company and
Armstrong Coal Company, Inc., dated as of December 22, 2009.
|
|
10
|
.23*
|
|
Coal Supply Agreement by and between Louisville Gas and Electric
Company and Kentucky Utilities Company, as Buyer, and Armstrong
Coal Company, Inc., as Seller, effective as of December 22,
2009.
|
|
10
|
.24*
|
|
Coal Supply Agreement by and between Louisville Gas and Electric
Company and Kentucky Utilities Company, as Buyer, and Armstrong
Coal Company, Inc., as Seller, effective as of January 1, 2012.
|
|
10
|
.25*
|
|
Fuel Purchase Order by and between Louisville Gas and Electric
Company and Kentucky Utilities Company, as Buyer, and Armstrong
Coal Company, Inc., as Seller, dated July 1, 2008.
|
|
10
|
.26*
|
|
Amendment No. 1 to Fuel Purchase Order dated July 1, 2008 by and
between Louisville Gas and Electric Company and Kentucky
Utilities Company, as Buyer, and Armstrong Coal Company, Inc.,
as Seller, dated July 28, 2008.
|
|
10
|
.27*
|
|
Fuel Purchase Order by and between Louisville Gas and Electric
Company and Kentucky Utilities Company, as Buyer, and Armstrong
Coal Company, Inc., as Seller, dated January 1, 2010.
|
|
10
|
.28**
|
|
Letter Agreement between Armstrong Land Company, LLC and J.
Richard Gist, dated as of September 14, 2009.
|
|
10
|
.29**
|
|
Employment Agreement by and between Armstrong Energy, Inc. and
J. Richard Gist, dated as of October 1, 2011.
|
|
10
|
.30**
|
|
Employment Agreement by and between Armstrong Energy, Inc. and
J. Hord Armstrong, III, dated as of October 1, 2011.
|
II-6
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
10
|
.31**
|
|
Employment Agreement by and between Armstrong Energy, Inc. and
Martin D. Wilson, dated as of October 1, 2011.
|
|
10
|
.32**
|
|
Employment Agreement by and between Armstrong Coal Co. and
Kenneth E. Allen, dated as of June 1, 2007.
|
|
10
|
.33**
|
|
Employment Agreement by and between Armstrong Coal Co. and David
R. Cobb, dated as of January 19, 2007.
|
|
10
|
.34
|
|
Employment Agreement by and between Armstrong Energy, Inc. and
Brian G. Landry, dated as of December 1, 2011.
|
|
10
|
.35**
|
|
Unit Repurchase Agreement by and between Armstrong Land Company,
LLC and J. Hord Armstrong, III, dated as of September 30,
2011.
|
|
10
|
.36**
|
|
Unit Repurchase Agreement by and between Armstrong Land Company,
LLC and Martin D. Wilson, dated as of September 30, 2011.
|
|
10
|
.37**
|
|
Form of Director Indemnification Agreement.
|
|
10
|
.38**
|
|
Armstrong Energy, Inc. 2011 Long-Term Incentive Plan.
|
|
10
|
.39**
|
|
Restricted Stock Unit Award Agreement between Armstrong Land
Company, LLC and David Cobb, dated as of June 1, 2011.
|
|
10
|
.40**
|
|
Restricted Stock Unit Award Agreement between Armstrong Land
Company, LLC and J. Hord Armstrong, III, dated as of June
1, 2011.
|
|
10
|
.41**
|
|
Restricted Stock Unit Award Agreement between Armstrong Land
Company, LLC and Kenny Allen, dated as of June 1, 2011.
|
|
10
|
.42**
|
|
Restricted Stock Unit Award Agreement between Armstrong Land
Company, LLC and Martin D. Wilson, dated as of June 1, 2011.
|
|
10
|
.43
|
|
Amended Overriding Royalty Agreement by and among Western Land
Company, LLC, Western Diamond, LLC, Ceralvo Holdings, LLC,
Armstrong Mining, Inc., Armstrong Coal Company, Inc., Armstrong
Land Company, LLC and Kenneth E. Allen, dated as of December 3,
2008.
|
|
10
|
.44**
|
|
Amended Overriding Royalty Agreement by and among Western Land
Company, LLC, Western Diamond, LLC, Ceralvo Holdings, LLC,
Armstrong Mining, Inc., Armstrong Coal Company, Inc., Armstrong
Land Company, LLC and David R. Cobb, dated as of December 3,
2008.
|
|
10
|
.45*
|
|
Administrative Services Agreement by and between Armstrong
Energy, Inc., Armstrong Resource Partners, L.P. and Elk Creek
GP, LLC, effective as of January 1, 2011.
|
|
10
|
.46*
|
|
Promissory Note of Armstrong Land Company, LLC in favor of Elk
Creek, L.P. in the principal amount of $11.0 million, dated
November 30, 2009.
|
|
10
|
.47*
|
|
Promissory Note of Armstrong Land Company, LLC in favor of Elk
Creek, L.P. in the principal amount of $9.5 million, dated March
31, 2010.
|
|
10
|
.48*
|
|
Promissory Note of Armstrong Land Company, LLC in favor of Elk
Creek, L.P. in the principal amount of $12.6 million, dated May
31, 2010.
|
|
10
|
.49*
|
|
Promissory Note of Armstrong Land Company, LLC in favor of Elk
Creek, L.P. in the principal amount of $11.0 million, dated
November 30, 2010.
|
|
10
|
.50*
|
|
Credit and Collateral Support Fee, Indemnification and Right of
First Refusal Agreement by and between Armstrong Land Company,
LLC, Armstrong Resource Holdings, LLC, Western Diamond, LLC,
Western Land Company, LLC, Armstrong Coal Company, Inc., Elk
Creek, L.P., Elk Creek Operating, L.P., Ceralvo Holdings, LLC
and Western Mineral Development, LLC, effective as of February
9, 2011.
|
|
10
|
.51*
|
|
Lease and Sublease Agreement between Armstrong Coal Company,
Inc. and Ceralvo Holdings, LLC, dated February 9, 2011.
|
|
10
|
.52*
|
|
Royalty Deferment and Option Agreement by and between Armstrong
Coal Company, Inc., Western Diamond, LLC, Western Land Company,
LLC and Western Mineral Development, LLC, effective February 9,
2011.
|
II-7
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
10
|
.53*
|
|
Lease Agreement by and between Armstrong Coal Company, Inc. and
David and Rebecca Cobb, dated August 1, 2009.
|
|
10
|
.54
|
|
Option Amendment, Option Exercise and Membership Interest
Purchase Agreement by and between Armstrong Land Company, LLC,
Armstrong Resource Holdings, LLC, Western Diamond, LLC, Western
Land Company, LLC, Western Mineral Development, LLC, and Elk
Creek, L.P., dated as of February 9, 2011.
|
|
10
|
.55
|
|
Coal Mining Lease and Sublease by and between Ceralvo Holdings,
LLC and Armstrong Coal Company, Inc., dated as of
February 9, 2011.
|
|
10
|
.56*
|
|
Contract to Sell Real Estate by and between Western Diamond LLC,
Western Land Company, LLC and Western Mineral Development, LLC,
dated as of October 11, 2011.
|
|
10
|
.57*
|
|
Asset Purchase Agreement between Cyprus Creek Land Resources,
LLC and Armstrong Coal Company, Inc., dated as of
December 29, 2011, by and between Cyprus Creek Land
Resources, LLC and Armstrong Coal Company, Inc.
|
|
10
|
.58*
|
|
Formation and Transfer Agreement by and among Cyprus Creek Land
Resources, LLC and Cyprus Creek Land Company, and Armstrong Coal
Company, Inc. and Western Land Company, LLC, effective as of
December 29, 2011.
|
|
10
|
.59*
|
|
Contract to Sell and Lease Real Estate between Midwest Coal
Reserves of Kentucky, LLC and Armstrong Coal Company, Inc. dated
December 25, 2011.
|
|
10
|
.60
|
|
Membership Interest Purchase Agreement by and between Western
Diamond LLC and Western Land Company, LLC, and Armstrong
Resource Partners, L.P.
|
|
16
|
.1**
|
|
Letter from Grant Thornton LLP to Securities and Exchange
Commission.
|
|
16
|
.2**
|
|
Letter from KPMG LLP to Securities and Exchange Commission.
|
|
21
|
.1**
|
|
List of Subsidiaries.
|
|
23
|
.1**
|
|
Consent of Armstrong Teasdale LLP (included in Exhibit 5.1).
|
|
23
|
.2
|
|
Consent of Ernst & Young LLP.
|
|
23
|
.3
|
|
Consent of Grant Thornton LLP.
|
|
23
|
.4**
|
|
Consent of Weir International, Inc.
|
|
24
|
.1**
|
|
Power of Attorney (included on signature page).
|
|
99
|
.1*
|
|
Audit Committee Charter.
|
|
99
|
.2*
|
|
Compensation Committee Charter.
|
|
99
|
.3*
|
|
Nominating and Corporate Governance Committee Charter.
|
|
|
|
* |
|
To be filed by amendment. |
|
** |
|
Previously filed. |
|
|
|
Indicates a management contract or compensatory plan or
arrangement. |
II-8